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How to Obtain Copies
You can electronically download this document on the U.S. EPA's homepage at http://www.epa.gov/globalwarming/publications/emis-
sions. To request free copies of this report, call the National Service Center for Environmental Publications (NSCEP) at (800) 490-
9198, or visit the web site above and click on order "online" after selecting an edition.
All data tables of this document are available for the full time series 1990 through 2000, inclusive, at the web site mentioned above.
FOR FURTHER INFORMATION
Contact Mr. Michael Gillenwater, Environmental Protection Agency, (202) 564-4092, ghginventory@epa.gov.
For more information regarding climate change and greenhouse gas emissions see EPA web side at http://www.epa.gov/globalwarming.
Released for printing: April 2002
Emissions by Economic Sectors
The photographs on the front and back cover of this report represent the six major economic sectors into which emissions have been allo-
cated for analytical purposes. The six economic sectors are Electricity Generation, Transportation, Industry, Agriculture, Residential, and
Commercial. The economic sectors represent an alternative method of allocating U.S. greenhouse gas emissions, different from the sec-
tors defined by the IPCC and used in this report for international reporting and standardized methodological reasons (i. e. Energy,
Industrial Processes, Solvent Use, Agriculture, Land-Use Change and Forestry, and Waste).
Residential: Residential sector greenhouse gas emissions are dominated by COz from fossil fuel combustion,
used to heat and supply electricity to homes. Emissions also result from landfills, wastewater treatment, waste
combustion, human sewage, stationary combustion, and leaks from the use of refrigerants.
Coal for Electricity Generation: Coal is a fossil fuel that is combusted to indirectly generate electricity. In coal
fueled combustors (i.e. boilers) the heat generated from burning coal is used to produce high-pressure steam.
The high-pressure steam is then used to turn turbines and generate electricity. Carbon dioxide is the predom-
inant greenhouse gas emitted from coal-fired boilers in Electricity Generation.
Agriculture: This is the only economic sector from which the majority of emissions are not from fossil fuel
combustion. Nitrous oxide emissions from agricultural soils dominate this sector, followed by emissions from
livestock due to enteric fermentation and manure management, and then CC>2 from fossil fuel combustion.
Smaller quantities of methane and nitrous oxide emissions are derived from rice cultivation, agricultural
residue burning, and mobile and stationary combustion.
Motor Vehicle Transportation: Petroleum-based products supplied almost all of the energy consumed for trans-
portation, with nearly two-thirds related to gasoline consumption in automobiles and other highway vehicles.
Motor vehicle emissions consist of COz, CBt and NzO from the internal combustion engines and HFCs from
motor vehicle air-conditioners and refrigerated transport.
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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
April 2002
The U.S. Environmental Protection Agency, in cooperation with other federal agencies,
has prepared the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000. The
estimates of emissions and removals contained in this report, along with future updates, will be
used to monitor and track the progress of the United States in meeting our commitments under
the United Nations Framework Convention on Climate Change (UNFCCC).
In accordance with a decision of the Conference of Parties to the UNFCCC (Decision
3/CP.5), this inventory complies with the UNFCCC Reporting Guidelines on Annual Inventories
(FCCC/CP/1999/7). Adherence to these guidelines ensures that natibnalinventories are well
documented, consistently prepared, and as accurate and complete as possible. The assumptions
and methodologies used in this report have been clearly explained, and are based on the Revised
1996IPCC Guidelines for National Greenhouse Gas Inventories and the IPCC Report on Good
Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories.
Each year, advances in scientific understanding and availability of underlying data allow
us to improve the quality and comprehensiveness of the inventory. A section entitled "Changes
in this Year's U.S. Greenhouse Gas Inventory Report," guides readers to specific areas where
methods have been improved or new data has been collected.
One of this year's advances is a new analysis that allocates emissions to "economic
sectors," which is intended to communicate more intuitively the emissions from broad categories
of economic activity. A "comprehensive electric power industry sector" has been evaluated for
the first time, as well as emissions from industrial wastewater and carbon sequestration in urban
trees. A series of improvements were also made to the estimates of CO2 emissions and carbon
storage from the non-energy use of fossil fuels for industrial feedstocks. Finally, newly reported
data on SF6 emissions from magnesium production and processing and electric power
transmission and distribution systems has been incorporated.
We hope that these improvements make this document more useful, and appreciate the
comments and suggestions we have received from numerous reviewers in both the scientific
community and the general public.
Sincerely,
^Holmstea
sy K. nolmstead
Assistant Administrator
Office of Air and Radiation
Recycled/Recyclable • Printed with Vegetable Oil Based Inks on 100% Recycled Paper (20% Postconsumer)
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Inventory of U.S. Greenhouse
Gas Emissions and Sinks:
199O — 2OOO
April 15, 2002
U.S. Environmental Protection Agency
Office of Atmospheric Programs (6202N)
1200 Pennsylvania Avenue, NW
Washington, DC 20460
USA
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Acknowledgments
TRie Environmental Protection Agency would like to acknowledge the many individual and organizational con
I contributors to this document, without whose efforts this report would not be complete. Although the
complete list of researchers, government employees, and consultants who have provided technical and editorial
support is too long to list here, we would like to thank some key contributors and reviewers whose work has signifi-
cantly improved this year's report.
In particular, we wish to acknowledge the efforts of the Energy Information Administration and the Department
of Energy for providing detailed statistics and insightful analysis on numerous energy-related topics; the U.S. Forest
Service for preparing the forest carbon inventory, and the Department of Agriculture's Agricultural Research Service
for their work on nitrous oxide emissions from soils; and to the Department of Agriculture's Agriculture Research
Service and the Natural Resource Ecology Laboratory at Colorado State University for their work on carbon in agricul-
tural soils.
Within the EPA, many Offices contributed data, analysis and technical review for this report. The EPA Office of
Atmospheric Programs developed methodologies and provided detailed emission estimates for numerous source
categories, particularly for methane, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. The Office of
Transportation and Air Quality and the Office of Air Quality Planning and Standards provided analysis and review for
several of the source categories addressed in this report. The Office of Solid Waste and the Office of Research and
Development also contributed analysis and research.
Other government agencies have contributed data as well, including the U.S. Geological Survey, the Federal
Highway Administration, the Department of Transportation, the Bureau of Transportation Statistics, the Department of
Commerce, the National Agricultural Statistics Service, the Federal Aviation Administration, and the Department of
Defense.
Michael Gillenwater has directed the analytical development and writing of this report. Work on fuel combustion
and industrial process emissions was also directed by Michael Gillenwater. Work on energy and waste sector methane
emissions was directed by Elizabeth Scheehle, while work on agriculture sector emissions was directed by Tom Wirth
and Joe Mangino. Land-Use Change and Forestry sector analysis was directed by Tom Wirth. Work on emissions of
HFCs, PFCs, and SF6 was directed by Deborah Schafer and Alicia Karspeck. Adam Chambers helped direct the review
process for this report.
We would especially like to thank Marian Martin, Randall Freed, and their staff at ICF Consulting's Global
Environmental Practice, including John Venezia, Kim Raby, Katrin Peterson, Barbara Braatz, Leonard Crook, Payton
Deeks, Susan Brown, Diana Pape, Bill Cowart, Anne Choate, Noam Glick, and Jeffrey King for synthesizing this report
and preparing many of the individual analyses. Eastern Research Group, Raven Ridge Resources, and Arcadis also
provided significant analytical support.
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The United States Environmental Protection Agency (EPA) prepares the official U.S. Inventory of Greenhouse
Gas Emissions and Sinks to comply with existing commitments under the United Nations Framework Convention on
Climate Change (UNFCCC).1 Under a decision of the UNFCCC Conference of the Parties, national inventories for most
UNFCCC Annex I parties should be provided to the UNFCCC Secretariat each year by April 15.
In an effort to engage the public and researchers across the country, the EPA has instituted an annual public
review and comment process for this document. The availability of the draft document is announced via Federal
Register Notice and is posted on the EPA web page.2 Copies are also mailed upon request. The public comment period
is generally limited to 30 days; however, comments received after the closure of the public comment period are accepted
and considered for the next edition of this annual report. The EPA's policy is to allow at least 60 days for public review
and comment when proposing new regulations or documents supporting regulatory development - unless statutory or
judicial deadlines make a shorter time necessary - and 30 days for non-regulatory documents of an informational
nature such as the Inventory document.
1 See http://www.unfccc.de
2 See http://www.epa.gov/globalwarming/emissions/national
I! Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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Table of Contents
Acknowledgments i
Preface , ii
Table of Contents , Hi
List of Tables, Figures, and Boxes , vi
Tables vi
Figures k
Boxes a
Executive Summary ES-1
Recent Trends in U.S. Greenhouse Gas Emissions ES-2
Emissions by Economic Sector ES-8
Global Warming Potentials ES-9
Carbon Dioxide Emissions ES-11
Methane Emissions ES-17
Nitrous Oxide Emissions ES-20
HFC, PFC, and SF6 Emissions ES-22
Ambient Air Pollutant Emissions ES-25
Changes in This Year's Inventory Report Changes-1
Methodological Changes Changes-3
Changes in Historical Data Changes-11
1. Introduction , 1-1
What is Climate Change? 1-2
Greenhouse Gases 1-2
Global Warming Potentials 1-7
Recent Trends in U.S. Greenhouse Gas Emissions 1-10
Emissions by Economic Sectors 1-16
Methodology and Data Sources 1-21
Uncertainty in and Limitations of Emission Estimates 1-24
Organization of Report 1-26
2. Energy 2-1
Carbon Dioxide Emissions from Fossil Fuel Combustion 2-3
Carbon Stored in Products from Non-Energy Uses of Fossil Fuels 2-19
Stationary Combustion (excluding CO2) 2-21
Mobile Combustion (excluding CO2) 2-25
CoalMining 2-30
Natural Gas Systems 2-33
Petroleum Systems 2-35
Municipal Solid Waste Combustion 2-37
Natural Gas Flaring and Ambient Air Pollutant Emissions from Oil and Gas Activities 2-41
Indirect CO2 from CH4 Oxidation 2-42
International Bunker Fuels 2-45
Wood Biomass and Ethanol Consumption 2-50
iii
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3. Industrial Processes „ 3-1
Iron and SteelProduction 3-2
Cement Manufacture , 3-5
Ammonia Manufacture 3-7
Lime Manufacture 3-9
Limestone and Dolomite Use 3-11
Soda Ash Manufacture and Consumption 3-14
Ferroalloy Production 3-15
Titanium Dioxide Production 3-16
Carbon Dioxide Consumption 3-18
Petrochemical Production 3-19
Silicon Carbide Production 3-20
Adipic Acid Production 3-21
Nitric Acid Production 3-23
Substitution of OzoneDepleting Substances 3-24
Aluminum Production 3-26
HCFC-22 Production 3-29
Semiconductor Manufacture 3-30
Electrical Transmission and Distribution 3-32
Magnesium Production and Processing 3-33
Industrial Sources of Ambient Air Pollutants 3-35
4. Solvent Use 4-1
5. Agriculture 5-1
Enteric Fermentation 5-2
Manure Management 5-5
Rice Cultivation 5-10
Agricultural Soil Management 5-14
Agricultural Residue Burning 5-19
6. Land-Use Change and Forestry 6-1
Changes in Forest Carbon Stocks 6-2
Changes in Carbon Stocks in Urban Trees 6-9
Changes in Agricultural Soil Carbon Stocks 6-11
Changes in Yard Trimming Carbon Stocks in Landfills 6-21
7. Waste 7-1
Landfills..... 7-1
Wastewater Treatment 7-5
Human Sewage 7-8
Waste Sources of Ambient Air Pollutants 7-9
8. References 8-1
Executive Summary 8-1
Changes in this Year's Inventory 8-2
Introduction 8-6
Energy 8-7
Industrial Processes 8-14
Solvent Use 8-19
Agriculture 8-19
Land-Use Change and Forestry 8-31
Waste 8-34
iv Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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Annexes
ANNEX A: Methodology for Estimating Emissions of CO2 from Fossil Fuel Combustion A-l
ANNEX B: Methodology for Estimating Carbon Stored in Products from Non-Energy Uses
of Fossil Fuels B-l
ANNEX C: Methodology for Estimating Emissions of CH4, N2O, and Ambient Air Pollutants from
Stationary Combustion C-l
ANNEXD: Methodology for Estimating Emissions of CH4, N2O, and Ambient Air Pollutants from
Mobile Combustion D-l
ANNEXE: Methodology for Estimating CH4 Emissions from Coal Mining E-l
ANNEX F: Methodology for Estimating CH4 Emissions fromNatural Gas Systems F-l
ANNEX G: Methodology for Estimating CH4 Emissions from Petroleum Systems G-l
ANNEX H: Methodology for Estimating CO2 Emissions from Municipal Solid Waste Combustion H-l
ANNEX I: Methodology for Estimating Emissions from International Bunker Fuels used by the
U.S. Military 1-1
ANNEX J: Methodology for Estimating HFC, and PFC Emissions from Substitution of Ozone
Depleting Substances J-l
ANNEX K: Methodology for Estimating CH4 Emissions from Enteric Fermentation K-l
ANNEX L: Methodology for Estimating CH4 and N2O Emissions from Manure Management L-l
ANNEXM: Methodology for Estimating N2O Emissions from Agricultural Soil Management M-l
ANNEX N: Methodology for Estimating Net Changes in Forest Carbon Stocks N-l
ANNEX O: Methodology for Estimating CH4 Emissions from Landfills O-l
ANNEX P: Key Source Analysis P-l
ANNEX Q: Global Warming Potential Values Q-l
ANNEX R: Ozone Depleting Substance Emissions R-l
ANNEX S: Sulfur Dioxide Emissions S-l
ANNEXT: Complete List of Source Categories T-l
ANNEX U: IPCC Reference Approach for Estimating CO2 Emissions from Fossil Fuel Combustion U-l
ANNEX V: Sources of Greenhouse Gas Emissions Excluded V-l
ANNEX W: Constants, Units, and Conversions W-l
ANNEXX: Abbreviations X-l
ANNEXY: Chemical Formulas Y-l
ANNEXZ: Glossary Z-l
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List of Tables,
Figures, and Boxes
Tables
Table ES-l: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq.) ES-3
Table ES-2: Annual Change in CO2 Emissions from Fossil Fuel Combustion for Selected Fuels and
Sectors (TgCO2Eq. and Percent) ES-5
Table ES-3: Recent Trends in Various U.S. Data (Index 1990= 100) ES-7
Table ES-4: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO2 Eq. and Percent
of Total in 2000) ES-8
Table ES-5: U.S Greenhouse Gas Emissions by Economic Sector and Gas with Electricity-Related Emissions
Distributed (TgCO2Eq.) ES-9
Table ES-6: Comparison of 100 Year GWPs ES-10
TableES-7: Global Wanning Potentials (100 YearTime Horizon) ES-11
Table ES-8: U.S. Sources of CO2 Emissions and Sinks (TgCO2Eq.) ES-13
Table ES-9: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.) ES-15
Table ES-10: U.S. Sources of Methane Emissions (Tg CO2 Eq.) ES-18
Table ES-11: U.S. Sources of Nitrous Oxide Emissions (TgCO2Eq.) ES-21
TableES-12: Emissions of HFCs, PFCs, and SF6 (Tg CO2 Eq.) ES-23
Table ES-13: Emissions of Ozone Depleting Substances (Gg) ES-24
TableES-14: Emissions of NOx, CO, NMVOCs, and SO2 (Gg) ES-26
Table Changes-1: Revisions to U.S. Greenhouse Gas Emissions (Tg CO2 Eq.) Changes-2
Table Changes-2: Revisions to Net CO2 Sequestration from Land-Use Change and Forestry
(TgCO2Eq.) Changes-3
Table 1-1: Global atmospheric concentration (ppm unless otherwise specified), rate of concentration
change (ppb/year) and atmospheric lifetime (years) of selected greenhouse gases 1-4
Table 1-2: Global Warming Potentials and Atmospheric Lifetimes (Years) 1-7
Table 1-3: Comparison of 100 Year GWPs 1-8
Table 1-4: Effects on U.S. Greenhouse Gas Emission Trends Using IPCC SAR and TAR GWP Values
(TgCO2Eq.) Change from 1990 to 2000 Revisions to Annual Estimates 1-9
Table 1-5: Comparison of Emissions by Sector using IPCC SAR and TAR GWP Values (Tg CO2 Eq.) 1-9
Table 1-6: Annual Change in CO2 Emissions from Fossil Fuel Combustion for Selected Fuels and Sectors
(TgCO2Eq. and Percent) 1-11
Table 1-7: Recent Trends in Various U.S. Data (Index 1990= 100) 1-13
Table 1-8: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO2Eq.) 1-14
Table 1-9: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg) 1-15
Table 1-10: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector
(TgCO2Eq.) 1-16
Table 1-11: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (TgCO2Eq. andPercentof
Totalin2000) 1-18
Table 1-12: U.S Greenhouse Gas Emissions by "Economic Sector" and Gas with Electricity-Related
Emissions Distributed (Tg CO2 Eq.) and Percent of Total in 2000 1-20
Table 1-13: Electricity Generation-Related Greenhouse Gas Emissions (Tg CO2 Eq.) 1-21
Table 1-14: Transportation-Related Greenhouse Gas Emissions (Tg CO2 Eq.) 1-22
Table 1-15: IPCC Sector Descriptions 1-24
Table 1-16: List of Annexes 1-25
Table 2-1: Emissions from Energy (TgCO2Eq.) 2-2
Table2-2: Emissions from Energy (Gg) 2-2
Table 2-3: CO2 Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg CO2 Eq.) 2-4
vi Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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Table 2-4: Fossil Fuel Carbon in Products (TgCO2Eq.) 2-7
Table 2-5: CO2 Emissions from International Bunker Fuels (TgCO2Eq.) 2-7
Table 2-6: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (TgCO2Eq.) 2-8
Table 2-7: CO2 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg CO2 Eq.) .... 2-10
Table 2-8: Carbon Intensity from Direct Fossil Fuel Combustion by Sector (Tg CO2 Eq./EJ) 2-15
Table 2-9: Carbon Intensity from Energy Consumption by Sector (Tg CO2 Eq./EJ) 2-15
Table 2-10: Change in CO2 Emissions from Direct Fossil Fuel Combustion Since 1990 (Tg CO2 Eq.) 2-16
Table 2-11:2000 Non-Energy Fossil Fuel Consumption, Storage, and Emissions (Tg CO2 Eq. unless
otherwise noted) 2-20
Table 2-12: Storage andEmissions from Non-Energy Fossil Fuel Consumption (Tg CO2 Eq.) 2-20
Table 2-13: CH4 Emissions from Stationary Combustion (TgCO2Eq.) 2-23
Table 2-14: N2O Emissions from Stationary Combustion (TgCO2Eq.) 2-23
Table 2-15: CH4Emissions from Stationary Combustion (Gg) 2-24
Table 2-16: N2O Emissions from Stationary Combustion (Gg) 2-24
Table 2-17: NOX, CO, and NMVOC Emissions from Stationary Combustion in 2000 (Gg) 2-25
Table 2-18: CH4 Emissions from Mobile Combustion (TgCO2Eq.) 2-26
Table 2-19: N2O Emissions from Mobile Combustion (TgCO2Eq.) 2-26
Table 2-20: CH4 Emissions from Mobile Combustion (Gg) 2-27
Table 2-21: N2O Emissions from Mobile Combustion (Gg) 2-27
Table 2-22: NOX, CO, and NMVOC Emissions from Mobile Combustion in 2000 (Gg) 2-28
Table 2-23: CH4 Emissions from Coal Mining (TgCO2Eq.) 2-31
Table 2-24: CH4 Emissions from Coal Mining (Gg) 2-31
Table 2-25: Coal Production (Thousand Metric Tons) 2-33
Table 2-26: CH4 Emissions from Natural Gas Systems (TgCO2Eq.) 2-34
Table 2-27: CH4 Emissions from Natural Gas Systems (Gg) 2-34
Table 2-28: CH4 Emissions from Petroleum Systems (Tg CO2 Eq.) 2-36
Table 2-29: CH4 Emissions from Petroleum Systems (Gg) 2-36
Table 2-30: Uncertainty in CH4 Emissions from Production Field Operations (Gg) 2-38
Table 2-31: CO2 andN2O Emissions from Municipal Solid Waste Combustion (Tg CO2 Eq.) 2-39
Table 2-32: CO2 and N2O Emissions from Municipal Solid Waste Combustion (Gg) 2-39
Table 2-33: Municipal Solid Waste Generation (Metric Tons) and Percent Combusted 2-40
Table 2-34: U.S. Municipal Solid Waste Combusted by Data Source (Metric Tons) 2-41
Table 2-35: CO2 Emissions from Natural Gas Flaring 2-42
Table 2-36: NOx,NMVOCs, and CO Emissions from Oil and Gas Activities (Gg) 2-42
Table 2-37: Total Natural Gas Reported Vented and Flared (Million Ft3) and Thermal Conversion
Factor (Btu/Ft3) 2-42
Table 2-3 8 :CH4 Emissions from Non-Combustion Fossil Sources (Gg) 2-43
Table 2-39: Indirect CO2 Emissions from Non-Combustion Fossil Methane Sources (Gg) 2-44
Table 2-40: Indirect CO2 Emissions from Non-Combustion Fossil Methane Sources (Tg CO2 Eq.) 2-44
Table 2-41: Emissions from International Bunker Fuels (TgCO2Eq.) 2-47
Table 2-42: Emissions from International Bunker Fuels (Gg) 2-47
Table 2-43: Aviation Jet Fuel Consumption for International Transport (Million Gallons) 2-48
Table 2-44: Marine Fuel Consumption for International Transport (Million Gallons) 2-48
Table 2-45: CO2 Emissions from Wood Consumption by End-Use Sector (Tg CO2 Eq.) 2-50
Table 2-46: CO2 Emissions from Wood Consumption by End-Use Sector (Gg) 2-50
Table 2-47: CO2 Emissions fromEthanol Consumption 2-51
Table 2-48: Woody Biomass Consumption by Sector (Trillion Btu) 2-51
Table 2-49: Ethanol Consumption 2-51
Table 3-1: Emissions from Industrial Processes (TgCO2Eq.) 3-3
Table 3-2: Emissions from Industrial Processes (Gg) 3-4
Table 3-3: CO2 Emissions from Iron and Steel Production 3-4
Table 3-4: CO2 Emissions from Cement Production 3-6
Table 3-5: Cement Production (Gg) 3-7
Table 3-6: CO2 Emissions from Ammonia Manufacture 3-8
vii
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Table 3-7: Ammonia Manufacture 3-8
Table 3-8: CO2 Emissions from Lime Manufacture 3-9
Table 3-9: CO2 Emissions from Lime Manufacture (Gg) 3-9
Table 3-10: Lime Production and Lime Use for Sugar Refining and PCC (Thousand Metric Tons) 3-10
Table 3-1 l:Hydrated Lime Production (Thousand Metric Tons) 3-10
Table 3-12: CO2 Emissions from Limestone & Dolomite Use (TgCO2Eq.) 3-12
Table3-13:CO2 Emissions from Limestone & Dolomite Use (Gg) 3-12
Table 3-14: Limestone and Dolomite Consumption (Thousand Metric Tons) 3-13
Table 3-15: Dolomitic Magnesium Metal Production Capacity (Metric Tons) 3-13
Table 3-16: CO2 Emissions from Soda Ash Manufacture and Consumption 3-14
Table 3-17: CO2 Emissions from Soda Ash Manufacture and Consumption (Gg) 3-14
Table 3-18: Soda Ash Manufacture and Consumption (Thousand Metric Tons) 3-15
Table3-19:CO2 Emissions from Ferroalloy Production 3-16
Table 3-20: Production of Ferroalloys (Metric Tons) 3-17
Table 3-21 :CO2 Emissions from Titanium Dioxide 3-17
Table 3-22: Titanium Dioxide Production 3-18
Table 3-23: CO2 Emissions from Carbon Dioxide Consumption 3-19
Table 3-24: Carbon Dioxide Consumption 3-19
Table 3-25: CH4 Emissions from Petrochemical Production 3-20
Table 3-26: Production of Selected Petrochemicals (Thousand Metric Tons) 3-20
Table 3-27: CH4Emissions from Silicon Carbide Production 3-20
Table 3-28: Production of Silicon Carbide 3-21
Table 3-29: N2O Emissions from Adipic Acid Production 3-22
Table 3-30: Adipic Acid Production 3-22
Table 3-31:N2O Emissions from Nitric Acid Production 3-23
Table 3-32: Nitric Acid Production 3-24
Table 3-33: Emissions of HFCs andPFCs from ODS Substitution (Tg CO2 Eq.) 3-24
Table 3-34: Emissions of HFCs and PFCs from ODS Substitution (Mg) 3-25
Table 3-35: CO2 Emissions from Aluminum Production 3-26
Table 3-36: PFC Emissions from Aluminum Production (TgCO2Eq.) 3-26
Table 3-37: PFC Emissions from Aluminum Production (Gg) 3-27
Table 3-38: Production of Primary Aluminum 3-28
Table 3-39: HFC-23 Emissions from HCFC-22 Production 3-29
Table 3-40: HCFC-22 Production 3-29
Table 3-41: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Tg CO2 Eq.) 3-31
Table 3-42: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Mg) 3-31
Table 3-43: SF6 Emissions from Electrical Transmission and Distribution 3-32
Table 3-44: SF6 Emissions from Magnesium Production and Processing 3-33
Table 3-45:2000 Potential and Actual Emissions of HFCs, PFCs, and SF6 from Selected Sources
CTgC02Eq.) 3-34
Table 3-46: NOX, CO, and NMVOC Emissions from Industrial Processes (Gg) 3-35
Table 4-1: Emissions of NOX, CO, and NMVOC from Solvent Use (Gg) 4-2
Table 5-1: Emissions from Agriculture (TgCO2Eq.) 5-2
Table 5-2: Emissions from Agriculture (Gg) .'..5-2
Table 5-3: CH4 Emissions from Enteric Fermentation (TgCO2Eq.) 5-3
Table 5-4: CH4 Emissions from Enteric Fermentation (Gg) 5-3
Table 5-5: CH4 and N2O Emissions from Manure Management (TgCO2Eq.) 5-7
Table 5-6: CH4 and N2O Emissions from Manure Management (Gg) 5-7
Table 5-7: CH4 Emissions fromRice Cultivation (TgCO2Eq.) 5-12
Table 5-8: CH4 Emissions from Rice Cultivation (Gg) 5-12
Table 5-9: Rice Areas Harvested (Hectares) 5-12
Table 5-10: N2O Emissions from Agricultural Soil Management (TgCO2Eq.) 5-15
Table 5-11:N2O Emissions from Agricultural Soil Management (Gg) 5-15
\riii Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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Table 5-12: DirectN2O Emissions from Managed Soils (TgCO2Eq.) 5-16
Table 5-13: Direct N2O Emissions from Pasture, Range, and Paddock Livestock Manure (Tg CO2 Eq.) 5-16
Table 5-14: IndirectN2O Emissions (TgCO2Eq.) 5-16
Table 5-15: Emissions from Agricultural Residue Burning (TgCO2Eq.) 5-20
Table 5-16: Emissions from Agricultural Residue Burning (Gg) 5-21
Table 5-17: Agricultural Crop Production (Thousand Metric Tons of Product) 5-22
Table 5-18: Percentage of Rice AreaBurned by State 5-22
Table 5-19: Percentage of Rice Area Burned in California 5-22
Table 5-20: Key Assumptions for Estimating Emissions from Agricultural Residue Burning 5-23
Table 5-21: Greenhouse Gas Emission Ratios 5-23
Table 6-1: Net CO2 Flux from Land-Use Change and Forestry (Tg CO2 Eq.) 6-2
Table 6-2: Net CO2 Flux from Land-Use Change and Forestry (Tg C) 6-2
Table 6-3: Net CO2Flux from U.S. Forests (TgCO2Eq.) 6-5
Table 6-4: Net CO2 Flux from U.S. Forests (Tg C) 6-5
Table 6-5: U.S. Forest Carbon Stock Estimates (TgC) 6-8
Table 6-6: Net CO2 Flux From Urban Trees (TgCO2Eq.) 6-9
Table 6-7: Carbon Storage (Metric Tons C), Carbon Sequestration (Metric Tons C/yr),
and Tree Cover(%) for Ten U.S. Cities 6-10
Table 6-8: Annual Sequestration per Area of Tree Cover (kg C/m2 cover-year) 6-10
Table 6-9: Net CO2 Flux From Agricultural Soils (Tg CO2 Eq.) 6-12
Table 6-10: Mineral Soil Areas by Land-Use Category andlPCC Climatic Region (million hectares)a 6-15
Table 6-11: Mineral Soil Areas by Land-Use Category and IPCC Mineral Soil Category
(thousand hectares)a 6-16
Table 6-12: Tillage Percentages by Management Category and IPCC Climatic Zonea 6-17
Table 6-13: Organic Soil Areas by IPCC Land-Use Category and Climatic Region (thousand hectares)a 6-18
Table 6-14: Quantities of Applied Minerals (Thousand Metric Tons) .' 6-18
Table 6-15: Net CO2Flux from LandfiUed Yard Trimmings 6-21
Table 6-16: Storage Factor (kg C/kg dry yard trimmings) Moisture Content (kg water/kg wet yard trimmings),
Composition (percent) and Converted Storage Factor (kg C/kg wet yard trimmings) of
LandfiUed Yard Trimmings 6-21
Table 6-17: Collection and Destination of Yard Trimmings (Million Metric Tons, wet) 6-22
Table 7-1: Emissions from Waste (TgCO2Eq.) 7-2
Table 7-2: Emissions from Waste (Gg) ,. 7-2
Table 7-3 :CH4 Emissions from Landfills (TgCO2Eq.) 1 7-4
Table 7-4: CH4 Emissions from Landfills (Gg) 7-4
Table 7-6: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Gg) 7-6
Table 7-5: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Tg CO2 Eq.) 7-6
Table 7-7: U.S. Population (Millions) and Wastewater BOD Produced (Gg) 7-7
Table 7-8: U.S. Pulp and Paper, Meat and Poultry, and Vegetables, Fruits and Juices Production
(Million Metric Tons) 7-7
Table 7-9: N2O Emissions from Human Sewage '. 7-8
Table 7-10: U.S. Population (Millions) and Average Protein Intake (kg/Person/Year) ..'. 7-9
Table 7-11: Emissions of NOX, CO, and NMVOC from Waste (Gg) 7-10
Figures
Figure ES-l: U.S. GHGEmissions by Gas ES-2
Figure ES-2: Annual Percent Change in U.S. GHG Emissions ES-4
Figure ES-3:2000 Greenhouse Gas Emissions by Gas ES^
Figure ES-4: Absolute Change in U.S. GHG Emissions Since 1990 ES-4-
Figure ES-5: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product ES-7
Figure ES-6: Emissions Allocated to Economic Sectors ES-8
Figure ES-7: Emissions with Electricity Distributed to Economic Sectors ES-9
IX
-------
Figure ES-8: U.S. Carbon Hows for 2000 ES-12
Figure ES-9:2000 Sources of CO2 2000 U.S. Energy Consumption by Energy Source ES-12
Figure ES-10:2000 Sources of CH4 ES-12
Figure ES-11: U.S. Energy Consumption (Quadrillion Btu) ES-13
Figure ES-12:2000 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type ES-14
Figure ES-13:2000 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion ES-14
Figure ES-14:2000 Sources of CH4 ES-18
Figure ES-15:2000 Sources of N2O 2000 Sources of HFCs, PFCs, and SF6 ES-20
Figure ES-16: Sources of HFCs.PFCs, and SF6 ES-22
^
Figure 1-1: U.S. GHG Emissions by Gas 1-10
Figure 1-2: Annual Percent Change in U.S. GHG Emissions 1-11
Figure 1-3: Absolute Change in U.S. GHG Emissions Since 1990 1-11
Figure 1-4: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product 1-13
Figure 1-5: U.S. GHG Emissions by Chapter/IPCC Sector 1-16
Figure 1-6: Emissions Allocated to Economic Sectors, 1990-2000 1-17
Figure 1-7: U.S. Greenhouse Gas Emissions with Electricity Distributed to Economic Sectors, 1990-2000.... 1-21
Figure 2-1:2000 Energy Chapter GHG Sources 2-1
Figure 2-2:2000 U.S. Fossil Carbon Flows 2-3
Figure 2-3:2000 U.S. Energy Consumption by Energy Source 2-5
Figure 2-4: U.S. Energy Consumption (Quadrillion Btu) 2-5
Figure 2-5:2000 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type 2-5
Figure 2-6: Annual Deviations from Normal Heating Degree Days for the United States (1949-2000) 2-6
Figure 2-7: Annual Deviations fromNormal Cooling Degree Days for the United States (1949-2000) 2-6
Figure 2-8: Nuclear and Hydroelectric Power Plant Capacity Factors in the United States (1973-2000) 2-7
Figure 2-9:2000 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion 2-9
Figure 2-10: Motor Gasoline Retail Prices (Real) 2-9
Figure 2-11: Motor Vehicle Fuel Efficiency 2-9
Figure2-12: Industrial Production Indexes (Index 1992=100) 2-11
Figure 2-13: Heating Degree Days 2-12
Figure 2-14: Cooling Degree Days 2-12
Figure 2-15: Electricity Generation Retail Sales by End-Use Sector 2-13
Figure 2-16: Net Generation by Electric Utilities and Nonutilities 2-13
Figure 2-17: U.S. Energy Consumption and Energy-Related CO2 Emissions Per Capita and Per Dollar GDP 2-15
Figure2-18: Change in CO2 Emissions from Fossil Fuel Combustion Since 1990 by End-Use Sector 2-15
Figure 2-19: Mobile Source CH4 and N2O Emissions 2-28
Figure 3-1:2000 Industrial Processes Chapter GHG Sources 3-1
Figure5-l: 2000 Agriculture Chapter GHG Sources 5-1
Figure 5-2: Direct and Indirect N2O Emissions from Agricultural Soils 5-15
Figure 6-1: Forest Sector Carbon Pools and Flows 6-3
Figure 6-2: Forest Carbon Stocks 1997 6-8
Figure 6-3: Net Annual CO2 Flux From Mineral Soils Under Agricultural Management, 1990-1992
(metric ton C/ha) 6-13
Figure 6-4: Net Annual CO2 Flux From Mineral Soils Under Agricultural Management, 1993-1997
(metric ton C/ha) 6-13
Figure 6-5: Net Annual CO2Flux From Organic Soils Under Agricultural Management, 1990-1992
(metric ton C/ha) 6-14
Figure 6-6: Net Annual CO2Flux From Organic Soils Under Agricultural Management, 1993-2000
(metric ton C/ha) 6-14
Figure 7-1:2000 Waste Chapter GHG Sources 7-1
x Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Boxes
BoxES-l: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data ES-7
BoxES-2: The IPCC Third Assessment Report and Global Warming Potentials ES-10
BoxES-3: Emissions of Ozone Depleting Substances ES-24
BoxES-4: Sources and Effects of Sulfur Dioxide ES-25
Box 1-1: The IPCC Third Assessment Report and Global Warming Potentials 1-8
Box 1-2: RecentTrends in Various U.S. Greenhouse Gas Emissions-Related Data 1-13
Box 1-3: IPCC Good Practice Guidance 1-23
Box 2-1: Weather and Non-Fossil Energy Effects on CO2 from Fossil Fuel Combustion Trends 2-6
Box 2-2: Sectoral Carbon Intensity Trends Related to Fossil Fuel and Overall Energy Consumption 2-14
Box 2-3: Biogenic Emissions and Sinks of Carbon 2-39
Box 3-1: Potential Emission Estimates of HFCs, PFCs, and SF6 3-34
Box 6-1: Estimating Uncertainty Using aRevised IPCC Approach 6-19
Box 6-2: Century Model Estimates of Soil Carbon Stock Changes on Cropland 6-20
Box 7-1: Biogenic Emissions and Sinks of Carbon 7-2
Box 7-2: Recycling and Greenhouse Gas Emissions and Sinks 7-3
xi
-------
-------
Executive Summary
Central to any study of climate change is the development of an emissions inventory that identifies and quantifies
a country's primary anthropogenic1 sources and sinks of greenhouse gases. This inventory adheres to both 1)
a comprehensive and detailed methodology for estimating sources and sinks of anthropogenic greenhouse gases, and 2) a
common and consistent mechanism that enables signatory countries to the United Nations Framework Convention on
Climate Change (UNFCCC) to compare the relative contribution of different emission sources and greenhouse gases to
climate change. Moreover, systematically and consistently estimating national and international emissions is a prerequisite
for accounting for reductions and evaluating mitigation strategies.
In June of 1992, the United States signed, and later ratified in October, the UNFCCC. The objective of the UNFCCC
is "to achieve.. .stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous
anthropogenic interference with the climate system."2
By signing the Convention, Parties make commitments "to develop, periodically update, publish and make
available.. .national inventories of anthropogenic emissions by sources and removals by sinks of all greenhouse gases not
controlled by the Montreal Protocol, using comparable methodologies..."3 The United States views this report as an
opportunity to fulfill this commitment.
This chapter summarizes the latest information on U.S. anthropogenic greenhouse gas emission trends from 1990
through 2000. To ensure that the U.S. emissions inventory is comparable to those of other UNFCCC signatory countries,
the estimates presented here were calculated using methodologies consistent with those recommended in the Revised
1996IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA1997) and the Good Practice
Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2000). For most source categories,
the IPCC default methodologies were expanded, resulting in a more comprehensive and detailed estimate of emissions.
Naturally occurring greenhouse gases include water vapor, carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O),
and ozone (O3). Several classes of halogenated substances that contain fluorine, chlorine, or bromine are also greenhouse
gases, but they are, for the most part, solely a product of industrial activities. Chlorofluorocarbons (CFCs) and
hydrochlorofluorocarbons (HCFCs) are halocarbons that contain chlorine, while halocarbons that contain bromine are
referred to as bromofluorocarbons (i.e., halons). Because CFCs, HCFCs, and halons are stratospheric ozone depleting
substances, they are covered under the Montreal Protocol on Substances that Deplete the Ozone Layer. The UNFCCC
1 The term "anthropogenic", in this context, refers to greenhouse gas emissions and removals that are a direct result of human activities or are the
result of natural processes that have been affected by human activities (IPCC/UNEP/OECD/IEA 1997).
2 Article 2 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change. See .
3 Article 4 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change (also identified in
Article 12). See .
Executive Summary ES-1
-------
defers to this earlier international treaty; consequently these
gases are not included in national greenhouse gas
inventories.4 Some other fluorine containing halogenated
substances—hydrofluorocarbons (HFCs), perfluorocarbons
(PFCs), and sulfur hexafluoride (SF6)—do not deplete
stratospheric ozone but are potent greenhouse gases. These
latter substances are addressed by the UNFCCC and
accounted for in national greenhouse gas inventories.
There are also several gases that do not have a direct
global warming effect but indirectly affect terrestrial and/
or solar radiation absorption by influencing the formation
or destruction of other greenhouse gases, including
tropospheric and stratospheric ozone. These gases include
carbon monoxide (CO), oxides of nitrogen (NOx), and
nonmethane volatile organic compounds (NMVOCs).
Aerosols, which are extremely small particles or liquid
droplets, such as those produced by sulfur dioxide (SO2) or
elemental carbon emissions, can also affect the absorptive
characteristics of the atmosphere.
Although the direct greenhouse gases CO2, CH4, and
N2O occur naturally in the atmosphere, their atmospheric
concentrations have been affected by human activities.
Since pre-industrial time (i.e., about 1750), concentrations
of these greenhouse gases have increased by 31, 150, and
16 percent, respectively (D?CC 2001). According to the
IPCC, the current concentration of CO2 and CH4 in the
atmosphere has not been exceeded in the last 420,000 years.
Additionally, the rate of increase of CO2 in the atmosphere
in the past century has been unprecedented in the last 20,000
years. This build-up has altered the chemical composition
of the earth's atmosphere, and therefore effected the global
climate system.
Beginning in the 1950s, the use of CFCs and other
stratospheric ozone depleting substances (ODSs) increased
by nearly 10 percent per year until the mid-1980s, when
international concern about ozone depletion led to the
signing of the Montreal Protocol. Since then, the production
of ODSs is being phased out. In recent years, use of ODS
substitutes such as HFCs and PFCs has grown as they begin
to be phased in as replacements for CFCs and HCFCs.
Accordingly, atmospheric concentrations of these substitutes
have been growing (IPCC 2001).
Recent Trends in U.S.
Greenhouse Gas Emissions
In 2000, total U.S. greenhouse gas emissions rose to
7,001.2 teragrams of carbon dioxide equivalents (Tg CO2
Eq.)5 (14.2 percent above 1990 emissions). The single year
increase in emissions from 1999 to 2000 was 2.5 percent
(171.7 Tg CO2 Eq.), which was greater than the average
annual rate of increase for 1990 through 2000 (1.3 percent).
The higher than average increase in emissions in 2000 was,
in part, attributable to the following factors: 1) robust
economic growth in 2000, leading to increased demand for
electricity and transportation fuels, 2) cooler winter
conditions compared to the previous two years, and 3)
decreased output from hydroelectric dams. (See following
section for an analysis of emission trends by general
economic sectors).
Figure ES-1 through Figure ES-3 illustrate the overall
trends in total U.S. emissions by gas, annual changes, and
absolute change since 1990. Table ES-1 provides a detailed
summary of U.S. greenhouse gas emissions and sinks for
1990 through 2000.
Figure ES-1
• HFCs, PFCs, & SF6
• Nitrous Oxide
• Methane
s Carbon Dioxide
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
!
4 Emissions estimates of CFCs, HCFCs, halons and other ozone-depleting substances are included in this document for informational purposes.
5 Estimates are presented in units of teragrams of carbon dioxide equivalents (Tg CO2 Eq.), which weight each gas by its Global Warming Potential,
or GWP, value. (See the following section on Global Warming Potentials, in Executive Summary or Chapter 1.)
ES-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table ES-1: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg C02 Eq.)
CGas/Sotirce
1990
1995
1996
1997
1998
1999
jfe-f'gqes not .exceed 0.05 Tg C02 Eq.
£-7* (Sinks are only included jn net emissions total, and are based partially on projected activity data.
y." Emissions from International Bunker Fuels are not included in totals.
JlNote: Totals_may not sum due to independent rounding.
' ' '
2000
tC02 ' ' " ' ' :'; ' "'
£ Fossil Fuel Combustion. _ ,
p Iron and Steel Production,
fe Cement Manufacture
F7' Indirect CO? from CH4 Oxidation
g=BT-'. .---'- , CL , _. 4 __
f~ Waste Combustion
p Ammonia Manufacture
1: Lime Manufacture
fc^ Limestone and Dolomite Use
&.. Natural Sas Flaring
!~ Aluminum Production
- -. ... -— §
4,998.5 *
4,779.8
85.4
33.3
30.9
14.1
18.5
11.2
5.2
5.5
. 6.3. i
p: Soda Ash Manufacture and Consumption 4.1 f
pr Titanium Dioxide Production
^..Ferroalloys
rr Carbon Dioxide Consumption
p= Land-Use Change and Forestry (Sink)a
;_ International Bunker Fuels'5
FCH4
f Landfills
t Enteric Fermentation
-~ Natural Gas Systems
1- Coal Mining
^ Manure Management
ft Wastewater Treatment
§>-•; Petroleum Systems
fc Stationary Sources
|i : Rice Cultivation
l Mobile Sources
I Petrochemical Production
|__ Agricultural Residue Burning
jP Silicon Carbide Production
1 - International Bunker Fuels'5
CN20
jr.- Agricultural Soil Management
fr \MobiJiSources '""' ""'" """.'". , .!...
i: Nitric Acid
&••• Manure Management \
p= .Stationary Sources
ti Human Sewage
£-, AdipicAcid
i;'. Agricultural Residue Burning
£- Waste Combustion
S International Bunker Fuelsb
MFCs, PFCs, and SF6
1.3 I
2.0
0.8
(1,097.7)
113.9
651.3
213.4
127.9
121.2
87.1 I
29.2 i
24.3
26.4
7.9 I
7.1 S
4.9 1
1.2
"""07 I
+ 1
0.2 I
387.3 !
267.1
... 50.9 1
. 17.8 .
16.0 !
12.8
7.0
14.9
0.4
0.3 j
1.0
93.6
;: Substitution of Ozone Depleting Substances 0.9 j
JL- HCFC-22 Production
J- Electrical Transmission and Distribution
t Aluminum Production
f: Semiconductor Manufacture
t Magnesium Production and Processing
feTotal
Net Emissions (Sources and Sinks)
35.0
31.2
18.1
2.9
5.5 j
6,130.7 I
5,033.0 *
S 5,305.9
S 5,085.0
74.4
^^^^» OC Q
OD.O
^Sr^^l ~ OA c
HOC
18-9
12.8
7.0
VM^ "'*' 0. /
iafl '• 5-3
43
rfg,^^ ''^
^^ 1 - J -i
^9 '19
1 .0
Sftp,(1 ,1 1 0.0)
101 0
El 657.6
S 216.6
III 133-2
fcl 1257
H 73'5
B 26-8
S 24.2
S ' 8-2
B 7.6
Us! 4-8
Bl ' 1-5"
+
• 0.1
P^*! 419.8
BR3 283.4
S 60.4
H 19.9
13 ' 16.4
13.5
ra 7.7
fiP 17'9
?imi-Ti't,.';,'P U.T"
S 0.3
Ba 0.9
fcl 98-5
^ 21.8
SI 27.0
SI 26.5
jj3 "11.8
c c
°.°
1^"* 5^371 .8
5,483.7
5,266.6
68.3
37.1
28.9
19.6
19.5
13.5
7.4
8.2
5.6
4.2
1.7
2.0
1.1
(1,108.1)
102.3
643.7
211.5
129.6
126.6
68.4
34.2
27.0
24.0
8.4
7.0
4.7
""• 1.6
0.7
+
0.1
430.5
292.6
60.1
20.7
16.8
14.1
7.8
17.8
0.4
0.3
0.9
111.9
30.6
31.1
26.8
12.5
5.4
5.5
6,669.8
5,561.7
5,568.0
5,339.6
76.1
38.3
28.4
21.3
19.5
13.7
8.4
7.6
5.6
4.4
1.8
2.0
1.3
(887.5)
109.9
633.3
206.4
126.8
122.7
68.1
35.8
27.5
24.0
7.5
7.5
4.6
1.6
0.8
+
0.1
429.8
297.5
59.7
21.2
17.1
14.2
7.9
11.5
0.4
0.3
.1.0
116.9
38.0
30.0
24.5
11.0
6.5
6.9
6,748.1
5,860.5
5,575.1
5,356.2
67.4
39.2
28.2
20.3
20.1
13.9
8.2
6.3
5.8
4.3
1.8
2.0
1.4
(885.9)
112.9
627.1
201.0
124.9
122.2
67.9
38.0
27.8
23.4
7.0
7.9
4.5
1.6
0.8
+
0.1
426.3
298.4
59.1
20.9
17.1
14.3
8.1
7.7
0.5
0.2
1.0
127.7
44.9
40.2
20.1
9.0
7.3
6.2
6,756.2
5,870.3
5,665.5
5,448.6
64.4
40.0
27.0
21.8
18.9
13.5
9.1
6.7
5.9
4.2
1.9
2.0
1.6
(896.4)
105.3
620.5
203.1
124.5
118.6
63.7
37.6
28.3
22.3
7.3
8.3
4.4
1.7
0.8
+
0.1
423.5
296.3
58.7
20.1
17.1
14.6
8.4
7.7
0.4
0.2
0.9
120.0
51.3
30.4
15.5
8.9
7.7
6.1
6,829.5
5,933.1
5,840.0
5,623.3
65.7
41.1
26.3
22.5
18.0
13.3
9.2
6.1
5.4
4.2
2.0
1.7
1.4
(902.5)
100.2
614.5
203.5
123.9
116.4
61.0
37.5
28.7
21.9
7.5
7.5
4.4
1.7
0.8
+
0.1
425.3
297.6
58.3
19.8
17.5
14.9
8.5
8.1
0.5
0.2
0.9
121.3
57.8
29.8
14.4
7.9
7.4
4.0
7,001.2
6,098.7
Parentheses indicate negative values (or sequestration). '.
Executive Summary ES-3
-------
Figure ES-2
Figure ES-4
mmSMmmm^-
2.9%
2.5%
1.7%HFCs, PFCs&SF6
6.1%N2O
8.7% CH4
83.5% CO2
Figure ES-3
Figure ES-4 illustrates the relative contribution of the
direct greenhouse gases to total U.S. emissions in 2000.
The primary greenhouse gas emitted by human activities in
the United States was CO2. The largest source of CO2, and
of overall greenhouse gas emissions, was fossil fuel
combustion. Methane emissions resulted primarily from
decomposition of wastes in landfills, enteric fermentation
associated with domestic livestock, and natural gas systems.
Emissions of N,O were dominated by agricultural soil
management and mobile source fossil fuel combustion. The
emissions of substitutes for ozone depleting substances and
emissions of HFC-23 during the production of HCFC-22
were the primary contributors to aggregate HFC emissions.
Electrical transmission and distribution systems accounted
for most SF6 emissions, while the majority of PFC emissions
were a by-product of primary aluminum production.
As the largest source of U.S. greenhouse gas emissions,
CO2 from fossil fuel combustion accounted for a nearly
constant 79 percent of global warming potential (GWP)
weighted emissions from 1990 to 2000.6 Emissions from
this source category grew by 18 percent (843.4 Tg CO2Eq.)
from 1990 to 2000 and were responsible for most of the
increase in national emissions during this period. The annual
increase in CO2 emissions from fossil fuel combustion was
3.2 percent in 2000, double the source's average annual
rate of 1.6 percent from 1990 through 2000. Historically,
changes in emissions from fossil fuel combustion have been
the dominant factor affecting U.S. emission trends.
Changes in CO2 emissions from fossil fuel combustion
are influenced by many long-term and short-term factors,
including population and economic growth, energy price
fluctuations, technological changes, and seasonal
temperatures. On an annual basis, the overall consumption
of fossil fuels in the United States and other countries
generally fluctuates in response to changes in economic
conditions, energy prices, weather, and the availability of
non-fossil alternatives. For example, a year with increased
consumption of goods and services, low fuel prices, severe
summer and winter weather conditions, nuclear plant
closures, and lower precipitation feeding hydroelectric dams
would be expected to have proportionally greater fossil fuel
6 If a full accounting of emissions from fossil fuel combustion is made by including emissions from the combustion of international bunker fuels and
CHj and N2O emissions associated with fuel combustion, then this percentage increases to a nearly constant 80 percent during the 1990s.
ES-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
consumption than a year with poor economic performance,
high fuel prices, mild temperatures, and increased output
from nuclear and hydroelectric plants.
Longer-term changes in energy consumption patterns,
however, tend to be more a function of changes that affect
the scale of consumption (e.g., population, number of cars,
and size of houses), the efficiency with which energy is
used in equipment (e.g., cars, power plants, steel mills, and
light bulbs) and consumer behavior (e.g., walking, bicycling,
or telecommuting to work instead of driving).
Energy-related CO2 emissions are also a function of
the type fuel or energy consumed and its carbon intensity.
Producing heat or electricity using natural gas instead of
coal, for example, can reduce the CO2 emissions associated
with energy consumption because of the lower carbon
content of natural gas per unit of useful energy produced.
Table ES-2 shows annual changes in emissions during the
last few years of the 1990s for selected fuel types and
sectors.
Carbon dioxide emissions from fossil fuel combustion
grew rapidly in 1996, due primarily to two factors: 1) fuel
switching by electric utilities from natural gas to more
carbon intensive coal as colder winter conditions and the
associated rise in demand for natural gas from residential
and commercial customers for heating caused gas prices to
rise sharply; and 2) higher consumption of petroleum fuels
for transportation. Milder weather conditions in summer
and winter moderated the growth in emissions in 1997;
however, the shut-down of several nuclear power plants lead
electric utilities to increase their consumption of coal and
other fuels to offset the lost nuclear capacity.
In 1998, weather conditions were again a dominant
factor in slowing the growth in emissions. Warm winter
temperatures resulted in a significant drop in residential and
commercial natural gas consumption. This drop in
emissions from natural gas used for heating was primarily
offset by two factors: 1) electric utility emissions, which
increased in part due to a hot summer and its associated air
conditioning demand; and 2) increased motor gasoline
consumption for transportation.
In 1999, the increase in emissions from fossil fuel
combustion was driven largely by growth in petroleum
consumption for transportation. In addition, residential and
commercial heating fuel demand partially recovered as
winter temperatures dropped relative to 1998, although
temperatures were still warmer than normal.7 These
increases were offset, in part, by a decline in emissions from
electric power producers due primarily to: 1) an increase in
net generation of electricity by nuclear plants to record
levels, which reduced demand from fossil fuel plants; and
2) moderated summer temperatures compared to the
previous year-thereby reducing electricity demand for air
conditioning.
Emissions from fuel combustion increased considerably
in 2000, due to several factors. The primary reason for the
increase was the robust U.S. economy, which produced a
Table ES-2: Annual Change in C02 Emissions from Fossil Fuel Combustion for
Selected Fuels and Sectors (Tg C02 Eq. and Percent)
Sector
*- Electricity Generation
- Electricity Generation
"_ Electricity Generation
^Transportation3
r Residential
' Commercial
Industrial
f- Industrial
% All Sectors'1
Fuel Type
Coal
Natural Gas
Petroleum
Petroleum
Natural Gas
Natural Gas
Coal
Natural Gas
All Fuels'1
1995to1996
91.2
(24.3)
5.0
38.7
21.4
7.0
(5.7)
16.3
181.6
5.5%
-8.8%
7.8%
2.5%
8.1%
4.3%
-4.4%
4.1%
3.6%
1996 to 1997
49.9
17.9
8.9
7.6
(14.0)
3.1
1.4
(5.2)
72.9
2.9%
7.1%
12.9%
0.5%
-4.9%
1.8%
1.1%
-1.3%
1.4%
1997 to 1998
28.0
32.4
28.1'
32.7
(24.0)
(11.1)
(5.6)
(31.6)
16.6
1.6%
12.0%
35.8%
2.1%
-8.9%
-6.4%
-4.4%
-7.7%
0.3%
1998 to 1999
11.1
7.5
1.2
68.0
10.0
1.7
(4.4)
(5.0)
92.4
0.6%
2.5%
1.2%
4.2%
4.0%
1.0%
-3.6%
-1.3%
1.7%
1999to2000
87.3
31.5
(12.5)
59.6
11.8
15.6
(14.1)
(1.6)
174.7
4.8% '
10.2%
-11.6%
3.5%
4.6%
9.4%
-12.1%
-0.4%
3.2%
a Excludes emissions from International Bunker Fuels.
b Includes fuels and sectors not shown in table.
7 Normal is calculated as the average of the years 1961 through 1990.
Executive Summary ES-5
-------
high demand for fuels—especially for petroleum in the
transportation sector—despite increases in the price of both
natural gas and petroleum. Colder winter conditions relative
to the previous year triggered a rise in residential and
commercial demand for heating. Structural and other
economic changes taking place within U.S. industry—
especially manufacturing—lead to lower coal consumption.
Additionally, electricity generation became more carbon
intensive as coal and natural gas consumption offset reduced
hydropower output. In sum, emissions from fossil fuel
combustion exhibited the second highest annual increase
since 1990.
Overall, from 1990 to 2000, total emissions of CO2 and
N2O increased by 841.5 (17 percent) and 38.0 Tg CO2 Eq.
(10 percent), respectively, while CH4 emissions decreased
by 36.8 Tg CO2 Eq. (6 percent). During the same period,
aggregate weighted emissions of HFCs, PFCs, and SF6 rose
by 27.7 Tg CO2 Eq. (30 percent). Despite being emitted in
smaller quantities relative to the other principal greenhouse
gases, emissions of HFCs, PFCs, and SF6 are significant
because many of them have extremely high global warming
potentials and, in the cases of PFCs and SF6, long
atmospheric lifetimes. Conversely, U.S. greenhouse gas
emissions were partly offset by carbon sequestration in
forests and in landfilled carbon, which were estimated to
be 13 percent of total emissions in 2000.
Other significant trends in emissions from additional
source categories over the eleven year period from 1990
through 2000 included the following:
• Aggregate HFC and PFC emissions resulting from the
substitution of ozone depleting substances (e.g., CFCs)
increased by 56.8 Tg CO2 Eq. This increase was
significantly offset, however, by reductions in PFC
emissions from aluminum production (10.2 Tg CO2 Eq.
or 56 percent), reductions hi emissions of HFC-23 from
the production of HCFC-22 (5.2 Tg CO2 Eq. or 15
percent), and reductions of SF6 from electric power
transmission and distribution systems (16.8 Tg CO2 Eq.
or 54 percent). Reductions in PFC emissions from
aluminum production were the result of both industry
emission reduction efforts and lower domestic
aluminum production. HFC-23 emissions from the
production of HCFC-22 decreased due to a reduction
in the intensity of emissions from that source, despite
increased HCFC-22 production. Reduced emissions of
SF6 from electric power transmission and distribution
systems are primarily the result of higher purchase prices
for SF6 and efforts by industry to reduce emissions.
• Methane emissions from coal mining dropped by 26.2
Tg CO2 Eq. (30 percent) as a result of the mining of
less gassy coal from underground mines and the
increased use of methane from degasification systems.
• Nitrous oxide emissions from agricultural soil
management increased by 30.5 Tg CO2 Eq. (11 percent)
as fertilizer consumption and cultivation of nitrogen
fixing crops rose.
• By 1998, all of the three major adipic acid producing
plants had implemented N2O abatement technology, and
as a result, emissions fell by 6.8 Tg CO2 Eq. (46
percent). The majority of this decline occurred from
1997 to 1998, despite increased production.
• Carbon dioxide emissions from feedstock uses of coal
coke for iron and steel production decreased by 19.7
Tg CO2 Eq. (23 percent), as imports of steel have
increased.
• Methane emissions from U.S. landfills decreased 5
percent, as the amount of landfill gas collected and
combusted by landfill operators has increased.
• Emissions of N2O from mobile combustion rose by 7.4
Tg CO2 Eq. (14 percent), primarily due to an increased
average N2O generation rate for the U.S. highway
vehicle fleet.
ES-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Box ES-1: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data
~ There are several ways to assess a nation's greenhouse gas emitting intensity. The basis for measures of intensity can be 1) per
i" unit of aggregate energy consumption, because energy-related activities are the largest sources of emissions; 2) per unit of fossil fuel
frTconsumption, because almost all energy-related emissions involve the combustion of fossil fuels; 3) per unit of electricity consumption,
|_because the electric power industry has been the largest source of U.S. greenhouse gas emissions in the United States; 4) per unit of
If total gross domestic product as a measure of national economic activity; or 5) on a per capita basis. Depending upon the measure used, ;
jLthe United States could appear to have reduced or increased its national greenhouse gas intensity during the 1990s.
m=:'' table ES-3 provides data on various statistics related to U.S. greenhouse gas emissions normalized to 1990 as a baseline year.
t Greenhouse gas emissions in the U.S. have grown at an average annual rate of 1.3 percent since 1990. This rate is slightly slower than
||that for total energy or fossil fuel consumption—thereby indicating an improved or lower greenhouse gas emitting intensity—and much "
Irslower than that for either electricity consumption or overall gross domestic product. At the same time, total U.S. greenhouse gas
ti emissions have grown at about the same rate as national population during the last decade (see Figure ES-5). Overall, global atmo-
fcspheric C02 concentrations—a function of many complex anthropogenic and natural processes—are increasing at 0.4 percent per year.
'Table ES-3: Recent Trends in Various U.S. Data (Index 1990 = 100)
I Variable 1991
|; 6H6 "Emissions3
EJEnergy Consumption15
f Fossil FueLConsujmptionb
^Electricity Consumption11
repp"
|_ Population11
kGiobal Atmospheric C02
|; Concentration6
!p 6WP weighted values
jt=.b. Energy content weighted values
99
100
99
102
100
101
100 ...
1992
101
101
""101""
102"
1133
103
101
1993
103
104
103
105
105
104
.._101
1994
105
106
106
108
110
105
...-.1.01
1995
106
108
107
"~ 111
112
107.
„., 1P2
1996
109
111
110
114
:iife"""
108..
102
1997
110
112
112
'116
122
109
103
1998
110
112
112
120
127
110
.._,104.
1999
111
115
114
122
132
112
...104
2000
114
117
116
125
138
113
,.,104 _
Growth
Rate'
1.3%
1.6%
1.5%
2.3%
3.2%
1,2%
.. 0.4%,,
(EIA2001)
O Gross Domestic Product in chained 1996 dollars (BEA 2000)
?;ft (U.S. Census Bureau 2000)
|-e Mauna Loa Observatory, Hawaii (Keeling and Whorf 2000)
I f Average annual growth rate
Figure ES-5
-
*;.-.
U.S. Greenhouse Gas Emissions Per Capita arid
ss& Pter Doliar^ of Grois^ Domeltjc^ I*rodu6t ^!2S
140
130
1 120
§ 11°
o>
r 100
90
80
Real GDP
Emissions per $GDP
Source: BEA (2001), U.S. Census Bureau (2000), and
emission estimates in this report.
Executive Summary ES-7
-------
Emissions by Economic Sector
Throughout this report, emission estimates are grouped
into six sectors (i.e., chapters) defined by the D?CC: Energy,
Industrial Processes, Solvent Use, Agriculture, Land-Use
Change and Forestry, and Waste. While it is important to
use this characterization for methodological reasons, it is
also useful to allocate emissions into sectoral categories that
are more intuitive. This section reports emissions by the
following economic sectors: Residential, Commercial,
Industry, Transportation, Electricity Generation, and
Agriculture, and U.S. Territories. Table ES-4 summarizes
emissions from each of these sectors. Figure ES-6 shows
the trend in emissions by sector from 1990 to 2000.
Using this categorization scheme, emissions from
electricity generation accounted for the largest portion (34
percent) of U.S. greenhouse gas emissions. The
transportation activities, in aggregate, accounted for the
second largest portion (27 percent). Emissions from
industry accounted for 19 percent of U.S. greenhouse gas
emissions in 2000. In contrast to electricity generation and
transportation, emissions from industry have declined over
the past decade, as structural changes have occurred in the
U.S. economy (i.e., shifts from a manufacturing base to a
service-based economy), fuel switching has occurred, and
efficiency improvements have been made. The remaining
20 percent of U.S. greenhouse gas emissions were
contributed by the residential, agriculture, commercial, and
Figure ES-6
2,500
2,000
& 1,500
1,000
500
0
Electricity Generation 34%
Transportation 27%
Industry 19%
Agriculture 8%v
Residential 8%\V
Commercial 5%
Mote: Does not include territories. Label includes percent of total in 2000.
U.S. territory economic sectors combined. Residences
accounted for about 8 percent, and primarily consisted of
carbon dioxide (CO2) emissions from fossil fuel combustion.
Activities related to agriculture accounted for roughly 8
percent of U.S. emissions, but unlike all other economic
sectors these emissions were dominated by nitrous oxide
(N2O) emissions from agricultural soils instead of CO2 from
fossil fuel combustion. The commercial sector accounted
for about 5 percent of emissions, while U.S. territories
accounted for less than 1 percent of total emissions.
Carbon dioxide was also emitted and sequestered by a
variety of activities related to land-use change and forestry.
Table ES-4: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors
(Tg C02 Eq. and Percent of Total in 2000)
Sector
Electricity Generation
Transportation
Industry
Agriculture
Residential
Commercial
U.S. Territories
Total
Sinks
Net Emissions
(Sources and Sinks)
- — - sssss
1990 ^
1,898.2 Z
1,527.7
1,393.9 "™
494.7
484.6 '
303.5 "
28.1 =
6,130.7
(1,097.7)
5,033.0
i-vn-y — "-
1995
2,024.3
-• 1,652.4
" 1,400.9
533.3
; 522.7
313.0
35.3
6,481.8
' (1,110.0)
" 5,371.8
1996
2,096.9
1,695.2
1,447.6
533.3
549.0
320.8
27.0
6,669.8
(1,108.1)
5,561.7
1997
2,171.6
1,708.5
1,442.7
544.2
531.1
320.9
29.1
6,748.1
(887.5)
5,860.5
1998
2,256.1
1,737.4
1,385.9
545.1
494.3
302.9
34.4
6,756.2
(885.9)
5,870.3
1999
2,271.2
1,813.3
1,341.1
544.9
516.0
307.1
35.8
6,829.5
(896.4)
5,933.1
2000
2,376.9
1,877.0
1,314.6
535.5
531.6
327.6
38.0
7,001.2
(902.5)
6,098.7
Percent3
33.9%
26.8%
18.8%
7.6%
7.6%
4.7%
0.5%
100.0%
Note: Totals may not sum due to independent rounding Includes all emissions of C02, CH4, N20, HFCs, PFGs.and SF6.
See Table 1-11 for more detailed data.
•Percent of total in 2000.
ES-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table ES-5 presents greenhouse gas emissions from
economic sectors with emissions related to electricity
generation distributed into end-use categories (i.e.,
emissions from electricity generation are allocated to the
economic sectors in which the electricity is consumed). To
distribute electricity emissions among end-use sectors,
emissions from the source categories assigned to electric
generation were allocated to the residential, commercial,
industry, transportation, and agriculture economic sectors
according to retail sales of electricity.8 These three source
categories include CO2 from fossil fuel combustion, CH4
and N2O from stationary sources, and SF6 from electrical
transmission and distribution.9
When emissions from electricity are distributed among
these sectors, industry accounts for the largest share of U.S.
greenhouse gas emissions (29 percent). Emissions from
the residential and commercial sectors also increase
substantially due to their relatively large share of electricity
consumption. Transportation activities remain the second
largest contributor to emissions. In all sectors except
agriculture, CO2 accounts for more than 75 percent of
greenhouse gas emissions, primarily from the combustion
of fossil fuels. Figure ES-7 shows the trend in these
emissions by sector from 1990 to 2000.
The following sections describe the concept of Global
Warming Potentials (GWPs), present the anthropogenic
sources and sinks of greenhouse gas emissions in the United
States, briefly discuss emission pathways, further summarize
the emission estimates, and explain the relative importance
of emissions from each source category.
Figure ES-7
. " '"i^Mifwd&nl^^ '
i :^i£3fe^ss^t:|.iJtp,Ecoii^|||iic Sectors ^.-;^^^^gif^i^-.^L;
2,500 i
2,000
S" 1,500 •
ow
o
D) 1,000
500
0
Note: Does m
Industrial 29%
Transportation 27% — "^""""'^
Residential 19%
__— : "".
Agriculture 8%
^><^'<^<^><^<^><^><^'^><^> ^
)t include territories. Label includes percent of total in 2000.
Global Warming Potentials
Gases in the atmosphere can contribute to the
greenhouse effect both directly and indirectly. Direct effects
occur when the gas itself is a greenhouse gas. Indirect
radiative forcing occurs when chemical transformations of
the original gas produce other greenhouse gases, when a
gas influences the atmospheric lifetimes of other gases, and/
or when a gas affects atmospheric processes that, alter the
radiative balance of the earth (e.g., affect cloud formation
or albedo).10 The concept of a Global Warming Potential
(GWP) has been developed to compare the ability of each
Table ES-5: U.S Greenhouse Gas Emissions by Economic Sector and Gas with Electricity-Related Emissions
Distributed (Tg C02 Eq.)
I Sector
c_ " , ;" - ' " "; "" " "" -.J'
t- Industry
g-Transportation
k Residential
P Commercial
fc Agriculture
r U.S. Territories
-Total
ir Note: Totals may not sum due to
| See Table 1-12 for more detailed
2,
1,
1,
6,
1990 |
029.7 \
530.5 j
131.2
890.7
520.5
28.1 . j
130.7
2Z; 1"5
S '2,071.6
Hi 1-655-1
^g 1,213.1
^3 944.9
^3 561.8
B . 35-3
Iu2 M81.8
independent rounding. Includes all emissions of C02,
data.
2,
1,
1,
6,
CH4,
1996
136.2
697.9
270.1
974.3
564.3
27.0
669.8
1997
2,151.5
1,711.2
1,265.6
1,022.4
568.2
29.1
6,748.1
N20, MFCs, PFGs, and
1998
2,104.0
1,740.2
1,266.3
1,040.0
571.4
34.4
6,756.2
SF6.
2
1
1
1
6,
1999
059.7
816.0
293.5
057.5
567.0
35.8
829.5
2
1
1
1
7
2000
,054.7 '*
,879.7
,357.4
,113.8
557.7
38.0 ,
,001.2
ib
• - *
8 Emissions were not distributed to U.S. territories, since they do not consume electricity produced by the electricity generation sector.
9 Emissions were not distributed to U.S. territories, since the electricity generation sector only includes emissions related to the generation of electricity
in the 50 states and the District of Columbia.
10 Albedo is a measure of the Earth's reflectivity; see the Glossary (Annex Z) for definition.
Executive Summary ES-9
-------
Box ES-2: The IPCC Third Assessment Report and Global Warming Potentials
The IPCC recently published its Third Assessment Report (TAR), providing the most current and comprehensive scientific assessment of
climate change, Within this report, the global warming potentials (GWPs) of several gases were revised relative to the IPCC's Second Assess-
ment Report (SAR), and new GWPs have been calculated for an expanded set of gases. Since the Second Assessment Report, the IPCC has
applied an improved calculation of C02 radiative forcing and an improved C02 response function (presented in WMO 1999). The GWPs are
drawn from WMO (1999) and the Second Assessment Report, with updates for those cases where significantly different new laboratory or
radiative transfer results have been published. Additionally, the atmospheric lifetimes of some gases have been recalculated. Because the
revised radiative forcing of C02 is about 12 percent lower than that in the Second Assessment Report, the GWPs of the other gases relative to
C02 tend to be larger, taking into account revisions in lifetimes. In addition, the values for radiative forcing and lifetimes have been calculated for
a variety of halocarbons, which were not presented in the Second Assessment Report. Table ES-6 presents the new Global Warming Potentials,
relative to those presented in the Second Assessment Report.
Table ES-6: Comparison of 100 Year GWPs
Gas SAR TAR
Change
Absolute Percent
Carbon dioxide (C02)
Methane (CH4)*
Nitrous oxide (N20)
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
CF4
C2F6
C^io
C6F14
SF6
1
21
310
11,700
650
2,800
1,300
3,800
140
2,900
6,300
1,300
6,500
9,200
7,000
7,400
23,900
1
23
296
12,000
550
3,400
1,300
4,300
120
3,500
9,400
1,500
5,700
11,900
8,600
9,000
22,200
IMC
2
(14)
300
(100)
600
NC
500
(20)
600
3,100
200
(800)
2,700
1,600
1,600
(1,700)
NC
10%
(5%)
3%
(15%)
21%
NC
13%
(14%)
21%
49%
15%
(12%)
29%
23%
22%
(7%)
Source: (IPCC 2001,1996)
NC (No Change)
* The methane GWP includes the direct effects and those indirect effects due to the production of
tropospheric ozone and stratospheric water vapor. The indirect effect due to the production of C02
is not included.
Although the GWPs have been updated by the IPCC, estimates of emissions presented in this Inventory will continue to use the GWPs from
the Second Assessment Report. The guidelines under which this Inventory is developed, the Revised 1996 IPCC Guidelines for National
Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA1997) and the UNFCCC reporting guidelines for national inventories11 were developed prior
to the publication of the TAR. Therefore, to comply with international reporting standards under the UNFCCC, official emission estimates are
reported by the United States using SAR GWP values. Overall, these revisions to GWP values do not have a significant effect on U.S. emission
trends (see Annex Q).
greenhouse gas to trap heat in the atmosphere relative to
another gas. Carbon dioxide (CO2) was chosen as the
reference gas to be consistent with IPCC guidelines.
Global warming potentials are not provided for CO, NOx,
NMVOCs, SO2, and aerosols because there is no agreed upon
method to estimate the contribution of gases that are short-
lived in the atmosphere, spatially variable, and have only
indirect effects on radiative forcing (IPCC 1996).
11 See FCCC/CP/1999/7 at .
ES-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
The GWP of a greenhouse gas is defined as the ratio of
the time-integrated radiative forcing from the instantaneous
release of 1 kg of a trace substance relative to that of 1 kg
of a reference gas (IPCC 2001). Direct radiative effects
occur when the gas itself is a greenhouse gas. Indirect
radiative forcing occurs when chemical transformations
involving the original gas produces a gas or gases that are
greenhouse gases, or when a gas influences other radiatively
important processes such as the atmospheric lifetimes of
other gases. The reference gas used is CO2, and therefore
GWP weighted emissions are measured in teragrams of CO2
equivalents (Tg CO2Eq.)12 All gases in this executive
summary are presented in units of Tg CO2 Eq. The
relationship between gigagrams (Gg) of a gas and Tg CO2
Eq. can be expressed as follows:
(TP- ^
——
l.OOOGgJ
While any time period can be selected, the 100 year
GWPs recommended by the IPCC and employed by the
United States for policy making and reporting purposes were
used in this report (IPCC 1996). GWP values are listed
below in Table ES-7.
Carbon Dioxide Emissions
Table ES-7: Global Warming Potentials
(100 Year Time Horizon)
The global carbon cycle is made up of large carbon
flows and reservoks. Billions of tons of carbon in the form
of CO2 are absorbed by oceans and living biomass (sinks)
and are emitted to the atmosphere annually through natural
processes (sources). When in equilibrium, carbon fluxes
among these various reservoirs are roughly balanced. Since
the Industrial Revolution, this equilibrium of atmospheric
carbon has been altered. Atmospheric concentrations of
CO2 have risen about 31 percent (IPCC 2001), principally
because of fossil fuel combustion, which accounted for 96
percent of total U.S. CO2 emissions in 2000. Globally,
approximately 23,300 Tg of CO2 were added to the
atmosphere through the combustion of fossil fuels at the
end of the 1990s, of which the United States accounted for
about 24 percent (see Figure ES-8).13 Changes in land use
and forestry practices can also emit CO2 (e.g., through
RGas
f -Carbon dioxide (C02)
E; Methane (GH4)*
f Nitrous oxide (N20)
1:: HFC-23 .
I HFC-32
t-:HFC-125
S;;HFC-134a
s;HFC-143a
isHFC-152a
R HFC-227ea """"
= HFC-236fa
^HFC-4310mee
feCF4
-;c2F6
•-. ^10
feP6F,4
?SF6
GWP
1
21
310
11,700
650
2,800
1,300
3,800
140
2,900
6,300
1,300
6,500
9,200
7,000
7,400
23,900
^Source: IPCC (1996)
|-iThe methane GWP includes the direct effects and those indirect
Fsffecfe due to the production of tropospheric ozone and stratospheric
*- water vapor. The indirect effect due to the production of C02 is not
^included.
conversion of forest land to agricultural or urban use) or
can act as a sink for CO2 (e.g., through net additions to
forest biomass).
Figure ES-9 and Table ES-8 summarize U.S. sources and
sinks of CO2. The remainder of this section then discusses
CO2 emission trends in greater detail.
Energy
Energy-related activities accounted for the vast
majority of U.S. CO2 emissions for the period of 1990
through 2000. Carbon dioxide from fossil fuel
combustion was the dominant contributor. In 2000,
approximately 85 percent of the energy consumed in the
United States was produced through the combustion of
fossil fuels. The remaining 15 percent came from other
energy sources such as hydropower, biomass, nuclear,
wind, and solar energy (see Figure ES-10 and Figure
ES-11). A discussion of specific trends related to CO2
emissions from energy consumption is presented below.
12 Carbon comprises 12/44ths of carbon dioxide by weight.
13 Global CO2 emissions from fossil fuel combustion were taken from Marland et al. (2001).
Executive Summary ES-11
-------
Figure ES-8
(Tg C02 Eq.)
MS 802-
000139'
ottwKiia-
fossi Fuel
Stock Consumption
Non-Energy Changes u.S.
Use Imports 133 Territories
47 32
Nate Totals may not sum due to Independent rounding.
The 'Balancing Item* above accounts for the statistical Imbalances
and unknowns In the reported data sets combined here.
NEU. Non-Energy Use
MS-Natural Gas
Fossil Fuel
Combustion
Residual
(Not Oxidized
Fraction)
50
Figure ES-9
Fossil Fuel Combustion
Iron and Steel
Production
Cement Manufacture
Indirect CO2 Emissions
Waste Combustion
Ammonia Manufacture
Lime Manufacture
Limestone and
Dolomite Use
Natural Gas Flaring
Aluminum Production
Soda Ash Manufacture
and Consumption
Titanium Dioxide
Production
Ferroalloys
Carbon Dioxide
Consumption
Figure ES-10
5,623
CO2 as a Portion
of all Emissions
I
I
I
10 20 30
Tg C02 Eq.
40
6.9% Renewable
8.1% Nuclear
22.8% Coal
23.7%
Natural Gas
38.4%
Petroleum
Source: DOE/EIA-0384(2000), Annual Energy Review
2000, Table 1.3, August 2001.
ES-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table ES-8: U.S. Sources of C02 Emissions and Sinks (Tg C02 Eq.)
Source or Sink
1990
1995
1996
1997
1998
1999
2000
^- . . - _. -- .. - - :, --
i- Fossil Fuel Combustion
i. Electricity Generation
^Transportation
L Industrial
jt - • ..- i: -, -;.=is -,---
p Residential
f Commercial
t U.S.. Territories ..„
f Iron and Steel Production
*" Cement Manufacture
; indirect C02 From CH4 Oxidation
t Waste Combustion
""Ammonia Manufacture
'.. Lime Manufacture
; Limestone and Dolomite Use
I Natural Gas Flaring
^Aluminum Production
4,779.8
1,858.9
1,471.8
.... 8716
: ,.,332.1
217.3
28.1
85.4
33.3
30.9
14.1
18.5
11.2
5.2
5.5
6.3
__ Soda Ash Manufacture and Consumption 4.1
"Titanium' Dioxide Production
Ferroalloys
Carbon Dioxide Consumption
Land-Use Change and Forestry (Sink)3
International Bunker Fuelsb
r Total
Net Emissions (Sources and Sinks)
1.3
2.0
0.8
(1,097.7)
113.9
4,998.5
3,900.8
111 5,085.0
isii 1-989-3
PSj 1,579.4
liy 894-9
362.3
IBlj 223-9
353
74.4
36.8
ESI 29.5
18.6
"' "I8-9"
s£3 12.8
iffii!,:J 7.0
8.7
E31 5.3
4.3
"1^7
fefei 1 .9
1.0
SHI (1.1 10.0)
1°1-°
B^J 5,305.9
t "\J 4,195.9
5,266.6
2,061.2
1,618.7
936.5
390.4
232.8
27.0
68.3
37.1
28.9
19.6
19.5
13.5
7.4
8.2
5.6
4.2
1.7
2.0
1.1
(1,108.1)
102.3
5,483.7
4,375.6
5,339.6
2,137.9
1,628.8
935.2
374.9
233.7
29.1
76.1
38.3
28.4
21.3
19.5
13.7
8.4
7.6
5.6
4.4
1.8
2.0
1.3
(887.5)
109.9
5,568.0
4,680.5
5,356.2
2,226.4
1,655.0
881.1
341.8
217.5
34.4
67.4
39.2
28.2
20.3
20.1
13.9
8.2
6.3
5.8
4.3
1.8
2.0
1.4
(885.9)
112.9
5,575.1
4,689.2
5,448.6
2,246.2
1,728.2
858.1
360.5
219.8
35.8
64.4
40.0
27.0
21.8
18.9
13.5
9.1
6.7
5.9
4.2
1.9
2.0
1.6
(896.4)
105.3
5,665.5
4,769.1
5,623.3
2,352.5
1,789.5
829.2
374.8
239.3
38.0
65.7
41.1
26.3
22.5
18.0
13.3
9.2
6.1
5.4
4.2
2.0
1.7
1.4
(902.5)
100.2
5,840.0
4,937.5
a Sinks are only included in net emissions total, and are based partially on projected activity data. Parentheses indicate negative values (or sequestration).
^Emissions from International Bunker Fuels are not included in totals.
Note: Totals may not sum due to independent rounding.
Figure ES-11
120 n
3-100 -
a
g
f 60 -\
3
W
o 40 -
O
I 20 -
0 J
Total Energy
Renewable & Nuclear
Note: Expressed as gross calorific values.
Source: DOE/EIA-0384 (2000), Annual Energy Review
2000, Table 1.3, August 2001
Fossil Fuel Combustion (5,623.3 Tg C02 Eq.)
As fossil fuels are combusted, the carbon stored in them
is almost entirely emitted as COr The amount of carbon in
fuels per unit of energy content varies significantly by fuel
type. For example, coal contains the highest amount of
carbon per unit of energy, while petroleum has about 25
percent less carbon than coal, and natural gas about 45
percent less. From 1990 through 2000, petroleum supplied
the largest share of U.S. energy demands, accounting for
an average of 39 percent of total energy consumption.
Natural gas and coal followed in order of importance,
accounting for an average of 24 and 23 percent of total
energy consumption, respectively. Most petroleum was
consumed in the transportation end-use sector, while the
vast majority of coal was used by electric power generators,
and natural gas was consumed largely in the industrial and
residential end-use sectors.
Emissions of CO2 from fossil fuel combustion increased
at an average annual rate of 1.6 percent from 1990 to 2000.
The fundamental factors behind this trend include (1) a
robust domestic economy, (2) relatively low energy prices
Executive Summary ES-13
-------
as compared to 1990, (3) significant growth in emissions
from transportation activities and electricity generation, and
(4) heavier reliance on nuclear energy. Between 1990 and
2000, CO2 emissions from fossil fuel combustion steadily
increased from 4,779.8 Tg CO2 Eq. to 5,623.3 Tg CO2 Eq.—
an 18 percent total increase over the eleven year period.
As introduced above, the four end-use sectors
contributing to CO2 emissions from fossil fuel combustion
include industrial, transportation, residential, and
commercial. Electricity generation also emits CO2, although
these emissions are produced as they consume fossil fuel to
provide electricity to one of the four end-use sectors. For
the discussion below, electricity generation emissions have
been distributed to each end-use sector based upon the
sector's share of aggregate electricity consumption. This
method of distributing emissions assumes that each end-
use sector consumes electricity that is generated with the
national average mix of fuels according to their carbon
intensity. In reality, sources of electricity vary widely in
carbon intensity. By assuming the same carbon intensity
for each end-use sector's electricity consumption, for
example, emissions attributed to the residential end-use
sector may be underestimated, while emissions attributed
to the industrial end-use sector may be overestimated.
Emissions from electricity generation are also addressed
separately after the end-use sectors have been discussed.
Figure ES-12
2000 CO? Enils^dSOLiroflfF^^
Figure ES-13
Sector aM Full Type"
Natural Gas
Petroleum
• Coal
2,000 -j Relative Contribution
by Fuel Type
1,000 -
5
500 -j
Note: Electricity Generation also includes emissions of less
than 0.01 Tg C02 Eq. from geothermal plants.
2,000
. 1,600
cr
"i 1,200
O
p 800
400
0
From Electricity Consumption
From Direct Fossil Fuel Combustion
*& ^
<&
x^^
-^JX
&
«$p
Note that emissions from U.S. territories are calculated
separately due to a lack of specific consumption data for
the individual end-use sectors. Table ES-9, Figure ES-12,
and Figure ES-13 summarize CO2 emissions from fossil fuel
combustion by end-use sector.
Industrial End-Use Sector. Industrial CO2 emissions
—resulting both directly from the combustion of fossil fuels
and indirectly from the generation of electricity that is
consumed by industry—accounted for 28 percent of CO2
from fossil fuel combustion in 2000. About half of these
emissions resulted from direct fossil fuel combustion to
produce steam and/or heat for industrial processes. The
other half of the emissions resulted from consuming
electricity for motors, electric furnaces, ovens, lighting, and
other applications.
Transportation End-Use Sector. Transportation
activities—excluding international bunker fuels—accounted
for 32 percent of CO2 emissions from fossil fuel combustion
in 2000.14 Virtually all of the energy consumed in this end-
use sector came from petroleum products. Just over half of
the emissions resulted from gasoline consumption in motor
vehicles. The remaining emissions came from other
transportation activities, including the combustion of diesel
fuel in heavy-duty vehicles and jet fuel in aircraft.
14 If emissions from international bunker fuels are included, the transportation end-use sector accounted for 34 percent of U.S. emissions from fossil
fuel combustion in 2000.
ES-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table ES-9: C02 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg C02 Eq.)
(.*:_. — " "- -" — 7 — rv
f End-Use Sector
[industrial
fefg-, -"'• "-"»"- ""--". •-" ' ' . _--±, -~"Tr—-'"
ipv Combustion
p . Electricity
,: Transportation
|— Combustion
f™ ; Electricity
; Residential
r' Combustion
^Electricity .. . .." „....
1 Commercial
JE: Combustion
F' Electricity
FU.S. Teitilories
ipbtal
: Electricity Generation
P Note: Totals may not sum due to
' :::i99o::;;"e_ r
:ii^.6;":"':f|l
871 .6
648.0 """
1 474 5 P*^
* !l(£B§£S£if
1,471.8
2.7
"• 965-3.
332.1
COQ O iHPi?-!?
'^
792.3 B>£ ,
217.3
575.0
2BA n
4>779-8 ' mi
1,858.9 B
1995
1,563.4
894.9
668.5
1,582.0
1,579.4
2.6
1,050.6
362.3
688.2
853.8
223.9
629.9
35.3
5,085.0
1,989.3
1996
1,623.5
936.5
687.0
1,621.3
1,618.7
2.7
1,109.9
390.4
719.5
884.8
232.8
652.0
27.0
5,266.6
2,061.2
1997
i, 640.8
935.2
705.6
1,631.5
1,628.8
2.7
1,106.1
374.9
731.2
932.0
233.7
698.4
29.1
5,339.6
2,137.9
1998
1,598.1
881.1
717.0
1,657.7
1,655.0
2.7
1,112.6
341.8
770.8
953.4
217.5
735.9
34.4
5,356.2
2,226.4
1999
1,575.7
858.1
717.7
1,731.0
1,728.2
2.7
1,136.9
360.5
776.5
969.2
219.8
749.4
35.8
5,448.6
2,246.2
independent rounding. Emissions from fossil fuel combustion by electricity generation are allocated based
2000 ;
1,568.5 *
829.2 "
739.3
1,792.3
1,789.5
2.8 '••
1,199.8
374.8
825.0
1,024.7
239.3 '
785.4 :
38.0
5,623.3
2,352.5
on
t aggregate national electricity consumption by each end-use sector.
Residential and Commercial End-Use Sectors. The
residential and commercial end-use sectors accounted for
21 and 18 percent, respectively, of CO2 emissions from fossil
fuel consumption in 2000. Both sectors relied heavily on
electricity for meeting energy needs, with 69 and 77 percent,
respectively, of their emissions attributable to electricity
consumption for lighting, heating, cooling, and operating
appliances. The remaining emissions were largely due to
the consumption of natural gas and petroleum, primarily
for meeting heating and cooking needs.
Electricity Generation. The United States relies on
electricity to meet a significant portion of its energy demands,
especially for lighting, electric motors, heating, and air
conditioning. Electricity generation is responsible for
consuming 34 percent of U.S. energy from fossil fuels and
emitted 42 percent of the CO2 from fossil fuel combustion
in 2000. The type of fuel combusted by electricity generators
has a significant effect on their emissions. For example,
some electricity is generated with low CO2 emitting energy
technologies, particularly non-fossil options such as nuclear,
hydroelectric, or geothermal energy. However, electricity
generators rely on coal for over half of their total energy
requirements and accounted for 94 percent of all coal
consumed in the United States in 2000. Consequently,
changes in electricity demand have a significant impact on
coal consumption and associated CO2 emissions.
Indirect C02 from CH4 Oxidation (26.3 Tg C02 Eq.)
Indirect CO2 emissions are formed in the atmosphere
from the oxidation of methane (CH4). Although this indirect
CO2 is a greenhouse gas, its generation is not accounted for
within the global warming potential (GWP) of CH4. Thus
for the sake of completion, it is necessary to account for
these indirect emissions whenever anthropogenic sources
of CH4 are calculated. Non-biogenic and non-combustion
emissions of CH4 are considered in this calculation.
Waste Combustion (22.5 Tg C02 Eq.)
Waste combustion involves the burning of garbage and
non-hazardous solids, referred to as municipal solid waste
(MSW), as well as the burning of hazardous waste. Waste
combustion, in the United States, is usually performed to
recover energy from the waste materials. Carbon dioxide
emissions arise from the organic (i.e., carbon) materials
found hi these wastes. Within MSW, many products contain
carbon of biogenic origin, and the CO2 emissions from their
combustion are accounted for under the Land-Use Change
and Forestry chapter. However, several components of
MSW—plastics, synthetic rubber, synthetic fibers, and
carbon black—are of fossil fuel origin, and are included as
sources of CO2 emissions.
Executive Summary ES-15
-------
Natural Gas Flaring (6.1 Tg C02 Eq.)
Carbon dioxide is produced when natural gas from oil
wells is flared (i.e., combusted) to relieve rising pressure or
to dispose of small quantities of gas that are not
commercially marketable. In 2000, flaring activities emitted
less than 0.1 percent of U.S. CO2 emissions.
Biomass Combustion (184.4 Tg C02 Eq.)
Biomass in the form of fuel wood and wood waste was
used primarily by the industrial end-use sector, while the
transportation end-use sector was the predominant user of
biomass-based fuels, such as ethanol from corn and woody
crops.
Although these fuels do emit CO2, in the long run the
CO, emitted from biomass consumption does not increase
atmospheric CO2 concentrations if the biogenic carbon
emitted is offset by the growth of new biomass. For
example, fuel wood burned one year but re-grown the next
only recycles carbon, rather than creating a net increase in
total atmospheric carbon. Net carbon fluxes from changes
in biogenic carbon reservoirs in wooded or croplands are
accounted for under Land-Use Change and Forestry.
The industrial sector accounted for 74 percent of gross
CO2 emissions from biomass combustion, and the residential
sector accounted for 19 percent. Ethanol consumption by
the transportation sector accounted for only 5 percent.
Industrial Processes
Emissions are produced as a by-product of many non-
energy-related activities. For example, industrial processes
can chemically transform raw materials. This transformation
often releases greenhouse gases such as CO2. The major
production processes that emit CO2 include iron and steel
production, cement manufacture, lime manufacture,
limestone and dolomite use, soda ash manufacture and
consumption, CO2 consumption, titanium dioxide
production, ferroalloy production, and ammonia
manufacturing. Carbon dioxide emissions, from these
sources were approximately 161.9 Tg CO2 Eq. in 2000,
accounting for about 3 percent of total CO2 emissions.
Iron and Steel Production (65.7 Tg C02 Eq.)
The production of iron and steel generates process-related
emissions of CO2. Iron is produced by first reducing iron oxide
(i.e., iron ore) with metallurgical coke in a blast furnace to
produce pig iron. Carbon dioxide is produced as the
metallurgical coke used in the blast furnace process is oxidized.
Steel—containing less than 2 percent carbon by weight—is
produced from pig iron in a variety of specialized steel making
furnaces. The majority of CO2 emissions from the iron and
steel processes come from the use of coke in the production of
pig iron, with smaller amounts evolving from the removal of
carbon from pig iron used to produce steel.
Cement Manufacture (41.1 Tg C02 Eq.)
Carbon dioxide is produced primarily during the
production of clinker, an intermediate product from which
finished Portland and masonry cement are made. When
calcium carbonate (CaCO3) is heated in a cement kiln to form
lime and CO2, the lime combines with other materials to
produce clinker, and the CO2 is released into the atmosphere.
Ammonia Manufacturing (18.0 Tg C02 Eq.)
Carbon dioxide emissions occur during the production
of ammonia. In the United States, roughly 98 percent of
synthetic ammonia is produced by catalytic steam reforming
of natural gas, and the remainder is produced using naphtha
(i.e., a petroleum fraction) or the electrolysis of brine at
chlorine plants (EPA 1997). The former two fossil fuel-
based reactions produce carbon monoxide and hydrogen
gas. This carbon monoxide is transformed into CO2 in the
presence of a catalyst—usually a metallic oxide—and
generally released into the atmosphere.
Lime Manufacture (13.3 Tg C02 Eq.)
Lime is used in steel making, construction, pulp and paper
manufacturing, and water and sewage treatment. It is
manufactured by heating limestone (mostly calcium carbonate,
CaCO3) in a kiln, creating quicklime (calcium oxide, CaO)
and CO2, which is normally emitted to the atmosphere.
Limestone and Dolomite Use (9.2 Tg C02 Eq.)
Limestone (CaCO3) and dolomite (CaMg(CO3)) are
basic raw materials used by a wide variety of industries,
including the construction, agriculture, chemical, and
metallurgy. For example, limestone can be used as a purifier
in refining metals. In the case of iron ore, limestone heated
in a blast furnace reacts with impurities in the iron ore and
fuels, generating CO2 as a by-product. Limestone is also
used in flue gas desulfurization systems to remove sulfur
dioxide from the exhaust gases.
ES-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Aluminum Production (5.4 Tg C02 Eq.)
Carbon dioxide is emitted during the aluminum
smelting process when alumina (aluminum oxide, A12O3) is
reduced to aluminum. The reduction of the alumina occurs
through electrolysis in a molten bath of natural or synthetic
cryolite. The reduction cells contain a carbon lining that
serves as the cathode. Carbon is also contained in the anode,
which can be a carbon mass of paste, coke briquettes, or
prebaked carbon blocks from petroleum coke. During
reduction, some of this carbon is oxidized and released to
the atmosphere as CO2.
Soda Ash Manufacture and Consumption
(4.2TgC02Eq.)
Commercial soda ash (sodium carbonate, Na2CO3) is
used in many consumer products, such as glass, soap and
detergents, paper, textiles, and food. During the
manufacturing of soda ash, some natural sources of sodium
carbonate are heated and transformed into a crude soda ash,
in which CO2 is generated as a by-product. In addition,
CO2 is often released when the soda ash is consumed.
Titanium Dioxide Production (2.0 Tg C02 Eq.)
Titanium dioxide (TiO2) is a metal oxide manufactured
from titanium ore, and is principally used as a pigment.
Titanium dioxide is used as an ingredient in white paint
and as a pigment in the manufacture of white paper, foods,
and other products. There are two processes for making
TiO2, the chloride process and the sulfate process. Carbon
dioxide is emitted from the chloride process, which uses
petroleum coke and chlorine as raw materials.
Ferroalloy Production (1.7 Tg C02 Eq.)
Carbon dioxide is emitted from the production of
several ferroalloys through the use of metallurgical coke as
a raw material. Ferroalloys are composites of iron and other
elements often including silicon, manganese, and chromium.
When incorporated in alloy steels, ferroalloys are used to
alter the material properties of the steel.
Carbon Dioxide Consumption (1.4 Tg C02 Eq.)
Carbon dioxide (CO2) is used directly hi many segments
of the economy, including food processing, beverage
manufacturing, chemical processing, and a host of industrial
and other miscellaneous applications. Carbon dioxide may
be produced as a by-product from the production of certain
chemicals (e.g., ammonia) from select natural gas wells, or
by separating it from crude oil and natural gas. For the
most part, the CO2 used in these applications is eventually
released to the atmosphere.
Land-Use Change and Forestry
When humans alter the terrestrial biosphere through
land use, changes in land-use, and forest management
practices, they alter the natural carbon flux between biomass,
soils, and the atmosphere. Forest management practices,
the management of agricultural soils, management of trees
in urban areas, and landfilling of yard trimmings have
resulted in a net uptake (sequestration) of carbon in the
United States that is equivalent to about 13 percent of total
U.S. gross emissions. Forests (including vegetation, soils,
and harvested wood) accounted for approximately 85
percent of the total sequestration, agricultural soils
(including mineral and organic soils and the application of
lime) accounted for over 7 percent, urban trees accounted
for more than 6 percent, and landfilled yard trimmings
accounted for less than 1 percent of the total sequestration.
The net forest sequestration is largely a result of improved
forest management practices, the regeneration of previously
cleared forest areas, and timber harvesting. In agricultural
soils, mineral soils account for a net carbon sink that is more
than three times larger than the sum of emissions from
organic soils and liming. Net sequestration in agricultural
mineral soils is largely due to improved cropland and grazing
land management practices, especially the adoption of
conservation tillage practices and leaving residues on the
field after harvest, and to taking erodable lands out of
production and planting them with grass or trees through
the Conservation Reserve Program. The landfilled yard
trimmings net sequestration is due to the long-term
accumulation of yard trimming carbon hi landfills.
Methane Emissions
Atmospheric methane (CH4) is an integral component
of the greenhouse effect. Methane's overall contribution
to global warming is significant because it has been
estimated to be more than 20 times as effective at trapping
heat hi the atmosphere as CO2. Over the last two hundred
and fifty years, methane's concentration in the atmosphere
has increased by 150 percent (IPCC 2001). Experts believe
Executive Summary ES-17
-------
that over half of these atmospheric increases were due to
emissions from anthropogenic sources, such as landfills,
natural gas and petroleum systems, agricultural activities,
coal mining, stationary and mobile combustion, wastewater
treatment, and certain industrial processes (see Figure
ES-14 and Table ES-10).
Landfills (203.5 Tg C02 Eq.)
Landfills are the largest source of anthropogenic CH4
emissions in the United States. In an environment where
the oxygen content is low or nonexistent, organic materials,
such as yard waste, household waste, food waste, and paper,
can be decomposed by bacteria, resulting in the generation
of CH4 and biogenic CO2. Methane emissions from landfills
are affected by site-specific factors such as waste
composition, moisture, and landfill size.
Methane emissions from U.S. landfills have decreased
by almost 5 percent since 1990. The generally declining
emission estimates are aresult of two offsetting trends: (1)
the amount of municipal solid waste in landfills contributing
to CH4 emissions has increased, thereby increasing the
potential for emissions; and (2) the amount of landfill gas
collected and combusted by landfill operators has also
increased, thereby reducing emissions. Additionally, a
regulation promulgated in March 1996 requires the largest
U.S. landfills to begin collecting and combusting their
landfill gas to reduce emissions of NMVOCs.
Figure ES-14
Landfills
Enteric Fermentation
Natural Gas Systems
Coal Mining
Manure Management
Wastewater Treatment
Petroleum Systems
Rice Cultivation
Stationary Sources
Mobile Sources
Petrochemical Production
Agricultural Residue Burning
Silicon Carbide Production
I
<0.05
CH4 as a Portion
of All Emissions
8.8%
o
50 100 150
Tg CO2 Eq.
200
Natural Gas and Petroleum Systems
(138.2TgC02Eq.)
Methane is the major component of natural gas. During
the production, processing, transmission, and distribution of
natural gas, fugitive emissions of methane often occur. Because
natural gas is often found in conjunction with petroleum
deposits, leakage from petroleum systems is also a source of
emissions. Emissions vary greatly from facility to facility and
are largely a function of operation and maintenance procedures
and equipment conditions. In 2000, CH4 emissions from U.S.
natural gas systems were accounted for approximately 19
percent of U.S. CH4 emissions.
Table ES-10: U.S. Sources of Methane Emissions (Tg C02 Eq.)
Source
Landfills
Enteric Fermentation
Natural Gas Systems
Coal Mining
Manure Management
Wastewater Treatment
Petroleum Systems
Stationary Sources
Rice Cultivation
Mobile Sources
Petrochemical Production
Agricultural Residue Burning
Silicon Carbide Production
International Bunker Fuels*
Total'
1990
213.4
127.9
121.2
87.1
29.2
24.3
26.4
7.9
7.1
4.9
1.2
0.7
+
0.2
651.3
fSE;
r '•'
EL.
i ^ ,
rf.'.'
":
fc* '
*—-
£. l""
1"? SH"'
t=v ' ":
L
*
,
.,,
'M
Ijr,
1 *
= *
i
,,»
'•£
:
-------
Petroleum is found in the same geological structures
as natural gas, and the two are often retrieved together.
Methane is also saturated in crude oil, and volatilizes as the
oil is exposed to the atmosphere at various points along the
system. Methane emissions from the components of
petroleum systems—including crude oil production, crude
oil refining, transportation, and distribution—generally
occur as a result of system leaks, disruptions, and routine
maintenance. In 2000, emissions from petroleum systems
were just under 4 percent of U.S. methane emissions.
Enteric Fermentation (123.9 Tg C02 Eq.)
During animal digestion, methane is produced through
the process of enteric fermentation, in which microbes
residing in animal digestive systems break down the feed
consumed by the animal. Ruminants, which include cattle,
buffalo, sheep, and goats, have the highest CH4 emissions
among all animal types because they have a rumen, or large
fore-stomach, in which CH4-producing fermentation occurs.
Non-ruminant domestic animals, such as pigs and horses,
have much lower CH4 emissions. In 2000, enteric
fermentation was the source of about 20 percent of U.S.
CH4 emissions, and more than half of the CH4 emissions
from agriculture. From 1990 to 2000, emissions from this
source decreased by 3 percent. Emissions from enteric
fermentation have been generally decreasing since 1995,
primarily due to declining dairy cow and beef cattle
populations.
Coal Mining (61.0 Tg C02 Eq.)
Produced millions of years ago during the formation
of coal, CH4 trapped within coal seams and surrounding rock
strata is released when the coal is mined. The quantity of
CH4 released to the atmosphere during coal mining
operations depends primarily upon the depth and type of
the coal that is mined.
Methane from surface mines is emitted directly to the
atmosphere as the rock strata overlying the coal seam are
removed. Because CH4 in underground mines is explosive
at concentrations of 5 to 15 percent in air, most active
underground mines are required to vent this methane,
typically to the atmosphere. At some mines, CH4-recovery
systems may supplement these ventilation systems.
Recovery of CH4 in the United States has increased in recent
years. During 2000, coal mining activities emitted 10
percent of U.S. CH4 emissions. From 1990 to 2000,
emissions from this source decreased by 30 percent due to
increased use of the CH4 collected by mine degasification
systems and a general shift toward surface mining.
Manure Management (37.5 Tg C02 Eq.)
The decomposition of organic animal waste in an
anaerobic environment produces methane. The most
important factor affecting the amount of CH4 produced is
how the manure is managed, because certain types of storage
and treatment systems promote an oxygen-free environment.
In particular, liquid systems tend to encourage anaerobic
conditions and produce significant quantities of CH4,
whereas solid waste management approaches produce little
or no CH4. Higher temperatures and moist climatic
conditions also promote CH4 production.
Emissions from manure management were about 6
percent of U.S. CH4 emissions in 2000 and 22 percent of
the methane emissions from agriculture. From 1990 to 2000,
emissions from this source increased by 28 percent. The
bulk of this increase was from swine and dairy cow manure,
and is attributed to the shift in the composition of the swine
and dairy industries towards larger facilities. Larger swine
and dairy farms tend to use liquid management systems.
Wastewater Treatment (28.7 Tg C02 Eq.)
Wastewater from domestic sources (i.e., municipal
sewage) and industrial sources is treated to remove soluble
organic matter, suspended solids, pathogenic organisms and
chemical contaminants. Soluble organic matter is generally
removed using biological processes in which
microorganisms consume the organic matter for
maintenance and growth. Microorganisms can biodegrade
soluble organic material in Wastewater under aerobic or
anaerobic conditions, with the latter condition producing
CH4. During collection and treatment, wastewater may be
accidentally or deliberately managed under anaerobic
conditions. In addition, the sludge may be further
biodegraded under aerobic or anaerobic conditions.
Untreated wastewater may also produce CH4 if contained
under anaerobic conditions.
Executive Summary ES-19
-------
Stationary and Mobile Combustion (11.9 Tg C02 Eq.)
Stationary and mobile combustion were responsible for
methane emissions of 7.5 and 4.4 Tg CO2 Eq., respectively.
The majority of emissions from stationary combustion
resulted from the burning of wood in the residential end-
use sector. The combustion of gasoline in highway vehicles
was responsible for the majority of the CH4 emitted from
mobile combustion.
Rice Cultivation (7.5 Tg C02 Eq.)
Most of the world's rice, and all of the rice in the United
States, is grown on flooded fields. When fields are flooded,
anaerobic conditions develop and the organic matter in the
soil decomposes, releasing methane to the atmosphere,
primarily through the rice plants. In 2000, rice cultivation
was the source of 1 percent of U.S. methane emissions, and
about 4 percent of U.S. CH4 emissions from agriculture.
Emission estimates from this source have increased about
5 percent since 1990 due to an increase in the area harvested.
Petrochemical and Silicon Carbide Production
(1.7TgC02Eq.)
Methane emissions resulted from two industrial
sources, petrochemical and silicon carbide production.
Small amounts of CH4 were released during the production
of five petrochemicals: carbon black, ethylene, ethylene
dichloride, styrene, and methanol. These production
processes resulted in emissions of 1.7 Tg CO2 Eq. in 2000.
Methane is also emitted from the production of silicon
carbide, a material used as an industrial abrasive. In 2000,
silicon carbide production resulted in emissions of less than
0.1TgC02Eq.
Agricultural Residue Burning (0.8 Tg C02 Eq.)
Burning crop residue releases a number of greenhouse
gases, including CH4. Because field burning is not a common
debris clearing method used in the United States, it was
responsible for only 0.1 percent of U.S. CH emissions in 1999.
Nitrous Oxide Emissions
Nitrous oxide (N2O) is a greenhouse gas that is
produced both naturally—from a wide variety of biological
sources in soil and water—and anthropogenically by a
variety of agricultural, energy-related, industrial, and waste
management activities. While total N2O emissions are much
smaller than CO2 emissions, N2O is approximately 300 times
more powerful than CO2 at trapping heat in the atmosphere.
Since 1750, atmospheric concentrations of N2O have risen
by approximately 16 percent (IPCC 2001). The main
anthropogenic activities producing N2O in the United States
were agricultural soil management, fuel combustion in motor
vehicles, and nitric acid production (see Figure ES-15 and
Table ES-11).
Agricultural Soil Management (297.6 Tg C02 Eq.)
Nitrous oxide is produced naturally in soils through
microbial processes of nitrification and denitrification. A
number of anthropogenic activities add to the amount of
nitrogen available to be emitted as N2O by microbial
Figure ES-15
Agricultural
Soil Management
Mobile Sources
Nitric Acid
Stationary Sources
Manure Management
Human Sewage
Adipic Acid
Agricultural
Residue Burning
Waste Combustion
297.6
N2O as a Portion
of All Emissions
6.1%
0.5
0.2
0
0 10 20 30 40 50 60 70
Tg C02 Eq.
ES-20 inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table ES-11: U.S. Sources of Nitrous Oxide Emissions (Tg C02 Eq.)
Source
Agricultural Soil Management
Mobile Sources
.Nitric Acid
Manure Management
Stationary Sources
Human Sewage
Adipic Acid
"Agricultural Residue Burning
Waste Combustion
International Bunker Fuels*
Total*
1990
267.1
50.9
17.8
16.0
12.8
7.0
14.9
0.4
0.3
1.0
387.3
f...
'
lEiS!
jpj,,:f
£—*•
1995
283.4
60.4
19.9
16.4
13.5
7.7
17.9
0.4
0.3
0.9
419.8
1996
292.6
60.1
20.7
16.8
14.1
7.8
17.8
0.4
0.3
0.9
430.5
1997
297.5
59.7
21.2
17.1
14.2
7.9
11.5
0.4
0.3
1.0
429,8
1998
298.4
59.1
20.9
17.1
14.3
8.1
7.7
0.5
0.2
1.0
426.3
1999
296.3
58.7
20.1
17.1
14.6
8.4
7.7
0.4
0.2
0.9
423.5
2000
297.6 "
58.3
19.8
17.5
14.9
8.5
8.1 :
0.5
0.2
0.9 1
425.3
* Emissions from International Bunker Fuels are not included in totals.
Note: Totals may not sum due to independent rounding.
processes. These activities may add nitrogen to soils either
directly or indirectly. Dkect additions occur through the
application of synthetic and organic fertilizers; production
of nitrogen-fixing crops; the application of livestock manure,
crop residues, and sewage sludge; cultivation of high-
organic-content soils; and direct excretion by animals onto
soil. Indirect additions result from volatilization and
subsequent atmospheric deposition, and from leaching and
surface run-off of some of the nitrogen applied to soils as
fertilizer, livestock manure, and sewage sludge.
In 2000, agricultural soil management accounted for
70 percent of U.S. N2O emissions. From 1990 to 2000,
emissions from this source increased by 11 percent as
fertilizer consumption, manure production, and crop
production rose.
Stationary and Mobile Combustion (73.2 Tg C02 Eq.)
Nitrous oxide is a product of the reaction that occurs
between nitrogen and oxygen during fuel combustion. Both
mobile and stationary combustion emit N2O, and the quantity
emitted varies according to the type of fuel, technology,
and pollution control device used, as well as maintenance
and operating practices. For example, catalytic converters
installed to reduce motor vehicle pollution can result in the
formation of N2O.
In 2000, N2O emissions from mobile combustion were
14 percent of U.S. N2O emissions, while stationary
combustion accounted for 4 percent. From 1990 to 2000,
combined N2O emissions from stationary and mobile
combustion increased by 15 percent, primarily due to
increased rates of N2O generation in highway vehicles.
Adipic Acid Production (8.1 Tg C02 Eq.)
Most adipic acid produced in the United States is used
to manufacture nylon 6,6. Adipic acid is also used to
produce some low-temperature lubricants and to add a
"tangy" flavor to foods. Nitrous oxide is emitted as a by-
product of the chemical synthesis of adipic acid.
In 2000, U.S. adipic acid plants emitted 2 percent of
U.S. N2O emissions. Even though adipic acid production
has increased, by 1998, all three major adipic acid plants in
the United States had voluntarily implemented N2O
abatement technology. As a result, emissions have decreased
by 46 percent since 1990.
Nitric Acid Production (19.8 Tg C02 Eq.)
Nitric acid production is another industrial source of
N2O emissions. Used primarily to make synthetic
commercial fertilizer, this raw material is also a major
component in the production of adipic acid and explosives.
Virtually all of the nitric acid manufactured in the
United States is produced by the oxidation of ammonia,
during which N2O is formed and emitted to the atmosphere.
In 2000, N2O emissions from nitric acid production
accounted for 5 percent of U.S. N2O emissions. From 1990
to 2000, emissions from this source category increased by
11 percent as nitric acid production grew.
Executive Summary ES-21
-------
Manure Management (17.5 Tg C02 Eq.)
Nitrous oxide is produced as part of microbial
nitrification and denitrification processes in managed and
unmanaged manure, the latter of which is addressed under
agricultural soil management. Total N2O emissions from
managed manure systems in 2000 accounted for 4 percent
of U.S. N2O emissions. From 1990 to 2000, emissions from
this source category increased by 9 percent, as poultry and
swine populations have increased.
Agricultural Residue Burning (0.5 Tg C02 Eq.)
Large quantities of agricultural crop residues are
produced by farming activities, some of which is disposed
by burning in the field. Field burning of crop residues is a
source of N2O, which is released during combustion. Field
burning is not a common method of agricultural residue
disposal in the United States; therefore, emissions from this
source are minor.
Human Sewage (8.5 Tg C02 Eq.)
Domestic human sewage is usually mixed with other
household wastewater and transported by a collection
system to either a direct discharge, an on-site or
decentralized wastewater system, or a centralized
wastewater system. After processing, treated effluent may
be discharged to a receiving water environment (e.g., river,
lake, estuary, etc.), applied to soils, or disposed of below
the surface. Nitrous oxide (N2O) may be generated during
both nitrification and denitrification of the nitrogen that is
present in the sewage, usually in the form of urea and
proteins. Emissions of N2O from treated human sewage
discharged into aquatic environments were estimated to be
8.5TgCO2Eq.in2000.
Waste Combustion (0.2 Tg C02 Eq.)
Combustion is used to manage about 7 to 17 percent of
the municipal solid wastes (MSW) generated in the United
States. Almost all combustion of MSW in the United States
occurs at waste-to-energy facilities where energy is
recovered. Most of the organic materials in MSW are of
biogenic origin (e.g., paper, yard trimmings). However,
some components—plastics, synthetic rubber, and synthetic
fibers—are of fossil origin, which accounted for emissions
of 0.2 Tg CO2 Eq. in 2000.
HFC, PFC, and SF6 Emissions
. Hydrofluorocarbons (HFCs) and perfluorocarbons
(PFCs) are categories of synthetic chemicals that are being
used as alternatives to the ozone depleting substances
(ODSs), which are being phased out under the Montreal
Protocol and Clean Air Act Amendments of 1990. Because
HFCs and PFCs do not deplete the stratospheric ozone layer,
they are not controlled by the Montreal Protocol.
These compounds, however, along with sulfur
hexafluoride (SF6), are potent greenhouse gases. In addition
to having high global warming potentials, SF6 and PFCs
have extremely long atmospheric lifetimes, resulting in their
essentially irreversible accumulation in the atmosphere once
emitted. Sulfur hexafluoride is the most potent greenhouse
gas the IPCC has evaluated.
Other emissive sources of these gases include aluminum
production, HCFC-22 production, semiconductor
manufacturing, electrical transmission and distribution systems,
and magnesium production and processing. Figure ES-16 and
Table ES-12 present emission estimates for HFCs, PFCs, and
SF6, which totaled 121.3 Tg CO2 Eq. in 2000.
Figure ES-16
Substitution of Ozone
Depleting Substances
HCFC-22
Production
Electrical Transmission
and Distribution
Aluminum B
Production HI
Semiconductor H
Manufacture H
Magnesium Production 1
HFC, PFC, and SF6
as a Portion of
All Emissions
1.7%
and Processing
0 10 20 30 40 50 60 70
Tg C02 Eq.
ES-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table ES-12: Emissions of HFCs, PFCs, and SF6 (Tg C02 Eq.)
y,-»i-__ . ,_!'._ . . - „_'-''' L.1- '. '• .'. ' ',*•
fclSource ,.'..'~~'~~. 1996
F Substitution of Ozone Depleting Substances 0.9
t HCFC-22 Production 35.0
fc Electrical Transmission and Distribution 31 .2
p Aluminum Production 18.1
! Semiconductor Manufacture 2.9
£ Magnesium Production and Processing 5.5
r Total 93.6
fe Note: Totals may not sum due to independent rounding.
sm 1995
21.8
27.0
UssJii 265
EH* 11-8
5.9
^Z 5.5 ;..
98.5
1996
30.6
31,1
26.8
12.5
• 5.4
5.5
111.9
1997
38.0
30.0
24.5
11.0
6.5
6.9
116.9
1998
44.9
40.2
20.1
9.0
7.3
6.2
127.7
1999
51.3
30.4
15.5
8.9
7.7
6.1
120.0
2000
57.8
29.8
14.4
7.9
7.4
4.0 :
121.3
Substitution of Ozone Depleting Substances
(57.8 Tg C02 Eq.)
The use and subsequent emissions of HFCs and PFCs
as substitutes for ozone depleting substances (ODSs) have
increased from small amounts in 1990 to account for 48
percent of aggregate HFC, PFC, and SF6 emissions. This
increase was in large part the result of efforts to phase-out
chlorofluorocarbons (CFCs) and other ODSs in the United
States, especially the introduction of HFC-134a as a CFC
substitute in refrigeration and air-conditioning applications.
In the short term, this trend is expected to continue, and
will likely accelerate in the next decade as
hydrochlorofluorcarbons (HCFCs), which are interim
substitutes in many applications, are themselves phased-
out under the provisions of the Copenhagen Amendments
to the Montreal Protocol. Improvements in the technologies
associated with the use of these gases and the introduction
of alternative gases and technologies, however, may help
to offset this anticipated increase in emissions.
Aluminum Production (7.9 Tg C02 Eq.)
During the production of primary aluminum, two
PFCs—CF4 and C2F6—are emitted as intermittent by-
products of the smelting process. These PFCs are primarily
formed when fluorine from the croylite bath combines with
carbon from the electrolyte anode. Emissions from
aluminum production have decreased by 56 percent between
1990 and 2000 due to emission reduction efforts by the
industry and falling domestic aluminum production.
HCFC-22 Production (29.8 Tg C02 Eq.)
HFC-23 is a by-product emitted during the production
of HCFC-22. Emissions from this source have decreased
by 15 percent since 1990. The intensity of HFC-23
emissions (i.e., the amount of HFC-23 emitted per kilogram
of HCFC-22 manufactured) has declined significantly since
1990, although production has been increasing.
Semiconductor Manufacturing (7.4 Tg C02 Eq.)
The semiconductor industry uses combinations of
HFCs, PFCs, SF6 and other gases for plasma etching and
to clean chemical vapor deposition tools. Emissions from
this source category have increased with the growth in the
semiconductor industry and the rising intricacy of chip
designs. However, the growth rate in emissions has slowed
since 1997, and emissions actually declined between 1999
and 2000. This later reduction is due to the implementation
of PFC emission reduction methods, such as process
optimization.
Electrical Transmission and Distribution Systems
(14.4TgC02Eq.)
The primary use of SF6 is as a dielectric in electrical
transmission and distribution systems. Fugitive emissions
of SF6 occur from leaks in and servicing of substations and
circuit breakers, especially from older equipment. Estimated
emissions from this source decreased by 54 percent since
1990, primarily due to higher SFS prices and industrial
efforts to reduce emissions.
Magnesium Production (4.0 Tg C02 Eq.)
SF6 is also used as a protective covergas for the casting
of molten magnesium. Emissions from primary magnesium
production and magnesium casting have decreased by 27
percent since 1990. Emissions have decreased since 1999,
due to a decrease in the quantity of magnesium die cast and
the closure of a U.S. primary magnesium production facility.
Executive Summary ES-23
-------
Box ES-3: Emissions of Ozone Depleting Substances
Manmade halogenated compounds were first emitted into the atmosphere in significant quantities during the 20th century. This
family of man-made compounds includes CFCs, halons, methyl chloroform, carbon tetrachloride, methyl bromide, and
hydrochlorofluorocarbons (HCFCs). These substances have been used in a variety of industrial applications, including refrigeration, air
conditioning, foam blowing, solvent cleaning, sterilization, fire extinguishing, agricultural fumigation and sterilization, coatings, paints,
and aerosols.
Because these compounds have been shown to deplete stratospheric ozone, they are typically referred to as ozone depleting
substances (ODSs). However, they are also potent greenhouse gases.
Recognizing the harmful effects of these compounds on the ozone layer, in 1987 many governments signed the Montreal Protocol
on Substances that Deplete the Ozone Layer to limit the production and importation of a number of CFCs and other halogenated
compounds. The United States furthered its commitment to phase out ODSs by signing and ratifying the Copenhagen Amendments to
the Montreal Protocol in 1992. Under these amendments, the United States committed to ending the production and importation of
halons by 1994, and CFCs by 1996.
The IPCC Guidelines and the UNFCCC do not include reporting instructions for estimating emissions of ODSs because their use is
being phased out under the Montreal Protocol. The United States believes that a greenhouse gas emissions inventory is incomplete
without these emissions; therefore, estimates for several Class I and Class II ODSs are provided in Table ES-13. Compounds are
grouped by class according to their ozone depleting potential. Class I compounds are the primary ODSs; Class II compounds include
partially halogenated chlorine compounds (i.e., HCFCs), some of which were developed as interim replacements for CFCs. Because
these HCFG compounds are only partially halogenated, their hydrogen-carbon bonds are more vulnerable to oxidation in the troposphere
and, therefore, pose only one-tenth to one-hundredth the threat to stratospheric ozone compared to CFCs.
ft should be noted that the effects of these compounds on radiative forcing are not provided. Although many ODSs have relatively
high direct GWPs, their indirect effects from the destruction of ozone—also a greenhouse gas—are believed to have negative radiative
forcing effects, and therefore could significantly reduce the overall magnitude of their radiative forcing effects. Given the uncertainties
surrounding the net effect of these gases, emissions are reported on an unweighted basis.
Table ES-13: Emissions of Ozone Depleting Substances (Gg)
Compound
Class I
CFC-11
CFC-12
CFC-11 3
CFC-11 4
CFC-11 5
Carbon Tetrachloride
Methyl Chloroform
HaIon-1211
Halon-1301
Class II
HCFC-22
HCFC-123
HCFC-124
HCFC-141b
HCFC-142b
HCFC-225ca/cb
Source: EPA, Office of Atmospheric Programs
+ Does not exceed 0.5 Gg
1990
53.5
112.6
52.7
4.7
4.2
32.3
316.6
1.0
1.8
34.0
+
+
1.3
0.8
+
L,,
tor
1-
*:::
|I
1
.
&
E
|:"
F
L
tl
L
s»
*"
u
K?
i
""...'":*
^
•s *
^1
33
™"i
1
--- ;,fj
•J:,,! ,-1
" I
•4
§
' i
„,_. , j
!
1
,lj
: ; i
1995
36.2
51.8
17.1
1.6
3.0
4.7
92.8
1.1
1.4
39.3
0.6
5.6
9.9
3.6
+
1996
26.6
35.5
+
0.3
3.2
+
+
1.1
1.4
41.0
0.7
5.9
9.9
4.0
+
1997
25.1
23.1
+
0.1
2.9
+
+
1.1
1.3
42.4
0.8
6.2
8.8
4.3
+
1998
24.9
21.0
+
0.1
2.7
+
+
1.1
1.3
43.8
0.9
6.4
9.7
4.7
+
1999
24.0
14.0
+
+
2.6
+
+
1.1
1.3
74.1
1.0
6.5
10.9
5.0
+
2000
22.8
17.2
+
+
2.3
+
+
1.1
1.3
79.1
1.1
6.5 .
10.9
5.4
+
ES-24 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Ambient Air Pollutant Emissions
In the United States, carbon monoxide (CO), nitrogen
oxides (NOx), nonmethane volatile organic compounds
(NMVOCs), and sulfur dioxide (SO2) are referred to as
"ambient air pollutants," as termed in the Clean Air Act.
These pollutants do not have a direct global wanning effect,
but indirectly affect terrestrial radiation absorption by
influencing the formation and destruction of tropospheric
and stratospheric ozone, or, in the case of SO2, by affecting
the absorptive characteristics of the atmosphere. Carbon
monoxide is produced when carbon-containing fuels are
combusted incompletely. Nitrogen oxides (i.e., NO and
NO2) are created by lightning, fires, fossil fuel combustion,
and in the stratosphere from nitrous oxide (N2O).
NMVOCs—which includes hundreds of organic
compounds that participate in atmospheric chemical
reactions (i.e., propane, butane, xylene, toluene, ethane and
many others)—are emitted primarily from transportation,
industrial processes, and non-industrial consumption of
organic solvents. In the United States, SO2 is primarily
emitted from coal combustion for electric power generation
and the metals industry.
Ambient air pollutants are regulated under the Clean
Air Act in ah effort to protect human health and the
Box ES-4: Sources and Effects of Sulfur Dioxide
environment. These gases also indkectly affect the global
climate by either acting as short-lived greenhouse gases or
reacting with other chemical compounds in the atmosphere
to form compounds that are greenhouse gases. Unlike the
other ambient air pollutants, sulfur-containing compounds
emitted into the atmosphere affect the Earth's radiative
budget negatively; therefore, it is discussed separately.
One important indirect climate change effect of
NMVOCs and NOx is their role as precursors for
tropospheric ozone formation. They can also alter the
atmospheric lifetimes of other greenhouse gases. Another
example of ambient air pollutant formation into greenhouse
gases is carbon monoxide's interaction with the hydroxyl
radical—-the major atmospheric sink for methane
emissions—to form CO2. Therefore, increased atmospheric
concentrations of CO limit the number of hydroxyl
molecules (OH) available to destroy methane.
Since 1970, the United States has published estimates
of annual emissions of ambient air pollutants (EPA 2001).1S
Table ES-14 shows that fuel combustion accounts for the
majority of emissions of these gases. Industrial processes—
such as the manufacture of chemical and allied products,
metals processing, and industrial uses of solvents—are also
significant sources of CO, NOx and NMVOCs.
Sulfur dioxide (S02) emitted into the atmosphere through natural and anthropogenic processes affects the Earth's radiative budget
fthrough its photochemical transformation into sulfate aerosols that can (1) scatter radiation from the sun back to space, thereby
reducing the radiation reaching the Earth's surface; (2) affect cloud formation; and (3) affect atmospheric chemical composition (e.g.,
_by providing surfaces for heterogeneous chemical reactions). The indirect effect of sulfur-derived aerosols on radiative forcing can be
considered in two parts. The first indirect effect is the aerosols' tendency to decrease water droplet size and increase water droplet
concentration in the atmosphere. The second indirect effect is the tendency of the reduction in cloud droplet size to affect precipitation
by increasing cloud lifetime and thickness. Although still highly uncertain, the radiative forcing estimates from both the first and the
- second indirect effect are believed to be negative, as is the combined radiative forcing of the two (1PCC 2001). However, because S02
is short-lived and unevenly distributed in the atmosphere, its radiative forcing impacts are highly uncertain.
. Sulfur dioxide is also a major contributor to the formation of regional haze, which can cause significant increases in acute and
chronic respiratory diseases. Once S02 is emitted, it is chemically transformed in the atmosphere and returns to the Earth as the
primary source of acid rain. Because of these harmful effects, the United States has regulated S02 emissions in the Clean Air Act.
Electricity generation is the largest anthropogenic source of S02 emissions in the United States, accounting for 63 percent in 2000.
Coal combustion contributes nearly all of those emissions (approximately 94 percent). Sulfur dioxide emissions have decreased in
: recent years, primarily as a result, of electric power generators switching from high sulfur to low sulfur coal and installing flue gas
\ desulfurization equipment.
' NOX and CO emission estimates from agricultural residue burning were estimated separately, and therefore not taken from EPA (2001).
Executive Summary ES-25
-------
Table ES-14: Emissions of NOX, CO, NMVOCs, and S02 (Gg)
Gas/Activity
NOX
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Industrial Processes
Solvent Use
Agricultural Burning
Waste
CO
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Industrial Processes
Solvent Use
Agricultural Burning
Waste
NMVOCs
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Industrial Processes
Solvent Use
Agricultural Burning
Waste
S02
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Industrial Processes
Solvent Use
Agricultural Burning
Waste
1990
21,873
9,884
10,900
139
921
1
28
+
85,016
4,999
69,523
302
9,502
4
685
1
18,630
912
8,154
555
3,110
5,225
NA
673
21,481
18,407
1,339
390
1,306
+
NA
39
u rrs
i"*'1"" *
P, ,,„«
«i
Sr^ i i nui '
fevi '4
I-L:;::-;:
fc '• ' .••'
f* V < "0
j— ,-»'.«
ll':'' ''l
Jr"HI
ffl'v I
r*~'^il !v''i
'•"!
pftr- • ,- -^
PI
j:,_.:_|
!$.
jr. !
»
1
S- .
£ J
r ' *
S i
r
i- •
p
L \
X
l_^
'
1 '
1995
24,126
9,822
13,329
100
842
3
29
1
79,726
5,383
68,072
316
5,291
5
656
2
18,434
973
7,725
582
2,805
5,618
NA
731
17,408
14,724
1,189
334
1,117
1
NA
43
1996
24,999
9,522
14,338
126
976
3
32
3
87,109
3,936
74,927
321
7,171
1
747
5
17,411
1,020
8,485
433
2,344
4,973
NA
156
17,629
14,726
1,612
304
958
1
NA
29
1997
25,508
9,577
14,771
130
991
3
34
3
87,567
3,926
73,764
333
8,776
1
761
5
17,766
1,019
8,257
442
2,783
5,108
NA
157
18,076
15,104
1,636
312
993
1
NA
30
1998
25,470
9,400
14,976
130
924
3
35
3
83,379
3,905
72,797
332
5,557
1
781
5
16,797
1,018
8,158
440
2,341
4,679
NA
161
18,185
15,192
1,655
310
996
1
NA
31
1999
25,224
9,022
15,087
130
946
3
34
3
86,354
3,928
70,565
332
10,763
1
760
5
16,970
1,025
7,962
385
3,043
4,390
NA
164
17,541
14,540
1,668
309
992
1
NA
31
2000
25,038
8,740
14,941
132
1,184
3
35
3
94,033
4,140
69,296
335
19,469
1
786
5
17,907
1,089
7,638
393
4,232
4,388
NA
168
16,498
13,496
1,626
314
1,031
+
NA
32
Source: (EPA2001) except for estimates from agricultural burning.
+ Does not exceed 0.5 Gg
NA (Not Available)
Note: Totals may not sum due to independent rounding.
ES-26 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Changes in This Year's
Inventory Report
;ach year the U.S. Greenhouse Gas Inventory Program not only recalculates and revises the emission and sink
estimates for all years that are presented in the Inventory of U.S. Greenhouse Gas Emissions and Sinks but also
attempts to improve the analyses themselves through the use of better methods or data as well as the overall usefulness of
the report. A summary of this year's changes is presented in the following sections and includes changes in methodology
in addition to updates to historical data. The magnitude of each change is also described. Table Changes-1 summarizes
the quantitative effect of these changes on U.S. greenhouse gas emissions and Table Changes-2 summarizes the quantitative
effect on U.S. sinks, both relative to the previously published U.S. Inventory (i.e., 1990-1999 report). These tables
present the magnitude of these changes in units of teragrams of carbon dioxide (CO2) equivalents (Tg CO2 Eq.).
A number of significant methodological and data revisions have been made to this year's Inventory. Fuel consumption
for electricity generation by non-utilities was removed from the industrial end-use sector and instead combined with
electric utility consumption - thus creating a comprehensive "electricity generation" sector. A series of improvements
were made to the estimate of CO2 emissions and carbon storage from the non-energy use (NEU) of fossil fuels, including
an enhanced analysis of storage and emissions for a set of fuels used as raw material inputs in petrochemicals production,
as well as reallocating emissions from non-energy fuel uses in industrial processes to the Industrial Processes chapter
(e.g., Iron and Steel Production), and, finally, accounting for the oxidation of non-combustion, non-biogenic fossil sources
of methane. Methane emission estimates for industrial wastewater now include food processing, whereas they previously
included only the pulp and paper industry. The Land-Use Change and Forestry chapter now includes estimates on changes
in carbon stocks in urban trees. Significant revisions have also been made to estimates of SFfi emissions from Magnesium
Production and Processing and from Electric Power Transmission and Distribution Systems, based on newly reported
data from industry. These revisions are among numerous others explained in detail below.
Changes in historical data are generally the result of changes in statistical data supplied by other agencies. Data
sources are provided for further reference.
For methodological changes, differences between the previous Inventory report and this report are explained. In
general, when methodological changes have been implemented, the entire time series (i.e., 1990 through 1999) has been
recalculated to reflect the change.
Changes-1
-------
Table Ghanges-1: Revisions to U.S. Greenhouse Gas Emissions (Tg C02 Eq.)
Gas/Source
C02
Fossil Fuel Combustion
Natural Gas Baring
Cement Manufacture
Lime Manufacture
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Carbon Dioxide Consumption
Waste Combustion
Titanium Dioxide Production3
Aluminum Production3
Iron and Steel Production3
Ferroalloys3
Indirect C02 Emissions from CH4 Oxidation3
Ammonia Manufacture3
International Bunker Fuels
CH4
Stationary Sources
Mobile Sources
Coal Mining
Natural Gas Systems
Petroleum Systems
Petrochemical Production
Silicon Carbide Production
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Residue Burning
Landfills
Wastewater Treatment
International Bunker Fuels
N20
Stationary Sources
Mobile Sources
AdipicAcid
Nitric Acid
Manure Management
Agricultural Soil Management
Agricultural Residue Burning
Human Sewage
Waste Combustion
International Bunker Fuels
HFCs, PFCs, and SF6
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production
Semiconductor Manufacture
Electrical Transmission and Distribution
Magnesium Production and Processing
Net Change in Total Emissions'3
Percent Change
+ Absolute value does not exceed 0.05 Tg C02 Eq.
"New source category relative to previous inventory.
" Excludes emissions from land-use change and forestry.
NC (No Change)
Note: Totals may not sum due to independent rounding.
1990
85.6
(55.8)
0.4
NC
+
0.1
+
NC
(3.5)
1.3
6.3
85.4
2.0
30.9
18.5
(0.1)
6.8
(0.6)
(0.1)
(0.7)
(0.8)
NC
NC
(1.6)
2.8
(1.6)
0.2
(3.9)
13.1
0.1
(9-6)
(0.8)
(3.4)
(3.4)
NC
+
(1.9)
+
(0.1)
NC
+
9.7
NC
(1.2)
0.2
+
10.7
NC
92.5
1.5%
n " 1995
86.1
f : (36.2)
: • (4.9)
- . NC
i * +
! t +
I:"! NC
I'.'-. J (4.5)
t: :j 1.7
k:..J 5.3
E:,";! 74.4
1.9
E::;II 29.5
I::;,:,! 18.9
t .' ' :| +
r :""" 7.1
sr^5 (o.6)
W :1 (O-1)
1 m* (1-0)
SFl 1-5
|l,T| (0.3)
t*~" i +
1 NC
H; (3.1)
f;:: ; * 3.8
t::>;| (1 9)
IS^t^'af V ' p ^/
»;"= 0.1
i=:;:J (6.3)
15.0
gpp.il 0.1
|7-::: (12.2)
£":.] (0.8)
r ! (6.4)
•rr-i (2.4)
= :, ..i NC
E=;--- +
tvil <1'9)
fe--: ' +
|- :i (0.5)
j: 4 NC
|i~ii| +
f"? (()5)
r :i (2-2)
I?-;S 0.6
t:,:1 (0.1)
k---4 0.4
.; ; 0.8
|.;: :"S +
r ^* 80.5
: * 1.3%
1996
80.5
(36.3)
(4.8)
NC
+
0.1
+
NC
(4.4)
1.7
5.6
68.3
2.0
28.9
19.5
0.1
5.8
(0.6)
(0.1)
(1.0)
0.8
+
+
NC
(2.6)
3.5
(1.8)
0.2
(7.6)
15.1
0.1
(11-D
(0.8)
(5.2)
(3.0)
NC
+
(2.0)
+
+
NC
+
(3.2)
(3.4)
0.9
(0.1)
(1.6)
1.1
(0.1)
71.9
1.1%
1997
89.3
(35.4)
(4.5)
NC
NC
0.1
(0.1)
NC
(4.3)
1.8
5.6
76.1
2.0
28.4
19.5
0.1
1.3
(0.6)
(0.2)
(0.6)
0.1
+
+
NC
(2.8)
3.2
(2.1)
0.2
(11.4)
15.5
0.1
(14.3)
(0.8)
(5.5)
(5.6)
NC
+
(2.3)
+
+
NC
+
(6.4)
(4.1)
0.1
(0.1)
(0.5)
(1.2)
(0.6)
70.0
1.0%
1998
85.4
(30.6)
(4.6)
NC
NC
0.1
NC
NC
(4.9)
1.8
5.8
67.4
2.0
28.2
20.1
0.1
2.9
(0.6)
(0.1)
1.4
0.1
0.1
+
NC
(2.6)
2.8
(2.2)
0.2
(12.6)
15.7
0.1
(7.4)
(0.7)
(5.1)
0.5
NC
+
(1.9)
+
+
NC
+
(10.9)
(4.8)
(1.1)
0.2
0.5
(5.6)
(0-1)
69.4
1.0%
1999
107.3
(4.5)
(5.0)
0.1
+
0.8
NC
+
(4.1)
1.9
5.9
64.4
2.0
27.0
18.9
(2.0)
0.9
(0.8)
(0.1)
1.9
(3.2)
0.4
+
+
(2.7)
3.2
(2.4)
0.2
(11.5)
16.1
0.1
(9.0)
(1.1)
(4.7)
(1.3)
(0.1)
+
(2.0)
+
0.2
+
+
(15.8)
(5.4)
(1.1)
+
0.9
(10.2)
+
83.4
1.2%
Changes-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table Changes-2: Revisions to Net C02 Sequestration from Land-Use Change and Forestry {Tg C02 Eq.)
Component
f Forests
• Urban Trees3
1 Agricultural Soils3
Landfilled Yard Trimmings
x Net Change in Total Flux
. Percent Change
1990
19.1
(58.7)
3.1
(1.3)
(37.8)
3.6%
£»^ 1995
(40.7)
BS*1 (58.7)
86
£3 (0.2)
i»a (90.9)
Bill 8.9% .
1996
(36.3)
(58.7)
8.6
(0.1)
(86.5)
8.5%
1997
144.5
(58.7)
86
(0.1)
94.4
-9.6%
1998
145.6
(58.7)
101
0.4
97.4
-9.9%
1999
143.0
(58.7)
92
0.4
94.0
-9.5%
• iv\j yivu wiiui iijuy
Note: Numbers in parentheses indicate an increase in estimated net sequestration, or a decrease in net flux of C02 to the atmosphere In the "percent
change row, negative numbers indicate that the sequestration estimate has decreased, and positive numbers indicate that the sequestration estimate
has increased. Totals may not sum due to independent rounding.
a New source category relative to previous inventory.
Methodological Changes
Emissions and Storage from Non-Energy
Uses of Fossil Fuels
The following section addresses changes associated
with estimation of CO2 emissions from non-energy uses
(NEU) of fossil fuels. These changes affect a number of
source categories in both the Energy and Industrial Processes
chapters, including:
• CO2 from Fossil Fuel Combustion
• Waste Combustion
• Titanium Dioxide Production
• Aluminum Production
• Iron and Steel Production
• Ferroalloy Production
• Ammonia Manufacture
Among the most significant methodological changes
made in last year's inventory were a series of improvements
in the estimation of CO2 emissions and carbon storage from
NEU of fossil fuels. This year, as in years past, these NEU
emissions are addressed in the Energy chapter, as an
adjustment to total potential energy emissions. This year's
inventory introduces several new improvements, and better
integrates the characterization of non-energy fuel use with
the estimation of emissions from industrial processes.
Most of the changes relate to an improved analysis of
storage and emissions for a set of fuels used as raw material
inputs in petrochemicals production: petrochemical
feedstocks, liquefied petroleum gas, pentanes plus, and
natural gas (for "other uses"). For these fuels—collectively
referred to as "feedstocks"—an empirically determined
storage factor was developed. The storage factor is equal
to the ratio of (a) carbon stored in the final products to (b)
total carbon content of the feedstocks used as inputs to non-
energy uses. Last year's inventory used a storage factor for
these fuels of 91 percent; revisions made this year changed
the estimate by first accounting for net exports (i.e.,
approximately 9 percent of non-energy fuel consumption),
and then applying a revised storage factor of 63 percent.
In addition, this year's inventory makes several changes
in its approach for handling non-energy fuel uses in
industrial processes. In past years, most of the emissions
from these processes were captured as part of the NEU
storage and emissions calculations, and addressed in the
Energy chapter of the inventory.1 This year, the emissions
are included in the Industrial Processes chapter in keeping
with IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).
These changes are summarized below, first addressing
the feedstocks storage factor calculation, and then the
changes in the integration of non-energy uses into the
Industrial Processes chapter. The complete methods are
described in the Energy and Industrial Processes chapters,
and in Annex B.
1 For example, petroleum coke used to produce carbon anodes for aluminum production was previously considered as non-energy fossil fuel use and
carbon emissions from aluminum production were accounted for in the Energy chapter.
Changes-3
-------
Feedstocks Storage Factor
The approach for characterizing emissions from non-
energy uses of feedstocks relies on a mass balance approach,
in which total carbon is allocated between long-term storage
in products and losses through emissive processes. The
overall balance is expressed as a storage factor. This year's
storage factor for feedstocks incorporates several new
analyses:
• Imports and Exports of Chemical Intermediates and
Products. To some degree, the energy flows tracked
by the Energy Information Administration do not
capture fossil-derived materials once they leave
refineries labeled as "feedstocks," and are thus no
longer valued for their energy content. Although direct
imports and exports of primary chemicals are included
in EIA's statistics, imports and exports of some
chemical intermediates and products produced by the
chemical industry (e.g., xylenes, vinyl chloride, and
polypropylene resins) are not covered. This year's
analysis accounts for these flows—which results in an
adjustment for net exports, thus lowering potential
emissions—based on data collected by the National
Petroleum Refiners' Association.
• Energy Recovery from NEU Byproducts. The chemical
reactions in which fuel feedstocks are used are not 100
percent efficient, and unreacted feedstocks or
byproducts of production may be combusted for energy
recovery in industrial boilers. This year's inventory
includes an estimate of CO2 released by industrial
boilers as a result of combustion of these byproducts.
The estimate is based on newly available data from
EIA's Manufacturers Energy Consumption Survey
(MEGS) for 1998. The survey includes data on the
consumption for energy recovery of "other" fuels in
the petroleum and coal products, chemicals, primary
metals, nonmetallic minerals, and other manufacturing
sectors. Of the improvements to the methodology made
this year, this component has the greatest effect,
increasing the amount of carbon emitted (versus stored).
Solvent Evaporation. Some feedstocks are used to
produce solvents. Most solvents are organic (thus
containing carbon), and when emitted to the
atmosphere, eventually oxidize into CO2. Carbon
emissions are the product of (a) total solvent tonnage
released and (b) the average carbon content of the
solvents. This year's inventory incorporates a more
accurate estimate of the latter factor, based on newly
available data categorizing solvent emissions by
chemical species (last year's estimate was based on an
assumed average carbon content).
Non-Combustion CO. Similarly, some processes using
feedstocks for non-energy uses emit CO, which
eventually oxidizes to CO2 in the atmosphere. This
year's inventory includes emissions from non-
combustion sources in the mass balance on carbon
(combustion sources are accounted for as part of the
fossil fuel combustion analysis).
Waste Combustion. Last year's inventory addressed
combustion of fossil-derived waste materials in the
Waste chapter. This year waste combustion is
incorporated in the Energy chapter because the vast
majority of waste combustion is performed with energy
recovery. Hazardous waste combustion is considered
one of the processes through which feedstock carbon
is emitted, and is among the components of the mass
balance calculation of the storage factor.2 Municipal
waste combustion is addressed separately in the Energy
chapter.
Assumed Fate of "Unaccountedfor" Carbon. As with
last year, it was not possible to account for all reported
feedstock carbon by tallying all carbon in products and
emissions. Last year's inventory assumed that the
"unaccounted for" carbon had the same proportions,
in terms of storage and emissions, as the "accounted"
for carbon. This year, most of the unaccounted for
carbon was "found" through further investigation—
primarily in the analysis of exports and energy recovery.
To be conservative, and to reflect the fact that most of
2 In last year's inventory, hazardous waste combustion was subdivided into energy recovery and incineration (i.e., combustion without energy recovery).
This year's calculation included a large flow of carbon in the form of "Energy Recovery of NEU Byproducts"; a subset of this would involve
combustion of hazardous waste. Thus, the storage factor for this year specifically incorporates only incineration of hazardous waste. See Annex B for
details.
Changes-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
the newly "found" carbon was emitted—rather than
stored—this year's inventory assumes that all remaining
carbon that is unaccounted for is emitted.
Integration of Non-Energy Uses and Industrial
Processes
In some cases, it is difficult to make a distinction
between CO2 emissions from fossil fuels used in non-energy
applications and CO2 emissions from industrial processes.
This year, five sources previously characterized as non-
energy uses—and addressed in the Energy chapter—were
recharacterized as Industrial Process emissions in keeping
with the IPCC Guidelines (IPGC/UNEP/OECD/IEA1997):
• Natural Gas used in Ammonia Production. Ammonia
is produced from natural gas, which is used as both a
raw material feedstock and as a fuel for process heat in
the ammonia production process. In previous inventory
calculations, carbon emissions from the portion used
as a raw material feedstock were accounted for under
the non-energy use portion of the Energy chapter. In
the current inventory, these emissions are calculated
based on multiplying a newly developed emission factor
by reported annual ammonia production. This year,
natural gas used for ammonia production was classified
as an industrial process, resulting in an average transfer
of emissions of 19.2 Tg CO2 Eq. from the Energy
chapter to the Industrial Processes chapter from 1990
to 1999.
• Industrial Coking Coal used in Iron and Steel
Production. Iron and steel production is an industrial
process in which coal coke is used as a raw material
(i.e., reducing agent) in the blast furnace process. In
this year's Inventory, production and use of coal coke
for iron and steel production was classified as an
industrial process use rather than a fuel use. Iron and
steel production accounts for the major portion of
consumption of coal coke in the United States. This
year the total non-energy use of industrial coking coal,
as reported by EIA, was adjusted downward to account
for the consumption by the industry, as reported by the
U.S. Geological Survey. The remaining industrial non-
energy uses of coal coke—accounting for less than 5
percent of total consumption—have not been
recharacterized as industrial process uses, and are still
reported in the Energy chapter as non-energy use of
industrial coking coal. This change resulted in an
average transfer of emissions of 73.1 Tg CO2 from the
Energy chapter to the Industrial Processes chapter from
1990 to 1999.
Petroleum Coke used in Ferroalloy Production. In
previous years, ferroalloy production data were adjusted
such that production of miscellaneous alloys (i.e., 32-
65 percent silicon) were not included in the emission
calculation. This year's calculation has been revised
to include production of these miscellaneous alloys.
The ferroalloy process uses metallurgical coke as a raw
material. In previous years, consumption of coke in
the ferrosilicon production process was not calculated
explicitly. Emissions from coke consumption for
ferroalloy production were accounted for in the
calculations for industrial coking coal under fossil fuel
combustion in the Energy chapter. This year, coke used
for ferroalloy production was classified as an industrial
process, resulting in an average transfer of emissions
of 2.0 Tg CO2 Eq. from the Energy chapter to the
Industrial Processes chapter from 1990 to 1999.
In past years, metallurgical coke used in the production
of ferrosilicon was assumed to be coal coke. However,
it is now assumed that 100 percent of U.S. ferroalloy
production is produced using petroleum coke using an
electric arc furnace process, although it is possible that
some ferroalloys may be produced with coking coal,
wood, other biomass, or graphite carbon inputs. Carbon
dioxide emissions from ferroalloy production for this
inventory were calculated based on IPCC emission
factors and annual ferroalloy production data.
Consumption of petroleum coke for ferroalloy
production was calculated from the CO2 emissions
based on the carbon content of petroleum coke. The
calculated petroleum coke consumption for ferroalloy
production was then subtracted from total non-energy
consumption of petroleum coke reported by EIA.
Petroleum Coke used in Aluminum Production. The
aluminum production process uses carbon anodes that
are manufactured from coal tar pitch and petroleum
coke. In past years, consumption of petroleum coke
and coal tar pitch for carbon anodes for aluminum
production was considered as non-energy fossil fuel
use, and carbon emissions from aluminum production
Changes-5
-------
were accounted for in the Energy chapter. This year,
emissions from petroleum coke and coal tar pitch used
for aluminum production were reported under the
Industrial Processes chapter. This resulted in an average
transfer of emissions of 5.8 Tg CO2 from the Energy
chapter to the Industrial Processes chapter.
Carbon dioxide emissions from aluminum production
were calculated based on IPCC emission factors and
annual aluminum production data. Consumption of
petroleum coke and coal tar pitch for aluminum
production was calculated from the CO2 emissions
based on the petroleum coke and coal tar pitch content
of the carbon anodes used in the process. The petroleum
coke consumption was then subtracted from the total
non-energy consumption of petroleum coke reported
by EIA. The calculated coal tar pitch consumption was
also factored into the mass balance calculation for Iron
and Steel Production.
Additional changes to the estimates of CO2 and PFC
emissions for 1990 through 1999 are explained below
in the section entitled Aluminum Production.
Petroleum Coke used in Titanium Dioxide Production.
The titanium dioxide production process (i.e., chloride
process), which uses petroleum coke as a raw material,
was not previously included in the Inventory.
Previously, petroleum coke consumed in the titanium
dioxide process was embedded in the reported non-
energy use of petroleum coke in the Energy chapter,
and the associated CO2 emissions were included in the
Inventory only indirectly through application of a
storage factor to the non-energy use of petroleum coke.
For the current Inventory, carbon emissions from
titanium dioxide production are calculated based on an
emission factor and titanium dioxide production data.
The petroleum coke consumed for titanium dioxide
production was then subtracted from the total non-
energy consumption of petroleum coke reported by
EIA. This year, petroleum coke used for titanium
dioxide production was classified as an industrial
process, resulting in an average transfer of emissions
of 1.6 Tg CO2 from the Energy chapter to the Industrial
Processes chapter from 1990 to 1999.
Mobile Combustion (excluding C02)
The N2O emission factors for light-duty gasoline trucks
(LDGT), heavy-duty gasoline vehicles (HDGV), and
motorcycles (MC) found in the Revised 1996 IPCC
Guidelines (IPCC/UNEP/OECD/IEA 1997) have been
revised. In the previous Inventory, N2O emission factors
for these vehicle types were estimated by using data on
grams of CO2/km (as a proxy for fuel consumption) taken
from the Revised 1996 IPCC Guidelines (IPCC/UNEP/
OECD/IEA1997) for each vehicle type as a scaling factor,
and applying this factor to the passenger car N2O emission
factors to derive the LDGT, HDGV, and MC factors. This
CO2/km data, however, was found to contain inconsistencies
and potential errors. To correct for these errors and use
more country-specific information, U.S. miles per gallon
(MPG) data were applied as proxy data for this Inventory.
Fuel economy data were derived from a number of sources,
including DOE's Transportation Energy Data Book (DOE
1993 through 2001), FHWA's Highway Statistics (FHWA
1996 through 2001), EPA and DOE's Fuel Economy 2001
Datafile (EPA, DOE 2001), and the Vehicle Inventory and
Use Survey (Census 1997).
Previously, a static 8.7 percent of U.S. vehicle miles
traveled (VMT) was assumed to be attributable to California
for each year. (Due to stricter motor vehicle control
technologies standards in California, the VMT in California
is treated separately from national VMT to estimate
emissions.) This assumption has been replaced using the
percent of U.S. VMT represented by California for each
year, as obtained from the Federal Highway Administration
(FHWA 1996 through 2001).
Historically U.S. VMT data were obtained from EPA's
Office of Air Quality Planning and Standards (OAQPS), as
they redistribute FHWA VMT data into the vehicle
categories for which emission factors exist. This
redistribution was recalculated using fuel economy and
consumption data from FHWA's Highway Statistics.3 Fuel
economy and consumption data were disaggregated by fuel
type using a number of sources, including DOE's
Transportation Energy Data Book (DOE 1993 through
2001), FHWA's Highway Statistics (FHWA 1996 through
2001), EPA and DOE's Fuel Economy 2001 Datafile (EPA,
3 The existing VMT data from OAQPS was believed to contain some inconsistencies.
Changes-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
DOE 2001), and the Vehicle Inventory and Use Survey
(Census 1997). These data were used to distribute national
VMT estimates across vehicle categories. All of the revisions
discussed above resulted in an annual average decrease of
0.1 Tg of CO2 Eq. (2.2 percent) in CH4 emissions and an
annual average decrease of 5.2 Tg of CO2 Eq. (8.2 percent)
in N2O emissions for 1990 through 1999.
Coal Mining
The methodology used to estimate emissions avoided
at underground coal mines has changed from the previous
Inventory. For most mines with recovery systems, coal mine
operators and state agencies provided individual well
production data for all coalbed methane wells. Previously,
the amount of methane recovered was estimated based on
reported gas sales and a pre-drainage timing factor. The
new methodology produces a more realistic estimate of
emissions avoided for mines that utilize pre-drainage wells
for two reasons. First, the new methodology takes into
account the location of a well to determine if the well should
be included in the emissions avoided estimate. Many of
the pre-drainage wells within a degas field adjacent to a
coal mine were never inside the footprint of the mine
workings. Second, the entire cumulative production of a
pre-drainage well is credited toward emissions avoided for
only the year in which it is mined through, and not spread
out over several years. Recent research showed that the life
of a well within the same degas field can vary greatly.
Although the data used for annual gas sales was accurate,
the methodology resulted in an overestimation due to the
inclusion of production from pre-drainage wells that did
not contribute to emissions avoided at the coal mine. This
methodological revision resulted in average decrease of 0.1
Tg of CO2 Eq. (less than 0.1 percent) in annual CH4
emissions from coal mining for 1990 through 1999.
Petroleum Systems
In the Petroleum systems section of the Energy chapter,
this year's inventory corrects the activity factors for thirteen
methane emissions activities. The thirteen activities include
separators (heavy and light crude oil), heater/treaters and
compressors, pneumatic devices (high and low bleeds),
vessel blowdowns, compressor blowdowns, compressor
starts, chemical injection pumps, headers (heavy and light
crude oil), and gas engines. Two changes were made in
how activity data were estimated. First, the base year for
activity data estimation was changed. In the previous report,
the activity data were based on Radian (1996a-e), which
represented activity data for the year 1995. However, Radian
activity data for these thirteen activities were found to be
based on 1993 data rather than 1995 data. Therefore, this
year's inventory applies Radian's activity data to the correct
year, which is 1993, not 1995. Secondly, the drivers used
to estimate activity data outside the base year were refined.
In the previous inventory report, non-base year activity data
were related only to changes in crude production. This
year's inventory follows the Radian approach, which
estimated the annual activity data by calculating arithmetic
mean of component estimates based on oil well counts and
oil production for the years 1990 through 1992 and 1994
through 2000. The magnitude of the combined changes
was small. For example, the activity data for pneumatic
devices used in this year's Inventory is 3.4 percent lower
for the years 1990 to 1995 compared to the 1999 Inventory,
but the same data have been increased by an average of 2.9
percent over the period 1996 to 1999 for this year's
Inventory. These methodological revisions, together with
the data changes described below, resulted in average
decrease of 0.2 Tg of CO2 Eq. (0.8 percent) in annual CH4
emissions from petroleum systems for 1990 through 1999.
Natural Gas Flaring and Ambient Air
Pollutant Emissions in Oil and Gas
Activities
Estimates of natural gas flaring have been modified. The
amount of natural gas flared was previously calculated by
subtracting the vented gas emissions from the total amount of
natural gas reported as vented and flared (EIA 200la).
However, for the current Inventory, it was assumed that all
reported vented and flared gas was flared. This assumption is
consistent with that used by EIA in preparing their emission
estimates, under the assumption that many states require flaring
of natural gas (EIA 2000b). Additionally, one facility hi
Wyoming had been incorrectly reporting CO2 vented as CH4.
EIA has corrected these data in the Natural Gas Annual (EIA
2001a) for the years 1998 and 1999 only; data for previous
years were corrected for this Inventory by assuming a
proportionate share of CO2 in the flare gas for those years as
Changes-7
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for 1998 and 1999. These changes resulted in average decrease
of 3.2 Tg of CO2 Eq. (28.7 percent) in annual CO2 emissions
for 1990 through 1999.
The National Air Pollutant Emission Trends Report 2000
revised the data for nitrogen oxides (NOx), carbon monoxide
(CO) and non-methane volatile organic compound (NMVOC)
emissions. These changes resulted in an average increase of
1,073 Gg (4.6 percent) in annual NOx emissions, an average
decrease of 196 Gg (0.2 percent) in annual CO emissions, and
an average decrease of 4 Gg (0.1 percent) in annual NMVOC
emissions for 1990 through 1999.
Indirect C02 from CH4 Oxidation
Indkect CO, emissions from CH4 oxidation originating
from non-combustion fossil sources—coal mining, natural
gas systems, petroleum systems, petrochemical production,
and silicon carbide production—have been added to this
year's report to account for the global wanning properties
of methane that occur in the atmosphere after the gas
oxidizes. These indirect emissions of CO2 are not accounted
for in the GWP of CH4. Emissions from this source category
added an average of 29.3 Tg of CO2 Eq. to total Energy
chapter emissions.
Limestone and Dolomite Use
The method for estimating carbon dioxide emissions
from limestone and dolomite use has been revised to include
the thermic reduction of dolomite (CaMg (CO3)2) to
magnesium metal vapor. This change, combined with the
data changes described below, resulted in an increase in
CO2 emissions for 1999 of 1.0 Tg of CO2 Eq. (9.9 percent).
For the years 1990 through 1998, these updates resulted in
an average increase in CO2 emissions of 0.1 Tg CO2Eq.
(1.8 percent).
Aluminum Production
The estimates of PFC emissions for 1990 through 1999
have been revised due to the receipt of additional smelter-
specific information on aluminum production and anode
effect frequency and duration. In addition, the estimates
reflect updated information on the average frequency and
duration of anode effects throughout the industry as reported
in the 2000 International Aluminum Institute survey on
anode effects. The revision of Aluminum Production led to
an average decrease of 0.4 Tg of CO2 Eq. (2.8 percent) in
annual CF4 and Cf6 emissions for 1990 through 1999.
The estimates of CO2 emissions for 1990 through 1999
have been revised to use emission factors from the Revised
1996 IPCC Guidelines for National Greenhouse Gas
Inventories (IPCC/UNEP/OECD/IEA1997). These factors
are 1.5 tons CO2/ton Aluminum for Prebake and 1.8 tons
CO2/ton Aluminum for Soderberg. (Production in the United
States is estimated to be split approximately 80/20 for
Prebake/Soderberg.) Previously, a single emission factor
of 1.47 tons CO2/ton Aluminum was used. Other revisions
to estimates of CO2 emissions for 1990 through 1999 are
explained above in the section entitled Emissions and
Storage from Non-Energy Uses of Fossil Fuels. These
revisions led to an average increase of 5.8 Tg of CO2 Eq. in
annual CO2 emissions for 1990 through 1999.
Semiconductor Manufacturing
The estimates for 1990 through 1999 have been revised,
reflecting a change in method. Both the previous method and
the new method are based on the total annual emissions reported
by the participants in the PFC Emission Reduction Partnership
for the Semiconductor Industry. However, while the previous
method used plant-specific emission factors, the new method
uses layer-weighted capacities of plants and a per-layer
emission factor to estimate total U.S. emissions. By considering
both the average number of layers per chip and the silicon
capacities of each plant, the new method more closely reflects
the activity associated with PFC emissions. The methodological
changes resulted in an average decrease of 0.1 Tg of CO2 Eq.
(1.5 percent) in annual HFCs, PFCs, and SF6 emissions for
1990 through 1999.
Electric Power Transmission and
Distribution Systems
Estimates of SF6 emissions from electrical equipment
have been revised based on two new pieces of information:
(1) the reported 1999 and 2000 SF6 emissions from EPA's
utility partners in the SF6 Emissions Reduction Partnership
for Electric Power Systems, and (2) updated aggregate world
sales of SF6 to utilities between 1990 and 1999 as reported
by the RAND Corporation for seven major world producers
Changes-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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of SF6. These new data, which rely on industry statistics for
SF6 emission and consumption, have reduced the uncertainty
in the reported emission estimates.
The revised emissions trajectory differs from the
previously estimated trend both in magnitude and in
direction. The earlier trend showed estimated emissions
rising from 20.5 Tg CO2 Eq. in 1990 to 25.7 Tg CO2 Eq. in
1995, plateauing thereafter. The revised estimates show a
trend in the opposite direction, with estimated emissions
fluctuating around 32 Tg CO2 Eq. between 1990 and 1994,
and then steadily falling to 14.4 Tg CO2 Eq. in 2000.
The previous estimates were based on estimated U.S.
SF6 production capacity in 1994, along with the assumption
that 90 percent of this capacity was utilized, 75 percent of
produced SFg was sold for electrical equipment, and 50
percent of this gas replaced emitted gas as of 1994. Although
these estimates were consistent with industry norms and
with current research regarding usage of SF6 world wide,
they were highly uncertain, particularly the estimate that
50 percent of the gas sold into the electric equipment sector
replaced emitted gas. In addition, they did not account for
imports, exports, or year-to-year changes in actual sales for
electrical equipment. Information on these factors was not
available. Instead, the estimates were simply grown at rates
intended to match the growth rate of the electrical power
industry. (The exception to this was during the years 1997
through 1999, when emissions estimates were held steady
in recognition of the fact that emissions had probably fallen
during the mid 1990s in response to the sharp rise in the
price of SF6. At that time, there was not sufficient
information available to develop alternative estimates.)
These revisions lead to an average increase of 3.1 Tg of
CO2 Eq. (15.0 percent) in annual SF6 emissions from electric
power systems for 1990 through 1999.
Magnesium Production and Processing
The emissions estimates for 1993 through 1999 were
revised slightly to reflect changes to the estimated emission
factors for different segments of the magnesium industry.
The revisions result in an average decrease of 0.1 Tg CO2
Eq. (1.6 percent) in annual SF6 emissions for the years 1993
through 1999.
Manure Management
This Inventory includes an improvement to the
calculations of MCFs for liquid/slurry and deep pit systems
for the entire time series. Previously, these MCFs were
calculated using the van't Hoff-Arrhenius equation and an
annual average temperature. The calculation now uses a
monthly average temperature to better represent seasonal
variations that affect the production of methane.
The calculation of MCFs for all liquid systems (liquid/
slurry, anaerobic lagoon, and deep pit) are based on the van't
Hoff-Arrhenius equation and a monthly ambient temperature
used to represent the temperature of the system throughout the
year. Some areas of the United States experience extremely
cold temperatures and the use of this equation results in
insignificant biological activity or methane generation below
5°C. However, there is evidence to suggest that a minimum
level of biological activity continues to occur in the manure
management system even in cold ambient temperatures, and
that the minimum temperatures experienced at depth in these
systems is higher than the surrounding ambient temperature.
Anaerobic lagoons are therefore modeled with a minimum
temperature of 5°C and other covered or partially covered
liquid/slurry and deep pit systems are assumed to have a
minimum temperature of 7.5°C.
These changes, combined with the data changes
described below, resulted in an average increase of 3.3 Tg
of CO2 Eq. (10.9 percent) in annual CH4 emissions, and an
average decrease of less than 0.1 Tg of CO2 Eq. (0.2 percent)
in annual N2O emissions, from 1990 through 1999.
Rice Cultivation
The method for calculating methane emissions from
rice cultivation has been revised to follow the Revised 1996
IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).
Emissions are now estimated from annual areas harvested
and U.S.-specific, area-based, seasonally integrated
emission factors; previously, these emissions were based
on annual areas harvested, flooding season lengths, and daily
average emission factors. This revision, in combination with
the revision to the historical data described below, resulted
in an average decrease of 1.9 Tg CO2 Eq. (20.0 percent) in
estimated annual CH4 emissions from rice cultivation over
the entire time series.
Changes-9
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Agricultural Soil Management
The methodology used to estimate emissions from
agricultural soil management includes two changes. First,
the calculation of N2O emissions from cultivated histosols
has been revised to take into account the climate of the
cropland area. The areas are now split into temperate and
sub-tropical categories with different N2O emission factors.
Second, the calculation of indirect emissions from leaching
and runoff of manure nitrogen has been corrected so that
the portion of manure that is not applied or deposited on
soils (i.e., the poultry manure used as a feed supplement—
less than 1 percent of total manure nitrogen) is excluded.
These two methodological changes, in combination with
the revisions to historical data described below, resulted in
an average annual decrease of 2.0 Tg of CO2 Eq. (0.7
percent) in total N2O emissions from agricultural soil
management for 1990 through 1999.
Agricultural Residue Burning
The emission ratio for methane from, agricultural
residue burning was revised from 0.004 to 0.005 to reflect
the correct IPCC default value from the Revised 1996IPCC
Guidelines (IPCC/UNEP/OECD/IEA 1997).
The calculation of rice straw burning was revised for
the entire time series. Instead of applying area-weighted
percent burned figures to national production numbers, state
estimates of percent residue burned were applied to state
production numbers. These calculations were then summed
over all the states to yield the national estimates of rice
residue burned. These two methodological changes, in
combination with the revisions to historical data described
below, resulted in average increases in agricultural residue
burning emissions of 0.2 Tg CO2 Eq. (27.9 percent) for
methane, less than 0.1 Tg CO2 Eq. (1.9 percent) for nitrous
oxide, 15.8 Gg (2.3 percent) for CO, and 0.6 Gg (1.9
percent) for NOX for 1990 through 1999.
Land-Use Change and Forestry
The Land-Use Change and Forestry chapter comprises
four sections: 1) Forests; 2) Urban Trees; 3) Agricultural
Soils; and 4) Landfilled Yard Trimmings. The section on
urban trees is new to this year's Inventory. The
methodologies used in the first and third sections have
changed relative to the previous Inventory. The changes to
each section are described below.
• Forests. In this year's Inventory, down dead wood from
both logging and mortality were counted explicitly. In
addition, new volume-to-carbon conversion factors and
new forest floor carbon equations were used. Soil
carbon densities (carbon per hectare) were assumed
constant over time, so that soil carbon changed only if
forest type changed or if forest land area changed.
• Agricultural Soils. The method for calculating mineral
soil carbon changes for cropping systems containing
rice and rice in rotation was modified this year. In last
year's Inventory, mineral soil carbon stock changes
were slightly overestimated due to a programming error
that resulted in a double-counting of soil carbon
increases for systems containing rice. The corrected
program, combined with revisions to the historical data
described below, resulted in an average decrease of 10
percent in total net sequestration from mineral and
organic soils for 1990 through 1999.
• Urban Trees. A new section on changes in carbon
stocks in urban trees has been added. The primary input
data were obtained from Nowak and Crane (2001).
These changes, combined with the revisions to
historical data described below, resulted in an average
increase of 75.4 Tg CO2 Eq. (7 percent) in annual carbon
sequestration from land-use change and forestry for 1990
through 1996, and an average decrease of 95.3 Tg CO2 Eq.
(10 percent) in annual carbon sequestration from land-use
change and forestry for 1997 through 1999.
Landfills
The methodology used to estimate CH4 emissions
avoided through flaring was modified in the following ways.
First, emissions avoided for all flares were based on reported
flow range or fit to standard flow ranges established by one
of the vendors. In many cases, vendors reported only a
flow rate without establishing whether the reported flow
rate represented the minimum, average, or maximum flow
rate. In previous year's the flow rate was used. To improve
consistency across vendors, for this year's inventory
individual flare flow rates were mapped into standard flow
ranges provided by one of the vendors. The midpoint of
this range was then used to calculate emissions avoided.
Second, multiple flares for landfills were tracked, while
previously only one flare per landfill was included. Finally,
Changes-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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emission reductions at utility flares were included as long
as they were not affiliated with a landfill-gas-to-energy
project. In past inventories, all utility flares were excluded
as it was unclear whether they corresponded to a landfill-
gas-to-energy project. This year's flaring estimate reflects
emission reductions taking place at 585 flares nationwide,
as compared to 487 flares in the previous inventory. These
methodological changes, together with the data changes
described below, resulted in an average decrease in annual
methane emissions from landfills of 7.2 Tg CO2 Eq. (3.3
percent). This decrease is mainly the result of the
incorporation of additional data on the national population
of flares.
Wastewater Treatment
In the Wastewater Treatment section of the Waste
chapter, the fraction of domestic wastewater that degrades
anaerobically was changed to reflect the use of septic tanks
in addition to treatment plants. Recent research has shown
that twenty five percent of domestic wastewater is disposed
into septic tanks. The new factor is 16.25 percent, an
increase from the 15 percent used in the previous Inventory.
The industrial wastewater estimate was changed to
reflect new information on pulp & paper wastewater.
Estimates from vegetables, fruits, and juice processing and
the meat and poultry industry were also included for the
first time. The pulp and paper estimates were revised to
account for secondary treatment lagoons, which, in this
industry, are more prone to anaerobic conditions.
These changes to wastewater treatment emissions,
coupled with the data changes described below, resulted in
an average increase of 14.6 Tg of CO2 Eq. (124.6 percent)
in annual CH4 emissions for 1990 through 1999, primarily
due to the expansion of the categories of industrial
wastewater covered by the estimate.
Human Sewage
In the Human Sewage section of the Waste chapter, a
change was made to the 1990 through 1999 sewage sludge
applications. In previous years, the sewage sludge applied
to soils was subtracted from the amount discharged into
aquatic environments. In this year's Inventory, the amount
landfilled is also subtracted from the amount discharged
into aquatic environments. This revision, in combination
with the revision to the historical data described below,
resulted in an average decrease of 0.1 Tg CO2 Eq. (0.8
percent) in estimated annual N2O emissions from human
sewage over the entire time series.
Changes in Historical Data
• In the CO2 Emissions from Fossil Fuel Combustion
section of the Energy chapter, energy consumption data
have been updated by the Energy Information
Administration (EIA 200la) for selected years (see
above for detail on methodological changes). To
highlight one significant revision, EIA removed fuel
consumption for electricity generation by non-utilities
from the industry end-use sector, and combined it with
electric utility consumption—-thus creating a
comprehensive electric power industry sector. This
sector is referred to in this report as "electricity
generation." In another instance, Puerto Rico began
consuming natural gas in 2000, which has been
reflected in the CO2 estimates from U.S. Territories for
2000. Puerto Rico began importing liquefied natural
gas (LNG) in August 2000 to fuel its new natural gas-
fired electricity generation plant. This consumption
estimate provided by the EIA is based on available data
on LNG shipments to Puerto Rico from Trinidad.
Additionally, the carbon storage factor for
miscellaneous products under other petroleum for U.S.
territories, originally assumed as ten percent has been
modified to 100 percent. This revision is based on the
assumption that the carbon consumption for
miscellaneous products is used for asphalt and road
oil. These changes, along with the methodological
changes in "Emissions and Storage from Non-Energy
Uses of Fossil Fuels" (which affect this sector), resulted
in an average decrease of 36.0 Tg CO2 Eq. (0.7 percent)
in annual CO2 emissions from fossil fuel combustion
for 1990 through 1999.
• In the Stationary Combustion (excluding CO2) section of
the Energy chapter, changes to emission estimates were
entirely due to revised data from EIA (2001a). These
revisions are explained in more detail in the section above
on CO2 Emissions from Fossil Fuel Combustion [and]
Carbon Stored in Products from Non-Energy Uses of
Fossil Fuels. On average, annual stationary combustion
Changes-11
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methane emissions estimates decreased by 0.6 Tg of CO2
Eq. (7.4 percent), and annual stationary combustion N2O
emissions increased by 0.8 Tg of CO2 Eq. (5.8 percent)
for 1990 through 1999.
In the Natural Gas Systems section of the Energy
chapter, methane emission estimates have been revised
to incorporate new activity driver data for distribution
mains and services for 1993 through 2000 (OPS 2001).
These data changes resulted hi an average increase of
0.4 Tg of CO2 Eq. (0.3 percent) in annual methane
emissions from natural gas systems from 1990 through
1999. Furthermore, the emissions reduction estimates
for 1999, as reported by EPA's Natural Gas STAR
partners, were updated to incorporate more recent data.
This change has resulted in a decrease in annual
methane emissions of 3.2 Tg of CO2 Eq. (2.6 percent)
in 1999.
In the Petroleum Systems section of the Energy chapter,
this year's inventory reflects one historical data change.
A different data source for the number of producing
wells has been used. In the previous report, the data
source for producing wells was the American Petroleum
Institute's (API), Petroleum Data Book 1999. Although
published annually, the API's data lags two years behind
the publication year. In this year's Inventory, data for
producing wells were taken from the Energy
Information Administration's (ElA), Annual Energy
Review 2001, which has data for 2000, unlike the API
publication. This change, combined with the
methodological changes described above, results in an
average emissions decrease of 0.2 Tg of CO2 Eq. (0.8
percent) across the entire period.
In the International Bunker Fuels section of the Energy
chapter, the CH4 emission factor for marine fuels was
revised from 0.03 to 0.315 g CH4/kg fuel. In addition,
DESC (2001) revised their estimates of marine and
aviation jet fuel consumption for international bunkers
for 2000. The military international bunker fuel data
provided by DESC for 2000 are from a data set
developed by the Navy Fuels and Logistics office,
which is more consistent with the 1995 to 1999 DESC
maritime data. An additional marine fuel, intermediate
fuel oil (IFO 180 and IFO 380), is included in the
estimates for this inventory providing consumption data
for 1996 through 2000. IFO is a blend of distillate and
residual fuels and is used by some Military Sealift
Command vessels. These revisions result in average
emission decreases of 0.2 Tg CO2 Eq. and less than
0.1 Tg CO2 Eq. of CO2 and N2O, respectively, and an
average increase of 0.1 Tg CO2 Eq. of CH4.
• In the Cement Manufacture section of the Industrial
Processes chapter, the clinker production data was
altered to reflect the information in the Cement Annual
Report 2001 (USGS 2001a). The revisions increased
the annual CO2 emissions by 0.1 Tg of CO2 Eq. (0.2
percent) for 1999.
• In the Lime Manufacture section of the Industrial
Processes chapter, the activity data was altered to
incorporate revised production numbers (USGS 2001b)
for dolomitic quicklime and high-calcium hydrated
lime. The revisions increased the total lime production
and sugar refining data for 1999 leading to an emissions
increase of 0.04 Tg of CO2 Eq. (0.3 percent) for that
year. These revisions also decreased total emissions
from lime manufacture by less than 0.001 Tg of CO2
Eq. (0.01 percent) for 1990 through 1996.
• In the Limestone and Dolomite Use section of the
Industrial Processes chapter, the activity data used to
calculate CO2 emissions have been changed to
incorporate revised numbers for the total flux stone
consumption numbers for both limestone and dolomite
(USGS 2001c). This change, combined with the
methodological change described above, resulted in an
increase in CO2 emissions for 1999 of 1.0 Tg of CO2
Eq. (9.9 percent). For the years 1990 through 1998,
these updates resulted in an average increase in CO2
emissions of 0.1 Tg CO2Eq. (1.8 percent).
• In the Soda Ash Manufacture and Consumption
section of the Industrial Processes chapter, the
activity data used to calculate CO2 emissions have
been revised to incorporate published 2001 data
(USGS 200Id). Trona Production was changed for
1990 and 1991 while soda ash consumption changed
1990 through 1997 according to the Soda Ash Annual
Report 2001. These updates resulted in a decrease
in annual CO2 emissions by less than 0.1 Tg of CO2
Eq. (0.4 percent) for 1990 through 1997.
Changes-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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• In the Carbon Dioxide Consumption section of the
Industrial Processes chapter, the activity data used to
calculate CO2 emissions has been revised reflect an
updated 1999 figure published by the Freedonia Group.
This resulted in a change of less than 0.01 Tg CO2 Eq.
in CO2 emissions from this source for 1999.
• In the Petrochemical Production section of the
Industrial Processes chapter, the activity data used to
calculate CH4 emissions were revised to reflect
modified data from the American Chemistry Council
2001. The production data was altered for
dichloroethylene, styrene, methanol for the years 1995
through 1999. Carbon black and ethylene data was
revised for 1999 only. The revisions increased CH4
emissions on average less than 0.1 Tg of CO2 Eq. (0.5
percent) for the years 1995 through 1999.
• In the Adipic Acid Production section of the Industrial
Processes chapter, information on emission estimates
for 1990 to 2000 was directly obtained from two of the
four adipic acid plants. These data were updated for
the whole time series for these plants. These revisions
resulted in an average decrease of 3.5 Tg of CO2 Eq.
(18.9 percent) in annual N2O emissions from 1990
through 1999.
• In the Nitric Acid Production section of the Industrial
Processes chapter, 1999 production data were revised
using updated estimates from Chemical and
Engineering News (C&EN 2001). The revision resulted
in a decrease of 0.1 Tg CO2 Eq. (0.6 percent) in N2O
emissions from nitric acid production in 1999.
• In the Substitution of Ozone Depleting Substances
section of the Industrial Processes chapter, a review of
the current chemical substitution trends, together with
input from industry representatives, resulted in updated
assumptions for the Vintaging Model, particularly in
the precision cleaning solvents, stationary refrigeration,
and fire extinguishing sectors. These revisions resulted
in an average decrease of 3.6 Tg CO2 Eq. (10.6 percent)
in HFC, PFC, and SF6 emissions from substitution of
ozone depleting substances for 1994 through 1999.
• For emissions of HFC-23 from HCFC-22 Production
within the Industrial Processes chapter, the emission
estimates for 1990 to 1998 were changed to correct a
small error in the conversion from Gg of HFC-23 to
Tg of CO2 equivalent. None of the changes were greater
than ± 0.2 Tg CO2. The revision lead to an average
increase of less than 0.1 Tg of CO2 Eq. (less than 0.1
percent) in annual HFC-23 emissions from the
production of HCFC-22.
In the Enteric Fermentation section of the Agriculture
chapter, the emission estimates have been recalculated
using updated animal population data. Specifically,
horse population data for 1990 through 1999 were
updated by the Food and Agriculture Organization
(FAO 2001). Additionally, population data for swine,
goats, and sheep were adjusted to match the most
updated data from USD A. Some cattle population data
were also revised to reflect updated USDA estimates.
Lastly, stocker and feedlot numbers were modified to
include animals at feedlots with less than 1000 head.
These data modifications caused an average decrease
of 2.5 Tg of CO2 Eq. (1.9 percent) in annual CH4
emissions from enteric fermentation for 1990 through
1999.
In the Manure Management section of the Agriculture
chapter, four changes have been incorporated into the
emission estimates. Each of these major changes is
discussed in more detail below.
— USDA updated the quarterly estimates for swine
population for the years 1998 and 1999; therefore,
population data for these years changed slightly.
The volatile solids and nitrogen excretion estimates
for these years have changed accordingly.
— The Food and Agriculture Organization of the
United Nations (FAO) has an online database that
is used for horse population estimates. These data,
from 1990 through 2000, have been updated.
Therefore, all N2O and CH4 emission estimates for
horses have changed relative to the previous
Inventory. The effect of the population changes
on the predicted CH4 emissions is less than the
effect on the predicted N2O emissions due to the
nonlinear effect of the change on the CH4
calculations.
— The beef cattle population data used to calculate
N2O emissions for the previous inventory were
slightly different than the data used to calculate
CH4 emissions. The N2O population data excluded
Changes-13
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a small portion of the population, which were
animal counts from states with a very small number
of animals, compared to the U.S. total population.
The CH4 populations included these counts. In
order to be consistent between the N2O and CH4
emission calculations, the N2O populations were
changed to include population from these states.
— The supporting documentation for the previous
inventory indicated that the relationship of volatile
solids excretion and milk production in dairy cows
was estimated using a polynomial fit curve. These
estimates were actually calculated using a
logarithmic curve.
The CH4 emission estimates for horses decreased an
average of 4 percent across the time series. The N2O
emission time series for horses decreased emissions by
an average of 12 percent across the tune series. These
changes, combined with the methodological changes
described above, changes in total resulted in an average
increase of 3.3 Tg of CO2 Eq. (10.9 percent) in annual
CH4 emissions, and an average decrease of less than
0.1 Tg of CO2 Eq. (0.2 percent) in annual N2O
emissions, from 1990 through 1999.
In the Rice Cultivation section of the Agriculture
chapter, one change has been made to the historical
data. Revised harvested rice areas for the primary crops
in Arkansas and California have been incorporated for
the years 1998 and 1999, based on the latest statistics
from USDA (200 Id). These changes resulted in a less
than 2 percent decrease in rice area harvested for each
of the affected years. This revision, together with the
methodological revision described above, resulted in
an average decrease of 1.9 Tg CO2 Eq. (20.0 percent)
in estimated annual CH4 emissions from rice cultivation
over the entire time series.
The estimates of N2O emissions from agricultural soil
management include several data changes, as described
below:
— Fertilizer consumption data for 1990 through 1999
were revised using the most recent estimates for
each year provided by TVA and AAPFCO (TVA
1990,1991,1992,1993,1994, andAAPFCO 1995,
1996, 1997, 1998, 1999, 2000b). Also, for the
commercial organic fertilizers, fertilizer type-
specific nitrogen contents were used to estimate
total nitrogen applied. These nitrogen contents
were obtained from TVA(1991,1992,1993,1994)
and AAPFCO (1995; 1996; 1997; 1998; 1999;
2000a,b).
— New manure data were incorporated based on
updated swine and horse population estimates, and
a regrouping of the beef cattle and cattle-not-on-
feed animal groups (USDA 2001a; FAO 2001;
USDA 2001b,c).
— The estimates of sewage sludge production and
land application were refined through new data
sources. Additional annual figures and projections
from EPA (1999) were incorporated, reducing the
amount of interpolation necessary. The nitrogen
content of the sludge was also revised from 4
percent to 3.3 percent based upon information in
Metcalf and Eddy, Inc. (1991).
— Crop production figures for 1990 through 1999
were revised using the most recent estimates for
each year provided by USDA (1994, 1998c,
2001a). This change resulted in a less than 1
percent revision in crop production for a few crops.
In the crop residue calculations, the rice component
was revised to include Florida data, which had been
omitted previously. Histosol area estimates were
revised, as they were extracted from NRI
incorrectly last year, and disaggregated into broad
climatic regions.
These revisions, in combination with the
methodological revisions described above, resulted in
an average annual 2.0 Tg CO2 Eq. (0.7 percent)
decrease in total N2O emissions from agricultural soil
management for 1990 through 1999.
The emission estimates for agricultural residue burning
include several changes. Crop production figures for
the time series from 1990 through 1999 were revised
using the most recent estimates from USDA (1994,
1998c, 2001). This change resulted in less than a 1
percent revision in crop production for a few crops.4
4 The production statistics presented in Table 5-19 of the Agriculture chapter were also revised to include Florida rice production, which had been
omitted previously. However, this had no effect on the emission estimates because rice residue burning does not occur in Florida.
Changes-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Agricultural extension agents in each rice-growing
state, and the California Air Resources Board, were
contacted to verify, and update as needed, the historical
estimates of rice acreage burned in each state. Estimates
for California, Mississippi and Missouri were revised.
For California, a new estimate of 1999 rice area burned
in Sacramento Valley was obtained from California Air
Resources Board (2001), resulting in a 13 percent
increase in California's burned acreage for that year.
New estimates of the percentage of rice area burned in
Mississippi were obtained from Street (2001), as the
previous estimates are now thought to be too low. The
1990 to 1998 estimates were revised from 5 to 10
percent, and the 1999 estimate from 10 to 40 percent.
The previous 1990 to 1998 estimates for Missouri were
also revised from 3.5 to 5 percent (Guethle 2001).
These revisions, in combination with the
methodological revisions described above, resulted in
average increases in agricultural residue burning
emissions of less than 0.2 Tg CO2 Eq. (27.9 percent)
for CH4, less than 0.1 Tg CO2 Eq. (1.9 percent) for
N2O, 15.8 Gg (2.3 percent) for CO, and 0.6 Gg (1.9
percent) for NOX for 1990 through 1999.
In the Land-Use Change and Forestry chapter, the
following changes were made:
— In the Forest Carbon section, results from the
USDA Forest Service Forest Sector Modeling
System were used to develop a projected stock
estimate for 2001. In last year's Inventory, results
from the modeling system were used to develop
both carbon flux and stock estimates for 1990
through 1999. This year, theUSDAForest Service,
Forest Inventory & Analysis data were used
directly as the base data (i.e., areas, volumes,
growth, land-use changes, and other forest
characteristics) for 1987 and 1997. For areas with
limited survey data on volume (i.e., Reserved
Forest Land and Other Forest Land), average
volumes were estimated using the Timberland data
for the appropriate forest type and region.
— In the Agricultural Soils section, the soil carbon
stock data were obtained from the updated (final
release) 1997National Resources Inventory (NRI)
data. Last year's estimates were based on the initial
(unofficial) 1997 NRI data. Use of the final 1997
NRI data, in combination with the agricultural soils
methodological revisions described above, resulted
in an average decrease of 10 percent in total net
sequestration from mineral and organic soils for
the 1990 to 1999 period.
— In the Agricultural Soils section, the 1999 carbon
dioxide emission estimates for liming were revised
based on the U.S. Geological Survey's latest
estimates of limestone and dolomite use in 1999
(Tepordei 2000). This decreased the 1999 emission
estimate for that source by about 9 percent.
— In the Landfilled Yard Trimmings section, the
landfilled yard trimmings data were revised to
correct incorrect data entry from last year's
inventory. These revisions resulted in an average
annual 10 percent decrease in yard trimmings
carbon storage for 1990 through 1999.
These changes, combined with the methodological
revisions described above, resulted in an average
increase of 75.4 Tg CO2 Eq. (7.4 percent) in annual
carbon sequestration from land-use change and forestry
for 1990 through 1996, and an average decrease of 95.3
Tg CO2 Eq. (9.7 percent) in annual carbon sequestration
from land-use change and forestry for 1997 through
1999.
In the Landfills section of the Waste chapter, this year's
inventory reflects an updated 1999 waste generation
and percent-landfilled estimate published by BioCycle
(2000). This revision caused the 1999 CH4 generation
estimate to decrease from 214.6 to 203.1 Tg CO2 Eq.
In addition, EPA used an updated database on landfill-
gas-to-energy projects. The methane mitigated from
these projects changed from 1990 through 1999. The
most recent data indicated a smaller quantity of CH4
mitigated in 1999 than last year's landfill gas-to-energy
database. For 1999, this year's landfill gas-to-energy
data showed 1.1 Tg CO2 Eq. less mitigated CH4 than
last year's data. The difference is primarily attributed
to revised estimates of municipal waste capacity for
electricity projects and landfill gas flow for direct use
projects. Finally, new data from an additional vendor
of landfill gas flares was obtained. These revisions,
coupled with the methodological changes described
Changes-15
-------
above, resulted in resulted in an average decrease of
7.2 Tg CO2 Eq. (3.3 percent) in annual CH4 emissions
from landfills for 1990 through 1999.
In the Wastewater Treatment section of the Waste
chapter, small changes were made to the 1990 through
1999 population data based on new estimates provided
by the U.S. Census. Along with the more substantive
methodological changes mentioned above, these
revisions resulted in average increase of 14.6 Tg of CO2
Eq. (125 percent) in annual CH4 emissions.
In the Human Sewage section of the Waste chapter, small
changes were made to the 1990 to 1999 per capita protein
consumption data based on new estimates provided by
the FAO. These revisions, together with the new census
population data mentioned previously and the
methodological changes described above, resulted in an
annual average decrease of 0.1 Tg CO2 Eq. (0.8 percent)
in N2O emissions from 1990 through 1999.
Changes-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
1. Introduction
Tis report presents estimates by the United States government of U.S. anthropogenic greenhouse gas emissions
nd sinks for the years 1990 through 2000. A summary of these estimates is provided in Table 1-8 and Table 1-
9 by gas and source category. The emission estimates in these tables are presented on both a full molecular mass basis and
on a Global Warming Potential (GWP) weighted basis in order to show the relative contribution of each gas to global
average radiative forcing.1'2 This report also discusses the methods and data used to calculate these emission estimates.
In June of 1992, the United States signed, and later ratified in October, the United Nations Framework Convention on
Climate Change (UNFCCC). The objective of the UNFCCC is "to achieve.. .stabilization of greenhouse gas concentrations
in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system." 3'4
Parties to the Convention, by signing, make commitments "to develop, periodically update, publish and make
available.. .national inventories of anthropogenic emissions by sources and removals by sinks of all greenhouse gases not
controlled by the Montreal Protocol, using comparable methodologies..."5 The United States views this report as an
opportunity to fulfill this commitment under the UNFCCC.
In 1988, preceding the creation of the UNFCCC, the Intergovernmental Panel on Climate Change (IPCC) was jointly
established by the World Meteorological Organization (WMO) and the United Nations Environment Programme (UNEP).
The charter of the IPCC is to assess available scientific information on climate change, assess the environmental and
socio-economic impacts of climate change, and formulate response strategies (IPCC 1996). Under Working Group 1 of
the IPCC, nearly 140 scientists and national experts from more than thirty countries collaborated in the creation of the
Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997) to ensure that
the emission inventories submitted to the UNFCCC are consistent and comparable between nations. The Revised 1996
IPCC Guidelines were accepted by the IPCC at its Twelfth Session (Mexico City, 11-13 September 1996). The information
provided in this inventory is presented in accordance with these guidelines. Additionally, in order to fully comply with the
Revised 1996 IPCC Guidelines, the United States has provided estimates of carbon dioxide emissions from fossil fuel
combustion using the IPCC Reference Approach in Annex U. In addition, this inventory is in accordance with the recently
published IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories, which
further expanded upon the methodologies in the Revised 1996 IPCC Guidelines.
1 See the section below entitled Global Warming Potentials for an explanation of GWP values.
2 See the section below entitled What is Climate Change? for an explanation of radiative forcing.
3 The term "anthropogenic", in this context, refers to greenhouse gas emissions and removals that are a direct result of human activities or are the
result of natural processes that have been affected by human activities (IPCC/UNEP/OECD/IEA 1997).
4 Article 2 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change. See . (UNEP/WMO 2000)
5 Article 4 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change (also identified in
Article 12). See . (UNEP/WMO 2000)
Introduction 1-1
-------
Overall, the purpose of an inventory of anthropogenic
greenhouse gas emissions is (1) to provide a basis for the
ongoing development of methodologies for estimating
sources and sinks of greenhouse gases; (2) to provide a
common and consistent mechanism through which Parties
to the UNFCCC can estimate emissions and compare the
relative contribution of individual sources, gases, and
nations to climate change; and (3) as a prerequisite for
accounting for reductions and evaluating possible
mitigation strategies.
What is Climate Change?
Climate change refers to long-term fluctuations in
temperature, precipitation, wind, and other elements of the
Earth's climate system.6 Natural processes such as solar-
irradiance variations, variations in the Earth's orbital
parameters,7 and volcanic activity can produce variations
in climate. The climate system can also be influenced by
changes in the concentration of various gases in the
atmosphere, which affect the Earth's absorption of radiation.
The Earth naturally absorbs and reflects incoming solar
radiation and emits longer wavelength terrestrial (thermal)
radiation back into space. On average, the absorbed solar
radiation is balanced by the outgoing terrestrial radiation
emitted to space. A portion of this terrestrial radiation,
though, is itself absorbed by gases hi the atmosphere. The
energy from this absorbed terrestrial radiation warms the
Earth's surface and atmosphere, creating what is known as
the "natural greenhouse effect." Without the natural heat-
trapping properties of these atmospheric gases, the average
surface temperature of the Earth would be about 33°C lower
(IPCC 2001).
Under the UNFCCC, the definition of climate change
is "a change of climate which is attributed directly or
indirectly to human activity that alters the composition of
the global atmosphere and which is in addition to natural
climate variability observed over comparable time periods."8
Given that definition, in its Second Assessment Report of
the science of climate change, the IPCC concluded that:
Human activities are changing the atmospheric
concentrations and distributions of greenhouse gases and
aerosols. These changes can produce a radiative forcing
by changing either the reflection or absorption of solar
radiation, or the emission and absorption of terrestrial
radiation (IPCC 1996).
Building on that conclusion, the more recent IPCC
Third Assessment Report asserts that "[concentrations of
atmospheric greenhouse gases and their radiative forcing
have continued to increase as a result of human activities."
(IPCC 2001)
The IPCC went on to report that the global average
surface temperature of the Earth has increased by between
0.6± 0.2° C over the 20th century (IPCC 2001). This value
is about 0.15° C larger than that estimated by the Second
Assessment Report, which reported for the period up to
1994, "owing to the relatively high temperatures of the
additional years (1995 to 2000) and improved methods of
processing the data" (IPCC 2001).
While the Second Assessment Report concluded, "the
balance of evidence suggests that there is a discernible
human influence on global climate," the Third Assessment
Report states the influence of human activities on climate
in even starker terms. It concludes that, "[I]n light of new
evidence and taking into account the remaining
uncertainties, most of the observed warming over the last
50 years is likely to have been due to the increase in
greenhouse gas concentrations" (IPCC 2001).
Greenhouse Gases
Although the Earth's atmosphere consists mainly of
oxygen and nitrogen, neither plays a significant role in
enhancing the greenhouse effect because both are essentially
transparent to terrestrial radiation. The greenhouse effect is
primarily a function of the concentration of water vapor,
carbon dioxide, and other trace gases in the atmosphere that
absorb the terrestrial radiation leaving the surface of the
Earth (IPCC 1996). Changes in the atmospheric
concentrations of these greenhouse gases can alter the
*Thc Earth's climate system comprises the atmosphere, oceans, biosphere, cryosphere, and geosphere.
7 For example, eccentricity, precession, and inclination.
8 Article 1 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change. (UNEP/WMO
2000)
1-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
balance of energy transfers between the atmosphere, space,
land, and the oceans. A gauge of these changes is called
radiative forcing, which is a simple measure of changes in
the energy available to the Earth-atmosphere system (IPCC
1996). Holding everything else constant, increases in
greenhouse gas concentrations in the atmosphere will
produce positive radiative forcing (i.e., a net increase in the
absorption of energy by the Earth).
Climate change can be driven by changes in the
atmospheric concentrations of a number of radiatively
active gases and aerosols. We have clear evidence that
human activities have affected concentrations, distributions
and life cycles of these gases (IPCC 1996).
Naturally occurring greenhouse gases include water
vapor, carbon dioxide (CO2), methane (CH4), nitrous oxide
(N2O), and ozone (O3). Several classes of halogenated
substances that contain fluorine, chlorine, or bromine are
also greenhouse gases, but they are, for the most part, solely
a product of industrial activities. Chlorofluorocarbons
(CFCs) and hydrochlorofluorocarbons (HCFCs) are
halocarbons that contain chlorine, while halocarbons that
contain bromine are referred to as bromofluorocarbons (i.e.,
halons). Because CFCs, HCFCs, and halons are
stratospheric ozone depleting substances, they are covered
under the Montreal Protocol on Substances that Deplete
the Ozone Layer. The UNFCCC defers to this earlier
international treaty; consequently these gases are not
included in national greenhouse gas inventories.9 Some other
fluorine containing halogenated substances—
hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and
sulfur hexafluoride (SF6)—do not deplete stratospheric
ozone but are potent greenhouse gases. These latter
substances are addressed by the UNFCCC and accounted
for in national greenhouse gas inventories.
There are also several gases that, although they do not
have a commonly agreed upon direct radiative forcing effect,
do influence the global radiation budget. These tropospheric
gases referred to as ambient air pollutants include carbon
monoxide (CO), nitrogen dioxide (NO2), sulfur dioxide
(SO2), and tropospheric (ground level) ozone (O3).
Tropospheric ozone is formed by two precursor pollutants,
volatile organic compounds (VOCs) and nitrogen oxides
(NOx) in the presence of ultraviolet light (sunlight). Aerosols
extremely small particles or liquid droplets often composed
of sulfur compounds, carbonaceous combustion products,
crustal materials and other human induced pollutants can
affect the absorptive characteristics of the atmosphere.
However, the level of scientific understanding of aerosols
is still very low (IPCC 2001).
Carbon dioxide, methane, and nitrous oxide are
continuously emitted to and removed from the atmosphere
by natural processes on Earth. Anthropogenic activities,
however, can cause additional quantities of these and other
greenhouse gases to be emitted or sequestered, thereby
changing their global average atmospheric concentrations.
Natural activities such as respiration by plants or animals
and seasonal cycles of plant growth and decay are examples
of processes that only cycle carbon or nitrogen between the
atmosphere and organic biomass. Such processes except
when directly or indirectly perturbed out of equilibrium by
anthropogenic activities generally do not alter average
atmospheric greenhouse gas concentrations over decadal
timeframes. Climatic changes resulting from anthropogenic
activities, however, could have positive or negative feedback
effects on these natural systems. Atmospheric concentrations
of these gases, along with their rates of growth and
atmospheric lifetimes, are presented in Table 1-1.
A brief description of each greenhouse gas, its sources,
and its role in the atmosphere is given below. The following
section then explains the concept of Global Warming
Potentials (GWPs), which are assigned to individual gases
as a measure of their relative average global radiative
forcing effect.
Water Vapor (H2O). Overall, the most abundant and
dominant greenhouse gas in the atmosphere is water vapor.
Water vapor is neither long-lived nor well mixed in the
atmosphere, varying spatially from 0 to 2 percent (IPCC
1996). In addition, atmospheric water can exist in several
physical states including gaseous, liquid, and solid. Human
activities are not believed to directly affect the average global
concentration of water vapor; however, the radiative forcing
produced by the increased concentrations of other
greenhouse gases may indirectly affect the hydrologic cycle.
A warmer atmosphere has an increased water holding
capacity; yet, increased concentrations of water vapor affects
the formation of clouds, which can both absorb and reflect
Emissions estimates of CFCs, HCFCs, halons and other ozone-depleting substances are included in this document for informational purposes.
Introduction 1-3
-------
Table 1-1: Global atmospheric concentration (ppm unless otherwise specified), rate of concentration change
(ppb/year) and atmospheric lifetime (years) of selected greenhouse gases
Atmospheric Variable
Pre-industrial atmospheric concentration
Atmospheric concentration (1998)
Rate of concentration changeb
Atmospheric Lifetime
C02
278
365
1.5°
50-200d
CH4
0.700
1.745
0.007°
12e
N20
0.270
0.314
0.0008
114e
SF6*
0
4.2
0.24
3,200
CF4a
40
80
1.0
>50,000
Source: IPCG (2001)
* Concentrations in parts per trillion (ppt) and rate of concentration change in ppt/year.
b Rate is calculated over the period 1990 to 1999.
c Rate has fluctuated between 0.9 and 2.8 ppm per year for C02 and between 0 and 0.013 ppm per year for GH4 over the period 1990 to 1999.
d No single lifetime can be defined for C02 because of the different rates of uptake by different removal processes.
• This lifetime has been defined as an "adjustment time" that takes into account the indirect effect of the gas on its own residence time.
solar and terrestrial radiation. Aircraft contrails, which
consist of water vapor and other aircraft emittants, are similar
to clouds in their radiative forcing effects (IPCC 1999).
Carbon Dioxide (CO2). In nature, carbon is cycled
between various atmospheric, oceanic, land biotic, marine
biotic, and mineral reservoirs. The largest fluxes occur
between the atmosphere and terrestrial biota, and between
the atmosphere and surface water of the oceans. In the
atmosphere, carbon predominantly exists in its oxidized
form as CO2. Atmospheric carbon dioxide is part of this
global carbon cycle, and therefore its fate is a complex
function of geochemical and biological processes. Carbon
dioxide concentrations in the atmosphere increased from
approximately 280 parts per million by volume (ppmv) in
pre-industrial10 times to 367 ppmv in 1999, a 31 percent
increase (IPCC 2001).11 The IPCC notes that "[t]his
concentration has not been exceeded during the past 420,000
years, and likely not during the past 20 million years. The
rate of increase over the past century is unprecedented, at
least during the past 20,000 years." The IPCC definitively
states that "the present atmospheric CO2 increase is caused
by anthropogenic emissions of CO2" (IPCC 2001). Forest
clearing, other biomass burning, and some non-energy
production processes (e.g., cement production) also emit
notable quantities of carbon dioxide.
In its second assessment, the IPCC also stated that
"[t]he increased amount of carbon dioxide [in the
atmosphere] is leading to climate change and will produce,
on average, a global warming of the Earth's surface
because of its enhanced greenhouse effect although the
magnitude and significance of the effects are not fully
resolved" (IPCC 1996).
Methane (CH4). Methane is primarily produced
through anaerobic decomposition of organic matter in
biological systems. Agricultural processes such as wetland
rice cultivation, enteric fermentation in animals, and the
decomposition of animal wastes emit CH4, as does the
decomposition of municipal solid wastes. Methane is also
emitted during the production and distribution of natural
gas and petroleum, and is released as a by-product of coal
mining and incomplete fossil fuel combustion.
Atmospheric concentrations of methane have increased
by about 150 percent since pre-industrial times, although
the rate of increase has been declining. The IPCC has
estimated that slightly more than half of the current CH4
flux to the atmosphere is anthropogenic, from human
activities such as agriculture, fossil fuel use and waste
disposal (IPCC 2001).
Methane is removed from the atmosphere by reacting
with the hydroxyl radical (OH) and is ultimately converted
to CO2. Minor removal processes also include reaction with
Cl in the marine boundary layer, a soil sink, and stratospheric
reactions. Increasing emissions of methane reduce the
concentration of OH, a feedback which may increase
methane's atmospheric lifetime (IPCC 2001).
10 The pre-industrial period is considered as the time preceding the year 1750 (IPCC 2001).
11 Carbon dioxide concentrations during the last 1,000 years of the pre-industrial period (i.e., 750-1750), a time of relative climate stability, fluctuated
by about ± 10 ppmv around 280 ppmv (IPCC 2001).
1-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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Nitrous Oxide (N2O). Anthropogenic sources of N2O
emissions include agricultural soils, especially the use of
synthetic and manure fertilizers; fossil fuel combustion,
especially from mobile combustion; adipic (nylon) and nitric
acid production; wastewater treatment and waste
combustion; and biomass burning. The atmospheric
concentration of nitrous oxide (N2O) has increased by 16
percent since 1750, from a pre industrial value of about
270 ppb to 314 ppb in 1998, a concentration that has not
been exceeded during the last thousand years. Nitrous oxide
is primarily removed from the atmosphere by the photolytic
action of sunlight in the stratosphere.
Ozone (O3). Ozone is present in both the upper
stratosphere,12 where it shields the Earth from harmful levels
of ultraviolet radiation, and at lower concentrations in the
troposphere,13 where it is the main component of
anthropogenic photochemical "smog." During the last two
decades, emissions of anthropogenic chlorine and bromine-
containing halocarbons, such as chlorofluorocarbons
(CFCs), have depleted stratospheric ozone concentrations.
This loss of ozone in the stratosphere has resulted in negative
radiative forcing, representing an indirect effect of
anthropogenic emissions of chlorine and bromine
compounds (IPCC 1996). The depletion of stratospheric
ozone and its radiative forcing was expected to reach a
maximum in about 2000 before starting to recover, with
detection of such recovery not expected to occur much
before 2010 (IPCC 2001).
The past increase in tropospheric ozone, which is also
a greenhouse gas, is estimated to provide the third largest
increase in direct radiative forcing since the pre-industrial
era, behind CO2 and CH4. Tropospheric ozone is produced
from complex chemical reactions of volatile organic
compounds mixing with nitrogen oxides (NOx) in the
presence of sunlight. Ozone, carbon monoxide (CO), sulfur
dioxide (SO2), nitrogen dioxide (NO2) and particulate
matter are included in the category referred to as "criteria
pollutants" in the United States under the Clean Air Act14
and its subsequent amendments. The tropospheric
concentrations of ozone and these other pollutants are short-
lived and, therefore, spatially variable.
Halocarbons, Perfluorocarbons, and Sulfur Hexafluoride
(SF6). Halocarbons are, for the most part, man-made chemicals
that have both direct and indirect radiative forcing effects.
Halocarbons that contain chlorine chlorofluorocarbons (CFCs),
hydrochlorofluorocarbons (HCFCs), methyl chloroform, and
carbon tetrachloride and bromine halons, methyl bromide, and
hydrobromofluorocarbons (HBFCs) result in stratospheric
ozone depletion and are therefore controlled under the Montreal
Protocol on Substances that Deplete the Ozone Layer. Although
CFCs and HCFCs include potent global wanning gases, their
net radiative forcing effect on the atmosphere is reduced
because they cause stratospheric ozone depletion, which is itself
an important greenhouse gas in addition to shielding the Earth
from harmful levels of ultraviolet radiation. Under the Montreal
Protocol, the United States phased out the production and
importation of halons by 1994 and of CFCs by 1996. Under
the Copenhagen Amendments to the Protocol, a cap was placed
on the production and importation of HCFCs by non-Article
51S countries beginning in 1996, and then followed by a
complete phase-out by the year 2030. The ozone depleting
gases covered under the Montreal Protocol and its Amendments
are not covered by the UNFCCC; however, they are reported
in this inventory under Annex R.
Hydrofluorocarbons (HFCs), perfluorocarbons (PFCs),
and sulfur hexafluoride (SF6) are not ozone depleting
substances, and therefore are not covered under the Montreal
Protocol. They are, however, powerful greenhouse gases.
HFCs primarily used as replacements for ozone depleting
substances but also emitted as a by-product of the HCFC-
22 manufacturing process currently have a small aggregate
radiative forcing impact; however, it is anticipated that their
12 The stratosphere is the layer from the troposphere up to roughly 50 kilometers. In the lower regions the temperature is nearly constant but in the
upper layer the temperature increases rapidly because of sunlight absorption by the ozone layer. The ozone-layer is the part of the stratosphere from
19 kilometers up to 48 kilometers where the concentration of ozone reaches up to 10 parts per million.
13 The troposphere is the layer from the ground up to 11 kilometers near the poles and up to 16 kilometers in equatorial regions (i.e., the lowest layer
of the atmosphere where people live). It contains roughly 80 percent of the mass of all gases in the atmosphere and is the site for most weather
processes, including most of the water vapor and clouds.
14 142 U.S.C § 7408, CAA § 108]
15 Article 5 of the Montreal Protocol covers several groups of countries, especially developing countries, with low consumption rates of ozone
depleting substances. Developing countries with per capita consumption of less than 0.3 kg of certain ozone depleting substances (weighted by their
ozone depleting potential) receive financial assistance and a grace period of ten additional years in the phase-out of ozone depleting substances.
Introduction 1-5
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contribution to overall radiative forcing will increase (IPCC
2001). PFCs and SF6 are predominantly emitted from
various industrial processes including aluminum smelting,
semiconductor manufacturing, electric power transmission
and distribution, and magnesium casting. Currently, the
radiative forcing impact of PFCs and SF6 is also small;
however, they have a significant growth rate, extremely long
atmospheric lifetimes, and are strong absorbers of infrared
radiation, and therefore have the potential to influence
climate far into the future (IPCC 2001).
Carbon Monoxide (CO). Carbon monoxide has an
indirect radiative forcing effect by elevating concentrations
of CH, and tropospheric ozone through chemical reactions
with other atmospheric constituents (e.g., the hydroxyl
radical, OH) that would otherwise assist in destroying CH4
and tropospheric ozone. Carbon monoxide is created when
carbon-containing fuels are burned incompletely. Through
natural processes hi the atmosphere, it is eventually oxidized
to COj. Carbon monoxide concentrations are both short-
lived in the atmosphere and spatially variable.
Nitrogen Oxides (NOK). The primary climate change
effects of nitrogen oxides (i.e., NO and NO2) are indirect
and result from their role in promoting the formation of
ozone in the troposphere and, to a lesser degree, lower
stratosphere, where it has positive radiative forcing effects.16
Additionally, NOx emissions from aircraft are also likely to
decrease methane concentrations, thus having a negative
radiative forcing effect (TPCC 1999). Nitrogen oxides are
created from lightning, soil microbial activity, biomass
burning — both natural and anthropogenic fires — fuel
combustion, and, in the stratosphere, from the photo-
degradation of nitrous oxide (N2O). Concentrations of NOx
are both relatively short-lived in the atmosphere and spatially
variable.
Nonmethane Volatile Organic Compounds (NMVOCs).
Nonmethane volatile organic compounds include
compounds such as propane, butane, and ethane. These
compounds participate, along with NOx, in the formation
of tropospheric ozone and other photochemical oxidants.
NMVOCs are emitted primarily from transportation and
industrial processes, as well as biomass burning and non-
industrial consumption of organic solvents. Concentrations
of NMVOCs tend to be both short-lived in the atmosphere
and spatially variable.
Aerosols. Aerosols are extremely small particles or
liquid droplets found in the atmosphere. They can be
produced by natural events such as dust storms and volcanic
activity, or by anthropogenic processes such as fuel
combustion and biomass burning. They affect radiative
forcing in both direct and indirect ways: directly by
scattering and absorbing solar and thermal infrared
radiation; and indirectly by increasing droplet counts that
modify the formation, precipitation efficiency, and radiative
properties of clouds. Aerosols are removed from the
atmosphere relatively rapidly by precipitation. Because
aerosols generally have short atmospheric lifetimes, and
have concentrations and compositions that vary regionally,
spatially, and temporally, their contributions to radiative
forcing are difficult to quantify (IPCC 2001).
The indirect radiative forcing from aerosols are
typically divided into two effects. The first effect involves
decreased droplet size and increased droplet concentration
resulting from an increase in airborne aerosols. The second
effect involves an increase in the water content and lifetime
of clouds due to the effect of reduced droplet size on
precipitation efficiency (IPCC 2001). Recent research has
placed a greater focus on the second indirect radiative
forcing effect of aerosols.
Various categories of aerosols exist, including naturally
produced aerosols such as soil dust, sea salt, biogenic
aerosols, sulphates, and volcanic aerosols, and
anthropogenically manufactured aerosols such as industrial
dust and carbonaceous17 aerosols (e.g., black carbon, organic
carbon) from transportation, coal combustion, cement
manufacturing, waste incineration, and biomass burning.
The net effect of aerosols is believed to produce a
negative radiative forcing effect (i.e., net cooling effect on
the climate), although because they are short-lived in the
atmosphere lasting days to weeks their concentrations
NO, emissions injected higher in the stratosphere, primarily from fuel combustion emissions from high altitude supersonic aircraft, can lead to
stratospheric ozone depletion.
17 Carbonaceous aerosols are aerosols that are comprised mainly of organic substances and forms of black carbon (or soot) (IPCC 2001).
1-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
respond rapidly to changes in emissions.18 Locally, the
negative radiative forcing effects of aerosols can offset the
positive forcing of greenhouse gases (IPCC 1996).
"However, the aerosol effects do not cancel the global-scale
effects of the much longer-lived greenhouse gases, and
significant climate changes can still result" (IPCC 1996).
The IPCC's Third Assessment Report notes that "the
indirect radiative effect of aerosols is now understood to
also encompass effects on ice and mixed-phase clouds, but
the magnitude of any such indirect effect is not known,
although it is likely to be positive" (IPCC 2001).
Additionally, current research suggests that another
constituent of aerosols may have a positive radiative forcing
(Jacobson 2001). The primary anthropogenic emission
sources of elemental carbon include diesel exhaust, coal
combustion, and biomass burning.
Table 1-2: Global Warming Potentials and
Atmospheric Lifetimes (Years)
Gas
Atmospheric Lifetime
GWPa
Carbon dioxide (G02)
Methane (CH4)b
Nitrous oxide (N20)
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
CF4
C2F6
C^io
C6F14
SF6
50-200
123
120
264
5.6
32.6
14.6
48.3
1.5
36.5
209
17.1
50,000
10,000
2,600
3,200
3,200
1
21
310
11,700
650
2,800
1,300
3,800
140
2,900
6,300
1,300
6,500
9,200
7,000
7,400
23,900
Source: (IPCC 1996)
a 100 year time horizon
b The methane GWP includes the direct effects and those indirect
effects due to the production of tropospheric ozone and stratospheric
water vapor. The indirect effect due to the production of C02 is not
included.
Global Warming Potentials
A Global Warming Potential (GWP) is intended as a
quantified measure of the globally averaged relative
radiative forcing impacts of a particular greenhouse gas (see
Table 1-2). It is defined as the ratio of the time-integrated
radiative forcing from the instantaneous release of 1 kg of
a trace substance relative to that of 1 kg of a reference gas
(IPCC 2001). Direct radiative effects occur when the gas
itself is a greenhouse gas. Indirect radiative forcing occurs
when chemical transformations involving the original gas
produces a gas or gases that are greenhouse gases, or when
a gas influences other radiatively important processes such
as the atmospheric lifetimes of other gases. The reference
gas used is CO2, and therefore GWP weighted emissions
are measured in teragrams of CO2 equivalents (Tg CO2
Eq.).19 The relationship between gigagrams (Gg) of a gas
and Tg CO2Eq. can be expressed as follows:
(
Tg C02 Eq = (Gg of gas)x (GWP)x
(J,OOOGgJ
where,
TgCO2Eq.= Teragrams of Carbon Dioxide Equivalents
Gg = Gigagrams (equivalent to a thousand metric tons)
GWP = Global Warming Potential
Tg = Teragrams
GWP values allow policy makers to compare the
impacts of emissions and reductions of different gases.
According to the IPCC, GWPs typically have an uncertainty
of 35 percent. The parties to the UNFCCC have also agreed
to use GWPs based upon a 100 year time horizon although
other time horizon values are available.
In addition to communicating emissions in
units of mass, Parties may choose also to use
global warming potentials (GWPs) to reflect their
inventories and projections in carbon dioxide-
equivalent terms, using information provided by
the Intergovernmental Panel on Climate Change
(IPCC) in its Second Assessment Report. Any use
18 Volcanic activity can inject significant quantities of aerosol producing sulfur dioxide and other sulfur compounds into the stratosphere, which can
result in a longer negative forcing effect (i.e., a few years) (IPCC 1996).
19 Carbon comprises 12/44tbs of carbon dioxide by weight.
Introduction 1-7
-------
Box 1-1: The IPCC Third Assessment Report and Global Warming Potentials
The IPCC recently published its Third Assessment Report (TAR), providing the most current and comprehensive scientific assess-
ment of climate change. Within this report, the GWPs of several gases were revised relative to the IPCC's Second Assessment Report
(SAR), and new GWPs have been calculated for an expanded set of gases. Since the SAR, the IPCC has applied an improved calculation
of COj, radiative forcing and an improved C02 response function (presented in WM01999). The GWPs are drawn from WMO (1999) and
the SAR, with updates for those cases where significantly different new laboratory or radiative transfer results have been published.
Additionally, the atmospheric lifetimes of some gases have been recalculated. Because the revised radiative forcing of C02 is about 12
percent lower than that in the SAR, the GWPs of the other gases relative to C02 tend to be larger, taking into account revisions in lifetimes.
In addition, the values for radiative forcing and lifetimes have been calculated for a variety of halocarbons, which were not presented in the
SAR. Table 1-3 presents the new GWPs, relative to those presented in the SAR.
Although the GWPs have been updated by the IPCC, estimates of emissions presented in this Inventory will continue to use the GWPs
from the Second Assessment Report. The guidelines under which this Inventory is developed, the Revised 1996 IPCC Guidelines for
National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA1997) and the UNFCCC reporting guidelines for national inventories20 were
developed prior to the publication of the TAR. Therefore, to comply with international reporting standards under the UNFCCC, official
emission estimates are reported by the United States using SAR GWP values. For informational purposes, emission estimates that use the
updated GWPs are presented in below and in even more detail in Annex Q. Overall, these revisions to GWP values do not have a significant
effect on U.S. emission trends, as shown in Table 1 -4.
Table 1-5 below shows a comparison of total emissions estimates by sector using both the IPCC SAR and TAR GWP values. For most
sectors, the change in emissions was minimal. The effect on emissions from waste was by far the greatest (9.1 percent), due the
predominance of CH4 emissions in this sector. Emissions from all other sectors were comprised of mainly C02 or a mix of gases, which
moderated the effect of the changes.
Table 1-3: Comparison of 100 Year GWPs
Gas
SAR
TAR
Change
Carbon dioxide (C02)
Methane (CH4)*
Nitrous oxide (N20)
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC4310mee
CF,
**• q
C,FB
£. O
\jA\in
4 10
CRf-ti
o 14
SFS
1
21
310
11,700
650
2,800
1,300
3,800
140
2,900
6,300
1,300
6,500
9,200
7,000
7,400
23,900
1
23
296
12,000
550
3,400
1,300
4,300
120
3,500
9,400
1,500
5,700
11,900
8,600
9,000
22,200
NC
2
(14)
300
(100)
600
NC
500
(20)
600
3,100
200
(800)
2,700
1,600
1,600
(1,700)
NC
10%
(5%)
3%
(15%)
21%
NC
13%
(14%)
21%
49%
15%
(12%)
29%
23%
22%
(7%)
Source: (IPCC 2001)
NC (Mo Change)
' The methane GWP includes the direct effects and those indirect effects due to the production of tropospheric ozone and stratospheric water vapor.
The Indirect effect due to the production of C02 is not included.
20 Sec FCCC/CP/1999/7 at www.unfccc.de.
1-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table H-4: Effects on U.S. Greenhouse Gas Emission Trends Using IPCC SAR and TAR GWP Values (Tg C02 Eq.)
Change from 1990 to 2000 Revisions to Annual Estimates
Change from 1990 to 2000
Revisions to Annual Estimates
t,
Gas
C02
CH4
N20
HFCs, PFCs, and SF6
Total
Percent Change
SAR
841.5
(36.8)
38.0
.. 27.7
870.5
14.2%
TAR
841.5
(40.3)
36.3
34.0
871.6
14.1%
1990
0
62.0
(17.5)
(2.6)
42.0
0.7%
2000
0
58.5
(19.2)
3.8
43.1
0.6%
Table 1-5: Comparison of Emissions by Sector using IPCC SAR and TAR GWP Values (Tg C02 Eq.)
Sector
1990
1995
1996
1997
1998
1999
2000
$-
jr""
I-
|.
k
'f-
K •
.^
i-
K
f-
J
h
P1
ft
!
V
r
•
•f
fl_
s
r
Energy
1 SAR GWP (Used In Inventory)
TAR GWP
Difference (%)
Industrial Processes
SAR GWP (Used In Inventory)
TAR GWP
7 Difference (%)
Agriculture
SAR GWP (Used In Inventory)
TAR GWP
Difference (%)
Land-Use Change and Forestry
SAR GWP (Used In inventory)
TAR GWP
Difference (%)
Waste
SAR GWP (Used In inventory)
1 TAR GWP
Difference (%)
Net Emissions (Sources and Sinks)
SAR GWP (Used In Inventory)
TAR GWP
Difference (%)
NC (No change)
5,141.9
5,162.6
0.4%
295.7
291.8
-1.3%
448.4
451.3
0.6%
(1,0977)
(1,097.7)
NC
244.7
267.0
9.1%
5,033.0
5,074.9
0.8%
. :
eESSf®^*?!
5,452,4
&s;fi^--'f r *-j-\ r.
jgjjjjjjf-^ O,T/ 1 ,O
0 4%
301 9
299.6
-0.8%
£: •-•
iet-;-- t 4 ye 4
t / D.t
Mij^-L,rj,; '^S_ /1"7O C
jj~sp;j 4/y.b
^W'a^!^ U./ /O
^V-
(1,110.0)"
p3 (1,110.0)
|\1C
^^;.;j
' 251.1 "
273.9
9.1%
fe'.l
5,371.8
5,414.7
0.8%
5,629.9
5,648.6
0.3%
312.3
. 310.8
-0.5%
481.3
483.6
0.5%
(1,108.1)
(1,108.1)
NC
246.3
268.7
9.1%
5,561.7
5,603.6
0.7%
5,697.9
5,716.2
0.3%
322.4
_. 321 7..
-0.2%
485.9
487.9
0.4%
(887.5)
(887.5)
NC
241.9
263.8
9.1%
5,860.5
5,902.1
0.7%
5,709.5
5,727.6
0.3%
322.1
323.1
0.3%
487.6
489.7
0.4%
(885.9)
(885.9)
NC
236.9
258.3
9.0%
5,870.3
5,912.9
0.7%
5,793.9
5,811.2
0.3%
310.8
312.6
.0.6%
485.0
487.1
0.4%
(896.4)
(896.4)
NC
239.8
261.5
9.0%
5,933.1
5,975.9
0.7%
5,962.6
5,979.4
0.3% ;
312.8
315.5
0.8% .;
485.1
487.1
0.4% :
(902.5)
(902.5)
NC ;
240.6
262.4
9.0%
-
6,098.7
6,141.8
0.7%
"Note: Totals may not sum due to independent rounding.
of GWPs should be based on the effects of the
greenhouse gases over a 100-year time horizon.
In addition, Parties may also use other time
horizons.21
Greenhouse gases with relatively long atmospheric
lifetimes (e.g., CO2, CH4, N2O, HFCs, PFCs, and SF6) tend
to be evenly distributed throughout the atmosphere, and
consequently global average concentrations can be
determined. The short-lived gases such as water vapor,
carbon monoxide, tropospheric ozone, ozone precursors
(e.g., NOx, and NMVOCs), and tropospheric aerosols (e.g.,
SO2 products and carbonaceous particles), however, vary
regionally, and consequently it is difficult to quantify their
21 Framework Convention on Climate Change; FCCC/CP/1996/15/Add.l; 29 October 1996; Report of the Conference of the Parties at its second
session; held at Geneva from 8 to 19 July 1996; Addendum; Part Two: Action taken by the Conference of the Parties at its second session; Decision 91
CP.2; Communications from Parties included in Annex I to the Convention: guidelines, schedule and process for consideration; Annex: Revised
Guidelines for the Preparation of National Communications by Parties Included in Annex I to the Convention; p. 18. FCCC (1996)
Introduction 1-9
-------
global radiative forcing impacts. No GWP values are
attributed to these gases that are short-lived and spatially
inhomogeneous in the atmosphere.
Recent Trends in U.S. Greenhouse
Gas Emissions
In 2000, total U.S. greenhouse gas emissions rose to
7,001.2 teragrams of carbon dioxide equivalents (Tg CO2
Eq.)22 (14.2 percent above 1990 emissions). The single year
increase in emissions from 1999 to 2000 was 2.5 percent
(171.7 Tg CO2 Eq.), which was greater than the average
annual rate of increase for 1990 through 2000 (1.3 percent).
The higher than average increase in emissions in 2000 was,
in part, attributable to the following factors: 1) robust
economic growth in 2000, leading to increased demand for
electricity and transportation fuels, 2) cooler winter
conditions compared to the previous two years, and 3)
decreased output from hydroelectric dams. (See following
section for an analysis of emission trends by general
economic sectors). Figure 1-1 through Figure 1-3 illustrate
the overall trends in total U.S. emissions by gas, annual
changes, and absolute changes since 1990.
Figure 1-1
• MFCs, PFCs, & SF6 » Methane
• Nitrous Oxide « Carbon Dioxide
8,000 -
8
5,000
O 4,000 "I
P 3.000 -J
2,000 '
i,ooo*iHr
Oi! tit
As the largest source of U.S. greenhouse gas emissions,
CO2 from fossil fuel combustion accounted for a nearly
constant 79 percent of global warming potential (GWP)
weighted emissions in the 1990s.23 Emissions from this
source category grew by 18 percent (843.4Tg CO2Eq.) from
1990 to 2000 and were responsible for most of the increase
in national emissions during this period. The annual increase
in CO2 emissions from fossil fuel combustion was 3.2
percent in 2000, double the source's average annual rate of
1.6 percent from 1990 through 2000. Historically, changes
in emissions from fossil fuel combustion have been the
dominant factor affecting U.S. emission trends.
Changes in CO2 emissions from fossil fuel combustion
are influenced by many long-term and short-term factors,
including population and economic growth, energy price
fluctuations, technological changes, and seasonal
temperatures. On an annual basis, the overall consumption
of fossil fuels in the United States and other countries
generally fluctuates in response to changes in general
economic conditions, energy prices, weather, and the
availability of non-fossil alternatives. For example, a year
with increased consumption of goods and services, low fuel
prices, severe summer and winter weather conditions,
nuclear plant closures, and lower precipitation feeding
hydroelectric dams would be expected to have
proportionally greater fossil fuel consumption than a year
with poor economic performance, high fuel prices, mild
temperatures, and increased output from nuclear and
hydroelectric plants.
Longer-term changes in energy consumption patterns,
however, tend to be more a function of changes that affect
the scale of consumption (e.g., population, number of cars,
and size of houses), the efficiency with which energy is
used in equipment (e.g., cars, power plants, steel mills, and
light bulbs) and consumer behavior (e.g., walking, bicycling,
or telecommuting to work instead of driving).
Energy-related CO2 emissions are also a function of the
type fuel or energy consumed and its carbon intensity.
Producing heat or electricity using natural gas instead of
coal, for example, can reduce the CO2 emissions associated
22 Estimates are presented in units of teragrams of carbon dioxide equivalents (Tg CO2 Eq.), which weight each gas by its Global Warming Potential,
or GWP, value. (See section on Global Warming Potentials, Chapter 1.)
23 If a full accounting of emissions from fossil fuel combustion is made by including emissions from the combustion of international bunker fuels and
CHj and N2O emissions associated with fuel combustion, then this percentage increases to a nearly constant 80 percent during the 1990s.
1-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Figure 1-2
Figure 1 -3
with energy consumption because of the lower carbon
content of natural gas per unit of useful energy produced.
Table 1-6 shows annual changes in emissions during the last
few years of the 1990s for selected fuel types and sectors.
Carbon dioxide emissions from fossil fuel combustion
grew rapidly in 1996, due primarily to two factors: 1) fuel
switching by electric utilities from natural gas to more
carbon intensive coal as colder winter conditions and the
associated rise in demand for natural gas from residential
and commercial customers for heating caused gas prices to
rise sharply; and 2) higher consumption of petroleum fuels
for transportation. Milder weather conditions in summer
and winter moderated the growth in emissions in 1997;
however, the shut-down of several nuclear power plants lead
electric utilities to increase their consumption of coal and
other fuels to offset the lost nuclear capacity.
871
In 1998, weather conditions were again a dominant
factor in slowing the growth in emissions. Warm winter
temperatures resulted in a significant drop in residential and
commercial natural gas consumption. This drop in emissions
from natural gas used for heating was primarily offset by
two factors: 1) electric utility emissions, which increased
in part due to a hot summer and its associated air
conditioning demand; and 2) increased motor gasoline
consumption for transportation.
In 1999, the increase in emissions from fossil fuel
combustion was driven largely by growth in petroleum
consumption for transportation. In addition, residential and
commercial heating fuel demand partially recovered as
winter temperatures dropped relative to 1998, although
temperatures were still warmer than normal. These
Table 1-3: Annual Change in C02 Emissions from Fossil Fuel Combustion for Selected Fuels and Sectors (Tg C02
Eq, and Percent)
Sector
Electricity Generation
Electricity Generation
Electricity Generation
Transportation3
Residential
Commercial
Industrial
Industrial
All Sectors'1
Fuel Type
Coal
Natural Gas
Petroleum
Petroleum
Natural Gas
Natural Gas
Coal
Natural Gas
All Fuels11
1995 to 1996
91.2
(24.3)
5.0
38.7
21.4
7.0
(5.7)
16.3
181.6
5.5%
-8.8%
7.8%
2.5%
8.1%
4.3%
-4.4%
4.1%
3.6%
1996 to 1997
49.9
17.9
8.9
7.6
(14.0)
3.1
1.4
(5.2)
72.9
2.9%
7.1%
12.9%
0.5%
-4.9%
1.8%
1.1%
-1.3%
1.4%
1997 to 1998
28.0
32.4
28.1
32.7
(24.0)
(11.1)
(5.6)
(31.6)
16.6
1.6%
12.0%
35.8%
2.1%
-8.9%
-6.4%
-4.4%
-7.7%
0.3%
1998 to 1999
11.1
7.5
1.2
68.0
10.0
1.7
(4.4)
(5.0)
92.4
0.6%
2.5%
1.2%
4.2%
4.0%
1.0%
-3.6%
-1.3%
1.7%
1999(02000
87.3
31.5
(12.5)
59.6
11.8
15.6
(14.1)
(1.6)
174.7
4.8%
10.2%
-11.6%
3.5%
4.6%
9.4%
-12.1%
-0.4%
3.2%
-a Excludes emissions from International Bunker Fuels.
b Includes fuels and sectors not shown in table.
Introduction 1-11
-------
increases were offset, in part, by a decline in emissions
from electric power producers due primarily to: 1) an
increase in net generation of electricity by nuclear plants
to record levels, which reduced demand from fossil fuel
plants; and 2) moderated summer temperatures compared
to the previous year-thereby reducing electricity demand
for air conditioning.
Emissions from fuel combustion increased considerably
in 2000, due to several factors. The primary reason for the
increase was the robust U.S. economy, which produced a
high demand for fuels—especially for petroleum in the
transportation sector—despite increases in the price of both
natural gas and petroleum. Colder winter conditions relative
to the previous year triggered a rise in residential and
commercial demand for heating. Structural and other
economic changes taking place within U.S. industry
especially manufacturing lead to lower coal consumption.
Additionally, electricity generation became more carbon
intensive as coal and natural gas consumption off set reduced
hydropower output. In sum, emissions from fossil fuel
combustion exhibited the second highest annual increase
since 1990.
Other significant trends in emissions from additional
source categories over the eleven year period from 1990
through 2000 included the following:
• Aggregate HFC and PFC emissions resulting from the
substitution of ozone depleting substances (e.g., CFCs)
increased by 56.8 Tg CO2 Eq. This increase was
significantly offset, however, by reductions in PFC
emissions from aluminum production (10.2 Tg CO2
Eq. or 56 percent), reductions in emissions of HFC-
23 from the production of HCFC-22 (5.2 Tg CO2 Eq.
or 15 percent), and reductions of SF6 from electric
power transmission and distribution systems (16.8 Tg
CO2 Eq. or 54 percent). Reductions in PFC emissions
from aluminum production were the result of both
industry emission reduction efforts and lower domestic
aluminum production. HFC-23 emissions from the
production of HCFC-22 decreased due to a reduction
in the intensity of emissions from that source, despite
increased HCFC-22 production. Reduced emissions
of SF6 from electric power transmission and
distribution systems are primarily the result of higher
purchase prices for SF6 and efforts by industry to
reduce emissions.
• Methane emissions from coal mining dropped by 26.2
Tg CO2 Eq. (30 percent) as a result of the mining of
less gassy coal from underground mines and the
increased use of methane from degasification systems.
• Nitrous oxide emissions from agricultural soil
management increased by 30.5 Tg CO2 Eq. (11 percent)
as fertilizer consumption and cultivation of nitrogen
fixing crops rose.
• By 1998, all of the three major adipic acid producing
plants had voluntarily implemented N2O abatement
technology, and as a result, emissions fell by 6.8 Tg
CO2 Eq. (46 percent). The majority of this decline
occurred from 1997 to 1998, despite increased
production.
• Carbon dioxide emissions from feedstock uses of coal
coke for iron and steel production decreased by 19.7
Tg CO2 Eq. (23 percent), as imports of steel have
increased.
• Methane emissions from U.S. landfills decreased 5
percent, as the amount of landfill gas collected and
combusted by landfill operators has increased.
• Emissions of N2O from mobile combustion rose by 7.4
Tg CO2 Eq. (14 percent), primarily due to an increased
average N2O generation rate for the U.S. highway
vehicle fleet.
Overall, from 1990 to 2000, total emissions of CO2 and
N2O increased by 841.5 (17 percent) and 38.0 Tg CO2 Eq.
(10 percent), respectively, while CH4 emissions decreased
by 36.8 Tg CO2 Eq. (6 percent). During the same period,
aggregate weighted emissions of HFCs, PFCs, and SF6 rose
by 27.7 Tg CO2 Eq. (30 percent). Despite being emitted in
smaller quantities relative to the other principal greenhouse
gases, emissions of HFCs, PFCs, and SF6 are significant
because many of them have extremely high global warming
potentials and, in the cases of PFCs and SF6, long
atmospheric lifetimes. Conversely, U.S. greenhouse gas
emissions were partly offset by carbon sequestration in
forests, agricultural soils, and in landfilled carbon, which
were estimated to be 13 percent of total emissions in 2000.
As an alternative, emissions can be aggregated across
gases by the IPCC defined sectors, referred to here as
chapters. Over the ten year period of 1990 to 2000, total
emissions in the Energy, Industrial Processes, and
Agriculture chapters climbed by 817.8 (16 percent), 17.1
1-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Box 1-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data
There are several ways to assess a nation's greenhouse gas emitting intensity. The basis for measures of intensity can be 1) per unit
L of aggregate energy consumption, because energy-related activities are the largest sources of emissions; 2) per unit of fossil fuel con-
t sumption, because almost all energy-related emissions involve the combustion of fossil fuels; 3) per unit of electricity consumption,
= because the electric power industry—utilities and nonutilities combined—were the largest sources of U.S. greenhouse gas emissions in
: 2000; 4) per unit of total gross domestic product as a measure of national economic activity; or 5) on a per capita basis. Depending upon
:" the measure used, the United States could appear to have reduced or increased its national greenhouse gas intensity during the 1990s.
; Table 1-7 provides data on various statistics related to U.S. greenhouse gas emissions normalized to 1990 as a baseline year.
^ Greenhouse gas emissions in the U.S. have grown at an average annual rate of 1.3 percent since 1990. This rate is slightly slower than
^that for total energy orfossil fuel consumption thereby indicating an improved or lower greenhouse gas emitting intensity and much slower
Hihan that for either electricity consumption or overall gross domestic product. At the same time, total U.S. greenhouse gas emissions have
: "grown at about the same rate as national population during the last decade (see Figure 1-4). Overall, atmospheric C02 concentrations a
function of many complex anthropogenic and natural processes are increasing at 0.4 percent per year.
Table 1-7: Recent Trends in Various U.S. Data (Index 1990 = 100)
Variable
• GHG Emissions3
Energy Consumption15
Fossil Fuel Consumption15
Electricity Consumption15
" GDP"
". Population11
^ Atmospheric C02
Concentration6
1991
99
100
99
102
100
101
100
1992
101
101
101
102
103
103
101
1993
103
104
103
105
105
104
101
1994
105
106
106
108
110
105
101
1995
106
108
107
111
112
107
102
1996
109
111
110
114
116
108
102
1997
110
112
112
116
122
109
103
1998
110
112
112
120
127
110
104
1999
111
115
114
122
132
112
104
2000
114
117
116
125
138
113
104
Growth
Rate'
1.3%
1.6%
1.5%
2.3%
3.2%
1.2%
0.4%
a GWP weighted values
b Energy content weighted values (EIA2001)
c Gross Domestic Product in chained 1996 dollars (BEA 2000)
_d (U.S. Census Bureau 2000)
e Mauna Loa Observatory, Hawaii (Keeling and Whorf 2000)
'Average annual growth rate
Figure 1-4
Source: BEA (2001), U.S. Census Bureau (2000), and
emission estimates in this report.
Introduction 1-13
-------
Table 1-8: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg C02 Eq.)
Gas/Source
C02
Fossil Fuel Combustion
Iron and Steel Production
Cement Manufacture
Indirect C02from CH4 Oxidation
Waste Combustion
Ammonia Manufacture
Lime Manufacture
Limestone and Dolomite Use
Natural Gas Raring
Aluminum Production
Soda Ash Manufacture
and Consumption
Titanium Dioxide Production
Ferroalloys
Carbon Dioxide Consumption
Land-Use Change & Forestry (Sink)3
International Bunker Fuels'1
CH<
Landfills
Enteric Fermentation
Natural Gas Systems
Coal Mining
Manure Management
Wastewater Treatment
Petroleum Systems
Stationary Sources
Rice Cultivation
Mobile Sources
Petrochemical Production
Agricultural Residue Burning
Silicon Carbide Production
International Bunker Fuels'3
N20
Agricultural Soil Management
Mobile Sources
Nitric Acid
Manure Management
Stationary Sources
Human Sewage
Adlpic Acid
Agricultural Residue Burning
Waste Combustion
International Bunker Fuelsb
HFGs, PFCs, and SF6
Substitution of Ozone Depleting
Substances
HCFC-22 Production
Electrical Transmission
and Distribution
Aluminum Production
Semiconductor Manufacture
1990
4,998.5
4,779.8
85.4
33.3
30.9
14.1
18.5
11.2
5.2
5.5
6.3
4.1
1.3
2.0
0.8
(1,097.7)
113.9
651.3
213.4
127.9
121.2
87.1
29.2
24.3
26.4
7.9
7.1
4.9
1.2
0.7
+
0.2
387.3
267.1
50.9
17.8
16.0
12.8
7.0
14.9
0.4
0.3
1.0
93.6
0.9
35.0
31.2
18.1
2.9
Magnesium Production and Processing 5.5
Total
Net Emissions (Sources and Sinks)
6,130.7
5,033.0
w
b-.. **
Snt I
k
IL :
L *
9 I
B,.1 '.
: 1
I (
I.J
fri
•~ *
1, r
ft
UJ
1- 4
1 ft
?
ri**
,
f-
C
:
X,
r~
^ _^ .
i
g.
y " .
JSJU-— =
SM "_
i1
FI™ r
IK,
C
(in- -
f" '— '
i*_L h
ll
i :,
I ' T'
|v- - . =
L,:;;, ,,,:
il •
i
t^--™"*
&,„,., /.
iu.
fc.^
p
I::1' "":*
1- *
F
js**- 7
r" :
B"V"
E'V;^;
If
,,r=-- =---*
t"
1995
5,305.9
5,085.0
74.4
36.8
29.5
18.6
18.9
12.8
7.0
8.7
5.3
4.3
1.7
1.9
1.0
(1,110.0)
101.0
657.6
216.6
133.2
125.7
73.5
34.8
26.8
24.2
8.2
7.6
4.8
1.5
0.7
+
0.1
419.8
283.4
60.4
19.9
16.4
13.5
7.7
17.9
0.4
0.3
0.9
98.5
21.8
27.0
26.5
11.8
5.9
5.5
6,481.8
5,371.8
1996
5,483.7
5,266.6
68.3
37.1
28.9
19.6
19.5
13.5
7.4
8.2
5.6
4.2
1.7
2.0
1.1
(1,108.1)
102.3
643.7
211.5
129.6
126.6
68.4
34.2
27.0
24.0
8.4
7.0
4.7
1.6
0.7
+
0.1
430.5
292.6
60.1
20.7
16.8
14.1
7.8
17.8
0.4
0.3
0.9
111.9
30.6
31.1
26.8
12.5
5.4
5.5
6,669.8
5,561.7
1997
5,568.0
5,339.6
76.1
38.3
28.4
21.3
19.5
13.7
8.4
7.6
5.6
4.4
1.8
2.0
1.3
(887.5)
109.9
633.3
206.4
126.8
122.7
68.1
35.8
27.5
24.0
7.5
7.5
4.6
1.6
0.8
+
0.1
429.8
297.5
59.7
21.2
17.1
14.2
7.9
11.5
0.4
0.3
1.0
116.9
38.0
30.0
24.5
11.0
6.5
6.9
6,748.1
5,860.5
1998
5,575.1
5,356.2
67.4
39.2
28.2
20.3
20.1
13.9
8.2
6.3
5.8
4.3
1.8
2.0
1.4
(885.9)
112.9
627.1
201.0
124.9
122.2
67.9
38.0
27.8
23.4
7.0
7.9
4.5
1.6
0.8
+
0.1
426.3
298.4
59.1
20.9
17.1
14.3
8.1
7.7
0.5
0.2
1.0
127.7
44.9
40.2
20.1
9.0
7.3
6.2
6,756.2
5,870.3
1999
5,665.5
5,448.6
64.4
40.0
27.0
21.8
18.9
13.5
9.1
6.7
5.9
4.2
1.9
2.0
1.6
(896.4)
105.3
620.5
203.1
124.5
118.6
63.7
37.6
28.3
22.3
7.3
8.3
4.4
1.7
0.8
+
0.1
423.5
296.3
58.7
20.1
17.1
14.6
8.4
7.7
0.4
0.2
0.9
120.0
51.3
30.4
15.5
8.9
7.7
6.1
6,829.5
5,933.1
2000
5,840.0
5,623.3
65.7
41.1
26.3
22.5
18.0
13.3
9.2
6.1
5.4
4.2
2.0
1.7
1.4
(902.5)
100.2
614.5
203.5
123.9
116.4
61.0
37.5
28.7
21.9
7.5
7.5
4.4
1.7
0.8
+
0.1
425.3
297.6
58.3
19.8
17.5
14.9
8.5
8.1
0.5
0.2
0.9
121.3
57.8
29.8
14.4
7.9
7.4
4.0
7,001.2
6,098.7
+ Does not exceed 0.05 Tg C02 Eq.
• Sinks are only included in net emissions total, and are based partially on projected activity data. Parentheses indicate negative values (or sequestration).
b Emissions from International Bunker Fuels are not included in totals.
Note: Totals may not sum due to independent rounding.
1-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 1-9: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg)
b Gas/Source 1990
N02 4,998,515
s- ' Fossil Fuel Combustion 4,779,847
f, , Iron and Steel Production . 85,414
f Cement Manufacture 33,278
;; Indirect C02 from CH4 Oxidation 30,899
" Waste Combustion 14,091
f Ammonia Manufacture 18,510
"'".' Lime Manufacture 11,238
C Limestone and Dolomite Use 5,181
>' Natural Gas Flaring 5,514
£ Aluminum Production 6,31 5
!" Soda Ash Manufactures Consumption 4,142
"f Titanium Dioxide Production 1 ,308
1 Ferroalloys 1,980
f Carbon Dioxide Consumption 800
: Land-Use Change and Forestry
; (Sink)3 (1,097,747)
v International Bunker Fuelsb 113,863
t CH4 31,014
! Landfills 10,162
: Enteric Fermentation 6,089
T Natural Gas Systems 5,772
': Coal Mining 4,149
*~ Manure Management 1,390
- Wastewater Treatment 1,155
Petroleum Systems 1,258
i Stationary Sources 376
T Rice Cultivation ' 339
-. Mobile Sources 233
r. Petrochemical Production 56
',- Agricultural Residue Burning 33
5 Silicon Carbide Production 1
r International Bunker Fuelsb 8
filjjO 1,249
; Agricultural Soil Management 862
'*_. Mobile Sources .... 164
•i Nitric Acid 58
* - Manure Management 52
Stationary Source 41
Human Sewage 23
T AdipicAcid 48
k Agricultural Residue Burning 1
f Waste Combustion 1
« International Bunker Fuelsb 3
" MFCs, PFCs, and SFB M
* Substitution of Ozone Depleting Substances M
I HCFC-22 Production0 3
J Electrical Transmission and Distributiond 1
:". Aluminum Production M
'i Semiconductor Manufacture M
; — Magnesium Production and Processing11 +
? NOX 21,955
= CO 85,994
5 NMVOCs 18,851
1995
asss^f^s
^*^ 5,305,895
?- * 5,085,044
l~" - 74,357
E**""** 36,847
i ! 29,458
P "* 18,608
* " 18,946
EP 12,804
f- ^ 7,028
r - 8,729
L*: 5.265
—I. ' 4,305
Sr" 1,670
&.-""! 1,866
968
F- ;
«-*"! (1,110,016)
I ! 101,037
««=", 31,134
^^™izi^. '
^^ 10,315
'^ I 6,342
t " " 5,984
- , 3,502
L ~l 1,657
^ 3 1,275
«=-- * 1i154
^- - 392
EH" " 363
IP.. 228
72
s~ .1 31
K- " 1
r-- • 6
1,354
gf : 914
- 195
i^ 64
£l~ 53
f" ' 43
^ " 25
~s~ ^ 58
^ ^
ST-- 1
IM "3
M
- » M
Zl O
l^^f 1
gr; "" M
r • M
«r-'J +
*— ' 24j214
"" r 80,798
-*"" 18,671
1996
5,483,670
5,266,619
68,324
37,079
28,891
19,569
19,512
13,495
7,379
8,233
5,580
4,239
1,657
1,954
1,140
(1,108066)
102,272
30,654
10,072
6,171
6,030
3,255
1,628
1,287
1,145
400
332
222
75
36
1
6
1,389
944
194
67
54
45
25
57
1
1
3
M
M
3
1
M
M
+
25,075
90,319
17,763
1997
5,567,981
5,339,562
76,127
38,323
28,354
21,344
19,477
13,685
8,401
7,565
5,621
4,355
1,836
2,038
1,294
(887,531)
109,885
30,159
9,827
6,037
5,845
3,244
1,707
1,311
1,144
356
356
217
77
36
1
7
1,387
960
192
68
55
46
26
37
1
1
3
M
M
3
1
M
M
+
25,584
90,778
18,118
1998
5,575,083
5,356,161
67,429
39,218
28,183
20,251
20,113
13,914
8,187
6,250
5,792
4,325
1,819
2,027
1,413
(885,883)
112,913
29,863
9,571
5,948
5,820
3,235
1,811
1,326
1,114
334
376
212
78
37
1
7
1,375
963
191
67
55
46
26
25
1
1
3
M
M
3
1
M
M
+
25,546
86,593
17,150
1999
5,665,472
5,448,589
64,376
39,991
27,004
21,843
18,874
13,466
9,115
6,679
5,895
4,217
1,853
1,996
1,572
(896,392)
105,341
29,548
9,671
5,929
5,646
3,033
1,788
1,350
1,061
350
395
209
79
36
1
6
1,366
956
189
65
55
47
27
25
1
1
3
M
M
3
1
M
M
+
25,300
89,568
17,323
2000
5,840,039
5,623,268
65,709
41,067
26,302
22,470
18,017
13,316
9,196
6,059
5,410
4,181
1,963
1,719
1,361
(902,495)
100,228
29,262
9,690
5,898
5,541
2,903
1,784
1,367
1,041
357
357
208
79
37
1
6
1,372
960
188
64
57
48
27
26
1
1
3
M
M
3
1
M
M
+
25,116
97,300
18,267
'" + Does not exceed 0.5 Gg.
M Mixture of multiple gases
a Sinks are not included in C02 emissions total, and are based partially on projected activity data.
;- b Emissions from International Bunker Fuels are not included in totals.
=---« HFC-23 emitted
; dSF6 emitted
r Note: Totals may not sum due to independent rounding.
Introduction 1-15
-------
Table 1-10: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg C02 Eq.)
Chapter/IPCC Sector
Energy
Industrial Processes
Agriculture
Land-Use Change and Forestry (Sink)*
Waste
Total
Net Emissions (Sources and Sinks)
1990
5,141.9
295.7
448.4
(1,097.7)
244.7
6,130.7
5,033.0
p. .
i~ ,
f~~
ir--"^
ffitfi
|.:,,:,
IM'/
f^:"
S -:
iS """
1
"ir':"l
~" TI;
,, -r
1995
5,452.4
301.9
476.4
(1,110.0)
251.1
6,481.8
5,371.8
1996
5,629.9
312.3
481.3
(1,108.1)
246.3
6,669.8
5,561.7
1997
5,697.9
322.4
485.9
(887.5)
241.9
6,748.1
5,860.5
1998
5,709.5
322.1
487.6
(885.9)
236.9
6,756.2
5,870.3
1999
5,793.9
310.8
485.0
(896.4)
239.8
6,829.5
5,933.1
2000
5,962.6
312.8
485.1
(902.5)
240.6
7,001.2
6,098.7
* Sinks are only included in net emissions total, and are based partially on projected activity data.
Note: Totals may not sum due to independent rounding.
Note: Parentheses indicate negative values (or sequestration).
(6 percent), and 35.7 Tg CO2Eq. (8 percent), respectively,
while the Waste chapter decreased 4.1 Tg CO2Eq. (2
percent). Estimates of net carbon sequestration in the Land-
Use Change and Forestry chapter declined by 195.2 Tg CO2
Eq. (18 percent).
Table 1-8 summarizes emissions and sinks from all U.S.
anthropogenic sources in weighted units of Tg CO2Eq.,
while unweighted gas emissions and sinks in gigagrams (Gg)
are provided in Table 1-9. Alternatively, emissions and sinks
are aggregated by chapter in Table 1-10 and Figure 1-5.
Figure 1-5
7,000
6,000
5,000
ff
3,000
2,000
1,000
0
(1,000)
(2,000)
Waste
Agriculture
Industrial
t Processes
i
-*- Energy
Land-Use
Change &
Forestry
(sink)
Emissions by
Economic Sectors
Throughout this report, emission estimates are grouped
into six sectors (i.e., chapters) defined by the IPCC: Energy,
Industrial Processes, Solvent Use, Agriculture, Land-Use
Change and Forestry, and Waste. While it is important to
use this characterization for methodological reasons, it is
also useful to allocate emissions into sectoral categories that
are more intuitive. This section reports emissions by the
following "economic sectors": Residential, Commercial,
Industry, Transportation, Electricity Generation, and
Agriculture, and U.S. Territories. Using this categorization
scheme, emissions from electricity generation accounted for
the largest portion (34 percent) of U.S. greenhouse gas
emissions. The transportation activities, in aggregate,
accounted for the second largest portion (27 percent).
Additional discussion and data on these two economic
sectors is provided below.
Emissions from industry accounted for 19 percent of
U.S. greenhouse gas emissions in 2000. In contrast to
electricity generation and transportation, emissions from
industry have declined over the past decade, as structural
changes have occurred in the U.S. economy (i.e., shifts from
a manufacturing base to a service-based economy), fuel
switching has occurred, and efficiency improvements have
been made. The remaining 20 percent of U.S. greenhouse
gas emissions were contributed by the residential,
agriculture, commercial economic sectors, and U.S.
territories. Residences accounted for about 8 percent, and
primarily consisted of carbon dioxide (CO2) emissions from
1-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
fossil fuel combustion. Activities related to agriculture also
accounted for roughly 8 percent of U.S. emissions, but
unlike all other economic sectors these emissions were
dominated by nitrous oxide (N2O) emissions from
agricultural soils instead of CO2 from fossil fuel combustion.
The commercial sector accounted for about 5 percent of
emissions, while U.S. territories accounted for less than 1
percent of total emissions.
Carbon dioxide was also emitted and sequestered by a
variety of activities related to land-use change and forestry.
Table 1-11 presents a detailed breakdown of emissions
from each of these economic sectors by source category, as
they are defined in this report. Figure 1-6 shows the trend
in emissions by sector from 1990 to 2000.
Emissions with Electricity Distributed to
Economic Sectors
It can also be useful to view greenhouse gas emissions
from economic sectors with emissions related to electricity
generation distributed into end-use categories (i.e.,
emissions from electricity generation are allocated to the
economic sectors in which the electricity is consumed). To
distribute electricity emissions among end-use sectors,
emissions from the source categories assigned to the
electricity generation sector were allocated to the residential,
commercial, industry, transportation, and agriculture
economic sectors according to retail sales of electricity (EIA
2001 and Duffield 2002). These three source categories
include CO2 from fossil fuel combustion, CH4 and N2O from
stationary sources, and SFg from electrical transmission and
distribution.24
When emissions from electricity are distributed among
these sectors, industry accounts for the largest share of U.S.
greenhouse gas emissions (29 percent). Emissions from the
residential and commercial sectors also increase
substantially due to their relatively large share of electricity
consumption. Transportation activities remain the second
largest contributor to emissions. In all sectors except
agriculture, CO2 accounts for more than 75 percent of
greenhouse gas emissions, primarily from the combustion
of fossil fuels.
Figure 1-S
2,500
2,000
iS" 1,500
CM
O
0 1,000
500
0
Electricity Generation 34%
^^^^
Transportation 27%
__———•""""'^^
Industry 19%
Agriculture 8%%
Residential 8%\
Commercial 5%
Table 1-12 presents a detailed breakdown of emissions
from each of these economic sectors, with emissions from
electricity generation distributed to them. Figure 1-7 shows
the trend in these emissions by sector from 1990 to 2000.
Electricity Generation
Activities related to the generation, transmission, and
distribution of electricity in the United States accounted for
34 percent of total U.S. greenhouse gas emissions.
Emissions from this economic sector increased by 25 percent
since 1990, as electricity demand to grew and fossil fuels
remained the dominant energy source for generation. The
electricity generation sector in the United States is composed
of traditional electric utilities as well as other entities, such
as power marketers and nonutility power producers. The
majority of electricity generated by these entities was
through the combustion of coal in boilers to produce high
pressure steam that is passed through a turbine. Table 1-13
provides a detailed summary of emissions from electricity
generation-related activities.
Transportation
Transportation activities accounted 27 percent of U.S.
greenhouse gas emissions. From 1990 to 2000, emissions from
transportation rose by 23 percent due, in part, to increased
24 Emissions were not distributed to U.S. territories, since the electricity generation sector only includes emissions related to the generation of
electricity in the 50 states and the District of Columbia.
Introduction 1-17
-------
Table 1-11: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg C02 Eq. and Percent of Total in 2000)
Sector/Source
Electricity Generation
C02 from Fossil Fuel Combustion
Transmission & Distribution0
Stationary Combustion0
Transportation
C02 from Fossil Fuel Combustion
Mobile Combustion0
Substitution of ODSd
Industry
C02 from Fossil Fuel Combustion
Natural Gas Systems
Iron & Steel Production
Coal Mining
Cement Manufacture
HCFC-22 Production6
Substitution of ODSd
Indirect C02 from CH4 Oxidation
Petroleum Systems
Nitric Acid
Ammonia Manufacture
Wastewater Treatment
Landfills
Aluminum Production*
Ume Manufacture
Limestone & Dolomite Use
Adipic Acid
Semiconductor Manufactured
Stationary Combustion0
Natural Gas Flaring
Soda Ash Manufacture &
Consumption
1990
1,898.2
1,858.9
31.2
8.1
1,527.7
1,471.8
55.8
+
1,393.9
825.3
121.2
85.4
87.1
33.3
35.0
+
30.9
26.4
17.8
18.5
12.0
14.9
24.4
11.2
5.2
14.9
2.9
5.9
5.5
4.1
Magnesium Production & Processing0 5.5
Titanium Dioxide Production
Ferroalloys
Petrochemical Production
Waste Combustion8
Carbon Dioxide Consumption
Silicon Carbide Production
Agriculture
Agricultural Soil Management
Enteric Fermentation
Manure Management0
C02 from Fossil Fuel Combustion
Rice Cultivation
Agricultural Residue Burning0
Mobile Combustion0
Stationary Combustion0
Residential
C02 from Fossil Fuel Combustion
Landfills
Wastewater Treatment
Waste Combustion8
Human Sewage
Stationary Combustion0
Substitution of ODSd
1.3
2.0
1.2
1.0
0.8
+
494.7
267.1
127.9
45.2
46.3
7.1
1.1
+
+
484.6
332.1
119.5
12.3
8.1
7.0
5.7
+
§'
L
I-!
fi'-r
t
I:;,:
r
IE;:;:
I" .-
!=,,„.
L
£_...
fciii: i.
L;
f
fe
_
1"
m
K" '
i
"
^
1
f
ft?
IT
i.
I"''"
r
PL--
f
IT -
t-
1::::
— , .
P ..
£ ' "
;"
«*" '
;,.
:
r
s
-----
"
1
i
=- -
—If-
j
-J
TIT
"
-
'•""'"I
A
. .1
..,fi
" ""'|
,J
,„ SI
ll
1
I
I,
T
;
fc
E
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I
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:
;;
*
,1)
«
•™i;
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fc
i
i
;:
•4
:
^
r
*
4
1
1995
2,024.3
1,989.3
26.5
8.5
1,652.4
1,579.4
65.2
7.9
1,400.9
838.0
125.7
74.4
73.5
36.8
27.0
11.1
29.5
24.2
19.9
18.9
13.7
15.2
17.1
12.8
7.0
17.9
5.9
6.3
8.7
4.3
5.5
1.7
1.9
1.5
1.3
1.0
+
533.3
283.4
133.2
51.2
56.9
7.6
1.0
+
+
522.7
362.3
121.3
13.1
10.6
7.7
5.8
1.9
1996
2,096.9
2,061.2
26.8
8.9
1,695.2
1,618.7
64.8
11.8
1,447.6
884.5
126.6
68.3
68.4
37.1
31.1
15.5
28.9
24.0
20.7
19.5
13.8
14.8
18.0
13.5
7.4
17.8
5.4
6.5
8.2
4.2
5.5
1.7
2.0
1.6
1.4
1.1
+
533.3
292.6
129.6
51.0
52.0
7.0
1.2
+
+
549.0
390.4
118.4
13.2
11.1
7.8
5.9
2.1
1997
2,171.6
2,137.9
24.5
9.2
1,708.5
1,628.8
64.2
15.4
1,442.7
876.9
122.7
76.1
68.1
38.3
30.0
18.3
28.4
24.0
21.2
19.5
14.2
14.4
16.6
13.7
8.4
11.5
6.5
6.7
7.6
4.4
6.9
1.8
2.0
1.6
1.5
1.3
+
544.2
297.5
126.8
52.9
58.3
7.5
1.2
+
+
531.1
374.9
115.6
13.4
12.1
7.9
4.7
2.5
1998
2,256.1
2,226.4
20.1
9.5
1,737.4
1,655.0
63.6
18.9
1,385.9
823.5
122.2
67.4
67.9
39.2
40.2
20.9
28.2
23.4
20.9
20.1
14.3
14.1
14.8
13.9
8.2
7.7
7.3
6.6
6.3
4.3
6.2
1.8
2.0
1.6
1.4
1.4
+
545.1
298.4
124.9
55.1
57.6
7.9
1.2
+
+
494.3
341.8
112.6
13.5
11.5
8.1
4.2
2.7
1999
2,271.2
2,246.2
15.5
9.5
1,813.3
1,728.2
63.1
22.0
1,341.1
798.1
118.6
64.4
63.7
40.0
30.4
23.5
27.0
22.3
20.1
18.9
14.6
14.2
14.8
13.5
9.1
7.7
7.7
6.8
6.7
4.2
6.1
1.9
2.0
1.7
1.5
1.6
+
544.9
296.3
124.5
54.7
59.9
8.3
1.2
+
+
516.0
360.5
113.7
13.7
12.4
8.4
4.5
2.9
2000
2,376.9
2,352.5
14.4
10.0
1,877.0
1,789.5
62.7
24.8
1,314.6
778.8
116.4
65.7
61.0
41.1
29.8
26.3
26.3
21.9
19.8
18.0
14.8
14.2
13.4
. 13.3
9.2
8.1
7.4
6.7
6.1
4.2
4.0
2.0
1.7
1.7
1.6
1.4
+
535.5
297.6
123.9
55.0
50.4
7.5
1.2
+
+
531.6
374.8
113.9
13.9
12.7
8.5
4.7
3.2
Percent3
33.9%
33.6%
0.2%
0.1%
26.8%
25.6%
0.9%
0.4%
18.8%
11.1%
1.7%
0.9%
0.9%
0.6%
0.4%
0.4%
0.4%
0.3%
0.3% :
0.3%
0.2%
0.2%
0.2%
0.2%
0.1%
0.1%
0.1%
0.1%
0.1%
0.1%
0.1%
+
+
+
+
+
+
7.6%
4.3%
1.8%
0.7%
0.7%
0.1%
+
+
+
7.6%
5.4%
1.6%
0.2%
0.2%
0.1%
0.1%
+ :
1-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 1-11: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg C02 Eq. and Percent of
Total in 2000) (Continued)
Sector/Source
1990
1995
1996
1997
1998
1999
2000 Percent3
a
»:
i.
j,_
iS=
b -
Commercial
C02 from Fossil Fuel Combustion
Landfills
Waste Combustion9
Substitution of ODSd
Stationary Combustion0
U.S. Territories
C02 from Fossil Fuel Combustion
Total
303.5
217.3
79.0
5.3
0.9
1.0
28.1
28.1
6,130.7
,: Sinks (1,097.7)
i- •
r
wests
Agricultural Soils
Urban Trees
Landfilled Yard Trimmings
Net Emissions (Sources and Sinks)
(982.7)
(37.3)
(58.7)
(19.1)
5,033.0
pMfaqg,^^
*—
r- ^
fc
*" i
•swfefcu.*
313.0
223.9
80.1
7.0
0.9
1.1
35.3
35.3
6,481.8
£ (1,110.0)
IT ~'
jj_
tr J!
Si*" J
(979.0)
(60.2)
(58.7)
(12.2)
5,371.8
320.8
232.8
78.3
7.3
1.3
1.1
27.0
27.0
6,669.8
(1,108.1)
(979.0)
(60.2)
(58.7)
(10.2)
5,561.7
320.9
233.7
76.4
8.0
1.8
1.1
29.1
29.1
6,748.1
(887.5)
(759.0)
(60.4)
(58.7)
(9.5)
5,860.5
302.9
217.5
74.4
7.6
2.4
1.0
34.4
34.4
6,756.2
(885.9)
(751.7)
(67.2)
(58.7)
(8.3)
5,870.3
307.1
219.8
75.1
8.2
2.9
1.1
35.8
35.8
6,829.5
(896.4)
(762.7)
(67.7)
(58.7)
(7.3)
5,933.1
327.6
239.3
75.3
8.4
3.5
1.1
38.0
38.0
7,001.2
(902.5)
(770.0)
(67.4)
(58.7)
(6.4)
6,098.7
4.7%
3.4%
1.1%
0.1%
_j_
0.5%
0.5%
100%
100%
85%
7%
7%
1%
-
Note: Includes all emissions of C02, CH4, N20, HFCs
ODS (Ozone Depleting Substances)
+ Does not exceed 0.05 Tg C02 Eq. or 0.05%.
[ - Not applicable.
aPercents for year 2000.
; b SF6 emitted.
V Includes both CH4 and N20.
' d May include a mixture of HFCs, PFCs, and SF6.
'• 6HFC-23 emitted.
'Includes both C02 and PFCs.
; 9 Includes both C02 and N20.
PFCs, and SF6. Totals may not sum due to independent rounding.
demand for travel and the stagnantion of fuel efficiency across
the U.S. vehicle fleet. Since the 1970s, the number of highway
vehicles registered in the United States has increased faster
than the overall population, according to the Federal Highway
Administration (FHWA). Likewise, the number of miles driven
up—28 percent from 1990 to 2000—and gallons of gasoline
consumed each year in the United States have increased steadily
since the 1980s, according to the FHWA and Energy
Information Administration, respectively. These increases in
motor vehicle usage are the result of a confluence of factors
including population growth, economic growth, urban sprawl,
low fuel prices, and increasing popularity of sport utility
vehicles and other light-duty trucks that tend to have lower
fuel efficiency. A similar set of social and economic trends has
led to a significant increase in air travel and freight
transportation—by both air androad modes—during the 1990s.
Almost all of the energy consumed for transportation
was supplied by petroleum-based products, with nearly two-
thirds being related to gasoline consumption in automobiles
and other highway vehicles. Other fuel uses, especially
diesel fuel for freight trucks and jet fuel for aircraft,
accounted for the remainder. These emissions were primarily
CO2 from fuel combustion, which increased by 22 percent
from 1990 to 2000. However, because of larger increases
in HFC emissions during this period, overall emissions from
transportation activities actually increased by 23 percent.
Table 1-14 provides a detailed summary of greenhouse gas
emissions from transportation-related activities.
Introduction 1-19
-------
Table 1-12: U.S Greenhouse Gas Emissions by "Economic Sector" and Gas with Electricity-Related Emissions
Distributed (Tg C02 Eq.) and Percent of Total in 2000
Sector/Gas
Industry
Direct Emissions
C02
CH,
*•" '4
N20
HFCs, PFCs, and SF6
Electricity-Related
CO,
c
CH4
N,O
SF6
Transportation
Direct Emissions
C02
Ik
CH,
**« -q
N,0
c
HFCsb
Electricity-Related
C02
CH4
N20
SF6
Residential
Direct Emissions
C02
CH4
N.,0
HFCs
Electricity-Related
CO,
•W f £
CH4
SF6
Commercial
Direct Emissions
CO,
c
CH4
N,0
HFCs
Electricity-Related
CO,
c,
CH4
N,0
'V
SF6
Agriculture
Direct Emissions
C02
CH4
N20
Electricity-Related
C02
CH4
**
SF6
U.S. Territories
C02
Total
1990
2,029.7
1,393.9
1,030.9
265.0
36.6
61.4
635.8
622.7
0.2
2.5
10.5
1,530.5
1,527.7
1,471.8
4.9
50.9
2.8
2.7
+
+
_l-
1,131.2
484.6
340.0
136.4
8.3
+
646.6
633.2
0.2
2.6
10.6
890.7
303.5
222.5
79.7
0.4
0.9
587.1
575.0
0.2
2.3
9.7
520.5
494.7
46.3
164.9
283.5
25.8
25.3
+
0.1
0.4
28.1
28.1
6,130.7
IfT— —
I"
|
\
f
L. ,
§..-
f-
f_
J
L_. .
i- „
fs- •••
L . .
F"
IL
j£
|g-4g-
i -
i .
I
e-
f,
B"»
F
I
r
§
l
I
I
F
i
I
1
i
"
1
i
" :
ft™ -
'•
f\'.
I
•
w~
,
•
^
-_•
.4
"B
;-
f
+
*
«
"H
1
i
*\
-i
'slim'
-::
1
IS
3
. |
i
*
'&:
i
'«t
*
f
"
,
i
t.
I
k
!
I
*
I
*
*
I
. s!
a,
1
J'"
„
1995
2,071.6
1,400.9
1,041.5
256.1
41.9
61.4
670.7
659.1
0.2
2.6
8.8
1,655.1
1,652.4
1,579.4
4.8
60.4
7.9
2.6
2.6
+
+
+
1,213.1
522.7
372.8
139.1
9.0
1.9
690.5
678.5
0.2
2.7
9.0
944.9
313.0
230.8
80.9
0.4
0.9
631.9
621.0
0.2
2.5
8.3
561.8
533.3
56.9
176.2
300.2
28.5
28.0
+
0.1
0.4
35.3
35.3
6,481.8
1996
2,136.2
1,447.6
1,083.4
251.6
42.7
70.0
688.6
676.9
0.2
2.8
8.8
1,697.9
1,695.2
1,618.7
4.7
60.1
11.8
2.7
2.6
+
+
+
1,270.1
549.0
401.4
136.4
9.1
2.1
721.1
708.9
0.2
2.9
9.2
974.3
320.8
240.1
79.0
0.4
1.3
653.5
642.4
0.2
2.6
8.3
564.3
533.3
52.0
171.5
309.8
31.0
30.5
+
0.1
0.4
27.0
27.0
6,669.8
1997
2,151.5
1,442.7
1,085.4
247.5
37.0
72.7
708.8
697.8
0.2
2.8
8.0
1,711.2
1,708.5
1,628.8
4.6
59.7
15.4
2.7
2.7
+
+
+
1,265.6
531.1
386.8
132.7
9.0
2.5
734.5
723.1
0.2
2.9
8.3
1,022.4
320.9
241.6
77.1
0.4
1.8
701.5
690.6
0.2
2.8
7.9
568.2
544.2
58.3
170.9
315.0
24.1
23.7
+
0.1
0.3
29.1
29.1
6,748.1
1998
2,104.0
1,385.9
1,023.6
245.9
32.9
83.6
718.1
708.7
0.2
2.8
6.4
1,740.2
1,737.4
1,655.0
4.5
59.1
18.9
2.7
2.7
+
+
+
1,266.3
494.3
353.1
129.4
9.1
2.7
772.0
761.8
0.2
3.0
6.9
1,040.0
302.9
225.0
75.1
0.4
2.4
737.0
727.3
0.2
2.9
6.6
571.4
545.1
57.6
171.6
316.0
26.2
25.9
+
0.1
0.2
34.4
34.4
6,756.2
1999
2,059.7
1,341.1
994.7
237.5
32.3
76.7
718.6
710.7
0.2
2.8
4.9
1,816.0
1,813.3
1,728.2
4.4
58.7
22.0
2.7
2.7
+
+
+
1,293.5
516.0
372.7
131.0
9.4
2.9
777.5
768.9
0.2
3.1
5.3
1,057.5
307.1
227.9
75.9
0.4
2.9
750.4
742.1
0.2
3.0
5.1
567.0
544.9
59.9
171.1
313.9
22.0
21.8
+
0.1
0.2
35.8
35.8
6,829.5
2000
2,054.7
1,314.6
974.7
232.3
32.2
75.4
740.0
732.4
0.2
2.9
4.5
1,879.7
1,877.0
1,789.5
4.4
58.3
24.8
2.8
2.7
+
+
+
1,357.4
531.6
387.4
131.5
9.5
3.2
825.7
817.3
0.2
3.2
5.0
1,113.8
327.6
247.6
76.1
0.4
3.5
786.2
778.1
0.2
3.1
4.8
557.7
535.5
50.4
169.6
315.5
22.2
22.0
+
0.1
0.1
38.0
38.0
7,001.2
Percent3
29.3%
18.8%
13.9%
3.3%
0.5%
1.1%
10.6%
10.5%
+
+
0.1%
26.8%
26.8%
25.6%
0.1%
0.8%
0.4%
+
+
+
+
+
19.4%
7.6%
5.5%
1.9%
0.1%
+
11.8%
11.7%
+
+
0.1%
15.9%
4.7%
3.5%
1.1%
+
+
11.2%
11.1%
+
+
0.1%
8.0%
7.6%
0.7%
2.4%
4.5%
0.3%
0.3%
+
+
+
0.5%
0.5%
-
Note: Emissions from electricity generation are allocated based on aggregate electricity consumption in each end-use sector.
Totals may not sum due to independent rounding.
+ Does not exceed 0.05 Tg G02 Eq. orO.05 percent.
•Percents for year 2000.
b Includes primarily HFC-134a.
1-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 1-13: Electricity Generation-Related Greenhouse Gas Emissions (Tg C02 Eq.)
Gas/Fuel Type or Source
C02
Coal
Natural Gas
Petroleum
Geothermal
CH4
Stationary Sources*
N20
Stationary Sources*
SF6
.Electrical Transmission and Distribution
Total
1990
1,858.9
1,541.5
213.8
103.4
0.2
0.5
0.5
7.6
7.6
31.2
31.2
1,898.2
£L 1995
.
E^ 1 .989.3
E| 1,647.9
ipf 276.8
64.5
BBS °-1
0.5 •
0.5
E2 8-°
8.0 .
pr 26.5
1£:^'J OC C
£°.v
IS 2,024.3
1996
2,061.2
1,739.1
252.5
69.5
0.1
0.5
0.5
8.4
8.4
26.8
26.8
2,096.9
1997
2,137.9
1,789.0
270.4
78.4
0.1
0.6
0.6
8.7
8.7
24.5
24.5
2,171.6
1998
2,226.4
1,817.0
302.9
106.5
0.1
0.6
0.6
8.9
8.9
20.1
20.1
2,256.1
1999
2,246.2
1,828.0
310.4
107.7
+
0.6
0.6
8.9
8.9
15.5
15.5
2,271.2
2000
2,352.5
1,915.4
341.9
95.2
+
0.6
0.6
9.3
9.3
14.4
14.4
2,376.9
; Note: Totals may not sum due to independent rounding.
^ * Includes only stationary source emissions related to the generation of electricity.
f-+ Does not exceed 0.05 Tg C02 Eq.
Methodology and Data Sources
Emissions of greenhouse gases from various source and
sink categories have been estimated using methodologies
that are consistent with the Revised 1996IPCC Guidelines
for National Greenhouse Gas Inventories (IPCC/UNEP/
OECD/IEA1997). To the extent possible, the present U.S.
Inventory relies on published activity and emission factor
data. Depending on the emission source category, activity
data can include fuel consumption or deliveries, vehicle-
miles traveled, raw material processed, etc.; emission factors
are factors that relate quantities of emissions to an activity.
For some sources, IPCC default methodologies and emission
factors have been employed. However, for most emission
sources, the IPCC default methodologies were expanded
and more comprehensive methods were applied.
Inventory emission estimates from energy consumption
and production activities are based primarily on the latest
official fuel consumption data from the Energy Information
Administration (EIA) of the U.S. Department of Energy and
augmented with additional data where available. Emission
estimates for NOx, CO, and NMVOCs were taken directly,
except where noted, from unpublished EPA data that provide
the latest estimates of regional and national emissions of
local air pollutants (EPA 2001). Emissions of these
pollutants are estimated by the EPA based on statistical
information about each source category, emission factors,
and control efficiencies. While the EPA's estimation
methodologies for local air pollutants are conceptually
Figure 1-7
2,500
2,000
S 1,500 •
o
en 1,000 -
500 -
0 -
Industrial 29%
Residential 19%
Commercial 16%
Agriculture 8%
T?
similar to the IPCC recommended methodologies, the large
number of sources EPA used in developing its local air
pollutant estimates makes it difficult to reproduce the
methodologies from EPA (2001) in this inventory document.
In these instances, the references containing detailed
documentation of the methods used are identified for the
interested reader. For agricultural sources, the EPA local
air pollutant emission estimates were supplemented using
activity data from other agencies. Complete documentation
of the methodologies and data sources used is provided in
conjunction with the discussion of each source and in the
various annexes.
Introduction 1-21
-------
Table 1-14: Transportation-Related Greenhouse Gas Emissions (Tg C02 Eq.)
Gas/Vehicle Type
1990
1995
1996
1997
1998
1999
2000
C02
Passenger Cars
Light-Duty Trucks
Other Trucks
Buses
Aircraft3
Boats and Vessels
Locomotives
Otherb
International Bunker Fuels0
CH4
Passenger Cars
Light-Duty Trucks
Other Trucks and Buses
Aircraft
Boats
Locomotives
Other"
International Bunker Fuels0
N20
Passenger Cars
Light-Duty Trucks
Other Trucks and Buses
Aircraft
Boats
Locomotives
Other"
International Bunker Fuels0
MFCs
Mobile Air Conditioners6
Refrigerated Transport
Total
1,474.5
619.9
283.1
206.0
10.7
176.9
59.4
28.5
90.1
113.9
4.9
2.4
1.6
0.4
0.2
0.1
0.1
0.2
0.2
50.9
31.1
14.4
2.5
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1,582.0
641.9
325.3
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13.5
171.4
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4.8
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1.8
0.4
0.1
0.1
0.1
0.2
0.1
60.4
33.1
21.0
3.3
1.7
0.5
0.3
0.6
0.9
7.9
6.7
1.2
1,655.1
1,621.3
654.1
333.5
248.1
11.3
180.2
63.8
33.6
96.8
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4.7
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1.8
0.4
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0.1
0.1
0.2
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32.7
20.9
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0.4
0.3
0.6
0.9
11.8
9.8
1.9
1,697.9
1,631.5
660.2
337.3
257.0
12.0
178.9
50.2
34.5
101.5
109.9
4.6
2.0
1.7
0.4
0.2
0.1
0.1
0.2
0.1
59.7
32.2
21.0
3.5
1.7
0.3
0.2
0.6
1.0
15.4
12.9
2.5
1,711.2
1,657.7
673.5
356.4
257.9
12.4
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47.8
33.8
93.0
112.9
4.5
1.9
1.6
0.4
0.1
0.1
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0.2
0.1
59.1
32.0
20.6
3.6
1.8
0.3
0.2
0.6
1.0
18.9
15.7
3.2
1,740.2
1,731.0
687.2
366.5
282.4
13.1
186.7
63.0
35.3
96.7
105.3
4.4
1.9
1.6
0.4
0.2
0.1
+
0.2
0.1
58.7
31.2
20.6
3.8
1.8
0.4
0.2
0.6
0.9
22.0
18.2
3.8
1,816.0
1,792.2
691.7
369.4
294.3
13.7
196.5
89.9
36.9
99.9
100.2
4.4
1.9
1.5
0.4
0.2
0.1
0.1
0.2
0.1
58.3
30.7
20.4
3.8
1.9
0.6
0.2
0.6
0.9
24.8
20.4
4.4
1,879.7
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
"Aircraft emissions consist of emissions from all jet fuel (less bunker fuels) and aviation gas consumption.
b "Other" C02 emissions include motorcycles, construction equipment, agricultural machinery, pipelines, and lubricants.
c Emissions from International Bunker Fuels include emissions from both civilian and military activities, but are not included in totals.
" "Other" CH4 and N20 emissions include motorcycles, construction equipment, agricultural machinery, industrial equipment, and snowmobiles.
• Includes primarily HFC-134a.
Emissions from fossil fuels combusted in civilian and
military ships and aircraft engaged in the international
transport of passengers and cargo are not included in U.S.
totals, but are reported separately as international bunkers
in accordance with IPCC reporting guidelines (TPCC/UNEP/
OECD/IEA 1997). Carbon dioxide emissions from fuel
combusted within U.S. territories, however, are included in
U.S. totals.
In order to aggregate emissions by economic sector,
source category emission estimates were generated
according to the methodologies outlined hi the appropriate
sections of this Inventory. Those emissions, then, were
simply reallocated into economic sectors. In most cases,
the IPCC subcategories distinctly fit into an apparent
economic sector category. Several exceptions exist, and the
methodologies used to disaggregate these subcategories are
described below:
• Agricultural CO2 Emissions from Fossil Fuel
Combustion, and non-CO2 emissions from Stationary
and Mobile Combustion. Emissions from on-farm
energy use were accounted for in the Energy chapter
as part of the industrial and transportation end-use
1-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Box 1-3: IPCC Good Practice Guidance
|:: In response to a request by Parties to the United Nations Framework Convention on Climate Change (UNFCCC), the Intergovernmen- *
rial Panel on Climate Change (IPCC) finalized a set of good practice guidance in May 2000 on uncertainty and good practices in inventory
t management. The report, entitled Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (Good ]
| Practice), was developed with extensive participation of experts from the United States as well as many other countries.25 It focuses on
jb providing direction to countries to produce emission estimates that are as accurate, with the least possible uncertainty. In addition, Good
^Practice was designed as a tool to compliment the methodologies suggested in the Revised 1996 IPCC Guidelines for National Green- "
I house Gas Inventories (IPCC Guidelines). \n order to obtain these goals, Good Practice establishes a set of guidelines for ensuring the _;
t following standards are met: :
&: . ' --.-_-_ - - - ,- - •- . = •-- .-..,--- --.. - - - - ,E
jr • The most appropriate estimation method is used, within the context of the IPCC Guidelines
ir- , --- -:- = - _ 7— -- - . :,= ;- - .::„;? -1,: - :-=--:- :r ,--:-* ,- -. - f : , - ,- . i
^ • Quality control and quality assurance measures are adhered to
* • Proper assessment and documentation of data and information is carried out '•
N - ' • - -- - — -™ -- :.._.,,_,,..,-. -—-.. -__--,_, ..,„„ . ,, , ___ . ... ^
|__ • Uncertainties are quantified andI tracked for eachsource category^as well as the inventory in its entirety
f- By providing such direction, the IPCC hopes to help countries provide inventories that are transparent, documented, and comparable,
I and that have been assessed for uncertainties, checked for quality control and quality assurance, and used resources efficiently. :
. . - - ' '
sectors. To calculate agricultural emissions related to
fossil fuel combustion, energy consumption estimates
were obtained from economic survey data from the U.S.
Department of Agriculture (Duffield 2002). To avoid
double counting, emission estimates of CO2 from fossil
fuel combustion and non-CO2 from stationary and
mobile sources were subtracted from the industrial
economic sector, although some of these fuels may have
been originally be accounted for under the
transportation end-use sector.
Landfills and Waste Combustion. Methane emissions
from landfills, as well as CO2 and N2O emissions from
waste combustion were allocated to the residential (56
percent), commercial (37 percent), and industrial (7
percent) economic sectors based on waste generation
surveys (EPA 2000).
Substitution of Ozone Depleting Substances. All
greenhouse gas emissions resulting from the
substitution of ozone depleting substances were placed
in the industrial economic sector, with the exception
of emissions from domestic, commercial, mobile and
transport refrigeration/air-conditioning systems were
placed in the residential, commercial, and transportation
sectors, respectively. Emissions from non-MDI aerosols
were attributed to the residential economic sector.
The IPCC requires countries to complete a "top-down"
Reference Approach for estimating CO2 emissions from
fossil fuel combustion in addition to their "bottom-up"
sectoral methodology. This estimation method uses
alternative methodologies and different data sources than
those contained in that section of the Energy chapter. Section
1.3 of the Revised 1996 IPCC Guidelines for National
Greenhouse Gas Inventories: Reporting Instructions states,
"If a detailed, Sectoral Approach for energy has been used
for the estimation of CO2 from fuel combustion you are
still asked to complete...the Reference Approach...for
verification purposes" (IPCC/UNEP/OECD/TEA 1997).
This reference method estimates fossil fuel consumption
by adjusting national aggregate fuel production data for
imports, exports, and stock changes rather than relying on
end-user consumption surveys (see Annex U). The reference
approach assumes that once carbon-based fuels are brought
into a national economy they are either saved in some way
(e.g., stored in products, kept in fuel stocks, or left
unoxidized in ash) or combusted, and therefore the carbon
in them is oxidized and released into the atmosphere.
Accounting for actual consumption of fuels at the sectoral
or sub-national level is not required.
' See
Introduction 1-23
-------
Uncertainty in and Limitations
of Emission Estimates
While the current U.S. emissions inventory provides a
solid foundation for the development of a more detailed
and comprehensive national inventory, it has several
strengths and weaknesses.
First, this inventory by itself does not provide a
complete picture of past or future emissions in the United
States; it only provides an inventory of U.S. emissions
for the years 1990 through 2000. However, the United
States believes that common and consistent inventories
taken over a period of time can and will contribute to
understanding future emission trends. The United States
produced its first comprehensive inventory of greenhouse
gas emissions and sinks in 1993, and intends to update it
annually, in conjunction with its commitments under the
UNFCCC. The methodologies used to estimate emissions
will also be updated regularly as methods and information
improve and as further guidance is received from the IPCC
and UNFCCC.
Secondly, there are uncertainties associated with the
emission estimates. Some of the current estimates, such as
those for CO2 emissions from energy-related activities and
cement processing, are considered to be fairly accurate. For
some other categories of emissions, however, a lack of data
or an incomplete understanding of how emissions are
generated limits the scope or accuracy of the estimates
presented. Despite these uncertainties, the Revised 1996
IPCC Guidelines for National Greenhouse Gas Inventories
(IPCC/UNEP/OECD/IEA 1997) require that countries
provide single point estimates for each gas and emission or
removal source category. Within the discussion of each
emission source, specific factors affecting the accuracy of
the estimates are discussed.
Finally, while the IPCC methodologies provided in the
Revised 1996 IPCC Guidelines represent baseline
methodologies for a variety of source categories, many of
these methodologies continue to be improved and refined
as new research and data becomes available. The current
U.S. inventory uses the IPCC methodologies when
applicable, and supplements them with other available
methodologies and data where possible. The United States
realizes that additional efforts are still needed to improve
methodologies and data collection procedures. Specific
areas requiring further research include:
• Incorporating excluded emission sources. Quantitative
estimates of some of the sources and sinks of
greenhouse gas emissions are not available at this time.
In particular, emissions from some land-use activities
and industrial processes are not included in the
inventory either because data are incomplete or because
methodologies do not exist for estimating emissions
from these source categories. See Annex V for a
discussion of the sources of greenhouse gas emissions
and sinks excluded from this report.
Table 1-15: IPCC Sector Descriptions
Chapter/IPCC Sector Activities Included
Energy
Industrial Processes
Solvent Use
Agriculture
Land-Use Change and Forestry
Waste
Emissions of all greenhouse gases resulting from stationary and mobile energy
activities including fuel combustion and fugitive fuel emissions.
By-product or fugitive emissions of greenhouse gases from industrial processes not
directly related to energy activities such as fossil fuel combustion.
Emissions, of primarily non-methane volatile organic compounds (NMVOCs), resulting
from the use of solvents.
Anthropogenic emissions from agricultural activities except fuel combustion and
sewage emissions, which are addressed under Energy and Waste, respectively.
Emissions and removals of carbon dioxide from forest management, other land-use
activities, and land-use change.
Emissions from waste management activities.
Source: (IPCC/UNEP/OECD/IEA 1997)
1-24 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
• Improving the accuracy of emission factors. Further
research is needed in some cases to improve the
accuracy of emission factors used to calculate emissions
from a variety of sources. For example, the accuracy
of current emission factors applied to methane and
nitrous oxide emissions from stationary and mobile
combustion is highly uncertain.
• Collecting detailed activity data. Although
methodologies exist for estimating emissions for some
sources, problems arise in obtaining activity data at a
level of detail in which aggregate emission factors can
be applied. For example, the ability to estimate
emissions of SF6 from electrical transmission and
distribution is limited due to a lack of activity data
regarding national SF6 consumption or average
equipment leak rates.
• Applying Global Warming Potentials. GWP values
have several limitations including that they are not
applicable to unevenly distributed gases and aerosols
Table 1-16: List of Annexes
such as tropospheric ozone and its precursors. They
are also intended to reflect global averages and,
therefore, do not account for regional effects. Overall,
the mam uncertainties in developing GWP values are
the estimation of atmospheric lifetimes, assessing
indirect effects, choosing the appropriate integration
time horizon, and assessing instantaneous radiative
forcing effects which are dependent upon existing
atmospheric concentrations. According to the IPCC,
GWPs typically have an uncertainty of 35 percent
(IPCC 1996).
Emissions calculated for the U.S. inventory reflect
current best estimates; in some cases, however, estimates
are based on approximate methodologies, assumptions, and
incomplete data. As new information becomes available in
the future, the United States will continue to improve and
revise its emission estimates.
> ANNEX A Methodology for Estimating Emissions of C02 from Fossil Fuel Combustion
L ANNEX B Methodology for Estimating Carbon Stored in Products from Non-Energy Uses of Fossil Fuels
f ANNEX C Methodology for Estimating Emissions of CH4, N26, and Ambient Air Pollutants from Stationary Combustion
r ANNEXD Methodology for Estimating Emissions of CH4, N20, andAmbient Air Pollutants from Mobile Combustion
I ANNEX E Methodology for Estimating CH4 Emissions from Coal Mining
r= ANNEX F Methodology for Estimating CH4 Emissions from Natural Gas Systems
|- ANNEX 6 Methodology for Estimating CH4 Emissions from Petroleum Systems
t; ANNEX H Methodology for Estimating C02 Emissions from Municipal Solid Waste Combustion
? ANNEX I Methodology for Estimating Emissions from International Bunker Fuels used by the U.S. Military
r ANNEX J Methodology for Estimating HFC, PFC, and SF6 Emissions from Substitution of Ozone Depleting Substances
'r: ANNEX K Methodology for Estimating CH4 Emissions from Enteric Fermentation
"r ANNEX L Methodology for Estimating CH4 and N20 Emissions from Manure Management
i ANNEX M Methodology for Estimating N20 Emissions from Agricultural Soil Management
? ANNEX N Methodology for Estimating C02 Emissions and Sinks from Forest Carbon Stocks
F- ANNEX 0 Methodology for Estimating CH4 Emissions from Landfills
irANNEX P Key Source Analysis
ff ANNEX Q Global Warming Potential Values
r ANNEX R Ozone Depleting Substance Emissions
; ANNEXS Sulfur Dioxide Emissions _.
r ANNEX T Complete List of Source Categories
r ANNEX U IPCC Reference Approach for Estimating C02 Emissions from Fossil Fuel Combustion
"ANNEXV Sources of Greenhouse Gas Emissions Excluded
- ANNEX W Constants, Units, and Conversions
[ ANNEX X Abbreviations
t ANNEX Y Chemical Formulas
I ANNEX Z Glossary
Introduction 1-25
-------
Organization of Report
In accordance with the IPCC guidelines for reporting
contained in the Revised 1996 IPCC Guidelines for National
Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA
1997), this U.S. inventory of greenhouse gas emissions and
sinks is segregated into six sector-specific chapters, listed
in Table 1-15.
Within each chapter, emissions are identified by the
anthropogenic activity that is the source or sink of the
greenhouse gas emissions being estimated (e.g., coal
mining). Overall, the following organizational structure is
consistently applied throughout this report:
Chapter/IPCC Sector: overview of
emission trends for each IPCC defined sector
Source Category? Description of source pathway
and emission trends.
— Methodology! Description of analytical
methods employed to produce emission estimates
— Data Sources: Identification of data
references, primarily for activity data and emission
factors
— Uncertainty. Discussion of relevant issues
related to the uncertainty hi the emission estimates
presented
Special attention is given to carbon dioxide from fossil
fuel combustion relative to other sources because of its share
of emissions relative to other sources and its dominant
influence on emission trends. For example, each energy
consuming end-use sector (i.e., residential, commercial,
industrial, and transportation), as well as the electricity
generation sector, are treated individually. Additional
information for certain source categories and other topics
is also provided in several Annexes listed in Table 1-16.
1-26 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
2. Energy
:nergy-related activities were the primary sources of U.S. anthropogenic greenhouse gas emissions, accounting
for 85 percent of total emissions on a carbon equivalent basis in 2000. This included 97,34, and 17 percent of the
nation's carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) emissions, respectively. Energy-related CO2 emissions
alone constituted 81 percent of national emissions from all sources on a carbon equivalent basis, while the non-CO2
emissions from energy-related activities represented a much smaller portion of total national emissions (4 percent collectively).
Emissions fromfossil fuel combustion comprise the vast majority of energy-related emissions, with CO2 being the primary gas emitted
(seeFigure 2-1). Globally, approximately 23,300 Tg of CO2 were added to the atmosphere through the combustion of fossil fuels at the end
of the 1990s, of which the United States accounted for about 24 percent (see Figure 2-2).1 Due to the relative importance of fossil fuel
combustion-related Commissions, they are considered separately from other emissions. Fossil fuel combustion also emits CH4 and N2O,
as well as ambient air pollutants such as nitrogen oxides (NOx), carbon monoxide (CO), and non-methane volatile organic compounds
(NMVOCs). Mobile fossil fuel combustion was the second largest source of N2O emissions in the United States, and overall energy-
related activities were collectively the largest source of these ambient air pollutant emissions.
Energy-related activities other than fuel combustion, such as the production, transmission, storage, and distribution of fossil fuels,
also emit greenhouse gases. These emissions consist primarily of CH4 from natural gas systems, petroleum systems, and coal mining.
Smaller quantities of CO2, CO, NMVOCs, andNOx are also emitted.
The combustion of biomass and biomass-based fuels also
emits greenhouse gases. Carbon dioxide emissions from these
activities, however, are not included in national emissions totals
because biomass fuels are of biogenic origin. It is assumed that the
carbon released when biomass is consumed is recycled as U.S.
forests and crops regenerate, causing no net addition of CO2 to the
atmosphere. The net impacts of land-use and forestry activities on
the carbon cycle are accounted for in the Land-Use Change and
Forestry chapter. Emissions of other greenhouse gases from the
combustion of biomass and biomass based fuels are included in
Figure 2-1
MflP Energy Chapter GHG Sour&tfT|
K-^Ili^JM^ii^^^^
national totals under stationary and mobile combustion.
Table2-l summarizes emissions forthe Energy chapterin units
of teragrams of carbon dioxide equivalents (Tg CO2 Eq.), while
unweighted gas emissions in gigagrams (Gg) are provided inTable
2-2. Overall, emissions due to energy-related activities were 5,962.6
TgCO2Eq.in 2000, an increase of 16percent since 1990.
Fossil Fuel Combustion
Natural Gas Systems
Mobile Sources
Coal Mining
Stationary Sources •
Waste Combustion •
Petroleum Systems •
Natural Gas Flaring I
5,623
Energy as a Portion
of All Emissions
40 80 120
Tg C02 Eq.
140
1 Global CO2 emissions from fossil fuel combustion were taken from Marland et al. (2001) .
Energy 2-1
-------
Table 2-1: Emissions from Energy (Tg C02 Eq.)
Gas/Source
C02
Fossil Fuel Combustion
Indirect C02 from CH4 Oxidation
Waste Combustion
Natural Gas Raring
Biomass-Wood*
International Bunker Fuels*
Biomass-Ethanol*
Carbon Stored in Products*
CH4
Natural Gas Systems
Coal Mining
Petroleum Systems
Stationary Sources
Mobile Sources
International Bunker Fuels*
N20
Mobile Sources
Stationary Sources
Waste Combustion
International Bunker Fuels*
Total
+ Does not exceed 0.05 Tg G02 Eq.
* These values are presented for informational
1990
4,830.3
4,779.8
30.9
14.1
5.5
149.6
113.9
4.4
221.0
247.6
121.2
87.1
26.4
7.9
4.9
0.2
64.0
50.9
12.8
0.3
1.0
5,141.9
purposes only
! '!
S 'VI '.=;{
c
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and are not
1995
5,141.8
5,085.0
29.5
18.6
8.7
163.3
101.0
8.1
251.1
236.4
125.7
73.5
24.2
8.2
4.8
0.1
74.2
60.4
13.5
0.3
0.9
5,452.4
included
1996
5,323.3
5,266.6
28.9
19.6
8.2
166.6
102.3
5.8
258.2
232.1
126.6
68.4
24.0
8.4
4.7
0.1
74.5
60.1
14.1
0.3
0.9
5,629.9
or are already
1997
5,396.8
5,339.6
28.4
21.3
7.6
159.3
109.9
7.4
269.8
226.9
122.7
68.1
24.0
7.5
4.6
0.1
74.2
59.7
14.2
0.3
1.0
5,697.9
accounted
1998
5,410.8
5,356.2
28.2
20.3
6.3
159.6
112.9
8.1
276.7
225.0
122.2
67.9
23.4
7.0
4.5
0.1
73.7
59.1
14.3
0.2
1.0
5,709.5
for in totals.
1999
5,504.1
5,448.6
27.0
21.8
6.7
173.9
105.3
8.5
291.6
216.3
118.6
63.7
22.3
7.3
4.4
0.1
73.5
58.7
14.6
0.2
0.9
5,793.9
2000
5,678.1
5,623.3
26.3
22.5
6.1
174.8
100.2
9.7
283.2
211.1
116.4
61.0
21.9
7.5
4.4
0.1
73.4
58.3
14.9
0.2
0.9
5,962.6
Note: Totals may not sum due to independent rounding.
Table 2-2: Emissions from Energy (Gg)
Gas/Source
C02
Fossil Fuel Combustion
1990
4,830,350
4,779,847
*r
""f
1
Indirect C02 from CH4 Oxidation 30,899 i I
Waste Combustion
Natural Gas Raring
Biomass-Wood*
International Bunker Fuels*
Biomass-Ethanol*
Carbon Stored in Products*
CH4
Natural Gas Systems
Coal Mining
Petroleum Systems
Stationary Sources
Mobile Sources
International Bunker Fuels*
N20
Mobile Combustion
Stationary Combustion
Waste Combustion
International Bunker Fuels*
+ Does not exceed 0.05 Tg
14,091
5,514
149,609
113,863
4,380
220,959
11,789
5,772
4,149
1,258
376
233
8
207
164
41
1
3
., _
i-
__
E'T
T
6:
P.
f:
f
p...
;
?"'"'
I.;
jii
JP.
1
T
*
:;-|
'*"!
; ,;§
•.'"-I
L
a
1
; ,,5
^i
* These values are presented for informational purposes only and
Note: Totals may not sum due to
independent rounding.
1995
5,141,838 5
5,085,044 5
29,458
18,608
8,729
163,286
101,037
8,099
251,110
11,259
5,984
3,502
1,154
392
228
6
239
195
43
1
3
are not included
1996
,323,312
,266,619
28,891
19,569
8,233
166,617
102,272
5,809
258,238
11,052
6,030
3,255
1,145
400
222
6
240
194
45
1
3
1997
5,396,825
5,339,562
28,354
21,344
7,565
159,286
109,885
7,356
269,787
10,807
5,845
3,244
1,144
356
217
7
239
192
46
1
3
or are already accounted
1998
5,410,844
5,356,161
28,183
20,251
6,250
159,610
112,913
8,128
276,659
10,715
5,820
3,235
1,114
334
212
7
238
191
46
1
3
for in totals.
1999
5,504,115
5,448,589
27,004
21,843
6,679
173,940
105,341
8,451
291,623
10,298
5,646
3,033
1,061
350
209
6
237
189
47
1
3
2000
5,678,099
5,623,268
26,302
22,470
6,059
174,770
100,228
9,667
283,180
10,050
5,541
2,903
1,041
357
208
6
237
188
48
1
3
2-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Carbon Dioxide Emissions
from Fossil Fuel Combustion
Carbon dioxide (CO2) emissions from fossil fuel
combustion grew by 3.2 percent from 1999 to 2000. This
above average growth rate was in part due to the strong
performance of the U.S. economy and continued population
growth. In 2000, CO2 emissions from fossil fuel combustion
were 5,623. 1 Tg CO2 Eq., or 17.6 percent above emissions in
1990 (see Table 2-3).2
Trends in CO2 emissions from fossil fuel combustion
are influenced by many long-term and short-term factors.
On a year-to-year basis, the overall demand for fossil fuels
in the United States and other countries generally fluctuates
in response to changes in general economic conditions,
energy prices, weather, and the availability of non-fossil
alternatives. For example, a year with increased consumption
of goods and services, low fuel prices, severe summer and
winter weather conditions, nuclear plant closures, and lower
precipitation feeding hydroelectric dams would be expected to
have proportionally greater fossil fuel consumption than a year
with poor economic performance, high fuel prices, mild
temperatures, and increased output from nuclear and
hydroelectric plants.
Longer-term changes in energy consumption patterns,
however, tend to be more a function of changes that affect the
scale of consumption (e.g., population, number of cars, and
size of houses), the efficiency with which energy is used in
equipment (e.g., cars, power plants, steel mills, and light bulbs),
and social planning and consumer behavior (e.g., walking,
bicycling, or telecommuting to work instead of driving).
Carbon dioxide emissions are also a function of the source
of energy and its carbon intensity. The amount of carbon in
fuels varies significantly by fuel type. For example, coal contains
Figure 2-2
Natural Gas liquids.
Liquefied Refinery Gqs,
& Other Liquids
185 _^^_
Petroleum
1.659
Fossil Fue
Stock Consumj
Non-Energy Changes u.S.
Use Imports 133 Territories
47 32
Note: Totals may not sum due to independent rounding.
The •Balancing Item" above accounts for the statistical imbalances
and unknowns in the reported data sets combined here.
NEU = Non-Energy Use
NG = Natural Gas
Fossil Fuel
Combustion
Residual
(Not Oxidized
Fraction)
50
2 An additional discussion of fossil fuel emission trends is presented in the Recent Trends in U.S. Greenhouse Gas Emissions section of the
Introduction chapter.
Energy 2-3
-------
Table 2-3: CO, Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg C02 Eq.)
Fuel/Sector
Coal
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Natural Gas
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Petroleum
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Geothermal*
Tola!
1990
1,692.6
5.8
8.7
135.9
NE
1,541.5
0.6
988.8
238.5
142.4
358.0
36.0
213.8
NO
2,098.2
87.7
66.1
377.8
1,435.8
103.4
27.4
0.2
4,779.8
,
1
r: '
p
§',-,
..I, . ,
!>::
P* '
1^-
i
fh
i
1
1
t
i
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I
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4"
B
f
4
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1
1
1
•
w
p
I
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i
i
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*
1995
1,792.7
5.0
7.6
131.2
NE
1,647.9
0.9
1,141.3
263.1
164.5
398.5
38.3
276.8
NO
2,150.9
94.2
51.8
365.1
1,541.0
64.5
34.3
0.1
5,084.9
1996
1,878.4
5.1
7.7
125.5
NE
1,739.1
0.9
1,162.4
284.6
171.6
414.8
38.9
252.5
NO
2,225.6
100.7
53.5
396.2
1,579.8
69.5
25.8
0.1
5,266.4
1997
1,930.5
5.5
8.2
126.9
NE
1,789.0
0.9
1,166.7
270.5
174.7
409.6
41.5
270.4
NO
2,242.0
98.9
50.8
398.7
1,587.3
78.4
27.9
0.1
5,339.4
1998
1,949.7
4.2
6.3
121.4
NE
1,817.0
0.9
1,125.8
246.5
163.6
378.0
34.9
302.9
NO
2,280.3
91.1
47.7
381.7
1,620.1
106.5
33.3
0.1
5,356.0
1999
1,956.9
4.4
6.6
117.0
NE
1,828.0
0.9
1,145.2
256.5
165.2
372.9
40.2
310.4
NO
2,346.3
99.6
48.0
368.2
1,688.0
107.7
34.8
+
5,448.4
2000
2,030.1
4.4
6.6
102.8
NE
1,915.4
0.9
1,204.8
268.3
180.8
371.3
41.9
341.9
0.6
2,388.2
102.2
51.8
355.1
1,747.6
95.2
36.3
+
5,623.1
NE (Not estimated)
NO (Not occurring)
+ Does not exceed 0.05 Tg C02 Eq.
* Although not technically a fossil fuel, geothermal energy-related C02 emissions are included for reporting purposes.
Note: Totals may not sum due to independent rounding.
the highest amount of carbon per unit of useful energy.
Petroleum has roughly 75 percent of the carbon per unit of
energy as coal, and natural gas has only about 55 percent.3
Therefore, producing heat or electricity using natural gas instead
of coal, for example, can reduce the CO2 emissions associated
with energy consumption, and using nuclear or renewable
energy sources (e.g., wind) can essentially eliminate emissions
(seeBox2-l).
In the United States, 85 percent of the energy consumed
in 2000 was produced through the combustion of fossil fuels
such as coal, natural gas, and petroleum (see Figure 2-3 and
Figure 2-4). The remaining portion was supplied by nuclear
electric power (8 percent) and by a variety of renewable energy
sources (7 percent), primarily hydroelectric power (EIA 2001).
Specifically, petroleum supplied the largest share of domestic
energy demands, accounting for an average of 38 percent of
total energy consumption from 1990 through 2000. Natural gas
and coal followed in order of importance, accounting for 28 and
26 percent of total consumption, respectively. Most petroleum
was consumed in the transportation end-use sector, while the
vast majority of coal was used in electricity generation, with
natural gas broadly consumed in all end-use sectors except
transportation (see Figure 2-5) (EIA 2001a).
Fossil fuels are generally combusted for the purpose of
producing energy for useful heat and work. During the
combustion process the carbon stored in the fuels is oxidized
and emitted as CO2 and smaller amounts of other gases,
including methane (CH4), carbon monoxide (CO), and non-
methane volatile organic compounds (NMVOCs).4 These
other carbon containing non-CO2 gases are emitted as a by-
product of incomplete fuel combustion, but are, for the most
part, eventually oxidized to CO2 in the atmosphere. Therefore,
3 Based on national aggregate carbon content of all coal, natural gas, and petroleum fuels combusted in the United States.
4 Sec the sections entitled Stationary Combustion and Mobile Combustion in this chapter for information on non-CO2 gas emissions from
fossil fuel combustion.
2-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Figure 2-3
Figure 2-4
6.9% Renewable
8.1% Nuclear
22.8% Coal
23.7%
Natural Gas
38.4%
Petroleum
Source: DOE/EIA-0384(2000), Annual Energy Review 2000,
Table 1.3, August 2001
120
=•100
GQ
1=0
_g
f 60
ID
o 40
O
I 20
c
ill
0 J
Total Energy
Renewable & Nuclear
Note: Expressed as gross calorific values.
Source: DOE/EIA-0384 (2000), Annual Energy Review
2000, Table 1.3, August 2001
Figure 2-5
. 2,000
"i, 1,500
O 1,000
500
0
Natural Gas • Petroleum m Coal
Relative Contribution
by Fuel Type
^sfe^7
.X
Note: Electricity Generation also includes emissions of less
than 0.01 Tg C02 Eq. from geothermal plants.
except for the soot an ash left behind during the combustion
process, all the carbon in fossil fuels used to produce energy
is eventually converted to atmospheric CO2.
For the purpose of international reporting, the IPCC
(IPCC/UNEP/OECD/IEA 1997) requires that particular
adjustments be made to national fuel consumption statistics.
Certain fossil fuels can be manufactured into plastics, asphalt,
lubricants, or other products. A portion of the carbon
consumed for these non-energy products can be stored (i.e.,
sequestered) indefinitely. To account for the fact that the
carbon in these fuels ends up in products instead of being
combusted (i.e., oxidized and released into the atmosphere),
the fraction of fossil fuel-based carbon in manufactured
products is subtracted from emission estimates. (See the
Carbon Stored in Products from Non-Energy Uses of Fossil
Fuels section in this chapter.) The fraction of this carbon
stored in products that is eventually combusted in waste
incinerators or combustion plants is accounted for in the
Waste Combustion section of this chapter.
The IPCC also requires that CO2 emissions from the
consumption of fossil fuels for aviation and marine
international transport activities (i.e., international bunker
fuels) be reported separately, and not included in national
emission totals. Estimates of carbon in products and
international bunker fuel emissions for the United States are
provided in Table 2-4 and Table 2-5.
Energy 2-5
-------
Box 2-1: Weather and Non-Fossil Energy Effects on C02 from Fossil Fuel Combustion Trends
After two unusually warm years in 1998 and 1999, weather conditions returned closer to normal in 2000. The colder winter conditions
caused increased demand for heating fuels, while a cooler summer reduced electricity demand. Overall, however, conditions were still
slightly warmer than usual. Heating degree days in the United States in 2000 were 3 percent below normal (see Figure 2-6) while cooling
degree days in 2000 were 4 percent above normal (see Figure 2-7).5
Although no new U.S. nuclear power plants have been constructed in many years, the utilization (i.e., capacity factors6) of existing
plants reached record levels in 2000, approaching 90 percent. This increase in utilization translated into an increase in electricity output by
nuclear plants of slightly more than 3 percent in 2000. This output by nuclear plants, however, was offset by reduced electricity output by
hydroelectric power plants, which declined by almost 12 percent. Electricity generated by nuclear plants provides approximately twice as
much of the energy consumed in the United States as hydroelectric plants. Aggregate nuclear and hydroelectric power plant capacity
factors since 1973 are shown in Figure 2-8.
Figure 2-6
Normal
(4,576 Heating Degree Days)
Note: 1998 and climatological normal data is highlighted. Statistical confidence interval for "normal" climatology period of 1961
through 1990.
Source: NOAA(2001a)
FIgurs 2-7
i§
||-
C o
-Q. -20
Normal
(1,193 Cooling Degree Days)
Note: 1998 and climatological normal data is highlighted. Statistical confidence interval for "normal" climatology period of 1961
through 1990.
Source: MOM (2001 b)
* Degree days are relative measurements of outdoor air temperature. Heating degree days are deviations of the mean daily temperature below
65° F, while cooling degree days are deviations of the mean daily temperature above 65° F. Excludes Alaska and Hawaii. Normals are based
on data from 1961 through 1990. The variation in these normals during this time period was ±10 percent and ±14 percent for heating and
cooling degree days, respectively (99 percent confidence interval).
6 The capacity factor is defined as the ratio of the electrical energy produced by a generating unit for a given period of time to the electrical
energy that could have been produced at continuous full-power operation during the same period (EIA 2001b).
2-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Box 2-1: Weather and Non-Fossil Energy Effects on C02 from Fossil Fuel Combustion Trends (Continued)
Figure 2-8
1973 1978 1983 1988 1993
1998
Table 2-4: Fossil Fuel Carbon in Products (Tg C02 Eq,)*
Sector
Industrial
Transportation
Territories
Total
1990
15
6.3
221.0
ET™I
1
1995
240.2
1.2
9.8
251.1
1996
242.4
1.1
14.7
258.2
1997
253.2
1.2
15.4
269.8
1998
260.2
1.2
15.2
276.7
1999
274.8
1.2
15.6
291.6
2000
265.6
1.2
16.3
283.2
See Carbon Stored in Products from Non-Energy Uses of Fossil Fuels section for additional detail.
Note: Totals may not sum due to independent rounding.
Table 2-5: C02 Emissionsfrom International Bunker Fuels (Tg C02 Eq.)*
Vehicle Mode 1990 EZZt 1995 1996
1997
1998
1999
2000
Aviation 46.6
Marine 67.3
p| 51.1 52.1 55.9 55.0 58.9 57.3
49.9 50.1 54.0 57.9 46.4 430
Tolal 113.9 ^_i 101.0 102.3 109.9 112.9 105.3 100.2
See International Bunker Fuels section for additional detail.
Note: Totals may not sum due to independent rounding.
Energy 2-7
-------
End-Use Sector Consumption
When analyzing CO2 emissions from fossil fuel
combustion, four end-use sectors were defined: industrial,
transportation, residential, and commercial.7 Electricity
generation also emits CO2; however, these emissions occur
as power plants combust fossil fuels to provide electricity
to one of the four end-use sectors. For the discussion below,
electricity generation emissions have been distributed to
each end-use sector based upon the sector's share of
national electricity consumption. This method of distributing
emissions assumes that each sector consumes electricity
generated from an equally carbon-intensive mix of fuels and
other energy sources. In reality, sources of electricity vary
widely in carbon intensity (e.g., coal versus wind power).
By giving equal carbon-intensity weight to each sector's
electricity consumption, emissions attributed to one end-
use sector may be somewhat overestimated, while emissions
attributed to another end-use sector may be slightly
underestimated. After the end-use sectors are discussed,
emissions from electricity generation are addressed
separately. Emissions from U.S. territories are also calculated
separately due to a lack of end-use-specific consumption
data. Table 2-6 and Figure 2-9 summarize CO2 emissions
from direct fossil fuel combustion and pro-rated electricity
generation emissions from electricity consumption by end-
use sector.
Transportation End-Use Sector
The transportation end-use sector accounted for the
largest share (approximately 32 percent) of CO2 emissions
from fossil fuel combustion—excluding international bunker
fuels.8 Almost all of the energy consumed in this end-use
sector was supplied by petroleum-based products, with
nearly two-thirds being related to gasoline consumption in
automobiles and other highway vehicles. Other fuel uses,
especially diesel fuel for freight trucks and jet fuel for aircraft,
accounted for the remainder.9
Carbon dioxide emissions from fossil fuel combustion
for transportation increased by 22 percent from 1990 to 2000,
to 1,792.3 Tg CO2 Eq. The growth in transportation end-use
sector emissions has been relatively steady, including a 3.5
percent single year increase in 2000. Like overall energy
demand, transportation fuel demand is a function of many
short and long-term factors. In the short term only minor
adjustments can generally be made through consumer
behavior (e.g., not driving as far for summer vacation).
Table 2-6: C02 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg C02 Eq.)
End-Use Sector
Industrial
Combustion
Electricity
Transportation
Combustion
Electricity
Residential
Combustion
Electricity
Commercial
Combustion
Electricity
U.S. Territories
Total
Electricity Generation
1990
1,519.6
871.6
648.0
1,474.5
1,471.8
2.7
965.3
332.1
633.2
792.3
217.3
575.0
28.1
4,779.8
1,858.9
Note: Totals may not sum due to independent rounding.
aggregate national electricity
r ••
f""' *
pr :
t;:;::::;|
|r," I
IL; '1
1 -i>--k
f-v i
lllllf
I" ' >
pS*f
S-;j":|
i- i
? *
1995
1,563.4
894.9
668.5
1,582.0
1,579.4
2.6
1,050.6
362.3
688.2
853.8
223.9
629.9
35.3
5,085.0
1,989.3
Emissions from fossil fuel
1996
1,623.5
936.5
687.0
1,621.3
1,618.7
2.7
1,109.9
390.4
719.5
884.8
232.8
652.0
27
5,266.4
2,061.2
combustion
1997
1,640.8
935.2
705.6
1,631.6
1,628.8
2.7
1,106.1
374.9
731.2
932.0
233.7
698.4
29.1
5,339.6
2,137.9
by electricity
1998
1,598.1
881.1
717.0
1,657.7
1,655.0
2.7
1,112.6
341.8
770.8
953.4
217.5
735.9
34.4
5,356.2
2,226.4
generation are
1999
1,575.7
858.1
717.7
1,731.0
1,728.2
2.7
1,136.9
360.5
776.5
969.2
219.8
749.4
35.8
5,448.6
2,246.2
allocated
2000
1,568.5
829.2
739.3
1,792.3
1,789.5
2.8
1,199.8
374.8
825.0
1,024.7
239.3
785.4
38
5,623.3
2,352.5
based on
consumption by each end-use sector.
7 See Glossary (Annex Z) for more detailed definitions of the industrial, residential, commercial, and transportation end-use sector, as well
as electricity generation.
8 Note that electricity generation is actually the largest emitter of CO2 when electricity is not distributed among end-use sectors.
9 See Glossary (Annex Z) for a more detailed definition of the transportation end-use sector.
2-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Figure 2-9
Figure 2-10
2,000
. 1,600
D"
"i, 1,200
800
400
0
• From Electricity Consumption
• From Direct Fossil Fuel Combustion
However, long-term adjustments such as vehicle purchase
choices, transport mode choice and access (i.e., trains versus
planes), and urban planning can have a significant impact
on fuel demand.
Motor gasoline and other petroleum product prices have
generally declined since 1990 (see Figure 2-10). Although
gasoline and other transport fuel prices did rise in 2000, an
overall strong economy and short-term constraints on
reductions in travel and increases in vehicle fuel efficiency
were likely causes for demand for fuel from contracting. Since
1990, travel activity in the United States has grown more
rapidly than population, with a 13 percent increase in vehicle
miles traveled per capita. In the meantime, improvements in
the average fuel efficiency of the U.S. vehicle fleet stagnated
after increasing steadily since 1977 (EIA 2001a). The average
miles per gallon achieved by the U.S. vehicle fleet has
remained fairly constant since 1991. This trend is due, in
part, to the increasing dominance of new motor vehicle sales
by less fuel-efficient light-duty trucks and sport-utility
vehicles (see Figure 2-11).
Table 2-7 provides a detailed breakdown of CO2
emissions by fuel category and vehicle type for the
transportation end-use sector. Fifty-five percent of the
emissions from this end-use sector in 2000 were the result of
180 •
60 J
1972 1976 1980 1984 1988 1992 1996 2000
Source for gasoline prices: DOE/EIA-0384(2000), Annual
Energy Review 2000, August 2001, Table 5.22 Source for
motor vehicle fuel efficiency: DOT/FHWA, Highway
Statistics Summary to 1995,1996,1997,1998, and 2000.
Figure 2-11
Motor Vehicle Fuel Efficiency
All Motor Vehicles
12
10 J
1972 1976 1980 1984 1988 1992 1996 2000
Source: DOT/FHWA, Highway Statistics Summary to 1995,
1996,1997,1998,1999, and 2000.
the combustion of motor gasoline in passenger cars and
light-duty trucks. Diesel highway vehicles and jet aircraft
were also significant contributors, accounting for 15 and 13
percent of CO2 emissions from the transportation end-use
sector, respectively.10
10 These percentages include emissions from bunker fuels.
Energy 2-9
-------
Table 2-7: CO, Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg C02 Eq.)
Fuel/Vehicle Type
Motor Gasoline
Passenger Cars
Light-Duty Trucks
Other Trucks
Motorcycles
Buses
Construction Equipment
Agricultural Machinery
Boats (Recreational)
Distillate Fuel Oil (Diesel)
Passenger Cars
Light-Duty Trucks
Other Trucks
Buses
Construction Equipment
Agricultural Machinery
Boats (Freight)
Locomotives
Marine Bunkers
Jet Fuel
General Aviation
Commercial Air Carriers
Military Vehicles
Aviation Bunkers
Other3
Aviation Gasoline
General Aviation
Residual Fuel Oil
Boats (Freight)"
Marine Bunkers"
Natural Gas
Passenger Cars
Light-Duty Trucks
Buses
Pipeline
LPG
Light-Duty Trucks
Other Trucks
Buses
Electricity
Buses
Locomotives
Pipeline
Lubricants
Total (Including Bunkers)0
Total (Excluding Bunkers)0
1990
955.3
612.8
274.1
41.4
1.6
2.0
2.2
4.4
16.9
277.4
7.1
9.0
164.1
7.9
10.5
23.1
18.0
26.3
11.4
220.4
6.3
118.2
34.8
46.6
14.6
3.1
3.1
80.4
24.5
55.8
36.0
+
+
4-
36.0
1.3
+
0.5
0.8
2.7
4-
2.2
0.5
11.7
1,588.4
1,474.5
p±z
IL . _
™" '" "• ' !"i
Pi
lL." ,1
B" "
LJ
r ' •«
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f" '
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1'-; 1
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If-"'"*,
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9
5i»i~ •
1,™ ",! ™*
|l= ' '
^ V '•
I
1995
1,023.0
634.3
314.2
40.0
1.7
3.0
2.4
7.9
19.5
312.2
7.6
11.2
195.4
9.9
10.5
23.0
16.1
29.5
9.1
219.9
5.3
121.4
24.1
51.1
17.9
2.7
2.7
72.1
31.3
40.8
38.3
0.1
+
0.1
38.2
1.0
+
0.5
0.5
2.6
+
2.1
0.5
11.2
1,683.0
1,582.0
1996
1,041.4
646.6
320.4
40.7
1.7
2.1
2.4
7.8
19.7
329.0
7.6
13.1
207.0
8.6
10.9
23.8
18.4
31.5
8.3
229.8
5.8
124.9
23.1
52.2
23.9
2.6
2.6
67.5
25.7
41.8
38.9
+
+
0.1
38.8
0.9
+
0.4
0.5
2.7
+
2.1
0.5
10.9
1,723.6
1,621.3
1997
1,050.6
652.3
323.1
40.5
1.7
2.2
2.5
8.2
20.1
342.8
7.9
14.2
216.1
9.2
11.2
24.5
18.3
32.4
9.1
232.1
6.1
129.4
21.1
55.9
19.6
2.7
2.7
56.7
11.8
44.9
41.5
+
+
0.2
41.3
0.8
+
0.4
0.4
2.7
+
2.1
0.6
11.5
1,741.4
1,631.5
1998
1,072.5
665.9
341.9
32.1
1.7
0.8
2.0
7.6
20.5
353.5
7.6
14.4
225.4
10.7
10.8
23.7
17.8
31.6
11.5
235.6
7.7
131.4
21.7
55.0
19.7
2.4
2.4
55.9
9.5
46.4
34.9
+
+
0.2
34.7
1.0
+
0.4
0.6
2.7
+
2.2
0.6
12.0
1,770.6
1,657.7
1999
1,098.7
682.2
351.2
34.7
1.8
0.7
1.5
5.9
20.8
373.7
5.0
15.3
247.4
11.6
11.0
24.0
18.1
33.2
8.2
242.9
9.2
137.3
21.0
58.9
16.6
2.7
2.7
62.3
24.1
38.2
40.2
+
+
0.3
39.9
0.8
+
0.3
0.5
2.7
+
2.1
0.6
12.1
1,836.3
1,731.0
2000
1,105.7
686.5
353.4
34.9
1.8
0.7
1.5
5.9
20.9
391.0
5.2
16.0
259.0
12.1
11.5
25.2
18.9
34.8
8.3
251.2
9.8
141.0
21.4
57.3
21.8
2.5
2.5
84.7
50.0
34.6
41.9
+
+
0.4
41.5
0.8
+
0.3
0.5
2.7
+
2.1
0.6
12.0
1,892.5
1,792.2
Note: Totals may not sum due to independent rounding.
' Including but not limited to fuel blended with heating oils and fuel used for chartered aircraft flights.
b Fluctuations in emission estimates from the combustion of residual fuel oil are currently unexplained, but may be related to data collection
problems.
c Oflicial estimates exclude emissions from the combustion of both aviation and marine international bunker fuels; however, estimates including
international bunker fuel-related emissions are presented for informational purposes.
+ Does not exceed 0.05 Tg of C02 Eq.
2-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Industrial End-Use Sector
The industrial end-use sector accounted for 28 percent
of CO2 emissions from fossil fuel combustion. On average,
53 percent of these emissions resulted from the direct
consumption of fossil fuels in order to meet industrial energy
demands such as for steam and process heat. The remaining
47 percent was associated with their consumption of
electricity for uses such as motors, electric furnaces, ovens,
and lighting.
The industrial end-use sector includes activities such
as manufacturing, construction, mining, and agriculture.11
The largest of these activities in terms of energy
consumption is manufacturing, which was estimated in 1998
to have accounted for about 84 percent of industrial energy
consumption (EIA 1997). Manufacturing energy
consumption was dominated by several industries, including
petroleum, chemical, primary metal, paper, food, stone, clay,
and glass products.
In theory, emissions from the industrial end-use sector
should be highly correlated with economic growth and
industrial output; however, certain activities within the sector,
such as heating of industrial buildings and agricultural
energy consumption, are also affected by weather
conditions.12 In addition, structural changes within the U.S.
economy that lead to shifts in industrial output away from
energy intensive manufacturing products to less energy
intensive products (e.g., from steel to computer equipment)
also have a significant affect on industrial emissions.
From 1999 to 2000, total industrial production and
manufacturing output were reported to have increased by
4.5 and 4.8 percent, respectively (FRB 2001). However,
excluding the fast growing computer, communication
equipment, and semiconductor industries from these indexes
reduces their growth considerably—to 1.2 and 1.1 percent,
respectively—and illustrates some of the structural changes
occurring in the U.S. economy (see Figure 2-12).
Figure 2-12
Jty|tt|ti|Pjld^^
Total Industrial Index
Total Index Excluding
Computers, Communications
Equip., and Semiconductors
Foods
Stone, Clay &
Glass Products
Chemicals &
Products
Primary Metals
g_ rrrzl Petroleum
1990 1992 1994 1996
1998
2000
Despite the growth in industrial output (49 percent) and
the overall U.S. economy (32 percent) from 1990 to 2000,
emissions from the industrial end-use sector decreased
slightly (by 0.5 percent). The reasons for the disparity
between rapid growth in industrial output and stagnant
growth in industrial emissions are not entirely clear. It is
likely, though, that several factors have influenced industrial
emission trends, including: 1) more rapid growth in output
from less energy-intensive industries relative to traditional
manufacturing industries, 2) improvements in energy
efficiency; and 3) a lowering of the carbon intensity of fossil
fuel consumption as industry shifts from its historical reliance
on coal and coke to heavier usage of natural gas.
11 See Glossary (Annex Z) for a more detailed definition of the industrial end-use sector.
Some commercial customers are large enough to obtain an industrial price for natural gas and/or electricity and are consequently grouped
with the industrial end-use sector in U.S. energy statistics. These misclassifications of large commercial customers likely cause the industrial
end-use sector to appear to be more sensitive to weather conditions.
Energy 2-11
-------
Industry was the largest user of fossil fuels for non-
energy applications. Fossil fuels can be used for producing
products such as fertilizers, plastics, asphalt, or lubricants
that can sequester or store carbon for long periods of time.
Asphalt used in road construction, for example, stores
carbon essentially indefinitely. Similarly, fossil fuels used in
the manufacture of materials like plastics can also store
carbon, if the material is not burned. The amount of carbon
contained in industrial products made from fossil fuels rose
24 percent between 1990 and 2000, to 265.6 Tg CO2 Eq.13
Residential and Commercial End-Use Sectors
The residential and commercial end-use sectors
accounted for an average 21 and 18 percent, respectively, of
CO2 emissions from fossil fuel combustion. Both end-use
sectors were heavily reliant on electricity for meeting energy
needs, with electricity consumption for lighting, heating, air
conditioning, and operating appliances contributing to about
69 and 77 percent of emissions from the residential and
commercial end-use sectors, respectively. The remaining
emissions were largely due to the direct consumption of
natural gas and petroleum products, primarily for heating
and cooking needs. Coal consumption was a minor
component of energy use in both these end-use sectors.
Emissions from residences and commercial buildings
generally increased throughout the 1990s, and, unlike in
other end-use sectors, emissions in these sectors did not
decline during the economic downturn in 1991 (see Table
2-6). This difference exists because short-term fluctuations
in energy consumption in these sectors are affected
proportionately more by the weather than by prevailing
economic conditions. In the long-term, both end-use sectors
are also affected by population growth, regional migration
trends, and changes in housing and building attributes (e.g.,
size and insulation).
In 2000, winter conditions in the United States were
slightly warmer than normal (i.e., heating degree days were
3 percent below normal), although not as warm as in 1999
(see Figure 2-13). Due, in part, to this colder winter relative
to the previous year, emissions from natural gas consumption
in residences and commercial establishments increased by
5 percent and 9 percent, respectively.
In 2000, electricity sales to the residential and
commercial end-use sectors increased by 4 and 3 percent,
respectively. Even though cooler summer conditions in 2000
relative to 1999 likely led to decreased air-conditioning related
electricity consumption (see Figure 2-14), growth hi personal
Figure 2-13
120
|
§100
^ 90 j
- 80 •
1990
Normal
(4,576 Heating Degree Days)
1992
1994 1996
1998
2000
Note: Excludes Alaska and Hawaii
Source: DOE/EIA-0384(2000), Annual Energy Review 2000,
August 2001, Table 1.7 and 1.8
Figure 2-14
120
1100
x 90 \
-------
Figure 2-15
Figure 2-16
1,400
1,200
> 1,000 •
3
o 800 -I
m
600
Residential,
Commercial
400 *•
1972 1976 1980 1984 1988 1992 1996 2000
Note: The transportation end-use sector consumes minor
quantities of electricity.
income along with other trends such as population growth
led to a 6 percent increase in both residential and commercial
end-use sector emissions from 1999 to 2000.
Electricity Generation
The process of generating electricity is the single largest
source of greenhouse gas emissions in the United States
(34 percent), which relies on electricity to meet a significant
portion of its energy requirements. Electricity was consumed
primarily in the residential, commercial, and industrial end-
use sectors for uses such as lighting, heating, electric
motors, appliances, electronics, and air conditioning (see
Figure 2-15). Electricity generation also accounted for the
largest share of CO2 emissions from fossil fuel combustion,
approximately 42 percent in 2000.
The electric power industry includes all power
producers, consisting of both regulated utilities and
nonutilities (e.g. independent power producers, qualifying
cogenerators, and other small power producers). While
utilities primarily generate power for the U.S. electric grid for
sale to retail customers, nonutilities produce electricity for
their own use, to sell to large consumers, or to sell on the
wholesale electricity market (e.g., to utilities for distribution
and resale to customers). The net generation of electricity
by utilities and nonutilities is shown in Figure 2-16.
3,000
2,500
2,000
1,500
1,000
500
Electric
Utilities
Nonutilities
0 J
1990 1992 1994 1996 1998 2000
Source: EIA"I2000c)
The electric power industry in the United States is
currently undergoing significant changes. Both Federal and
State government agencies are modifying regulations to
create a competitive market for electricity generation from
what was a market dominated by vertically integrated and
regulated monopolies (i.e., electric utilities). These changes
have led to the growth of nonutility power producers,
including the sale of generating capacity by electric utilities
to nonutilities.16 As a result, the proportion of electricity in
the United States generated by nonutilities has grown from
about 7 percent in 1990 to 21 percent in 2000 (EIA 2001b).
In 2000, CO2 emissions from electricity generation
increased by 4.7 percent relative to the previous year,
coinciding with increased electricity consumption and robust
growth in the U.S. economy. An additional factor leading to
this above average increase in emissions was the decreased
generation of electricity from renewable resources, including
a 12 percent reduction in output from hydroelectric dams.
This generation was primarily replaced by additional fossil
fuel consumption for producing electricity, thus increasing
the overall the carbon intensity from energy consumption
for electricity generation (see Table 2-9).
Coal is consumed primarily by the electric power sector
in the United States, which accounted for 94 percent of total
coal consumption in 2000. Consequently, changes in
16 In 2000, 47,710 megawatts of electrical generating capacity was sold by electric utilities to nonutilities, or 5.9 percent of total electric
power industry capacity (EIA 2001b).
Energy 2-13
-------
Box 2-2: Sectoral Carbon Intensity Trends Related to Fossil Fuel and Overall Energy Consumption
Fossil fuels are the dominant source of energy in the United States, and carbon dioxide (C02) is emitted as a product from their combustion.
Useful energy, however, can be generated from many other sources that do not emit C02 in the energy conversion process. In the United States,
useful energy is also produced from renewable (i.e., hydropower, biofuels, geothermal, solar, and wind) and nuclear sources.17
Energy-related C02 emissions can be reduced by not only lowering total energy consumption (e.g., through conservation measures)
but also by lowering the carbon intensity of the energy sources employed (e.g., fuel switching from coal to natural gas). The amount
of carbon emitted—in the form of C02—from the combustion of fossil fuels is dependent upon the carbon content of the fuel and
the fraction of that carbon that is oxidized.18 Fossil fuels vary in their average carbon content, ranging from about 53 Tg C02 Eq./EJ for
natural gas to upwards of 95 Tg C02 Eq./EJ for coal and petroleum coke.19 In general, the carbon intensity per unit of energy of fossil fuels
is the highest for coal products, followed by petroleum and then natural gas. Other sources of energy, however, may be directly or indirectly
carbon neutral (i.e., 0 Tg C02 Eq./EJ). Energy generated from nuclear and many renewable sources do not result in direct emissions of C02.
Biofuels such as wood and ethanol are also considered to be carbon neutral, as the C02 emitted during their combustion is assumed to be
offset by the carbon sequestered in the growth of new biomass.20 The overall carbon intensity of the U.S. economy is thus dependent upon
the quantity and combination of fuels and other energy sources employed to meet demand.
Table 2-8 provides a time series of the carbon intensity for each sector of the U.S. economy. The time series incorporates only the
energy consumed from the direct combustion of fossil fuels in each sector. For example, the carbon intensity for the residential sector does
not include the energy from or emissions related to the consumption of electricity for lighting or wood for heat. Looking only at this direct
consumption of fossil fuels, the residential sector exhibited the lowest carbon intensity, which is related to the large percentage of its energy
derived from natural gas for heating. The carbon intensity of the commercial sector was greater than the residential sector for the period from
1990 to 1997, butthen declined to a comparable level as commercial businesses shifted away from petroleum to natural gas. The industrial
sector was more dependent on petroleum and coal than either the residential or commercial sectors, and thus had higher carbon intensities
over this period. The carbon intensity of the transportation sector was closely related to the carbon content of petroleum products (e.g.,
motor gasoline and jet fuel, both around 67 Tg C02 Eq./EJ), which were the primary sources of energy. Lastly, the electricity generation
sector had the highest carbon intensity due to its heavy reliance on coal for generating electricity.
In contrast to Table 2-8, Table 2-9 presents carbon intensity values that incorporate energy consumed from all sources (i.e., fossil fuels,
renewables, and nuclear). In addition, the emissions related to the generation of electricity have been attributed to both electricity generation and the
end-use sectors in which that electricity was eventually consumed.21 This table, therefore, provides a more complete picture of the actual carbon
intensity of each end-use sector per unit of energy consumed. The transportation end-use sector in Table 2-9 emerges as the most carbon intensive
when all sources of energy are included, due to its almost complete reliance on petroleum products and relatively minor amount of biomass based
fuds such as ethanol. The "other end-use sectors" (i.e., residential, commercial, and industrial) use significant quantities of biofuels such as wood,
thereby lowering the overall carbon intensity. The carbon intensity of the electricity generation sector differs greatly from the scenario in Table 2-8,
where only the energy consumed from the direct combustion of fossil fuels was included. This difference is due almost entirely to the inclusion of
electricity generation from nuclear and hydropower sources, which do not emit carbon dioxide.
By comparing the values in Table 2-8 and Table 2-9, a couple of observations can be made. The usage of renewable and nuclear energy
sources has resulted in a significantly lower carbon intensity of the U.S. economy. However, over the eleven year period of 1990 through 2000, the
carbon intensity of U.S. energy consumption has been fairly constant, as the proportion of renewable and nuclear energy technologies has not
changed significantly.
Although the carbon intensity of total energy consumption has remained fairly constant, per capita energy consumption has increased, leading
to a greater energy-related G02 emissions per capita in the United States since 1990 (see Figure 2-17). Due to structural changes and the strong
growth in the U.S. economy, though, energy consumption and energy-related C02 emissions per dollar of gross domestic product (GDP) declined
in the 1990s.
17 Small quantities of CO2, however, are released from some geologic formations tapped for geothermal energy. These emissions are included
with fossil fuel combustion emissions from the electricity generation. Carbon dioxide emissions may also be generated from upstream
activities (e.g., manufacture of the equipment) associated with fossil fuel and renewable energy activities, but are not accounted for here.
18 Generally, more than 97 percent of the carbon in fossil fuel is oxidized to CO2 with most carbon combustion technologies used in the
United States.
19 One exajoule (EJ) is equal to 1018 joules or 0.9478 QBtu.
20 This statement assumes that there is no net loss of biomass-based carbon associated with the land use practices used to produce these
biomass fuels.
21 In other words, the emissions from the generation of electricity are intentionally double counted by attributing them both to electricity
gcncratipn and the end-use sector in which electricity consumption occurred.
2-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 2-8: Carbon Intensity from Direct Fossil Fuel Combustion by Sector (Tg C02 Eq./EJ)
Sector
1990
1995
1996
1997
1998
1999
2000
Residential3
Commercial3
Industrial3 ... . _..
^Transportation3
Electricity Generation13
All Sectors0
53.8
55.7
60.5
66.9
80.4
68.4
l£-«
S^SSM-H
53.7
54.2
59.6
66.8
79.6
67.9
53.6
54.2
59.5
66.7
80.5
68.0
53.7
54.0
59.6
66.6
80.2
68.2
53.7
53.8
59.7
66.7
79.6
68.4
53.7
53.8
59.2
66.7
79.5
68.3
53.7
53.8
58.9
66.8
79.2
68.3
3 Does not include electricity or renewable energy consumption.
b Does not include electricity produced using nuclear or renewable energy.
c Does not include nuclear or renewable energy consumption.
Note: Excludes non-energy fuel use emissions and consumption. Exajoule (EJ) = 1013 joules = 0.9479 QBtu.
Table 2-9: Carbon Intensity from Energy Consumption by Sector (Tg C02 Eq./EJ)
Sector
1990
1995
1996
1997
Transportation3
Other End-Use Sectors3'13
Electricity Generation0
All Sectors'1
66.7
54.0
55.0
57.6
fLl
IKILJ
T "
66.4
52.8
53.4
56.6
66.5
52.9
53.8
56.7
66.3
53.8
55.1
57.3
66.4
53.9
55.3
57.5
66.3
53.2
54.5
57.0
66.4
53.6
55.3
57.3
-a Includes electricity (from fossil fuel, nuclear, and renewable sources) and direct renewable energy consumption.
b Other End-Use Sectors include the residential, commercial, and industrial sectors.
c Includes electricity generation from nuclear and renewable sources.
d Includes nuclear and renewable energy consumption.
-Note: Excludes non-energy fuel use emissions and consumption. Exajoule (EJ) = 1018 joules = 0.9479 QBtu.
Figure 2-17
Figure 2-18
Energy Consumption/capita
104-
COo/Energy Consumption
Energy Consumption/$GDP
1992
1994
1996
1998
2000
Source: BEA (2001), Census (2000), Emission and energy
consumption estimates in this report.
Dark shaded columns relate to changes in emissions from
electricity consumption. Lightly shaded columns relate to
changes in emissions from both electricity and direct fossil
fuel combustion.
300
-50
Residential Commercial Industrial Transportation
Figure 2-18 and Table 2-10 present the detailed C02 emission trends underlying the carbon intensity differences and changes described in
Table 2-8. In Figure 2-18, changes overtime in both overall end-use sector-related emissions and electricity-related emissions for each year since
1990 are highlighted. In Table 2-10 changes in emissions since 1990 are presented by sector and fuel type to provide a more detailed accounting.
Energy 2-15
-------
Table 2-10: Change in C02 Emissions from Direct Fossil Fuel Combustion Since 1990 (Tg C02 Eq.)
r~™
Sector/Fuel Type 1991 f 1995 1996 1997 1998 1999
Residential
Coal
Natural Gas
Petroleum
Commercial
Coal
Natural Gas
Petroleum
Industrial
Coal
Natural Gas
Petroleum
Transportation
Coal
Natural Gas
Petroleum
Electricity Generation
Coal
Natural Gas
Petroleum
Geothermal
U.S. Territories
Coal
Natural Gas
Petroleum
All Sectors
9.9
(0.5)
8.8
1.7
1.5
(0.8)
5.8
(3.5)
(24.3)
(1.5)
(1.4)
(21.4)
(34.1)
NE
(3.2)
(30.9)
(3.7)
(5.8)
7.4
(5.2)
3.7
0.1
NE
3.7
(46.8)
'f
-~
f
*
i-
&•
~
l
¥
I1
i
iar
CL
i
L
i». .
pss^
ry.
(S.
i.
In
i
L
I
"
~
I
^
-
*
*
1
1
..i
rf
i
"IF
jl
1
J
ijBI
HI
w
fr
11
-g
30.2
(0.8)
24.6
6.4
6.6
(1.2)
22.1
(14.3)
23.2
(4.6)
40.5
(12.7)
107.5
NE
2.3
105.3
130.3
106.4
63.0
(38.9)
(0.1)
7.2
0.3
NE
6.9
305.1
58.3
(0.7)
46.0
13.0
15.5
(1.0)
29.2
(12.6)
64.9
(10.4)
56.8
18.4
146.9
NE
2.9
144.0
202.3
197.6
38.7
(33.9)
(0.1)
(1.2)
0.3
NE
(1.5)
486.6
42.8
(0.4)
32.0
11.2
16.4
(0.5)
32.3
(15.3)
63.5
(8.9)
51.6
20.9
157.0
NE
5.5
151.6
279.0
247.5
56.6
(25.0)
(0.1)
0.9
0.3
NE
0.6
559.6
9.7
(1.6)
8.0
3.4
0.3
(2.5)
21.1
(18.4)
9.4
(14.5)
20.0
3.9
183.2
NE
(1.1)
184.3
367.5
275.4
89.1
3.1
(0.1)
6.1
0.3
NE
5.9
576.2
28.4
(1.4)
17.9
11.9
2.5
(2.1)
22.8
(18.1)
(13.6)
(18.9)
14.9
(9.6)
256.4
NE
4.2
252.3
387.3
286.5
96.6
4.3
(0.2)
7.6
0.3
NE
7.4
668.6
2000
42.7
(1.4)
29.7
14.4
22.0
(2.1)
38.4
(14.3)
(42.4)
(33.0)
13.3
(22.7)
317.7
NE
5.9
311.9
493.6
373.8
128.1
(8.2)
(0.2)
9.8
0.3
0.6
8.9
843.3
+ Does not exceed 0.05 Tg C02 Eq.
NE (Not Estimated)
Note: Totals may not sum due to independent rounding.
electricity demand have a significant impact on coal
consumption and associated U.S. CO2 emissions. Coal
consumption for electricity generation increased by 5 percent
in 2000, due to 1) increased electricity demand, 2) decreased
electricity output of from hydropower, and 3) the relatively
stable price of coal. In 2000, the price of coal decreased 2
percent, while petroleum and natural gas prices increased
68 and 63 percent, respectively.
Methodology
The methodology used by the United States for
estimating CO2 emissions from fossil fuel combustion is
conceptually similar to the approach recommended by the
IPCC for countries that intend to develop detailed, sectoral-
based emission estimates (TPCC/UNEP/OECD/TJEA1997). A
detailed description of the U.S. methodology is presented
in Annex A, and is characterized by the following steps:
1. Determine fuel consumption by fuel type and sector. By
aggregating consumption data by end-use sector (e.g.,
commercial, industrial, etc.), primary fuel type (e.g., coal,
petroleum, gas), and secondary fuel category (e.g., motor
gasoline, distillate fuel oil, etc.), estimates of total U.S. fossil
fuel consumption for a particular year were made. The
United States does not include territories in its national
energy statistics; therefore, fuel consumption data for
territories was collected separately.22 Portions of the fuel
consumption data for three fuel categories - coking coal,
petroleum coke, and natural gas — were reallocated to the
22 Fuel consumption by U.S. territories (i.e. American Samoa, Guam, Puerto Rico, U.S. Virgin Islands, Wake Island, and other U.S. Pacific
Islands) is included in this report and contributed emissions of 53 Tg CO2 Eq. in 2000.
2-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
industrial processes chapter, as these portions were
actually consumed during a non-energy related industrial
activity.23
2. Determine the total carbon content of fuels consumed.
Total carbon was estimated by multiplying the amount
of fuel consumed by the amount of carbon in each fuel.
This total carbon estimate defines the maximum amount
of carbon that could potentially be released to the
atmosphere if all of the carbon in each fuel was converted
to CO2. The carbon content coefficients used by the
United States are presented in Annex A.
3. Subtract the amount of carbon stored in products.
Non-energy uses of fossil fuels can result in storage of
some or all of the carbon contained in the fuel for some
period of time, depending on the end-use. For example,
asphalt made from petroleum can sequester up to 100
percent of the carbon for extended periods of time, while
other fossil fuel products, such as lubricants or plastics,
lose or emit some carbon when they are used and/or
burned as waste. Aggregate U.S. energy statistics
include consumption of fossil fuels for non-energy
uses; therefore, the portion of carbon that remains in
products after they are manufactured was subtracted
from potential carbon emission estimates.24 The amount
of carbon remaining in products was based on the best
available data on the end-uses and fossil fuel products.
These non-energy uses occurred in the industrial and
transportation end-use sectors and U.S. territories.
Emissions of CO2 associated with the disposal of these
fossil fuel-based products are not accounted for here,
but are instead accounted for under the Waste
Combustion section in this chapter.
4. Subtract the amount of carbon from international
bunker fuels. According to the IPCC guidelines (IPCC/
UNEP/OECD/IEA 1997) emissions from international
transport activities, or bunker fuels, should not be
included in national totals. Because U.S. energy
consumption statistics include these bunker fuels—
distillate fuel oil, residual fuel oil, and jet fuel—as part
of consumption by the transportation end-use sector,
emissions from international transport activities were
calculated separately and the carbon content of these
fuels was subtracted from the transportation end-use
sector. The calculations for emissions from bunker fuels
follow the same procedures used for emissions from
consumption of all fossil fuels (i.e., estimation of
consumption, determination of carbon content, and
adjustment for the fraction of carbon not oxidized).25
5. Adjust for carbon that does not oxidize during
combustion. Because combustion processes are not 100
percent efficient, some of the carbon contained in fuels
is not emitted to the atmosphere. Rather, it remains
behind as soot and ash. The estimated amount of carbon
not oxidized due to inefficiencies during the combustion
process was assumed to be 1 percent for petroleum and
coal and 0.5 percent for natural gas (see Annex A).
Unoxidized or partially oxidized organic (i.e., carbon
containing) combustion products were assumed to have
eventually oxidized to CO2 in the atmosphere.26
6. Allocate transportation emissions by vehicle type.
Because the transportation end-use sector was such a
large consumer of fossil fuels in the United States,27 a
more detailed accounting of carbon dioxide emissions
is provided. For fuel types other than jet fuel, fuel
consumption data by vehicle type and transportation
mode were used to allocate emissions by fuel type
calculated for the transportation end-use sector. Specific
data by vehicle type were not available for 2000;
therefore, the 1999 percentage allocations were applied
to 2000 fuel consumption data in order to estimate
emissions in 2000. Military vehicle jet fuel consumption
was provided by the Defense Energy Support Center,
under Department of Defense's (DoD) Defense
Logistics Agency and the Office of the Undersecretary
of Defense (Environmental Security). The difference
between total U.S. jet fuel consumption (as reported by
23 See sections on Iron and Steel Production, Ammonia Manufacture, Titanium Dioxide Production, Ferroalloy Production, and Aluminum
Production in the Industrial Proceses chapter.
24 See Carbon Stored in Products from Non-Energy Uses of Fossil Fuels section in this chapter for a more detailed discussion.
25 See International Bunker Fuels section in this chapter for a more detailed discussion.
26 See Indirect CO2 from CH4 Oxidation section in this chapter for a more detailed discussion.
27 Electricity generation is not considered a final end-use sector, because energy is consumed solely to provide electricity to the other
sectors.
Energy 2-17
-------
EIA) and civilian air carrier consumption for both
domestic and international flights (as reported by DOT
and BEA) plus military jet fuel consumption is reported
as "other" under the jet fuel category hi Table 2-7, and
includes such fuel uses as blending with heating oils
and fuel used for chartered aircraft flights.
Data Sources
Data on fuel consumption for the United States and its
territories, and carbon content of fuels were obtained directly
from the Energy Information Administration (EIA) of the
U.S. Department of Energy (DOE). Fuel consumption data
were obtained primarily from the Annual Energy Review
and other EIA databases (EIA 2001a). Data on military jet
fuel use was supplied by the Office of the Under Secretary
of Defense (Environmental Security) and the Defense Energy
Support Center (Defense Logistics Agency) of the U.S.
Department of Defense (DoD) (DESC 2001). Estimates of
international bunker fuel emissions are discussed in the
section entitled International Bunker Fuels. Estimates of
carbon stored in products are discussed in the section
entitled Carbon Stored in Products from Non-fuel Uses of
Fossil Fuels.
IPCC provided fraction oxidized values for petroleum
and natural gas (IPCC/UNEP/OECD/IEA1997). Bechtel (1993)
provided the fraction oxidation value for coal. Vehicle type
fuel consumption data for the allocation of transportation
end-use sector emissions were primarily taken from the
Transportation Energy Data Book prepared by the Center
for Transportation Analysis at Oak Ridge National
Laboratory (DOE 1993 through 2001). Specific data on military
fuel consumption were taken from DESC (2001). Densities
for each military jet fuel type were obtained from the Air
Force (USAF1998).
Carbon intensity estimates were developed using
nuclear and renewable energy data from EIA (200la) and
fossil fuel consumption data as discussed above and
presented in Annex A.
For consistency of reporting, the IPCC has
recommended that national inventories report energy data—
and emissions from energy—using the International Energy
Agency (IEA) reporting convention and/or IEA data. Data
in the IEA format are presented "top down"—that is, energy
consumption for fuel types and categories are estimated
from energy production data (accounting for imports,
exports, stock changes, and losses). The resulting quantities
are referred to as "apparent consumption." The data
collected in the United States by EIA, and used in this
inventory, are, instead, "bottom up" in nature. In other words,
they are collected through surveys at the point of delivery
or use and aggregated to determine national totals.28
It is also important to note that U.S. fossil fuel energy
statistics are generally presented using gross calorific values
(GCV) (i.e., higher heating values). Fuel consumption activity
data presented here have not been adjusted to correspond
to international standard, which are to report energy
statistics in terms of net calorific values (NCV) (i.e., lower
heating values).29
Uncertainty
For estimates of CO2 from fossil fuel combustion, the
amount of CO2 emitted is - in principle - directly related to
the amount of fuel consumed, the fraction of the fuel that is
oxidized, and the carbon content of the fuel. Therefore, a
careful accounting of fossil fuel consumption by fuel type,
average carbon contents of fossil fuels consumed, and
production of fossil fuel-based products with long-term
carbon storage should yield an accurate estimate of CO2
emissions.
There are uncertainties, however, in the consumption
data, carbon content of fuels and products, and carbon
oxidation efficiencies. For example, given the same primary
fuel type (e.g., coal, petroleum, or natural gas), the amount
of carbon contained in the fuel per unit of useful energy can
vary.
28 See IPCC Reference Approach for estimating CO2 emissions from fossil fuel combustion in Annex R for a comparison of U.S. estimates
using lop-down and bottom-up approaches.
29 A crude convention to convert between gross and net calorific values is to multiply the heat content of solid and liquid fossil fuels by 0.95
and gaseous fuels by 0.9 to account for the water content of the fuels. Biomass-based fuels in U.S. energy statistics, however, are generally
presented using net calorific values.
2-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Although statistics of total fossil fuel and other energy
consumption are considered to be relatively accurate, the
allocation of this consumption to individual end-use sectors
(i.e., residential, commercial, industrial, and transportation)
is considerably more uncertain. For example, for some fuels
the sectoral allocations are based on price rates (i.e., tariffs).
However, commercial establishment may be able to negotiate
an industrial rate or a small industrial establishment may
end up paying an industrial rate, leading to a misallocation
of emissions. Also, the deregulation of the natural gas
industry and the more recent deregulation of the electric
power industry have likely led to some minor problems in
collecting accurate energy statistics as firms in these
industries have undergone significant restructuring.
Non-energy uses of the fuel can also create situations
where the carbon is not emitted to the atmosphere (e.g.,
plastics, asphalt, etc.) or is emitted at a delayed rate. The
proportions of fuels used in these non-energy production
processes that result in the sequestration of carbon have
been assumed. Additionally, inefficiencies in the combustion
process, which can result in ash or soot remaining unoxidized
for long periods, were also assumed. These factors all
contribute to the uncertainty in the CO2 estimates. More
detailed discussions on the uncertainties associated with
Carbon Stored in Products from Non-Energy Uses of Fossil
Fuels are provided this section in this chapter.
Various uncertainties surround the estimation of
emissions from international bunker fuels, which are
subtracted from U.S. totals. These uncertainties are primarily
due to the difficulty in collecting accurate fuel consumption
data for international transport activities. Small aircraft and
many marine vessels often carry enough fuel to complete
multiple voyages without refueling, which, if used for both
domestic and international trips, may be classified as solely
international. The data collected for aviation does not include
some smaller planes making international voyages, and also
designates some flights departing to Canada and Mexico as
domestic. More detailed discussions on these uncertainties
are provided in the International Bunker Fuels section of
this chapter.
Another source of uncertainty is fuel consumption by
U.S. territories. The United States does not collect energy
statistics for its territories at the same level of detail as for
the fifty States and the District of Columbia. Therefore
estimating both emissions and bunker fuel consumption by
these territories is difficult.
For Table 2-7, uncertainties also exist as to the data used
to allocate CO2 emissions from the transportation end-use sector
to individual vehicle types and transport modes. In many cases,
bottom up estimates of fuel consumption by vehicle type do
not match aggregate fuel-type estimates from EIA. Further
research is planned to better allocate detailed transportation
end-use sector emissions. In particular, residual fuel
consumption data for marine vessels are highly uncertain, as
shown by the large fluctuations in emissions.
For the United States, however, the impact of these
uncertainties on overall CO2 emission estimates is believed to
be relatively small. For the United States, CO2 emission estimates
from fossil fuel combustion are considered accurate within
several percent. See, for example, Marland and Pippin (1990).
Carbon Stored in Products from
Non-Energy Uses of Fossil Fuels
Besides being combusted for energy, fossil fuels are also
consumed for non-energy purposes. The types of fuels used
for non-energy uses are listed hi Table 2-11. These fuels are
used in the industrial and transportation end-use sectors and
are quite diverse, including natural gas, asphalt (a viscous liquid
mixture of heavy crude oil distillates), petroleum coke,
(manufactured from heavy oil) and coal coke (manufactured
from coking coal.) The non-energy fuel uses are equally diverse,
and include application as solvents, lubricants, and waxes, or
as raw materials in the manufacture of plastics, rubber, synthetic
fibers, and fertilizers.
Carbon dioxide emissions arise from non-energy uses
via several pathways. Emissions may occur during the
manufacture of a product, as is the case in producing plastics
or rubber from fuel-derived feedstocks. Additionally, in the
case of solvents or lubricants, for example, emissions may
occur during the product's lifetime. Overall, more than 65
percent of the total carbon consumed for non-energy
purposes is stored in products, and not released to the
atmosphere. However, some of the products release CO2 at
the end of their commercial life when they are disposed.
These emissions are covered separately in this chapter in
the Waste Combustion section.
Energy 2-19
-------
In 2000, fossil fuel consumption for non-energy uses
constituted 6 percent (5,915.6 TBtu) of overall fossil fuel
consumption, approximately the same as 1990. In 2000, the
carbon contained in fuels consumed for non-energy uses
was approximately 410 Tg CO2 Eq., an increase of 28 percent
since 1990. About 283 Tg CO2Eq. of this carbon was stored,
while the remaining 126 Tg CO2 Eq. was emitted. The
proportion of carbon emitted has remained about the same,
at 31 percent of total non-energy consumption, since 1990.
Table 2-12 shows the fate of the non-energy fossil fuel carbon
for 1990 and 1995 through 2000.
Methodology
The first step in estimating carbon stored in products was
to determine the aggregate quantity of fossil fuels consumed
for non-energy uses. The carbon content of these feedstock
fuels is equivalent to potential emissions, or the product of
consumption and the fuel-specific carbon content values (see
Annex A). Consumption of natural gas, LPG, pentanes plus,
naphthas, and other oils were adjusted to account for net
exports of these products. Approximately 8 percent of the U.S.
production of these products is exported. Consumption values
Table 2-11:2000 Non-Energy Fossil Fuel Consumption, Storage, and Emissions (Tg C02 Eq. unless otherwise noted)
Sector/Fuel Type
Industry
Industrial Coking Coal
Natural Gas to Chemical Plants
Asphalt & Road Oil
LPG
Lubricants
Pentanes Plus
Petrochemical Feedstocks
Naphtha (<401 deg. F)
Other Oil (>401deg.F)
Still Gas
Petroleum Coke
Special Naphtha
Distillate Fuel Oil
Residual Fuel
Waxes
Miscellaneous Products
Transportation
Lubricants
U.S. Territories
Lubricants
Other Petroleum (Misc. Prod.)
Total
Consumption (TBtu)
Total Adjusted3
6,675.0
793.1
372.3
1,275.7
1,856.7
189.9
311.9
613.5
722.2
7.4
225.5
97.4
7.0
50.3
33.1
119.2
179.4
179.4
223.8
1.4
222.5
7,078.3
5,512.4
26.4
342.4
1,275.7
1,707.3
189.9
286.8
564.2
664.1
7.4
141.4
97.4
7.0
50.3
33.1
119.2
179.4
179.4
223.8
1.4
222.5
5,915.6
Carbon
Content
379.8
2.5
18.2
96.4
105.6
14.1
19.2
37.5
48.6
0.5
14.4
7.1
0.5
4.0
2.4
8.8
13.3
13.3
16.4
0.1
16.3
409.6
Storage
Factor
.
0.8
0.6
1.0
0.6
0.1
0.6
0.6
0.6
0.8
0.5
-
0.5
0.5
1.0
1.0
0.1
0.1
1.0
-
Carbon
Stored
265.6
1.9
11.5
96.4
66.8
1.3
12.1
23.7
30.7
0.4
7.2
-
0.3
2.0
2.4
8.8
1.2
1.2
16.3
+
16.3
283.2
Emissions
114.2
0.6
6.7
-
38.8
12.8
7.0
13.8
17.8
0.1
7.2
7.1
0.3
2.0
-
-
12.1
12.1
0.1
0.1
-
126.4
1 Natural gas, LPG, Pentanes Plus, Naphthas, and Other Oils are adjusted to account for exports of chemical intermediates derived from these
fuels. To avoid double-counting, coal coke, petroleum coke, and natural gas consumption are adjusted for industrial process consumption
addressed in the Industrial Process chapter.
- Not applicable.
Note: Totals may not sum due to independent rounding.
Table 2-12: Storage and Emissions from Non-Energy Fossil Fuel Consumption (Tg C02 Eq.)
Variable
1990
1995
1996
1997
1998
1999
2000
Potential Emissions
Carbon Stored
Emissions
319.9
221.0
99.0
F t
1- I
f* „
is I
362.9
251.1
111.8
371.9
258.2
113.7
388.0
269.8
118.2
402.7
276.7
126.1
428.1
291.6
136.4
409.6
283.2
126.4
2-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
for industrial coking coal, petroleum coke, and natural gas in
Table 2-11 are adjusted to subtract non-energy uses that are
addressed in the Industrial Process chapter.30
For the remaining non-energy uses, the amount of
carbon stored was estimated by multiplying the potential
emissions by a storage factor. For several fuel types—
asphalt and road oil, lubricants, petrochemical feedstocks,
liquid petroleum gases (LPG), pentanes plus, and natural
gas for non-fertilizer uses—U.S. data on carbon stocks and
flows were used to develop carbon storage factors, calculated
as the ratio of (a) the carbon stored by the fuel's non-energy
products to (b) the total carbon content of the fuel
consumed. A lifecycle approach was used in the development
of these factors in order to account for losses in the
production process—from raw material acquisition through
manufacturing and processing—and during use. Details of
these calculations are shown in Annex B. Because losses
associated with municipal solid waste management are
handled separately in this chapter under Waste Combustion,
the storage factors do not account for losses at the disposal
end of the life cycle. For the other fuel types, the storage
factors were taken directly from Marland and Rotty (1984).
Lastly, emissions were estimated by subtracting the
carbon stored from the potential emissions.
Data Sources
Non-energy fuel consumption and carbon content data
were supplied by the EIA (200 la).
Where storage factors were calculated specifically for the
United States, data was obtained on fuel products such as
asphalt, plastics, synthetic rubber, synthetic fibers, pesticides,
and solvents. Data was taken from a variety of industry sources,
government reports, and expert communications. Sources
include EPA compilations of air emission factors (EPA 1995,
EPA2001), the EIAManufacturer's Energy Consumption Survey
(MECS) (EIA 2001b), the National Petrochemical & Refiners
Association (NPRA 2001), the National Asphalt Pavement
Association (Connolly 2000), the Emissions Inventory
Improvement Program (EEP 1999), the U.S. Census Bureau
(1999), the American Plastics Council (APC 2000), the
International Institute of Synthetic Rubber Products (HSR?
2000), the Fiber Economics Bureau (FEE 2000), and (he Chemical
Manufacturer's Handbook (CMA 1999). For the other fuel
types, storage factors were taken fromMarland and Rotty (1984).
Specific data sources are listed in full detail in Annex B.
Uncertainty
The fuel consumption data for non-energy uses and the
carbon content values employed here were taken from the same
references as the data used for estimating overall CO2 emissions
from fossil fuel combustion. In addition, data used to make
adjustments to the fuel consumption estimates were taken from
several sources. Given that the uncertainty in these data is
expected to be small, the uncertainty of the estimate for the
potential carbon emissions is also expected to be small.
However, there is a large degree of uncertainty in the storage
factors employed, depending upon the fuel type. For each of
the calculated storage factors, the uncertainty is discussed in
detail in Annex B. Generally, uncertainty arises from
assumptions made to link fuel types with their derivative
products and in determining the fuel products' carbon contents
and emission or storage fates. The storage factors from Marland
and Rotty (1984) are also highly uncertain.
Stationary Combustion
(excluding C02)
Stationary combustion encompasses all fuel combustion
activities except those related to transportation (i.e., mobile
combustion). Other than carbon dioxide (CO2), which was
addressed in the previous section, gases from stationary
combustion include the greenhouse gases methane (CH4)
and nitrous oxide (N2O) and the ambient air pollutants
nitrogen oxides (NOx), carbon monoxide (CO), and non-
methane volatile organic compounds (NMVOCs).31
Emissions of these gases from stationary combustion
sources depend upon fuel characteristics, size and vintage
to the combustion technology, pollution control equipment,
and ambient environmental conditions. Emissions also vary
with operation and maintenance practices.
30 These source categories include Iron and Steel Production, Ammonia Manufacture, Titanium Dioxide Production, Ferroalloy Production,
and Aluminum Production.
31 Sulfur dioxide (SO2) emissions from stationary combustion are addressed in Annex S.
Energy 2-21
-------
Nitrous oxide and NOx emissions from stationary
combustion are closely related to air-fuel mixes and
combustion temperatures, as well as the characteristics of
any pollution control equipment that is employed. Carbon
monoxide emissions from stationary combustion are
generally a function of the efficiency of combustion; they
are highest when less oxygen is present in the air-fuel mixture
than is necessary for complete combustion. These conditions
are most likely to occur during start-up, shutdown and during
fuel switching (e.g., the switching of coal grades at a coal-
burning electric utility plant). Methane and NMVOC
emissions from stationary combustion are primarily a
function of the CH4 and NMVOC content of the fuel and
combustion efficiency.
Emissions of CH4 decreased 5 percent overall from 7.9
Tg C02 Eq. (376 Gg) in 1990 to 7.5 Tg CO2 Eq. (357 Gg) in
2000. This decrease in CH4 emissions was primarily due to
lower wood consumption hi the residential sector. Conversely,
nitrous oxide emissions rose 16 percent since 1990 to 14.9 Tg
CO, Eq. (48 Gg) in 2000. The largest source of N2O emissions
was coal combustion by electricity generators, which alone
accounted for 60 percent of total N2O emissions from stationary
combustion in 2000. Overall, though, stationary combustion is
a small source of CH4 and N2O in the United States.
In contrast, stationary combustion was a significant source
of NO emissions, but a smaller source of CO and NMVOCs. In
2000, emissions of NOx from stationary combustion represented
35 percent of national NOx emissions, while CO and NMVOC
emissions from stationary combustion contributed
approximately 4 and 6 percent, respectively, to the national
totals. From 1990 to 2000, emissions of NOx and CO from
stationary combustion decreased by 12 and 17 percent,
respectively, and emissions of NMVOCs increased by 19percent
ThedecreaseinNOx emissions from 1990 to 2000 are mainly
due to decreased emissions from electricity generation. The
decrease in CO and increase in NMVOC emissions over this time
period can largely be attributed to changes in residential wood
consumption, which is the most significant source of these
pollutants from stationary combustion. Table 2-13 through Table
2-16 provide CH4 and N2O emission estimates from stationary
combustion by sector and fuel type. Estimates of NOx, CO, and
NMVOC emissions in 2000 are given inTable 2-17.32
Methodology
Methane and N2O emissions were estimated by multiplying
emission factors (by sector and fuel type) by fossil fuel and
wood consumption data. National coal, natural gas, fuel oil,
and wood consumption data were grouped into four sectors—
industrial, commercial, residential, and electricity generation.
For NOx, CO, and NMVOCs, the major categories included
in this section are those used in EPA (2001): coal, fuel oil,
natural gas, wood, other fuels (including LPQ coke, coke oven
gas, and others), and stationary internal combustion. The EPA
estimates emissions of NOx, CO, and NMVOCs by sector and
fuel source using a "bottom-up" estimating procedure. In other
words, emissions were calculated either for individual sources
(e.g., industrial boilers) or for multiple sources combined, using
basic activity data as indicators of emissions. Depending on
the source category, these basic activity data may include fuel
consumption, fuel deliveries, tons of refuse burned, raw material
processed, etc.
The EPA derived the overall emission control efficiency of
a source category from published reports, the 1985 National
Acid Precipitation and Assessment Program (NAPAP)
emissions inventory, and other EPA databases. The U.S.
approach for estimating emissions of NOx, CO, and NMVOCs
from stationary combustion, as described above, is consistent
with the methodology recommended by the IPCC (IPCC/UNEP/
OECD/DEA1997).
More detailed information on the methodology for
calculating emissions from stationary combustion, including
emission factors and activity data, is provided in Annex C.
Data Sources
Emissions estimates for NOx, CO, and NMVOCs in this
section were taken directly from unpublished EPA data (2001).
Fuel consumption data for CH4 and N2O estimates were
provided by the U.S. Energy Information Administration's
Annual Energy Review (EIA 2001). Estimates for wood biomass
consumption for fuel combustion do not include wood wastes,
liquors, municipal solid waste, tires, etc. that are reported as
biomass by EIA. Emission factors were provided by the
Revised 1996 IPCC Guidelines for National Greenhouse
Gas Inventories (3PCC/UNEP/OECD/TEA1997).
32 See Annex C for a complete time series of ambient air pollutant emission estimates for 1990 through 2000.
2-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 2-13: CH4 Emissions from Stationary Combustion (Tg C02 Eq.)
•r Sector/Fuel Type
Electricity Generation
ir Coal
i Fuel Oil
; Natural gas
: Wood
;* Industrial
r- Coal
Fuel Oil
Natural gas
f Wood
Commercial
I Coal
:" Fuel Oil
i Natural gas
', Wood
• Residential
r Coal
:: Fuel Oil
: Natural Gas
I Wood
Total
• + Does not exceed 0.05 Tg
: Note: Totals may not sum
1990 t ^
0.5 F--'
0.3 gg
0.1 IS,;.--!
0.1' fcj
_j_ E^,:'3
" 2.1 '" fc"!
0.3 ' p;l
0.3
0,7
0.8 US?
0.7 '
+ pff"5f
o-2 El
o.s [«:;;*
02 fSwj
4.6 f™"™*
0.4
0 If^.-. - -I
.0 S5i---V^
f) C
- - O.O h£ .4
3.5
7.9 EL,-
G02 Eq.
due to independent rounding.
1995
0.5
0.4
0.1
0.1
_[.
2.3
0.3
0.4
0.8
0.8
0.7
4.
0.2
0.3
0.3
4.7
0.3
0.3
0.5
3.6
8.2
1996
0.5
0.4
0.1
0.1
_j_
2.3
0.3
0.4
0.8
0.8
0.8
+
0.2
0.3
0.3
4.7
0.3
0.3
0.5
3.6
8.4
1997
0.6
0.4
0.1
0.1
4.
2.4
0.3
0.4
0.8
0.9
0.8
_i_
0.1
0.3
0.3
3.8
0.4
0.3
0.5
2.6
7.5
1998
0.6
0.4
0.1
0.1
_j.
2.3
0.3
0.4
0.7
0.9
0.7
+
0.1
0.3
0.3
3.3
0.3
0.3
0.5
2.3
7.0
1999
0.6
0.4
0.1
0.1
,
2.4
0.3
0.4
0.7
1.0
0.8
+
0.1
0.3
0.3
3.6
0.3
0.3
0.5
2.5
7.3
2000
0.6
0.4
0.1
0.1
,
2.3
0.2
0.4
0.7
1.0
0.8
+
0.2
0.3
0.3
3.7
0.3
0.3
0.5
2.6
7.5
Table 2-14: N20 Emissions from Stationary Combustion (Tg C02 Eq.)
"•" "
Sector/Fuel Type 1990 L A 1995
1996
1997
1998
Electricity Generation
jr'. Coal
t Fuel Oil
, Natural Gas
; Wood
Industrial
Coal
. Fuel Oil
f Natural Gas
' Wood
: Commercial
- Coal
r Fuel Oil
:" Natural Gas
Wood
Residential
Coal
FuelOil
Natural Gas
• Wood
Total
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent
7.6
7.2
0.2
0.1
+
3.8
0.6
1.5
0.2
1.5
0.3
+""
0.2
0.1
+
1.1
+
0.2
0.1
0.7
12.8
rounding.
—
P\ ----:
IB?.'- i
jfc™!
.
^~~ "
lip?"-1!
J5SS-~i
fc:''J
H
':", .'..;'*" "i
t^7|
to;-'--™|
p^..-,j
K-'-i
y^,,_
8.0
7.7
0.2
0.2
4.
4.1
0.6
1.6
0.2
1.7
0.3
+
0.1
0.1
0.1
1.1
+
0.3
0.1
0.7
13.5
8.4
8.1
0.2
0.1
+
4.2
0.6
1.7
0.2
1.7
0.3
_l_
0.1
0.1
0.1
1.2
+
0.3
0.2
0.7
14.1
8.7
8.3
0.2
0.2
_l_
4.3
0.6
1.7
0.2
1.8
0.3
+
0.1
0.1
0.1
1.0
+
0.3
0.2
0.5
14.2
8.9
8.5
0.3
0.2
+
4.3
0.6
1.7
0.2
1.8
0.3
+
0.1
0.1
0.1
0.9
+
0.2
0.1
0.5
14.3
8.9
8.5
0.3
0.2
4.
4.4
0.6
1.7
0.2
2.0
0.3
0.1
0.1
0.1
0.9
+
0.3
0.1
0.5
14.6
9.3
8.9
0.2
0.2
_j_
4.3
0.5
1.6
0.2
2.0
0.3
0.1
0.1
0.1
1.0
+
0.3
0.1
0.5
14.9
Energy 2-23
-------
Table 2-15: CH4 Emissionsfrom Stationary Combustion (Gg)
Sector/Fuel Type
Electricity Generation
Coal
Fuel Oil
Natural Gas
Wood
Industrial
Coal
Fuel Oil
Natural Gas
Wood
Commercial
Coal
Fuel Oil
Natural Gas
Wood
Residential
Coal
Fuel Oil
Natural Gas
Wood
Total
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to
1990
24
17
4
4
100
15
16
33
36
33
1
9
13
11
218
19
13
21
166
376
independent rounding.
K
" *
•
J-
:
H
m f
•
i~ :
»=-. _
!r ~~^
it
.
V I
r
fr f
t „
I "
I
1995
25
18
2
5
+
108
14
17
37
40
36
1
7
15
13
223
16
14
24
170
392
1996
26
19
3
5
+
111
14
18
38
41
38
1
7
15
14
226
16
15
26
170
400
1997
27
19
3
5
+
113
14
18
38
43
37
1
7
16
13
179
17
14
24
123
356
1998
29
19
4
5
+
110
13
18
35
45
35
1
7
15
13
159
13
13
22
110
334
1999
29
20
4
6
-f
114
13
18
35
49
37
1
7
15
15
170
14
15
23
118
350
2000
30
21
4
6
+
111
11
17
34
48
39
1
7
16
15
177
14
15
24
123
357
Table 2-16: N20 Emissionsfrom Stationary Combustion (Gg)
Sector/Fuel Type
Electricity Generation
Coal
Fuel Oil
Natural Gas
Wood
Industrial
Coal
Fuel Oil
Natural Gas
Wood
Commercial
Coal
Fuel Oil
Natural Gas
Wood
Residential
Coal
Fuel OH
Natural Gas
Wood
Total
+ Does not exceed 0.5 Gg
Note: Totals may not sum due
1990
24
23
1
+
+
12
2
5
1
5
1
+
1
+
+
3
+
1
+
2
41
to independent rounding.
i
^ m
» i
a |
^ £
t- ;
p • i
i
^ HI
e *
F
' T
. I
£ I
=-
^ a
- -1
aL
a; ^
-~- - J
t- !
i= t
i :
r=-»
r
1995
26
25
+
+
+
13
2
5
1
5
1
+
+
+
+
4
+
1
+
2
43
1996
27
26
+
+
+
13
2
5
1
5
1
h
+
+
+
4
+
1
1
2
45
1997
28
27
1
+
+
14
2
5
1
6
1
+
+
+
+
3
+
1
+
2
46
1998
29
27
1
1
+
14
2
5
1
6
1
+
+
+
+
3
+
1
+
1
46
1999
29
27
1
1
+
14
2
5
1
7
1
+
+
+
+
3
+
1
+
2
47
2000
30
29
1
1
+
14
2
5
1
6
1
+
+
+
+
3
+
1
+
2
48
2-24 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 2-17: NOX, CO, and NMVOC Emissions from
Stationary Combustion in 2000 (Gg)
Sector/Fuel Type
NOX
CO NMVOC
Electricity Generation
I Coal
i. Fuel Oil
'. Natural Gas
f Internal Combustion
• Industrial
I Coal
;• Fuel Oil
Natural Gas
F Other Fuels3
;, . Internal Combustion
Commercial
* Coal
I Fuel Oil
t Natural Gas
f Other Fuels3
= Residential
i Wood
Other Fuelsb
Total
4,763
4,149
140
320
154
2,924
493
207
1,137
112
976
376
34
73.
244
26
677
30
647
8,740
380
212
16
- 95
56
1,108
100
50
327
322
308
137
14
15
. 63
46
2,515
2,292
223
4,140
51
27
4
10
10
169
6
8
57
34
64
26
1
3
...1.4
9
843
812
31
1,089
MA (Not Available)
a "Other Fuels" include LPG, waste oil, coke oven gas, coke, and
non-residential wood (EPA 2001).
b "Other Fuels" include LPG, waste oil, coke oven gas, and coke
(EPA 2001).
Note: Totals may not sum due to independent rounding. See
Annex C for emissions in 1990 through 2000.
Uncertainty
Methane emission estimates from stationary sources
are highly uncertain, primarily due to difficulties in calculating
emissions from wood combustion (i.e., fireplaces and wood
stoves). The estimates of CH4 and N2O emissions presented
are based on broad indicators of emissions (i.e., fuel use
multiplied by an aggregate emission factor for different
sectors), rather than specific emission processes (i.e., by
combustion technology and type of emission control). The
uncertainties associated with the emission estimates of these
gases are greater than with estimates of CO2 from fossil fuel
combustion, which mainly rely on the carbon content of the
fuel combusted. Uncertainties in both CH4 and N2O estimates
are due to the fact that emissions are estimated based on
emission factors representing only a limited subset of
combustion conditions. For the ambient air pollutants,
uncertainties are partly due to assumptions concerning
combustion technology types, age of equipment, emission
factors used, and activity data projections.
Mobile Combustion (excluding C02)
Mobile combustion emits greenhouse gases other than
CO2, including methane (CH4), nitrous oxide (N2O), and the
ambient air pollutants carbon monoxide (CO), nitrogen oxides
(NOx), and non-methane volatile organic compounds
(NMVOCs). As with stationary combustion, N2O and NOx
emissions are closely related to fuel characteristics, air-fuel
mixes, combustion temperatures, as well as usage of pollution
control equipment. Nitrous oxide, in particular, can be formed
by the catalytic processes used to control NOx, CO, and
hydrocarbon emissions. Carbon monoxide emissions from
mobile combustion are significantly affected by combustion
efficiency and presence of post-combustion emission
controls. Carbon monoxide emissions are highest when air-
fuel mixtures have less oxygen than required for complete
combustion. These emissions occur especially in idle, low
speed and cold start conditions. Methane and NMVOC
emissions from motor vehicles are a function of the CH4
content of the motor fuel, the amount of hydrocarbons
passing uncombusted through the engine, and any post-
combustion control of hydrocarbon emissions, such as
catalytic converters.
Emissions from mobile combustion were estimated by
transport mode (e.g., highway, air, rail, and water) and fuel
type—motor gasoline, diesel fuel, jet fuel, aviation gas,
natural gas, liquefied petroleum gas (LPG), and residual fuel
oil—and vehicle type. Road transport accounted for the
majority of mobile source fuel consumption, and hence, the
majority of mobile combustion emissions. Table 2-18 through
Table 2-21 provide CH4 and N2O emission estimates from
mobile combustion by vehicle type, fuel type, and transport
mode. Estimates of NOx, CO, and NMVOC emissions in 2000
are given in Table 2-22.33
Mobile combustion was responsible for a small portion
of national CH4 emissions but was the second largest source
of N2O in the United States. From 1990 to 2000, CH4 emissions
declined by 11 percent, to 4.4 Tg CO2 Eq. (208 Gg). Nitrous
oxide emissions, however, rose 14 percent to 58.3 Tg CO2
Eq. (188 Gg) (see Figure 2-19). The reason for this conflicting
trend was that the control technologies employed on
highway vehicles in the United States lowered CO, NOx,
NMVOC, and CH4 emissions, but resulted in higher average
See Annex D for a complete time series of emission estimates for 1990 through 2000.
Energy 2-25
-------
Table 2-18: CH4 Emissionsfrom Mobile Combustion (Tg C02 Eq.)
Fuel Type/Vehicle Type 1990 * 1995
1996
1997
1998
1999
2000
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-DutyVehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
4.2
2.4
1.6
0.2
0.1
0.2
+
+
0.2
0.4
0.1
0.1
0.1
+
0.2
+
4.9
•
r-
1 **
„
T^ "
f
^ *.
!~ *~^~-
Sf
F
*
JL. -.J
&-•-.-•.»
t~r-
is't , ,-i,
4.1
2.0
1.8
0.1
0.1
0.3
+
+
0.3
0.4
0.1
0.1
0.1
+
0.1
+
4.8
3.9
2.0
1.7
0.1
0.1
0.3
+
+
0.3
0.4
0.1
0.1
0.1
+
0.1
+
4.7
3.8
1.9
1.7
0.1
0.1
0.3
+
+
0.3
0.4
0.1
0.1
0.1
+
0.2
+
4.6
3.8
1.9
1.6
0.1
0.1
0.3
+
+
0.3
0.4
0.1
+
0.1
+
0.1
+
4.5
3.7
1.9
1.6
0.1
0.1
0.3
+
+
0.3
0.4
0.1
+
0.1
+
0.2
+
4.4
3.6
1.9
1.5
0.1
0.1
0.3
+
+
0.3
0.5
0.1
0.1
0.1
+
0.2
+
4.4
+ Does not exceed 0.05 Tg C02 Eq.
Note; Totals may not sum due to independent rounding.
* "Other" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty diesel
powered utility equipment.
Table 2-19: M20 Emissions from Mobile Combustion (Tg C02 Eq.)
Fuel Type/Vehicle Type
1990
1995
1996
1997
1998 1999 2000
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Tola!
46.0
31.0
14.2
0.7
+
2.1
0.1
0.2
1.8
2.9
0.4
0.3
0.3
0.1
1.7
0.1
50.9
B 1
I
f !
1 1
1 :
i s
^ i
ft
I t
B" is
1 *
r
i- |
1 t
|" 1
Ft
• !
1 «
t ;-•
54.9
33.1
20.8
1.0
+
2.6
0.1
0.2
2.3
3.0
0.5
0.3
0.3
0.1
1.7
0.1
60.4
54.4
32.7
20.7
1.0
+
2.7
0.1
0.2
2.4
3.0
0.4
0.3
0.3
0.1
1.8
0.1
60.1
54.0
32.2
20.7
1.0
+
2.8
0.1
0.2
2.5
2.9
0.3
0.2
0.3
0.2
1.7
0.1
59.7
53.4
32.0
20.3
1.1
+
2.9
0.1
0.3
2.6
2.8
0.3
0.2
0.3
0.2
1.8
0.1
59.1
52.7
31.2
20.4
1.1
+
3.0
+
0.3
2.7
3.0
0.4
0.2
0.3
0.1
1.8
0.1
58.7
51.9
30.6
20.1
1.1
+
3.1
+
0.3
2.7
3.4
0.6
0.2
0.3
0.2
1.9
0.1
58.3
+ Does not exceed 0.05 Tg G02 Eq.
Note: Totals may not sum due to independent rounding.
* "Older" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty diesel
powered utility equipment.
2-26 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 2-20: CH4 Emissions from Mobile Combustion (Gg)
Fuel Type/Vehicle Type
1990
1995
1996
1997
1998
1999
2000
k Gasoline Highway
r Passenger Cars
| Light-Duty Trucks
' Heavy-Duty Vehicles
t Motorcycles
Diesel Highway
i Passenger Cars
r Light-Duty Trucks
: Heavy-Duty Vehicles
[_ Non-Highway
JT Ships and Boats
L Locomotives
( Farm Equipment
£ Construction Equipment
fc Aircraft
r Other*
f Total
202
115
74
9
4
11
+
+
10
21
3
3
6
1
7
T
233
LJ-l: . -. !
" Ep
ijjj££liisi&jf
??•' --' ' '
"
F**
.
- - jgaife-,;.i^"ff
193
96
86
7
4
13
+
+
13
21
4
3
6
1
7
1
228
188
94
83
6
4
13
+
+
13
21
. 4"
3
6
1
7
1
222
183
93
81
6
3
14
+
+
13
20
3
2
6
1
7
1
217
179
93
77
6
3
14
+
+
13
19
2
2
5
1
7
1
212
175
91
75
6
3
14
+
+
13
20
4
2
5
1
7
1
209
171
90
72
6
3
14
+
+
13
23
6
2
5
1
7
1
208
[+Does not exceed 0.5 Gg
;:_Note: Totals may not sum due to independent rounding.
1 * "Other" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty diesel
•• powered utility equipment.
Table 2-21: N20 Emissions from Mobile Combustion (Gg)
Fuel Type/Vehicle Type
1990
1995
1996
1997
1998
1999
2000
i," Gasoline Highway
;T Passenger Cars
\ Light-Duty Trucks
fr Heavy-Duty Vehicles
C Motorcycles
; Diesel Highway
I Passenger Cars
I- Light-Duty Trucks
t Heavy-Duty Vehicles
Non-Highway
'; Ships and Boats
! Locomotives
f. Farm Equipment
j Construction Equipment
E~ Aircraft
! Other*
Total
100 107
46 67
2 3
+ '" +
1
6
9
1
1
1
+
6
+
+
1
gfar--\.;.'.;^ 7
iffidis'f'H!
gr: :i, -|Q
1
ig^f 1
1
,
5
164 195
176
105
67
3
+
9
+
1
8
10
1
1
1
+
6
+
194
174
104
67
3
+
9
+
1
8
9
1
1
1
+
6
+
192
172
103
66
3
+
9
+
1
8
9
1
1
1
+
6
+
191
170
101
66
4
+
10
+
1
9
10
1
1
1
+
6
+
189
167
99
65
3
+
10
+
1
9
11
2
1
1
1
6
+
188
ir,
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding.
"Other" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty diesel
powered utility equipment.
Energy 2-27
-------
Table 2-22: NOX, CO, and NMVOC Emissions from
Figure 2-19
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft*
Other13
Total
NOX
4,388
2,519
1,459
398
12
3,004
6
4
2,994
7,549
1,041
704
815
1,114
76
3,799
14,941
CO
41,944
24,058
14,367
3,338
181
2,026
5
4
2,017
25,326
2,070
70
465
1,290
331
21,100
69,296
^^^^^^•; 7 T"~T" Mobile Source CH4 and N20 lmissiohT^i3i«
NMVOCs
4,333
2,500 ;
1,501
293 ;
38
236
2
2
232
3,069
833
27
93 ;
199
26
1,891
70 -,
60 -
50 -
uT 40 -
a
8 30 -
H5 20 -
10 -
o -I
N2O
^ — • : - __
- '
4
<§><£•$'<§>&<$>($><&<$><§><§>
»v>"v>*?>»$l>v>»?>»s!)»v>^»$>r£)
7,638
* Aircraft estimates include only emissions related to landing and
take-off (LTO) cycles, and therefore do not include cruise altitude
emissions.
b "Other" includes gasoline powered recreational, industrial, lawn and
garden, light commercial, logging, airport service, other equipment;
and diesel powered recreational, industrial, lawn and garden, light
construction, airport service.
Note: Totals may not sum due to independent rounding. See Annex
D for emissions from 1990 through 2000.
N2O emission rates. Fortunately, since 1994 improvements
in the emission control technologies installed on new
vehicles have reduced emission rates of both NOx and N2O
per vehicle mile traveled. Overall, CH4 and N2O emissions
were predominantly from gasoline-fueled passenger cars and
light-duty gasoline trucks.
Fossil-fueled motor vehicles comprise the single largest
source of CO emissions in the United States and are a
significant contributor to NOx and NMVOC emissions. In
2000, mobile combustion contributed to 74 percent of
national CO emissions and 60 and 43 percent of NOx and
NMVOC emissions, respectively. Since 1990, emissions of
NMVOCs from mobile combustion decreased by 6 percent,
while emissions of NOx increased by 37 percent. Carbon
monoxide emissions remained unchanged.
Methodology
Estimates for CH4 and N2O emissions from mobile
combustion were calculated by multiplying emission factors
by measures of activity for each category. Depending upon
the category, activity data included such information as fuel
consumption, fuel deliveries, and vehicle miles traveled
(VMT). Emission estimates from highway vehicles were
based on VMT and emission factors by vehicle type, fuel
type, model year, and control technology. Fuel consumption
data were employed as a measure of activity for non-highway
vehicles and then fuel-specific emission factors were
applied.34 A complete discussion of the methodology used
to estimate emissions from mobile combustion is provided
in Annex D.
EPA (2001) provided emissions estimates of NOx, CO,
and NMVOCs for eight categories of highway vehicles,35
aircraft, and seven categories of off-highway vehicles.36
M The consumption of international bunker fuels is not included in these activity data, but are estimated separately under the International
Bunker Fuels source category.
35 These categories included: gasoline passenger cars, diesel passenger cars, light-duty gasoline trucks less than 6,000 pounds in weight, light-
duty gasoline trucks between 6,000 and 8,500 pounds in weight, light-duty diesel trucks, heavy-duty gasoline trucks and buses, heavy-duty
diesel trucks and buses, and motorcycles.
These categories included: gasoline and diesel farm tractors, other gasoline and diesel farm machinery, gasoline and diesel construction
equipment, snowmobiles, small gasoline utility engines, and heavy-duty gasoline and diesel general utility engines.
2-28 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Data Sources
Emission factors used in the calculations of CH4 and N2O
emissions are presented in Annex D. The Revised 1996IPCC
Guidelines (IPCC/UNEP/OECD/DEA1997) provided emission
factors for CH4, and were developed using MOBILESa, a model
used by the Environmental Protection Agency (EPA) to estimate
exhaust and running loss emissions from highway vehicles.
The MOBILESa model uses information on ambient
temperature, vehicle speeds, national vehicle registration
distributions, gasoline volatility, and other variables in order to
produce these factors (EPA 1997).
Emission factors for N2O from gasoline passenger cars are
from EPA (1998). This report contains emission factors for older
passenger cars—roughly pre-1992 in California and pre-1994
in the rest of the United States—from published references,
and for newer cars from a recent testing program at EPA's
National Vehicle and Fuel Emissions Laboratory (NVFEL).
These emission factors for gasoline highway vehicles are lower
than the U.S. default values in the Revised 1996 IPC'C
Guidelines, but are higher than the European default values,
both of which were published before the more recent tests and
literature review conducted by the NVEEL. The U.S. default
values in the Revised 1996 IPCC Guidelines were based on
three studies that tested a total of five cars using European
rather than U.S. test protocols. More details may be found in
EPA(1998).
Nitrous oxide emission factors for gasoline vehicles other
than passenger cars (i.e., light-duty gasoline tracks, heavy-
duty gasoline vehicles, and motorcycles) were scaled from N2O
factors from passenger cars with the same control technology,
based on their relative fuel economy. Fuel economy for each
vehicle category was derived from data in DOE (1993 through
2001), (FHWA 1996 through 2001), (EPA, DOE 2001), and
(Census 1997). This scaling was supported by limited data
showing that light-duty trucks emit more N2O than passenger
cars with equivalent control technology. The use of fuel
consumption ratios to determine emission factors is considered
a temporary measure only, and will be replaced as additional
testing data become available.
Nitrous oxide emission factors for diesel highway
vehicles were taken from the European default values found
in the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/
IEA1997). Little data exists addressing N2O emissions from
U.S. diesel-fueled vehicles, and in general, European
countries have had more experience with diesel-fueled
vehicles. U.S. default values in the Revised 1996 IPCC
Guidelines were used for non-highway vehicles.
Activity data were gathered from several U.S.
government sources including BEA (1991 through 2001),
Census (1997), DESC (2001), DOC (1991 through 2001), DOT
(1991 through 2001), EIA (2001a), EIA (1991-2001), EIA
(2001c), EIA (2001e), EPA/DOE (2001), FAA(1995 through
2001), andFHWA (1996 through 20001). Control technology
and standards data for highway vehicles were obtained from
the EPA's Office of Transportation and Air Quality (EPA
1997 and 2000). These technologies and standards are
defined in Annex D, and were compiled from EPA (1993),
EPA(1994a), EPA(1994b), EPA(1998),EPA(1999), andlPCC/
UNEP/OECD/EA (1997). Annual VMT data for 1990 through
2000 were obtained from the Federal Highway
Administration's (FHWA) Highway Performance
Monitoring System database as reported in Highway
Statistics (FHWA 1996 through 20001).
Emissions estimates for NOx, CO, NMVOCs were taken
directly from the EPA (2001).
Uncertainty
Mobile combustion emissions from each vehicle mile
traveled can vary significantly due to assumptions
concerning fuel type and composition, technology type,
average speeds, type of emission control equipment,
equipment age, and operating and maintenance practices.
Fortunately, detailed activity data for mobile combustion
were available, including VMT by vehicle type for highway
vehicles. The allocation of this VMT to individual model
years was done using temporally variable profiles of both
vehicle usage by age and vehicle usage by model year in
the United States. Data for these profiles were provided by
EPA(2000).
Average emission factors were developed based on
numerous assumptions concerning the age and model of
vehicle; percent driving in cold start, warm start, and cruise
conditions; average driving speed; ambient temperature;
and maintenance practices. The factors for regulated
emissions from mobile combustion (i.e., CO, NO , and
hydrocarbons) have been extensively researched, and thus
involve lower uncertainty than emissions of unregulated
gases. Although CH4 has not been singled out for regulation
Energy 2-29
-------
in the United States, overall hydrocarbon emissions from
mobile combustion—a component of which is methane—
are regulated.
In calculating CH4 and N2O emissions from highway
vehicles, only data for Low Emission Vehicles (LEVs) in
California has been obtained. Data on the number of LEVs
in the rest of the United States will be researched and may
be included in future inventories.
Compared to CH4, CO, NOx, and NMVOCs, there is
relatively little data available to estimate emission factors
for N2O. Nitrous oxide is not a regulated air pollutant, and
measurements of it in automobile exhaust have not been
routinely collected. Research data has shown that N2O
emissions from vehicles with catalytic converters are greater
than those without emission controls, and vehicles with
aged catalysts emit more than new vehicles. The emission
factors used were, therefore, derived from aged cars (EPA
1998). The emission factors used for Tier 0 and older cars
were based on tests of 28 vehicles; those for newer vehicles
were based on tests of 22 vehicles. This sample is small
considering that it is being used to characterize the entire
U.S. fleet, and die associated uncertainty is therefore large.
Currently, N2O gasoline highway emission factors for
vehicles other than passenger cars are scaled based on those
for passenger cars and their relative fuel economy. Actual
measurements should be substituted for this procedure
when they become available. Further testing is needed to
reduce the uncertainty in emission factors for all classes of
vehicles, using realistic driving regimes, environmental
conditions, and fuels.
Overall, uncertainty for N2O emissions estimates is
considerably higher than for CH4, CO, NOx, or NMVOC;
however, all these gases involve far more uncertainty than
CO2 emissions from fossil fuel combustion.
U.S. jet fuel and aviation gasoline consumption is
currently all attributed to the transportation sector by EIA,
and it is assumed that it is all used to fuel aircraft. However,
some fuel purchased by airlines is not necessarily used in
aircraft, but instead used to power auxiliary power units, in
ground equipment, and to test engines. Some jet fuel may
also be used for other purposes such as blending with diesel
fuel or heating oil.
In calculating CH4 emissions from aircraft, an average
emission factor is applied to total jet fuel consumption. This
average emission factor takes into account the fact that CH4
emissions occur only during the landing and take-off (LTO)
cycles, with no CH4 being emitted during the cruise cycle.
While some evidence exists that fuel emissions in cruise
conditions may actually destroy CH4, the average emission
factor used does not take this into account.
Lastly, in EPA (2000b), U.S. aircraft emission estimates
for CO, NOx, and NMVOCs are based upon landing and
take-off (LTO) cycles and, consequently, only estimate near
ground-level emissions, which are more relevant for air
quality evaluations. These estimates also include both
domestic and international flights. Therefore, estimates
presented here overestimate IPCC-defined domestic CO,
NOx, and NMVOC emissions by including LTO cycles by
aircraft on international flights but underestimate total
emissions because they exclude emissions from aircraft on
domestic flight segments at cruising altitudes.
Coal Mining
All underground and surface coal mining liberates
methane as part of the normal mining operations. The amount
of methane liberated depends upon the amount that remains
in the coal ("in situ") and surrounding strata when mining
occurs. The in-situ methane content depends upon the
amount of methane created during the coal formation (i.e.,
coalification) process, and the geologic characteristics of
the coal seams. During coalification, deeper deposits tend
to generate more methane and retain more of the gas
afterwards. Accordingly, deep underground coal seams
generally have higher methane contents than shallow coal
seams or surface deposits.
Three types of coal mining related activities release
methane to the atmosphere: underground mining, surface
mining, and post-mining (i.e. coal-handling) activities.
Underground coal mines contribute the largest share of
methane emissions. All underground coal mines employ
ventilation systems to ensure that methane levels remain
within safe concentrations. These systems can exhaust
significant amounts of methane to the atmosphere in low
concentrations. Additionally, seventeen U.S. coal mines
2-30 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
supplement ventilation systems with degasification systems.
Degasification systems are wells drilled from the surface or
boreholes drilled inside the mine that remove large volumes
of methane before, during or after mining. In 2000, ten coal
mines collected methane from degasification systems and
sold this gas to a pipeline, thus reducing emissions to the
atmosphere. Surface coal mines also release methane as the
overburden is removed and the coal is exposed; however,
the level of emissions is much lower than from underground
mines. Finally, some of the methane retained in the coal after
mining is released during processing, storage, and transport
of the coal.
Total methane emissions in 2000 were estimated to be
61.0 Tg CO2 Eq. (2,903 Gg), declining 30 percent since 1990
(see Table 2-23 and Table 2-24). Of this amount, underground
mines accounted for 65 percent, surface mines accounted
for 14 percent, and post-mining emissions accounted for 21
percent. With the exception of 1994 and 1995, total methane
emissions declined in each successive year during this
period. In 1993, methane generated from underground mining
dropped, primarily due to labor strikes at many large
underground mines. In 1995, there was an increase in
methane emissions from underground mining due to
significantly increased emissions at the highest-emitting coal
mine in the country. The decline in methane emissions from
underground mines in 2000 is the result of a decrease in coal
production, the mining of less gassy coal, and an increase
in methane recovered and used. Surface mine emissions and
post-mining emissions remained relatively constant from 1990
to 2000.
Methodology
The methodology for estimating methane emissions
from coal mining consists of two parts. The first part
involves estimating methane emissions from underground
mines. Because of the availability of ventilation system
measurements, underground mine emissions can be
estimated on a mine-by-mine basis and then summed to
Table 2-23: CH4 Emissions from Coal Mining (Tg C02 Eq.)
Activity
1 Underground Mining
E: Liberated
!: Recovered & Used
Surface Mining
i Post-Mining (Underground)
;-. Post-Mining (Surface)
Total
: Note: Totals may not sum due to
1990
62.1
67.6
(5.6)
10.2
13.1
1.7
87.1
independent rounding.
2&J 1995
p| (12.0)
m -;-9
•i 1-
'•°
1LJ. 73.5
1996
45.3
59.8
(14.5)
9.2
12.4
1.5
68.4
1997
44.3
55.7
(11.4)
9.5
12.8
1.5
68.1
1998
44.4
58.6
(14.2)
9.4
12.6
1.5
67.9
1999
41.6
54.4
(12.7)
8.9
11.7
1.4
63.7
Table 2-24: CH4 Emissions from Coal Mining (Gg)
• Activity
J7 Underground Mining
T Liberated
^ Recovered & Used
L Surface Mining
S Post-Mining (Underground)
;= Post-Mining (Surface)
; Total
r_No_te:_ Totals may not sum due to
1990 ;
2,956 i
3,220 i
(265) j
488 i
626 I
79 !
m
i— 1995
K 2,439
3,012
Cj (574)
425
r : 559
fej 69
4,149 L— 3,502
independent rounding
1996
2,158
2,850
(692)
436
590
71
3,255
1997
2,111
2,654
(543)
.. 451 ..
609
73
3,244
1998
2,117
2,791
(674)
446
600
72
3,235
1999
1,982
2,589
(607)
424
557
69
3,033
2000
39.4
54.1
(14.7) :
8.8
11.3 ;
1.4
61.0
2000
1,877
2,575 .
(698)
420
538
68
2,903
Energy 2-31
-------
determine total emissions. The second step involves
estimating emissions from surface mines and post-mining
activities by multiplying basin-specific coal production by
basin-specific emissions factors.
Underground mines. Total methane emitted from
underground mines was estimated as the sum of methane
liberated from ventilation systems, plus methane liberated
by means of degasification systems, minus methane
recovered and used. The Mine Safety and Heath
Administration (MSHA) samples methane emissions from
ventilation systems for all mines with detectable37 methane
concentrations. These mine-by-mine measurements are used
to estimate methane emissions from ventilation systems.
Some of the higher-emitting underground mines also
use degasification systems (e.g., wells or boreholes) that
remove methane before, during, or after mining. This methane
can then be collected for use or vented to the atmosphere.
Various approaches were employed to estimate the quantity
of methane collected by each of the seventeen mines using
these systems, depending on available data. For example,
some mines report to EPA the amounts of methane liberated
from their degasification systems. For mines that sell
recovered methane to a pipeline, pipeline sales data were
used to estimate degasification emissions. For those mines
for which no other data are available, default recovery
efficiency values were developed, depending on the type of
degasification system employed.
Finally, the amount of methane recovered by
degasification systems and then used (i.e., not vented) was
estimated. This calculation was complicated by the fact that
most methane is not recovered and used during the same
year in which the particular coal seam is mined. In 2000, ten
active coal mines sold recovered methane into the local gas
pipeline networks. Emissions avoided for these projects were
estimated using gas sales data reported by various State
agencies. For most mines with recovery systems, companies
and state agencies provided individual well production
information, which was used to assign gas sales to a particular
year. For the few remaining mines, coal mine operators
supplied information regarding the number of years in
advance of mining that gas recovery occurs.
Surface Mines and Post-Mining Emissions. Surface
mining and post-mining methane emissions were estimated
by multiplying basin-specific coal production by basin-
specific emissions factors. Surface mining emissions factors
were developed by assuming that surface mines emit two
times as much methane as the average in situ methane
content of the coal. This accounts for methane released
from the strata surrounding the coal seam. For post-mining
emissions, the emission factor was assumed to be 32.5
percent of the average in situ methane content of coals mined
in the basin.
Data Sources
The Mine Safety and Health Administration provided
mine-specific information on methane liberated from
ventilation systems at underground mines. The primary
sources of data for estimating emissions avoided at
underground mines were gas sales data published by State
petroleum and natural gas agencies, information supplied
by mine operators regarding the number of years in advance
of mining that gas recovery occurred, and reports of gas
used on-site. Annual coal production data were taken from
the Energy Information Administration's Coal Industry
Annual (see Table 2-25) (EIA2000). Data on in situ methane
content and emissions factors are taken from EPA (1990).
Uncertainty
The emission estimates from underground ventilation
systems were based upon actual measurement data, which
are believed to have relatively low uncertainty. A degree of
imprecision was introduced because the measurements were
not continuous but rather an average of quarterly
instantaneous readings. Additionally, the measurement
equipment used possibly resulted in an average of ten
percent overestimation of annual methane emissions
(Mutmansky and Wang 2000). Estimates of methane liberated
and recovered by degasification systems are also relatively
certain because many coal mine operators provided
information on individual well gas sales and mined through
dates. Many of the recovery estimates use data on wells
within 100 feet of a mined area. Alevel of uncertainty currently
37 MSHA records coal mine methane readings with concentrations of greater than 50 ppm (parts per million) methane. Readings below this
threshold are considered non-detectable.
2-32 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
exists concerning the radius of influence of each well. The
number of wells counted, and thus the avoided emissions,
may Increase if the drainage area is found to be larger than
currently estimated. EPA is currently working to determine
the proper drainage radius and may include additional mines
in the recovery estimate in the future. Compared to
underground mines, there is considerably more uncertainty
associated with surface mining and post-mining emissions
because of the difficulty in developing accurate emissions
factors from field measurements. The EPA plans to update
the basin-specific surface mining emission factors.
Additionally, EPA plans to re-evaluate the post-mining
emission factors for the impact of methane not released
before combustion. Because underground emissions
comprise the majority of total coal mining emissions, the
overall uncertainty is preliminarily estimated to be roughly
±15 percent. Currently, the estimate does not include
emissions from abandoned coal mines because of limited
data. The EPA is conducting research on the feasibility of
including an estimate in future years.
Natural Gas Systems
The U.S. natural gas system encompasses hundreds of
thousands of wells, hundreds of processing facilities, and
over a million miles of transmission and distribution
pipelines. Overall, natural gas systems emitted 116.4 Tg CO2
Eq. (5,541 Gg) of methane in 2000, a slight decrease over
emissions in 1990 (see Table 2-26 and Table 2-27).
Table 2-25: Coal Production (Thousand Metric Tons)
lYear
£ - ~
11990
J 1991
IJ992
1-1993
r. 1994
I 1995
£."1996
t!997
f 1998
11999
N 200038
*
!"
!-
Underground
384,250
368,635
368,627
318,478
362,065
359,477
371,816
381,620
378,964
355,433
338,173
Surface
546,81 8
532,656
534,290
539,214
575,529
577,638
593,315
607,163
634,864
642,877
635,592
Total
931,068
901,291
902,917
857,692
937,594
937,115
965,131
988,783
1,013,828
998,310
973,765
Improvements in management practices and technology,
along with the normal replacement of older equipment, have
helped to stabilize emissions.
Methane emissions from natural gas systems are
generally process related, with normal operations, routine
maintenance, and system upsets being the primary
contributors. Emissions from normal operations include:
natural gas combusting engine and turbine exhaust, bleed
and discharge emissions from pneumatic devices, and
fugitive emissions from system components. Routine
maintenance emissions originate from pipelines, equipment,
and wells during repair and maintenance activities. Pressure
surge relief systems and accidents can lead to system upset
emissions. Below is a characterization of the four major
stages of the natural gas system. Each of the stages is
described and the different factors affecting methane
emissions are discussed.
Field Production. In this initial stage, wells are used to
withdraw raw gas from underground formations. Emissions
arise from the wells themselves, gathering pipelines, and
well-site gas treatment facilities such as dehydrators and
separators. Fugitive emissions and emissions from pneumatic
devices account for the majority of emissions. Emissions
from field production accounted for approximately 25 percent
of methane emissions from natural gas systems between
1990 and 2000.
Processing. In this stage, natural gas liquids and various
other constituents from the raw gas are removed, resulting
in "pipeline quality" gas, which is injected into the
transmission system. Fugitive emissions from compressors,
including compressor seals, are the primary emission source
from this stage. Processing plants account for about 12
percent of methane emissions from natural gas systems.
Transmission and Storage. Natural gas transmission
involves high pressure, large diameter pipelines that transport
gas long distances from field production and processing areas
to distribution systems or large volume customers such as
power plants or chemical plants. Compressor station facilities,
which contain large reciprocating and turbine compressors,
are used to move the gas throughout the United States
transmission system. Fugitive emissions from these compressor
stations and from metering and regulating stations account for
38 The EIA Coalndustry Annual 2000 was not yet available; however, EIA provided preliminary production statistics from MSHA (EIA
2001).
Energy 2-33
-------
Table 2-26: CH4 Emissions from Natural Gas Systems (Tg C02 Eq.)
Stage
Reid Production
Processing
Transmission and Storage
Distribution
Total
1990
29.6
14.7
46.7
30.2
121.2
tn
I-
s,«
I
a
.
4
i
1995
31.0
15.0
46.7
33.0
125.7
1996
30.9
14.9
47.1
33.6
126.6
1997
29.5
14.9
46.2
32.1
122.7
1998
31.7
14.6
45.1
30.8
122.2
1999
28.3
14.5
44.1
31.5
118.6
2000
26.2
14.8
43.3
32.0
116.4
Note: Totals may not sum due to independent rounding.
Table 2-27: CH4 Emissionsfrom Natural Gas Systems (Gg)
Stage 1990 £ " 1995
1996
1997
1998
Note: Totals may not sum due to independent rounding.
1999
2000
Reid Production
Processing
Transmission and Storage
Distribution
Total
1,407
702
2,223
1,440
5,772
fei.
l^ ..-.-..
= '
jj|-~
! "
i
;
^,
,,,^,
,
1,477
712
2,225
1,570
5,984
1,474
711
2,243
1,602
6,030
1,407
710
2,198
1,530
5,845
1,511
693
2,150
1,467
5,820
1,350
693
2,102
1,501
5,646
1,248
707
2,061
1,526
!5,541
the majority of the emissions from this stage. Pneumatic devices
and engine exhaust are also sources of emissions from
transmission facilities. Methane emissions from transmission
account for approximately 37 percent of the emissions from
natural gas systems.
Natural gas is also injected and stored in underground
formations during periods of low demand (e.g., summer),
and withdrawn, processed, and distributed during periods
of high demand (e.g., winter). Compressors and dehydrators
are the primary contributors to emissions from these storage
facilities. Approximately one percent of total emissions from
natural gas systems can be attributed to storage facilities.
Distribution. Distribution pipelines take the high-
pressure gas from the transmission system at "city gate"
stations, reduce the pressure and distribute the gas through
mains and service lines to individual end users. There were
over 1,043,000 miles of distribution mains in 2000, an increase
from just over 837,000 miles in 1990 (AGA1998). Distribution
system emissions, which account for approximately 25
percent of emissions from natural gas systems, resulted
mainly from fugitive emissions from gate stations and non-
plastic piping (cast kon, steel).39 An increased use of plastic
piping, which has lower emissions than other pipe materials,
has reduced the growth in emissions from this stage.
Distribution system emissions in 1999 were only slightly
higher than 1990 levels.
Methodology
The basis for estimates of methane emissions from the
U.S. natural gas industry is a detailed study by the Gas
Research Institute and EPA (EPA/GRI1996). The EPA/GRI
study developed over 100 emission and activity factors to
characterize emissions from the various components within
the operating stages of the U.S. natural gas system. The
study was based on a combination of process engineering
studies and measurements at representative gas facilities.
From this analysis, the EPA developed a 1992 base year
emissions estimate using the emission and activity factors.
For other years, the EPA has developed a set of industry
activity factor drivers that can be used to update activity
factors. These drivers include statistics on gas production,
number of wells, system throughput, miles of various kinds
of pipe, and other statistics that characterize the changes in
the U.S. natural gas system infrastructure and operations.
39 The percentages of total emissions from each stage may not add to 100 because of independent rounding.
2-34 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
The methodology also adjusts the emission factors to
reflect underlying technological improvement through both
innovation and normal replacement of equipment. For the
period 1990 through 1995, the emission factors were held
constant. Thereafter, emission factors are reduced at a rate
of 0.2 percent per year such that by 2020, emission factors
will have declined by 5 percent from 1995. Emission
reductions, as reported by EPA's Natural Gas STAR partners,
were also incorporated into the analysis. Emission reductions
associated with each stage of the natural gas system
(production, processing, transmission and distribution) were
subtracted from the corresponding total emissions estimates
for each operating stage. See Annex F for more detailed
information on the methodology and data used to calculate
methane emissions from natural gas systems.
Data Sources
Activity factor data were obtained from the following
sources: American Gas Association (AGA 1991 through
1999); Natural Gas Annual (EIA1999); Natural Gas Monthly
(EIA 2001); Oil and Gas Journal (PennWell Corporation
1999, 2000, 2001); Independent Petroleum Association of
America (IPAA 1998, 1999, 2000); and the Department of
Transportation's Office of Pipeline Safety (OPS 2001a,b).
The Minerals Management Service (DOI1998 through 2001)
supplied offshore platform data. All emission factors were
takenfromEPA/GRI (1996).
Uncertainty
The heterogeneous nature of the natural gas industry
makes it difficult to sample facilities that are completely
representative of the entire industry. Because of this, scaring
up from model facilities introduces a degree of uncertainty.
Additionally, highly variable emission rates were measured
among many system components, making the calculated
average emission rates uncertain. Despite the difficulties
associated with estimating emissions from this source, the
uncertainty in the total estimated emissions is preliminarily
believed to be on the order of ±40 percent.
Petroleum Systems
Methane emissions from petroleum systems are primarily
associated with crude oil production, transportation, and refining
operations. During each of these activities, methane is released
to the atmosphere as fugitive emissions, vented emissions,
emissions from operational upsets, and emissions from fuel
combustion. Methane emissions from petroleum systems in
2000 were 21.9 Tg CO2 Eq. (1,041 Gg). Since 1990, emissions
declined gradually, primarily due to a decline in domestic oil
production. (See Table 2-28 and Table 2-29.) The activities
associated with petroleum systems are detailed below.
Production Field Operations. Production field
operations account for approximately 97 percent of total
methane emissions from petroleum systems. Vented methane
from oil wells, storage tanks, and related production field
processing equipment account for the vast majority of the
emissions from production, with field storage tanks and
natural-gas-powered pneumatic devices being the dominant
sources. The emissions from storage tanks occur when the
methane entrained in crude oil under high pressure volatilizes
once the crude oil is dumped into storage tanks at
atmospheric pressure. The next most dominant sources of
vented emissions are chemical injection pumps and vessel
blowdown. The remaining emissions from production can
be attributed to fugitives and combustion.
Crude Oil Transportation. Crude transportation
activities account for approximately one-half percent of total
methane emissions from the oil industry. Venting from tanks
and marine vessel loading operations accounts for the
majority of methane emissions from crude oil transportation.
Fugitive emissions, almost entirely from floating roof tanks,
account for the remainder.
Crude Oil Refining. Crude oil refining processes and
systems account for only two percent of total methane
emissions from the oil industry because most of the methane
in crude oil is removed or escapes before the crude oil is
delivered to the refineries. Within refineries, vented
emissions account for about 87 percent of the emissions
from refining, while fugitive and combustion emissions
Energy 2-35
-------
Table 2-28: CH4 Emissionsfrom Petroleum Systems (Tg C02 Eq.)
Activity 1990 I
Production Field Operations 25.8 |
Tank venting 11.8 j
Pneumatic device venting 11.0 1
Wellhead fugitives 0.5 i
Combustion & process upsets 1.0 |
Misc. venting & fugitives 1 .4 j
Crude Oil Transportation 0.1 j
Refining 0.5 I
'"* 1995 1996
'- : 23.6 23.4
l;::f 10.4 10.2
li 1 10.4 10.4
j^ii 0.5 0.5
III 0.9 0.9
El 1-3 1-3
0.1 0.1
*' f 0.5 0.5
Total 26.4 £ " 24.2 24.0
1997
23.3
10.2
10.4
0.5
0.9
1.3
0.1
0.6
24.0
1998
22.7
9.8
10.2
0.5
0.9
1.3
0.1
0.6
23.4
1999
21.6
. 9.1
9.9
0.4
0.9
1.3
0.1
0.6
22.3
2000
21.2
8.9
9.7
0.4
0.9
1.3
0.1
0.6
21.9
Note: Totals may not sum due to independent rounding.
Table 2-29: CH4 Emissionsfrom Petroleum Systems (Gg)
Activity 1990 i
Production Field Operations 1,227 j
Tank venting 564
Pneumatic device venting 525
Wellhead fugitives 25
Combustion & process upsets 47
Misc. venting & fugitives 66 j
Crude Oil Transportation 7
Refining 25
Total 1,258 |
Mote: Totals may not sum due to independent rounding.
Cr?rl 1995 1996
/-™1| ^122 ^114
?TJ™ 493 485
S'" 1 497 496
ff'1 25 25
&S 44 45
££:! 63 63
'~'~~ t 6 6
-:1 25 26
r "1 1,154 1,145
1997
1,112
484
495
24
45
63
6
27
1,144
1998
1,081
466
485
23
44
63
6
27
1,114
1999
1,028
433
470
21
42
62
6
27
1,061
2000
1,008
425
460
20
42 -
61 :
5
28
1,041
account for approximately six percent each. Refinery system
falowdowns for maintenance and the process of asphalt
blowing—with air to harden it—are the primary venting
contributors. Most of the fugitive emissions from refineries
are from leaks in the fuel gas system. Refinery combustion
emissions accumulate from small amounts of unburned
methane in process heater stacks as well as from unburned
methane in engine exhausts and flares. The very slight
increase in emissions from refining, relative to the decline in
emissions from field production operations, is due to
increasing imports of crude oil.
Methodology
The methodology for estimating methane emissions from
petroleum systems is based on a comprehensive studies of
methane emissions from U.S. petroleum systems, Estimates of
Methane Emissions from the U.S. Oil Industry (Draft Report)
(EPA 1999) and Methane Emissionsfrom the U.S. Petroleum
Industry (Radian 1996). The studies estimated emissions from
70 activities occurring in petroleum systems from the oil
wellhead through crude oil refining, including 39 activities for
crude oil production field operations, 11 for crude oil
transportation activities, and 20 for refining operations. Annex F
explains the emission estimates for these 70 activities in greater
detail. The estimates of methane emissions from petroleum
systems do not include emissions downstream from oil refineries
because these emissions are very small compared to methane
emissions upstream from oil refineries.
The methodology for estimating methane emissions from
the 70 oil industry activities employs emission and activity
factors initially developed in EPA (1999) and Radian (1996).
Emissions were estimated for each activity by multiplying
emission factors (e.g., emission rate per equipment item or per
activity) by their corresponding activity data (e.g., equipment
count or frequency of activity). The report provides emission
factors and activity factors for all activities except those related
to offshore oil production. For offshore oil production, an
emission factor was calculated by dividing an emission estimate
from the Minerals Management Service (MMS) by the number
of platforms. Emission factors were held constant for the period
1990 through 2000.
2-36 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Activity data for 1990 through 2000 from a wide variety of
statistical resources. For some years, complete activity factor
data are not available. In these cases, the activity data was
evaluated in the same manner as in Radian (1996), by arithmetic
mean of component estimates based on annual oil production
and producing wells. Alternatively, the activity data was held
constant.
Annex F provides a more detailed discussion of the
methodology for petroleum systems.
Data Sources
Nearly all emission factors were takenfrom Radian (1996e).
Other emission factors were taken from an American Petroleum
Institute publication (API 1996), EPA default values, MMS
reports (MMS 1995 and 1999), the Exploration and Production
(E&P) Tank model (API and GRI), reports by the Canadian
Association of Petroleum Producers (CAPP 1992 and 1993),
and consensus of industry peer review panels.
Among the more important references used to obtain
activity data are Energy Information Administration annual and
monthly reports (EIA 1998, 2001), the API Basic Petroleum
Data Book (API 1997 and 1999), Methane Emissions from the
Natural Gas Industry prepared for the Gas Research Institute
(GRI) and EPA (Radian 1996a-d), consensus of industry peer
review panels, MMS reports (MMS 1995 and 1999), and the
Oil & Gas Journal (OGJ 2000a,b).
Uncertainty
There is uncertainty associated with the estimate of annual
venting emissions in production field operations because a
recent census of tanks and other tank battery equipment, such
as separators and pneumatic devices, were not available. These
uncertainties are significant because storage tanks and
pneumatic devices accounted for 85 percent of methane
emissions from petroleum systems. Emission rates can also
vary widely from reservoir to reservoir and well to well. A single
average emission factor cannot reflect this variation. Pneumatic
devices were estimated by assuming that the devices were a
function of number of heater/treaters and separators, and that
35 percent of the total pneumatic devices were high bleed and
65 percent were low bleed. These assumptions may overestimate
the numbers of high bleed pneumatic devices, and thus
overestimate emissions. Finally, because the majority of
methane emissions occur during production field operations,
where methane can first escape from crude oil, a better
understanding of tanks, tank equipment and vapor recovery
practices would reduce that uncertainty. Because of the
dominance of crude storage tank venting and pneumatics, Table
2-30 provides preliminary emission estimate ranges for these
sources. For tank venting, these ranges include numbers that
are 25 percent higher than or lower than the given point
estimates. For pneumatics, the range is between 33 percent
lower or 25 percent higher than the point estimates.
Municipal Solid Waste Combustion
Combustion is used to manage about 7 to 17 percent of
the municipal solid wastes (MSW) generated in the United
States (EPA2000c, Glenn 1999). Almost all combustion of
MSW in the United States occurs at waste-to-energy facilities
where energy is recovered, and thus emissions from waste
combustion are accounted for in the Energy chapter.
Combustion of MSW results in conversion of the organic
inputs to CO2. According to the IPCC Guidelines, when the
CO2 emitted is of fossil origin, it is counted as a net
anthropogenic emission of CO2 to the atmosphere. Thus,
the emissions from waste combustion are calculated by
estimating the quantity of waste combusted and the fraction
of the waste that is carbon derived from fossil sources.
Most of the organic materials in MSW are of biogenic
origin (e.g., paper, yard trimmings), and have their net carbon
flows accounted for under the Land-Use Change and
Forestry chapter (see Box 2-3). However, some
components—plastics, synthetic rubber, and synthetic
fibers—are of fossil origin. Plastics in the U.S. waste stream
are primarily in the form of containers, packaging, and
durable goods. Rubber is found in durable goods, such as
carpets, and in non-durable goods, such as clothing and
footwear. Fibers in MSW are predominantly from clothing
and home furnishings. Tires are also considered a "non-
hazardous" waste and are included in the MSW combustion
estimate, though waste disposal practices for tires differ
from the rest of MSW.
Energy 2-37
-------
Table 2-30: Uncertainty in CH4 Emissions from Production Field Operations (Gg)
Activity
Tank venting (point estimate)
Low
High
Pneumatic devices (point estimate)
Low
High
1990
564
423
705
525
352
656 !
SSit
1995
" . 493
?""! 370
^,"1 617
t. ,i 497
333
r"1 : 621
1996
485
364
606
496
332
620
1997
484
363
605
495
332
619
1998
466
349
582
485
325
606
1999
433
325
541
470
315
588
2000
425
319
531
460
308
575
It was estimated that approximately 24 million metric
tons of MS\V were combusted in the United States in 2000.
Carbon dioxide emissions from combustion of MSW rose
63 percent since 1990, to an estimated 22.5 Tg CO2 Eq. (22,470
Gg) in 2000, as the volume of plastics in MSW increased
(see Table 2-31 and Table 2-32). Waste combustion is also a
source of nitrous oxide (N2O) emissions (De Soete 1993).
Nitrous oxide emissions from MSW combustion were
estimated to be 0.3 Tg CO2 Eq. (1 Gg) in 2000, and have not
changed significantly since 1990.
Methodology
Emissions of CO2 from MSW combustion include CO2
generated by the combustion of plastics, synthetic fibers,
and synthetic rubber, as well as the combustion of synthetic
rubber and carbon black in tires. These emissions were
calculated by multiplying the amount of each material
combusted by the carbon content of the material and the
fraction oxidized (98 percent). Plastics combusted in MSW
were categorized into seven plastic resin types, each material
having a discrete carbon content. Similarly, synthetic rubber
is categorized into three product types; synthetic fibers were
categorized into four product types, each having a discrete
carbon content. Scrap tires contain several types of
synthetic rubber, as well as carbon black. Each type of
synthetic rubber has a discrete carbon content, and carbon
black is 100 percent carbon. Emissions of CO2 were calculated
based on the number of scrap tires used for fuel and the
synthetic rubber and carbon black content of the tires.
Combustion of municipal solid waste also results in
emissions of N,O. These emissions were calculated as a
function of the total estimated mass of MSW combusted
and an emission factor.
More detail on the methodology for calculating
emissions from each of these waste combustion sources is
provided in Annex H.
Data Sources
For each of the methods used to calculate CO emissions
from MSW combustion, data on the quantity of product
combusted and the carbon content of the product are needed.
It was estimated that approximately 24 million metric tons of
MSW were combusted in the United States in 2000, based
on an extrapolation of data from 1998 and earlier years (EPA
2000c, Glenn 1999). Waste combustion for 2000 was assumed
to be the same as for 1999. For plastics, synthetic rubber,
and synthetic fibers, the amount of material in MSW and its
portion combusted was taken from the Characterization of
Municipal Solid Waste in the United States.(EPA 2000c).
For synthetic rubber and carbon black in scrap tires, this
information was provided by the Scrap Tire Use/Disposal
Study 1998/1999 Update (STMC 1999) and the Scrap Tires,
Facts and Figures (STMC 2000).
Average carbon contents for the "Other" plastics
category, synthetic rubber in scrap tires, synthetic rubber in
MSW, and synthetic fibers were calculated from recent
production statistics which divide their respective markets
by chemical compound. The plastics production data set
was taken from the website of the American Plastics Council
(APC 2000); synthetic rubber production was taken from
the website of the International Institute of Synthetic Rubber
Producers (IISRP 2000); and synthetic fiber production was
taken from the website of the Fiber Economics Bureau (FEB
2000). Personal communications with the APC (Eldredge-
Roebuck 2000) and the FEB (DeZan 2000) validated the
website information. All three sets of production data can
also be found in Chemical and Engineering News, "Facts &
Figures for the Chemical Industry." Lastly, information about
scrap tire composition was taken from the Scrap Tire
Management Council's Internet web site entitled "Scrap Tire
Facts and Figures" (STMC 2000).
2-38 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Box 2-3: Biogenic Emissions and Sinks of Carbon
For many countries, C02 emissions from the combustion or degradation of biogenic materials are important because of the significant
amount of energy they derive from biomass (e.g., burning fuelwood). The fate of biogenic materials is also important when evaluating waste
management emissions (e.g., the decomposition of paper). The carbon contained in paper was originally stored in trees during photosyn- ]
thesis. Under natural conditions, this material would eventually degrade and cycle back to the atmosphere as C02. The quantity of carbon
that these degradation processes cycle through the Earth's atmosphere, waters, soils, and biota is much greater than the quantity added by l
anthropogenic greenhouse gas sources. But the focus of the United Nations Framework Convention on Climate Change is on anthropo-
genic emissions—emissions resulting from human activities and subject to human control—because it is these emissions that have the
potential to alter the climate by disrupting the natural balances in carbon's biogeochemical cycle, and enhancing the atmosphere's natural
greenhouse effect.
Carbon dioxide emissions from biogenic materials (e.g., paper, wood products, and yard trimmings) grown on a sustainable basis are
considered to mimic the closed loop of the natural carbon cycle—that is, they return to the atmosphere C02 that was originally removed by
photosynthesis. However, CH4 emissions from landfilled waste occur due to the man-made anaerobic conditions conducive to CH4
formation that exist in landfills, and are consequently included in this Inventory.
The removal of carbon from the natural cycling of carbon between the atmosphere and biogenic materials—which occurs when
wastes of biogenic origin are deposited in landfills—sequesters carbon. When wastes of sustainable, biogenic origin are landfilled, and do ;
hot completely decompose, the carbon that remains is effectively removed from the global carbon cycle. Landfilling of forest products and
yard trimmings results in long-term storage of 154 Tg C02 Eq. and 13 Tg C02 Eq. on average per year, respectively. Carbon storage that
results from forest products and yard trimmings disposed in landfills is accounted for in the Land-Use Change and Forestry chapter, as
recommended in the Revised 1996IPCC Guidelines (IPCC/UNEP/OECD/IEA1997) regarding the tracking of carbon flows.
Table 2-31: C02 and N20 Emissions from Municipal Solid Waste Combustion (Tg C02 Eq.)
""""•""'"'."" ""~ ~" ----- - — --' ,--.,,.-:-.--- -.-.-...- . -.„ _ , ...... . ..„ .__
f Gas/Waste Product 1990 £ " 1995 1996 1997 1998
Table 2-32: C02 and N20 Emissions from Municipal Solid Waste Combustion (Gg)
Gas/Waste Product 1990 1995 1996 1997
1998
1999
1999
2000
C02
Plastics
Synthetic Rubber in Tires
Carbon Black in Tires
Synthetic Rubber in MSW
Synthetic Fibers
N20
Total
—
14.1 fc^r
10.3
0.3 jfar—i
°-4
1.6
IP ife*"' -'" ' j§
•5
0.3 j^^.
14.4 g"™
"^* - — Hfc_.«
18.6
11.1
1.5
2.4
1.7
1.9
0.3
18.9
19.6
11.5
1.7
2.7
1.7
2.0
0.3
19.8
21.3
12.5
1.9
3.0
1.8
2.1
0.3
21.6
20.3
12.9
1.3
2.0
1.8
2.2
0.2
20.5
21.8
13.3
1.7
2.7
1.9
2.3
0.2
22.1
22.5
13.7
1.8
2.8
1.9
2.3
0.2
22.7
2000
coz
*— Plastics
k-
_
Synthetic Rubber in Tires
Carbon Black in Tires
Synthetic Rubber in MSW
Synthetic Fibers
N20
14
10
1
1
,014 c£, ;
,320 fir?^
253
399 StvrT ?|
,584
,535
1 \^^:- ,_,,.
18,608
11
1
2
1
1
,077
,507
,377
,708
,938
1
19,569
11,459
1,689
2,666
1,737
2,018
1
21,344
12,484
1,906
3,006
1,807
2,141
1
20,251
12,929
1,263
1,993
1,833
2,233
1
21
,843
13,297
1
2
1
2
,703
,687
,870
,285
1
22,470
13,653
1,771
2,795
1,905
2,346
1
Energy 2-39
-------
The use of the value 98 as the fraction of carbon
oxidized, which applies to all municipal solid waste
combustion categories for CO2 emissions, was reported in
the EPA's life cycle analysis of greenhouse gas emissions
and sinks from management of solid waste (EPA 1998).
The N O emission estimates are based on different data
sources. The N O emissions are a function of total waste
2
combusted, as reported in the November 2000 issue of
BioCyclc (Goldstein N. and C. Matdes 2000). Table 2-33
provides MSW generation and percentage combustion data
for the total waste stream. The emission factor of N O
emissions per quantity of MSW combusted was taken from
Olivier (1993).
Table 2-33: Municipal Solid Waste Generation (Metric
Tons) and Percent Combusted
Uncertainty
Uncertainties in the waste combustion emission
estimates arise from both the assumptions applied to the
data and from the quality of the data.
• MSW Combustion Rate. A source of uncertainty
affecting both fossil CO2 and N2O emissions is the
estimate of the MSW combustion rate. The EPA (2000c)
estimates of materials generated, discarded, and
combusted carry considerable uncertainty associated
with the material flows methodology used to generate
them. Similarly, BioCycle (Glenn 1999, Goldstein and
Matdes 2000) estimate of total waste combustion —
used for the N2O emissions estimate—is based on a
survey of State officials, who use differing definitions
of solid waste and who draw from a variety of sources
of varying reliability and accuracy. Despite the
differences in methodology and data sources, the two
references—the EPA's Office of Solid Waste (EPA2000c)
and BioCycle (Glenn 1999, Goldstein and Matdes
2000)—provide estimates of total solid waste combusted
that are relatively consistent (see Table 2-34).
• Fraction Oxidized. Another source of uncertainty for
the CO2 emissions estimate is fraction oxidized.
Municipal waste combustors vary considerably in their
efficiency as a function of waste type, moisture content,
combustion conditions, and other factors. The value of
98 percent assumed here may not be representative of
typical conditions.
• Use of 1998 Data on MSW Composition. Emissions
have been calculated from activity that has been
Year
1990
1991
1992
1993
1994
1995
1996
"1997
1998
1999
2000
Waste Generation
266,541,881
254,796,765
264,843,388
278,572,955
293,109,556
296,586,430
297,268,188
309,075,035
340,090,022
347,318,833
347,318,833
Combusted (%)
11.5
10.0
11.0
10.0
10.0
10.0
10.0
9.0 '
7.5
7.0
7.0
extrapolated from reported 1998 values using average
annual growth rates. In addition, the ratio of landfilling
to combustion was assumed to be constant for the entire
period (1990 to 2000) based on the 1998 ratio (EPA2000c).
Average Carbon Contents. Average carbon contents
were applied to the mass of "Other" plastics combusted,
synthetic rubber in tires and MSW, and synthetic fibers.
These average values were estimated from the average
carbon content of the known products recently
produced. The true carbon content of the combusted
waste may differ from this estimate depending on
differences in the formula between the known and
unspecified materials, and differences between the
composition of the material disposed and that produced.
For rubber, this uncertainty is probably small since the
major elastomers' carbon contents range from 77 to 91
percent; for plastics, where carbon contents range from
29 to 92 percent, it may be more significant. Overall, this
is a small source of uncertainty.
Synthetic/Bio genie Assumptions. A portion of the fiber
and rubber in MSW is biogenic in origin. Assumptions
have been made concerning the allocation between
synthetic and biogenic materials based primarily on
expert judgment.
Combustion Conditions Affecting N2O Emissions.
Because insufficient data exist to provide detailed
estimates of N2O emissions for individual combustion
facilities, the estimates presented are highly uncertain.
The emission factor for N2O from MSW combustion
facilities used in the analysis is a default value used to
2-40 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 2-34: U.S. Municipal Solid Waste Combusted by
Data Source (Metric Tons)
* Year
fel990
': 1991
'-' 1992
: 1993
1:1994
i-1995
1996
1997
^1998
1999
2000
£• NA (Not Available)
EPA
28,939,680
30,236,976
29,656,638
29,865,024
29,474,928
32,241,888
32,740,848
32,294,240
31,218,818
30,945,455
NA :.„
BioCycIe
30,652,316
25,479,677
29,132,773
27,857,295
29,310,956
29,658,643
29,726,819
27,816,753
25,506,752
NA
.._„.,.. ,„.., ...NA... .
.- -..v--:-".-.- •--.-*; -..-
estimate N2O emissions from facilities worldwide (Olivier
1993). As such, it has a range of uncertainty that spans
an order of magnitude (between 25 and 293 g N2O/metric
ton MSW combusted) (Watanabe, et al. 1992). Due to a
lack of information on the control of N2O emissions
from MSW combustion facilities in the United States,
the estimate of zero percent for N2O emissions control
removal efficiency is also uncertain.
Natural Gas Flaring and Ambient
Air Pollutant Emissions from
Oil and Gas Activities
The flaring of natural gas from oil wells is a small source
of carbon dioxide (CO2). In addition, oil and gas activities
also release small amounts of nitrogen oxides (NOx), carbon
monoxide (CO), and nonmethane volatile organic
compounds (NMVOCs). This source accounts for only a
small proportion of overall emissions of each of these gases.
Emissions of NOx, and CO from petroleum and natural gas
production activities were both less than 1 percent of
national totals, while NMVOC and SO2 emissions were
roughly 2 percent of national totals.
Carbon dioxide emissions from petroleum production
result from natural gas that is flared (i.e., combusted) at the
production site. Barns and Edmonds (1990) noted that of
total reported U.S. venting and flaring, approximately 20
percent may be vented, with the remaining 80 percent flared;
however, it is now believed that flaring accounts for an even
greater proportion, although some venting still occurs.
Methane emissions from venting are accounted for under
Petroleum Systems. For 2000, CO2 emissions from flaring
were estimated to be approximately 6.1 Tg CO2 Eq. (6,059
Gg), an increase of 10 percent since 1990 (see Table 2-35).
Ambient air pollutant emissions from oil and gas
production, transportation, and storage, constituted a
relatively small and stable portion of the total emissions of
these gases from the 1990 to 2000 (see Table 2-36).
Methodology
Estimates of CO2 emissions were prepared using an
emission factor of 54.71 Tg CO2 Eq./QBtu of flared gas, and
an assumed flaring efficiency of 100 percent.
Ambient air pollutant emission estimates for NO , CO,
and NMVOCs were determined using industry-published
production data and applying average emission factors.
Data Sources
Total natural gas vented and flared was taken from EIA's
Natural Gas Annual (EIA 2001). It was assumed that all
reported vented and flared gas was flared. This assumption
is consistent with that used by EIA in preparing their
emission estimates, under the assumption that many states
require flaring of natural gas (EIA 2000b).
There is a discrepancy in the time series for natural gas
vented and flared as reported in EIA (2001). One facility in
Wyoming had been incorrectly reporting CO2 vented as CH4.
EIA has corrected these data in the Natural Gas Annual
(EIA2001a) for the years 1998 and 1999 only. Data for 1990
through 1997 were adjusted by assuming a proportionate
share of CO2 in the flare gas for those years as for 1998 and
1999. The adjusted values are provided in Table 2-37. The
emission and thermal conversion factors were also provided
by EIA (2001) and are included in Table 2-37.
Energy 2-41
-------
Table 2-35: G02 Emissions from Natural Gas Flaring Indirect C02 from CH4 Oxidation
Year
1990
1995
1996
1997
1998
1999
2000
Tg C02 Eq.
5.5
~— -— -
8.2
7.6
6.3
6.7
6.1
Gg
5,514
87729
8,233
7,565
6,250
6,679
6,059
EPA (2001) provided emission estimates for NOx, CO,
and NMVOCs from petroleum refining, petroleum product
storage and transfer, and petroleum marketing operations.
Included are gasoline, crude oil and distillate fuel oil storage
and transfer operations, gasoline bulk terminal and bulk
plants operations, and retail gasoline service stations
operations.
Uncertainty
Uncertainties in CO2 emission estimates primarily arise
from assumptions concerning the flaring efficiency and the
correction factor applied to 1990-1997 venting and flaring
data. Uncertainties in ambient air pollutant emission estimates
are partly due to the accuracy of the emission factors used
and projections of growth.
Indirect CO2 emissions are formed in the atmosphere
from the oxidation of methane (CH4). Although this indirect
CO2 is a greenhouse gas, its generation is not accounted for
within the global warming potential (GWP) of CH4. Thus for
the sake of completion, it is necessary to account for these
indirect emissions whenever anthropogenic sources of CH4
are calculated.
Indirect CO2 emissions from CH4 oxidation originating
from non-combustion fossil sources—coal mining, natural
gas systems, petroleum systems, petrochemical production,
and silicon carbide production—are included in this
estimate. Methane is also emitted from stationary and mobile
combustion sources (e.g., natural gas-fired boilers, gasoline
fueled vehicles), and from several managed biological
Table 2-36: NOX, NMVOCs, and CO Emissions from
Oil and Gas Activities (Gg)
Year
1990
fe"
1995
1996
L1997 . -
" 1998
1999
2000
-
NO,
139
— , , ""I ,
100
126
130
130
130
132
CO
302
m
316
321
333
332
332
335
NMVOCs
555
•Tn *J*mu^*A
582
433
442
440
385
393
Table 2-37: Total Natural Gas Reported Vented and Flared (Million Ft?) and Thermal Conversion Factor (Btu/Ft3)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
" Wyoming venting
Vented and Flared (original)
150,415
169,909
167,519
226,743
228,336
283,739
272,117
256,351
103,019
110,285
100,048
and flaring estimates were revised. See text for further
Vented and Flared (revised)*
91,130
92,207
83,363
108,238
109,493
144,265
135,709
124,918
103,019
110,285
100,048
explanation.
Thermal Conversion Factor
1,106
1,108
1,110
1,106
1,105
1,106
1,109
1,107
1,109
1,107
1,107
2-42 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
systems (e.g., livestock, rice cultivation), but CO2 produced
through oxidation of CH4 from these sources is excluded
because:
• Indirect CO2 emissions from CH4 emitted by combustion
sources are accounted for within the Carbon Dioxide
from Fossil Fuel Combustion section in the assumption
that all carbon containing gaseous combustion products
are eventually oxidized to CO2 in the atmosphere (see
Annex A).
• Methane from biological systems is derived from rapidly
cycling (non-fossil) sources. For example, the carbon
content of methane from enteric fermentation is derived
from plant matter, which has converted atmospheric CO2
to organic compounds. Anthropogenic activity (e.g.,
management of a biological system) converts the
atmospheric CO2 to CH4 and thus is counted in the
Inventory. The subsequent atmospheric oxidation of
CH4 merely completes the natural cycle.
In addition to oxidation of CH4, indirect CO2 emissions can
also result from emissions of carbon monoxide (CO) and non-
rnethane volatile organic compounds (NMVOCs). However,
CO2 from non-combustion emissions of CO and NMVOCs are
not included in this section because they are explicitly included
in the mass balance used in calculating the storage and
emissions from non-energy uses of fossil fuels, with the carbon
components of CO andNMVOC counted as CO2 emissions in
the mass balance. Thus, it would be double-counting to include
them in the indirect CO2 emissions estimates presented in this
section.40 If reported separately, indirect CO2 emissions from
applicable CO and NMVOC sources—primarily from industrial
processes and solvent use—would be 31.1 and 28.1 Tg of CO2
in 2000.
Total CH4 emissions from non-combustion fossil sources,
gathered from the respective sections of this Inventory, are
presented in Table 2-38. Indirect CO2 emissions from those
sources are summarized in Table 2-39 and Table 2-40.
Methodology
Indirect emissions of CO2 are calculated by applying a
factor of 44/16, which is the ratio of molecular weight of CO2
to the molecular weight of CH4, to the appropriate methane
emissions. The methodology for calculating the methane
emissions is presented within the respective sections of
this Inventory. For the purposes of the calculation, it is
assumed that CH4 emitted to the atmosphere from non-
combustion fossil processes is oxidized to CO2 in the same
year that it is emitted. This is a simplification, because the
average atmospheric lifetime of methane is actually on the
order of 12 years.
The IPCC Guidelines for Greenhouse Gas Inventories
(IPCC/UNEP/OECD/1EA1997) makes passing references to
issues of "double counting carbon" in estimating CO2
emissions from fossil fuel combustion. In one case, by
double counting, the IPCC is referring to the fact that some
carbon during the combustion is actually emitted as CH4,
CO, and NMVOCs. The IPCC also assumes that the carbon
in these compounds is assumed to eventually oxidizes to
CO2 in the atmosphere. Therefore in the case of emissions
from fossil fuel combustion, the carbon is intentionally
double counted (e.g., once as an atom in a CH4 molecule and
once in a CO2 molecule) in order to develop a more
comprehensive estimate of the long-term CO2 burden in the
atmosphere and the radiative forcing effects of fossil fuel
combustion emissions.
Table 2-38: CH4 Emissions from Non-Combustion Fossil Sources (Gg)
tJJource
t Coal Mining
^Natural Gas Systems
1 Petroleum Systems
J Petrochemical Production
^Silicon Carbide Production
if Total
1990
4,149
5,772
1,258
56
1
11,236
f*3.
1995
3,502
5,984
1,154
72
1
10,712
1996
3,255
6,030
1,145
75
1
10,506
1997
3,244
5,845
1,144
77
1
10,311
1998
3,235
5,820
1,114
78
1
10,248
1999
3,033
5,646
1,061
79
1
9,820
2000
2,903 :
5,541 :
1,041
79 .:
9,564
jTNote: These emissions are accounted for under their respective source categories. Totals may not sum due to independent rounding.
40 See Annex B for a more detailed discussion on accounting for indirect emissions from CO and NMVOCs.
Energy 2-43
-------
Table 2-39: Indirect C02 Emissionsfrom Non-Combustion Fossil Methane Sources (Gg)
Source
Coal Mining
Natural Gas Systems
Petroleum Systems
Petrochemical Production
Silicon Carbide Production
Total
1990
11,409
15,873
3,460
153
3
30,899
1
•*- -
|_
sT
fc,
i:
~~i
|
1
f
I
. f
1
1995
9,630
16,456
3,173
197
2
29,458
1996
8,951
16,581
3,149
207
2
28,891
1997
8,922
16,073
3,146
211
2
28,354
1998
8,897
16,005
3,063
215
2
28,183
1999
8,340
15,527
2,917
218
2
27,004
2000
7,984
15,237
2,862
217
1
215,302
Note: Totals may not sum due to independent rounding.
Table 2-40: Indirect CO, Emissionsfrom Non-Combustion Fossil Methane Sources (Tg C02
Source
Coal Mining
Natural Gas Systems
Petroleum Systems
Petrochemical Production
Silicon Carbide Production
Total
1990
11.4
15.9
3.5
0.2
+
30.9
fcu *
ftilf
pi-.f
F" :' '"'
B, <
1995
9.6
16.5
3.2
0.2
+
29.5
1996
9.0
16.6
3.1
0.2
+
28.9
1997
8.9
16.1
3.1
0.2
+
28.4
1998
8.9
16.0
3.1
0.2
+
28.2
1999
8.3
15.5
2.9
0.2
+
27.0
2000
8.0
15.2
2.9
0.2
+
26.3
Note; Totals may not sum due to independent rounding.
+ Does not exceed 0.05 Tg G02 Eq.
The IPCC, though, points out that this approach misses
the indirect CO2 emitted from sources other than fossil fuel
combustion, such as venting of CH4 from natural gas and
petroleum systems and coal mines. It also misses biogenic
sources of CH4, CO and NMVOCs, such as enteric
fermentation in ruminant livestock and decomposition of
organic wastes in landfills. The exclusion of biogenic
emissions is appropriate, however, given the cyclical nature
and probable net zero effect on the atmospheric CO2 burden.
It should be noted that the climate forcing caused by
CO2 produced from the oxidation of CH4 is not included in
these GWP estimates. As discussed hi IPCC (1996), it is
often the case that this CO2 is included in national carbon
production inventories. Therefore, depending on how the
inventories are combined, including CO2 production from
CH4 could result in double counting this CO2 (IPCC 2001).
Data Sources
Data sources for estimating methane emissions from
non-combustion processes are summarized in other sections
of this Inventory. Methane emissions from coal mining,
natural gas systems, and petroleum systems are summarized
in this chapter and described in detail in Annexes E, F, and G,
respectively. Methane emissions from petrochemicals
production and from silicon carbide production are discussed
in the Industrial Processes chapter.
Uncertainty
The two principal sources of uncertainty in the estimate
of indirect CO2 emissions are the extent to which methane
emissions are included in the overall carbon emissions
calculated as CO2 for combustion sources, and the time frame
in which the methane is assumed to oxidize to CO2 once
emitted to the atmosphere. It is assumed that 100 percent of
the methane emissions from combustion sources are
accounted for in the overall carbon emissions calculated as
CO2 for sources using emission factors and carbon mass
balances. However, it may be the case for some types of
combustion sources that the oxidation factors used for
calculating CO2 emissions do not accurately account for the
full mass of carbon emitted in gaseous form (i.e., partially
oxidized or still in hydrocarbon form). Also, the indirect CO2
emission calculation is based on the assumption that the
methane is completely oxidized to CO2in the same year that
it is emitted to the atmosphere, but its average atmospheric
lifetime is approximately 12 years.
2-44 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
International Bunker Fuels
Emissions resulting from the combustion of fuels used
for international transport activities, termed international
bunker fuels under the United Nations Framework
Convention on Climate Change (UNFCCC), are currently not
included in national emission totals, but are reported
separately based upon location of fuel sales. The decision
to report emissions from international bunker fuels
separately, instead of allocating them to a particular country,
was made by the Intergovernmental Negotiating Committee
in establishing the Framework Convention on Climate
Change.41 These decisions are reflected in the Revised 1996
IPCC Guidelines, in which countries are requested to report
emissions from ships or aircraft that depart from their ports
with fuel purchased within national boundaries and are
engaged in international transport separately from national
totals CEPCC/UNEP/OECD/EEA1997).42
Greenhouse gases emitted from the combustion of
international bunker fuels, like other fossil fuels, include
carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O),
carbon monoxide (CO), oxides of nitrogen (NOx), non-
methane volatile organic compounds (NMVOCs), particulate
matter, and sulfur dioxide (SO2).43 Two transport modes are
addressed under the IPCC definition of international bunker
fuels: aviation and marine. Emissions from ground transport
activities—by road vehicles and trains—even when
crossing international borders are allocated to the country
where the fuel was loaded into the vehicle and, therefore,
are not counted as bunker fuel emissions.
The IPCC Guidelines distinguish between different
modes of air traffic. Civil aviation comprises aircraft used for
the commercial transport of passengers and freight, military
aviation comprises aircraft under the control of national
armed forces, and general aviation applies to recreational
and small corporate aircraft. The IPCC Guidelines further
define international bunker fuel use from civil aviation as
the fuel combusted for civil (e.g., commercial) aviation
purposes by aircraft arriving or departing on international
flight segments. However, as mentioned above, and in
keeping with the IPCC Guidelines, only the fuel purchased
in the United States and used by aircraft taking-off (i.e.,
departing) from the United States are reported here. The
standard fuel used for civil aviation is kerosene-type jet
fuel, while the typical fuel used for general aviation is aviation
gasoline.44
Emissions of CO2 from aircraft are essentially a function
of fuel use. Methane, N2O, CO, NOx, andNMVOC emissions
also depend upon engine characteristics, flight conditions,
and flight phase (i.e., take-off, climb, cruise, decent, and
landing). Methane, CO, and NMVOCs are the product of
incomplete combustion and occur mainly during the landing
and take-off phases, hi jet engines, N2O and NOx are primarily
produced by the oxidation of atmospheric nitrogen, and the
majority of emissions occur during the cruise phase. The
impact of NOx on atmospheric chemistry depends on the
altitude of the actual emission. The cruising altitude of
supersonic aircraft, near or in the ozone layer, is higher than
that of subsonic aircraft. At this higher altitude, NOx
emissions contribute to stratospheric ozone depletion.45 At
the cruising altitudes of subsonic aircraft, however, NO
emissions contribute to the formation of tropospheric ozone.
At these lower altitudes, the positive radiative forcing effect
of ozone has enhanced the anthropogenic greenhouse gas
forcing.46 The vast majority of aircraft NOx emissions occur
at these lower cruising altitudes of commercial subsonic
aircraft (NASA 1996).47
International marine bunkers comprise emissions from
fuels burned by ocean-going ships of all flags that are
engaged in international transport. Ocean-going ships are
See report of the Intergovernmental Negotiating Committee for a Framework Convention on Climate Change on the work of its ninth
session, held at Geneva from 7 to 18 February 1994 (A/AC.237/55, annex I, para. Ic) (contact secretariat@unfccc.de).
42 Note that the definition of international bunker fuels used by the UNFCCC differs from that used by the International Civil Aviation
Organization.
Sulfur dioxide emissions from jet aircraft and marine vessels, although not estimated here, are mainly determined by the sulfur content of
the fuel. In the U.S., jet fuel, distillate diesel fuel, and residual fuel oil average sulfur contents of 0.05, 0.3, and 2.3 percent, respectively.
These percentages are generally lower than global averages.
44 Naphtha-type jet fuel was used in the past by the military in turbojet and turboprop aircraft engines.
In 1996, there were only around a dozen civilian supersonic aircraft in service around the world which flew at these altitudes, however.
46 However, at this lower altitude, ozone does little to shield the earth from ultraviolet radiation.
47 Cruise altitudes for civilian subsonic aircraft generally range from 8.2 to 12.5 km (27,000 to 41,000 feet).
Energy 2-45
-------
generally classified as cargo and passenger carrying,
military (i.e., Navy), fishing, and miscellaneous support ships
(e.g., tugboats). For the purpose of estimating greenhouse
gas emissions, international bunker fuels are solely related
to cargo and passenger carrying vessels, which is the largest
of the four categories, and military vessels. Two main types
of fuels are used on sea-going vessels: distillate diesel fuel
and residual fuel oil. Carbon dioxide is the primary
greenhouse gas emitted from marine shipping. In comparison
to aviation, the atmospheric impacts of NOx from shipping
are relatively minor, as the emissions occur at ground level.
Overall, aggregate greenhouse gas emissions in 2000
from the combustion of international bunker fuels from both
aviation and marine activities were 101.2 Tg CO2 Eq., or 12
percent below emissions in 1990 (see Table 2-41). Although
emissions from international flights departing from the
United States have increased significantly (23 percent),
emissions from international shipping voyages departing
the United States have decreased by 36 percent since 1990.
Increased military activity during the Persian Gulf War
resulted in an increased level of military marine emissions in
1990 and 1991; civilian marine emissions during this period
exhibited a similar trend.48 The majority of these emissions
were in the form of carbon dioxide; however, small amounts
of CH, and N.O were also emitted. Emissions of NO by
4 * A
aircraft during idle, take-off, landing and at cruising altitudes
are of primary concern because of their effects on ground-
level ozone formation (see Table 2-42).
Emissions from both aviation and marine international
transport activities are expected to grow in the future, as
both air traffic and trade increase, although emission rates
should decrease over time due to technological changes.49
Methodology
Emissions of CO2 were estimated through the
application of carbon content and fraction oxidized factors
to fuel consumption activity data. This approach is
analogous to that described under CO2 from Fossil Fuel
Combustion. A complete description of the methodology
and a listing of the various factors employed can be found
in Annex A. See Annex I for a specific discussion on the
methodology used for estimating emissions from
international bunker fuel use by the U.S. military.
Emission estimates for CH4, N2O, ;CO, NOx, and
NMVOCs were calculated by multiplying emission factors
by measures of fuel consumption by fuel type and mode.
Activity data for aviation included solely jet fuel
consumption statistics, while the marine mode included both
distillate diesel and residual fuel oil.
Data Sources
Carbon content and fraction oxidized factors for jet fuel,
distillate fuel oil, and residual fuel oil were taken directly
from the Energy Information Administration (EIA) of the
U.S. Department of Energy and are presented in Annex A.
Heat content and density conversions were taken from EIA
(2001) and USAF (1998). Emission factors used in the
calculations of CH4, N2O, CO, NOx, andNMVOC emissions
were obtained from the Revised 1996 IPCC Guidelines
(IPCC/UNEP/OECD/IEA1997). For aircraft emissions, the
following values, in units of grams of pollutant per kilogram
of fuel consumed (g/kg), were employed: 0.09 for CH4,0.1
for N20,5.2 for CO, 12.5 for NOx, and 0.78 fpr NMVOCs. For
marine vessels consuming either distillate diesel or residual
fuel oil the following values, in the same units, except where
noted, were employed: 0.32 for CH4,0.08 for N20,1.9forCO,
87 for NOx, and 0.052 g/MJ for NMVOCs.
Activity data on aircraft fuel consumption were collected
from three government agencies. Jet fuel consumed by U.S.
flag air carriers for international flight segments was supplied
by the Bureau of Transportation Statistics (DOT 1991
through 2001). It was assumed that 50 percent of the fuel
used by U.S. flagged carriers for international flights—both
departing and arriving in the United States—was purchased
48 See Uncertainty section for a discussion of data quality issues.
49 Most emission related international aviation and marine regulations are under the rubric of the International Civil Aviation Organization
(ICAO) or the International Maritime Organization (IMO), which develop international codes, recommendations, and conventions, such as
the International Convention of the Prevention of Pollution from Ships (MARPOL).
2-46 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 2-41: Emissions from International Bunker Fuels (Tg C02 Eq.)
Gas/Mode
1990
1995 1996
1997
1998
1999
2000
C02
I Aviation
't Marine
CH4
Aviation
Marine
N20
Aviation
Marine
jotal
+ Does not exceed
113.9
46.6
67.3
0.2
+
0.1
1.0
0.5
0.5
115.0
0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
^r rf
M
tf^- •*
• •- fiMPisw
fa-—.*
SP£5££»^£
1
101.0
51.1
49.9
0.1
+
0.1
0.9
0.5
0.4
102.1
Includes aircraft cruise altitude
102.3
52.2
50.1
0.1
+
0.1
0.9
0.5
0.4
103.3
emissions.
109.9
55.9
54.0
0.1
+
0.1
1.0
0.5
0.4
111.0
112.9
55.0
57.9
0.1
+
0.1
1.0
0.5
0.4
114.0
105.3
58.9
46.4
0.1
+
0.1
0.9
0.6
0.4
106.4
100.2
57.3
43.0
0.1
+
0.1
0.9
0.6
0.3
101.2
Table 2-42: Emissions from International Bunker Fuels (Gg)
Gas/Mode
1990
1995
1996
1997
1998
1999
2000
r co2
Aviation
Marine
; CH4
Aviation
Marine
= NZ0
Aviation
"~" Marine
CO
Aviation
Marine
NOX
Aviation
Marine
_ NMVOC
Aviation
Marine
Note: Totals
113,863
46,591
67,272
8
1
7
3
1
2
116
77
39
1,987
184
1,803
59
"11
48
may not sum due to independent rounding.
"F^- 101,037
51,117
lESrfi 40 Q2-)
,; ' Q
SS;, 1 1
5
SF?r^ 3
2
t- -- - ^ 1
^|£S«^ H-IO
T * llO
%&M^™~m
^B*!?ff g^
^^"•i^ on
^3
E 1-541
i»^:--s 202
1 ,339
fe'~",; 48
- - - ^SfmsqsSg ,
• 13
^^^^•» oc
»s--:^r",,i oO
102,272
52,164
50,109
6
1
5
3
2
1
115
86
29
1,549
207
1,343
49
13
36
109,885
55,925
53,960
7
2
5
3
2
1
124
92
32
1,667
222
1,446
52
14
38
112,913
55,012
57,900
7
2
6
3
2
1
125
91
34
1,771
218
1,553
55
14
41
105,341
58,913
46,429
6
2
5
3
2
1
124
97
27
1,478
233
1,244
48
15
33
100,228
57,274
42,954
6
2
4
3
2
1
120
94
25
1,379
227
1,152
45
14
31
Includes aircraft cruise altitude emissions.
domestically for flights departing from the United States. In
other words, only one-half of the total annual fuel
consumption estimate was used in the calculations. Data on
jet fuel expenditures by foreign flagged carriers departing
U.S. airports was taken from unpublished data collected by
the Bureau of Economic Analysis (BEA) under the U.S.
Department of Commerce (BEA 1991 through 2001).
Approximate average fuel prices paid by air carriers for
aircraft on international flights was taken from DOT (1991
through 2001) and used to convert the BEA expenditure
data to gallons of fuel consumed. Data on U.S. Department
of Defense (DoD) aviation bunker fuels and total jet fuel
consumed by the U.S. military was supplied by the Office of
the Under Secretary of Defense (Installations and
Environment), DoD. Estimates of the percentage of each
services' total operations that were international operations
were developed by DoD. Military aviation bunkers included
international operations, operations conducted from naval
vessels at sea, and operations conducted from U.S.
installations principally over international water in direct
support of military operations at sea. Military aviation bunker
fuel emissions were estimated using military fuel and
operations data synthesized from unpublished data by the
Defense Energy Support Center, under DoD's Defense
Logistics Agency (DESC 2001), and by the Naval Operations
Navy Strategic Mobility/Combat Logistics Division (N42
Energy 2-47
-------
2001). Together, the data allow the quantity of fuel used in
military international operations to be estimated. Densities
for each jet fuel type were obtained from a report from the
U.S. Air Force (USAF 1998). Final jet fuel consumption
estimates are presented in Table 2-43. See Annex I for
additional discussion of military data.
Activity data on distillate diesel and residual fuel oil
consumption by cargo or passenger carrying marine vessels
departing from U.S. ports were taken from unpublished data
collected by the Foreign Trade Division of the U.S. Department
of Commerce's Bureau of the Census (DOC 1991 through 2001).
Activity data on distillate diesel consumption by military
vessels departing from U.S. ports were provided by DESC (2001)
and N42 (2001). The total amount of fuel provided to naval
vessels was reduced by 13 percent to account for fuel used
while the vessels were not-underway (i.e., in port). Data on the
percentage of steaming hours underway versus not-underway
were provided by the U.S. Navy. These fuel consumption
estimates are presented in Table 2-44.
Uncertainty
Emission estimates related to the consumption of
international bunker fuels are subject to the same
uncertainties as those from domestic aviation and marine
mobile combustion emissions; however, additional
uncertainties result from the difficulty in collecting accurate
Table 2-43: Aviation Jet Fuel Consumption for International Transport (Million Gallons)
fuel consumption activity data for international transport
activities separate from domestic transport activities.50 For
example, smaller aircraft on shorter routes often carry
sufficient fuel to complete several flight segments without
refueling in order to minimize time spent at the airport gate
or take advantage of lower fuel prices at particular airports.
This practice, called tankering, when done on international
flights, complicates the use of fuel sales data for estimating
bunker fuel emissions. Tankering is less common with the
type of large, long-range aircraft that make many international
flights from the United States, however. Similar practices
occur in the marine shipping industry where fuel costs
represent a significant portion of overall operating costs
and fuel prices vary from port to port, leading to some
tankering from ports with low fuel costs.
Particularly for aviation, the DOT (1991 through 2001)
international flight segment fuel data used for U.S. flagged
carriers does not include smaller air carriers and unfortunately
defines flights departing to Canada and some flights to
Mexico as domestic instead of international. As for the BEA
(1991 through 2001) data on foreign flagged carriers, there is
some uncertainty as to the average fuel price, and to the
completeness of the data. It was also not possible to
Nationality
U.S. Carriers
Foreign Carriers
U.S. Military
Total
Note; Totals may not sum due to
1990
1,982
2,062
862
4,905
independent rounding.
i i!
k •!
Si.:"- ' '-%
fk;7f
fesi,,,lr.,i :-|
*I , - , t
aw '• '=9
ianiv*.:»
k^
1995
2,256
2,549
581
5,385
1996
2,329
2,629
540
5,497
1997
2,482
2,918
496
5,895
1998
2,363
2,935
502
5,799
1999
2,638
3,085
488
6,211
2000
2,740
2,818
480
-------
determine what portion of fuel purchased by foreign carriers
at U.S. airports was actually used on domestic flight
segments; this error, however, is believed to be small.51
Uncertainties exist with regard to the total fuel used by
military aircraft and ships, and in the activity data on military
operations and training that were used to estimate
percentages of total fuel use reported as bunker fuel
emissions. There are also uncertainties in fuel end-uses by
fuel-type, emissions factors, fuel densities, diesel fuel sulfur
content, aircraft and vessel engine characteristics and fuel
efficiencies, and the methodology used to back-calculate
the data set to 1990. All assumptions used to develop the
estimate were based on process knowledge, Department and
military service data, and expert judgments. The magnitude
of the potential errors related to the various uncertainties
has not been calculated, but is believed to be small. The
uncertainties associated with future military bunker fuel
emissions estimates could be reduced through additional
data collection.
Aircraft and ship fuel data were developed from DoD
records, which document fuel sold to the Navy and Air Force
by the Defense Logistics Agency. This data may slightly
over or under estimate actual fuel use in aircraft and ships
because each service may have procured fuel from, sold to,
traded, or given fuel to other ships, aircraft, governments,
or other entities. Small fuel quantities may have been used
in vehicles or equipment other than that which was assumed
for each fuel type. In particular, the marine fuel data provided
by the Navy Fuels and Logistics office (N42 2001) were
inconsistent with previous years' data.
There are also uncertainties in aircraft operations and
training activity data. Estimates for the quantity of fuel used
in Navy and Air Force flying activities reported as bunker
fuel emissions was estimated based on a combination of
available data and expert judgment.
Estimates of marine bunker fuel emissions were based
on Navy vessel steaming hour data that reports fuel used
while underway and fuel used while not underway. This
approach does not capture some voyages that would be
classified as domestic for a commercial vessel. Conversely,
emissions from fuel used while not underway preceding an
international voyage are reported as domestic rather than
international, as would be done for a commercial vessel.
There is also uncertainty in the methodology used to
estimate emissions for 1990 through 1994. These emissions
were estimated based on the 1995 values of the original data
set and extrapolated back in time based on a closely
correlated data set of fuel usage.
Although aggregate fuel consumption data has been
used to estimate emissions from aviation, the recommended
method for estimating emissions of gases other than CO2 in
the Revised 1996IPCC Guidelines is to use data by specific
aircraft type (ff CCVUNEP/OECD/IEA1997). The IPCC also
recommends that cruise altitude emissions be estimated
51 Although foreign flagged air carriers are prevented from providing domestic flight services in the United States, passengers may be
collected from multiple airports before an aircraft actually departs on its international flight segment. Emissions from these earlier domestic
flight segments should be classified as domestic, not international, according to the IPCC.
52 It should be noted that in the EPA's National Air Pollutant Emissions Trends, 1900-2000 (EPA 2001), U.S. aviation emission estimates
for CO, NOx, and NMVOCs are based solely upon LTO cycles and consequently only capture near ground-level emissions, which are more
relevant for air quality evaluations. These estimates also include both domestic and international flights. Therefore, estimates given under
Mobile Source Fossil Fuel Combustion overestimate EPCC-defined domestic CO, NOX, and NMVOC emissions by including landing and take-
off (LTO) cycles by aircraft on international flights but underestimate because they do not include emissions from aircraft on domestic flight
segments at cruising altitudes. EPA (2001) is also likely to include emissions from ocean-going vessels departing from U.S. ports on
international voyages.
Energy 2-49
-------
separately using fuel consumption data, while landing and
take-off (LTO) cycle data be used to estimate near-ground
level emissions of gases other than CO2.52
There is also concern as to the reliability of the existing
DOC (1991 through 2001) data on marine vessel fuel
consumption reported at U.S. customs stations due to the
significant degree of inter-annual variation.
Wood Biomass and Ethanol
Consumption
The combustion of biomass fuels—such as wood,
charcoal, and wood waste—and biomass-based fuels—such
as ethanol from corn and woody crops—generates carbon
dioxide (CO,). However, in the long run the carbon dioxide
emitted from biomass consumption does not increase
atmospheric carbon dioxide concentrations, assuming the
biogenic carbon emitted is offset by the uptake of CO2
resulting from the growth of new biomass. As a result, CO2
emissions from biomass combustion have been estimated
separately from fossil fuel-based emissions and are not
included in the U.S. totals. Net carbon fluxes from changes
in biogenic carbon reservoirs in wooded or crop lands are
accounted for in the Land-Use Change and Forestry chapter.
In 2000, CO2 emissions due to burning of woody biomass
within the industrial and residential/commercial sectors and
by electricity generation were about 174.8 Tg CO2 Eq. (174,770
Gg) (see Table 2-45 and Table 2-46). As the largest consumer
of woody biomass, the industrial sector in 2000 was
responsible for 78 percent of the CO2 emissions from this
source. The residential sector was the second largest emitter,
making up 20 percent of total emissions from woody biomass.
The commercial end-use sector and electricity generation
accounted for the remainder.
Biomass-derived fuel consumption in the United States
consisted mainly of ethanol use in the transportation sector.
Ethanol is primarily produced from corn grown in the
Midwest, and was used mostly in the Midwest and South.
Pure ethanol can be combusted, or it can be mixed with
gasoline as a supplement or octane-enhancing agent. The
most common mixture is a 90 percent gasoline, 10 percent
ethanol blend known as gasohol. Ethanol and ethanol blends
are often used to fuel public transport vehicles such as
buses, or centrally fueled fleet vehicles. Ethanol and ethanol
blends burn cleaner than gasoline (i.e., lower in NOx and
hydrocarbon emissions), and have been employed in urban
areas with poor air quality. However, because ethanol is a
hydrocarbon fuel, its combustion emits CO2.
Table 2-45: C02 Emissions from Wood Consumption by End-Use Sector (Tg C02 Eq.)
End-Use Sector
Industrial
Residential
Commercial
Electricity Generation
Total
1990 l~~
100.2 r
46.4 I
3.0 |
M"«4
149.6
1995
112.0
47.6
3.6
163.3
1996
115.1
47.5
3.9
166.6
1997
120.9
34.6
3.8
159.3
1998
124.9
30.9
3.7
159.6
1999
136.7
33.1
4.1
173.9
2000
136.0
34.6
4.1
174.8
Note: Totals may not sum due to independent rounding.
Table 2-46: C02 Emissions from Wood Consumption by End-Use Sector (Gg)
End-Use Sector
Industrial
Residential
Commercial
Electricity Generation
Total
1990
100,204
46,424
2,956
25
149,609
W 1
P = i
P_j(
f
1995
112,038
47,622
3,596
30
163,286
1996
115,145
47,542
3,899
30
166,617
1997
120,908
34,598
3,752
28
159,286
1998
124,933
30,933
3,717
26
159,610
1999
136,740
33,070
4,099
31
173,940
2000
135,964
34,626
4,148
33
174,770
Note: Totals may not sum due to independent rounding.
2-50 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 2-47: C02 Emissions from Ethanol Consumption
"Year
1990
1995
-1996
1997
1998
1999
-2000
TgC02Eq.
4.4
8.1
5.8
7.4
8.1
8.5
9.7
Gg
4,380
8,099
5,809
7,356
8,128
.8,451
9,667
In 2000, the United States consumed an estimated 139
trillion Btus of ethanol. Emissions of CO2 in 2000 due to
ethanol fuel burning were estimated to be approximately 9.7
Tg CO2 Eq. (8,451 Gg) (see Table 2-47).
Ethanol production dropped sharply in the middle of
1996 because of short corn supplies and high prices. Plant
output began to increase toward the end of the growing
season, reaching close to normal levels at the end of the
year. However, total 1996 ethanol production fell far short of
the 1995 level (EIA1997). Since the low in 1996, production
has continued to grow.
Methodology
Woody biomass emissions were estimated by
converting U.S. consumption data in energy units (17.2
million Btu per short ton) to megagrams (Mg) of dry matter
using EIA assumptions. Once consumption data for each
sector were converted to megagrams of dry matter, the carbon
content of the dry fuel was estimated based on default values
of 45 to 50 percent carbon in dry biomass. The amount of
Table 2-48: Woody Biomass Consumption by Sector (Trillion Btu)
carbon released from combustion was estimated using 90
percent for the fraction oxidized (i.e., combustion efficiency).
Ethanol consumption data in energy units were also
multiplied by a carbon coefficient (18.96 mg C/Btu) to produce
carbon emission estimates.
Data Sources
Woody biomass consumption data were provided by EIA
(2001) (see Table 2-48). Estimates of wood biomass consumption
for fuel combustion do not include wood wastes, liquors,
municipal solid waste, tires, etc. that are reported as biomass
by EIA. The factor for converting energy units to mass was
supplied by EIA (1994). Carbon content and combustion
efficiency values were taken from the Revised 1996IPCC
Guidelines (EPCC/UNEP/OECD/TEA1997).
Table 2-49: Ethanol Consumption
Year
- 1990
"" 1991
1992
1993
1994
: 1995 .
~ '- 1996
1997
1998
•- 1999
2000
Trillion Btu
63
73
83
97
109
117"
84
106
117
122
139
fcYear
t-~ 1990
f 1991
i 1992
'• 1993
* 1994
f. 1995
1 1996
•-- 1997
-1998
I 1999
!- 2000
Industrial
1,254
1,190
1,233
1,255
1,342
1,402
1,441
1,513
1,564
1,711
1,702
Residential
581
613
645
548
537
596
595
433
387
414
433
Commercial
37
39
42
44
45
45
49
47
47
51
52
Electric Generation
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO (Not Occurring)
f-- Emissions from ethanol were estimated using consumption data from EIA (2001) (see Table 2-49). The carbon coefficient used was provided by
~ "' " ~ ' """ """"
Energy 2-51
-------
Uncertainty
The fraction oxidized (i.e., combustion efficiency) factor
used is believed to under estimate the efficiency of wood
combustion processes in the United States. The IPCC
emission factor has been used because better data are not
yet available. Increasing the combustion efficiency would
increase emission estimates. In addition, according to EIA
(1994) commercial wood energy use is typically not reported
because there are no accurate data sources to provide reliable
estimates. Emission estimates from ethanol production are
more certain than estimates from woody biomass
consumption due to better activity data collection methods
and uniform combustion techniques.
2-52 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
3. Industrial Processes
Greenhouse gas emissions are produced as a by-product of various non-energy-related industrial activities.
That is, these emissions are produced from an industrial process itself and are not directly a result of energy
consumed during the process. For example, raw materials can be chemically transformed from one state to another. This
transformation can result in the release of greenhouse gases such as carbon dioxide (CO2), methane (CH4), or nitrous oxide
(N2O). The processes addressed in this chapter include iron and steel production, cement production, ammonia manufacture,
Figure 3-1
20Q(nn!|u^jK
Industrial Processes
as a Portion of All
Emissions
lime manufacture, limestone
and dolomite use (e.g., flux
stone, flue gas desulfurization,
and glass manufacturing), soda
ash production and use, titanium
dioxide production, ferroalloy
production, CO2 consumption,
aluminum production, petro-
chemical production, silicon
carbide production, nitric acid
production, and adipic acid
production (see Figure 3-1).
In addition to the three
greenhouse gases listed above,
there are also industrial sources
of several classes of man-made
fluorinated compounds called
hydrofluorocarbons (HFCs),
perfluorocarbons (PFCs), and
sulfur hexafluoride (SF6). The
present contribution of these
gases to the radiative forcing
effect of all anthropogenic greenhouse gases is small; however, because of their extremely long lifetimes, many of them will
continue to accumulate in the atmosphere as long as emissions continue. Usage of these gases, especially HFCs, is growing
rapidly as they are the primary substitutes for ozone depleting substances (ODSs), which are being phased-out under the Montreal
Protocol on Substances that Deplete the Ozone Layer. In addition to ODS substitutes, HFCs, PFCs, and other fluorinated
compounds are employed and emitted by a number of other industrial sources in the United States. These industries include
aluminum production, HCFC-22 production, semiconductor manufacture, electric power transmission and distribution, and
magnesium metal production and processing. Sulfur hexafluoride is the most potent greenhouse gas the IPCC has evaluated.
Iron and Steel Production
Substitution of Ozone Depleting Substances
Cement Manufacture
HCFC-22 Production
Nitric Acid
Ammonia Manufacture
Electrical Transmission and Distribution
Aluminum Production
Lime Manufacture
Limestone and Dolomite Use
Adipic Acid
Semiconductor Manufacture
Soda Ash Manufacture and Consumption
Magnesium Production and Processing
Titanium Dioxide Production
Ferroalloys
Petrochemical Production
Carbon Dioxide Consumption
Silicon Carbide Production
I
I
I
I
<0.05
10 20
30 40 50
Tg C02 Eq.
60 70
Industrial Processes 3-1
-------
In 2000, industrial processes generated emissions of 312.8
Tg CO2 Eq., or 4.5 percent of total U.S. greenhouse gas
emissions. Carbon dioxide emissions from all industrial
processes were 161.9 Tg CO2 Eq. (161,940 Gg) in the same
year. This amount accounted for only 2.8 percent of national
CO2 emissions. Methane emissions from petrochemical and
silicon carbide production resulted in emissions of
approximately 1.7 Tg CO2 Eq. (79 Gg) in 2000, which was
less than 1 percent of U.S. CH4 emissions. Nitrous oxide
emissions from adipic acid and nitric acid production were
27.9 Tg CO2 Eq. (90 Gg) in 2000, or 6.6 percent of total U.S.
N2O emissions. In the same year, combined emissions of HFCs,
PFCs and SF6 totaled 121.3 Tg CO2 Eq. Overall, emissions
from industrial processes increased by 6 percent from 1990 to
2000, which was the result of increases in emissions from
several industrial processes—the largest being substitutes for
ozone depleting substances—which was offset by decreases
in emissions from adipic acid production, aluminum
production, and production of HCFC-22.
Greenhouse gases are also emitted from a number of
industrial processes not addressed in this chapter. For
example, caprolactam—a chemical feedstock'for the
manufacture of nylon 6,6—and urea production are believed
to be industrial sources of N2O emissions. However,
emissions for these and other sources have not been
estimated due to a lack of information on the emission
processes, manufacturing data, or both. As more information
becomes available, emission estimates for these processes
will be calculated and included in future greenhouse gas
emission inventories, although their contribution is expected
to be small.1
The general method employed to estimate emissions
for industrial processes, as recommended by the
Intergovernmental Panel on Climate Change (IPCC),
involves multiplying production data for each process by
an emission factor per unit of production. The emission
factors used were either derived using calculations that
assume precise and efficient chemical reactions or were
based upon empirical data in published references. As a
result, uncertainties in the emission coefficients can be
attributed to, among other things, inefficiencies in the
chemical reactions associated with each production process
or to the use of empirically derived emission factors that
are biased and, therefore, may not represent U.S. national
averages. Additional sources of uncertainty specific to an
individual source category are discussed in each section.
Table 3-1 summarizes emissions for the Industrial
Processes chapter in units of teragrams of carbon dioxide
equivalents (Tg CO2 Eq.), while unweighted gas emissions
in gigagrams (Gg) are provided in Table 3-2.
iron and Steel Production
In addition to being an energy intensive process, the
production of iron and steel also generates process-related
emissions of CO2. Iron is produced by first reducing iron oxide
(iron ore) with metallurgical coke in a blast furnace to produce
pig iron (impure iron containing about 3 to 5 percent carbon
by weight). Metallurgical coke is manufactured in a coke plant
using coal as a raw material. Coke oven gas and coal tar are
carbon by-products of the coke manufacturing process. The
metallurgical coke is a raw material supplied to the blast furnace.
Coke oven gas is generally burned as a fuel within the steel
mill. Coal tar is used as a raw material in the manufacture of
anodes used for primary aluminum production and for other
electrolytic processes.
Carbon dioxide is produced as the metallurgical coke used
in the blast furnace process is oxidized. Steel (containing less
than 2 percent carbon by weight) is produced from pig iron in
a variety of specialized steel making furnaces. The majority of
CO2 emissions from the iron and steel process come from the
use of coke in the production of pig iron, with smaller amounts
evolving from the removal of carbon from pig iron used to
produce steel. Some carbon is also stored in the finished iron
and steel products.
Emissions of CO2 from iron and steel production in
2000 were 65.7 Tg CO2 Eq. (65,709 Gg) (see Table 3-3).
Emissions have fluctuated significantly from 1990 to 2000
due to changes in domestic economic conditions and
changes in imports and exports. For the past several years,
pig iron production has experienced a downward trend,
however domestic production recovered somewhat in 2000.
Pig iron production in 2000 was 4 percent higher than in
1999, but remains 6 percent below 1995 levels. Asian
economic problems and the availability of low-priced
imports limit growth in domestic production (USGS 2001).
See AnnexV for a discussion of emission sources excluded.
3-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-1: Emissions from Industrial Processes (Tg C02 Eq.)
&=-?,-,-,,,-,-mra-^-----~rr'~: - --" i-**-iM,jr-,7,,-;;,y i_v--T~"|3iMt™i»..iurr,i,r;,;r",'-sl;'T"--j«-" .~s,--™;,:,:r^,*l~'~^>-*™-i.ii.s^-™-;r,-:-r-?-'>-
Gas/Source 1990
C02 168.2
Iron and Steel Production 85.4
Cement Manufacture 33.3
Ammonia Manufacture 18,5
Lime Manufacture 11.2
Limestone and Dolomite Use 5.2
Aluminum Production 6.3 i
Soda Ash Manufacture and Consumption 4.1 j
Ferroalloy Production 2.0 ]
Titanium Dioxide Production 1.3 j
Carbon Dioxide Consumption 0.8 j
CH4 1.2 f
Petrochemical Production 1.2 I
Silicon Carbide Production + j
N20 32.7 ?
Nitric Acid Production 17.8 j
Adipic Acid Production 14.9 !
MFCs, PFCs, and SF6 93.6 \
Substitution of Ozone Depleting Substances 0.9 !
„ HCFC-22 Production "" _ 35.0 j
Electrical Transmission and Distribution 31 .2 j
Aluminum Production 18.1 ]
Semiconductor Manufacture 2.9 ]
Magnesium Production and Processing 5.5 j
Total 295.7 '
£^J 1995 1996
"1 164.1 160.4
m 74-4 68-3
36.8 37.1
mi 18.9 19.5
SI 12.8 13.5 '
.....7,0 .. . 7.4
Bt 5-3 ' 5.6
Si 4.3 4.2
mm 1.9. 2.0
iSI 1.7 1.7
is3 1-0 1-1
fe. 1-5 1-6
SE! 1.5 1.6
+ +
; 37.8 38.5
19.9 20.7
1£J 17.9 17.8
p| 98.5 111.9
fi;J 21.8 30.6
El 27.0 . 3.1.1
gpj 26.5 26.8
Us! ii-8 12-5
ii 5.9 5.4
B?~f 5.5 5.5
S 301.9 312.3
1997
171.2
76.1
38.3
19.5
13.7
8.4
5.6
4.4
2.0
1.8
1.3
1.6
1.6
+
32.7
21.2
11.5
116.9
38.0
30.0
24.5
11.0
6.5
6.9
322.4
1998
164.2
67.4
39.2
20.1
13.9
8.2
5.8
4.3
2.0
1.8
1.4
1.7
1.6
+
28.6
20.9
7.7
127.7
44.9
40.2
20.1
9.0
7.3
6.2
322.1
1999
161.4
64.4
40.0
18.9
13.5
9.1
5.9
4.2
2.0
1.9
1.6
1.7
1.7
+
27.8
20.1
7.7
120.0
51.3
30.4
15.5
8.9
7.7
6.1
310.8
2000
161.9
65.7
41.1
18.0
13.3
9.2
5.4
4.2
1.7
2.0
1.4
1.7
1.7
+
27.9
19.8
8.1
121.3
57.8
29.8
14.4
7.9
7.4
4.0
312.8
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
Methodology
Since coke is consumed as a reducing agent during the
manufacture of pig iron, the corresponding quantity of coal
consumed during coking operations was identified. This
quantity of coal is considered a non-energy use. Data were
also collected on the amount of imported coke consumed in
the blast furnace process. These data were converted to their
energy equivalents. The carbon content of the combusted
coal and imported coke was estimated by multiplying their
energy consumption by material specific carbon-content
coefficients. The carbon-content coefficients used are
presented in Annex A.
Emissions from the re-use of scrap steel and imported
pig iron in the steel production process were calculated by
assuming that all the associated carbon-content of these
materials are released on combustion. Steel has an associated
carbon-content of approximately 0.4 percent, while pig iron
is assumed to contain 4 percent carbon by weight.
Emissions from carbon anodes, used during the
production of steel in electric arc furnaces (EAF), were also
estimated. Emissions of CO2 were calculated by multiplying
the annual production of steel in electric arc furnaces by an
emission factor (4.4 kg CO2/ton steel^). It was assumed
that the carbon anodes are composed of 80 percent
petroleum coke and 20 percent coal tar pitch (DOE 1997).
Since coal tar pitch is a by-product of the coking process
and its carbon related emissions are already accounted for
during the estimation of emissions from coal combustion,
the emission factor was reduced by 20 percent to avoid
double counting.
Similarly, an adjustment was made to account for the
coal tar pitch component of carbon anodes consumed during
the production of aluminum. Again, it was assumed that the
carbon anodes have a composition of 80 percent petroleum
coke and 20 percent coal tar. These coal tar emissions are
accounted for in the aluminum production section of this
Industrial Processes 3-3
-------
Table 3-2: Emissions from Industrial Processes (Gg)
Gas/Source
1990
C02 168,165
Iron and Steel Production 85,414
Cement Manufacture 33,278
Ammonia Manufacture 1 8,51 0
»
E"
Lime Manufacture 11,238 9-
Limestone and Dolomite Use
Aluminum Production
Soda Ash Manufacture and Consumption
Ferroalloy Production
Titanium Dioxide Production
Carbon Dioxide Consumption
CRs
fJ
Petrochemical Production
Silicon Carbide Production
20
Nitric Acid Production
Adipic Acid Production
MFCs, PFCs, and SF6
Substitution of Ozone Depleting Substances
HCFC-22 Production3
Electrical Transmission and Distributionb
Aluminum Production
Semiconductor Manufacture
Magnesium Production and Processing1"
5,181
6,315
4,142
1,980
1,308
800
57
56
1
106
58
48
M
M
3
1
M
M
+
m
P "
1 1 T
|y _
r
SaQanHiir
Sp- —
^ L
IT
fin
fc
mr
S..
m '
1™*
r
t
I
"I
n
u£
Ti
1
1
*1
T,
I
"iil
i
1
'
S
,
""*
1
!
1995
164,057
74,357
36,847
18,946
12,804
7,028
5,265
4,305
1,866
1,670
968
73
72
1
122
64
58
M
M
2
1
M
M
+
1996
160,358
68,324
37,079
19,512
13,495
7,
5,
4,
1,
1,
1,
379
580
239
954
657
140
76
75
1
124
67
57
M
M
3
1
M
M
+
1997
171,156
76,127
38,323
19,477
13,685
8,401
5,621
4,355
2,038
1,836
1,294
78
77
1
106
68
37
M
M
3
1
M
M
+
1998
164,238
67,429
39,218
20,113
13,914
8,187
5,792
4,325
2,027
1,819
1,413
79
78
1
92
67
25
M
M
3
1
M
M
+
1999
161,356
64,376
39,991
18,874
13,466
9,115
5,895
4,217
1,996
1,853
1,572
80
79
1
90
65
25
M
M
3
'1
M
'M
+
2000
161,940
65,709
41,067
18,017
13,316
9,196
5,410
4,181
1,719
1,963
1,361
79
79
1
90
64
26
M
M
3
1
M
M
+
+ Does not exceed 0.5 Gg
M (Mixture of gases)
• HFC-23 emitted
" SF6 emitted
Note: Totals may not sum due to independent rounding.
chapter. To prevent double counting, 20 percent of the
emissions reported in the aluminum section have been
subtracted from the estimates for iron and steel production.
Carbon storage was accounted for by assuming that all
domestically manufactured steel had a carbon content of
0.4 percent. Furthermore, any pig iron that was not
consumed during steel production, but fabricated into
finished iron products, was assumed to have a carbon
content by weight of 4 percent.
Table 3-3:
Pirnrlnpfinn
* Year
!" 1990
1995
p 1996
-1997
;' 1998
1:1999
E2DQO ...
C02 Emissions from
Tg C02 Eq.
85.4
V 1"Vl.1i _L^1.
"~i"~ •* -• -^Ofe fc
74.4
68.3
76.1
67.4
64.4
65.7
Iron and Steel
Gg
85,414
74,357
68,324
76,127
67,429
64,376
65,709
Data relating to the amount of coal consumed at coke
plants, for the production of coke for domestic consumption
in blast furnaces, as well as, the quantity of coke imported
for iron production were taken from Energy Information
Administration (EIA), Quarterly Coal Report October-
December 2000 (EIA 2000); U.S. Coal Domestic and
International Issues (EIA 2001); Mineral Yearbook: Iron
and Steel (USGS 2000a, 1999, 1997, 1995a, 1993) and
American Iron and Steel Institute (AISI), Annual Statistical
Report (AISI 2000). Scrap steel and imported pig iron
consumption data for 1990 through 2000 were obtained from
Annual Statistical Reports (AISI 2000, 1995). Crude steel
production, as well as pig iron use for purposes other than
steel production, was also obtained from Annual Statistical
Reports (AISI 2001,1996). Carbon content percentages for
pig iron and crude steel and the CO2 emission factor for
carbon anode emissions from steel production were obtained
from IPCC Good Practice Guidance and Uncertainty
3-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Management (IPCC 2000). Aluminum production data for
1990 through 2000 were obtained from Mineral Industry
Surveys: Aluminum Annual Report (USGS 1995b, 1998,
2000b, 2001). The CO2 emission factor for carbon anode
emissions from aluminum production was taken from the
Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA
1997). Estimates for the composition of carbon anodes used
during steel and aluminum production were obtained from
Energy and Environmental Profile of the U.S. Aluminum
Industry (DOE 1997).
Uncertainty
Estimating CO2 emissions from coal and coke
combustion is based on energy consumption data, average
carbon contents, and the fraction of carbon oxidized produce
a relatively accurate estimate of CO2 emissions. However,
there are uncertainties associated with each of these factors.
For example, carbon oxidation factors may vary depending
on inefficiencies in the combustion process, where varying
degrees of ash or soot can remain unoxidized.
Simplifying assumptions were made concerning the
composition of carbon anodes (80 percent petroleum coke
and 20 percent coal tar). For example, within the aluminum
industry, the coal tar pitch content of anodes can vary from
15 percent in prebaked anodes to 24 to 28 percent in
Soderberg anode pastes (DOE 1997). An average value was
assumed and applied to all carbon anodes utilized during
aluminum and steel production. The assumption is also made
that all coal tar used during anode production originates as
a by-product of the domestic coking process. Similarly, it
was assumed that all pig iron and crude steel have carbon
contents of 4 percent and 0.4 percent, respectively. The
carbon content of pig iron can vary between 3 and 5 percent,
while crude steel can have a carbon content of up to 2
percent, although it is typically less than 1 percent (IPCC
2000).
There is uncertainty in the most accurate CO2 emission
factor for carbon anode consumption in aluminum
production. Emissions vary depending on the specific
technology used by each plant (Prebake or Soderberg). The
Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA
1997) provide CO2 emission factors for each technology
type. Using information gathered from the Voluntary
Aluminum Industrial Partnership (VAIP) program, it was
assumed that production was split 80 percent prebake and
20 percent Soderberg for the whole time series. Similarly,
the carbon anode emission factor for steel production can
vary between 3.7 and 5.5 kg CO2/ton steel (IPCC 2000).
For this analysis, the upper bound value was used.
Cement Manufacture
Cement manufacture is an energy and raw material
intensive process resulting in the generation of carbon
dioxide (CO2) from both the energy consumed in making
the cement and the chemical process itself.2 Cement
production has accounted for about 2.4 percent of total
global industrial and energy-related CO2 emissions (IPCC
1996), and the United States is the world's third largest
cement producer. Cement is manufactured in almost every
U.S. state. Carbon dioxide emitted from the chemical
process of cement production represents one of the largest
sources of industrial CO2 emissions in the United States.
During the cement production process, calcium
carbonate (CaCO3) is heated in a cement kiln at a
temperature of about 1,300°C (2,400°F) to form lime (i.e.,
calcium oxide or CaO) and CO2. This process is known as
calcination or calcining. Next, the lime is combined with
silica-containing materials to produce clinker (an
intermediate product), with the earlier by-product CO2 being
released to the atmosphere. The clinker is then allowed to
cool, mixed with a small amount of gypsum, and used to
make Portland cement. The production of masonry cement
from Portland cement requires additional lime and, thus,
results in additional CO2 emissions. However, this additional
lime is already accounted for in the Lime Manufacture
source category in this chapter; therefore, the additional
emissions from making masonry cement from clinker are
not counted in this source category's total. They are
presented here for informational purposes only.
In 2000, U.S. clinker production—including Puerto
Rico—totaled 79,417 thousand metric tons, and U.S.
masonry cement production was estimated to be 4,275
thousand metric tons (USGS 2001). The resulting emissions
2 The CO2 emissions related to the consumption of energy for cement manufacture are accounted for under CO2 from Fossil Fuel Combustion in the
Energy chapter.
Industrial Processes 3-5
-------
Table 3-4: C02 Emissions from Cement Production*
Year
Tg C02 Eg.
Gg
1990
i; ;. : ••
1995
1996
1997
1998
1999
2000
33.3
' ;'; •. j ";:|f ; ;':':i ',„':;"'
36.8
37.1
38.3
39.2
40.0
41.1
33,278
36,847
37,079
38,323
39,218
39,991
41,066
".' i
'
* Totals exclude C02 emissions from making masonry cement from
clinker, which are accounted for under Lime Manufacture.
of CO2 from clinker production were estimated to be 41.1
Tg CO2 Eq. (41,066 Gg) (see Table 3-4). Emissions from
masonry production from clinker raw material were
estimated to be 0.1 Tg CO2 Eq. (96 Gg) in 2000, but again
are accounted for under Lime Manufacture.
After falling in 1991 by 2 percent from 1990 levels,
cement production emissions have grown every year since.
Overall, from 1990 to 2000, emissions increased by 23
percent. In 2000, output by cement plants increased 3 percent
over 1999, to 79,417 thousand metric tons. Cement is a
critical component of the construction industry; therefore,
the availability of public construction funding, as well as
overall economic growth, have had considerable influence
on cement production.
Methodology
Carbon dioxide emissions from cement manufacture
are created by the chemical reaction of carbon-containing
minerals (i.e., calcining limestone). While in the kiln,
limestone is broken down into CO2 and lime with the CO2
released to the atmosphere. The quantity of the CO2 emitted
during cement production is directly proportional to the lime
content of the clinker. During calcination, each mole of
CaCO3 (i.e., limestone) heated in the clinker kiln forms one
mole of lime (CaO) and one mole of CO2:
CaCO3 + heat
CaO + CO
Carbon dioxide emissions were estimated by applying
an emission factor, hi tons of CO2 released per ton of clinker
produced, to the total amount of clinker produced. The
emission factor used in this analysis is the product of the
average lime fraction for clinker of 64.6 percent (IPCC
2000) and a constant reflecting the mass of CO2 released
per unit of lime. This calculation yields an emission factor
of 0.507 tons of CO2 per ton of clinker produced, which
was determined as follows:
During clinker production, some of the clinker
precursor materials remain in the kiln as non-calcinated,
partially calcinated, or fully calcinated cement kiln dust
(CKD). The emissions attributable to the calcinated portion
of the CKD are not accounted for by the clinker emission
factor. The IPCC recommends that these additional CKD
CO2 emissions should be estimated as 2 percent of the CO2
emissions calculated from clinker production. Total cement
production emissions were calculated by adding the
emissions from clinker production to the emissions assigned
to CKD (IPCC 2000).
Masonry cement requires additional lime over and
above the lime used in clinker production. In particular, non-
plasticizer additives such as lime, slag, and shale are added
to the cement, increasing its weight by approximately 5
percent. Lime accounts for approximately 60 percent of this
added weight. Thus, the additional lime is equivalent to
roughly 2.86 percent of the starting amount of the product,
since:
0.6 x 0.057(1 + 0.05) = 2.86%
An emission factor for this added lime can then be
calculated by multiplying this percentage (2.86 percent) by
the molecular weight ratio of CO2 to CaO (0.785) to yield
0.0224 metric tons of additional CO2 emitted for every
metric ton of masonry cement produced.
As previously mentioned, the CO2 emissions from the
additional lime added during masonry cement production
are accounted for hi the section on CO2 emissions from Lime
Manufacture. Thus, these emissions were estimated in this
chapter for informational purposes only, and are not included
in the cement emission totals.
3-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Data Sources
The activity data for clinker and masonry cement
production (see Table 3-5) were obtained from U.S.
Geological Survey (USGS 1992,1995a, 1995b, 1996,1997,
1998,1999,2000,2001). The data were compiled by USGS
through questionnaires sent to domestic clinker and cement
manufacturing plants.
Table 3-5: Cement Production (Gg)
fcYear
..- 1990
'-1991
i 1992
^r1993
£1994
|:1995
* 1996
fl997
fe!998
H'999
T-2000
»— ;
Clinker
64,355
62,918
63,415
66,957
69,786
71,257
71,706
74,112
75,842
77,337
79,417
Masonry
3,209
2,856
3,093
2,975
3,283
3,603
3,469 i
3,634
3,989 :
4,375
4,275
.. •' I
Uncertainty
The uncertainties contained in these estimates are primarily
due to uncertainties in the lime content of clinker, in the amount
of lime added to masonry cement, and in the percentage of
CKD recycled inside the clinker Mln. The lime content of
clinker varies from 64 to 66 percent. CKD loss can range from
1.5 to 8 percent depending upon plant specifications.
Additionally, some amount of CO2 is reabsorbed when the
cement is used for construction. As cement reacts with water,
alkaline substances such as calcium hydroxide are formed.
During this curing process, these compounds may react with
CO2 in the atmosphere to create calcium carbonate. This
reaction only occurs in roughly the outer 0.2 inches of
surface area. Because the amount of CO2 reabsorbed is
thought to be minimal, it was not estimated.
Ammonia Manufacture
Emissions of carbon dioxide (CO2) occur during the
production of synthetic ammonia. In the United States,
roughly 98 percent of synthetic ammonia is produced by
catalytic steam reforming of natural gas. The remainder is
produced using naphtha (a petroleum fraction) as a feedstock
or through the electrolysis of brine at chlorine plants (EPA
1997). The natural gas-based and naphtha-based processes
produce CO2 and hydrogen (H2), the latter of which is used
in the production of ammonia. The brine electrolysis process
does not lead to CO2 emissions.
There are five principal process steps in synthetic
ammonia production from natural gas feedstock. The
primary reforming step converts methane to CO2, carbon
monoxide (CO), and H2 in the presence of a catalyst. Only
30 to 40 percent of the methane feedstock to the primary
reformer is converted to CO and CO2. The secondary
reforming step converts the remaining methane feedstock
to CO and CO2. The CO in the process gas from the
secondary reforming step (representing approximately 15
percent of the process gas) is converted to CO2 in the
presence of a catalyst, water, and air in the shift conversion
step. Carbon dioxide is removed from the process gas by
the shift conversion process, and the hydrogen gas is
combined with the nitrogen gas in the process gas during
the ammonia synthesis step to produce ammonia. The CO2
is included in a waste gas stream with other process
impurities and is absorbed by a scrubber solution. In
regenerating the scrubber solution, CO2 is released.
The conversion process for conventional steam
reforming of methane, including primary and secondary
reforming and the shift conversion processes, is
approximately as follows:
(catalyst)
0.88 CH4 + 1.26 Air + 1.24 It,O
0.88 CO2 + N2 + 3
Emissions of CO2 from ammonia production in 2000
were 18.0 Tg CO2 Eq. (18,017 Gg). Carbon dioxide
emissions from this source are summarized in Table 3-6.
Methodology
Emissions of CO2 were calculated by multiplying
annual estimates of ammonia production by an emission
factor (1.2 ton CO2/ton NH3). It was assumed that all
ammonia was produced using conventional catalytic steam
reformation and natural gas feedstock, although small
amounts may have been produced using reforming of
naphtha feedstock or electrolysis of chlorine brines. The
actual amount produced using these alternative methods is
not known, but assumed to be small, constituting less than
Industrial Processes 3-7
-------
Table 3-6: CO, Emissions from Ammonia Manufacture Table 3-7: Ammonia Manufacture
Year
1990
1995
19S6
1997
1998
1999
2000
Tg C02 Eq.
18.5
IxaeattgUUSidftis^ti
18.9
19.5
19.5
20.1
18.9
18.0
2 percent of all ammonia production.
Gg
lo.olU ,
BEaaudutHbMswwa ^~
iSitgeii^tiAssfs^iaSast = •
18,946 '
19,512 r
19,477 - "
20,113
18,874 : t
18,017 : 1
; 1
It was also assumed r
Year
1990
1991
1992.
1993
1994
1995
1996
1997
1998
1999
,2000
• -•'•'•-.
Thousand
Metric Tons
15,425 : '-•
15,576- ";
16,261 :
15,599
16,211 "I
15,788
16,260
16,231
16,761
15,728
15,014,,, •• J
-• • •; --.- - : - *
to the ammonia synthesis process is ultimately converted to
CO2 and emitted to the atmosphere as process exhaust gas.
Data Sources
The emission factor of 1.2 ton CO2/ton NHj was taken
from the European Fertilizer Manufacturers Association
Best Available Techniques publication, Production of
Ammonia (EFMA1995). The EFMA reported an emission
factor range of 1.15 to 1.30 ton CO/ton NHj with 1.2 ton
COj/ton NH3 as a typical value. The EFMA reference also
indicates that more than 99 percent of the methane feedstock
to the catalytic reforming process is ultimately converted to
CO2. Ammonia production data (see Table 3-7) were
obtained from the Census Bureau of the U.S. Department
of Commerce (Census Bureau 1998, 2000) as reported in
Chemical and Engineering News, "Facts & Figures for the
Chemical Industry."
Uncertainty
It is uncertain how accurately the emission factor used
represents an average across all ammonia plants. The EFMA
reported an emission factor range of 1.15 to 1.30 ton CO2/
ton NHj, with, 1.2 ton CO2/ton NH3 reported as a typical
value. The actual emission factor depends upon the amount
of air used in the ammonia production process, with 1.15
ton CO2/ton NH3 being the approximate' stoichiometric
minimum that is achievable for the conventional reforming
process. By using natural gas consumption data for each
ammonia plant, more accurate estimates of CO2 emissions
from ammonia production could be calculated. However,
these consumption data are often considered confidential.
Also, natural gas is consumed at ammonia plants both as a
feedstock to the reforming process and also for generating
process heat and steam. Natural gas consumption data, if
available, would need to be divided into feedstock use (non-
energy) and process heat and steam (fuel) use in order to be
used for the Inventory, as CO2 emissions from fuel use and
non-energy use are calculated separately in the Inventory.3
Natural gas feedstock consumption data for the U.S.
ammonia industry as a whole is available from the Energy
Information Administration (EIA) Manufacturers Energy
Consumption Survey (MECS) for the years 1985, 1988,
1991, 1994 and 1998 (EIA 1994; EIA 1998). These
feedstock consumption data collectively correspond to an
effective average emission factor of 1.0 ton CO2/ton NH3,
which appears to be below the stoichiometric minimum that
is achievable for the conventional steam reforming process.
3 It appears, for example, that the IPCC emission factor for ammonia production of 1.5 tonne CO2 per tonne ammonia may include both CO2 emissions
from the natural gas feedstock to the process and some CO2 emissions from the natural gas used to generate process heat and steam for the process.
Table 2-5, Ammonia Production Emission Factors, in Volume 3 of the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories
Reference Manual (IPCC, 1997) includes two emission factors, one reported for Norway and one reported for Canada. The footnotes to the table
indicate that the factor for Norway does not include natural gas used as fuel but that it is unclear whether the factor for Canada includes natural gas
used as fuel. However, the factors for Norway and Canada are nearly identical (1.5 and 1.6 tonnes CO2per tonne ammonia, respectively) and it is
likely that if one value includes fuel use the other value also does. Further, for the conventional steam reforming process the EFMA reports an emission
factor range for feedstock CO2 of 1.15 to 1.30 tonnes per tonne (with a typical value of 1.2 tonne per tonne) and a emission factor for fuel CO2 of 0.5
tonnes per tonne. This corresponds to a total CO2 emission factor for the ammonia production process, including both feedstock CD2 and process heat
CO2, of 1.7 tonne per tonne, which is closer to the emission factors reported in the IPCC 1996 Reference Guidelines than to the feedstock-only CO2
emission factor of 1.2 tonne CO2 per tonne ammonia reported by the EFMA.
3-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
The EIA data for natural gas consumption for the years 1994
and 1998 correspond more closely to the CO2 emissions
calculated using the EFMA emission factor than do data
for previous years. The 1994 and 1998 data alone yield an
effective emission factor of 1.1 ton CO./ton NHL,
•i 3
corresponding to CO2 emissions estimates that are
approximately 1.5 Tg CO2 Eq. below the estimates
calculated using the EFMA emission factor of 1.2 ton CO2/
ton NH3. Natural gas feedstock consumption data are not
available from EIA for other years, and data for 1991 and
previous years may underestimate feedstock natural gas
consumption, and therefore the emission factor was used
to estimate CO2 emissions from ammonia production, rather
than EIA data.
All ammonia production in this analysis was assumed
to be from the same process; conventional catalytic
reforming of natural gas feedstock. However, actual
emissions could differ because processes other than catalytic
steam reformation and feedstocks other than natural gas may
have been used for ammonia production.
Lime Manufacture
Lime is an important manufactured product with many
industrial, chemical, and environmental applications. Its
major uses are in steel making, flue gas desulfurization
(FGD) at coal-fired electric power plants, construction, pulp
and paper manufacturing, and water purification. Lime has
historically ranked fifth in total production of all chemicals
in the United States. For U.S. operations, the term "lime"
actually refers to a variety of chemical compounds. These
include calcium oxide (CaO), or high-calcium quicklime;
calcium hydroxide (Ca(OH)2), or hydrated lime; dolomitic
quicklime ([CaOMgO]); and dolomitic hydrate
([Ca(OH)2-MgO] or [Ca(OH)2.Mg(OH)2]).
Lime production involves three main processes: stone
preparation, calcination, and hydration. Carbon dioxide is
generated during the calcination stage, when limestone—•
mostly calcium carbonate (CaCO3)—is roasted at high
temperatures in a kiln to produce CaO and CO2. The CO2 is
driven off as a gas and is normally emitted to the atmosphere.
Some of the CO2 generated during the production process,
however, is recovered at some facilities for use in sugar
refining and precipitated calcium carbonate (PCC)4
production. It is also important to note that, for certain
applications, lime reabsorbs CO2 during use (see
Uncertainty, below).
Lime production in the United States—including Puerto
Rico—was reported to be 19,541 thousand metric tons in
2000 (USGS 2001). This resulted in an estimated CO2
emissions of 13.3 Tg CO2 Eq. (13,316 Gg) (see Table 3-8
and Table 3-9).
Table 3-8: C02 Emissions from Lime Manufacture
y Year Tg G02 Eq.
1990 11.2
g1g^^BS^^ȣs:^
r^-iss™ ~BT3j
1996
1997
1998
----- -1999
2000
13.5
13.7
13.9
13.5
13.3
Table 3-9: C02 Emissions from Lime Manufacture (Gg)
^ Year
": 1990
fcfcftSSi^i^igiq
?. 1995
' -1996
: 1997
1 1998
t~~ 1999
£".2000
Potential
11,730
;^T:r TH^"'.'^^!^ T
13,701
14,347
14,649
14,975
14,655
14,549
Recovered*
(493)
S*l:=^??'7~'r'^-iI;::i,J:'
(896)
(852)
(964)
(1,061)
(1,188)
(1,233)
Emissions
11,238
'.-^-vr1-"?, ',,.,,.,':,,• • • - r~- •
12,804
13,495
13,685
13,914
13,466
13,316
'—* For sugar refining and precipitated calcium carbonate production
"Note: Totals may not sum due to independent rounding.
At the turn of the 20th Century, over 80 percent of lime
consumed in the United States went for construction uses.
The contemporary quicklime market is distributed across
its four end-use categories as follows: metallurgical uses,
38 percent; environmental uses, 26 percent; chemical and
industrial uses, 24 percent; and construction uses, 11
percent. Construction end-uses are still important to the
hydrated lime market, accounting for 52 percent of
consumption. However, hydrated lime constitutes only 8
percent of the total lime market (USGS 2001).
* Precipitated calcium carbonate is a specialty filler used in premium-quality coated and uncoated papers.
Industrial Processes 3-9
-------
Lime production in 2000 declined less than 1 percent
from 1999, the second consecutive drop in annual
production. Overall, from 1990 to 2000, lime production
increased by 23 percent. The increase in production is
attributed in part to growth in demand for environmental
applications, especially flue gas desulfurization (FGD)
technologies. In 1993, the U.S. Environmental Protection
Agency (EPA) completed regulations under the Clean Air
Act capping sulfur dioxide (SO2) emissions from electric
utilities. Lime scrubbers' high efficiencies and increasing
affordability have allowed the FGD end-use to expand from
10 percent of total lime consumption in 1990 to 16 percent
in 2000 (USGS 1992, 2001).
Methodology
During the calcination stage of lime manufacture, CO2 is
driven off as a gas and normally exits the system with the stack
gas. To calculate emissions, the amounts of high-calcium and
dolomitic lime produced were multiplied by their respective
emission factors. The emission factor is the product of a
constant reflecting the mass of CO2 released per unit of lime
and the average calcium plus magnesium oxide (CaO + MgO)
content for lime (95 percent for both types of lime). The
emission factors were calculated as follows:
For high-calcium lime:
(44.01 § CO2/mole) -s- [(56.08 8 Ca°/mole) -=-
(0.95 § Ca°/lime)] = 0.75 £ CO2/g lime
For dolomitic lime:
(88.02 8 C02/mole) * [(97.01 § CaO*MSO/mole)
- (0.95 g CaOMgO/g lime)] = a86 g CO^ Ume
Production is adjusted to remove the mass of chemically
combined water found in hydrated Ume (see Table 3-11),
using the midpoint of default ranges provided by the IPCC
Good Practice Guidance (IPCC 2000). These factors set
the chemically combined water content to 27 percent for
high-calcium hydrated lime, and 24 percent for dolomitic
hydrated lime.
Lime production in the United States was 19,541 thousand
metric tons in 2000 (USGS 2001), resulting in potential CO2
emissions of 14,549 Gg. Some of the CO2 generated during
the production process, however, was recovered for use in sugar
refining and precipitated calcium carbonate (PCC) production.
Combined Ume manufacture by these producers was 2,067
thousand metric tons in 2000, generating 1.5 Tg of CO2. It was
assumed that approximately 80 percent of the CO2 involved in
sugar refining and PCC was recovered.
Data Sources
The activity data for lime manufacture and lime
consumption by sugar refining and precipitated calcium
carbonate (PCC) for 1990 through 2000 (see Table 3-10)
were obtained from USGS (1992, 1994, 1995,1996, 1997,
1998,1999,2000,2001). The CaO and CaO'MgO contents
of lime were obtained from the IPCC Good Practice
Guidance (IPCC 2000). Since data for the individual lime
types was not provided prior to 1997, total lime production
for 1990 through 1996 was allocated according to the 1997
distribution. For lime consumption, it was assumed that 100
percent was high-calcium based on communication with the
National Lime Association (Males 2001).
Table 3-10: Lime Production and Lime Use for Sugar
Refining and PCC (Thousand Metric Tons)
£•:. -.---=
"Year
6 1990
* 1991
5 1992
M993
:,J994. ;.
t1995
C.1996
fr 1997
151998
5:1999
L..2DOO
i - a Includes
High-Calcium
Production3
12,947
12,840
13,307
13,741
14,274
15,193
15,856
16,120
16,750"
16,110
16,350
hydrated limes.
Dolomite
Production3'11
2,895
2,838
2,925
3,024
3,116
3,305
3,434 :
3,552
3,423
3,598
3,191
Use
826
964
1,023
1,279
1,374
1,503
1,429
1,616
1,779
1,992
2,067
:" b Includes dead-burned dolomite. ;
Table 3-11: Hydrated Lime Production
(Thousand Metric Tons)
Year
High-Calcium Hydrate Dolomitic Hydrate
* 1990
M991
t 1992
*1"993
-1994
t-1995 , .
p. 1996
-1997
f 1998
-1999
i 2000
1,781
1,841
1,892
1,908
1,942
_ 2,027
1,858
1,820
1,950
2,010
1,550
319
329
348
342
348
363
332
352
383
298
"' 421
3-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Uncertainty
Uncertainties in the emission estimate can be attributed
to slight differences in the chemical composition of these
products. Although the methodology accounts for various
formulations of lime, it does not account for the trace
impurities found in lime, such as iron oxide, alumina, and
silica. Due to differences in the limestone used as a raw
material, a rigid specification of lime material is impossible.
As a result, few plants manufacture lime with exactly the
same properties.
In addition, a portion of the CO2 emitted during lime
manufacture will actually be reabsorbed when the lime is
consumed. As noted above, lime has many different
chemical, industrial, environmental, and construction
applications. In many processes, CO2 reacts with the lime
to create calcium carbonate (e.g., water softening). Carbon
dioxide reabsorption rates vary, however, depending on the
application. For example, 100 percent of the lime used to
produce precipitated calcium carbonate (PCC) reacts with
CO2; whereas most of the lime used in steelmaking reacts
with impurities such as silica, sulfur, and aluminum
compounds. A detailed accounting of lime use in the United
States and further research into the associated processes
are required to quantify the amount of CO2 that is
reabsorbed.5 As more information becomes available, this
emission estimate will be adjusted accordingly.
In some cases, lime is generated from calcium carbonate
by-products at paper mills and water treatment plants.6 The
lime generated by these processes is not included in the USGS
data for commercial lime consumption. In the paper industry,
mills that employ the sulfate process (i.e., Kraft) consume lime
in order to causticize a waste sodium carbonate solution (i.e.,
black liquor). Most sulfate mills recover the waste calcium
carbonate after the causticizing operation and calcine it back
into lime—thereby generating CO2—for reuse in the pulping
process. Although this re-generation of lime could be
considered a lime manufacturing process, the CO2 emitted
during this process is biogenic in origin, and therefore would
not be included in Inventory totals.
In the case of water treatment plants, lime is used in the
softening process. Some large water treatment plants may
recover their waste calcium carbonate and calcine it into
quickhme for reuse in the softening process. Further research
is necessary to determine the degree to which lime recycling is
practiced by water treatment plants in the United States.
Limestone and Dolomite Use
Limestone (CaCO3) and dolomite (CaCO3MgCO3)7 are
basic raw materials used by a wide variety of industries,
including construction, agriculture, chemical, metallurgy,
glass manufacture, and environmental pollution control.
Limestone is widely distributed throughout the world in
deposits of varying sizes and degrees of purity. Large
deposits of limestone occur in nearly every State in the
United States, and significant quantities are extracted for
industrial applications. For some of these applications,
limestone is sufficiently heated during the process to
generate CO2 as a by-product. Examples of such applications
include limestone used as a flux or purifier in metallurgical
furnaces, as a sorbent in flue gas desulfurization (FGD)
systems for utility and industrial plants, as a raw material in
glass manufacturing, or in magnesium production.
In 2000, approximately 16,314 thousand metric tons
of limestone and 4,019 thousand metric tons of dolomite
were used for these applications. Overall, both limestone
and dolomite usage resulted in aggregate CO2 emissions of
9.2Tg CO2 Eq. (9,196 Gg) (see Table 3-12 and Table 3-13).
Emissions in 2000 increased 1 percent from the previous
year and 77 percent since 1990. In the future, increases in
demand for crushed stone are anticipated. Demand for crushed
stone from the transportation sector continues to drive growth
hi limestone and dolomite use. The Transportation Equity Act
5 Representatives of the National Lime Association estimate that CO2 reabsorption that occurs from the use of lime may offset as much as a third of
the CO2 emissions from calcination.
6 Some carbide producers may also regenerate lime from their calcium hydroxide by-products, which does not result in emissions of CO2. In making
calcium carbide, quicklime is mixed with coke and heated in electric furnaces. The regeneration of lime in this process is done using a waste calcium
hydroxide (hydrated lime) [CaC2 + 2H2O -> C2H2 + Ca(OH)2], not calcium carbonate [CaCO3]. Thus, the calcium hydroxide is heated in the kiln to
simply expel the water [Ca(OH)2 + heat -» CaO + H2O] and no CO2 is released to the atmosphere.
7 Limestone and dolomite are collectively referred to as limestone by the industry, and intermediate varieties are seldom distinguished.
Industrial Processes 3-11
-------
Table 3-12: C02 Emissions from Limestone & Dolomite Use (Tg C02 Eq.)
Activity
Flux Stone
Glass Making
FGD
Magnesium Production
Total
Note; Totals may not sum due to independent rounding
1990
3.0
0.2
1.9
0.1
5.2
~ " • •
— ur —
ill
jjjnii nnii
'i -,- • ', S
f I
iffij1'1. ; r ,' y.
'¥": ~v ™:v:l
i , i
ft!
Table 3-13: C02 Emissions from Limestone & Dolomite
Activity
Flux Stone
Limestone
Dolomite
Glass Making
Limestone
Dolomite
FGD
Magnesium Production
Total
1990
3,005
2,554
452
189
189
NA
1,922
64
5,182
I
WL
£
1
F
t
IF^=
&_^
^-
Use
1
(
I
1995
3.9
0.5
2.6
7.0
(Gg)
1995
3,903
2,523
1,380
526
421
105
2,558
41
7,028
1996
4.2
0.4
2.7
0.1
7.4
1996
4,249
3,330
919
362
251
110
2,695
73
7,379
1997
5.0
0.4
2.9
0.1
8.4
1997
5,042
3,970
1,072
383
266
117
2,902
73
8,401
1998
5.1
0.2
2.8
0.1
8.2
1998
5,142
4,298
844
191
65
125
2,781
73
8,187
1999
6.1
0.2
2.8
0.1
9.1
1999
6,065
4,273
1,792
194
67
128
2,781
73
9,115
2000
6.1
0.2
2.8
0.1
9.2
2000
6,144
4,329
1,816
197
67
129
2,781
73
9,196
NA (Not Available)
Note: Totals may not sum due to independent rounding.
for the 21" Century, which commits over $200 billion dollars
to highway work through 2003, is expected to maintain the
upward trend in consumption.
Methodology
Carbon dioxide emissions were calculated by
multiplying the amount of limestone consumed by an
average carbon content for limestone, approximately 12.0
percent for limestone and 13.2 percent for dolomite (based
on stoichiometry). Assuming that all of the carbon was
oxidized and released to the atmosphere, the appropriate
emission factor was multiplied by the annual level of
consumption for flux stone, glass manufacturing, and FGD
systems to determine emissions.
Carbon dioxide emitted during the thermic reduction of
dolomite (CaMg (CO3)2) to magnesium metal vapor were
estimated based on magnesium production capacity and the
magnesium to carbon molar ratio. Operation at maximum
operational capacity is assumed, this overestimation accounts
forlessthanideal(chemically)production. Stoichiometrically,
two carbon molecules are emitted per magnesium molecule.
One plant in the United States produces magnesium metal from
the dolomitic process, the other production method used in the
United States produces magnesium from magnesium chloride
(electrolytic reduction). Capacity fluctuations are due to
variable furnace availability.
Data Sources
Consumption data for 1990 through 2000 of limestone
and dolomite used as flux stone and in glass manufacturing
(see Table 3-14) and production capacity of dolomitic
magnesium metal (see Table 3-15) were obtained from the
USGS (1993,1995a, 1995b, 1996,1997,1998,1999,2000,
2001). Consumption data for limestone used in FGD were
taken from unpublished survey data in the Energy
Information Administration's Form EIA-767, "Steam
Electric Plant Operation and Design Report," (EIA 1997,
1998,1999). For 1990 and 1994, the USGS did not provide
a breakdown of limestone and dolomite production by end-
use and for 2000 the end-use breakdowns had not yet been
finalized at the time of publication. Consumption figures
for these years were estimated by assuming that Limestone
and dolomite accounted for the same percentage of total
crushed stone consumption for a given year as the average
3-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-14: Limestone and Dolomite Consumption (Thousand Metric Tons)
* Activity 1990 1991 1992 1993 1994
Flux Stone 6,737 6,052 5,185 4,263 5,487
Limestone 5,804 5,213 4,447 3,631 3,149
Dolomite 933 838 738 632 2,339
Glass Making 430 386 495 622 949
Limestone 430 386 495 622 949
Dolomite NA NA NA NA NA
FGD 4,369 4,606 4,479 4,274 5,080
1995 1996 1997 1998 1999 2000
8,586 9,468 11,239 11,512 13,415 13,590
5,734 7,569 9,024 9,769 9,712 9,838
2,852 1,899 2,215 1,743 3,703 3,751
1,174 799 847 407 415 421
958 571 605 148 151 153 '
216 228 242 259 264 267
5,815 6,125 6,595 6,322 6,322 6,322
NA (Not Available) :
F'" " """ ' ""• • """" " " " -=- - --- -- - -- -
Table 3-15: Dolomitic Magnesium Metal Production
Capacity (Metric Tons)
L Year Production Capacity
h 1990 35,000 '
t 1991 35,000
L- 1992 14,909
& 1993 12,964
L :1994 21,111
|. 1995 22,222
£ 1996 40,000
t 1997 40,000
t 1998 40,000
L- 1999 40,000 '
1: 2000 40,000
1 2001 . .' .. 29,167
« " - - - . - •=•
of the percentages for the years before and after.8
Furthermore, following 1996, limestone used in glass
manufacture has only been reported for 1998. For 1996 and
1997, limestone used in glass manufacture was estimated
based on the percent of total crushed stone for 1995 and
1998. For 1999 and 2000, limestone used in glass
manufacture was estimated based on the percent of total
crushed stone for 1998.
It should be noted that there is a large quantity of
crushed stone reported to the USGS under the category
"unspecified uses." A portion of this consumption is
believed to be limestone or dolomite used as flux stone and
for glass manufacture. The quantity listed for "unspecified
uses" was, therefore, allocated to each reported end-use
according to each end-uses fraction of total consumption in
that year.9
Uncertainty
Uncertainties in this estimate are due in part, to
variations in the chemical composition of limestone. In
addition to calcite, limestone may contain smaller amounts
of magnesia, silica, and sulfur. The exact specifications for
limestone or dolomite used as flux stone vary with the
pyrometallurgical process, the kind of ore processed, and
the final use of the slag. Similarly, the quality of the
limestone used for glass manufacturing will depend on the
type of glass being manufactured.
Uncertainties also exist in the activity data. Much of
the limestone consumed in the United States is reported as
"other unspecified uses;" therefore, it is difficult to
accurately allocate this unspecified quantity to the correct
end-uses. Also, some of the limestone reported as
"limestone" is believed to actually be dolomite, which has
a higher carbon content than limestone. Lastly, the
uncertainty of the estimates for limestone used in glass
making are especially high. Large fluctuations in reported
consumption exist, reflecting year-to-year changes in the
number of survey respondees. The uncertainty resulting
from a shifting survey population is exacerbated by the gaps
in the time series of reports. However, since glass making
accounts for no more than 10 percent of limestone
consumption, its contribution to the overall emissions
estimate is low.
8 Exception: 1990 and 2000 consumption were estimated using the percentages for only 1991 and 1999, respectively.
9 This approach was recommended by USGS.
Industrial Processes 3-13
-------
Soda Ash Manufacture and
Consumption
Soda ash (sodium carbonate, Na2CO3) is a white
crystalline solid that is readily soluble in water and strongly
alkaline. Commercial soda ash is used as a raw material in
a variety of industrial processes and in many familiar
consumer products such as glass, soap and detergents, paper,
textiles, and food. It is used primarily as an alkali, either in
glass manufacturing or simply as a material that reacts with
and neutralizes acids or acidic substances. Internationally,
two types of soda ash are produced—natural and synthetic.
The United States produces only natural soda ash and is the
largest soda ash-producing country in the world. Trona is
the principal ore from which natural soda ash is made.
Only two States produce natural soda ash: Wyoming
and California. Of these two States, only Wyoming has net
emissions of CO2. This difference is a result of the
production processes employed in each State.10 During the
production process used in Wyoming, natural sources of
sodium carbonate are heated and transformed into a crude
soda ash mat requires further refining. Carbon dioxide (CO2)
is generated as a by-product of this reaction, and is
eventually emitted into the atmosphere. In addition, CO2
may also be released when soda ash is consumed.
In 2000, CO2 emissions from the manufacture of soda
ash from trona were approximately 1.5 Tg CO2 Eq. (1,529
Gg). Soda ash consumption in the United States also
generated 2.7 Tg CO2 Eq. (2,652 Gg) in 2000. Total
emissions from this source in 2000 were then 4.2 Tg CO2
Eq. (4,181 Gg) (see Table 3-16 and Table 3-17). Emissions
have fluctuated since 1990. These fluctuations were strongly
related to the behavior of the export market and the U.S.
economy. Emissions in 2000 decreased by 1 percent from
the previous year, and have increased 1 percent since 1990.
The United States has the world's largest deposits of
trona and represents about one-third of total world soda
ash output. The distribution of soda ash by end-use in 2000
was glass making, 50 percent; chemical production, 27
percent; soap and detergent manufacturing, 11 percent;
Table 3-16: C02 Emissions from Soda Ash
Manufacture and Consumption
f
fessB*
i
Year
1990
1995
1996
1997
1998 " '
1999
2000
, - --- --
Tg C02 Eq.
4.1.
4.3
4.2
4.4
4.3
4.2
4.2.
' • •;• •• • • •• 1
Table 3-17: C02 Emissions from Soda Ash
Manufacture and Consumption (Gg)
L Year
1990
If"' -r-
1995
1996
', 1997
r 1998
• 1999
: 2000
Manufacture
1,432
' T ^ y
1,607
1,588
1,666
1,607
1,549
1,529
Consumption
2,710
"""I
2,698
2,652
2,689
2,718
2,668
2,652
Total
4,142
SwM, *
4,305
4,239
4,355
4,325
4,217
4,181
- Note: Totals may not sum due to independent rounding.
distributors, 6 percent; flue gas desulfurization, and pulp
and paper production, 2 percent each; and water treatment
and miscellaneous, 1 percent each (USGS 2001).
Soda ash production and consumption decreased by 1
percent from 1999 values. Exports were a driving force
behind U.S. soda ash production and the Asian economic
crisis beginning in late 1997 has been cited as a major cause
for the drop in world soda ash demand. However, growing
demand in Asia and South America is expected to lead to
moderate growth (between 0.5 and 1 percent) in U.S. soda
ash production.
Construction is currently underway on a major soda
ash plant that will use a new feedstock—nahcolite, a natural
sodium bicarbonate found in deposits in Colorado's
Piceance Creek Basin. The new facility will have an annual
capacity of 900,000 tons of soda ash and is slated to open
in January 2001 (USGS 2000). Part of this production
10 In California, soda ash is manufactured using sodium carbonate-bearing brines instead of trona ore. To extract the sodium carbonate, the complex
brines arc first treated with CO2 in carbonation towers to convert the sodium carbonate into sodium bicarbonate, which then precipitates from the
brine solution. The precipitated sodium bicarbonate is then calcined back into sodium carbonate. Although CO2 is generated as a by-product, the CO2
is recovered and recycled for use in the carbonation stage and is not emitted.
3-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
process involves the stripping of CO2. At this point, however,
it is unknown whether any CO2 will be released to the
atmosphere or captured and used for conversion back to
sodium bicarbonate.
Methodology
During the production process, trona ore is calcined in
a rotary kiln and chemically transformed into a crude soda
ash that requires further processing. Carbon dioxide and
water are generated as by-products of the calcination
process. Carbon dioxide emissions from the calcination of
trona can be estimated based on the following chemical
reaction:
2(Na3H(CO3)2 x 2H2O) -» 3Na2CO3 + 5H2O + CO2
[trona] [soda ash]
Based on this formula, approximately 10.27 metric tons
of trona are required to generate one metric ton of CO2.
Thus, the 15.7 million metric tons of trona mined in 2000
for soda ash production (USGS 2001) resulted in CO2
emissions of approximately 1.5 Tg CO2 Eq. (1,529 Gg).
Once manufactured, most soda ash is consumed ha glass
and chemical production, with minor amounts in soap and
detergents, pulp and paper, flue gas desulfurization and
water treatment. As soda ash is consumed for these purposes,
additional CO2 is usually emitted. In these applications, it
is assumed that one mole of carbon is released for every
mole of soda ash used. Thus, approximately 0.113 metric
tons of carbon (or 0.415 metric tons of CO2) are released
for every metric ton of soda ash consumed.
Data Sources
The activity data for trona production and soda ash
consumption (see Table 3-18) were taken from USGS (1994,
1995, 1996, 1997, 1998, 1999, 2000, 2001). Soda ash
manufacture and consumption data were collected by the
USGS from voluntary surveys of the U.S. soda ash industry.
All six of the soda ash manufacturing operations in the
United States completed surveys to provide data to the
USGS.
Uncertainty
Emissions from soda ash manufacture are considered
to be relatively certain. Both the emissions factor and activity
data are reliable. However, emissions from soda ash
Table 3-18: Soda Ash Manufacture and Consumption
(Thousand Metric Tons)
siYear
£1990
fc1991
'•"1992
L1993
^1994
:~1995
S&1996
^1997
?? 1998
£1999
"2000
s;* Soda ash
Manufacture*
14,734
14,674
14,900 "
14,500
14,600
16,500
16,300
17,100
16,500
15,900
15,700
manufactured from trona ore only.
Consumption
6,527
6,278
6,360
6,350
6,240
6,510
6,470
6,670
6,550
6,430
6,390 :
consumption are dependent upon the type of processing
employed by each end-use. Specific information
characterizing the emissions from each end-use is limited.
Therefore, uncertainty exists as to the accuracy of the
emission factors.
Ferroalloy Production
Carbon dioxide is emitted from the production of
several ferroalloys. Ferroalloys are composites of iron and
other elements often including silicon, manganese, and
chromium. When incorporated in alloy steels, ferroalloys
are used to alter the material properties of the steel. Estimates
from two types of ferrosilicon (25 to 55 percent and 56 to
95 percent silicon), silicon metal (about 98 percent silicon),
and miscellaneous alloys (36 to 65 percent silicon) have
been calculated. Emissions from the production of
ferrochromium and ferromanganese are not included here
because of the small number of manufacturers of these
materials. As a result, government information disclosure
rules prevent the publication of production data for them.
Similar to emissions from the production of iron and steel,
CO2is emitted when metallurgical coke is oxidized during
a high-temperature reaction with iron and the selected
alloying element. Due to the strong reducing environment,
CO is initially produced. The CO is eventually oxidized,
becoming CO2. A representative reaction equation for the
production of 50 percent ferrosilicon is given below:
Emissions of CO2 from ferroalloy production in 2000
were 1.7 Tg CO2 Eq. (1,719 Gg) (see Table 3-19).
Industrial Processes 3-15
-------
Table 3-19: C02 Emissions from Ferroalloy Production
Year
1990
PF=&=^- 3
1995
1996
1997
1998
1999
2000
Tg C02 Eq.
n,-^r_2-CLT_,
1.9
2.0
2.0
2.0
2.0
1.7
fig
,,-_^_I980_
1,866
1,954
2,038
2,027
1,996
1,719
Methodology
Emissions of CO2 from ferroalloy production were
calculated by multiplying annual ferroalloy production by
material-specific emission factors. Emission factors taken
from the Revised 1996 IPCC Guidelines (IPCC/UNEP/
OECD/EEA 1997) were applied to ferroalloy production.
For ferrosilicon alloys containing 25 to 55 percent silicon
and miscellaneous alloys (including primarily magnesium-
ferrosilicon, but also including other silicon alloys)
containing 32 to 65 percent silicon, an emission factor for
ferrosilicon 50 percent (2.35 tons CO2/ton of alloy produced)
was applied. Additionally, for ferrosilicon alloys containing
56 to 95 percent silicon, an emission factor for ferrosilicon
75 percent (3.9 tons CO2 per ton alloy produced) was
applied. The emission factor for silicon metal was assumed
to be 4.3 tons CCyton metal produced. It was assumed that
100 percent of the ferroalloy production was produced using
petroleum coke using an electric arc furnace process (IPCC/
UNEP/OECD/IEA 1997) although some ferroalloys may
have been produced with coking coal, wood, other biomass,
or graphite carbon inputs. The amount of petroleum coke
consumed in ferroalloy production was calculated assuming
that the petroleum coke used is 90 percent carbon and 10
percent inert material.
Data Sources
Emission factors for ferroalloy production were taken from
ttaRevised 1996IPCCGuidelines (IPCC/UNEP/OECD/ffiA
1997). Ferroalloy production data for 1990 through 1999 (see
Table 3-20) were obtained from the U.S. Geological Survey's
(USGS) Minerals Yearbook: Silicon Annual Report (USGS
1991,1992,1993,1994,1995,1996,1997,1998,1999,2000).
Data for 2000 were obtained from USGS (2001) Mineral
Industry Surveys - Silicon in December 2000. Until 1999, the
USGS reported production of ferrosih'con 25 to 55 percent
separately from production of miscellaneous alloys containing
32 to 65 percent silicon; beginning in 1999, the USGS reported
these as a single category (see Table 3-20). The composition
data for petroleum coke was obtained from Onder and
Bagdoyan (1993).
Uncertainty
Although some ferroalloys may be produced using wood
or other biomass as a carbon source, information and data
regarding these practices were not available. Emissions from
ferroalloys produced with wood or other biomass would not
be counted under this source because wood-based carbon is
of biogenic origin.11 Emissions from ferroalloys produced with
coking coal or graphite inputs would be counted in national
trends, but may generate differing amounts of CO2 per unit of
ferroalloy produced compared to the use of petroleum coke.
The most accurate method for these estimates would be basing
calculations on the amount of reducing agent used in the
process, rather than the amount of ferroalloys produced. These
data were not available, however.
Also, annual ferroalloy production is now reported by
the USGS in three broad categories: ferroalloys containing
25 to 55 percent silicon (including miscellaneous alloys),
ferroalloys containing 56 to 95 percent silicon, and silicon
metal. It was assumed that the IPCC emission factors apply
to all of the ferroalloy production processes, including
miscellaneous alloys. Finally, production data for silvery
pig iron (alloys containing less than 25 percent silicon) are
not reported by the USGS to avoid disclosing company
proprietary data. Emissions from this production category,
therefore, were not estimated.
Titanium Dioxide Production
Titanium dioxide (TiO2) is a metal oxide manufactured
from titanium ore, and is principally used as a pigment.
Titanium dioxide is a principal ingredient in white paint,
and TiO2 is also used as a pigment in the manufacture of
white paper, foods, and other products. There are two
processes for making TiO2, the chloride process and the
11 Emissions and sinks of biogenic carbon are accounted for in the Land-Use Change and Forestry chapter.
3-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-20: Production of Ferroalloys (Metric Tons)
\- Year
• .1990
I 1996
f 1997
I 1998
" 1999
L.2000
>- NA (Not Available)
Ferrosilicon 25%-55%
321,385
•~-g^ — ™- •*•
182,000
175,000
162,000
252,000
229,000
Ferrosilicon 56%-95%
109,566
'^"'^^iHflOO****^**'
132,000
147,000
147,000
145,000
100,000
Silicon Metal
145,744
'"'TesJoiT"'"
175,000
187,000
195,000
195,000
184,000
Misc. Alloys (32-65%)
72,444
^ l _ 7:..;^^r;^,.^;,^".'.:;.r~j
""" ^99,500""""""" ~"'".
110,000
106,000
99,800
NA
NA.. ;
.
sulfate process. Carbon dioxide is emitted from the chloride
process, which uses petroleum coke and chlorine as raw
materials and emits process-related CO2. The sulfate process
does not use petroleum coke or other forms of carbon as a
raw material and does not emit CO2. In 2000, approximately
93 percent of the titanium dioxide production capacity was
chloride process and the remainder was sulfate process.
The chloride process is based on the following chemical
reactions:
2 FeTiO3 + 7 CL, + 3 C -» 2 TiCl4 + 2 FeCl3 + 3 CO2
2 TiCl4 + 2 O2 -> 2 TiO2 + 40,,
The carbon in the first chemical reaction is provided
by petroleum coke, which is oxidized in the presence of the
chlorine and FeTiO3 (the Ti-containing ore) to form CO2.
More than 90 percent of U.S. TiO2 was produced through
chloride process, and a special grade of petroleum coke is
manufactured specifically for this purpose. Emissions of
CO2 from titanium dioxide production have grown from 1.3
Tg CO2 Eq. (1,308 Gg) in 1990 to 2.0 Tg CO2 Eq. (1,963
Gg) in 2000, due to growth in titanium dioxide production
(see Table 3-21).
Table 3-21: C02 Emissions from Titanium Dioxide
-Year
^1990
.. 1995^"'^"^"
\, 1996
H997
; 1998
-1999
.2000
TgC02Eq.
1.3
^.-.«-»_^w.— »«.
1.7
i;s
1.8
1.9
2.0
fig
1,308
""?T67T*"
1,657
1,836
1,819
1,853
1,963
... , ,f
Methodology
Emissions of CO2 from titanium dioxide production
were calculated by multiplying annual titanium dioxide
production by chlorine process-specific emission factors.
Data were obtained for the total amount of titanium
dioxide produced each year, and it was assumed that 93
percent of the total production in 2000 was produced using
the chloride process. An emission factor of 0.4 metric tons
C/metric ton TiO2 was applied to the estimated chloride
process production. It was assumed that all titanium dioxide
produced using the chloride process was produced using
petroleum coke, although some titanium dioxide may have
been produced with graphite or other carbon inputs. The
amount of petroleum coke consumed annually in titanium
dioxide production was calculated based on the assumption
that petroleum coke used in the process is 90 percent carbon
and 10 percent inert materials.
Data Sources
The emission factor for the titanium dioxide chloride
process was taken from the report Everything You 've Always
Wanted to Know about Petroleum Coke (Onder and
Bagdoyan 1993). Titanium dioxide production data for 1990
through 1999 (see Table 3-22) were obtained from the U.S.
Geological Survey's (USGS) Minerals Yearbook: Titanium
Annual Report (USGS 1991,1992,1993,1994,1995,1996,
1997,1998,1999,2000). Data for 2000 were obtained from
USGS (2001) Mineral Industry Surveys - Titanium in
December 2000. Data for the percentage of the total titanium
dioxide production capacity that is chloride process for 1994
through 1999 were also taken from the USGS Minerals
Yearbook. Percentage chloride process data were not
available for 1990 through 1993, and data from the 1994
Industrial Processes 3-17
-------
Table 3-22: Titanium Dioxide Production
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Metric Tons
979,000
992,000
1,140,000 :
1,160,000
1,250,000
1,250,000
1,230,000
1,340,000
1,330,000
1,350,000
1,440,000
USGS Minerals Yearbook were used for these years. The
chloride process percentage for 2000 was estimated from
data published in the Chemical Market Report (2000). The
composition data for petroleum coke were obtained from
Onder and Bagdoyan (1993).
Uncertainty
Although some titanium dioxide may be produced using
graphite or other carbon inputs, information and data
regarding these practices were not available. Titanium
dioxide produced using graphite inputs may generate
differing amounts of CO2 per unit of titanium dioxide
produced compared to the use of petroleum coke. The most
accurate method for these estimates would be basing
calculations on the amount of reducing agent used in the
process, rather than the amount of titanium dioxide
produced. These data were not available, however.
Also, annual titanium production is not reported by
USGS by the type of production process used (chloride or
sulfate). Only the percentage of total production capacity is
reported. It was assumed that titanium dioxide was produced
using the chloride process and the sulfate process in the
same ratio as the ratio of the total U.S. production capacity
for each process. This assumes that the chloride process
plants and sulfate process plants operate at the same level
of utilization. Finally, the emission factor was applied
uniformly to all chloride process production, and no data
were available to account for differences in production
efficiency among chloride process plants. In calculating the
amount of petroleum coke consumed in chloride process
titanium dioxide production, literature data were used for
petroleum coke composition. Certain grades of petroleum
coke are manufactured specifically for use in the titanium
dioxide chloride process, however this composition
information was not available.
Carbon Dioxide Consumption
Carbon dioxide (CO2) is used for a variety of
applications, including food processing, chemical
production, carbonated beverages, and enhanced oil
recovery (EOR). Carbon dioxide used for EOR is injected
into the ground to increase reservoir pressure, and is
therefore considered sequestered.12 For'the most part,
however, CO2 used in non-EOR applications will eventually
be released to the atmosphere. ;
Carbon dioxide is produced from a small number of
natural wells, as a by-product from the production of
chemicals (e.g., ammonia), or separated from crude oil and
natural gas. Depending on the raw materials that are used,
the by-product CO2 generated during these production
processes may akeady be accounted for in the CO2 emission
estimates from fossil fuel consumption (either during
combustion or from non-fuel uses). For example, ammonia
is primarily manufactured using natural gas as a feedstock.
Carbon dioxide emissions from this process are accounted
for in the Energy chapter under Fossil Fuel Combustion
and, therefore, are not included here.
In 2000, CO2 emissions from this source not accounted
for elsewhere were 1.4 Tg CO2 Eq. (1,361. Gg) (see Table
3-23). This amount represents a decrease of 13 percent from
the previous year and is 70 percent higher than emissions
in 1990.
Methodology
Carbon dioxide emission estimates were based on
CO2 consumption with the assumption that the end-
use applications, except enhanced oil recovery,
eventually release 100 percent of the CO2 into the
12 It is unclear to what extent the CO2 used for EOR will be re-released. For example, the CO2 used for EOR may show up at the wellhead after a few
years of injection (Hangebrauk et al. 1992). This CO2, however, is typically recovered and re-injected into the well. More research is required to
determine the amount of CO2 that in fact escapes from EOR operations. For the purposes of this analysis, it is assumed that all of the CO2 remains
sequestered.
3-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-23: C02 Emissions from Carbon Dioxide
Consumption
: Year
:. 1990
te»jji~£~jj»» i£~^..
I 1995
ngge
1 1997
I 1998
! 1999
K 2000
Tg C02 Eq.
0.8
1.0
1.1
1.3
1.4
1.6
1.4
Gg
800
968
1,140
1,294
1,413
1,572
1,361
iX^^gfM^M
atmosphere. Carbon dioxide consumption for uses
other than enhanced oil recovery was about 6,807
thousand metric tons in 2000. The Freedonia Group
estimates that, in the United States, there is an 80
percent to 20 percent split between CO2 produced as
a by-product and CO2 produced from natural wells.
Thus, emissions are equal to 20 percent of CO2
consumption. The remaining 80 percent was assumed
to already be accounted for in the CO2 emission
estimates from other categories (the most important
being Fossil Fuel Combustion).
Data Sources
Carbon dioxide consumption data (see Table 3-24) were
obtained from Industrial Gases to 2004, published by the
Freedonia Group Inc. (1994,1996,1999a, 1999b, 2000). The
2000 report contains actual data for 1999 only. Data for 1996
were obtained by personal communication with Paul Ita of the
Freedonia Group Inc. (Ita 1997). Data for 1997 and 2000
production were calculated from annualized growth rates for
1994 through 1996 and 1997 through 1999 respectively. The
1997 and 2000 values for enhanced oil recovery were set equal
Table 3-24: Carbon Dioxide Consumption
Year
Thousand Metric Tons
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
4,000
4,200
4,410
4,559
4,488
4,842
5,702
6,468 :
7,067
6,512
6,807
•• ' - ---• »
to the 1998 and 1999 values, respectively. The percent of carbon
dioxide produced from natural wells was obtained from
Freedonia Group Inc. (1991).
Uncertainty
Uncertainty exists in the assumed allocation of carbon
dioxide produced from fossil fuel by-products (80 percent)
and carbon dioxide produced from wells (20 percent). In
addition, it is possible that CO2 recovery exists in particular
end-use sectors. Contact with several organizations did not
provide any information regarding recovery. More research
is required to determine the quantity, if any, that may be
recovered.
Petrochemical Production
Small amounts of methane (CH^ are released during
the production of some petrochemicals. Petrochemicals are
chemicals isolated or derived from petroleum or natural gas.
Emissions are presented here from the production of five
chemicals: carbon black, ethylene, ethylene dichloride,
styrene, and methanol.
Carbon black is an intensely black powder made by
the incomplete combustion of an aromatic petroleum
feedstock. Most carbon black produced in the United States
is added to rubber to impart strength and abrasion resistance,
and the tire industry is by far the largest consumer. Ethylene
is consumed in the production processes of the plastics
industry including polymers such as high, low, and linear
low density polyethylene (HDPE, LDPE, LLDPE),
polyvinyl chloride (PVC), ethylene dichloride, ethylene
oxide, and ethylbenzene. Ethylene dichloride is one of the
first manufactured chlorinated hydrocarbons with reported
production as early as 1795. In addition to being an
important intermediate in the synthesis of chlorinated
hydrocarbons, ethylene dichloride is used as an industrial
solvent and as a fuel additive. Styrene is a common precursor
for many plastics, rubber, and resins. It can be found in
many construction products, such as foam insulation, vinyl
flooring, and epoxy adhesives. Methanol is an alternative
transportation fuel as well as a principle ingredient in
windshield wiper fluid, paints, solvents, refrigerants, and
disinfectants. In addition, methanol-based acetic acid is used
in making PET plastics and polyester fibers. The United
States produces close to one quarter of the world's supply
of methanol.
Industrial Processes 3-19
-------
Aggregate emissions of CH4 from petrochemical
production in 2000 were 1.7 Tg CO2 Eq. (79 Gg) (see
Table 3-25).
Table 3-25: CH4 Emissions from Petrochemical
Production
Year
1990
f'i i"1""''1"1"1""1 '
9M,-.}, -„ —
1995
1996
1997
1998
1999
2000
Tg C02 Eq.
1.2
1 1 , P i i i i
1.5
1.6
1.6
1.6
1.7
1.7
Gg
56
iv qi , mmfpHp^rfip men
72
75
77
78
79
79
I
Methodology
Emissions of CH4 were calculated by multiplying annual
estimates of chemical production by an emission factor. The
following factors were used: 11 kg CH4/metric ton carbon black,
1 kg CH4/metric ton ethylene, 0.4 kg CH4/metric ton ethylene
dichloride,13 4 kg CH4/metric ton styrene, and 2 kg CH4/metric
ton methanol. These emission factors were based upon
measured material balances. Although the production of other
chemicals may also result in methane emissions, there were
not sufficient data to estimate their emissions.
Data Sources
Emission factors were taken from the Revised 1996IPCC
Guidelines (IPCC/UNEP/OECD/IEA 1997). Annual
production data for 1990 through 1998 (see Table 3-26) were
obtained from the Chemical Manufacturer's Association
Statistical Handbook (CMA1999). Production for 1999 and
2000 was projected by the American Chemistry Council (2001).
Uncertainty
The emission factors used here were based on a limited
number of studies. Using plant-specific factors instead of
average factors could increase the accuracy of the emissions
estimates, however, such data were not available. There may
also be other significant sources of methane arising from
petrochemical production activities that have not been
included in these estimates.
Silicon Carbide Production
Methane is emitted from the production of silicon
carbide, a material used as an industrial abrasive. To make
silicon carbide (SiC), quartz (SiO2) is reabted with carbon
hi the form of petroleum coke. Methane is produced during
this reaction from volatile compounds in the petroleum coke.
Although CO2 is also emitted from this production process,
the requisite data were unavailable for these calculations.
Regardless, they are already accounted for under CO2 from
Fossil Fuel Combustion in the Energy chapter. Emissions
of CH4 from silicon carbide production in 2000 (see Table
3-27) were 1 Gg CH4(0.01 Tg CO2 Eq.).
Table 3-27: CH4 Emissions from Silicon
Carbide Production
"Year
tg C02 Eq.
4§IL
:-*199T
- 1996
L 1997
- 1998
T1999
r 2000
+ Does not exceed 0.05 Tg C02 Eq.
Table 3-26: Production of Selected Petrochemicals (Thousand Metric Tons)
Chemical
Carbon Black
Ethylene
Ethylene Dichloride
Styrene
Methanol
1990
1,306
16,542
6,282
3,637
3,785
1991
1,225
18,124
6,221
3,681
3,948
1992
1,365
18,563
6,872
4,082
3,666
1993
1,452
18,709
8,141
4,565
4,782
1994
1,492
20,201
8,482
5,112
4,904
1995
1,524
21,199
7,829
5,167
4,991
1996
1,560
22,197
9,303
5,387
5,280
1997
1,588
23,088
10,324
5,171
5,743
1998
1,610
23,474
11,080
5,183
5,861
1999
1,642
25,119
10,309
5,410
5,303
2000
1,674
2.4,971
9,866
5,421
5,221
13 The emission factor obtained from IPCC/UNEP/OECD/IEA (1997), page 2.23 is assumed to have a misprint; the chemical identified should be
dichloroethylene (CjHjCy instead of ethylene dichloride (C2H4Cl2).
3-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Methodology
Emissions of CH4 were calculated by multiplying annual
silicon carbide production by an emission factor (11.6 kg CH4/
metric ton silicon carbide). This emission factor was derived
empirically from measurements taken at Norwegian silicon
carbide plants (ffCC/UNEP/OECD/IEA 1997).
Data Sources
The emission factor was taken from the Revised 1996
IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).
Production data for 1990 through 2000 (see Table 3-28)
were obtained from the Minerals Yearbook: Volume I-Metals
andMinerals, Manufactured Abrasives (USGS 1991,1992,
1993, 1994, 1995, 1996, 1997, 1998, 1999, 2000, 2001).
Table 3-28: Production of Silicon Carbide
Year
1990
1991
1992
1993
1994
1995
1996
1997..
1998
1999
2000
Metric Tons
105,000
78,900 :
84,300
74,900
84,700
75,400
73,600
68,200
69,800
65,000
45,000
-
Uncertainty
The emission factor used here was based on one study
of Norwegian plants. The applicability of this factor to
average U.S. practices at silicon carbide plants is uncertain.
A better alternative would be to calculate emissions based
on the quantity of petroleum coke used during the production
process rather than on the amount of silicon carbide
produced. These data were not available, however.
Adipic Acid Production
Adipic acid production has been identified as an
anthropogenic source of nitrous oxide (N2O) emissions.
Worldwide, there are few adipic acid plants. The United
States is the major producer with three companies in four
locations accounting for approximately forty percent of
world production. Adipic acid is a white crystalline solid
used in the manufacture of synthetic fibers, coatings,
plastics, urethane foams, elastomers, and synthetic
lubricants. Commercially, it is the most important of the
aliphatic dicarboxylic acids, which are used to manufacture
polyesters. Approximately 80 percent of all adipic acid
produced in the United States is used in the production of
nylon 6,6. Food grade adipic acid is also used to provide
some foods with a "tangy" flavor.
Adipic acid is produced through a two-stage process
during which N2O is generated in the second stage. The
first stage of manufacturing usually involves the oxidation
of cyclohexane to form a cyclohexanone/cyclohexanol
mixture. The second stage involves oxidizing this mixture
with nitric acid to produce adipic acid. Nitrous oxide is
generated as a by-product of the nitric acid oxidation stage
and is emitted in the waste gas stream. Process emissions
from the production of adipic acid will vary with the types
of technologies and level of emissions controls employed
by a facility. In 1990, two of the three major adipic acid
producing plants had N2O abatement technologies in place
and as of 1998, the three major adipic acid production
facilities had control systems in place.14 Only one small
plant, representing approximately two percent of production,
does not control for N2O.
Nitrous oxide emissions from this source were
estimated to be 8.11 Tg CO2 Eq. (26.2 Gg) in 2000 (see
Table 3-29).
14 During 1997, the N2O emission controls installed by the third plant operated for approximately a quarter of the year.
Industrial Processes 3-21
-------
Table 3-29: N20 Emissions from Adipic Acid
Production
Table 3-30: Adipic Acid Production
Year
1990
•' S • i !
1995
1996
1997
1998
1999
2000
Tg C02 Eq.
14.9
{' ,;i:H " ' T -r-
17.9
17.8
11.5
7.7
7.7
8.1
fig
48
, v~ ,-FT"
58
57
37
25
25
26
Year
Thousand Metric Tons
National adipic acid production has increased about
50 percent over the period of 1990 through 2000, to
approximately 1.1 million metric tons. This increase was
primarily due to a 120,000 metric ton expansion in
production capacity and rising demand for engineering
plastics. At the same time, emissions have been significantly
reduced due to the widespread installation of pollution
control measures.
Methodology
For two plants, emission estimates were based on
information obtained directly from the plant engineer. For
the other two plants, N2O emissions were calculated by
multiplying adipic acid production by the ratio of N2O
emitted per unit of adipic acid produced and adjusting for
the actual percentage of N2O released as a result of plant-
specific emission controls. Because emissions of N2O in
the United States are not regulated, emissions have not been
well characterized. However, on the basis of experiments
(Thiemens and Trogler 1991), the overall reaction
stoichiometry for N2O production in the preparation of
adipic acid was estimated at approximately 0.3 kg of N2O
per kilogram of product. Emissions are estimated using the
following equation:
N,O emissions = [production of adipic acid] x
[0.3 kg N2O /kg adipic acid] x [ 1 - (N2O destruction factor
X abatement system utility factor) ]
The "N2O destruction factor" represents the amount of
N,O expressed as a percentage of N2O emissions that are
destroyed by the currently installed abatement technology.
The "abatement system utility factor" represents the percent
- 1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
735
771
708
765
815
816
835
860
866
1,100
1,128
of time that the abatement equipment operates. Overall, in
the United States, two of the plants employ catalytic
destruction, one plant employs thermal destruction, and the
smallest plant uses no N2O abatement equipment. The N2O
abatement system destruction factor is assumed to be 95
percent for catalytic abatement and 98 percent for thermal
abatement (Reimer et al. 1999, Reimer 1999).
Data Sources
National adipic acid production data for 1990 through
1995 (see Table 3-30) were obtained from Chemical and
Engineering News, "Facts and Figures" and "Production
of Top 50 Chemicals" (C&EN 1992, 1993, 1994, 1995,
1996). For 1996 and 1997 data were projected from the
1995 manufactured total based upon suggestions from
industry contacts. For 1998, production data were obtained
from Chemical Week, Product focus: adipic :acid/adiponitrile
(CW 1999). Production data for 1999 are based on an
estimate provided by the adipic acid industry (Reimer 2000).
The production data for the smallest plant in 2000 was
obtained from Chemical Week (Westeryelt 2000). The
emission factor was taken from Thiemens and Trogler
(1991). Adipic acid plant capacities for 1998, 1999, and
2000 were updated using Chemical Week, Product focus:
adipic acid/adiponitrile (CW 1999, 2001). Plant capacities
for previous years were obtained from Chemical Market
Reporter (1998). The national production and plant
capacities were utilized for two of the four plants.
Information for the other two plants was taken directly from
the plant engineer (Childs 2000).
3-22 inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Uncertainty
Because N2O emissions are controlled in some adipic
acid production facilities, the amount of N2O that is actually
released will depend on the level of controls in place at a
specific production plant. Thus, in order to calculate
emissions, it is necessary to have production data on a plant-
specific basis. In most cases, however, these data are
confidential. As a result, plant-specific production figures
were estimated by allocating total adipic acid production
using existing plant capacities. This creates a degree of
uncertainty in the adipic acid production data used to derive
the emission estimates as it is necessary to assume that all
plants operate at equivalent utilization levels. For two of
the plants, estimates were calculated based on information
obtained directly from the plant.
The emission factor was based on experiments~(Thiemens
andTrogler 1991) that attempt to replicate the industrial process
and, thereby, measure the reaction stoichiometry for N2O
production in the preparation of adipic acid. However, the
extent to which the lab results are representative of actual
industrial emission rates is not known.
Nitric Acid Production
Table 3-31: N20 Emissions from Nitric Acid
Production
Nitric acid (HNO3) is an inorganic compound used
primarily to make synthetic commercial fertilizers. It is also
a major component in the production of adipic acid—a
feedstock for nylon—and explosives. Virtually all of the
nitric acid produced in the United States is manufactured
by the catalytic oxidation of ammonia (EPA 1997). During
this reaction, N2O is formed as a by-product and is released
from reactor vents into the atmosphere.
Currently, the nitric acid industry controls for NO and
NO2, (i.e., NOx). As such the industry uses a combination
of non-selective catalytic reduction (NSCR) and selective
catalytic reduction (SCR) technologies. In the process of
destroying NOx, NSCR systems are also very affective at
destroying N2O. However, NSCR units are generally not
preferred in modern plants because of high energy costs
and associated high gas temperatures. NSCRs were widely
installed in nitric plants built between 1971 and 1977.
Currently, it is estimated that approximately 20 percent of
feYear
£.. ...
1^1996
F1997
1:1998
PS 1999
|;2000_,
ft-: ' -
t . '
Tg C02 Eq.
17.8
|t|b™>-sS3gS^.^^^!irf^^i!i^^
19.9
20.7
21.2
20.9
20.1
19.8
Gg
58 ''••
64
67 ":
68
67 :
65
64
nitric acid plants use NSCR (Choe, et al. 1993). The
remaining 80 percent use SCR or extended absorption,
neither of which is known to reduce N2O emissions.
Nitrous oxide emissions from this source were
estimated at 19.8 Tg CO2 Eq. (64 Gg) in 2000 (see Table
3-31). Emissions from nitric acid production have increased
11 percent since 1990.
Methodology
Nitrous oxide emissions were calculated by multiplying
nitric acid production by the amount of N2O emitted per
unit of nitric acid produced. The emissions factor was
determined as a weighted average of 2 kg for plants using
non-selective catalytic reduction (NSCR) systems and 9.5
kg for plants not equipped with NSCR (Reimer et al. 1992).
An estimated 20 percent of HNO3 plants in the United States
were equipped with NSCR (Choe, et al. 1993). In the process
of destroying NOx, NSCR systems also destroy 80 to 90
percent of the N2O. Hence, the emission factor is equal to
(9.5 x 0.80) + (2 x 0.20) = 8 kg N2O / metric ton HNO3.
Data Sources
Nitric acid production data for 1990 through 2000 (see
Table 3-32) were obtained from Chemical and Engineering
News, "Facts and Figures" (C&EN 2001). The emission
factor range was taken from Reimer et al. (1992).
Industrial Processes 3-23
-------
Table 3-32: Nitric Acid Production
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Thousand Metric Tons
7,196
7,191
7,381
7,488
7,905
8,020
8,351
8,557
8,423
8,115
7,981
Substitution of Ozone
Depleting Substances
Uncertainty
In general, the nitric acid industry is not well
categorized. A significant degree of uncertainty exists in
nitric acid production figures because nitric acid plants are
often part of larger production facilities, such as fertilizer
or explosives manufacturing. As a result, only a small
volume of nitric acid is sold on the market making
production quantities difficult to track. Emission factors are
also difficult to determine because of the large number of
plants using many different technologies. Based on expert
judgment, it is estimated that the N2O destruction factor for
NSCR nitric acid facilities is associated with an uncertainty
of approximately ±10 percent.
Hydrofluorocarbons (HFCs) and perfluorocarbons
(PFCs) are used primarily as alternatives to several classes
of ozone-depleting substances (ODSs) thatare being phased
out under the terms of the Montreal Protocol and the Clean
Air Act Amendments of 1990.15 Ozone depleting
substances—chlorofluorocarbons (CFCs), halons, carbon
tetrachloride, methyl chloroform, and hydrochloro-
fluorocarbons (HCFCs)—-are used in a variety of industrial
applications including refrigeration and air conditioning
equipment, solvent cleaning, foam production, sterilization,
fire extinguishing, and aerosols. Although HFCs and PFCs,
unlike ODSs, are not harmful to the stratospheric ozone
layer, they are potent greenhouse gases. Emission estimates
for HFCs and PFCs used as substitutes for ODSs are
provided in Table 3-33 and Table 3-34.
In 1990 and 1991, the only significant emissions of
HFCs and PFCs as substitutes to ODSs were relatively small
amounts of HFC-152a—a component of the refrigerant
blend R-500 used in chillers—and^ HFC-134a in
refrigeration end-uses. Beginning in 1992, HFC-134a was
used in growing amounts as a refrigerant in motor vehicle
air conditioners and in refrigerant blends such as R-404A.16
Table 3-33: Emissions of HFCs and PFCs from ODS Substitution (Tg C02 Eq.)
Gas
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-236fa
CF4
Others*
Total
1990
+
+
+
0.7
+
+
+
0.2
0.9
i
m
js~_ _.
E£-
r
i
f.
fr
I
•r-
"
-9
*
1
. i
1
•S
i
i
1
c
l»
^
1995
0.1
+
1.3
15.9
0.4
+
+
4.1
21.8
1996
0.2
+
1.9
21.1
0.8
+
+
6.7
30.6
1997
0.2
+
2.5
26.2
1.3
0.1
+
7.7
38.0
1998
0.3
+
3.1
30.0
1.9
0.8
+
8.8
44.9
1999
0.4
+
3.6
33.9
2.6
1.3
+
9.4
51.3
2000
0.5
0.1
4.4
37.6
3.4
1.9
+
10.0
57.8
+ Does not exceed 0.05 Tg G02 Eq.
* Others include HFC-152a, HFC-227ea, HFC-4310mee, and PFC/PFPEs, the latter being a proxy for a diverse collection of PFCs and
perfluoropolyethers (PFPEs) employed for solvent applications. For estimating purposes, the GWP value used for PFC/PFPEs was based upon C6F14.
Note: Totals may not sum due to independent rounding.
15 [42 U.S.C § 7671, CAA § 601]
16 R-404 contains HFC-125, HFC-143a, and HFC-134a.
3-24 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-34: Emissions of HFCs and PFCs from ODS Substitution (Mg)
Gas
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-236fa
CF4
Others*
1990 1995
+ El ' 8
+ fcgj +
+ 478
564 12,232
ilEr-r"i
+ +
-- - M -M
1996
14
3
675
16,211
209
+
+
_.. M
1997
20
7
889
20,166
334
15
+
M
1998
28
11
1,116
23,089
488
120
+
M
1999
36
17
1,289
26,095
676
213
1
M
2000
45
94
1,559
28,906
903
296
1
M
M (Mixture of Gases)
+ Does not exceed 0,5 Mg
* Others include HFC-152a, HFG-227ea, HFC-4310mee and PFC/PFPEs, which are a proxy for a diverse collection of PFCs and perfluoropolyethers
(PFPEs) employed for solvent applications.
In 1993, the use of HFCs in foam production and as an
aerosol propellant began, and in 1994 these compounds also
found applications as solvents and sterilants. In 1995, ODS
substitutes for halons entered widespread use in the United
States as halon production was phased-out.
The use and subsequent emissions of HFCs and PFCs
as ODS substitutes has been increasing from small amounts
in 1990 to 57.8 Tg CO2 Eq. in 2000. This increase was in
large part the result of efforts to phase out CFCs and other
ODSs in the United States. In the short term, this trend is
expected to continue, and will likely accelerate in the next
decade as HCFCs, which are interim substitutes in many
applications, are themselves phased-out under the provisions
of the Copenhagen Amendments to the Montreal Protocol.
Improvements in the technologies associated with the use
of these gases and the introduction of alternative gases and
technologies, however, may help to offset this anticipated
increase in emissions.
Methodology and Data Sources
A detailed vintaging model of ODS-containing
equipment and products was used to estimate the actual-—•
versus potential—emissions of various ODS substitutes,
including HFCs and PFCs. The name of the model refers to
the fact that the model tracks the use and emissions of
various compounds for the annual "vintages" of new
equipment that enter service in each end-use. This vintaging
model predicts ODS and ODS substitute use in the United
States based on modeled estimates of the quantity of
equipment or products sold each year containing these
chemicals and the amount of the chemical required to
manufacture and/or maintain equipment and products over
tune. Emissions for each end-use were estimated by applying
annual leak rates and release profiles, which account for
the lag hi emissions from equipment as they leak over time.
By aggregating the data for more than 40 different end-uses,
the model produces estimates of annual use and emissions
of each compound. Further information on the Vintaging
Model is contained in Annex J.
Uncertainty
Given that emissions of ODS substitutes occur from
thousands of different kinds of equipment and from millions
of point and mobile sources throughout the United States,
emission estimates must be made using analytical tools such
as the Vintaging Model or the methods outlined in IPCC/
UNEP/OECD/IEA (1997). Though the model is more
comprehensive than the IPCC default methodology,
significant uncertainties still exist with regard to the levels
of equipment sales, equipment characteristics, and end-use
emissions profiles that were used to estimate annual
emissions for the various compounds.
Industrial Processes 3-25
-------
Table 3-35: C02 Emissions from Aluminum
Production
Table 3-36: PFC Emissions from Aluminum Production
(Tg C02 Eq.)
Year
1990
OfS :-: -» 1- £
1995
1996
1997
1998
1999
2000
Tg C02 Eq.
6.3
!;!ir , 4 •, ; ,, ";i:|,,i,!11 ^i:^;,,, •;•,,'' >»«,j' '''•[!
5.3
5.6
5.6
5.8
5.9
5.4
Gg
6,315
' ' Jluj> '1 i"i:"' '"l lJ? '' '• '' i )"'•' I r ll
5,265
5,580
5,621
5,792
5,895
5,410
Year
; 1990
Ii*^af995ljl
1996
1997
1998
1999
2000
CF4
15.8
10.5
11.1
9.8
8.1
8.0
7.1
C2F6
2.3
iisJJiHS&^at
1.3
1.4
1.2
0.9
0.9
0.8
Total
;18.1
di4S;5S- S|ilsS$;|;S|
12.5
11.0
9.0
8.9
7.9
I "Note: Totals may not sum due to independent rounding.
Aluminum Production
Aluminum is a light-weight, malleable, and corrosion
resistant metal that is used in many manufactured products
including aircraft, automobiles, bicycles, and kitchen
utensils. In 2000, the United States was the largest producer
of primary aluminum, with 15 percent of the world total
(USGS 2001). The United States was also a major importer
of primary aluminum. The production of primary
aluminum—in addition to consuming large quantities of
electricity—results in process-related emissions of several
greenhouse gases including carbon dioxide (CO2) and two
perfluorocarbons (PFCs): perfluoromethane (CF4) and
perfluoroethane (C2F6).
Carbon dioxide is emitted during the aluminum
smelting process when alumina (aluminum oxide, A12O3) is
reduced to aluminum using the Hall-Heroult reduction
process. The reduction of the alumina occurs through
electrolysis in a molten bath of natural or synthetic cryolite
(Na3AlF6). The reduction cells contain a carbon lining that
serves as the cathode. Carbon is also contained in the anode,
which can be a carbon mass of paste, coke briquettes, or
prebaked carbon blocks from petroleum coke. During
reduction, some of this carbon is oxidized and released to
the atmosphere as CO2.
Process emissions of CO2 from aluminum production
were estimated at 5.4 Tg CO2 Eq. (5,410 Gg) in 2000 (see
Table 3-35). The carbon anodes consumed during aluminum
production consist of petroleum coke and, to a minor extent,
coal tar pitch. The petroleum coke portion of the total CO2
process emissions from aluminum production is considered
to be a non-energy use of petroleum coke, and is accounted
for in the Industrial Processes chapter and not with Fossil
Fuel Combustion emissions in the Energy chapter. Similarly,
the coal tar pitch portion of these CO2 process emissions is
subtracted from the Iron and Steel section-r-where it would
otherwise be counted—to avoid double-counting.
In addition to CO2 emissions, the aluminum production
industry is also the largest source of PFC emissions in the
United States. During the smelting process, when the
alumina ore content of the electrolytic bath falls below
critical levels required for electrolysis, rapid voltage
increases occur, termed "anode effects." These anode effects
cause carbon from the anode and fluorine from the
dissociated molten cryolite bath to combine, thereby
producing fugitive emissions of CF4 and C2F6. In general,
i
the magnitude of emissions for a given level of production
depends on the frequency and duration1 of these anode
effects. The more frequent and long-lasting the anode
effects, the greater the emissions.
Primary aluminum production-related emissions of
PFCs are estimated to have declined 56 percent since 1990.
Since 1990, emissions of CF4 and C2F6 have declined 55
and 64 percent, respectively, to 7.1 Tg CO2'Eq. of CF4 (1.10
Gg CF4) and 0.8 Tg CO2 Eq. of C2F6 (0.1 Gg C2F6) in 2000,
as shown in Table 3-36 and Table 3-37. This decline was
due to both reductions in domestic aluminum production
and actions taken by aluminum smelting companies to
reduce the frequency and duration of anode effects.
3-26 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-37: PFC Emissions from Aluminum
Production (Gg)
Year
-1990
:. 1995
1996
- 1997
•" 1998
'•• 1999
: 2000
CF4
2.4 _ ' _
1.6
1.7
1.5
1.2
1.2
1.1
C2FB
0.2
0.1
0.1
0.1
0.1
0.1
0.1
U.S. primary aluminum production for 2000—totaling
3,468 thousand metric tons—decreased slightly from 1999."
This decrease is attributed to the curtailment of production
at several U.S. smelters, due to high electric power costs in
various regions of the country. The transportation industry
remained the largest domestic consumer of aluminum,
accounting for about 37 percent (USGS 2001).
Methodology
Carbon dioxide is generated during alumina reduction
to aluminum metal following the reaction below:
2A1203 + 3C -> 4A1 + 3C02
The CO2 emission factor employed was estimated from
the production of primary aluminum metal and the carbon
consumed by the process. Emissions vary depending on the
specific technology used by each plant (e.g., Prebake or
Soderberg). The Revised 1996 IPCC Guidelines (IPCC/
UNEP/OECD/IEA 1997) provide CO2 emission factors for
each technology type. During alumina reduction in a prebake
anode cell process, approximately 1.5 metric tons of CO2
are emitted for each metric ton of aluminum produced
(IPCC/UNEP/OECD/IEA1997). Similarly, during alumina
reduction in a Soderberg cell process, approximately 1.8
metric tons of CO2 are emitted per metric ton of aluminum
produced (IPCC/UNEP/OECD/IEA 1997). Based on
information gathered by EPA's Voluntary Aluminum
Industrial Partnership (VAIP) program, it was assumed that
production was split 80 percent prebake and 20 percent
Soderberg for the whole time series.
PFC emissions from aluminum production were
estimated using a per unit production emission factor that
is expressed as a function of operating parameters (anode
effect frequency and duration), as follows:
PFC (CF4 or C2F6) kg/metric ton Al = S x Anode Effect
Minutes/Cell-Day
where,
S = Slope coefficient
Anode Effect Minutes/Cell-Day = Anode Effect
Frequency x Anode Effect Duration
The slope coefficient was established for each smelter
based on field measurements, where available, or default
coefficients by technology-type, based on field
measurements. Once established, the slope coefficient was
used along with smelter anode effect data, collected by
aluminum companies and reported to the VAIP, to estimate
emissions factors over time. Where smelter-specific anode
effect data were not available, industry averages were used.
Emissions factors were multiplied by annual production to
estimate annual emissions at the smelter level. Emissions
were then aggregated across smelters to estimate national
emissions. The methodology used to estimate emissions is
consistent with the methodologies recommended by the
Good Practice Guidance and Uncertainty Management in
National Greenhouse Gas Inventories (IPCC 2000).
Data Sources
Primary aluminum production data for 2000 (see
Table 3-38) were obtained by using information from
VAIP program submittals and from USGS, Mineral
Industry Surveys: Aluminum Annual Report (USGS
2001). The 2000 data from the USGS were adjusted based
on the VAIP submittals. Primary aluminum production
data for 1990 through 1999 (see Table 3-38) were
obtained from USGS, Mineral Industry Surveys:
Aluminum Annual Report (USGS 1995,1998, 2000). The
USGS requested data from the 12 domestic producers,
all of whom responded. The CO2 emission factors were
taken from the Revised 1996 IPCC Guidelines (IPCC/
UNEP/OECD/IEA 1997). Emission estimates of PFCs
17 Comparing a subset of smelter specific production data from EPA's Voluntary Aluminum Industrial Partnership (VAIP) program and the USGS
Mineral Industry Surveys: Aluminum Annual Report (USGS 2001), it was observed that the VAIP program data was approximately 200 thousand
metric tons less than the USGS production total. The data from VAIP were believed to provide a more accurate estimate of U.S. aluminum production
and therefore were used to calculate emissions.
Industrial Processes 3-27
-------
Table 3-38: Production of Primary Aluminum
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Thousand Metric Tons
4,048
4,121
4,042
3,695
3,299
3,375
3,577
3,603
3,713
3,779
3,468
were provided by aluminum smelters participating in the
VAIP program. Where smelter-specific slope coefficients
were not available, technology-specific coefficients were
drawn from the IPCC's Good Practice Guidance (IPCC
2000). Information on the average frequency and duration
of anode effects was taken from the International
Aluminum Institute's anode effect survey (IAI 2000).
Uncertainty
Carbon dioxide emissions vary depending on the
specific technology used by each plant. A more accurate
method would be to calculate CO2 emissions based upon
the amount of carbon—in the form of petroleum coke or tar
pitch—consumed by the process; however, this type of
information was not available.
For PFC emission estimates, the uncertainty in the
aluminum production data is relatively low (roughly ± 1 to
2 percent) compared to the uncertainty in the emissions
factors (roughly ± 10 to 50 percent). Uncertainty in the
emissions factors arises from the lack of comprehensive
data for both the slope coefficients and anode effect data.
Currently, insufficient measurement data exist to quantify
a relationship between PFC emissions and anode effect
minutes for all smelters. Future inventories will incorporate
additional data reported by aluminum smelters and ongoing
research into PFC emissions from aluminum production.
Occasionally, sulfur hexafluoride (SF6) is also used by
the aluminum industry as a cover gas or a fluxing and degassing
agent in experimental and specialized casting operations. In
its application as a cover gas, SF6 is mixed with nitrogen or
carbon dioxide and injected above the surface of molten
aluminum; as a fluxing and degassing agent, SF6 is mixed with
argon, nitrogen, and/or chlorine and blown through molten
aluminum. These practices are not employed extensively by
primary aluminum producers and are believed to be isolated
to secondary casting firms. The aluminum industry in the United
States and Canada was estimated to use 230 Mg of SF6 per
year (Maiss and Brenninkmeijer 1998); however, this estimate
is highly uncertain. -
Historically, SF6 from aluminum activities has been
omitted from estimates of global SF6 emissions, with the
caveat that any emissions would be insignificant (Ko et al.
1993, Victor and MacDonald 1998). Emissions are believed
to be insignificant, given that the concentration of SFS hi
the mixtures is small and a portion of the SF6 is decomposed
in the process (MacNeal et al. 1990, Gariepy and Dube 1992,
Ko et al. 1993, Ten Eyck and Lukens 1996, Zurecki 1996).
Emissions of SF6 from aluminum fluxing and degassing
have not been estimated. Uncertainties; exist as to the
quantity of SF6 used by the aluminum industry and its rate
of destruction in its uses as a degassing agent or cover gas.
18 As construed, interpreted, and applied in the terms and conditions of the Montreal Protocol on Substances that Deplete the Ozone Layer. [42 U.S.C.
§7671m(b),CAA§614] i
3-28 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-39: HFC-23 Emissions from HCFC-22
Production
Table 3-40: HCFC-22 Production
Year
Year
1990
fcp. .•:..'.- 1,u:-.Hl:":ii;.'.v-
; Hl95
1996
1997
;-1998
IT1999
: 2000
I
TgCOzEq.
35.0
-' 'L> ,--.^AW--~.^vi"kii.ir;», i^-t
27.0
31.1
30.0
40.2
30.4
29.8
Gg ;
3.0 ; r
;—• •
2.3 *>-
2.7 p
2.6 : ;:
3.4
2.6 . ',"•
2.6 •; £....
----- -- -J br" - - -
: yr-.-
fe
1990
1991
; 1992
1993
1994
1995
1996
1997
1998
1999
2000
-
138.9
142.7
H /Q C
14y.b
132.4
146.8
154.7
166.1
164.5
182.8
-ifi£ £
186.9
HCFC-22 Production
Trifluoromethane (HFC-23 or CHF3) is generated as a
by-product during the manufacture of chlorodifluoromethane
(HCFC-22), which is primarily employed in refrigeration and
air conditioning systems and as a chemical feedstock for
manufacturing synthetic polymers. Since 1990, production and
use of HCFC-22 has increased significantly as it has replaced
chlorofluorocarbons (CFCs) in many applications. Because
HCFC-22 depletes stratospheric ozone, its production for non-
feedstock uses is scheduled to be phased out by 2020 under
the U.S. Clean Air Act. 18 Feedstock production, however, is
permitted to continue indefinitely.
HCFC-22 is produced by the reaction of chloroform
(CHC13) and hydrogen fluoride (HF) in the presence of a
catalyst, SbCl5. The reaction of the catalyst and HF produces
SbCl F, (where x + y = 5), which reacts with chlorinated
x y
hydrocarbons to replace chlorine atoms with fluorine. The HF
and chloroform are introduced by submerged piping into a
continuous-flow reactor that contains the catalyst in a
hydrocarbon mixture of chloroform and partially fluorinated
intermediates. The vapors leaving the reactor contain HCFC-
21 (CHC12F), HCFC-22 (CHOF2), HFC-23 (CHF3), HC1,
chloroform, and HF. The under-fluorinated intermediates
(HCFC-21) and chloroform are then condensed and returned
to the reactor, along with residual catalyst, to undergo further
fluorination. The final vapors leaving the condenser are
primarily HCFC-22, HFC-23, HC1 and residual HF. The HC1
is recovered as a useful byproduct, and the HF is removed.
Once separated from HCFC-22, the HFC-23 is generally vented
to the atmosphere as an unwanted by-product, or may be
captured for use in a limited number of applications.
Emissions of HFC-23 in 2000 were estimated to be
29.8 Tg CO2 Eq. (2.6 Gg). This quantity represents a 15
percent decrease from emissions in 1990 (see Table 3-39).
Although HCFC-22 production has increased by 35 percent
since 1990, the intensity of HFC-23 emissions (i.e., the
amount of HFC-23 emitted per kilogram of HCFC-22
manufactured) has declined by 37 percent, lowering
emissions.
In the future, production of HCFC-22 in the United
States is expected to decline as non-feedstock HCFC
production is phased-out. Feedstock production is
anticipated to continue growing, mainly for manufacturing
fluorinated polymers.
Methodology
The methodology employed for estimating emissions
was based upon measurements of critical feed components
at individual HCFC-22 production plants. Individual
producers also measured HFC-23 concentrations in their
output stream by gas chromatography. Using measurements
of feed components and HFC-23 concentrations in output
streams, the amount of HFC-23 generated was estimated.
HFC-23 concentrations were determined at the point the
gas leaves the chemical reactor; therefore, estimates also
include fugitive emissions.
Data Sources
Emission estimates were provided by the EPA's Global
Programs Division in cooperation with the U.S.
manufacturers of HCFC-22. Annual estimates of U.S.
HCFC-22 production are presented in Table 3-40.
Industrial Processes 3-29
-------
Uncertainty
A high level of confidence has been attributed to the
HFC-23 concentration data employed because
measurements were conducted frequently and accounted for
day-to-day and process variability. It is believed that the
emissions reported are roughly within 10 percent of the true
value. This methodology accounted for the declining
intensity of HFC-23 emissions over time. The use of a
constant emission factor would not have allowed for such
accounting. More simplistic emission estimates generally
assume that HFC-23 emissions are between 2 and 4 percent
of HCFC-22 production on a mass ratio basis.
Semiconductor Manufacture
The semiconductor industry uses multiple long-lived
fluorinated gases in plasma etching and chemical vapor
deposition (CVD) processes. The gases most commonly
employed are trifluoromethane (HFC-23), perfluoromethane
(CF4), perfluoroethane (C2F6), nitrogen trifluoride (NF3),
and sulfur hexafluoride (SF6), although other compounds
such as perfluoropropane (C3F8) and perfluorocyclobutane
(c-C,F8) are also used. The exact combination of compounds
is specific to the process employed.
Plasma etching is performed to provide pathways for
conducting material to connect individual circuit
components in silicon wafers, using HFCs, PFCs, SFS and
other gases in plasma form. The etching process uses
plasma-generated fluorine atoms that react at the
semiconductor surface according to prescribed patterns to
selectively remove substrate material. A single
semiconductor wafer may require as many as 100 distinct
process steps that use these gases. Chemical vapor
deposition chambers, used for depositing materials that will
act as insulators and wires, are cleaned periodically using
PFCs and other gases. During the cleaning cycle the gas is
converted to fluorine atoms in plasma, which etches away
residual material from chamber walls, electrodes, and
chamber hardware. However, due to the low destruction
efficiency (i.e., high dissociation energy) of PFCs, a portion
of the gas flowing into the chamber flows unreacted through
the chamber and, unless emission abatement technologies
are used, this portion is emitted into the atmosphere. In
addition to emissions of unreacted gases, these compounds
can also be transformed in the plasma processes into a
different HFC or PFC compound, which is' then exhausted
into the atmosphere. For example, when either CHF3 or C2F6
is used in cleaning or etching, CF4 is generated and emitted
as a process by-product. ;
For 2000, in part, total weighted emissions of all
fluorinated greenhouse gases by the U.S. semiconductor
industry were estimated to be 7.6 Tg CO2 Eq. Combined
emissions of all fluorinated greenhouse gases are presented
in Table 3-41 and Table 3-42 below. The rapid growth of
this industry and the increasing complexity of semiconductor
products which use more PFCs in the production process
have led to an increase in emissions of over 160 percent
since 1990. However, the growth rate in: emissions has
slowed since 1997, and emissions declined between 1999
and 2000. This decline is due to the initial implementation
of PFC emission reduction methods, such as process
optimization.
Methodology
Emissions from semiconductor manufacturing were
estimated using two sets of data. For 1990! through 1994,
emission estimates were based on the historical consumption
of silicon (i.e., square centimeters), the estimated average
number of interconnecting layers in the chips produced, and
an estimated per-layer emission factor. (The number of
layers per chip, and hence the PFC emissions per square
centimeter of silicon, increases as the line-width of the chip
decreases.) The average number of layers per chip was based
on industry estimates of silicon consumption by line-width
and of the number of layers per line-width. The per-layer
emission factor was based on the total annual emissions
reported by participants in EPA's PFC Emission Reduction
Partnership for the Semiconductor Industry in 1995 and later
years. For the three years for which gas sales data were
available (1992 to 1994), the estimates derived using this
method are within 10 percent of the estimates derived using
gas sales data and average values for emission factors and
global warming potentials (GWPs).
For 1995 through 2000, total U.S. emissions were
extrapolated from the total annual emissions reported by
the participants in the PFC Emission Reduction Partnership
for the Semiconductor Industry. The emissions from the
participants were multiplied by the ratio of the total layer-
3-30 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-41: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Tg C02 Eq.)
Year
*'CF4
" C2F6
J csFs
HFC-23
= SF6
' NF3*
Total
Note: Totals
1990 1995
0.7
1.5 '
0.1
0.1
0.4
0.1
I^^SsjS
Ei 1.5
3.2
0.2
. 0.2
0.8
•SI 0.1
2.9 6.1
may not sum due to independent rounding.
1996
1.4
2.9
0.2
0.2
0.8
0.1
5.6
* NF3 emissions are presented for informational purposes, using a GWP of 8,000, and are not included
1997
1.7
3.5
0.2
0.2
1.0
0.2
6.7
in totals.
1998
1.8
3.9
0.2
0.2
1.0
0.2
7.4
1999
1.9
4.2
0.3
0.3
1.1
0.2
7.9
2000
1.9
4.0
0.2
0.2
1.1
0.2
7.6
Table 3-42: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Mg)
1995
1996 1997
1998 1999 2000
LCF
(..Ci,
r ^3
4 111
F6 167
F8 14
jr HFC-23 8 .
E":8F
B 17
I_NF3 • 9
L - - : -.--:.•- -•.-.- .:.:•: ••: - -;- -' -
BB 229 211 254 282
ill 345 318 383 424
IIS 28 26 31 35
fea 17 16 19 21
Bj 35 32 39 43
E3 19 17 21 23
300
452
37
22
46
24
286
431
35
21
44
23
weighted capacity of all of the semiconductor plants in the
United States and the total layer-weighted capacity of the
plants operated by the participants. The layer-weighted
capacity of a plant (or group of plants) consists of the silicon
capacity of that plant multiplied by the number of layers
used in the chips produced by that plant. This method
assumes that participants and non-participants have similar
capacity utilizations and per-layer emission factors.
From 1995 through 1999, the per-layer emission factor
calculated for participants remained fairly constant and was
assumed to be applicable to the non-participants. In 2000,
the per-layer emission factor of participants declined
significantly, presumably reflecting efforts to reduce PFC
emissions. However, non-participants were assumed to emit
PFCs at the historic per-layer rate during the year 2000.
The 2000 U.S. emissions estimate was adjusted accordingly.
Chemical-specific emission estimates were based data
submitted for the year by participants, which were the first
reports to provide emissions by chemical. It was assumed
that emissions from non-participants and emissions from
previous years were distributed among the chemicals in the
same proportions as in these 2000 participant reports. This
assumption is supported by chemical sales information from
previous years and chemical-specific emission factors.
Participants estimate their emissions using a range of
methods. For 2000, all participants used a method at least as
accurate as the IPCC's method 2c, recommended in Good
Practice Guidance and Uncertainty Management in National
Greenhouse Gas Inventories (TPCC 2000). The partners with
relatively high emissions typically use the more accurate TPCC
2b or 2a methods, multiplying estimates of their PFC
consumption by process-specific emission factors that they
have either measured or obtained from tool suppliers.
Data Sources
Aggregate emissions estimates from the semiconductor
manufacturers participating in the EPA's PFC Emission
Reduction Partnership were used to develop these estimates.
Estimates of the capacities and characteristics of plants
operated by participants and non-participants were derived
from the Semiconductor Equipment and Materials
International (SEMI) World Fab Watch (formerly
International Fobs on Disk) database (1996 to 2001).
Estimates of silicon consumed by line-width from 1990
through 1994 were derived from information from VLSI
Research (2000), and the number of layers per line-width
was obtained from International SEMATECH's
International Technology Roadmap: 2000 Update.
Industrial Processes 3-31
-------
Table 3-43: SFG Emissions from Electrical
Transmission and Distribution
Year
1990
rrrrr
1995
1996
1997
1998
1999
2000
Tg C02 Eq.
31.2
I I i . .
26.5
26.8
24.5
20.1
15.5
14.4
Gg
1.3
,,»L ' .!' I I .1 t'«,.\l
1.1
1.1
1.0
0.8
0.7
0.6
Uncertainty
Emission, estimates for this source category have
improved, but are still relatively uncertain. Emissions vary
depending upon the total amount of gas used and the tool
and process employed. Much of this information is tracked
by semiconductor manufacturers participating in the EPA's
PFC Emission Reduction Partnership; however, there is
some uncertainty associated with the data collected. In
addition, not all semiconductor manufacturers track this
information. Total U.S. emissions were extrapolated from
the information submitted by the participants, introducing
additional uncertainty.
Electrical Transmission
and Distribution
The largest use for sulfur hexafluoride (SF6), both
domestically and internationally, is as an electrical insulator
in equipment that transmits and distributes electricity
(RAND 2000). The gas has been employed by the electric
power industry in the United States since the 1950s because
of its dielectric strength and arc-quenching characteristics.
It is used in gas-insulated substations, circuit breakers, and
other switchgear. Sulfur hexafluoride has replaced
flammable insulating oils in many applications and allows
for more compact substations in dense urban areas.
Fugitive emissions of SF6 can escape from gas-insulated
substations and switch gear through seals, especially from
older equipment. The gas can also be released during
equipment installation, servicing, and disposal. In the past,
some electric utilities vented SF6 to the atmosphere during
servicing and disposal; however, increased awareness and
the relatively high cost of the gas have reduced this practice.
Emissions of SF6 from electrical transmission and
distribution systems were estimated to be 14.4 Tg CO2 Eq.
(0.6 Gg) in 2000. This quantity represents a 54 percent
decrease below the estimate for 1990 (see Table 3-43). This
decrease, which is reflected in the atmospheric record, is
believed to be a response to increases in the price of SF6
and to growing awareness of the environmental impact of
SF^ emissions. :
Methodology
The 2000 estimate of SF6 emissions from electrical
equipment, 14.4 Tg CO2Eq., is comprised of (1) estimated
emissions of approximately 14.3 Tg CO2 Eql from U.S. elec-
tric power systems, and (2) estimated emissions of approxi-
mately 0.2 Tg CO2 Eq. from U.S. electrical equipment manu-
facturers (original equipment manufacturers, or OEMs). The
2000 estimate of emissions from electric power systems is
based on the reported 2000 emissions (5.1 Tg CO2) of par-
ticipating utilities in EPA's SFg Emissions Reduction Part-
nership for Electric Power Systems, which began in 1999.
These emissions were scaled up to the national level using
the results of a regression analysis that indicated that utili-
ties' emissions are strongly correlated with their transmis-
sion miles. The 2000 emissions estimate for OEMs of 0.2
Tg CO2 is based on statistics compiled by the National Elec-
trical Manufacturers Association and a paper prepared un-
der the auspices of the International Council on Large Elec-
tric Systems (CIGRE) in May 2001 (P. O'Connell, et al.,
Study Committee 23), which indicates that OEMs have a
release rate of approximately 3 percent of the amount of
SF6 installed in new equipment. Emissions for 1999 were
estimated similarly.
Because most participating utilities reported emissions
only for 1999 and 2000, and only one reported emissions
for more than three years, it was necessary to model
"backcast" electric power system SF6 emissions for the years
1990 through 1998. It was assumed that SF6 purchases were
strongly related to emissions. To estimate 19^0 through 1998
emissions, aggregate world sales of SF6 (RAND 2000) for
each year from 1990 through 1999 were divided by Ihe world
sales from 1999. The result was a time series that gave each
year's sales as a multiple of 1999 sales. Each year's
normalized sales were then multiplied by the estimated U.S.
emissions of SF6 from electrical equipment in 1999, which
3-32 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
was estimated to be 15.5 Tg of CO2 Eq., to estimate U.S.
emissions of SF6 from electrical equipment in that year. This
yielded a time series that was related to statistics for both
Table 3-44: SF6 Emissions from Magnesium
Production and Processing
SF6 emissions and SF6 sales.
Data Sources
Emission estimates were provided by EPA's Global
Programs Division in cooperation with companies that
participate in the SF6 Emissions Reduction Partnership for
Electric Power Systems and with producers of SF6.
Uncertainty
There is uncertainty involved in extrapolating emissions
reported by participants to total U.S. emissions, and in
extrapolating to estimate past emissions. The regression
equations used to extrapolate U.S. emissions from
participant reports have a variance (at the 95 percent
confidence level) of +/- 2 Tg CO2 for 1999 and +/- 2.5 Tg
CO2 for 2000. In addition, emission rates for utilities that
were not participants, which accounted for approximately
75 percent of U.S. transmission miles, may differ from those
that were participants. Global sales of SF6 appear to closely
reflect global emissions; global sales declined by 24 percent
between 1995 and 1998, while atmospheric measurements
indicate that world emissions of SF6 declined by 27 percent
during the same period. However, U.S. emission patterns
may differ from global emission patterns.
Magnesium Production
and Processing
The magnesium metal production and casting industry
uses sulfur hexafluoride (SF6) as a covergas to prevent the
violent oxidation of molten magnesium in the presence of
air. A dilute gaseous mixture of SF6 with dry air and/or
carbon dioxide is blown over molten magnesium metal to
induce and stabilize the formation of a protective crust. A
minute portion of the SF6 reacts with the magnesium to form
a thin molecular film of mostly magnesium oxide and
magnesium fluoride. It is assumed that the amount of SF6
reacting in magnesium production and processing is
negligible and thus all SF used is emitted into the
tYear
__-_
M996
? 1997
E1998
urn .
-2000
F"" ''•'.." "
Tg C02 Eq.
5.5
5T5' "
5.5
6.9
6.2
6.1
4.0
-,.
Gg
0.2
0.2
0.2
0.3
0.3
0.3
0.2
atmosphere. Sulfur hexafluoride has been used in this
application around the world for the last twenty years. It
has largely replaced salt fluxes and sulfur dioxide (SO2),
which are more toxic and corrosive than SF6.
The magnesium industry emitted 4.0 Tg CO2 Eq. (0.17
Gg) of SF6 in 2000 (see Table 3-44). There are no significant
plans for expansion of primary magnesium production in
the United States, but demand for magnesium metal by U.S.
casting companies has grown as auto manufacturers design
more lightweight magnesium parts into vehicle models.
Foreign magnesium producers are expected to meet the
growing U.S. demand for primary magnesium.
Methodology
U.S. magnesium metal production (primary and
secondary) and consumption data from 1993 to 1999 were
available from the U.S. Geological Survey (USGS).19
Emissions were estimated by multiplying average industry
emission factors (kg SF6/tonne Mg produced or processed)
by the amount of metal produced or consumed in the six
major processes that require SF6 melt protection; 1) primary
production, 2) secondary production, 3) die casting, 4)
gravity casting, 5) wrought products and, 6) anodes. The
emission factors were derived from participants in EPA's
SF6 Emission Reduction Partnership for the Magnesium
Industry, technical publications (Gjestland and Magers
1996), and expert judgement. Participants represent 100
percent of U.S. primary production and approximately 60
percent of magnesium casting in the United States.
19 http://minerals.usgs.gov/minerals/pubs/commodity/magnesium/index.html#mis
Industrial Processes 3-33
-------
Box 3-1: Potential Emission Estimates of MFCs, PFCs, and SF6
Emissions of HFCs, PFCs and SF6 from industrial processes can be estimated in two ways, either as potential emissions or as
actual emissions. Emission estimates in this chapter are "actual emissions," which are defined by the Revised 1996IPCC Guidelines for
National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA1997) as estimates that take into account the time lag between consump-
tion and emissions. In contrast, "potential emissions" are defined to be equal to the amount of a chemical consumed in a country, minus
the amount of a chemical recovered for destruction or export in the year of consideration. Potential emissions will generally be greater
for a given year than actual emissions, since some amount of chemical consumed will be stored in products or equipment and will not
be emitted to the atmosphere until a later date, if ever. Because all chemicals consumed will eventually be emitted into the atmosphere,
In the long term the cumulative emission estimates using the two approaches should be equivalent unless the chemical is captured and
destroyed. Although actual emissions are considered to be the more accurate estimation approach for a single year, estimates of
potential emissions are provided for informational purposes.
Separate estimates of potential emissions were not made for industrial processes that fall into the following categories:
• By-product emissions. Some emissions do not result from the consumption or use of a chemical, but are the unintended by-
products of another process. For such emissions, which include emissions of CF4 and C2F6 from aluminum production and of
HFC-23 from HCFC-22 production, the distinction between potential and actual emissions is not relevant.
• Potential emissions that equal actual emissions. For some sources, such as magnesium production and processing, it is
assumed that there is no delay between consumption and emission and that no destruction of the chemical takes place. In this
case, actual emissions equal potential emissions.
• Emissions that are not easily defined. In some processes, such as PFC emissions from semiconductor manufacture, the gases
used in the process may be destroyed or transformed into other compounds, which may also be greenhouse gases. It is
therefore not logical to estimate potential emissions based on consumption of the original chemical.
Table 3-45 presents potential emission estimates for HFCs and PFCs from the substitution of ozone depleting substances and SF6
emissions from semiconductor manufacturer, magnesium production and processing, and electrical transmission and distribution.20
Potential emissions associated with the substitution for ozone depleting substances were calculated through a combination of the EPA's
Vintaging Model and information provided by U.S. chemical manufacturers. For SF6 from semiconductor manufacture, estimates were
assumed to equal emissions divided by a 0.53 percent emission factor. The U.S. utility purchases of SF6 for electrical equipment were
backcasted based on world sales of SF6 to utilities, this was added to the SF6 Purchased by U.S. orignal equipment manufacturers
(OEMs).
Table 3-45: 2000 Potential and Actual Emissions of HFCs, PFCs, and SF6 from Selected Sources (Tg C02 Eq.)
Source
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production
Semiconductor Manufacture*
Magnesium Production and Processing
Electrical Transmission and Distribution
Potential
203.4
_
-
2.0
4.0
23.2
Actual
57.8
7.9
29.8
7.4
4.0
14.4
- Not applicable.
*Potential emissions only include SF6, while actual emissions include SF6 and PFCs.
20 Sec Annex V for a diiscussion of sources of SF6 emissions excluded from the actual emissions estimates in this report.
3-34 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-46: NOX, CO, and NMVOC Emissions from Industrial Processes (Gg)
Gas/Source
-NOX
' Chemical & Allied Product Manufacturing
- Metals Processing
Storage and Transport
Other Industrial Processes
Miscellaneous*
' CO
- Chemical & Allied Product Manufacturing
^ Metals Processing
- Storage and Transport
Other Industrial Processes
" Miscellaneous*
1 NMVOCs
t Chemical & Allied Product Manufacturing
s Metals Processing
f Storage and Transport
t Other Industrial Processes
- Miscellaneous*
1990
921
152
88
3
343
335
9,502
1,074
2,395
69
487
5,479
3,110
575
111
1,356
364
705
fgSSS'~~
KEW-'J
if^
i£~!
|ipE£-'?f
-- gfe^V^C
KST'-S
m^~--^f
£•»••-!!
y^-' -i:
tttwi,,±
PksnS!
_3
ips?^-^
ppafi^.u..!^
pS":?
1995
842
144
89
5
362
242
5,291
1,109
2,159
22
566
1,435
3,622
599
113
1,499
409
185
1996
976
' 113
75
14
397
376
7,171
955
1,455
64
509
4,188
3,110
351
66
1,169
383
375
1997
991
115
80
15
417
364
8,776
972
1,550
64
528
5,662
3,578
352
71
1,204
397
759
1998
924
117
80
15
424
288
5,557
981
1,544
65
535
2,431
3,145
357
71
1,204
402
308
1999
946
119
80
15
422
311
10,763
981
1,518
65
543
7,656
3,883
359
69
1,129
420
1,065
2000
1184
122
83
15
442
523
19,469
1,009
1,574
67
562
16,257
4,232
369
72
1,111
435
2,244
' Miscellaneous includes the following categories: catastrophic/accidental release, other combustion, health services, TSDFs (Transport, Storage, and
Disposal Facilities under the Resource Conservation and Recovery Act), cooling towers, and fugitive dust. It does not include agricultural fires or slash/
prescribed burning, which are accounted for under the Agricultural Residue Burning source.
Note: Totals may not sum due to independent rounding.
Data Sources
Emission estimates were provided by EPA's Climate
Protection Division in cooperation with the U.S. EPA SF6
Emission Reduction Partnership for the Magnesium
Industry and the USGS.
Uncertainty
There are a number of uncertainties in these estimates,
including the assumption that SF6 neither reacts nor
decomposes during use. It is possible that the melt surface
reactions and high temperatures associated with molten
magnesium would cause some gas degradation. As is the case
for other sources of SF6 emissions, total SF6 consumption data
for magnesium production and processing in United States were
not available. Sulfur hexafluoride may also be used as a
covergas for the casting of molten aluminum with a high
magnesium content; however, it is unknown to what extent
this technique is used in the United States.
Industrial Sources of
Ambient Air Pollutants
In addition to the main greenhouse gases addressed
above, many industrial processes generate emissions of
ambient air pollutants. Total emissions of nitrogen oxides
(NOx), carbon monoxide (CO), and nonmethane volatile
organic compounds (NMVOCs) from non-energy industrial
processes from 1990 to 2000 are reported in Table 3-46.
Methodology and Data Sources
The emission estimates for this source were taken
directly from the EPA (2001). Emissions were calculated
either for individual categories or for many categories
combined, using basic activity data (e.g., the amount of raw
material processed) as an indicator of emissions. National
activity data were collected for individual categories from
various agencies. Depending on the category, these basic
activity data may include data on production, fuel deliveries,
raw material processed, etc.
Industrial Processes 3-35
-------
Activity data were used in conjunction with emission
factors, which together relate the quantity of emissions to
the activity. Emission factors are generally available from
the EPA's Compilation of Air Pollutant Emission Factors,
AP-42 (EPA 1997). The EPA currently derives the overall
emission control efficiency of a source category from a
variety of information sources, including published reports,
the 1985 National Acid Precipitation and Assessment
Program emissions inventory, and other EPA databases.
Uncertainty
Uncertainties in these estimates are partly due to the
accuracy of the emission factors used and accurate estimates
of activity data.
3-36 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
4. Solvent Use
The use of solvents and other chemical products can result in emissions of various ozone precursors (i.e., ambient
air pollutants).1 Nonmethane volatile organic compounds (NMVOCs), commonly referred to as "hydrocarbons,"
are the primary gases emitted from most processes employing organic or petroleum based solvents. Surface coatings
accounted for just under a majority of NMVOC emissions from solvent use—43 percent in 2000—while "non-industrial"2
uses accounted for about 36 percent and degreasing applications for 8 percent. Overall, solvent use accounted for
approximately 24 percent of total U.S. emissions of NMVOCs in 2000, and decreased 16 percent since 1990.
Although NMVOCs are not considered direct greenhouse gases, their role as precursors to the formation of ozone—
which is a greenhouse gas—results in their inclusion in a greenhouse gas inventory. Emissions from solvent use have
been reported separately by the United States to be consistent with the inventory reporting guidelines recommended by the
IPCC. These guidelines identify solvent use as one of the major source categories for which countries should report
emissions. In the United States, emissions from solvents are primarily the result of solvent evaporation, whereby the
lighter hydrocarbon molecules in the solvents escape into the atmosphere. The evaporation process varies depending on
different solvent uses and solvent types. The major categories of solvent uses include: degreasing, graphic arts, surface
coating, other industrial uses of solvents (i.e., electronics, etc.), dry cleaning, and non-industrial uses (i.e., uses of paint
thinner, etc.). Because some of these industrial applications also employ thermal incineration as a control technology,
combustion by-products (CO and NOx) are also reported with this source category.
Total emissions of nitrogen oxides (NOx), nonmethane volatile organic compounds (NMVOCs), and carbon monoxide
(CO) from 1990 to 2000 are reported in Table 4-1.
Methodology
Emissions were calculated by aggregating solvent use data based on information relating to solvent uses from different
applications such as degreasing, graphic arts, etc. Emission factors for each consumption category were then applied to
the data to estimate emissions. For example, emissions from surface coatings were mostly due to solvent evaporation as
the coatings solidify. By applying the appropriate solvent emission factors to the type of solvents used for surface coatings,
an estimate of emissions was obtained. Emissions of CO and NOx result primarily from thermal and catalytic incineration
of solvent laden gas streams from painting booths, printing operations, and oven exhaust.
1 Solvent usage in the United States also results in the emission of small amounts of hydrofluorocarbons (HFCs) and hydrofluoroethers (HFEs), which
are included under Substitution of Ozone Depleting Substances in the Industrial Processes chapter.
2 "Non-industrial" uses include cutback asphalt, pesticide application adhesives, consumer solvents, and other miscellaneous applications.
Solvent Use 4-1
-------
Table 4-1: Emissions of NOX, CO, and NMVOC from Solvent Use (Gg)
Activity
NOX
Degreasing
Graphic Arts
Dry Cleaning
Surface Coating
Other Industrial Processes3
Non-Industrial Processes5
CO
Degreasing
Graphic Arts
Dry Cleaning
Surface Coating
Other Industrial Processes3
Non-Industrial Processes5
NMVOGs
Degreasing
Graphic Arts
Dry Cleaning
Surface Coating
Other industrial Processes3
Non-Industrial Processes5
1990
1
+
+
+
1
+
+
4
+
+
+
+
4
+
5,225
675
249
195
2,289
94
1,724
?"'•
rni,
e ,
fc-,W
|S!:J!f
SBiiHiL - H
*""' '
m
J
E-
.. —
F^
ffi
p,
t
f
^
e. _
^
i.
c
f
*
.. S
:,-*
*j
i -3t
; 'i
^
»
_
1I™5
a,
f
I
is
t
4
f
1995
3
+
1
+
2
+
+
5
+
+
1
1
3
+
5,618
716
307
209
2,432
96
1,858
1996
3
+
1
+
2
+
-t-
1
+
+
+
1
+
+
4,973
546
260
140
2,153
106
1,768
1997
3
+
1
+
2
+
+
1
+
+
+
1
+
+
5,108
566
266
148
2,228
110
1,790
1998
3
+
1
+
2
+
+
1
+
+
+
1
+
+
4,679
337
272
151
1,989
111
1,818
1999
3
+
1
+
2
+
+
1
+
+
+
1
+
+
4,390
337
268
152
1,940
113
1,581
2000
3
+
1
_l_
2
+
+
1
+
+
+
1
+
+
4,388
347
276
153
1,893
118
1,601
" Includes rubber and plastics manufacturing, and other miscellaneous applications.
b Includes cutback asphalt, pesticide application adhesives, consumer solvents, and other miscellaneous applications.
Note: Totals may not sum due to independent rounding.
+ Does not exceed 0.5 Gg.
Data Sources
The emission estimates for this source were taken
directly from the EPA (2001). Emissions were calculated
either for individual categories or for many categories
combined, using basic activity data (e.g., the amount of
solvent purchased) as an indicator of emissions. National
activity data were collected for individual applications from
various agencies.
Activity data were used in conjunction with emission
factors, which together relate the quantity of emissions to
the activity. Emission factors are generally available from
the EPA's Compilation of Air Pollutant Emission Factors,
AP-42 (EPA 1997). The EPA currently derives the overall
emission control efficiency of a source ^category from a
variety of information sources, including published reports,
the 1985 National Acid Precipitation and Assessment
Program emissions inventory, and other EPA data bases.
Uncertainties in these estimates are partly due to the
accuracy of the emission factors used and the reliability of
correlations between activity data and actual emissions.
4-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
5. Agriculture
Agricultural activities contribute directly to emissions of greenhouse gases through a variety of processes. This
chapter provides an assessment of non-carbon dioxide emissions from the following source categories: enteric
fermentation in domestic livestock, livestock manure management, rice cultivation, agricultural soil management, and
agricultural residue burning (see Figure 5-1). Carbon dioxide (CO2) emissions and removals from agriculture-related
land-use activities, such as conversion of grassland to cultivated land, are discussed in the Land-Use Change and Forestry
chapter.
Figure 5-1
Agricultural Soil
Management
Enteric
Fermentation
Manure
Management
Rice Cultivation
Agricultural
Residue Burning
In 2000, agricultural activities were responsible for
emissions of 485.1 Tg CO2 Eq., or 6.9 percent of total
U.S. greenhouse gas emissions. Methane (CH4) and
nitrous oxide (N2O) were the primary greenhouse gases
emitted by agricultural activities. Methane emissions from
enteric fermentation and manure management represent
about 20 percent and 6 percent of total CH4 emissions
from anthropogenic activities, respectively. Of all
domestic animal types, beef and dairy cattle were by far
the largest emitters of methane. Rice cultivation and
agricultural crop residue burning were minor sources of
methane. Agricultural soil management activities such as
fertilizer application and other cropping practices were
the largest source of U.S. N2O emissions, accounting for
70 percent. Manure management and agricultural residue
burning were also small sources of N2O emissions.
Table 5-1 and Table 5-2 present emission estimates
for the Agriculture chapter. Between 1990 and 2000, CH4 emissions from agricultural activities increased by 2.9 percent
while N2O emissions increased by 11.3 percent. In addition to CH4 and N2O, agricultural residue burning was also a minor
source of the ambient air pollutants carbon monoxide (CO) and nitrogen oxides (NOx).
1.2
Agriculture as a
Portion of all
Emissions
/ 6.9°/cf \
50 100
150 200
Tg C02 Eq.
250 300
Agriculture 5-1
-------
Table 5-1: Emissions from Agriculture (Tg C02 Eq.)
Gas/Source
1990
1995 1996 1997 1998 1999 2000
CH4 164.9
Enteric Fermentation 127.9
Manure Management 29.2
Rice Cultivation 7.1
Agricultural Residue Burning 0.7
N20 283.5
Agricultural Soil Management 267.1
Manure Management 16.0
Agricultural Residue Burning 0.4
f- i
176.2
133.2
34.8
7.6
0.7
300.2
283.4
16.4
0.4
171.5
129.6
34.2
7.0
0.7
309.8
292.6
16.8
0.4
170.9
126.8
35.8
7.5
0.8
315.0
297.5
17.1
0.4
171.6
124.9
38.0
7.9
0.8
316.0
298.4
17.1
0.5
171.1
124.5
37.6
8.3
0.8
313.9
296.3
17.1
0.4
169.6
123.9
37.5
7.5
0.8
315.5
297.6
17.5
0.5
Total
448.4
476.4 481.3 485.9 487.6 485.0 485.1
Note: Totals may not sum due to independent rounding.
Table 5-2: Emissions from Agriculture (Gg)
Gas/Source
CR,
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Residue Burning
N20
Agricultural Soil Management
Manure Management
Agricultural Residue Burning
1990
7,851
6,089
1,390
339
33
914
862
52
1
L
s,
1
i»/
r..
«
f? '
i/-
ft
Note: Totals may not sum due to independent rounding.
_,j
— !
- -f
,1
1995
8,392
6,342
1,657
363
31
968
914
53
1
1996
8,166
6,171
1,628
332
36
999
944
54
1
1997
8,136
6,037
1,707
356
36
1,016
960
55
1
1998
8,172
5,948
1,811
376
37
1,019
963
55
1
1999
8,149
5,929
1,788
395
36
1,012
956
55
1
2000
8,076
5,898
1,784
357
37
1,018
960
57
1
Enteric Fermentation
Methane (CH4) is produced as part of normal
digestive processes in animals. During digestion,
microbes resident in an animal's digestive system ferment
food consumed by the animal. This microbial
fermentation process, referred to as enteric fermentation,
produces methane as a by-product, which can be exhaled
or eructated by the animal. The amount of methane
produced and excreted by an individual animal depends
primarily upon the animal's digestive system, and the
amount and type of feed it consumes.
Among domesticated animal types, ruminant animals
(e.g., cattle, buffalo, sheep, goats, and camels) are the major
emitters of methane because of their unique digestive
system. Ruminants possess a rumen, or large "fore-
stomach," in which microbial fermentation breaks down the
feed they consume into products that can be metabolized.
The microbial fermentation that occurs in the rumen enables
them to digest coarse plant material that non-ruminant
animals cannot. Ruminant animals, consequently, have the
highest methane emissions among all animal types.
Non-ruminant domesticated animals (e.g., swine,
horses, mules, and goats) also produce methane emissions
through enteric fermentation, although this microbial
fermentation occurs in the large intestijne. These non-
ruminants emit significantly less methaneion a per-animal
basis than ruminants because the capacity of the large
intestine to produce methane is lower.
In addition to the type of digestive system, an animal's
feed intake also affects methane emissions. In general, a
higher feed intake leads to higher methane emissions. Feed
intake is positively related to animal size, growth rate, and
production (e.g., milk production, wool growth, pregnancy,
or work). Therefore, feed intake varies among animal types
as well as among different management practices for
individual animal types.
5-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 5-3: CH4 Emissions from Enteric Fermentation (Tg C02 Eq.)
Livestock Type
f Beef Cattle
ft Dairy Cattle
I Horses
r Sheep
i Swine
'~- Goats
!" Total
1990 1
93.3 I
28.7 J
1.9 1
1-9 I
1.7 |
0-3 I
Sat* 1gg5
IBS 100.1
SSf 27.5
3 2.0
Suv..^ 1 ,0
Bl 1-9
El • 0.2
127.9 F^ 133.2
f Note: Totals may not sum due to independent rounding.
Table 5-4: CH4
'" Livestock Type
' Beef Cattle
'* Dairy Cattle
f Horses
• Sheep
.", Swine
F Goats
[ Total
Emissions from Enteric Fermentation
1990 I
i
4,444 1
1,369 1
93
91
81
13
6,089
(Gg)
f*8? 1995
fil . 4>768
H 1,308
§>^ 94
72
00
s--._. ,^ OO
, ' '
k^ 6,342
1996
98.1
26.1
2.0
1.4
1.8
0.2
129.6
1996
4,673
1,241
94
68
84
10
6,171
1997
95.4
26.0
2.0
1.3
1.8
0.2
126.8
1997
4,541
1,240
94
64
88
10
6,037
1998
93.5
25.9
2.0
1.3
2.0
0.2
124.9
1998
4,453
1,234
95
63
93
10
5,948
1999
93.0
26.2
2.0
1.2
1.9
0.2
124.5
1999
4,429
1,246
96
58
90
10
5,929
2000
91.7
26.9
2.0
1.2
1.9
0.2 :
123.9
2000
4,365
1,283 :
96
56
88
10
5,898
1 Note: Totals may not sum due to independent rounding.
Methane emission estimates from enteric
fermentation are provided in Table 5-3 and Table 5-4.
Total livestock m'ethane emissions in 2000 were 123.9
Tg CO2 Eq. (5,898 Gg), decreasing slightly since 1999.
Beef cattle remain the largest contributor of methane
emissions from enteric fermentation, accounting for 74
percent in 2000. Emissions from dairy cattle in 2000
accounted for 22 percent, and the remaining 4 percent
was from horses, sheep, swine, and goats.
Methodology
Livestock emission estimates fall into two categories:
cattle and other domesticated animals. Cattle, due to their
large population, large size, and particular digestive
characteristics, account for the majority of methane
emissions from livestock in the United States. Cattle
production systems in the United States are better
characterized in comparison with other livestock
management systems. Amore detailed methodology (i.e.,
IPCC Tier 2) was therefore applied to estimating
emissions for cattle. Emission estimates for other
domesticated animals were handled using a less detailed
approach (i.e., IPCC Tier 1).
While the large diversity of animal management
practices cannot be precisely characterized and evaluated,
significant scientific literature exists that describes the
quantity of methane produced by individual ruminant
animals, particularly cattle. A detailed model that
incorporates this information and other analyses of livestock
population, feeding practices and production characteristics
was used to estimate emissions from cattle populations.
National cattle population statistics were disaggregated
into the following cattle sub-populations:
Dairy Cattle
• Calves
• Heifer Replacements
• Cows
Beef Cattle
• Calves
• Heifer Replacements
• Heifer and Steer Stackers
• Animals in Feedlots
• Cows
• Bulls
Agriculture 5-3
-------
Calf birth estimates, end of year population statistics,
detailed feedlot placement information, and slaughter weight
data were used in the model to initiate and track cohorts of
individual animal types having distinct emissions profiles.
The key variables tracked for each of the cattle population
categories are described in Annex K. These variables include
performance factors such as pregnancy and lactation as well
as average weights and weight gain.
Diet characteristics were estimated by State and region
for U.S. dairy, beef, and feedlot cattle. These estimates were
used to calculate Digestible Energy (DE) values and methane
conversion rates (Ym) for each population category. The
IPCC recommends Ym values of 3.5 to 4.5 percent for feedlot
cattle and 5.5 to 6.5 percent for all other cattle. Given the
availability of detailed diet information for different regions
and animal types in the United States, DE and Ym values
unique to the United States were developed, rather than
using the recommended IPCC values. The diet
characterizations and estimation of DE and Ym values were
based on contact with state agricultural extension specialists,
areview of published forage quality studies, expert opinion,
and modeling of animal physiology. See Annex K for more
details on the method used to characterize cattle diets in the
United States,
In order to estimate methane emissions from cattle, the
population was divided into region, age, sub-type (e.g.,
calves, heifer replacements, cows, etc.), and production (i.e.,
pregnant, lactating, etc.) groupings to more fully capture
any differences in methane emissions from these animal
types. Cattle diet characteristics developed under Step 2
were used to develop regional emission factors for each
sub-category. Tier 2 equations from IPCC (2000) were used
to produce methane emission factors for the following cattle
types: dairy cows, beef cows, dairy replacements, beef
replacements, steer stackers, heifer stackers, steer feedlot
animals, heifer feedlot animals, and steer and heifer feedlot
step-up diet animals. To estimate emissions from cattle,
population data were multiplied by the emission factor for
each cattle type. More details can be found in Annex K.
Emission estimates for other animal types were based
upon average emission factors representative of entire
populations of each animal type. Methane emissions from
these animals accounted for a minor portion of total methane
emissions from livestock in the United States from 1990
through 2000. Also, the variability hi emission factors for
each of these other animal types (e.g. variability by age,
production system, and feeding practice within each animal
type) is less than that for cattle.
See Annex K for more detailed information on the
methodology and data used to calculate methane emissions
from enteric fermentation.
Data Sources
Annual cattle population data were obtained from the
U.S. Department of Agriculture's National Agricultural
Statistics Service (1995a-d, 1996b,; 1997, 1998a,
1999a-c,f-g, 2000a,c,d,f, 2001a,c,d,g). DE and Ym values
were used to calculate emissions from cajttle populations.
DE and Ym for dairy and beef cows, and for beef stackers,
were calculated from diet'characteristics using a model
simulating ruminant digestion in growing and/or lactating
cattle (Donovan and Baldwin 1999). For feedlot animals,
DE and Ym values recommended by Johnson (1999) were
used. Values from EPA (1993) were used for dairy
replacement heifers. Weight data were .estimated from
Feedstuffs (1998), Western Dairyman (1998), and expert
opinion. Annual livestock population data for other livestock
types, except horses, as well as feedlot placement
information were obtained from the U.S. Department of
Agriculture's National Agricultural Statistics Service
(USDA 1994a-b, 1998b-c, 1999d,e,h, 2000b,e, 2001b,e,f).
Horse data were obtained from the Food;and Agriculture
Organization (FAO) statistical database (FAO 2000,2001).
Methane emissions from sheep, goats, swine, and horses
were estimated by using emission factors utilized in Crutzen
et al. (1986). These emission factors are representative of
typical animal sizes, feed intakes, and feed characteristics
in developed countries. The methodology is the same as
that recommended by IPCC (IPCC/UNEP/OECD/IEA
1997, IPCC 2000). '.
Uncertainty
The basic uncertainties associated with estimating
emissions from enteric fermentation are the range of
emission factors possible for the different animal types and
the number of animals with a particular emissions profile
that exist during the year. Although determihing an emission
factor for all possible cattle sub-groupings and diet
characterizations in the United States is riot possible, the
5-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
enteric fermentation model that was used estimates the likely
emission factors for the major animal types and diets. The
model generates estimates for dairy and beef cows, dairy
and beef replacements, beef stackers, and feedlot animals.
The analysis departs from the recommended IPCC (2000)
DE and Ym values to account for diets for these different
animal types regionally. Based on expert opinion and peer
reviewer recommendations, it is believed that the values
supporting the development of emission factors for the
animal types studied are appropriate for the situation in the
United States.
In addition to the uncertainty associated with
developing emission factors for different cattle population
categories based on estimated energy requirements and diet
characterizations, there is uncertainty in the estimation of
animal populations by animal type. The model estimates
the movement of animal cohorts through the various monthly
age and weight classes by animal type. Several inputs affect
the precision of this approach, including estimates of births
by month, weight gain of animals by age class, and
placement of animals into feedlots based on placement
statistics and slaughter weight data. However, it is believed
that the model sufficiently characterizes the U.S. cattle
population and captures the potential differences related to
the emission factors used for different animal types.
In order to ensure the quality of the emission
estimates from enteric fermentation, the IPCC Tier 1 and
Tier 2 QA/QC procedures were implemented. Tier 1
procedures included quality checks on data gathering,
input, and documentation, as well as checks on the actual
emission calculations. Additionally, Tier 2 procedures
included quality checks on emission factors, activity data,
and emissions.
Manure Management
The management of livestock manure can produce
anthropogenic methane (CH4) and nitrous oxide (N2O)
emissions. Methane is produced by the anaerobic
decomposition of manure. Nitrous oxide is produced as part
of the nitrogen cycle through the nitrification and
denitrification of the organic nitrogen in livestock manure
and urine.
When livestock or poultry manure are stored or treated
in systems that promote anaerobic conditions (e.g., as a
liquid in lagoons, ponds, tanks, or pits), the decomposition
of materials in the manure tends to produce CH4. When
manure is handled as a solid (e.g., in stacks or pits) or
deposited on pasture, range, or paddock lands, it tends to
decompose aerobically and produce little or no CH4. A
number of other factors related to how the manure is handled
also affect the amount of CH4 produced: 1) ambient
temperature and moisture affect the amount of CH4 produced
because they influence the growth of the bacteria responsible
for methane formation; 2) methane production generally
increases with rising temperature and residency time; and
3) for non-liquid based manure systems, moist conditions
(which are a function of rainfall and humidity) favor CH4
production. Although the majority of manure is handled as
a solid, producing little CH4, the general trend in manure
management, particularly for large dairy and swine
producers, is one of increasing use of liquid systems. In
addition, use of daily spread systems at smaller dairies is
decreasing, due to new regulations limiting the application
of manure nutrients, which has resulted in an increase of
manure managed and stored on site at these smaller dairies.
The composition of the manure also affects the
amount of methane produced. Manure composition varies
by animal type, including the animal's digestive system
and diet. In general, the greater the energy content of the
feed, the greater the potential for CH4 emissions. For
example, feedlot cattle fed a high energy grain diet
generate manure with a high CH4-producing capacity
(represented by Bo). Range cattle fed a low energy diet
of forage material produce manure with about 50 percent
of the CH4-producing potential of feedlot cattle manure.
In addition, there is a trend in the dairy industry indicating
that dairy cows are producing more milk per year. These
high-production milk cows tend to produce more volatile
solids in their manure as milk production increases, which
increases the probability of CH4 production.
A very small portion of the total nitrogen excreted is
expected to convert to nitrous oxide in the waste
management system. The production of nitrous oxide from
livestock manure depends on the composition of the manure
and urine, the type of bacteria involved in the process, and
the amount of oxygen and liquid in the manure system. For
Agriculture 5-5
-------
N2O emissions to occur, the manure must first be handled
aerobically where ammonia or organic nitrogen is converted
to nitrates and nitrites (nitrification), and then handled
anaerobically where the nitrates and nitrites are reduced to
nitrogen gas (N2), with intermediate production of nitrous
oxide (N2O) and nitric oxide (NO) (denitrification)
(Groffman, et al. 2000).
These emissions are most likely to occur in dry manure
handling systems that have aerobic conditions, but that also
contain pockets of anaerobic conditions due to saturation.
For example, manure at cattle drylots is deposited on soil,
oxidized to nitrite and nitrate, and has the potential to
encounter saturated conditions following rain events.
Certain H,O emissions are accounted for and discussed
under Agricultural Soil Management. These are emissions
from livestock manure and urine deposited on pasture, range,
or paddock lands, as well as emissions from manure and
urine that is spread onto fields either directly as "daily
spread" or after it is removed from manure management
systems (e.g., lagoon, pit, etc.).
Table 5-5 and Table 5-6 provide estimates of CH4 and
N2O emissions from manure management by animal
category. Estimates for methane emissions in 2000 were
37.5 Tg CO2 Eq. (1,783 Gg), 28 percent higher than in 1990.
The majority of this increase was from s wine and dairy cow
manure and is attributed to shifts by the swine and dairy
industries towards larger facilities. Larger swine and dairy
farms tend to use flush or scrape liquid systems to manage
and store manure. Thus the shift towards larger facilities is
translated into an increasing use of liquid manure
management systems. This shift was accounted for by
incorporating state-specific weighted methane conversion
factor (MCF) values calculated from the 1992 and 1997
farm-size distribution reported in the Census of Agriculture
(USDA 1999e). In 2000, swine CH4 emissions decreased
from 1999 due to a decrease in those animal populations.
As stated previously, smaller dairies are moving away
from daily spread systems. Therefore, more manure is
managed and stored on site, contributing to additional CH4
emissions over the time series. The CH4 estimates also
account for changes hi volatile solids production from dairy
cows correlated to their generally increasing milk
production. A description of the methodology is provided
in Annex L.
Total N2O emissions from manure management systems
in 2000 were estimated to be 17.5 Tg CQ2 Eq. (56.5 Gg).
The 9 percent increase in N2O emissions from 1990 to 2000
can be partially attributed to a shift in the'poultry industry
away from the use of liquid manure management systems,
in favor of Utter-based systems and high rise houses. In
addition, there was an overall increase in the population of
poultry and swine from 1990 to 2000,' although swine
populations declined slightly in 1993, 1995, 1996, 1999,
and 2000 from previous years and poultry populations
decreased in 1995.
The population of beef cattle in feedlots, which tend to
store and manage manure on site, also increased, resulting
in increased N2O emissions from this animal category.
Although dairy cow populations decreased overall, the
population of dairies managing and storing manure on site—
as opposed to using pasture, range, or paddock or daily
spread systems—increased. Therefore, | the increase in
dairies using on-site storage to manage their manure results
in increased N2O emissions. As stated previously, N2O
emissions from livestock manure deposited on pasture,
range, or paddock land and manure immediately applied to
land in daily spread systems are accounted for under
Agricultural Soil Management.
Methodology
i
The methodologies presented in Good Practice Guidance
and Uncertainty Management in National Greenhouse Gas
Inventories (TPCC 2000) form the basis of the CH4 and N2O
emissions estimates for each animal type. The calculation of
emissions requires the following information:
• Animal population data (by animal type and state)
• Amount of nitrogen produced (amount per 1000 pound
animal times average weight times number of head)
• Amount of volatile solids produced (amount per
1000 pound animal times average weight times
number of head)
• Methane producing potential of the volatile solids (by
animal type)
• Extent to which the methane producing potential is
realized for each type of manure management system
(by State and manure management sy'stem)
5-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 5-5: CH4 and N,0 Emissions from Manure Management (Tg C02 Eq.)
•r Gas/Animal Type 1990 i
LCH4 29.2 !
~~~ Dairy Cattle 9.6 |
: Beef Cattle o.d • j
Swine 13.0 ;
L Sheep 0.1
f Goats + '
r Poultry 2.7
F Horses 0.6
•i, N20 16.0 (
''' Dairy Cattle " 4.2
-- Beef Cattle 4.9
"t Swine 0.3
! Sheep +
fi Goats +
i: Poultry 6.3
S- Horses 0.2
^ Total 45.2
p?1 1995 1996 1997 1998
P5; 34.8 34.2 35.9 38.0
|gf 12.0 12.1 12.7 13.1
US 16!o m3 164 18/1
£2 °-1 + +" +
IP! 2.6 2.6 2.7 2.7
B3 0.6 0.6 0.6 0.6
^:^ 16.4 16.8 17.1 17.1
BBI 4.0 3.9 3.9 3.8
prf 5.3 5.1 5.4 5.5
•PSi 0.3 0.3 0.4 0.4
+ + + +
HI ' '6.5 7.2 7.2 7.2
0.2 0.2 0.2 0.2
E8**! 51.2 51.0 53.0 55.1
1999
37.6
13.3
04
17.6
2.6
0.6
17.2
3.8
5.5
0.4
7.2
0.2
54.8
2000
37.5
13.7
•24
17.1
2.6
0.6
17.5
3.8
5.9
0.4
7.2
0.2
55.0
" + Does not exceed 0.05 Tg C02 Eq.
- Note: Totals may not sum due to independent rounding.
Table 5-6: CH4 and N20 Emissions from Manure Management (Gg)
Gas/Animal Type
CH4
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
N20
Dairy Cattle
~ Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
1990 f
1,390 t
457
151
621
128 i
29 f
52 i
14
16
; . . i '
1
f»t 1995
«
sgf — 571"
El ^
Hf 2
^3 124 '
ini 29
"^n 53
13
21
1
1996
1,628
577
165
729
2
1
125
29
54
13
17
1
23
1
1997
1,707
604
163
782
2
1
127
29
55
12
17
1
23
1
1998
1,811
624
161
864
2
1
130
29
55
12
18
1
23
1
1999
1,788
634
160
839
2
1
124
30
55
12
18
1
23
1
2000
1,783
653
161
814
2
1
124
30
57
12
19
1
23
1
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding.
• Portion of manure managed in each manure
management system (by State and animal type)
• Portion of manure deposited on pasture, range, or
paddock or used in daily spread systems
Both CH4 and N2O emissions were estimated by first
determining activity data, including animal population,
waste characteristics, and manure management system
usage. For swine and dairy cattle, manure management
system usage was determined for different farm size
categories using data from USDA (USDA 1996b, 1998d,
2000h) and EPA(ERG2000a,EPA2001a,2001b). For beef
cattle and poultry, manure management system usage data
was not tied to farm size (ERG 2000a, USDA 2000i). For
other animal types, manure management system usage was
based on previous EPA estimates (EPA 1992).
Next, MCFs and N2O emission factors were determined
for all manure management systems. MCFs for dry systems
and N2O emission factors for all systems were set equal to
Agriculture 5-7
-------
default IPCC factors (IPCC 2000). MCFs for liquid/slurry,
anaerobic lagoon, and deep pit systems were calculated
based on the forecast performance of biological systems
relative to temperature changes as predicted in the van't
Hoff-Arrhenius equation (see Annex L for detailed
information on MCF derivations for liquid systems). The
MCF calculations model the average monthly ambient
temperature, a minimum system temperature, the carryover
of volatile solids in the system from month to month due to
long storage times exhibited by anaerobic lagoon systems,
and a factor to account for management and design practices
that result in the loss of volatile solids from lagoon systems.
For each animal group—except sheep, goats, and
horses—the base emission factors were then weighted to
incorporate the distribution of management systems used
within each state and thereby to create an overall state-
specific weighted emission factor. To calculate this weighted
factor, the percent of manure for each animal group managed
in a particular system in a state was multiplied by the
emission factor for that system and state, and then summed
for all manure management systems in the state.
Methane emissions were estimated by calculating the
volatile solids (VS) production for all livestock. For each
animal group except dairy cows, VS production was
calculated using a national average VS production rate from
the Agricultural Waste Management Field Handbook
(USDA 1996a), which was then multiplied by the average
weight of the animal and the State-specific animal
population. For dairy cows, the national average VS constant
was replaced with a mathematical relationship between milk
production and VS (USDA 1996a), which was then
multiplied by State-specific average annual milk production
(USDA 2001g), The resulting VS for each animal group
was then multiplied by the maximum methane producing
capacity of the waste (Bo), and the State-specific methane
conversion factors.
Nitrous oxide emissions were estimated by determining
total Kjeldahl nitrogen (TKN)1 production for all livestock
wastes using; livestock population data and nitrogen
excretion rates. For each animal group, TKN production
was calculated using a national average nitrogen excretion
rate from the Agricultural Waste Management Field
Handbook (USDA 1996a), which was then multiplied by
the average weight of the animal and the State-specific
animal population. State-specific weighted N2O emission
factors specific to the type of manure management system
were then applied to total nitrogen production to estimate
N2O emissions.
E
See Annex L for more detailed information on the
methodology and data used to calculate methane and nitrous
oxide emissions from manure management.
Data Sources
Animal population data for all livestock types, except
horses and goats, were obtained from the U.S. Department
of Agriculture's National Agricultural Statistics Service
(USDA 1994a-b, 1995a-b, 1998a-b, 1999a-c, 2000a-g,
2001a-f). Horse population data were obtained from the
FAOSTAT database (FAO 2001). Goat population data were
obtained from the Census of Agriculture (USDA 1999d).
Information regarding poultry turnover (i.e., slaughter) rate
was obtained from State Natural Resource Conservation
Service (NRCS) personnel (Lange 2000): Dairy cow and
swine population data by farm size for each state, used for
the weighted MCF and emission factor calculations, were
obtained from the Census of Agriculture, which is conducted
every five years (USDA 1999e).
Manure management system usage data for dairy and
swine operations were obtained from USDA's Centers for
Epidemiology and Animal Health (USDA 1996b, 1998d,
2000h) for small operations and from preliminary estimates
for EPA's Office of Water regulatory effort for large
operations (ERG 2000a; EPA 2001a, 2001b). Data for layers
were obtained from a voluntary United Egg Producers'
survey (UEP 1999), previous EPA estimates (EPA 1992),
and USDA's Animal Plant Health Inspection Service (USDA
2000i). Data for beef feedlots were also obtained from EPA's
Office of Water (ERG 2000a; EPA2001a, 2001b). Manure
management system usage data for other livestock were
taken from previous EPA estimates (EPA 1992). Data
regarding the use of daily spread and pasture, range, or
paddock systems for dairy cattle were ^obtained from
personal communications with personnel from several
organizations, and data provided by those ^personnel (Poe
Total Kjeldahl nitrogen is a measure of organically bound nitrogen and ammonia nitrogen.
5-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
et al. 1999). These organizations include State NRCS
offices, State extension services, State universities, USDA
National Agriculture Statistics Service (NASS), and other
experts (Deal 2000, Johnson 2000, Miller 2000, Stettler
2000, Sweeten 2000, and Wright 2000). Additional
information regarding the percent of beef steer and heifers
on feedlots was obtained from contacts with the national
USDA office (Milton 2000).
Methane conversion factors for liquid systems were
calculated based on average ambient temperatures of the
counties in which animal populations were located. The
average county and state temperature data were obtained
from the National Climate Data Center (NO A A 2001),
and the county population data were based on 1992 and
1997 Census data (USDA 1999e). County population data
for 1990 and 1991 were assumed to be the same as 1992;
county population data for 1998 through 2000 were
assumed to be the same as 1997; and county population
data for 1993 through 1996 were extrapolated based on
1992 and 1997 data.
The maximum methane producing capacity of the
volatile solids, or Bo, was determined based on data collected
in a literature review (ERG 2000b). Bo data were collected
for each animal type for which emissions were estimated.
Volatile solids and nitrogen excretion rate data from
the USDAAgricultural Waste Management Field Handbook
(USDA 1996a) were used for all livestock except sheep,
goats, and horses. Data from the American Society of
Agricultural Engineers (ASAE 1999) were used for these
animal types. In addition, annual NASS data for average
milk production per cow per State (USDA 2001 g) were used
to calculate state-specific volatile solids production rates
for dairy cows for each year of the inventory. Nitrous oxide
emission factors andMCFs for dry systems were taken from
Good Practice Guidance and Uncertainty Management in
National Greenhouse Gas Inventories (IPCC 2000).
Uncertainty
The primary factors contributing to the uncertainty in
emission estimates are a lack of information on the usage
of various manure management systems in each regional
location and the exact methane generating characteristics
of each type of manure management system. Because of
significant shifts hi the swine and dairy sectors toward larger
farms, it is believed that increasing amounts of manure are
being managed in liquid manure management systems. The
existing estimates reflect these shifts in the weighted MCFs
based on the 1992 and 1997 farm-size data. However, the
assumption of a direct relationship between farm size and
liquid system usage may not apply in all cases and may
vary based on geographic location. In addition, the CH4
generating characteristics of each manure management
system type are based on relatively few laboratory and field
measurements, and may not match the diversity of conditions
under which manure is managed nationally.
Good Practice Guidance and Uncertainty
Management in National Greenhouse Gas Inventories
(IPCC 2000) published a default range of MCFs for
anaerobic lagoon systems of 0 to 100 percent, which
reflects the wide range in performance that may be
achieved with these systems. There exist relatively few
data points on which to determine country-specific MCFs
for these systems. In the United States, many livestock
waste treatment systems classified as anaerobic lagoons
are actually holding ponds that are substantially
organically overloaded and therefore not producing
methane at the same rate as a properly designed lagoon.
In addition, these systems may not be well operated,
contributing to higher loading rates when sludge is
allowed to enter the treatment portion of the lagoon or
the lagoon volume is pumped too low to allow treatment
to occur. Rather than setting the MCF for all anaerobic
lagoon systems in the United States based on data
available from optimized lagoon systems, an MCF
methodology was developed that more closely matches
observed system performance and accounts for the affect
of temperature on system performance.
However, there is uncertainty related to the new
methodology. The MCF methodology used in the inventory
includes a factor to account for management and design
practices that result in the loss of volatile solids from the
management system. This factor is currently estimated based
on data from anaerobic lagoons in temperate climates, and
from only three systems. However, this methodology is
intended to account for systems across a range of
management practices. Future work in gathering
measurement data from animal waste lagoon systems across
the country will contribute to the verification and refinement
of this methodology. It will also be evaluated whether lagoon
Agriculture 5-9
-------
temperatures differ substantially from ambient temperatures
and whether the lower bound estimate of temperature
established for lagoons and other liquid systems should be
revised for use with this methodology.
The IPCC provides a suggested MCF for poultry
waste management operations of 1.5 percent. Additional
study is needed in this area to determine if poultry high-
rise houses promote sufficient aerobic conditions to
warrant a lower MCF.
The default N2O emission factors published in Good
Practice Guidance and Uncertainty Management in
National Greenhouse Gas Inventories (IPCC 2000) were
derived using limited information. The IPCC factors are
global averages; U.S.-specific emission factors may be
significantly different. Manure and urine in anaerobic
lagoons and liquid/slurry management systems produce
methane at different rates, and would in all likelihood
produce nitrous oxide at different rates, although a single
N2O emission factors was used for both system types. In
addition, there are little data available to determine the
extent to which nitrification-denitrification occurs in
animal waste management systems. Ammonia
concentrations that are present in poultry and swine
systems suggest that N2O emissions from these systems
may be lower than predicted by the IPCC default factors.
At this time, there are insufficient data available to
develop U.S.-specific N2O emission factors; however,
this is an area of on-going research, and warrants further
study as more data become available.
Although an effort was made to introduce the variability
in volatile solids production due to differences in diet for
dairy cows, additional work is needed to establish the
relationship between milk production and volatile solids
production. In addition, the corresponding dairy methane
emissions may be underestimated because milk production
was unable to be correlated to specific manure management
systems in each state. A methodology to assess variability
in swine volatile solids production would be useful in future
inventory estimates.
Uncertainty also exists with the maximum CH4
producing potential of volatile solids excreted by different
animal groups (i.e., Bo). The Bo values used in the CH4
calculations are published values for U.S. animal waste.
However, there are several studies that provide a range of
Bo values for certain animals, including dairy and swine.
The Bo values chosen for dairy assign separate values for
dairy cows and dairy heifers to better represent the feeding
regimens of these animal groups. For example, dairy heifers
do not receive an abundance of high energy feed and
consequently, dairy heifer manure will not produce as much
methane as manure from a milking cow. However, the data
available for Bo values are sparse, and do not necessarily
reflect the rapid changes that have occurred in this industry
with respect to feed regimens. Current research is being
conducted to evaluate the usefulness of incorporating animal
excretion data developed for the enteric fermentation
emissions inventory into the manure management inventory
calculations.
Rice Cultivation
Most of the world's rice, and all rice in the United
States, is grown on flooded fields. When fields are
flooded, aerobic decomposition of organic material
gradually depletes the oxygen present; in the soil and
floodwater, causing anaerobic conditions in the soil to
develop. Once the environment becomes anaerobic,
methane is produced through anaerobic decomposition
of soil organic matter by methanogenic bacteria. As much
as 60 to 90 percent of the methane produced is oxidized
by aerobic methanotrophic bacteria in the soil (Holzapfel-
Pschorn et al. 1985, Sass et al. 1990). Some of the CH4
is also leached away as dissolved methane in floodwater
that percolates from the field. The remaining un-oxidized
CH4 is transported from the submerged soil to the
atmosphere primarily by diffusive transport through the
rice plants. Minor amounts of methane also escape from
the soil via diffusion and bubbling through floodwaters.
The water management system under which rice is
grown is one of the most important factors affecting CH4
emissions. Upland rice fields are not flooded, and therefore
are not believed to produce CH4. In deepwater rice fields
(i.e., fields with flooding depths greater than one meter),
the lower stems and roots of the rice plants are dead so the
primary CH4 transport pathway to the atmosphere is blocked.
The quantities of CH4 released from deepwater fields,
therefore, are believed to be significantly less than the
quantities released from areas with more phallow flooding
5-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
depths. Some flooded fields are drained periodically during
the growing season, either intentionally or accidentally. If
water is drained and soils are allowed to dry sufficiently,
CH4 emissions decrease or stop entirely. This is due to soil
aeration, which not only causes existing soil methane to
oxidize but also inhibits further CH4 production in soils.
All rice in the United States is grown under continuously
flooded conditions; none is grown under deep water
conditions. Mid-season drainage does not occur except by
accident (e.g., due to levee breach).
Other factors that influence CH4 emissions from
flooded rice fields include fertilization practices (especially
the use of organic fertilizers), soil temperature, soil type,
rice variety, and cultivation practices (e.g., tillage, and
seeding and weeding practices). The factors that determine
the amount of organic material that is available to decompose
(i.e., organic fertilizer use, soil type, rice variety,2 and
cultivation practices) are the most important variables
influencing the amount of CH4 emitted over an entire
growing season because the total amount of CH4 released
depends primarily on the amount of organic substrate
available. Soil temperature is known to be an important
factor regulating the activity of methanogenic bacteria, and
therefore the rate of CH4 production. However, although
temperature controls the amount of time it takes to convert
a given amount of organic material to CH4, that time is short
relative to a growing season, so the dependence of total
emissions over an entire growing season on soil temperature
is weak. The application of synthetic fertilizers has also been
found to influence CH4 emissions; in particular, both nitrate
and sulfate fertilizers (e.g., ammonium nitrate, and
ammonium sulfate) appear to inhibit CH4 formation.
Rice is cultivated in seven states: Arkansas, California,
Florida, Louisiana, Mississippi, Missouri, and Texas. Soil
types, rice varieties, and cultivation practices for rice vary
from state to state, and even from farm to farm. However,
most rice farmers utilize organic fertilizers in the form of
rice residue from the previous crop, which is left standing,
disked, or rolled into the fields. Most farmers also apply
synthetic fertilizer to their fields, usually urea. Nitrate and
sulfate fertilizers are not commonly used in rice cultivation
in the United States. In addition, the climatic conditions of
Arkansas, southwest Louisiana, Texas, and Florida allow
for a second, or ratoon, rice crop. This second rice crop is
produced from regrowth of the stubble after the first crop
has been harvested. Because the first crop's stubble is left
behind in ratooned fields, and there is no time delay between
cropping seasons (which would allow for the stubble to
decay aerobically), the amount of organic material that is
available for decomposition is considerably higher than with
the first (i.e., primary) crop. Methane emissions from ratoon
crops have been found to be considerably higher than those
from the primary crop.
Rice cultivation is a small source of CH4 in the United
States (Table 5-7 and Table 5-8). In 2000, CH4 emissions
from rice cultivation were 7.5 Tg CO2 Eq. (357 Gg).
Although annual emissions fluctuated considerably between
the years 1990 and 2000, there was an overall increase of 5
percent over the ten year period due to an overall increase
in harvested area. However, between 1990 and 1999 there
was a 17 percent increase in emissions, which highlights
the annual variability in the estimates. In 2000, the harvest
area was the largest since 1996, as seen in Table 5-9.
The factors that affect the rice acreage in any year vary
from State to State, although the price of rice relative to
competing crops is the primary controlling variable in most
States. Price is the primary factor affecting rice area in
Arkansas, as farmers will plant more of what is most
lucrative amongst soybeans, rice, and cotton. Government
support programs have also been influential in so much as
they affect the price received for a rice crop (Slaton 200 Ib,
Mayhew 1997). California rice area is primarily influenced
by price and government programs, but is also affected by
water availability (Mutters 2001). In Florida, the State
having the smallest harvested rice area, rice acreage is
largely a function of the price of rice relative to sugarcane
and corn. Most rice in Florida is rotated with sugarcane,
but sometimes it is more profitable for farmers to follow
their sugarcane crop with sweet corn or more sugarcane
instead of rice (Schueneman 1997, 2001b). In Louisiana,
rice area is influenced by government support programs,
the price of rice relative to cotton, soybeans, and corn, and
in some years, weather (Saichuk 1997, Linscombe 2001b).
For example, a drought in 2000 caused extensive saltwater
2 The roots of rice plants shed organic material, which is referred to as "root exudate." The amount of root exudate produced by a rice plant over a
growing season varies among rice varieties.
Agriculture 5-11
-------
Table 5-7: CH4 Emissions from Rice Cultivation (Tg C02 Eq.)
State
Arkansas
California
Rorida
Louisiana
Mississippi
Missouri
Texas
Total
1990
2.1
0.7
0.1
2.1
0.4
0.1
1.6
7.1
f "'
p 3
I
I 1
„ i
I
r •*
r
1995
2.4
0.8
0.1
2.2
0.5
0.2
1.4
7.6
1996
2.1
0.9
0.1
2.0
0.4
0.2
1.3
7.0
1997
2.5
0.9
0.1
2.2
0.4
0.2
1.1
7.5
1998
2.7
0.8
0.1
2.3
0.5
0.3
1.3
7.9
1999
2.9
0.9
0.1
2.3
0.6
0.3
1.1
8.3
2000
2.5
1.0
0.1
2.1
0,4
0.3
1.1
7.5
Note: Totals may not sum due to independent rounding.
Table 5-8: CH4
Site
Arkansas
California
Rorida
Louisiana
Mississippi
Missouri
Texas
Total
Emissions from
1990
102
34
3
98
21
7
75
339
Rice Cultivation (Gg)
_, 4
H U
i
j>
1
i i
1995
114
40
6
102
24
10
67
363
1996
99
42
5
96
18
8
63
332
1997
118
44
5
105
20
10
55
356
1998
126
39
5
111
23
12
60
376
1999
138
43
5 •
111
27
16
55
395
Note: Totals may not sum due to independent rounding.
2000
120
47
4
101
19
15
52
357
Table 5-9: Rice Areas Harvested (Hectares)
State/Crop
Arkansas
Primary
Ratoon*
California
Florida
Primary
Ratoon
Louisiana
Primary
Ratoon
Mississippi
Missouri
Texas
Primary
Ratoon
Total
1990
485,633
NO
159,854
4,978
2,489
220,558
66,168
101,174
32,376
142,857
57,143
1,273,229
-
if:;*!
?.
=- , , , f
•L ;„!!;
£!... IK
"- i
i %
f : :: |
»- -;;l
-- f,
t: |
»
1995
542,291
NO
188,183
9,713
4,856
230,676
69,203
116,552
45,326
128,693
51,477
1,386,969
1996
473,493
NO
202,347
8,903
4,452
215,702
64,711
84,176
38,446
120,599
48,240
1,261,068
1997
562,525
NO
208,822
7,689
3,845
235,937
70,781
96,317
47,349
104,816
41,926
1,380,008
1998
600,971
202
185,350
8,094
4,047
250,911
75,273
108,458
57,871
114,529
45,811
1,451,518
1999
657,628
202
204,371
7,229
4,673
249,292
74,788
130,716
74,464
104,816
41,926
1,550,106
2000
570,619
NO
• 221,773
7,801
3,193
, 194,253
77,701
88,223
70,417
86,605
43,302
1,363,888
Note: Totals may not sum due to independent rounding.
* Arkansas ratooning occurred only in
NO (Not Occurring)
1998 and
1999.
5-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
intrusion along the Gulf Coast, making over 32,000 hectares
unplantable. In Mississippi, rice is usually rotated with
soybeans, but if soybean prices increase relative to rice
prices, then some of the acreage that would have been
planted in rice, is instead planted in soybeans (Street 1997,
2001). In Missouri, rice acreage is affected by weather (e.g.,
rain during the planting season may prevent the planting of
rice), the price differential between rice and soybeans or
cotton, and government support programs (Stevens 1997,
Guethle 2001). In Texas, rice area is affected mainly by the
price of rice, government support programs, and water
availability (Klosterboer 1997, 2001b).
Methodology
The Revised 1996 IPCC Guidelines (IPCC/UNEP/
OECD/TEA 1997) recommends utilizing annual harvested
rice areas and area-based seasonally integrated emission
factors (i.e., amount of CH4 emitted over a growing season
per unit harvested area) to estimate annual CH4 emissions
from rice cultivation. This methodology is followed but a
United States specific emission factor is used in the
calculations. In addition, because daily average emissions
have been found to be much higher for ratooned crops than
for primary crops, emissions from ratooned and primary
areas are estimated separately. This is consistent with IPCC
Good Practice (guidance and Uncertainty Management in
National Greenhouse Gas Inventories (IPCC 2000).
Data Sources
The harvested rice areas for the primary and ratoon
crops in each state are presented in Table 5-9. Data for 1990
through 2000 for all states except Florida were taken from
U.S. Department of Agriculture's Field Crops Final
Estimates 1987-1992 (USDA 1994), Field Crops Final
Estimates 1992-1997 (USDA 1998), Crop Production 1999
Summary (USDA 2000), and Crop Production 2000
Summary (USDA 2001). Harvested rice areas in Florida,
which are not reported by USDA, were obtained from Tom
Schueneman (1999b, 1999c, 2000, 200la), a Florida
agricultural extension agent. Acreages for the ratoon crops
were derived from conversations with the agricultural
extension agents in each state. In Arkansas, ratooning
occurred only in 1998 and 1999, when the ratooned area
was less than 1 percent of the primary area (Slaton 1999,
2000, 2001a). In Florida, the ratooned area was 50 percent
of the primary area from 1990 to 1998 (Schueneman 1999a),
about 65 percent of the primary area in 1999 (Schueneman
2000), and around 41 percent of the primary area in 2000
(Schueneman 200la). In Louisiana, the percentage of the
primary area that was ratooned was constant at 30 percent
over the 1990 to 1999 period, but increased to approximately
40 percent in 2000 (Linscombe 1999a, 2001a and Bollich
2000). In Texas, the percentage of the primary area that
was ratooned was constant at 40 percent over the entire
1990 to 1999 period, but increased to 50 percent in 2000
due to an early primary crop (Klosterboer 1999, 2000,
2001a).
To determine what seasonal CH4 emission factors
should be used for the primary and ratoon crops, CH4 flux
information from rice field measurements in the United
States was collected. Experiments which involved the
application of nitrate or sulfate fertilizers, or other
substances believed to suppress CH4 formation, as well as
experiments in which measurements were not made over
an entire flooding season or in which floodwaters were
drained mid-season, were excluded from the analysis. The
remaining experimental results3 were then sorted by season
(i.e., primary and ratoon) and type of fertilizer amendment
(i.e., no fertilizer added, organic fertilizer added, and
synthetic and organic fertilizer added). The experimental
results from primary crops with synthetic and organic
fertilizer added (Bossio et al. 1999, Cicerone et al. 1992,
Sass et al. 1991a and 1991b) were averaged to derive an
emission factor for the primary crop, and the experimental
results from ratoon crops with synthetic fertilizer added
(Lindau and Bollich 1993, Lindau et al. 1995) were averaged
to derive an emission factor for the ratoon crop. The resultant
emission factor for the primary crop is 210 kg CH4/hectare-
season, and the resultant emission factor for the ratoon crop
is 780 kg CH4/hectare-season.
3 In some of these remaining experiments, measurements from individual plots were excluded from the analysis because of the reasons just mentioned.
In addition, one measurement from the ratooned fields (i.e., the flux of 2.041 g/m2/day in Lindau and Bollich 1993) was excluded since this emission
rate is unusually high compared to other flux measurements in the United States, as well as in Europe and Asia (IPCC/UNEP/OECD/IEA1997).
Agriculture 5-13
-------
Uncertainty
The largest uncertainty in the calculation of CH4
emissions from rice cultivation is associated with the
emission factors. Seasonal emissions, derived from field
measurements in the United States, vary by more than one
order of magnitude. This variability is due to differences in
cultivation practices, particularly the type, amount, and mode
of fertilizer application; differences in cultivar type; and
differences in soil and climatic conditions. Some of this
variability is accounted for by separating primary from
ratooned areas. However, even within a cropping season,
measured emissions vary significantly. Of the experiments
that were used to derive the emission factors used here,
primary emissions ranged from 22 to 479 kg CH/hectare-
season and ratoon emissions ranged from 481 to 1,490 kg
CH4/hectare-season. Based on these emission ranges, total
CH4 emissions from rice cultivation in 2000 were estimated
to range from 1.8 to 16 Tg CO2 Eq. (87 to 779 Gg).
A second source of uncertainty is the ratooned area
data, which are not compiled regularly. However, this is a
relatively minor source of uncertainty, as these areas account
for less than 10 percent of the total area. Expert judgment
was used to estimate these areas.
The last source of uncertainty is in the practice of
flooding outside of the normal rice season. According to
agriculture extension agents, all of the rice-growing States
practice this on some part of their rice acreage. Estimates
of these areas range from 5 to 33 percent of the rice acreage.
Fields are flooded for a variety of reasons: to provide habitat
for waterfowl, to provide ponds for crawfish production,
and to aid in rice straw decomposition. To date, methane
flux measurements have not been undertaken in these
flooded areas, so this activity is not included in the emission
estimates presented here.
Agricultural Soil Management
Nitrous oxide (N2O) is produced naturally in soils
through the microbial processes of nitrification and
denitrification.4 A number of agricultural activities add
nitrogen to soils, thereby increasing the amount of nitrogen
available for nitrification and denitrification, and ultimately
the amount of N2O emitted. These activities may add
nitrogen to soils either directly or indirectly (Figure 5-2).
Direct additions occur through various soil management
practices and from the deposition of manure on soils by
animals on pasture, range, and paddock (i.e., by animals
whose manure is not managed). Soil management practices
that add nitrogen to soils include fertilizer use, application
of managed livestock manure, disposal of sewage sludge,
production of nitrogen-fixing crops, retention of crop
residues, and cultivation of histosols (i.e., soils with a high
organic matter content, otherwise known as organic soils).5
Indirect additions of nitrogen to soils occur through two
mechanisms: 1) volatilization and subsequent atmospheric
deposition of applied nitrogen;6 and 2) surface runoff and
leaching of applied nitrogen into groundwater and surface
water. Other agricultural soil management practices, such
as irrigation, drainage, tillage practices, and fallowing of
land, can affect fluxes of N2O, as well as other greenhouse
gases, to and from soils. However, because there are
significant uncertainties associated with these other fluxes,
they have not been estimated. >
Agricultural soil management is the largest source of
N2O in the United States.7 Estimated emissions from this
source in 2000 were 297.4 Tg CO2 Eq. (959 Gg N2O) (see
Table 5-10 and Table 5-11). Although annual agricultural
soil management emissions fluctuated between 1990 and
2000, there was a general increase in emissions over the
^ Nitrification and denitrification are two processes within the nitrogen cycle that are brought about by certain microorganisms in! soils. Nitrification
is the aerobic microbial oxidation of ammonium (NH4) to nitrate (NO3), and denitrification is the anaerobic microbial reduction of nitrate to dinitrogen
gas (N2). Nitrous oxide is a gaseous intermediate product in the reaction sequence of denitrification, which leaks from microbial cells into the soil and
then into the atmosphere. Nitrous oxide is also produced during nitrification, although by a less well understood mechanism (Nevison 2000).
5 Cultivation of histosols does not, per se, "add" nitrogen to soils. Instead, the process of cultivation enhances mineralization of old, nitrogen-rich
organic matter that is present in histosols, thereby enhancing N2O emissions from histosols.
6 These processes entail volatilization of applied nitrogen as ammonia (NH3) and oxides of nitrogen (NOX), transformations of these gases within the
atmosphere (or upon deposition), and deposition of the nitrogen primarily in the form of paniculate ammonium (NH4), nitric acid (HNO3), and oxides
of nitrogen.
Note that the emission estimates for this source category include applications of nitrogen to all soils, but the term "Agricultural;Soil Management"
is kept for consistency with the reporting structure of the Revised 1996IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). -
5-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Figure 5-2
Agricultural Soils ;x£*g^sB;i|ili
Volatilization
This graphic illustrates the sources and pathways of nitrogen that
result in direct and indirect N2O emissions from agricultural soils
in the United States. Sources of nitrogen applied to, or deposited
on, soils are represented with arrows on the left-hand side of the
graphic. Emission pathways are also shown with arrows. On the
lower right-hand side is a cut-away view of a representative sec-
tion of a managed soil; histosol cultivation is represented here.
eleven-year period (see Annex M for a complete time series
of emission estimates). This general increase in emissions
was due primarily to an increase in synthetic fertilizer use,
manure production, and crop production over this period.
The year-to-year fluctuations are largely a reflection of
annual variations in synthetic fertilizer consumption and
crop production. Over the eleven-year period, total
emissions of N2O from agricultural soil management
increased by approximately 11 percent.
Estimated direct and indirect N2O emissions, by
subsource, are provided in Table 5-12, Table 5-13, and
Table 5-14.
Methodology
The methodology used to estimate emissions from
agricultural soil management is consistent with the Revised
1996IPCC Guidelines (IPCC/UNEP/OECD/IEA1997), as
amended by the IPCC Good Practice Guidance and
Uncertainty Management in National Greenhouse Gas
Inventories (IPCC 2000). The Revised 1996 IPCC
Guidelines divide this N2O source category into three
components: (1) direct emissions from managed soils due
to applied nitrogen and cultivation of histosols; (2) direct
emissions from soils due to the deposition of manure by
livestock on pasture, range, and paddock; and (3) indirect
emissions from soils induced by applied nitrogen.
Table 5-10: H20 Emissions from Agricultural Soil Management (Tg C02 Eq.)
Activity
Direct
Managed Soils
Pasture, Range, & Paddock Livestock
Indirect
Total
1990 ^7Z
193.5
153.0
73.6
267.1 H_!
1995
204.8
161.1
43.6
78.6
283.4
1996
212.1
168.6
43.6
80.3
292.4
1997
217.2
175.0
42.2
80.0
297.2
1998
218.4
177.1
41.4
79.8
298.3
1999
216.5
175.5
41.0
79.8
296.3
2000
217.5
177.1
40.5
79.8
297.4
Note: Totals may not sum due to independent rounding.
Table 5-11: N20 Emissions from Agricultural Soil Management (Gg)
\: Activity
r Direct
:: Managed Soils
; Pasture, Range, & Paddock
Indirect
Total
'- Note: Totals may not sum due to
•
1990 Hi
624 ' Iff?
494 SB-!.-"-".*
Livestock 130
237 EJ
independent rounding.
1995
661
520
141
254
914
1996
684
544
140
259
943
—
1997
701
564
136
258
959
1998
705
571
133
257
962
1999
698
566
132
257
956
2000
702
571
131
257
959
Agriculture 5-15
-------
Table 5-12: Direct N20 Emissions from Managed Soils (Tg C02 Eq.)
Activity 1990
S" f
Commercial Fertilizers* 55.4
Livestock Manure 12.7 ~ ;
Sewage Sludge 0.4 s
N Fixation 58.5 -
Crop Residue 23.2
Histosol Cultivation 2.8 ' "
Total 153.0
Note: Totals may not sum due to independent rounding.
* Excludes sewage sludge and livestock manure used as commercial fertilizers.
1995
59.2'
13.2
0.6
61.8
23.4
2.8
161.1
1996
61.2
13.2
0.6
63.9
26.8
2.8
168.6
1997
61.3
13.4
0.7
68.2
28.7
2.9
175.0
1998
61.4
13.6
0.7
69.2
29.3
2.9
177.1
1999
61.6
13.8
0.7
68.2
28.3
2.9
175.5
2000
61.7
13.8
0.7
69.0
29.1
2.9
177.1
Table 5-13: Direct N20 Emissions from Pasture, Range, and Paddock Livestock Manure (Tg C02 Eq.)
Animal Type
Beef Cattle
Dairy Cows
Swine
Sheep
Goats
Poultry
Horses
Total
1990
35.2
1.7
0.5
0.4
0.2
0.1
2.3
40.4
Note: Totals may not sum due to independent rounding.
H
F m
5" "I
i i
- i
!
1995
38.9
1.5
0.3
0.3
0.2
0.1
2.3
43.6
1996
39.0
1.4
0.3
0.3
0.2
0.1
2.3
43.6
1997
37.8
1.3
0.2
0.3
0.2
0.1
2.3
42.2
1998
37.0
1.3
0.2
0.3
0.2
0.1
2.3
41.4
1999
36.7
1.2
0.2
0.3
0.2
'0.1
2.3
41.0
2000
36.2
1.2 . ;
0.2
0.3 ;
0.2
0.1
2.3 ;
40.5
Table 5-14: Indirect N20 Emissions (Tg C02 Eq.)
Activity
Volatilization & Aim. Deposition
Commercial Fertilizers*
Livestock Manure
Sewage Sludge
Surface Leaching & Runoff
Commercial Fertilizers*
Livestock Manure
Sewage Sludge
Total
1990
11.6
4.9
6.6
0.1
62.0
36.9
24.7
0.3
73.6
r •• •• • v
«i, j
i"" i
«;: 'J'~*
~
-'- Ij
f™ i1 : inl.
3^-" ,"'
fe n,,.
1995
12.4
5.3
7.0
0.1
66.2
39.5
26.3
0.5
78.6
1996
12.6
5.4
7.1
0.1
67.6
40.8
26.4
0.5
80.3
1997
12.6
5.5
7.0
0.1
67.4
40.9
26.1
0.5
80.0
1998
12.5
5.5
6.9
0.1
67.3
40.9
25.8
0.5
79.8
1999
12.5
.5.5
6.9
0.1
67.3
41.1
25.7
;o.s
79.8
2000
12.5
5.5
6.9
0.1
67.3
41.1
25.7
0.5
79.8
Note: Totals may not sum due to independent rounding.
* Excludes sewage sludge and livestock manure used as
commercial fertilizers.
5-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Annex M provides more detailed information on the
methodologies and data used to calculate N2O emissions
from each of these three components.
Direct N20 Emissions from Managed Soils
Direct N2O emissions from managed soils are composed
of two parts, which are estimated separately and then summed.
These two parts are 1) emissions due to nitrogen applications,
and 2) emissions from histosol cultivation.
Estimates of direct N2O emissions from nitrogen
applications were based on the total amount of nitrogen
that is applied to soils annually through the following
practices: (a) the application of synthetic and organic
commercial fertilizers, (b) the application of livestock
manure through both daily spread operations and through
the eventual application of manure that had been stored in
manure management systems, (c) the application of sewage
sludge, (d) the production of nitrogen-fixing crops, and (e)
the retention of crop residues (i.e., leaving residues in the
field after harvest). For each of these practices, the annual
amounts of nitrogen applied were estimated as follows:
a) Synthetic and organic commercial fertilizer
nitrogen applications were derived from annual fertilizer
consumption data and the nitrogen content of the fertilizers.
b) Livestock manure nitrogen applications were
based on the assumption that all livestock manure is
applied to soils except for two components: 1) a small
portion of poultry manure that is used as a livestock feed
supplement, and 2) the manure from pasture, range, and
paddock livestock. The manure nitrogen data were
derived from animal population and weight statistics,
information on manure management system usage,
annual nitrogen excretion rates for each animal type, and
information on the fraction of poultry litter that is used
as a livestock feed supplement.
c) Sewage sludge nitrogen applications were derived
from estimates of annual U.S. sludge production, the
nitrogen content of the sludge, and periodic surveys of
sludge disposal methods.
d) The amounts of nitrogen made available to soils
through the cultivation of nitrogen-fixing crops were based
on estimates of the amount of nitrogen in aboveground plant
biomass, which were derived from annual crop production
statistics, mass ratios of aboveground residue to crop
product, dry matter fractions, and nitrogen contents of the
plant biomass.
e) Crop residue nitrogen retention data were derived
from information about which residues are typically left on
the field, the fractions of residues left on the field, annual
crop production statistics, mass ratios of aboveground
residue to crop product, and dry matter fractions and
nitrogen contents of the residues.
After the annual amounts of nitrogen applied were
estimated for each practice, each amount of nitrogen was
reduced by the fraction that is assumed to volatilize
according to the Revised 1996 IPCC Guidelines and the
IPCC Good Practice Guidance and Uncertainty
Management in National Greenhouse Gas Inventories. The
net amounts left on the soil from each practice were then
summed to yield total unvolatilized applied nitrogen, which
was multiplied by the IPCC default emission factor for
nitrogen applications.
Estimates of annual N2O emissions from histosol
cultivation were based on estimates of the total U.S.
acreage of histosols cultivated annually for each of two
climatic zones: 1) temperate, and 2) sub-tropical. To
estimate annual emissions, the total temperate area was
multiplied by the IPCC default emission factor for
temperate regions, and the total sub-tropical area was
multiplied by the average of the IPCC default emission
factors for temperate and tropical regions.8
Total annual emissions from nitrogen applications, and
annual emissions from histosol cultivation, were then summed
to estimate total direct emissions from managed soils.
Direct N20 Emissions from Pasture, Range, and
Paddock Livestock Manure
Estimates of N2O emissions from this component are
based on the amount of nitrogen in the manure that is
deposited annually on soils by livestock in pasture, range,
and paddock. Estimates of annual manure nitrogen from
8 Note that the IPCC default emission factors for histosols have been revised in the IPCC Good Practice Guidance and Uncertainty Management in
National Greenhouse Gas Inventories (IPCC 2000). These revised default emission factors (IPCC 2000) were used in these calculations.
Agriculture 5-17
-------
these livestock were derived from animal population and
weight statistics; information on the fraction of the total
population of each animal type that is on pasture, range,
or paddock; and annual nitrogen excretion rates for each
animal type. The annual amounts of manure nitrogen from
each animal type were summed over all animal types to
yield total pasture, range, and paddock manure nitrogen,
which was then multiplied by the IPCC default emission
factor for pasture, range, and paddock nitrogen to
estimate N00 emissions.
Indirect N20 Emissions from Soils
Indirect emissions of N2O are composed of two parts,
which are estimated separately and then summed. These
two parts are 1) emissions resulting from volatilization and
subsequent deposition of the nitrogen in applied fertilizers,
applied sewage sludge, and all livestock manure,9 and 2)
leaching and runoff of nitrogen in applied fertilizers, applied
sewage sludge, and applied plus deposited livestock manure.
The activity data (i.e., nitrogen in applied fertilizers, applied
sewage sludge, all livestock manure, and applied plus
deposited livestock manure) were estimated in the same way
as for the direct emission estimates.
To estimate the annual amount of applied nitrogen that
volatilizes, the annual amounts of applied synthetic fertilizer
nitrogen, applied sewage sludge nitrogen, and all livestock
manure nitrogen, were each multiplied by the appropriate
IPCC default volatilization fraction. The three amounts of
volatilized nitrogen were then summed, and the sum was
multiplied by the IPCC default emission factor for
volatilized/deposited nitrogen.
To estimate the annual amount of nitrogen that leaches
or runs off, the annual amounts of applied synthetic fertilizer
nitrogen, applied sewage sludge nitrogen, and applied plus
deposited livestock manure nitrogen were each multiplied
by the IPCC default leached/runoff fraction. The three
amounts of leached/runoff nitrogen were then summed, and
the sum was multiplied by the IPCC default emission factor
for leached/runoff nitrogen.
Total annual indirect emissions from volatilization, and
annual indirect emissions from leaching [and runoff, were
then summed to estimate total indirect emissions of N2O
from managed soils.
Data Sources
The activity data used in these calculations were
obtained from numerous sources. Annual synthetic and
organic fertilizer consumption data for the United States
were obtained from annual publications on commercial
fertilizer statistics (TVA1991,1992a, 1993,1994; AAPFCO
1995, 1996, 1997, 1998, 1999, 2000b). Fertilizer nitrogen
contents were taken-from these same publications and
AAPFCO (2000a). Livestock population data were obtained
from USDA publications (USDA 1994b,c; 1995a,b;
1998a,c; 1999a-e; 2000a-g; 2001b-g), the FAOSTAT
database (FAO 2001), and Lange (2000). Manure
management information was obtained from Poe et al.
(1999), Safley et al. (1992), and personal communications
with agricultural experts (Anderson 2000, Deal 2000,
Johnson 2000, Miller 2000, Milton 2000, Stettler 2000,
Sweeten 2000, Wright 2000). Livestock weight data were
obtained from Safley (2000), USDA (1996, 1998d), and
ASAE (1999); daily rates of nitrogen excretion from AS AE
(1999) and USDA (1996); and information about the
fraction of poultry litter used as a feed supplement from
i
Carpenter (1992). Data collected by the EPA were used to
derive annual estimates of land application1 of sewage sludge
(EPA 1993, 1999). The nitrogen content of sewage sludge
was taken from Metcalf and Eddy, Inc. (1991). Annual
production statistics for nitrogen-fixing crops were obtained
from USDA reports (USDA 1994a, 1998b, 2000i, 2001a),
a book on forage crops (Taylor and Smitri 1995, Pederson
1995, Beuselinck and Grant 1995, Hoveland and Evers
1995), and personal communications with forage experts
(Cropper 2000, Gerrish 2000, Hoveland 2000, Evers 2000,
and Pederson 2000). Mass ratios of abovegrourid residue
to crop product, dry matter fractions, and nitrogen contents
for nitrogen-fixing crops were obtained from Strehler and
Stutzle (1987), Barnard and Rristoferson!(1985), Karkosh
(2000), Ketzis (1999), andlPCC/UNEP/OfeCD/IEA (1997).
9 Total livestock manure nitrogen is used in the calculation of indirect N2O emissions from volatilization because all manure nitrogen, regardless of
how the manure is managed or used, is assumed to be subject to volatilization. '
5-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Annual production statistics for crops whose residues are
left on the field, except for rice in Florida, were obtained
from USDA reports (USDA 1994a, 1998b, 2000i, 200la).
Production statistics for rice in Florida are not recorded by
USDA, so these were derived from Smith (2001) and
Schueneman (1999, 2001). Aboveground residue to crop
mass ratios, residue dry matter fractions, and residue
nitrogen contents were obtained from Strehler and Stiitzle
(1987), Turn et al. (1997), Ketzis (1999), and Barnard and
Kristoferson (1985). Estimates of the fractions of residues
left on the field were based on information provided by
Karkosh (2000), and on information about rice residue
burning (see the Agricultural Residue Burning section). The
annual areas of cultivated histosols were estimated from
1982, 1992, and 1997 statistics in USDA's 1997 National
Resources Inventory (USDA 2000h, as extracted by Eve
2001, and revised by Ogle 2002).
All emission factors, volatilization fractions, and the
leaching/runoff fraction were taken from the Revised 1996
IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997), as
amended by the IPCC Good Practice Guidance and
Uncertainty Management in National Greenhouse Gas
Inventories (IPCC 2000).
Uncertainty
The amount of N2O emitted from managed soils
depends not only on N inputs, but also on a large number of
variables, including organic carbon availability, O2 partial
pressure, soil moisture content, pH, soil temperature, and
soil amendment management practices. However, the effect
of the combined interaction of these other variables on N2O
flux is complex and highly uncertain. Therefore, the IPCC
default methodology, which is used here, is based only on
N inputs and does not utilize these other variables. As noted
in the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/
IEA1997), this is a generalized approach that treats all soils,
except cultivated histosols, as being under the same
conditions. The estimated ranges around the IPCC default
emission factors provide an indication of the uncertainty in
the emission estimates due to this simplified methodology.
Most of the emission factor ranges are about an order of
magnitude, or larger. Developing an emission estimation
methodology that explicitly utilizes these other variables
will require more scientific research and much more detailed
databases, and will likely involve the use of process models.
Uncertainties also exist in the activity data used to
derive emission estimates. In particular, the fertilizer
statistics include only those organic fertilizers that enter the
commercial market, so non-commercial fertilizers (other
than the estimated manure and crop residues) have not been
captured. The livestock excretion values, while based on
detailed population and weight statistics, were derived using
simplifying assumptions concerning the types of
management systems employed. Statistics on sewage sludge
applied to soils were not available on an annual basis; annual
production and application estimates were based on figures
and projections that were calculated from surveys that
yielded uncertainty levels as high as 14 percent (Bastian
1999). Annual data were obtained by interpolating and
extrapolating at constant rates from these uncertain figures,
though change between the years was unlikely to be constant
(Bastian 2001). The production statistics for the nitrogen-
fixing crops that are forage legumes are highly uncertain
because statistics are not compiled for any of these crops
except alfalfa, and the alfalfa statistics include alfalfa
mixtures. Conversion factors for the nitrogen-fixing crops
were based on a limited number of studies, and may not be
representative of all conditions in the United States. Data
on crop residues left on the field are not available, so expert
judgment was used to estimate the amount of residues left
on soils. And finally, the estimates of cultivated histosol
areas are uncertain because they are from a natural resource
inventory that was not explicitly designed as a soil survey,
and this natural resource inventory contains data for only
three years (1982, 1992, and 1997). Annual histosol areas
were estimated by linear interpolation and extrapolation.
Agricultural Residue Burning
Large quantities of agricultural crop residues are
produced by farming activities. There are a variety of ways
to dispose of these residues. For example, agricultural
residues can be left on or plowed back into the field,
composted and then applied to soils, landfilled, or burned
Agriculture 5-19
-------
in the field. Alternatively, they can be collected and used as
a fuel or sold in supplemental feed markets. Field burning
of crop residues is not considered a net source of carbon
dioxide (CO2) because the carbon released to the atmosphere
as CO2 during burning is assumed to be reabsorbed during
the next growing season. Crop residue burning is, however,
a net source of methane (CH4), nitrous oxide (N2O), carbon
monoxide (CO), and nitrogen oxides (NOx), which are
released during combustion.
Field burning is not a common method of agricultural
residue disposal in the United States; therefore, emissions
from this source are minor. The primary crop types whose
residues are typically burned hi the United States are wheat,
rice, sugarcane, corn, barley, soybeans, and peanuts. Of
these residues, less than 5 percent is burned each year, except
for rice.10 Annual emissions from this source over the period
1990 through 2000 averaged approximately 0.7 Tg CO2 Eq.
(35 Gg) of CH4, 0.4 Tg CO2 Eq. (1 Gg) of N2O, 725 Gg of
CO, and 31 Gg of NOX (see Table 5-15 and Table 5-16).
Methodology
The methodology for estimating;greenhouse gas
emissions from field burning of agricultural residues is
consistent with the Revised 1996IPCC Guidelines (IPCC/
UNEP/OECD/IEA 1997). In order to estimate the amounts
of carbon and nitrogen released during burning, the
following equations were used:11
Carbon Released = (Annual Crop Production) x
(Residue/Crop Product Ratio) x (Fraction of Residues
Burned in situ) x (Dry Matter Content of the Residue)
x (Burning Efficiency) x (Carbon Content of the
Residue) x (Combustion Efficiency):12
Nitrogen Released = (Annual Crop Production) x
(Residue/Crop Product Ratio) x (Fraction of Residues
Burned in situ) x (Dry Matter Content of the Residue)
x (Burning Efficiency) x (Nitrogen Content of the
Residue) x (Combustion Efficiency)'
Table 5-15: Emissions from Agricultural
Gas/Crop Type
CH4
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
N20
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
Total
Residue Burning (Tg C02 Eq.)
1990 r~^
0
0
0
0
0
0
0
0
1
,7 ^"^
.1 i- ;
.1 r~ •
if
.3
i i
+ j I
.1 j I
r~~ 1
.4 *
+ s •
-
— — — i
•1
_1_ t_ 1
^k f
.2 ;~ *
f
.1 r a
1995
0
0
0
0
0
0
.7
.1
.1
+
.3
+
.2
+
.4
4.
+
+
0.1
0
1
+
.2
+
.0
1996
0
0
0
0
0
.7
.1
.1
+
.3
+
.2
+
0.4
0
0
1
+
+
+
.1
+
.2
+
.2
1997
0
0
0
0
0
.8
.1
.1
+
.3
+
.2
+
0.4
0
0
1
4.
+
+
.1
+
.3
+
.2
1998
0.8
0.1
0.1
+
0.3
+
0.2
+
0.5
4-
+
+
0.1
+
0.3
+
1.2
I
1999
0.8
0.1
: 0.1
+
0.3
r +
0.2
+
0.4
4.
+
+
' 0.1
+
0.3
+
1.2
2000
0.8
0.1
0.1
+
0.4
+
0.2
+
0.5
4-
4-
+
0.1
+
0.3
+
1.2
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
10 The fraction of rice straw burned each year is significantly higher than that for other crops (see "Data Sources" discussion below).
" Note: As is explained below, the fraction of residues burned varies among states for rice, so these equations were applied at the state level for rice.
These equations were applied at the national level for all other crop types.
12 Burning Efficiency is defined as the fraction of dry biomass exposed to burning that actually burns. Combustion Efficie'ncy is defined as the
fraction of carbon in the fire that is oxidized completely to CO2. In the methodology recommended by the IPCC, the "burning efficiency" is assumed
to be contained in the "fraction of residues burned" factor. However, the number used here to estimate the "fraction of residues burned" does not
account for the fraction of exposed residue that does not burn. Therefore, a "burning efficiency factor" was added to the calculations.
5-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 5-16: Emissions from Agricultural Residue Burning (Gg)"
Gas/Crop Type
tcH4
[- Wheat
I Rice
|; Sugarcane
* Corn
t Barley
Soybeans
t: Peanuts
f N20
f Wheat
'__ Rice
jj. Sugarcane
t. Corn
f~ Barley
r Soybeans
T Peanuts
No
1; Wheat
C Rice
f"" Sugarcane
c- Corn
j~ Barley
t Soybeans
f Peanuts
f NOX
F Wheat
[ Rice
£:L Sugarcane
I Corn
^ Barley
r Soybeans
L Peanuts
,r * Full molecular weight basis.
'-•-+ Does not exceed 0.5 Gg
F- Note: Totals may not sum due to
r
1990 Sjf-"
•" ' •• 33
7
4
1
13
1"
7
+
1
i ^™Zi,sl
+
+
+
+ '"
1
+
685
j A-™ lUlisSSnS
. 137 _
81
18
282
16
j^-lCgfrrf
BtaEffiagES
28
4
3
+
7
1""
14
+
independent rounding.
1995
31
5
4
1
13
1
8
+
1
i
+
+
+
+
1
+
656
109
80
20
263
13
167
2
29
3
3
+
6
+
16
+. .
..... " "~ „"."., "" .'
1996
36
5
4
1
16
1
9
+
1
i
+
+
+
+
' 1
+
747
114
85
19
328
15
183
2
32
3
"3
+
8
+
17
+
1997
36
6"
3
1
16
1
10
+
1
i
. _ +
+
+
+
1
+
761
124
66
21
328
13
207
2
34
3
2
+
8
+
20
+
1998
37
6
3
1
17
1
10.
+
1
j
+
+
+
+
1
+
781
128
58
22
347
13
211
2
35
3
2
+
8
+
20
+
1999
36
5
3
1
16
+
10
+
i
i,
+
+
+
+
1
+
760
115
69
23
336
10
204
2
34
3
2
+
8
+
19
+
2000
37
5 '.
3
1
17 ;
1
10
+ <•
1
, i
+ :
+ '-:
+
+
1
+ -.
786
111 ':
69 "
24
355
12 '.
213 ',
2 =;
35
3
2 *
+ •
9
+ "
20
+ :
;
'•'- ' i
Emissions of CH4 and CO were calculated by
multiplying the amount of carbon released by the appropriate
IPCC default emission ratio (i.e., CH4-C/C or CO-C/C).
Similarly, N2O and NOx emissions were calculated by
multiplying the amount of nitrogen released by the
appropriate IPCC default emission ratio (i.e., N2O-N/N or
NOX-N/N).
Data Sources
The crop residues that are burned in the United States
were determined from various state level greenhouse gas
emission inventories (ILENR1993, Oregon Department of
Energy 1995, Wisconsin Department of Natural Resources
1993) and publications on agricultural burning in the United
States (Jenkins et al. 1992, Turn et al. 1997, EPA 1992).
Crop production data for all crops except rice in Florida
were taken from the USDA's Field Crops, Final Estimates
1987-1992, 1992-1997 (USDA 1994, 1998), Crop
Production 1999 Summary (USDA 2000), and Crop
Production 2000 Summary (USDA2001). Crop production
data for Florida, which are not collected by USDA, were
estimated by applying average primary and ratoon crop
yields for Florida (Smith 2001) to Florida acreages
(Schueneman 1999b, 2001). The production data for the
crop types whose residues are burned are presented in
Table 5-17.
The percentage of crop residue burned was assumed to
be 3 percent for all crops in all years, except rice, based on
state inventory data (ILENR 1993, Oregon Department of
Agriculture 5-21
-------
Table 5-17: Agricultural Crop Production (Thousand Metric Tons of Product)
Crop 1990
Wheat 74,292
Rice 7,105
Sugarcane 25,525
Corn* 201,534
Barley 9,192
Soybeans 52,41 6
Peanuts 1,635
*Corn for grain (i.e., excludes corn for silage).
E ''
I *
h*
tar
I 1
S- - l£
* I
1995
59,404
7,935
27,922
187,970
7,824
59,174
1,570
1996
61,980
7,828
26,729
234,518
8,544
64,780
1,661
1997
67,534
8,339
28,766
233,864
7,835
73,176
1,605
1998
69,327
8,570
30,896
247,882
7,667
74,598
1,798
1999
62,569
9,381
32,023
239,549
6,103
72,223
1,737
2000
60,512
8,708
32,973
253,208
6,921
75,338
1,491
Table 5-18: Percentage of Rice Area Burned by State
State
Arkansas
California
Florida1"
Louisiana
Mississippi
Missouri
Texas
Percent Burned
1990-1998
10
variable3
0
6
10
5
1
Percent Burned
1999
10
27
0
0
40
5
2
Percent Burned
2000
10
27
0
5
40
8
0
"Values provided in Table 5-19.
"Burning of crop residues is illegal in Florida. ;
Table 5-19: Percentage of Rice Area Burned in
California
mtni
Year
1990
I , .l.ii. :..' ,.
1995
1996
1997
1998
1999
2000
California
75
' " 'LjJl*'1'1 iLiiJiij«ii"iJ
59
63
34
33
27
27
Energy 1995, Noller 1996, Wisconsin Department of Natural
Resources 1993, and Cibrowski 1996). Estimates of the
percentage of rice acreage on which residue burning took
place were obtained on a state-by-state basis from
agricultural extension agents in each of the seven rice-
producing states (Bollich 2000; Guethle 1999,2000,2001;
Fife 1999; California Air Resources Board 1999;
Klosterboer 1999a, 1999b, 2000,2001; Linscombe 1999a,
1999b, 2001; Najita 2000,2001; Schueneman 1999a, 1999b,
2001; Slaton 1999a, 1999b, 2000; Street 1999a, 1999b,
2000,2001; Wilson 2001) (see Table 5-18 and Table 5-19).
The estimates provided for Arkansas and Florida remained
constant over the entire 1990 through 2QOO period, while
the estimates for all other states varied over the time series.
For California, it was assumed that the annual percents of
rice acreage burned in Sacramento Valley are representative
of burning in the entire state, because the Sacramento Valley
accounts for over 95 percent of the rice acreage in California
(Fife 1999). The annual percents of rice acreage burned in
Sacramento Valley were obtained from a report of the
California Air Resources Board (2001). These values
declined over the 1990 through 2000 period because of a
legislated reduction in rice straw burning ;(see Table 5-19).
All residue/crop product mass ratios except sugarcane
were obtained from Strehler and Stiitzle (1987). The datum
for sugarcane is from University of California (1977).
Residue dry matter contents for all crops, except soybeans
and peanuts were obtained from Turn et aL (1997). Soybean
dry matter content was obtained from Strehler and Stiitzle
(1987). Peanut dry matter content was obtained through
personal communications with Jen Ketzis (1999), who
accessed Cornell University's Department of Animal
Science's computer model, Cornell Net Carbolrydrate and
5-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Protein System. The residue carbon contents and nitrogen
contents for all crops except soybeans and peanuts are from
Turn et al. (1997). The residue carbon content for soybeans
and peanuts is the IPCC default (IPCC/UNEP/OECD/IEA
1997). The nitrogen content of soybeans is from Barnard
and Kristoferson (1985). The nitrogen content of peanuts
is from Ketzis (1999). These data are listed in Table 5-20.
The burning efficiency was assumed to be 93 percent, and
the combustion efficiency was assumed to be 88 percent,
for all crop types (EPA 1994). Emission ratios for all gases
(see Table 5-21) were taken from the Revised 1996 IPCC
Guidelines (IPCC/UNEP/OECD/IEA 1997).
Uncertainty
The largest source of uncertainty in the calculation of
non-CO2 emissions from field burning of agricultural
residues is in the estimates of the fraction of residue of each
crop type burned each year. Data on the fraction burned, as
well as the gross amount of residue burned each year, are
not collected at either the national or State level. In addition,
burning practices are highly variable among crops, as well
as among States. The fractions of residue burned used in
these calculations were based upon information collected
by State agencies and in published literature. It is likely
that these emission estimates will continue to change as more
information becomes available in the future.
Other sources of uncertainty include the residue/crop
product mass ratios, residue dry matter contents, burning
and combustion efficiencies, and emission ratios. Aresidue/
crop product ratio for a specific crop can vary among
cultivars, and for all crops except sugarcane, generic residue/
crop product ratios, rather than ratios specific to the United
States, have been used. Residue dry matter contents, burning
and combustion efficiencies, and emission ratios, all can
vary due to weather and other combustion conditions, such
as fuel geometry. Values for these variables were taken from
literature on agricultural biomass burning.
Table 5-20: Key Assumptions for Estimating Emissions from Agricultural Residue Burning4
[ Crop
I Wheat
i Rice
I- Sugarcane
f Corn
j: . Barley
^Soybeans
L, Peanuts
\ * The burning
.,_, Residue/
Crop Ratio
U
1.4
0.8
1.0
1.2
2.1
1.0
Fraction of
Residue Burned
0.03 ~"
variable
0.03
0.03
0.03
0.03
0.03
efficiency and combustion efficiency for all crops were assumed to be 0
Dry Matter
Fraction
0.93
0.91
0.62
0.91
0.93
0.87
0.86
.93 and 0.88, respectively.
Carbon
Fraction
"0.4428
0.3806
0.4235
0.4478
0.4485
0.4500
0.4500
Nitrogen
Fraction
0.0062
0.0072
0.0040
0.0058
0.0077
0.0230
0.0106
Table 5-21: Greenhouse Gas Emission Ratios
Gas
Emission Ratio
C0a
N20b
i\IOxb
0.005
0.060
0.007
0.121
a Mass of carbon compound released (units of C) relative to mass of
total carbon released from burning (units of C).
b Mass of nitrogen compound released (units of N) relative to mass of
total nitrogen released from burning (units of N).
Agriculture 5-23
-------
5-24 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
6. Land-Use Change and Forestry
chapter provides an assessment of the net carbon dioxide (CO2) flux1 caused by 1) changes in forest carbon
stocks, 2) changes in carbon stocks in urban trees, 3) changes in agricultural soil carbon stocks, and 4) changes
in carbon stocks in landfilled yard trimmings. Seven components of forest carbon stocks are analyzed: trees, understory
vegetation, forest floor, down dead wood, soils, wood products in use, and landfilled wood products. The estimated CO2
flux from each of these forest components was derived from U.S. forest inventory data, using methodologies that are
consistent with the Revised 1996IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). Changes in carbon stocks in urban
trees were estimated based on field measurements in ten U.S. cities and data on national urban tree cover, using a
methodology consistent with the Revised 1996 IPCC Guidelines. Changes in agricultural soil carbon stocks include mineral
and organic soil carbon stock changes due to use and management of cropland and grazing land, and emissions of CO2 due
to the application of crushed limestone and dolomite to agricultural soils (i.e., soil liming). The methods in the Revised
1996 IPCC Guidelines were used to estimate all three components of changes in agricultural soil carbon stocks. Changes
in yard trimming carbon stocks in landfills were estimated using analysis of life-cycle greenhouse gas emissions and sinks
associated with solid waste management (EPA 1998). Note that the chapter title "Land-Use Change and Forestry" has
been used here to maintain consistency with the IPCC reporting structure for national greenhouse gas inventories; however,
the chapter covers land-use activities, in addition to land-use change and forestry activities. Therefore, except in table
titles, the term "land use, land-use change, and forestry" will be used in the remainder of this chapter.
Unlike the assessments in other chapters, which are based on annual activity data, the flux estimates in this chapter,
with the exception of those from wood products, urban trees, and liming, are based on periodic activity data in the form of
forest, land-use, and municipal solid waste surveys. Carbon dioxide fluxes from forest carbon stocks (except the wood
product components) and from agricultural soils (except the liming component) are calculated on an average annual basis
over five or ten year periods. The resulting annual averages are applied to years between surveys. As a result of this data
structure, estimated CO2 fluxes from forest carbon stocks (except the wood product components) and from agricultural
soils (except the liming component) are constant over multi-year intervals, with large discontinuities between intervals.
For the landfilled yard trimmings, periodic solid waste survey data were interpolated so that annual storage estimates
could be derived. In addition, because the most recent national forest, land-use, and municipal solid waste surveys were
completed for the year 1997, the estimates of CO2 flux from forests, agricultural soils, and landfilled yard trimmings are
based in part on modeled projections. Carbon dioxide fluxes from urban trees are based on neither annual data nor
periodic survey data, but instead is data collected over the decade 1990 through 2000. Therefore, this flux has been
applied to the entire time series.
'The term "flux" is used here to encompass both emissions of greenhouse gases to the atmosphere, and removal of carbon from the atmosphere
Removal of carbon from the atmosphere is also referred to as "carbon sequestration."
Land-Use Change and Forestry 6-1
-------
Table 6-1: Net C02 Flux from Land-Use Change and Forestry (Tg C02 Eq.)
Forests
Urban Trees
Agricultural Soils
Landfilled Yard Trimmings
Tola!
1990
(982.7)
(58.7)
(37.3)
(19.1)
(1,097.7)
=
I
r
PI
I
?
5
1995
(979.0)
(58.7)
(60.2)
(12.2)
(1,110.0)
1996
(58.7)
(60.2)
(10.2)
Hiiffyl
1997
. .7P
^(60.4)
DCS)
"1887.5)
1998
— L58J)
"TST^r
(8.3)
Pgj|
1999
(58.7)
(BHf :'
(7:3)
(896.4)
2000
(58.7)
;:[67jy,
(6.4):
P_g)
Note: Parentheses indicate net sequestration. Totals may not sum due to independent rounding. Lightly shaded areas indicate values based on a
combination of historical data and projections. All other values are based on historical data only.
Table 6-2: Net CO, Flux from Land-Use Change and Forestry (Tg C)
Sink Category
1990
1995
1996 1997
1998
1999 2000
Forests
Urban Trees
Agricultural Soils
Landfilled Yard Trimmings
(268)
(16)
(10)
(5)
(267)
(16)
(16)
(3)
,
(16) ~
Total
(299)
(303)
302
246)
Note-1 Tg C = 1 teragram carbon = 1 million metric tons carbon. Parentheses indicate net sequestration. Totals may not sum due to independent rounding.
Lightly shaded areas indicate values based on a combination of historical data and projections. All other values are based on historical data only.
Land use, land-use change, and forestry activities in
2000 resulted in a net sequestration of 903 Tg CO2 Eq. (246
Tg C) (Table 6-1 and Table 6-2). This represents an offset
of approximately 15 percent of total U.S. CO2 emissions.
Total land use, land-use change, and forestry net
sequestration declined by about 18 percent between 1990
and 2000. This decline was primarily due to a decline in the
rate of net carbon accumulation in forest carbon stocks.
Annual carbon accumulation in landfilled yard trimmings
also slowed over this period, while annual carbon
accumulation in agricultural soils increased. As described
above, the constant rate of carbon accumulation in urban
trees is a reflection of limited underlying data (i.e., this rate
represents an average for the decade).
Changes in Forest Carbon Stocks
Carbon in forests can be described as the total of several
interrelated carbon storage pools, including:
• Trees (i.e., living trees and standing dead trees,
including the roots, stems, branches, and foliage);
• Understory vegetation (i.e., shrubs and bushes,
including the roots, stems, branches, and foliage);
• Forest floor (i.e., fine woody debris, tree litter, and
humus); •
• Down dead wood (i.e., logging residue and other coarse
dead wood on the ground, and stumps and roots of
stumps); and :
• Soil (i.e., organic material in soil). j
As a result of biological processes in' forests (e.g.,
growth and mortality) and anthropogenic activities (e.g.,
harvesting, thinning, clearing, and replanting), carbon is
continuously cycled through and among these storage pools,
as well as between the forest ecosystem and the atmosphere.
For example, as trees grow, carbon is removed from the
atmosphere and stored in living tree biomass. As trees age,
they continue to accumulate carbon until they reach maturity,
at which point carbon storage slows. As;trees die and
otherwise deposit litter and debris on the forest floor, decay
processes release carbon to the atmosphere and also increase
soil carbon stocks.
6-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
The net change in forest carbon, however, may not be
equivalent to the net flux between forests and the atmosphere
because timber harvests may not always result in an
immediate flux of carbon to the atmosphere. Harvesting in
effect transfers carbon from one of the "forest pools" to a
"product pool." Once in a product pool, the carbon is
emitted over time as CO2 if the wood product combusts or
decays. The rate of emission varies considerably among
different product pools. For example, if timber is harvested
for energy use, combustion results in an immediate release
of carbon. Conversely, if timber is harvested and
subsequently used as lumber in a house, it may be many
decades or even centuries before the lumber is allowed to
decay and carbon is released to the atmosphere. If wood
products are disposed of in landfills, the carbon contained
in the wood may be released years or decades later, or may
even be stored permanently in the landfill.
Figure 6-1
This section of the Land-Use Change and Forestry
chapter tracks net changes in carbon stocks in five forest
carbon pools and two harvested wood pools. The net change
in stocks for each pool is estimated, and then the changes in
stocks are summed over all pools to estimate total net flux.
An illustration of forest carbon storage pools, and flows
between them via emissions, sequestration, and transfers,
is presented in Figure 6-1. In this illustration, forest carbon
storage pools are represented by boxes, while flows between
storage pools, and between storage pools and the
atmosphere, are represented by arrows. Note that boxes are
not identical with storage pools identified in this chapter.
The storage pools identified in this chapter have been
arranged to better illustrate the processes that result in
transfers of carbon from one pool to another, and that result
in emissions to the atmosphere (adapted from Birdsey and
Lewis 2001).
Methane
Flaring \
and
tilization
Atmosphere
Growth
Live
Vegetation
Litterfall
Mortality
Woody Debris,
Litter, and
Logging Residue
Humification
Soil Organic
Material
Combustion
Source: Adapted from Birdsey and Lewis (2001)
Land-Use Change and Forestry 6-3
-------
Approximately 33 percent (747 million acres) of the U.S.
land area is forested (Smith et al. 2001). Between 1977 and
1987, forest land declined by approximately 5.9 million acres,
and between 1987 and 1997, the area increased by about 9.2
million acres. These changes in forest area represent average
annual fluctuations of only about 0.1 percent.
Given the low rate of change in U.S. forest land area,
the major influences on the recent net carbon flux from forest
land are management activities and the ongoing impacts of
previous land-use changes. These activities affect the net
flux of carbon by altering the amount of carbon stored in
forest ecosystems. For example, intensified management of
forests can increase both the rate of growth and the eventual
biomass density2 of the forest, thereby increasing the uptake
of carbon. Harvesting forests removes much of the
aboveground carbon, but trees can grow on this area again
and sequester carbon. The reversion of cropland to forest
land through natural regeneration also will, over decades,
result in increased carbon storage in biomass and soils. The
net effect of both forest management and land-use change
involving forests is captured in these estimates.
In the United States, improved forest management
practices, the regeneration of previously cleared forest areas,
and timber harvesting and use have resulted in an annual
net (i.e., net sequestration) of carbon during the period from
1990 through 2000. Due to improvements in U.S.
agricultural productivity, the rate of forest clearing for crop
cultivation and pasture slowed in the late 19th century, and
by 1920 this practice had all but ceased. As farming
expanded hi the Midwest and West, large areas of previously
cultivated land in the East were taken out of crop production,
primarily between 1920 and 1950, and were allowed to
revert to forests or were actively reforested. The impacts of
these land-use changes are still affecting carbon fluxes from
forests in the East. In addition to land-use changes in the
early part of this century, carbon fluxes from Eastern forests
have been affected by a trend toward managed growth on
private land. Collectively, these changes have produced a
near doubling of the biomass density in Eastern forests since
the early 1950s. More recently, the 1970s and 1980s saw a
resurgence of federally sponsored forest; management
programs (e.g., the Forestry Incentive Program) and soil
conservation programs (e.g., the Conservation Reserve
Program), which have focused on tree planting, improving
timber management activities, combating soil erosion, and
converting marginal cropland to forests. In addition to forest
regeneration and management, forest harvests have also
affected net carbon fluxes. Because most of the timber that
is harvested from U.S. forests is used in wood products and
much of the discarded wood products are disposed of by
landfilling, rather than incineration, significant quantities
of this harvested carbon are transferred to long-term storage
pools rather than being released to the atmosphere. The size
of these long-term carbon storage pools has ;also increased
over the last century. i
Changes in carbon stocks in U.S. forests and harvested
wood were estimated to account for an average annual net
sequestration of 899 Tg CO2 Eq. (245 Tg C) over the period
1990 through 2000 (see Table 6-3 and Table:6-4).3 The net
sequestration is a reflection of net forest growth and
increasing forest area over this period, particularly from
1987 to 1997, as well as net accumulation of carbon in
harvested wood pools. The rate of annual; sequestration,
however, declined by 22 percent between 1*990 and 2000.
This is due to a greater rate of forest area increase between
1987 and 1997 than between 1997 and 2001. Most of the
1
decline in annual sequestration occurred in the forest soil
carbon pool. This is a reflection of modeling assumptions
used in this analysis, specifically that soil carbon stocks for
each forest type are constant over time, rather than varying
by age, whereas biomass carbon stocks are a function of
forest type and age class. Therefore, as lands are converted
from non-forest to forest, there is a relatively large
immediate increase in soil carbon stocks compared to the
increase in biomass carbon stocks. The relatively large shifts
in annual net sequestration from 1996 to 1997 are the result
of calculating average annual forest fluxes!from periodic,
rather than annual, activity data. ;
2 The term "biomass density" refers to the weight of vegetation per unit area. It is usually measured on a dry-weight basis. Dry biomass is about 50
percent carbon by weight.
3 This average annual net sequestration is based on the entire time series (1990 through 2000), rather than the abbreviated time Series presented in
Table 6-3 and Table 6-4. Results for the entire time series are presented in Annex N (Methodology for Estimating Net Changes in Forest Carbon
Stocks).
6-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 6-3: Net C02 Flux from U.S. Forests (Tg C02 Eq.)
; Description
Forest Carbon Stocks
; Trees
I: Understory
Forest Floor
i Down Dead Wood
|. Forest Soils
Harvested Wood Carbon Stocks
i Wood Products
Landfilled Wood
< Total
1990
(773.7)
(469.3)
(11.0)
(25.7)
(55.0)
(212.7)
(209.0)
(47.7)
(161.3)
(982.7)
" " "
1995
^ „ (773.7)
St- ", (469.3)
jpr^ (11.0)
W I (25J)
!t (55.0)
El * (212.7)
* _ (205.3)
CT., (55.0)
(150.3)
„_ (979.0)
1996
(773.7)
(469.3)
(11.0)
(25.7)
(55.0)
(212.7)
(205.3)
(55.0)
(150.3)
(979.0)
1997
546.3)
£(4473)
£3147)"
f 293
*r(58 7)
ti(55.0)
?(212.7)
»
t (759.0)
1998
(546.3)
(4473)
(147)
293
" (587)
(55.0)
(205.3)
(51.3)
(154.0J
(751.7)
1999
(546.3)
(447.3)
(147)
293
(587)
(55.0)
(216.3)
(62.3)
(154.0)
(762.7)
2000
(546.3) '
(447.3)
(14.7) "
29.3
(58.7)
(55.0)
(223.7)
(66.0) ;
(157.7)
(770.0)
Note: Parentheses indicate net carbon "sequestration" (i.e., accumulation into the carbon pool minus emissions or stock removal from the carbon pool)
The sum of the net stock changes in this table (i.e., total) is an estimate of the actual net flux between the total forest carbon pool and the atmosphere
Lightly shaded areas indicate values based on a combination of historical data and projections. Forest values are based on periodic measurements-
harvested wood estimates are based on annual surveys. Totals may not sum due to independent rounding.
Table 6-4: Net C02 Flux from U.S. Forests (Tg C)
Description
1990
1995
1996 1997
~m
1998
1999
2000
Forest Carbon Stocks
Trees
Understory
Forest Floor
Down Dead Wood
Forest Soils
Harvested Wood Carbon Stocks
Wood Products
Landfilled Wood
(13)
(44)
(211)
(128)
(3)
(7)
(15)
(58)
(56)
(15)
(41)
(211)
(128)
(3) ! (4)
(7) r 8~
(15)
(58)
(56) ^ (58)
(15) f (16)
(41) jjjjgj
(149)
(1221
(4).
8
(16)
(IS)""
(56)
(14)
(421
(149) (149)
(122) (122)
....;.M:._j4i
,8 8
(16) (16)
^115)(15)
(59) (61)
- (17) (18)
^.J42) (43)
Total
(268)
(267) (267) ^(207) _ (205) (208) (210)
Note: 1 Tg C = 1 Tg carbon = 1 million metric tons carbon. Parentheses indicate net carbon "sequestration" (i.e., accumulation into the carbon pool
e minus emissions or harvest from the carbon pool). The sum of the net stock changes in this table (i.e., total) is an estimate of the actual net flux
L between the total forest carbon pool and the atmosphere. Lightly shaded areas indicate values based on a combination of historical data and
L projections. Forest values are based on periodic measurements; harvested wood estimates are based on annual surveys Totals may not sum due
to independent rounding.
Methodology
The approach to calculating changes in carbon stocks
in forests can genetically be described as sampling the forest
carbon at one time, sampling the forest carbon a second
time at a later date, and then subtracting the two estimates
for the net stock change. Historically, the main purpose of
the national forest inventory has been to estimate areas,
volume of growing stock, and timber products output and
utilization factors. Growing stock is simply a classification
of timber inventory that includes live trees of commercial
species meeting specified standards of quality (Smith et al.
2001). Timber products output refers to the production of
industrial roundwood products such as logs and other round
timber generated from harvesting trees, and the production
of bark and other residue at processing mills. Utilization
factors relate inventory volume to the volume cut or
destroyed when producing roundwood (May 1998). Growth,
harvests, land-use change, and other estimates of change
are derived from repeated surveys. The inventory data are
converted to carbon using conversion factors or a model
that estimates basic relationships between forest
characteristics and carbon pools like forest floor. Historical
carbon stock changes are derived from USDA Forest
Service, Forest Inventory & Analysis inventory data (Smith
et al. 2001, Prayer and Furnival 1999). Projected carbon
stock changes are derived from areas, volumes, growth,
Land-Use Change and Forestry 6-5
-------
land-use changes and other forest characteristics projected
in a system of models (see Haynes et al. 2001a) representing
the U.S. forest sector, including a model (FORCARB) that
estimates carbon for merchantable and non-merchantable
tree pools, and other forest carbon pools.
The USD A Forest Service, Forest Inventory & Analysis
(FIA) has conducted consistent scientifically designed forest
surveys of much of the forest land in the United States since
1952. Historically, these were conducted periodically, state-
by-state within a region. One state within a region would
be surveyed, and when finished, another state was surveyed.
Eventually (every 5-14 years, depending on the state), all
states within a region would be surveyed, and then states
would be resurveyed. FIA has adopted a new annualized
design, so that a portion of each state will be surveyed each
year (Gillespie 1999); however, data are not yet available
for all states. The annualized survey also includes a plan to
measure attributes that are needed to estimate carbon in
various pools, such as soil carbon and forest floor carbon.
Characteristics that are measured and readily available from
some surveys include individual tree diameter and species,
and forest type and age of the plot. For more information
about forest inventory data and carbon flux, see Birdsey
and Heath (2001).
The USDA Forest Service periodically compiles and
reports survey data for a specific base year. Available years
relevant to CO, flux estimates are 1987 and 1997. Live tree
carbon and dead tree carbon are estimated from the inventory
data using the conversion factors by forest type and region
in Smith et al. (in review). Understory carbon is estimated
from forest inventory data and equations based on estimates
in Birdsey (1992). Forest floor carbon is estimated from
the forest inventory data using the equations listed in Smith
and Heath (in review). Projections produce estimates of
areas and volumes; carbon estimates are produced using
this information using procedures similar to those used to
produce carbon estimates from forest inventory data. For a
detailed description of the modeling system, see Annex N.
In the past, FIA surveyed all productive forest land,
which is called timberland, and some reserved forest land
and some other forest land.4 With the introduction of the
annualized design (Gillespie 1999), all forest lands will
feature the same type of information. Forest carbon stocks
on non-timberland forests were estimated based on average
carbon estimates derived from representative timberlands.
Reserved forests were assumed to contain the same average
carbon densities as timberlands of the same forest type,
region, and owner group. These averages were multiplied
by the areas in the forest statistics, and then aggregated for
a national total. Average carbon stocks were derived for
other forest land by using average carbon stocks for
timberlands, which were multiplied by,50 percent to
simulate the effects of lower productivity. ;
Estimates of carbon stock changes in wood products
and wood discarded in landfills are based on the methods
described in Skog and Nicholson (1998). The disposition of
harvested wood carbon removed from the forest can be
described in four general pools: products in use, discarded
wood in landfills, emissions from wood burned for energy,
! and emissions from decaying wood or wood jburned in which
energy was not captured. The net carbon stock changes
presented here represent the amounts of carbon that are
stored (i.e., not released to the atmosphere). Annual historical
estimates and projections of detailed production were used
to divide consumed roundwood into product, wood mill
residue, and pulp mill residue. The carbon decay rates for
products and landfills were estimated, and applied to the
respective pools. The results were aggreg4ted for national
estimates. The production approach to accounting for imports
and exports was used. Thus, carbon in exported wood is
included using the same disposal rates as in the United States,
while carbon in imported wood is not included. Over the
period 1990 to 2000, carbon in exported wood accounted
for an average of 22 Tg CO2 Eq. storage pet year, with little
variation from year to year. For comparison, imports—which
are not included in the harvested wood net flux estimates—
increased from 26 Tg CO2 Eq. per year in 1990 to 46 Tg
CO2 Eq. per year in 2000. !
4 Forest land in the United States includes all land that is at least 10 percent stocked with trees of any size. Timberland is the mo;jt productive type of
forest land, growing at a rate of 20 cubic feet per acre per year or more. In 1997, there were about 503 million acres of timberlands, which represented
67 percent of all forest lands (Smith and Sheffield 2000). Forest land classified as timberland is unreserved forest land that is producing or is capable
Of producing crops of industrial wood. The remaining 33 percent of forest land is classified as reserved forest land, which is forest land withdrawn
from timber use by statute or regulation, or other forest land, which includes forests on which timber is growing at a rate less tbjan 20 cubic feet per
acre per year. :
6-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
The methodology described above is consistent with
the Revised 1996IPCC Guidelines (IPCC/UNEP/OECD/
IEA 1997). The IPCC identifies two approaches to
developing estimates of net carbon flux from Land-Use
Change and Forestry: 1) using average annual statistics on
land use, land-use change, and forest management activities,
and applying carbon density and flux rate data to these
activity estimates to derive total flux values; or 2) using
carbon stock estimates derived from periodic inventories
of forest stocks, and measuring net changes in carbon stocks
over time. The latter approach was employed because the
United States conducts periodic surveys of national forest
stocks. In addition, the IPCC identifies two approaches to
accounting for carbon emissions from harvested wood: 1)
assuming that all of the harvested wood replaces wood
products that decay in the inventory year so that the amount
of carbon in annual harvests equals annual emissions from
harvests; or 2) accounting for the variable rate of decay of
harvested wood according to its disposition (e.g., product
pool, landfill, combustion). The latter approach was applied
for this Inventory using estimates of carbon stored in wood
products and landfilled wood.5 The use of direct
measurements from forest surveys and associated estimates
of product and landfilled wood pools is likely to result in
more accurate flux estimates than the alternative IPCC
methodology.
Data Sources
The estimates of forest carbon stocks used to calculate
forest carbon fluxes are based largely on areas, volumes,
growth, harvests, and utilization factors derived from the
forest inventory data collected by the USDA Forest Service.
Compilations of these data for 1987 and 1997 are given in
Waddell et al. (1989) and Smith et al. (2001), respectively,
with trends discussed in the latter citation. The timber
volume data used here include timber volumes on forest
land classified as timberland, as well as on some reserved
forest land and other forest land. Timber volumes on forest
land in Alaska, Hawaii, and the U.S. territories are not
sufficiently detailed to be used here. Also, timber volumes
on non-forest land (e.g., urban trees, rangeland) are not
included. The timber volume data include estimates by tree
species, size class, and other categories. The forest inventory
data are augmented or converted to carbon following the
methods described in the methodology section. The carbon
storage factors applied to these data are described in Annex
N. Soil carbon estimates are based on data from the
STATSGO database (USDA 1991). Carbon stocks in wood
products in use and wood stored in landfills are based on
historical data from the USDA Forest Service (USDA 1964,
Ulrich 1989, Howard 2001), and historical data as
implemented in the framework underlying the NAPAP (Ince
1994) and TAMM/ATLAS (Haynes et al. 2001a, MiUs and
Kincaid 1992) models. The carbon conversion factors and
decay rates for harvested carbon removed from the forest
are taken from Skog and Nicholson (1998).
Table 6-5 presents the carbon stock estimates for forest
and harvested wood storage pools. Together, the tree and
forest soil pools account for over 80 percent of total carbon
stocks. Carbon stocks in all pools, except forest floor,
increased over time, indicating that, during these periods,
all storage pools except forest floor accumulated carbon
(e.g., carbon sequestration by trees was greater than carbon
removed from the tree pool through respiration, decay,
litterfall, and harvest). Figure 6-2 shows 1997 carbon stocks
by the regions that were used in the forest carbon analysis.
Uncertainty
There are sampling and measurement errors associated
with the forest survey data that underlie the forest carbon
estimates. These surveys are based on a statistical sample
designed to represent the wide variety of growth conditions
present over large territories. Although newer inventories
are being conducted annually in every state, much of the
data currently used may have been collected over more than
one year in a state, and data associated with a particular
year may have been collected over several earlier years.
Thus, there is uncertainty in the year associated with the
forest inventory data. In addition, the forest survey data that
are currently available exclude timber stocks on most forest
land in Alaska, Hawaii, U.S. territories. The assumptions
that were used to calculate carbon stocks in reserved forests
and other forests in the coterminous United States also
contribute to the uncertainty. Although the potential for
uncertainty is large, the sample design for the forest surveys
contributes to limiting the error in carbon flux. Re-measured
Again, the product estimates in this study do not account for carbon stored in imported wood products. However, they do include carbon stored in
exports, even if the logs are processed in other countries (Heath et al. 1996).
Land-Use Change and Forestry 6-7
-------
Table 6-5: U.S. Forest Carbon Stock Estimates (Tg C)
Description
Forests
Trees
Understory
Forest Roor
Down Dead Wood
Forest Soils
Harvested Wood
Wood Products
Landfilled Wood
Total
1987
47,594
15,168
448
4,240
o n^ft
25,681
1,920
1,185
735
49,514
1997
49,694
16,449
473
4,306
2205
26,262
2,479
1,319
1,159
52,173
fjae.
*
per-" " '
gniij,iniMirmimn -p- -rim
ipt
«~ -
Jr *T
s»_
|—
F
2001
50,291
16,937
489
--4,274
2,269 '
26,322
2,712
1,384
1,328_
'53,003
Note1 rorestcarDonsiocKs ao nounciuae miesisiuuns m ™uBi\a, na»»an, m u.u. U.IMIUIK.O, »• w^ u....«..,-.—* — ^~-v, —,,
product stocks include exports, even if the logs are processed in other countries, and exclude imports. Lightly shaded areas indicate yalues based on
a combination of historical data and projections. All other estimates are based on historical data only. Totals may not sum due to independent
rounding. Note thatthe stock is listed for 2001 because stocks are defined as of January 1 of the listed year.
Figure 6-2
PACIFIC
NORTHWEST
PLWNS NORTH NORTHEAST
PLAINS> CENTRAL
PAPIPIf*
SOUTHWEST ROCRY
MTS.
SOUTH
SOUTHEAST
ALASKA
9,018
8,340 H 8,398
6,603
Region
This graphic shows total forest carbon stocks in 1997, by region.
Harvested wood carbon stocks are not included.
permanent plot estimates are correlated, and greater
correlation leads to decreased uncertainties in change
estimates. For example, in a study on the uncertainty of the
forest carbon budget of private timberlands of the United
States, Smith and Heath (2000) estimated that the uncertainty
of the flux increased about 3.5 times when the correlation
coefficient dropped from 0.95 to 0.5.
Additional sources of uncertainty come
-------
changes in soil carbon may sum to large differences over
large areas. This analysis assumes that soil carbon density
for each forest type stays constant over time. In the future,
land-use effects will be incorporated into the soil carbon
density estimates.
Recent studies have looked at quantifying the amount
of uncertainty in national-level carbon budgets based on
the methods adopted here. Smith and Heath (2000) and
Heath and Smith (2000a) report on an uncertainty analysis
they conducted on carbon sequestration in private
timberlands. These studies are not strictly comparable to
the estimates in this chapter because they used an older
version of the FORCARB model, which was based on older
data and produced decadal estimates. However, the
magnitudes of the uncertainties should be instructive. Their
results indicate that the carbon flux of private timberlands,
not including harvested wood, was approximately the
average carbon flux (271 Tg CO2 Eq. per year) ±15 percent
at the 80 percent confidence level for the period 1990
through 1999. The flux estimate included the tree, soil,
understory vegetation, and forest floor components only.
The uncertainty in the carbon inventory of private
timberlands for 2000 was approximately 5 percent at the
80 percent confidence level. These estimates did not include
all uncertainties, such as the ones associated with public
timberlands, and reserved and other forest land, but they
did include many of the types of uncertainties listed
previously. It is expected that the uncertainty should be
greater for all forest lands.
Changes in Carbon Stocks
in Urban Trees
Urban forests constitute a significant portion of the total
U.S. tree canopy cover (Dwyer et al. 2000). It was estimated
that urban areas (cities, towns, and villages), which cover
3.5 percent of the continental United States, contained about
3.8 billion trees. With an average tree canopy cover of 27.1
percent, urban areas accounted for approximately 2.8
percent of total tree cover in the continental United States.
Trees in urban areas of the continental United States
were estimated by Nowak and Crane (2001) to account for
an average annual net sequestration of 59 Tg CO2 Eq. (16
Tg C). This estimate is representative of the period from
1990 through 2000, as it is based on data collected during
that decade. Annual estimates of CO2 flux have not been
developed (see Table 6-6).
Methodology
The methodology used by Nowak and Crane (2001) is
based on average annual estimates of urban tree growth and
decomposition, which were derived from field
measurements and data from the scientific literature, urban
area estimates from U.S. Census data, and urban tree cover
estimates from remote sensing data. This approach is
consistent with, but more robust than, the default IPCC
methodology in the Revised 1996 IPCC Guidelines (IPCC/
UNEP/OECD/IEA 1997).6
Nowak and Crane (2001) developed estimates of annual
gross carbon sequestration from tree growth and annual
gross carbon emissions from decomposition for ten U.S.
cities: Atlanta, GA; Baltimore, MD; Boston, MA; Chicago,
IL; Jersey City, NJ; New York, NY; Oakland, CA;
Philadelphia, PA, Sacramento, CA; and Syracuse, NY. The
gross carbon sequestration estimates were derived from field
data that were collected in these ten cities during the period
from 1990 through 2000, including tree measurements of
stem diameter, tree height, crown height, and crown width,
and information on location, species, and canopy condition.
The field data were converted to annual gross carbon
sequestration rates for each species (or genus), diameter
Table 6-6: Net C02 Flux From Urban Trees (Tg C02 Eq.)
^ Year TgC02Eq.
1990
1996
1997
1998
1999
2000
(58.7)
(58.7)
(58.7)
(58.7)
(58.7)
"Note: Parentheses indicate net sequestration.
6 It is more robust in that both growth and decomposition are accounted for, and data from individual trees are scaled up to state and then national
estimates based on data on urban area and urban tree canopy cover.
Land-Use Change and Forestry 6-9
-------
Table 6-7: Carbon Storage (Metric Tons C), Carbon Sequestration (Metric Tons C/yr),
and Tree Cover (%) for Ten U.S. Cities
City
New York, NY
Atlanta, 6A
Sacramento, CA
Chicago, IL
Baltimore, MD
Philadelphia, PA
Boston, MA
Syracuse, NY
Oakland, CA
Jersey City, NJ
NA (Not Available)
Carbon Storage
1,225,200
1,220,200
1,107,300
854,800
528,700
481,000
289,800
148,300
145,800
19,300
Gross
Sequestration
38,400
42,100
20,200
40,100
14,800
14,600
9,500
4,700
NA
800
Net
Sequestration
20,800
32,200
NA
NA
10,800
10,700
6,900
3,500
NA
600
Tree Cover
20.9%
36.7%
13.0%
11.0%
25.2%
15.7%
22.3%
24.4%
21.0%
11.5%
class, and land-use condition (forested, park-like, and open
growth) by applying allometric equations, a root-to-shoot
ratio, moisture contents, a carbon content of 50 percent (dry
weight basis), an adjustment factor to account for smaller
abovegroundbiomass volumes (given a particular diameter)
in urban conditions compared to forests, an adjustment
factor to account for tree condition (fair to excellent, poor,
critical, dying, or dead), and annual diameter and height
growth rates. The annual gross carbon sequestration rates
for each species (or genus), diameter class, and land-use
condition were then scaled up to city estimates using tree
population information (see Table 6-7).
The annual gross carbon emission estimates were
derived by applying to carbon stock estimates, which were
derived as an intermediate step in the gross sequestration
calculations, estimates of annual mortality by tree diameter
and condition class, assumptions about whether dead trees
would be removed from the site—since removed trees were
assumed to decay faster than those left on the site—and
assumed decomposition rates for dead trees left standing
and dead trees that are removed. The annual gross carbon
emission rates for each species (or genus), diameter class,
and condition class were then scaled up to city estimates
using tree population information.
Annual net carbon sequestration estimates were derived
for each of the ten cities by subtracting by the annual gross
emission estimates from the annual gross sequestration
estimates (see Table 6-7).
National annual net carbon sequestration by urban trees
was estimated from the city estimates of1 gross and net
sequestration, and urban area and urban tree cover data for
the contiguous United States. Note that the urban areas are
based on U.S. Census data, which define "urban" as having
a population greater than 2,500. Therefore, urban
encompasses most cities, towns, and villages i(i.e., it includes
both urban and suburban areas). The gross and net carbon
i
sequestration values for each city were divided by each city's
area of tree cover to determine the average annual
sequestration rates per unit of tree area for each city (see
Table 6-8). The median value for gross sequestration (0.30
kg C/m2-year) was then multiplied by an estimate of national
urban tree cover area (76,151 km2) to estimate national
annual gross sequestration. To estimate national annual net
sequestration, the estimate of national i annual gross
sequestration was multiplied by the averageiof the ratios of
net to gross sequestration for those cities! that had both
estimates (0.70).
Table 6-8: Annual Sequestration per Area of Tree
Cover (kg C/m2 cover-year)
• i ," i. -I'C-j
i- City Gross
| New York, NY 0.23
s,, Atlanta, SA 0.34
i Sacramento, CA 0.66
^Chicago, IL 0.61
r. Baltimore, Mb 0.28
^Philadelphia, PA 0.27
JE Boston, MA 0.30
s Syracuse, NY 0.30
si, Oakland, CA NA
| Jersey City, NJ 0.18
| NA (Not Available)
t- - ,-.- --
,i ^
0.12
0.26
NA
NA
" " 0:20 ;:
0.20
0.22
0.22
NA
0.1.3
6-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Data Sources
The field data from the 10 cities, some of which are
unpublished, are described in Nowak and Crane (2001) and
references cited therein. The allometric equations were taken
from the scientific literature (see Nowak 1994, Nowak et
al. in press), and the adjustments to account for smaller
volumes in urban conditions were based on information in
Nowak (1994). A root-to-shoot ratio of 0.26 was taken from
Cairns et al. (1997), and species- or genus-specific moisture
contents were taken from various literature sources (see
Nowak 1994). Adjustment factors to account for tree
condition were based on expert judgement of the authors
(Nowak and Crane 2001). Tree growth rates were also taken
from existing literature. Average diameter growth was based
on the following sources: estimates for trees in forest stands
came from Smith and Shifley (1984); estimates for trees on
land uses with a park-like structure came from deVries
(1987); and estimates for more open-grown trees came from
Nowak (1994). Formulas from Fleming (1988) formed the
basis for average height growth calculations. Estimates of
annual mortality rates by diameter class and condition class
were derived from a study of street-tree mortality (Nowak
1986). Assumptions about whether dead trees would be
removed from the site and assumed decomposition rates
were based on percent crown dieback (Nowak and Crane
2001). Urban tree cover area estimates for each of the 10
cities and the contiguous United States were obtained from
Dwyer et al. (2000) and Nowak et al. (2001).
Changes in Agricultural
Soil Carbon Stocks
Uncertainty
The estimates are based on limited field data collected
in ten U.S. cities, and the uncertainty in these estimates
increases as they are scaled up to the national level. There
is also uncertainty associated with the biomass equations,
conversion factors, and decomposition assumptions used
to calculate carbon sequestration and emission estimates
(Nowak et al. in press), as well as with the tree cover area
estimates for urban areas, as these are based on interpretation
of Advanced Very High Resolution Radiometer (AVHRR)
data. In addition, these results do not include changes in
soil carbon stocks, and there may be some overlap between
the urban tree carbon estimates and the forest tree carbon
estimates. However, both the omission of urban soil carbon
flux, and the potential overlap with forest carbon, are
believed to be relatively minor (Nowak 2002).
The amount of organic carbon contained in soils
depends on the balance between inputs of organic material
(e.g., decayed plant matter, roots, and organic amendments
such as manure and crop residues) and loss of carbon
through decomposition. The quantity and quality of organic
matter inputs, and their rate of decomposition, are
determined by the combined interaction of climate, soil
properties, and land use. Agricultural practices such as
clearing, drainage, tillage, planting, grazing, crop residue
management, fertilization, and flooding, can modify both
organic matter inputs and decomposition, and thereby result
in a net flux of carbon to or from soils. In addition, the
application of carbonate minerals to soils through liming
operations results in emissions of CO2. The IPCC
methodology for estimation of net CO2 flux from agricultural
soils (IPCC/UNEP/OECD/IEA 1997) is divided into three
categories of land-use/land-management activities: 1)
agricultural land-use and land-management activities on
mineral soils; 2) agricultural land-use and land-management
activities on organic soils; and 3) liming of soils. Mineral
soils and organic soils are treated separately because each
responds differently to land-use practices.
Mineral soils contain comparatively low amounts of
organic matter, much of which is concentrated near the soil
surface. Typical well-drained mineral surface soils contain
from 1 to 6 percent organic matter (by weight); mineral
subsoils contain even lower amounts of organic matter (Brady
and Weil 1999). When mineral soils undergo conversion from
their native state to agricultural use, as much as half of the
soil organic carbon can be lost to the atmosphere. The rate
and ultimate magnitude of carbon loss will depend on native
vegetation, conversion method and subsequent management
practices, climate, and soil type. In the tropics, 40 to 60
percent of the carbon loss generally occurs within the first
10 years following conversion; after that, carbon stocks
continue to decline but at a much slower rate. In temperate
regions, carbon loss can continue for several decades.
Eventually, the soil will reach a new equilibrium that reflects
a balance between carbon accumulation from plant biomass
and carbon loss through oxidation. Any changes in land-use
or management practices that result in increased organic
inputs or decreased oxidation of organic matter (e.g.,
Land-Use Change and Forestry 6-11
-------
Table 6-9: Net C02 Flux From Agricultural Soils (Tg C02 En..)
Description
Mineral Soils
Organic Soils
Liming of Soils
2000
e Parentheses indicate net sequestratlor^ightry shaded areas indicate values based on a combination ot historical data and projections . Ai, other
values are based on historical data only.
improved crop rotations, cover crops, application of organic
amendments and manure, and reduction or elimination of
tillage) will result in a net accumulation of soil organic carbon
until a new equilibrium is achieved.
Organic soils, which are also referred to as histosols,
include all soils with more than 20 to 30 percent organic
matter by weight, depending on clay content (Brady and
Weil 1999). The organic matter layer of these soils is also
typically extremely deep. Organic soils form under water-
logged conditions, in which decomposition of plant residues
is retarded. When organic soils are cultivated, they are first
drained which, together with tilling or mixing of the soil,
aerates the soil, and thereby accelerates the rate of
decomposition and CO2 generation. Because of the depth
and richness of the organic layers, carbon loss from
cultivated organic soils can continue over long periods of
lime. When organic soils are disturbed, through cultivation
and/or drainage, the rate at which organic matter
decomposes, and therefore the rate at which CO2 emissions
are generated, is determined primarily by climate, the
composition (i.e., decomposability) of the organic matter,
and the specific land-use practices undertaken. The use of
organic soils for annual crops results in greater carbon loss
than conversion to pasture or forests, due to deeper drainage
and more intensive management practices (Armentano and
Verhoeven 1990, as cited in IPCC/UNEP/OECD/IEA1997).
Lime in the form of crushed limestone (CaCO3) and
dolomite (CaMg(CO3)2) is commonly added to agricultural
soils to ameliorate acidification. When these compounds come
in contact with acid soils, they degrade, thereby generating
CO . The rate of degradation is determined by soil conditions
and the type of mineral applied; it can take several years for
applied limestone and dolomite to degrade completely.
Of the three activities, use and management of mineral
soils was the most important component of total flux during
the 1990 through 2000 period (see Table 6-9). Carbon
sequestration in mineral soils in 2000 was estimated at about
100 Tg CO2 Eq. (27 Tg C), while emissions from organic
soils were estimated at 23 Tg CO2 Eq. (6 Tg C) and emissions
from liming were estimated at 9 Tg CO|2 Eq. (3 Tg C).
Together, the three activities accounted for net sequestration
of about 67 Tg CO2 Eq. (18 Tg C) in 2000] Total annual net
CO2 flux was negative (i.e., net sequestration) each year
over the 1990 to 2000 period. Between 1990 and 2000, total
net carbon sequestration in agricultural soils increased by
about 80 percent. The increase is largely due to additional
acreage of annual cropland converted to permanent pastures
and hay production, a reduction in the frequency of summer-
fallow use in semi-arid areas and some increase in the
adoption of conservation tillage (i.e., reduced and no-till)
practices. The relatively large shifts in annual net
sequestration from 1990 to 1995, and from 1997 to 1998 are
the result of calculating average annual mineral and organic
soil fluxes from periodic, rather than annual, activity data.
The results for mineral and organic soil^ are displayed by
region in Figure 6-3, Figure 6-4, Figure 6J5, and Figure 6-6.
The flux estimates presented here are restricted to CO2
fluxes associated with the use and:management of
agricultural soils. Agricultural soils aj-e also important
sources of other greenhouse gases, particularly nitrous oxide
(N2O) from application of fertilizers, manure, and crop
residues and from cultivation of legumes,!as well as methane
(CH4) from flooded rice cultivation. Tljese emissions are
accounted for in the Agriculture chapter.7' It should be noted
that other land-use and land-use change: activities result in
fluxes of non-CO2 greenhouse gases to and from soils that
Citrous oxide emissions from agricultural soils and methane emissions from rice fields are addressed under the Agricultural Soil Management and
Rice Cultivation sections, respectively, of the Agriculture chapter.
6-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Figure 6-3
Soil carbon flux from mineral soils 1990-
1992 (metric tons C/ha-yr)
Note: negatives representives emissions,
and positives represent sequestration.
I 1 <-01
H3 0.1 to 0
ED 0 to 0.1
am 0.1 to 0.2
•I 0.2 to 0.3
wm >o.s
This map shows the spatial distribution of annual flux from mineral soils for the years 1990 through 1992
Note: Estimates exclude Alaska and U.S. Territories.
Figure 6-4
Soil carbon flux from mineral soils 1990- I I < -"1
1992 (metric tons C/ha-yr) EH] °-1 '° °
Note: negatives representives emissions, g|-g 0.1 to 0.2
and positives represent sequestration. mm 0.2 to 0.3
mm >o.3
This map shows the spatial distribution of annual flux from mineral soils for the years 1993 through 1997. A similar map cannot be prepared for 1998
through 2000 because the land-use projections for those years are not spatially based
Note: Estimates exclude Alaska and U.S. Territories.
Land-Use Change and Forestry 6-13
-------
Figure 6-5
Soil carbon flux from mineral soils 1990-
1992 (metric tons C/ha-yr)
Note: negatives representives emissions,
and positives represent sequestration.
HI -20 to -10
•B -10 to-5
EH-51°-3
liilill -3 to -1
I 1 -1 to 0
I | No Organic Soils
This map shows the spatial distribution of annual flux from organic soils for the years 1993 through 2000.
Figure 6-6
Soil carbon flux from mineral soils 1990-
1992 (metric tons C/ha-yr)
Note: negatives representives emissions,
and positives represent sequestration.
•1 -18 to-10 ;
§• -10 to-5 ;
mm -5 to-3 |
liiiM -3to-1 :
II -1 to 0 |
I I No Organic Soils'
This map shows the spatial distribution of annual flux from organic soils for the years 1993 through 2000.
6-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
are not currently accounted for. These include emissions of
CH4 and N2O from managed forest soils (above what would
occur if the forest soils were undisturbed), as well as CH4
emissions from artificially flooded lands, resulting from
activities such as dam construction. Aerobic (i.e., non-
flooded) soils are a sink for CH4, so soil drainage can result
in soils changing from a CH4 source to a CH4 sink, but if
the drained soils are used for agriculture, fertilization and
tillage disturbance can reduce the ability of soils to oxidize
CH4. The non-CO2 emissions and sinks from these other
land use and land-use change activities were not assessed
due to scientific uncertainties about the greenhouse gas
fluxes that result from these activities.
Methodology and Data Sources
The methodologies used to calculate CO2 emissions
from use and management of mineral and organic soils and
from liming follow the Revised 1996 IPCC Guidelines
(IPCC/UNEP/OECD/IEA1997), except where noted below.
The estimates of annual net CO2 flux from mineral soils
were based on application of the Revised 1996 IPCC
Guidelines as described by Eve et al. (2001). Total mineral
soil carbon stock estimates for 1982,1992, and 1997 were
developed for the conterminous United States and Hawaii
by applying the default IPCC carbon stock and carbon
adjustment factors (with one exception), to cropland and
grazing land area estimates, classified by climate, soil type,
and management regime. The exception is the base factor
for lands set aside for less than 20 years. The IPCC default
value is 0.8, but recent research (e.g., Paustian et al. 2001,
Follett et al. 2001, Huggins et al. 1998, and Gebhart et al.
1994) indicates that 0.9 is a more accurate factor for the
United States. Therefore, 0.9 was used instead of 0.8 for
the base factor for grassland set aside through the
Conservation Reserve Program. Data on land-use and land-
management changes over time were aggregated by Major
Land Resource Areas (MLRAs; NRCS 1981), which
represent geographic units with relatively similar soils,
climate, water resources, and land uses. MLRAs were
Table 6-10: Mineral Soil Areas by Land-Use Category and IPCC Climatic Region (million hectares)3
- . kdiv ..:.-.;.... ;• . - ,- - ., .,,. ...,.- .-- . . !,.,...-.. ' . . .....,--
f Category
Cropland (No fallow)
, Cold Temperate, Dry
fc.- Cold Temperate, Moist
Warm Temperate, Dry
'• Warm Temperate, Moist
if- Sub-Tropical, Dry
'" Sub-Tropical, Moist
f Cropland (Fallow)
J Cold Temperate, Dry
L, Cold Temperate, Moist
!'-• Warm Temperate, Dry
t~~ Warm Temperate, Moist
L-.. Sub-Tropical, Dry
| Sub-Tropical, Moist
fv Cold Temperate, Dry
|3 Cold Temperate, Moist
r Warm temperate, Dry
!j^- Warm Temperate, Moist
r" Sub-Tropical, Dry
; Sub-Tropical, Moist
i»- Grazing Land
f Cold Temperate, Dry
-— Cold Temperate, Moist
- Warm Temperate, Dry
*• Warm Temperate, Moist
;— Sub-Tropical, Dry
- Sub-Tropical, Moist
te - .,---!..
£ ....
1982
117,6
2.5
44.9
12.4
53.9
1.3
2.6
27.4
9.4
9.0
4.8
4.0
0.0
0.2
19.6
2.1
10.7
0.9
5.7
0.1
0.0
214.1
38.3
48.3
51.0"
64.2
6.8
5.3
1992
107.6
2.4
42.9
10.7
47.9
1.2
2.6
24.6
7.6
8.0
4.2
47
0.0
02
21.1
2.2
11.0
1.2 ""
6.5
0.1
0.0
215.6
38.3
47.4
51.5
66.2
6.9
5.3
1997
— . _ _ — - • ^-
109.2
2.8
45.6
10.6
467
1.1
2.4
20.0
7.0 ;
5-2 " ; ,
4.0
3.5 " •
0.0 "
^ OT '. [
22.0
2.4 ;
10.9 ;
1.2 * '<
7.5 •
0.1 t
0.0 ; ;
212.5 ;
38.2 : ;
46.5 "'• •;
Category 1982 1992
CRP" 0.0 13.7
Cold Temperate, Dry 0.0 2.4
^ Cold Temperate, Moist 0.0 4.4
* Warm temperate, Dry 0.0 2.5
Warm Temperate, Moist 0.0 4.4
Sub-Tropical, Dry 0.0 0.1
_„': Sub-Tropical, Moist 0.0 0.0
Non-Agricultural0 6.3 2.5
II Cold Temperate, Dry 0.8 0.2
^Cold Temperate, Moist 1.2 0.5
:_jA/arm Temperate, Dry 1 .0 0.3
Warm Temperate, Moist 3.1 1.4
17 Sub-Tropical, Dry 0.0 0.0
Subtropical, Moist 0.1 0.1
Total 385.0 385.0
-'• Cold Temperate, Dry 53.1 53.1
- Cold Temperate, Moist 114.2 114.2
- Warm Temperate, Dry 70.2 70.2
"Warm Temperate, Moist 131.0 . 131.0
: Sub-Tropical, Dry 8.3 8.3
=•-• Sub-Tropical, Moist 8.3 8.3
"Note: Totals may not sum due to independent rounding.
1997
13.2
2.3
4.1
2.4
4.3
0.1
0.0
8.1
0.4
1.9
0.8
4.4
0.1
0.6
385.0
53.1
114.2
70.2
131.0
8.3
8.3
""a Based on analysis of the 7997 National Resources Inventory data
51 2 ": ^ ^^ 2000). Includes all conterminous U.S. land categorized as
R4'fi ' agricultural in 1992 or 1997.
pg • e; b CRP (Conservation Reserve Program)
°-" -; '~.c Non-agricultural lands are included when they are either cropland or
5.0 Lgrazing land during 1992 or 1997.
-- " "" ~™, «KT.ri. . • • . ._,'. . ' .--'.'. . . '. :'-• . • .
- _ ...... - .], *
Land-Use Change and Forestry 6-15
-------
Table 6-11: Mineral Soil Areas by Land-Use Category and
IPCC Mineral Soil Category (thousand hectares)3
Category
Cropland (Fallow)
High Clay Activity Mineral Soils
Low Clay Activity Mineral Soils
Sandy Soils
Volcanic Soils
Aquic Soils
Cropland (No fallow)
High Clay Activity Mineral Soils
Low Clay Activity Mineral Soils
Sandy Soils
Volcanic Soils
Aquic Soils
CRPb
High Clay Activity Mineral Soils
Low Clay Activity Mineral Soils
Sandy Soils
Volcanic Soils
Aquic Soils
Grazing Land
High Clay Activity Mineral Soils
Low Clay Activity Mineral Soils
Sandy Soils
Volcanic Soils
Aquic Soils
Hay
High Clay Activity Mineral Soils
Low Clay Activity Mineral Soils
Sandy Soils
Volcanic Soils
Aquic Soils
Non-Agricultural0
High Clay Activity Mineral Soils
Low Clay Activity Mineral Soils
Sandy Soils
Volcanic Soil
Aquic Soils
Tola!
High Clay Activity Mineral Soils
Low Clay Activity Mineral Soils
Sandy Soils
Volcanic Soils
Aquic Soils
1982
27,338
24,026
1,516
635
11
1,149
117,825
72,043
14,151
9,198
163
22,270
0
0
0
0
0
0
213,840
136,731
41,876
24,885
362
9,986
19,616
13,563
2,745
1,132
228
1,948
6,426
2,782
2,280
651
48
665
385,044
249,146
62,567
36,500
811
36,019
1992
24,627
21,153
1,370
613
11
1,481
107,563
66,093
11,960
7,919
137
21,454
13,745
10,087
1,555
1,259
18
826
215,585
136,669
43,445
25,126
381
9,965
21,056
14,227
3,225
1,318
240
2,047
2,468
918
1,012
266
26
246
385,044
249,146
62,567
36,500
811
36,019
1997
20,024
17,422
1,160
416
12
1,016
109,194
68,437 :
11,292
7,645
130
21,690
13,209
9,671
1,491
1,219
17
811
212,540
135,273 :
42,665 .
24,667
365
9,570 ;
22,001
14,719
3,621
1,369
231
2,061
8,075
3,624
2,337
1,184
57
873
385,044
249,146
62,567
36,500
811
36,019
Note: Totals may not sum due to independent rounding.
» Based on analysis of the 1997 National Resources Inventory data (NRCS
2000). Includes all conterminous U.S. land categorized as agricultural in
1992 or 1997,
b CRP (Conservation Reserve Program)
c Non-agricultural land are included when they are either cropland or grazing
land during 1992 or 1997.
classified by IPCC climate categories using the climate
mapping program in Daly et al. (1994). For each MLRA,
area estimates for each combination of soil type and
land-use/land-management combination were derived
for 1982,1992, and 1997 using data obtained from the
1997National Resources Inventory (NRI; NRCS 2000).
Mineral soil areas by broad land-use category and IPCC
climatic region, and by broad land-use category and
IPCC mineral soil category, are shown in Table 6-10
and Table 6-11, respectively. Estimates of tillage
practices for each cropping system were derived from
data collected by the Conservation Technology
Information Center (CTIC1998), as adjusted by Towery
(2001) (see Table 6-12). :
The carbon flux estimate for 1990 is based on the
change in stocks between 1982 and 1992j and the carbon
flux estimate for 1995 through 1997 is based on the
change in stocks between 1982 and 1^97. The IPCC
base, tillage, and input factors were adjusted to account
for use of a ten-year and a fifteen-year accounting
period, rather than the 20-year period used in the Revised
1996 IPCC Guidelines. The carbon fhrx estimates for
1998 through 2000 were based on a projection of 1997
land use and management to 2008 (USDA 2000b).
The estimates of annual CO2 emissions from
organic soils were also based on the Revised 1996 IPCC
Guidelines as described by Eve et al. (2001). The IPCC
methodology for organic soils utilizes annual CO2
emission factors, rather than a stock change approach.
Following the IPCC methodology, only organic soils
under intense management were included, and the
default IPCC rates of carbon loss were applied to the
total 1992 and 1997 areas for the climate/land-use
categories defined in the IPCC Guidelines (see Table
6-13).8 The area estimates were derived from the same
climatic, soil, and land-use/land-management databases
that were used in the mineral soil calculations (Daly et
al. 1994, USDA2000a). The annual flux estimated for
1992 is applied to 1990, and the annual flux estimated
for 1997 is applied to 1995 through 2000.
8 The default IPCC emission factors for tropical regions was applied to the sub-tropical areas.
6-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 6-12: Tillage Percentages by Management Category and IPCC Climatic Zone3
Climatic Region/Cropping System
Sub-Tropical, Dry
Continuous Cropping Rotations6
Rotations with Fallow'
Low Residue Agricultures
Sub-Tropical, Moist
Continuous Cropping Rotations6
Rotations with Fallow*
Low Residue Agricultures
Warm Temperate, Dry
Continuous Cropping Rotations6
Rotations with Fallow'
Low Residue Agricultures
Warm Temperate, Moist
Continuous Cropping Rotations6
Rotations with Fallow'
Low Residue Agricultures
Cold Temperate, Dry
Continuous Cropping Rotations6
" Rotations with Fallow*
--• Low Residue Agricultures
Cold Temperate, Moist
Continuous Cropping Rotations6
.,, Rotations with Fallow*
Low Residue Agricultures
No
Till"
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1982
Reduced
Till0
3
0
3
0
0
3
0
3
3
6
6
9
3
6
q
fi
11
0
Conv.
Till"
97
100
97
100
100
97
100
97
97
94
94
91
97
94
100
89
89
100
No
Till"
0
0
0
0
0
0
0
0
o
10
5
1
2
4
1
5
5
1
1992
Reduced
Till0
4
2
4
20
10
4
10
15
1
30
30
10
25
25
2
30
30
2
Conv.
Tilld
96
98
96
80
90
96
90
85
..._.9.9 ....
60
65
89
73
71
97
65
65
97
No
Till"
0
0
0
1
1
0
1
2
0
12
8
2
8
12
2
3
3
1
1997
Reducei
Till0
15
5
10
10
10
5
15
20
0
28
27
13
12
13
6
17
27
7
d Conv.
Till"
85
95
90
89
89
95
84
78
100
60
65
85
80
75
92
80
70
92
Based on annual survey conducted by Conservation Technology Information Center (CTIC), with modifications for long-term adoption of no-till
agriculture (Towery 2001).
No-till includes CTIC survey data designated as no-tillage.
Conventional till includes CTIQ.su.ryey data designated as intensive tillage and conventional tillage.
Reduced-till includes CTIC survey data designated as ridge tillage, mulch tillage, and reduced tillage.
Includes medium and high input rotations. CTIC survey data for corn, soybeans, and sorghum were used in this category.
Includes rotations with fallow. CT|C survey data on fallow and small grain cropland were used in this category.
Includes low input rotations (low residue crops and vegetables in rotation). CTIC survey data on cotton were used in this category.
Carbon dioxide emissions from degradation of
limestone and dolomite applied to agricultural soils were
calculated by multiplying the annual amounts of limestone
and dolomite applied (see Table 6-14) by CO2 emission
factors (0.120 metric ton C/metric ton limestone, 0.130
metric ton C/metric ton dolomite).9 These emission factors
are based on the assumption that all of the carbon in these
materials evolves as CO2 in the same year in which the
minerals are applied. The annual application rates of
limestone and dolomite were derived from estimates and
industry statistics provided in the Minerals Yearbook and
Mineral Industry Surveys (Tepordei 1993, 1994, 1995,
1996, 1997, 1998, 1999, 2000, 2001; USGS 2001). To
develop these data, USGS (U.S. Bureau of Mines prior to
1997) obtained production and use information by surveying
crushed stone manufacturers. Because some manufacturers
were reluctant to provide information, the estimates of total
crushed limestone and dolomite production and use were
divided into three components: 1) production by end-use,
as reported by manufacturers (i.e., "specified" production);
2) production reported by manufacturers without end-uses
specified (i.e., "unspecified" production); and 3) estimated
additional production by manufacturers who did not respond
to the survey (i.e., "estimated" production).
9 Note: the default emission factor for dolomite provided in the Workbook volume of the Revised 1996 IPCC Guidelines (IPCCAJNEP/OECD/TEA
1997) is incorrect. The value provided is 0.122 metric ton carbon/metric ton of dolomite; the correct value is 0.130 metric ton carbon/metric ton of
dolomite.
Land-Use Change and Forestry 6-17
-------
Table 6-13: Organic Soil Areas by IPCC Land-Use
Category and Climatic Region (thousand hectares)3
Climatic Region/
Land-Use Category
Cold Temperate, Dry
Non-Agricultural11
Pasture/Forest
Cropland
Cold Temperate, Moist
Non-Agricultural*1
Pasture/Forest
Cropland
Sub-Tropical, Dry
Non-Agricultural15
Pasture/Forest
Cropland
Sub-Tropical, Moist
Non-Agricultural11
Pasture/Forest
Cropland
Warm Temperate, Dry
Non-Agricultural11
Pasture/Forest
Cropland
Warm Temperate, Moist
Non-Agricultural11
Pasture/Forest
Cropland
Total
Non-Agricultural11
Pasture/Forest
Cropland
1982
4
3
1
0
757
79
368
310
2
2
0
0
391
143
63
185
47
1
2
44
140
13
34
93
1,341
240
469
633
1992
4
3
1
0
757
53
419
285
2
2
0
0
391
131
66
194
47
<1
1
45
140
3
39
98
1,341
193
526
623
1997
4
3
1
0
757
52
411
294
2
2
0
0
391
117
77
196
47
1
2
44
140
2
38
101
1,341
176
530
635
Note: Totals may not sum due to independent rounding.
* Based on analysis of the 1997 National Resources Inventory data
(NRCS 2000). Includes all conterminous U.S. land categorized as
agricultural in 1992 or 1997.
b Non-agricultural lands are included for informational purposes only;
only pasture/forest areas and cropland areas contribute to
emissions.
To estimate the "unspecified" and "estimated" amounts
of crushed limestone and dolomite applied to agricultural
soils, it was assumed that the fractions of "unspecified" and
"estimated" production that were applied to agricultural soils
in a specific year were equal to the fraction of "specified"
production that was applied to agricultural soils hi that same
year. In addition, data were not available for 1990, 1992,
and 2000 on the fractions of total crushed stone production
that were limestone and dolomite, and on jthe fractions of
limestone and dolomite production that were; applied to soils.
To estimate the 1990 and 1992 data, a ;set of average
fractions were calculated using the 1991 jand 1993 data.
These average fractions were applied to the quantity of "total
crushed stone produced or used" reported for 1990 and 1992
in the 1994 Minerals Yearbook (Tepordei 1996). To estimate
2000 data, the 1999 fractions were applied to a 2000 estimate
of total crushed stone found in the USGS Mineral Industry
Surveys: Crushed Stone and Sand and Gravel in the First
Quarter of 2001 (USGS 2001).
The primary source for limestone and dolomite activity
data is the Minerals Yearbook, published by the Bureau of
Mines through 1994 and by the U.S. Geological Survey
from 1995 to the present. In 1994, the "Crushed Stone"
chapter in Minerals Yearbookbegan. rounding (to the nearest
thousand) quantities for total crushed stone produced or
used. It then reported revised (rounded) quantities for each
of the years from 1990 to 1993. In order to minimize the
. inconsistencies in the activity data, these revised production
numbers have been used in all of the subsequent
!
calculations.
Uncertainty
Uncertainties in the flux estimates for mineral and
organic soils result from both the activity data and the carbon
stock and adjustment factors. Each of the datasets used in
deriving the area estimates has a level of uncertainty that is
passed on through the analysis, and the aggregation of data
over large areas necessitates a certain degree of
generalization. The default IPCC values 'for mineral soil
carbon stocks under native vegetation as well as values for
, the base, tillage, and input factors represent broad regional
averages. Thus, the values have potentially jhigh uncertainty
when applied to specific combinations of climate, soil, and
Table 6-14: Quantities of Applied Minerals (Thousand Metric Tons)
Description
Limestone
Dolomite
1990
19,012
2,360
1991
20,312
2,618
1992
17,984
2,232
1993
15,609
1,740
1994
16,686
2,264
1995
17,297
2,769
1996
17,479
2,499
1997
16,539
2,989
1998
14,882
6,389
1999
16,894
3,420
2000
17,443
3,531
6-18 inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
land management conditions. Similarly, measured carbon
loss rates from cultivated organic soils vary by as much as
an order of magnitude, depending on climate, land use
history and management intensity.
Revised inventory approaches to better quantify
uncertainty and to better represent between-year variability
in annual fluxes are being developed and are currently under
review. A modification of the inventory based on the Revised
1996IPCC Guidelines uses field data specific to the United
States to statistically estimate land-use and management
factor values and baseline carbon stocks (see Box 6-1).
These are combined with other error estimates in a Monte-
Carlo simulation to generate 95 percent confidence intervals
for average annual fluxes for mineral and organic soils. An
annual activity-based inventory using a dynamic simulation
model is also being tested (see Box 6-2). The method uses
similar climate, soil, and land-use/land-management
databases as the IPCC approach, but is more capable of
estimating annual variation in fluxes, and including the
effects of long-term trends in agricultural productivity on
soil carbon stocks.
Uncertainties in the estimates of emissions from liming
result from both the methodology and the activity data. It
can take several years for agriculturally-applied limestone
and dolomite to degrade completely. The IPCC method
assumes that the amount of mineral applied in any year is
equal to the amount that degrades in that year, so annual
application rates can be used to derive annual emissions.
Further research is required to determine actual degradation
rates, which would vary with varying soil and climatic
conditions. However, application rates are fairly constant
over the entire time series, so this assumption may not
contribute significantly to overall uncertainty.
Box 6-1: Estimating Uncertainty Using a Revised IPCC Approach
•_ A modification of the IPCC methodology, which incorporates estimates of factor values and baseline carbon stocks based on U.S.-
" specific data and a Monte Carlo uncertainty analysis, is currently under peer-review (Ogle et al. in prep.). Based on an extensive literature
review of more than 1,000 published studies, IPCC factor values and organic soil emission rates have been re-estimated using field
^ studies specific to U.S. conditions. Linear mixed-effect models were used to derive probability density functions (PDF) for each factor
'~ value. In addition, PDFs for baseline soil carbon levels were derived from the National Soil Characterization Database, which contains _;
; carbon measurements for thousands of soil pedons sampled in the United States (NRCS 1997). Finally, PDFs were derived for the area "
fr" estimates of individual land-use/management categories based on the expansion factors from the National Resources Inventory and
j. tillage management data provided by the Conservation Technology Information Center. The expansion factors are a statistical representa-
;T~ tion of the land area in the inventory. Probability density functions for the climate/soil/land-use/land-management categories were based _
£.-. on mean and variance estimates for individual land areas, assuming normality, while accounting for the inter-dependence in land use
r; between starting and ending years in the inventory. A Monte Carlo approach (Smith and Heath 2001) was used to estimate overall
r uncertainty for carbon fluxes associated with each agricultural management activity. The Monte Carlo procedure simulated 50,000 ^
! estimates, using an iterative process in which random selections were made from the probability density functions described above. This
^ method provides estimates of carbon flux between U.S. agricultural soils and the atmosphere with statistically valid 95 percent confidence
; intervals.
f_ Preliminary results suggest that basing the inventory on U.S.-specific data sources gives somewhat lower estimates for carbon
J sequestration on mineral soils and higher estimates for carbon emissions from cultivated organic soils. Preliminary results show confi-
I dence intervals of about ±45 percent of the mean for mineral soil fluxes and ±30 percent for organic soil fluxes.
Land-Use Change and Forestry 6-19
-------
Box 6-2: Century Model Estimates of Soil Carbon Stock Changes on Cropland
Soil carbon stock changes on U.S. cropland were estimated using a dynamic ecosystem simulation model called Century (Metherell
et al. 1993, Parton et al. 1994). This method differs from the IPCC approach in that annual changes are computed dynamically as a
function of inputs of carbon to soil (i.e., crop residues, manure, and sewage sludge) and soil carbon decomposition rates, which are
governed by climate and soli factors as well as management practices. The model simulates all major field crops (maize, wheat and other
small grains, soybean, sorghum, cotton) as well as hay and pasture (grass, alfalfa, clover). Management variables included tillage,
fertilization, irrigation, drainage, and manure addition.
Input data were the same as that used in the IPCC-based method, (i.e., mean climate variables were from the PRISM database; crop
rotation, irrigation and soil characteristics were from the National Resources Inventory (NRI); and tillage data were from the Conservation
Technology Information Center). Differences with respect to the IPCC-based method were as follows: 1) climate values were applied to
each individual MLRA to drive the simulation (as opposed to their use for classification into broad climate zones in the IPCC method) and
2) soil physical parameters, which influence decomposition rates and soil water balance, specific to each MLRA point were used with
Century, while, in the IPCC method, soils information were used to group NRI points by broad soil taxonomic classes. In the Century-
based analysis, land areas having less than 5 percent of total area in crop production were excluded and several less-dominant crops
(e.g,, vegetables, sugar beets and sugar cane, potatoes, tobacco, orchards, and vineyards), for which the model has not yet been
parameterized, were not included. Thus, the total area included in the Century analysis (149 million hectares) was smaller than the
corresponding area of cropland (165 million hectares) included in the IPCC estimates.
Preliminary results using the Century model suggest (as with the IPCC model) that U.S. cropland soils (excluding organic soils) are
currently acting as a carbon sink, of about 21 Tg C/year (77 Tg C02 Eq./year) (average rates for 1992 through 1997). The main manage-
ment changes responsible for the increase in mineral soil carbon stocks, according to the Century approach, are the same as those
indicated by the IPCC method: reduced tillage intensity; establishment of the Conservation Reserve Program; reduced bare fallow; and
some increase in hay area. In addition, the Century analysis includes the effect of increasing residues inputs due to higher productivity on
cropland in general, which contributes to the increase in soil carbon stocks.
Potential advantages of a dynamic simulation based approach include the ability to use actual observed weather, observed annual
crop yields, and more detailed soils and management information to drive the estimates of soil carbon change. This would facilitate
annual estimates of carbon stock changes and C02 emissions from soils that would better reflect interannual variability in cropland
production and weather influences on carbon cycle processes.
There are several sources of uncertainty in the limestone
and dolomite activity data. When reporting data to the USGS
(or U.S. Bureau of Mines), some producers do not
distinguish between limestone and dolomite. In these cases,
data are reported as limestone, so this could lead to an
overestimation of limestone and an underestimation of
dolomite. In addition, the lack of comprehensive limestone
and dolomite end-use data makes it necessary to derive
amounts of "unspecified" and "estimated" crushed
limestone and dolomite applied to agricultural soils based
on "specified" production data. Lastly, the total quantity of
crushed stone listed each year in the Minerals Yearbook
excludes American Samoa, Guam, Puerto Rico, and the U.S.
Virgin Islands. The Mineral Industry Surveys further
excludes Alaska and Hawaii from its totals:
6-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Changes in Yard Trimming
Carbon Stocks in Landfills
As is the case with carbon in landfilled forest products,
carbon contained in landfilled yard trimmings can be stored
indefinitely. In the United States, yard trimmings (i.e., grass
clippings, leaves, branches) comprise a significant portion
of the municipal waste stream, and a large fraction of the
collected yard trimmings are discarded in landfills. However,
both the amount of yard trimmings collected annually and
the fraction that is landfilled have declined over the last
decade. In 1990, nearly 32 million metric tons (wet weight)
of yard trimmings were collected at landfills and transfer
stations (Franklin Associates 1999). Since then, programs
banning or discouraging disposal have led to an increase in
backyard composting and the use of mulching mowers, and
a consequent 35 percent decrease in the amount of yard
trimmings collected. At the same time, a dramatic increase
in the number of municipal composting facilities has reduced
the proportion of collected yard trimmings that are discarded
in landfills—from 72 percent in 1990 to 36 percent by 2000.
The decrease in the yard trimmings landfill disposal rate
has resulted in a decrease in the rate of landfill carbon
storage from about 19.1 Tg CO2 Eq. in 1990 to 6.4 Tg CO2
Eq. in 2000 (see Table 6-15).
Table 6-15: Net C02 Flux from Landfilled
Yard Trimmings
Methodology
The methodology for estimating carbon storage is based
on a life-cycle analysis of greenhouse gas emissions and
sinks associated with solid waste management (EPA 1998).
According to this methodology, carbon storage is the product
of the weight of landfilled yard trimmings and a storage
factor. The storage factor, which is the ratio of the weight
of the carbon that is stored indefinitely to the wet weight of
the landfilled yard trimmings, is based on a series of
experiments designed to evaluate methane generation and
residual organic material in landfills (Barlaz 1998). These
experiments analyzed grass, leaves, branches, and other
materials, and were designed to promote biodegradation by
providing ample moisture and nutrients.
Barlaz (1998) determined carbon storage factors, on a
dry weight basis, for each of the three components of yard
trimmings: grass, leaves, and branches (seeTable 6-16). For
purposes of this analysis, these were converted to wet weight
basis using assumed moisture contents of 0.6, 0.2, and 0.4,
respectively. To develop a weighted average carbon storage
factor, the composition of yard trimmings was assumed to
consist of 50 percent grass clippings, 25 percent leaves,
and 25 percent branches on a wet weight basis. The weighted
average carbon storage factor is 0.23 (weight of carbon
stored indefinitely per unit weight of wet yard trimmings).
Table 6-16: Storage Factor (kg C/kg dry yard trimmings)
Moisture Content (kg water/kg wet yard trimmings),
Composition (percent) and Converted Storage Factor
(kg C/kg wet yard trimmings) of Landfilled Yard Trimmings
Year
1990
.
- 1995
1996
7 1 QQ7
- 1998 jfe
1999 **
' -2000 gr
Note: Parentheses indicate net storage
values based on projections.
Tg C02 Eq.
(19.1)
(12.2)
(10.2)
(95) _
Z^jis) " v"iy.*
-_=-» J64I l"IHZ"~*
. Lightly shaded area indicates
Component Grass Leaves Branches
Storage Factor3 0 32 0 54 0 38
Moisture Content 0 60 0 20 0 40
Composition 50% 25% 25%
.Converted Storage Factorb 0.13 0.43 0.23°
a Frnm Rarla? f1QQfl\
(., b The converted storage factor for each component is the product of
the original storage factor and one minus the moisture content; the
;; .weighted average storage factor is obtained by weighting the
p.'- component storage factors by the composition percents.
~ ° Value is also value of weighted average.
Land-Use Change and Forestry 6-21
-------
Data Sources
The yard trimmings discards data were taken from the
report Characterization of Municipal Solid Waste in the
United States: 1998 Update (Franklin Associates 1999),
which provides estimates for 1990 through 1997 and
forecasts for 2000 and 2005 (Table 6-17). Yard trimmings
discards for 1998 through 2000 were projected using the
Franklin Associates (1999) forecast of generation and
recovery rates (i.e., decrease of 6 percent per year, increase
of 8 percent per year, respectively) for 1998 through 2000.
This report does not subdivide discards of individual
materials into volumes landfilled and combusted, although
it does provide an estimate of the overall distribution of
solid waste between these two management methods (i.e.,
ranging from 81 percent and 19 percent respectively in 1990,
to 76 percent and 24 percent in 2000) for the waste stream
as a whole.10 Thus, yard trimmings disposal to landfills is
the product of the quantity discarded and the proportion of
discards managed in landfills. As discussed above, the
carbon storage factor was derived from the results of Barlaz
(1998), and assumed moisture contents and component
fractions for yard trimmings.
Table 6-17: Collection and Destination of Yard Trimmings (Million Metric Tons, wet)
Uncertainty
The principal source of uncertainty for the landfill
carbon storage estimates stems from an incomplete
understanding of the long-term fate of carbon in landfill
environments. Although there is ample field evidence that
many landfilled organic materials remain virtually intact for
long periods, the quantitative basis for predicting long-term
storage is based on limited laboratory results under
experimental conditions." In reality, there is likely to be
considerable heterogeneity in storage rates, based on 1)
actual composition of yard trimmings (e,.g., oak leaves
decompose more slowly than grass clippings) and 2) landfill
characteristics (e.g., availability of moisture, nitrogen,
phosphorus, etc.). Other sources of uncertainty include the
estimates of yard trimmings disposal rates, which are based
on extrapolations of waste composition surveys, and the
extrapolation of values for 1998 through 2000 disposal from
estimates for the period from 1990 through 1997.
Destination
Municipal Composting Facilities
Discarded
Landfill
Incineration
Total
1990
3.8
27.9
22.8
5.2
31.8
1 *
1
i. ' J
I- *
i
**
1995
8.2
27.4
22.2
4.3
26.9
1996
9.4
26.9
21.7
3.8
25.3
1997
10.4
23.9
19.2
3.5
25.2
1998
|j30
till
23.6
1999
8
114
145
27
22.2
2000
10.9
100 *
76
24 "
™^'9
Note: Lightly shaded area indicates values based on projections.
10 These pcrcents represent the percent of total MSW discards, after recovery for recycling or composting. ,
1' In addition there was a mass balance problem with the experimental results that are used here to derive the yard trimmings carbon storage factor. In
particular, the carbon storage factor for leaves that was determined experimentally by Barlaz (1998) was greater than Barlaz's measured carbon
content of the leaves. :
6-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
7. Waste
Wastewater
Treatment
Human
Sewage
I
I
Waste as a
Portion of all
Emissions
3.4%
Wiste management and treatment activities are sources of greenhouse gas emissions (see Figure 7-1). Landfills
were the largest source of anthropogenic methane (CH^) emissions, accounting for 33 percent of the U.S. total.1
Smaller amounts of methane are emitted from wastewater systems by bacteria used in various treatment processes. Wastewater
treatment systems are also a potentially significant source of
N2O emissions; however, methodologies are not currently Figure 7-1
available to develop a complete estimate. Nitrous oxide
emissions from the treatment of the human sewage component
of wastewater were estimated, however, using a simplified
methodology. Nitrogen oxide (NOx), carbon monoxide (CO),
and non-methane volatile organic compounds (NMVOCs) are
emitted by waste activities, and are addressed separately at the
end of this chapter. A summary of greenhouse gas emissions
from the Waste chapter is presented in Table 7-1 and Table 7-2.
Overall, in 2000, waste activities generated emissions
of 240.6 Tg CO2 Eq., or 3.4 percent of total U.S. greenhouse
gas emissions.
Landfills
Landfills are the largest anthropogenic source of
methane (CH4) emissions in the United States. In 2000,
landfill CH4 emissions were approximately 203.5 Tg CO2
Eq. (9,690 Gg). Emissions from municipal solid waste (MSW) landfills, which received about 61 percent of the total solid
waste generated in the United States, accounted for about 94 percent of total landfill emissions, while industrial landfills
accounted for the remainder. Over 2,100 operational landfills exist in the United States (BioCycle 2001), with the largest
landfills receiving most of the waste and generating the majority of the methane.
Methane emissions result from the decomposition of organic landfill materials such as paper, food scraps, and yard
trimmings. This decomposition process is a biological process through which microorganisms derive energy. After being
placed in a landfill, organic waste is initially digested by aerobic (in the presence of oxygen) bacteria. After the oxygen
supply has been depleted, the remaining waste is consumed by anaerobic bacteria, which break down organic matter into
substances such as cellulose, amino acids, and sugars. These substances are further broken down through fermentation
into gases and short-chain organic compounds that form the substrates for the growth of methanogenic bacteria. Methane-
1 Landfills also store carbon, due to incomplete degradation of organic materials such as wood products and yard trimmings, as described in the Land-
Use Change and Forestry chapter.
50
100 150
Tg CO2 Eq.
200
Waste 7-1
-------
Table 7-1: Emissions from Waste (Tg C02 Eq.)
Gas/Source
Landfills
Wastewater Treatment
N20
Human Sewage
Total
1990 i !
237.7 F'":ri
213.4 1'. i
24.3 (*' I
7.0 • :•
7.0 m=M
244.7 r "
1995
243.4
216.6
26.8
7.7
7.7
251.1
1996
238.5
211.5
27.0
7.8
7.8
246.3
1997
233.9
206.4
27.5
7.9
7.9
241.9
1998
228.8
201.0
27.8
8.1
8.1
236.9
1999
231.4
203.1
28.3
8.4
8.4
239.8
2000
232.2
203.5
28.7
8.5
8.5
240.6
Note: Totals may not sum due to independent rounding.
Table 7-2: Emissions from Waste (Gg)
1990
1995
1996
1997
1998
1999 2000
CH
Landfills
Wastewater Treatment
N20
Human Sewage
11,317
10,162
1,155
23
23
r *
C-J.
f-™f
«nr •*
E
S'::
«• , -, *
11,591
10,315
1,275
25
25
11,359
10,072
1,287
25
25
11,138
9,827
1,311
26
26
10,897
9,571
1,326
26
26
11,021
9,671
1,350
27
27
11,056
9,690
1,367
27
27
Note: Totals may not sum due to independent rounding.
Box 7-1: Biogenic Emissions and Sinks of Carbon
For many countries, C02 emissions from the combustion or degradation of biogenic materials are important because of the signifi-
cant amount of energy they derive from biomass (e.g., burning fuelwood). The fate of biogenic materials is also important when
evaluating waste management emissions (e.g., the decomposition of paper). The carbon contained in paper was originally stored in trees
during photosynthesis. Under natural conditions, this material would eventually degrade and cycle back to the atmosphere as C02. The
quantity of carbon that these degradation processes cycle through the Earth's atmosphere, waters, soils, and biota is much greater than
the quantity added by anthropogenic greenhouse gas sources. But the focus of the United Nations Framework Convention on Climate
Change is on anthropogenic emissions—emissions resulting from human activities and subject to human control—because it is these
emissions that have the potential to alter the climate by disrupting the natural balances in carbon's biogeochemical cycle, and enhancing
the atmosphere's natural greenhouse effect.
Carbon dioxide emissions from biogenic materials (e.g., paper, wood products, and yard trimmings) grown on a sustainable basis
are considered to mimic the closed loop of the natural carbon cycle—that is, they return to the atmosphere C02 that was originally
removed by photosynthesis. However, CH4 emissions from landfilled waste occur due to the man-made anaerobic conditions conducive
to CH4 formation that exist in landfills, and are consequently included in this Inventory.
The removal of carbon from the natural cycling of carbon between the atmosphere and biogenic materials—which occurs when
wastes of biogenic origin are deposited in landfills—sequesters carbon. When wastes of sustainable, biogenic origin are landfilled, and
do not completely decompose, the carbon that remains is effectively removed from the global carbon cycle. Landfilling of forest products
and yard trimmings results in long-term storage of about 70 Tg C02 Eq. and 7 to 18 Tg C02 Eq. per year, respectively. Carbon storage that
results from forest products and yard trimmings disposed in landfills is accounted for in the Land-Use Change and Forestry chapter, as
recommended in the Revised 1996IPCC Guidelines (IPCC/UNEP/OECD/IEA1997) regarding the tracking of carbon flows.
7-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Box 7-2: Recycling and Greenhouse Gas Emissions and Sinks
U.S. waste management patterns changed dramatically over the past decade in response to changes in economic and regulatory
factors. Perhaps the most significant change from a greenhouse gas perspective was the increase in the national average recycling rate,
which climbed from 16 percent in 1990 to 28 percent in 1999 (EPA 2000).
This change has affected emissions in several ways, primarily by reducing emissions from waste and energy activities, as well as by
enhancing forestry sinks. The impact of increased recycling on greenhouse gas emissions can be best understood when emissions are
considered from a life cycle perspective (EPA 1998). When a material is recycled, it is used in place of virgin inputs in the manufacturing
process, rather than being disposed and managed as waste. The substitution of recycled inputs for virgin inputs reduces three types of
emissions throughout the product life cycle. First, manufacturing processes involving recycled inputs generally require less energy than
those using virgin inputs. Second, the use of recycled inputs leads to reductions in process non-energy emissions (e.g., perf luorocarbon
emissions from aluminum smelting). Third, recycling reduces disposal and waste management emissions, including methane from
landfills and nitrous oxide and non-biogenic carbon dioxide emissions from combustion. In addition to greenhouse gas emission reduc-
tions from manufacturing and disposal, recycling of paper products—the largest component of the U.S. wastestream—results in in-
creased forest carbon sequestration. When paper is recycled, fewer trees are needed as inputs in the manufacturing process; reduced
harvest levels result in older average forest ages, with correspondingly more carbon stored.
producing anaerobic bacteria convert these fermentation
products into stabilized organic materials and biogas
consisting of approximately 50 percent carbon dioxide
(CO2) and 50 percent methane (CH4), by volume.2 Methane
production typically begins one or two years after waste
disposal in a landfill and may last from 10 to 60 years.
Between 1990 and 2000, net methane emissions from
landfills were relatively constant (see Table 7-3 and Table
7-4). The roughly constant emissions estimates are a result
of two offsetting trends: (1) the amount of MSW in landfills
contributing to methane emissions increased, thereby
increasing the potential for emissions; and (2) the amount
of landfill gas collected and combusted by landfill operators
also increased, thereby reducing emissions.
Methane emissions from landfills are a function of
several factors, including: (1) the total amount of MSW in
landfills, which is related to total MSW landfilled annually
for the last 30 years; (2) the characteristics of landfills
receiving waste (i.e., composition of waste-in-place; size,
climate); (3) the amount of methane that is recovered and
either flared or used for energy purposes; and (4) the amount
of methane oxidized in landfills instead of being released
into the atmosphere. The estimated total quantity of waste-
in-place contributing to emissions increased from about
4,926 Tg in 1990 to 6,147 Tg in 2000, an increase of 25
percent (see Annex O). During this period, the estimated
methane recovered and flared from landfills increased as
well. In 1990, for example, approximately 1,119 Gg of
methane was recovered and combusted (i.e., used for energy
or flared) from landfills. In 2000, the estimated quantity of
methane recovered and combusted increased to 4,874 Gg.
Over the next several years, the total amount of MSW
generated is expected to increase slightly. The percentage
of waste landfilled, however, may decline due to increased
recycling and composting practices. In addition, the quantity
of methane that is recovered and either flared or used for
energy purposes is expected to increase, partially as a result
of a 1996 regulation that requires large MSW landfills to
collect and combust landfill gas (see 40 CFR Part 60,
Subparts Cc and WWW).
Methodology
Based on available information, methane emissions
from landfills were estimated to equal the methane produced
from municipal landfills, minus the methane recovered and
combusted, minus the methane oxidized before being
released into the atmosphere, plus the methane produced
by industrial landfills.
2 The percentage of CO2 in biogas released from a landfill may be smaller because some CO2 dissolves in landfiE water (Bingemer and Crutzen 1987).
Additionally, less than 1 percent of landfill gas is composed of non-methane volatile organic compounds (NMVOCs).
Waste 7-3
-------
Table 7-3: CH4 Emissions from Landfills (Tg C02 Eq.)
Activity
MSW Landfills
Industrial Landfills
Recovered
Gas-to-Energy
Rared
Total
1990
221.6
15.3
(14.5)
(9.0)
213.4
Note: Totals may not sum due to independent rounding.
• I
«i
5
c
t '.
! I
an 1*
i,
u
1995
255.5
17.5
(21.4)
(35.0)
216.6
1996
261.8
17.8
(24.6)
(43.5)
211.5
1997
268.4
18.2
(29.7)
(50.5)
206.4
1998
274.0
18.5
(36.3)
(55.3)
201.0
1999
280.9
19.0
(41.7)
(55,1)
203.1
2000
286.5
19.3
(46.1)
(56.2)
203.5
Table 7-4: CH4 Emissions from Landfills (Gg)
Activity
MSW Landfills
Industrial Landfills
Recovered
Gas-to-Energy
Rared
Total
1990
10,551
731
(692)
(427)
10,162
S- 1
r j
t= — i
Z I
a,
& J
I !
%
1995
12,165
833
(1,017)
(1,665)
10,315
1996
12,465
850
(1,171)
(2,073)
10,072
1997
12,779
868
(1,415)
(2,405)
9,827
1998
13,050
883
(1,729)
(2,633)
9,571
1999
13,374
904
(1,984)
(2,623)
9,671
2000
13,642
921
(2,196)
(2,678)
9,690
Note: Totals may notsum due to independent rounding.
The methodology for estimating CH4 emissions from
municipal landfills is based on a model that updates the
population of U.S. landfills each year. This model is based
on the pattern of actual waste disposal, as evidenced in an
extensive landfill survey by the EPA's Office of Solid Waste
in 1987. A second model was employed to estimate
emissions from the landfill population (EPA 1993). For each
landfill in the data set, the amount of waste-in-place
contributing to methane generation was estimated using its
year of opening, its waste acceptance rate, year of closure,
and design capacity. Data on national waste disposed in
landfills each year was apportioned by landfill. Emissions
from municipal landfills were then estimated by multiplying
the quantity of waste contributing to emissions by emission
factors (EPA 1993). For further information see Annex O.
The estimated landfill gas recovered per year was based
on updated data collected from vendors of flaring equipment
and a database of landfill gas-to-energy (LFGTE) projects.
Based on the information provided by vendors, the methane
combusted by the 585 flares in operation from 1990 to 2000
were estimated. This quantity likely underestimates flaring.
Additionally, the database provided sufficient data on
landfill gas flow and energy generation: for 306 of the
approximately 314 operational LFGTE projects. If both flare
data and LFGTE recovery data for a particular landfill were
available, then the emissions recovery was based on the
LFGTE data, which provides actual landfill-specific data
on gas flow for direct use projects and project capacity (i.e.,
megawatts) for electricity projects. The flare data, on the
other hand, only provided a range of landfill gas flow for a
given flare size. Given that each LFGTE project was likely
to also have had a flare, double counting reductions from
flares and LFGTE projects was avoided by subtracting
emissions reductions associated with LFGTE projects for
which a flare had not been identified from the emissions
reductions associated with flares.3
Emissions from industrial landfills were assumed to
be equal to 7 percent of the total methane emissions from
municipal landfills. The amount of methane oxidized was
assumed to be 10 percent of the methane generated that is
3 Due to the differences in referencing landfills and incomplete data on the national population of flares, matching flare vendor data with the LFGTE
data was problematic and a flare could not be identified for each of the LFGTE projects. Because each LFGTE project likely has a flare, the aggregate
estimate of emission reductions through flaring was reduced by the LFGTE projects for which a specific flare could not be identified. This approach
eliminated the potential for double counting emissions reductions at landfills with both flares and a LFGTE project.
7-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
not recovered (Liptay et al. 1998). To calculate net methane
emissions, both methane recovered and methane oxidized
were subtracted from methane generated at municipal and
industrial landfills.
Data Sources
The landfill population model, including actual waste
disposal data from individual landfills, was developed from
a survey performed by the EPA's Office of Solid Waste (EPA
1988). National landfill waste disposal datafor 1990 through
2000 were obtained from BioCycle (2001). Documentation
on the landfill methane emissions methodology employed
is available hi the EPA''s Anthropogenic Methane Emissions
in the United States, Estimates for 1990: Report to Congress
(EPA 1993). Information on flares was obtained from
vendors, and information on landfill gas-to-energy projects
was obtained from the EPS's Landfill Methane Outreach
Program database.
Uncertainty
Several types of uncertainties are associated with the
estimates of methane emissions from landfills. The primary
uncertainty concerns the characterization of landfills.
Information is lacking on the area landfilled and total waste-
in-place —the fundamental factors that affect methane
production. In addition, the statistical model used to estimate
emissions is based upon methane generation at landfills that
currently have developed energy recovery projects, and may
not precisely capture the relationship between emissions
and various physical characteristics of individual landfills.
Overall, uncertainty hi the landfill methane emission rate is
estimated to be roughly ±30 percent.
Wastewater Treatment
Wastewater from domestic sources (municipal sewage)
and industrial sources is treated to remove soluble organic
matter, suspended solids, pathogenic organisms, and
chemical contaminants. Treatment may either occur off-site
or on-site. For example, in the United States, approximately
25 percent of domestic wastewater is treated in septic
systems or other on-site systems. Soluble organic matter is
generally removed using biological processes in which
microorganisms consume the organic matter for
maintenance and growth. The resulting biomass (sludge) is
removed from the effluent prior to discharge to the receiving
stream. Microorganisms can biodegrade soluble organic
material in wastewater under aerobic or anaerobic
conditions, where the latter condition produces methane.
During collection and treatment, wastewater may be
accidentally or deliberately managed under anaerobic
conditions. In addition, the sludge may be further
biodegraded under aerobic or anaerobic conditions.
Untreated wastewater may also produce methane if
contained under anaerobic conditions.
The organic content, expressed in terms of either
biochemical oxygen demand (BOD) or chemical oxygen
demand (COD), determines the methane producing potential
of wastewater. BOD represents the amount of oxygen that
would be required to completely consume the organic matter
contained in the wastewater through aerobic decomposition
processes. COD refers to the amount of oxygen consumed
under specified conditions in the oxidation of the organic
and oxidizable inorganic matter and is a parameter typically
used to characterize industrial wastewater. Under anaerobic
conditions and with all other parameters, such as
temperature, being the same, wastewater with higher organic
content will produce more methane than wastewater with
lower BOD or COD.
In 2000, methane emissions from domestic wastewater
treatment were 13.9 Tg CO2 Eq. (660 Gg). Emissions have
increased since 1990 in response to the increase in the U.S.
human population. Industrial emission sources include
wastewater from the pulp and paper, meat and poultry
processing, and the vegetables, fruits and juices processing
industry.4 In 2000, methane emissions from industrial
wastewater treatment were 14.8 Tg CO2Eq. (707 Gg). Table
7-5 and Table 7-6 provide emission estimates from domestic
and industrial wastewater treatment.
Methodology
Domestic wastewater methane emissions were
estimated using the default IPCC methodology (IPCC 2000).
The total population for each year was multiplied by a per
capita wastewater BOD production rate to determine total
1 Industrial wastewater emissions from petroleum systems is included in the petroleum systems section in the Energy chapter.
Waste 7-5
-------
Table 7-5: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Tg C02 Eq.)
f n SI
Activity
1990
1995
1996
1997
1998
1999 2000
Domestic
Industrial*
Total
12.3
12.0
24.3
f_]
r -!
. i
13.1
13.7
26.8
13.2
13.8
27.0
13.4
14.2
27.5
13.5
14.3
27.8
13.7
14.6
28.3
13.9
14.8
28.7
* Industrial activity includes the pulp and paper, meat and poultry, and the vegetables, fruits and juices processing industry.
Note: Totals may not sum due to independent rounding.
Table 7-6: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Gg)
Activity
Domestic
Industrial*
Total
1990
584
571
1,155
!'
II !
r..
L
i,
• .in)
,, fl
1995
622
653
1,275
1996
630
658
1,287
1997
637
674
1,311
1998
645
681
1,326
1999
653
697
1,350
2000
660
707
1,367
* Industrial activity includes the pulp and paper, meat and poultry, and the vegetables, fruits and juices processing industry.
Note; Totals may not sum due to independent rounding.
wastewater BOD produced. It was assumed that, per capita,
0.065 kilograms of wastewater BOD55 was produced per
day and that 16.25 percent of wastewater BODS was
anaerobically digested. This proportion of BOD was then
multiplied by an emission factor of 0.6 kg CH4/kg BODS.
A top-down approach was used to develop estimates
of methane emissions from industrial wastewater according
to the methodology described in the IPCC Good Practice
Guidance (IPCC 2000). Industry categories identified by
IPCC were analyzed to identify industries likely to have
significant methane emissions from industrial wastewater.
Industries were chosen that typically have both a high
volume of wastewater generated and a high organic COD
wastewater load. The top three industries that met these
criteria were:
• Pulp and paper manufacturing
• Meat and poultry packing
• Vegetables, fruits and juices processing
Methane emissions from these categories were
estimated by multiplying the annual product output (metric
tons/year) by the average outflow (m3/ton of output), the
organics loading in the outflow (grams of organic COD/
m3), the emission factor (grams CH4/grams COD), and the
percentage of organic COD assumed to degrade
anaerobically.
Wastewater treatment for the pulp and paper industry
typically includes neutralization, screening, ;sedimentation,
and flotation/hydrocycloning to remove solids (Worldbank
1999, Nemerow 1991). The most important step is
lagooning for storage, settling, and biological treatment
! (secondary treatment). In developing estimates for this
i !
^category BOD was used instead of COD,; because more
accurate BOD numbers were available. In determining the
percent that degraded anaerobically, both primary and
secondary treatment were considered. Primary treatment
lagoons are aerated to reduce anaerobic activity. However,
the lagoons are large and zones of anaerobic activity may
;occur. Approximately 42 percent of the BOD passes on to
,secondary treatment, which are less likely to be aerated
'(EPA 1993). It was assumed that 25 percent of the BOD in
; secondary treatment lagoons degrades anaerobically, while
10 percent passes through to be discharged with the effluent
(EPA 1997a). Overall, the percentage of wastewater
organics that degrade anaerobically was determined to be
10.3 percent. The emission factor that was; used is 0.6 kg
CH4/kg BOD, which is the default emission factor from
IPCC (2000).
5 The 5-day biochemical oxygen demand (BOD) measurement (Metcalf and Eddy 1991).
7-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
The meat and poultry processing industry makes
extensive use of anaerobic lagoons in sequence to screening,
fat traps and dissolved air flotation, and it was estimated
that 77 percent of all wastewater organics from this industry
degrades anaerobically (EPA 1997b).
Treatment of wastewater from fruits, vegetables, and
juices processing includes screening, coagulation/settling
and biological treatment (lagooning). The flows are
frequently seasonal, and robust treatment systems are
preferred for on-site treatment. Effluent is suitable for
discharge to the sewer. Therefore, it was assumed that this
industry is likely to use lagoons intended for aerobic
operation, but that the large seasonal loadings may develop
limited anaerobic zones. In addition, some anaerobic lagoons
may also be used. Consequently, it was estimated that 5
percent of these wastewater organics degrade anaerobically.
Data Sources
National population data for 1990 to 2000, used in the
domestic wastewater emissions estimates, were supplied by
the U.S. Census Bureau (2000). Per-capita production of
BODS for domestic wastewater was obtained from the EPA
(1997b). The emission factor (0.6 kg CH/kg BOD5)
employed for domestic wastewater treatment was taken from
IPCC (2000). The same emission factor was used for pulp
and paper wastewater, whereas the emission factor for meat
and poultry, and vegetables, fruits and juices category is
0.25 kg CH4/kg COD (IPCC 2000).
Table 7-7 provides U.S. population and wastewater
BOD data.
Table 7-7: U.S. Population (Millions) and Wastewater
For pulp and paper, a time series of methane emissions
for post-1990 years was developed based on production
figures reported in the Lockwood-Post Directory
(Lockwood-Post Directory 1992-2001). The overall
wastewater outflow was estimated to be 85 mVton and the
average BOD loading entering the secondary treatment
lagoons was estimated to be 0.4 gram BOD/liter. Both values
are based on information from multiple handbooks.
Production data for the meat and poultry industry were
obtained from the U.S. Census (2001). EPA (1997b)
provides wastewater outflows of 13 (out of a range of 8 to
18) mVton and an average COD value of 4.1 (out of a range
of2to7)g/liter.
The USDA National Agricultural Statistics Service
(USDA 2001) provided production data for the fruits,
vegetables, and juices processing sector. Outflow data for
various subsectors (canned fruit, canned vegetables, frozen
vegetables, fruit juices, jams, baby food) were obtained from
World Bank (1999) and an average wastewater outflow of
5.6 m3/ton was used. For the organics loading, a COD value
of 5 (out of a range of 2 to 10) g/liter was used (EPA 1997b).
Table 7-8 provides U.S. pulp and paper; meat and
poultry; and vegetables, fruits, and juices production data.
Uncertainty
Domestic wastewater emissions estimates are
uncertain due to the lack of data on the occurrence of
anaerobic conditions in treatment systems, especially
incidental occurrences.
Table 7-8: U.S. Pulp and Paper, Meat and Poultry,
and Vegetables, Fruits and Juices Production (Million
Metric Tons)
BOD Produced
fYear
: 1990
- 1991
i 1992
i 1993
1994
r 1995
fc 1996
;, 1997
'; 1.9.98
f 1999
: 2000
&
[Gg)
Population
249.4
252.0
254.9
257.7
260.2
262.7
265.2
267.7
270.2
272.6
275.1
BOD5
5,920
5,984
6,052
6,118
6,179
6,238
6,296
6,356
6,415
6,473
6,531
•-'•--• ---- -----
C- ,
; Year
1990
1991
1992
1993
1994
n995
1996
,1.1997
.: 1998
i 1999
12000
- S-~— - . ,
Pulp
and Paper
128.9
129.2
134.5
134.1
139.3
140.9
140.3
145.6
144.0
145.1
144.4
- ,,---. '.": ,_,;
Meat
and Poultry
28.2
29.0
30.0
31.0
32.0
33.6
34.2
34.6
35.7
37.0
38.0
Vegetables,
Fruits and
Juices
297
308
329
336
36 7
362
359
371
359
368
38.0
___„.-, ^ .. _ ._.. :,_~
Waste 7-7
-------
Large uncertainties are associated with the industrial
wastewater emission estimates. Wastewater outflows and
organics loadings may vary greatly for different plants and
different sub-sectors (e.g. paper vs. board, poultry vs. beef,
baby food vs. juices, etc.). Also, the degree to which
anaerobic degradation occurs in treatment systems is very
difficult to assess. In addition, it is believed that pulp and
paper, meat and poultry and vegetables, fruits and juices
are the most significant industrial sources, but there may be
additional sources that also produce wastewater organics
that may degrade under anaerobic conditions (e.g., organic
chemicals and plastics production).
Human Sewage
Domestic human sewage (termed "blackwater") is
usually mixed with other household wastewater (known as
"graywater"), which includes shower drains, sink drains,
washing machine effluent, etc. and transported by a
collection system to either a direct discharge, an on-site or
decentralized wastewater system, or a centralized
wastewater system. Decentralized wastewater systems are
septic systems and package plants that may include several
process steps. Centralized treatment systems may include a
variety of treatment processes, ranging from lagooning to
advanced tertiary wastewater treatment technology for
removing nutrients. After processing, treated effluent may
be discharged to a receiving water environment (e.g., river,
lake, estuary, etc.), applied to soils, or disposed of below
the surface.
Nitrous oxide (N2O) may be generated during both
nitrification and denitrification of the nitrogen that is
present, usually in the form of urea and proteins. Some of
these primary nitrogen-containing compounds are rapidly
broken down to ammonia-nitrogen while others persist as
organic nitrogen. Both forms are converted to nitrate via
nitrification, an aerobic process converting ammonia-
nitrogen into nitrate (NCy). Denitrification occurs under
anoxic conditions (without free oxygen), and involves the
biological conversion of nitrate into dinitrogen gas (N2).
Nitrous oxide (N2O) can be an intermediate product of
table 7-9: N,0 Emissions from Human Sewage
*• i
- Year
... 1990
1995
1996
;iL.1997
-- 1998
1999
lf 2000
tgC02E(|.
7.0
7.7
7.8
7.9
8.1
8.4
8.5
Gg
'23
25
25
26
26
27
27
both processes, but is more often associated with
denitrification. In general, temperature,; pH/alkalinity,
biochemical oxygen demand (BOD), and nitrogen
concentration affect N2O generation from domestic
• wastewater treatment processes, while the amount of
; protein consumed by humans determines the quantity of
nitrogen contained in sewage. Emissions of N2O from
sewage nitrogen discharged into aquatic environments
were estimated to be 8.5 Tg CO2 Eq. (27 Gg) in 2000.
; (See Table 7-9). ;
Methodology
Nitrous oxide emissions from human sewage effluent
disposal were estimated using the IPCC default
methodology (IPCC/UNEP/OECD/IEA 1997) with one
modification. The IPCC methodology assumes that
nitrogen disposal and thus N2O emissions -associated with
: land disposal, subsurface disposal, as well as sewage
: treatment are negligible and all sewage nitrogen is
discharged directly into aquatic environments. In the
, United States, however, a certain amount of sewage
nitrogen is incinerated or applied to soils or landfills via
sewage sludge applications, and therefore^, not all sewage
J nitrogen enters aquatic environments.;6 The nitrogen
disposal into aquatic environments is reduced to account
i for the sewage sludge application.
6 The IPCC methodology is based on the total amount of nitrogen in sewage, which is in turn based on human protein consumption and the fraction of
nitrogen in protein (i.e., FracNPR). Aportion of the total nitrogen in sewage in the United States is incinerated or applied to soils or, landfills in the form
of sewage sludge each year. This amount is subtracted here from total nitrogen in human sewage to estimate sewage N2O emissions. The amount
applied to soils is estimated as part of agricultural soil management (see Chapter 6). ;
7-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
With the modification described above, N2O emissions
from human sewage were estimated using the IPCC default
methodology (IPCC/UNEP/OECD/IEA 1997). This
methodology is illustrated below:
N2O(s) = {[(Protein) x (Frac^) x (U.S. Population)]
where,
N2O(s) = N2O emissions from human sewage
Protein = Annual, per capita protein consumption
Frac^ = Fraction of nitrogen in protein
Nstadge = Quantity of sewage sludge N not entering
aquatic envkonments
EF = Emission factor (kg N20-N/kg sewage-N
produced)
("%„) = The molecular weight ratio of N2O to N2
Data Sources
U.S. population data were taken from the U.S. Census
Bureau (2001). Data on annual per capita protein
consumption were provided by the United Nations Food
and Agriculture Organization (FAO 2001) (see Table 7-10).
Because data on protein intake were unavailable for 2000,
the value of per capita protein consumption for the previous
year was used. An emission factor has not been specifically
estimated for the United States, so the default IPCC value
(0.01 kg N2O-N/kg sewage-N produced) was applied.
Similarly, the fraction of nitrogen in protein (0.16 kg N/
kg protein) was also obtained from IPCC/UNEP/OECD/
IEA (1997).
Uncertainty
The U.S. population, per capita protein intake data
(Protein), and fraction of nitrogen in protein (Frac^) are
believed to be fairly accurate. Significant uncertainty exists,
however, in the emission factor (EF). This uncertainty is
due to regional differences in the receiving waters that would
likely affect N2O emissions but are not accounted for in the
default IPCC factor. Moreover, the underlying
methodological assumption that negligible N2O emissions
result from sewage treatment may be incorrect. A related
uncertainty results from assuming all sewage nitrogen is
discharged directly into aquatic environments. Although the
above methodology takes this into account for a portion of
emissions, there are additional discharge pathways that need
to be investigated. Taken together, these uncertainties present
significant difficulties in estimating N2O emissions from
human sewage.7
Waste Sources of Ambient Air
Pollutants
In addition to the main greenhouse gases addressed
above, waste generating and handling processes are also
sources of criteria air pollutant emissions. Total emissions
of nitrogen oxides (NOx), carbon monoxide (CO), and
nonmethane volatile organic compounds (NMVOCs) from
waste sources for the years 1990 through 2000 are provided
in Table 7-11.
Methodology and Data Sources
These emission estimates were taken directly from the
EPA (2001). This EPA report provides emission estimates
of these gases by sector, using a "top down" estimating
procedure—emissions were calculated either for individual
sources or for many sources combined, using basic activity
data (e.g., the amount of raw material processed) as an
indicator of emissions. National activity data were collected
for individual source categories from various agencies.
Table 7-10: U.S. Population (Millions) and Average
Protein Intake (kg/Person/Year)
• Year
•1990
. 1991
" 1992
1993
-1994
1995
-1996
-1997
11998
; 1999
i 2000
Population
252.2
255.5
258.8
262.1
265.4
268.7
272.0
275.3
278.6
281.9
285.2
Protein
39.2
39.8
40.0
40.2
41.2
40.6
40.7
41.0
41.1
41.9
41.9
' The 1999 protein consumption estimate was used as a proxy for the 2000 estimate, as these data are not yet available.
Waste 7-9
-------
Table 7-11: Emissions of NOX, CO, and NMVOC from Waste (Gg)
Gas/Source
NOX
Landfills
Wastewater Treatment
Waste Combustion3
Miscellaneous11
CO
Landfills
Wastewater Treatment
Waste Combustion3
Miscellaneous11
NMVOCs
Landfills
Wastewater Treatment
Waste Combustion3
Miscellaneous11
1990
83
+
4-
82
4-
979
1
4.
978
4-
895
58
57
222
558
t
will
F""
JL»
L'
a,,
^
pniiiliu
r
ii;
I"
«''
£#
r
|SI
&
i
f~
j
iiiLi ^jpip
,,,_:|
:;::3
V
• : ::i
• 4
•' "1
" 6
1
:-; ..:|
.,
•L r. !',i
1995
89
1
+
88
1
1,075
2
+
1,073
1
968
68
61
237
602
1996
78
2
4.
75
1
3,215
5
4.
3,210
4.
508
32
61
352
64
1997
78
2
4.
75
1
3,217
5
4.
3,211
4.
509
32
62
352
64
1998
79
2
4.
76
1
3,220
5
4.
3,214
4.
513
33
63
353
65
1999
79
2
4.
76
1
3,220
5
4.
3,214
+
518
33
64
354
67
2000
81
2
+
78
1
3,273
5
4.
3,268
+
528
34
65
360
69
* Includes waste incineration and open burning (EPA 2001)
b Miscellaneous includes TSDFs (Treatment, Storage, and Disposal Facilities under the Resource Conservation and Recovery Act [42 U.S.G. § 6924,
SWDAi 3004]) and other waste categories.
Note: Totals may notsum due to independent rounding.
+ Does not exceed 0.5 Gg
Depending on the source category, these basic activity data
may include data on production, fuel deliveries, raw material
processed, etc.
Activity data were used in conjunction with emission
factors, which relate the quantity of emissions to the activity.
Emission factors are generally available from the EPA's
Compilation of Air Pollutant Emission Factors, AP-42 (EPA
1997). The EPA currently derives the overall emission
control efficiency of a source category from a variety of
information sources, including published reports, the 1985
National Acid Precipitation and Assessment Program
emissions inventory, and other EPA databases.
Uncertainty
Uncertainties in these estimates are primarily due to
the accuracy of the emission factors used and accurate
estimates of activity data. :
7-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
8. References
Executive Summary
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Analysis, National Income and Product Accounts. August
2001.
EIA (2001) Annual Energy Review 2000 and other EIA data.
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.
WMO (1999) Scientific Assessment of Ozone Depletion,
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References 8-1
-------
Changes in this Year's Inventory
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8-36 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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Annexes
The following twenty-six annexes provide additional information to the material presented in the main
body of this report. Annexes A through O discuss methodologies for individual source categories in greater detail
than was presented in the main body of the report and include explicit activity data and emission factor tables.
Annex P analyzies the key sources in this report. Annex Q presents a summary of Global Warming Potential values.
Annexes R and S summarize U.S. emissions of ozone depleting substances (e.g., CFCs and HCFCs) and sulfur
dioxide (SO2), respectively. Annex T provides a complete list of emission sources assessed in this report. Annex U
presents the IPCC reference approach for estimating CO2 emissions from fossil fuel combustion. Annex V
addresses the criteria for the inclusion of an emission source category and some of the sources that meet the criteria
but are nonetheless excluded from U.S. estimates. Annex W provides some useful constants, unit definitions, and
conversions. Annexes X and Y provide a listing of abbreviations and chemical symbols used. Finally, Annex Z
contains a glossary of terms related to greenhouse gas emissions and inventories.
List of Annexes
ANNEX A Methodology for Estimating Emissions of COz from Fossil Fuel Combustion
ANNEX B Methodology for Estimating Carbon Stored in Products from Non-Energy Uses of Fossil Fuels
ANNEX C Methodology for Estimating Emissions of CHt, NaO, and Ambient Air Pollutants from Stationary Combustion
ANNEX D Methodology for Estimating Emissions of CHi, NzO, and Ambient Air Pollutants from Mobile Combustion
ANNEX E Methodology for Estimating CHU Emissions from Coal Mining
ANNEX F Methodology for Estimating ChU Emissions from Natural Gas Systems
ANNEX G Methodology for Estimating CH4 Emissions from Petroleum Systems
ANNEX H Methodology for Estimating COa Emissions from Municipal Solid Waste Combustion
ANNEX I Methodology for Estimating Emissions from International Bunker Fuels used by the U.S. Military
ANNEX J Methodology for Estimating HFC, PFC, and SFe Emissions from Substitution of Ozone Depleting Substances
ANNEX K Methodology for Estimating CH4 Emissions from Enteric Fermentation
ANNEX L Methodology for Estimating CH4 and NaO Emissions from Manure Management
ANNEX M Methodology for Estimating NzO Emissions from Agricultural Soil Management
ANNEX N Methodology for Estimating COz Emissions and Sinks from Forest Carbon Stocks
ANNEX 0 Methodology for Estimating ChU Emissions from Landfills
ANNEX P Key Source Analysis
ANNEX Q Global Warming Potential Values
ANNEX R Ozone Depleting Substance Emissions
ANNEX S Sulfur Dioxide Emissions
ANNEX T Complete List of Source Categories
ANNEX U IPCC Reference Approach for Estimating COz Emissions from Fossil Fuel Combustion
ANNEX V Sources of Greenhouse Gas Emissions Excluded
ANNEX W Constants, Units, and Conversions
ANNEX X Abbreviations
ANNEX Y Chemical Formulas
ANNEX Z Glossary __^___^
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ANNEX A
Methodology for Estimating Emissions of C02 from Fossil Fuel Combustion
Carbon dioxide (CO2) emissions from fossil fuel combustion were estimated using a "bottom-up"
methodology characterized by six steps. These steps are described below.
Step 1: Determine Energy Consumption by Fuel Type and Sector
The bottom-up methodology used by the United States for estimating CC>2 emissions from fossil fuel
combustion is conceptually similar to the approach recommended by the Intergovernmental Panel on Climate
Change (IPCC) for countries that intend to develop detailed, sectoral-based emission estimates
(IPCC/UNEP/OECD/IEA 1997). Basic consumption data are presented in Columns 2-8 of Table A-l through Table
A- 11, with totals by fuel type in Column 8 and totals by end-use sector in the last rows. Fuel consumption data for
the bottom-up approach were obtained directly from the Energy Information Administration (EIA) of the U.S.
Department of Energy. These data were first gathered in physical units, and then converted to their energy
equivalents (see "Converting Physical Units to Energy Units" in Annex W). The EIA data were collected through a
variety of consumption surveys at the point of delivery or use and qualified with survey data on fuel production,
imports, exports, and stock changes. Individual data elements were supplied by a variety of sources within EIA.
Most information was taken from published reports, although some data were drawn from unpublished energy
studies and databases maintained by EIA.
Energy consumption data were aggregated by sector (i.e., residential, commercial, industrial,
transportation, electricity generation, and U.S. territories), primary fuel type (e.g., coal, natural gas, and petroleum),
and secondary fuel type (e.g., motor gasoline, distillate fuel, etc.). The 2000 total energy consumption across all
sectors, including territories, and energy types was 83,610 trillion British thermal units (TBtu), as indicated in the
last entry of Column 8 in Table A-l. This total includes fuel used for non-energy purposes and fuel consumed as
international bunkers, both of which are deducted in later steps.
Fuel consumption data for electricity generation data by nonutility power producers are initially categorized
by the EIA as part of the industrial sector. These data are then combined with fuel consumption by electric utilities
to form the electricity generation sector. The method for this reallocation is described in detail in EIA's report on
U.S. GHG emissions, Emissions of Greenhouse Gases in the United States, 2000 (EIA 2001c).
• There were a number of modifications made in this report that may cause consumption information herein
to differ from figures given in the cited literature. These are 1) the reallocation of some coking coal, petroleum
coke, and natural gas consumption for ammonia production to the Industrial Processes chapter, 2) corrections for
synthetic natural gas production, 3) corrections for ethanol added to motor gasoline, and 4) corrections for biogas in
natural gas.
First, portions of the fuel consumption data for three fuel categories—coking coal, petroleum coke, and
natural gas—were reallocated to the Industrial Processes chapter, as these portions were actually consumed as raw
material during non-energy related industrial processes. Coking coal, also called "coal coke," is used as a raw
material (specifically as a reducing agent) in the blast furnace process to produce iron and steel, and therefore is not
used as a fuel for this process. Similarly, petroleum coke is used in multiple processes as a raw material, and is thus
not used as a fuel in those applications. The processes in which petroleum coke is used include 1) ferroalloy
production, 2) aluminum production (for the production of carbon anodes and cathodes), and 3) titanium dioxide
production (in the chloride process). Finally, natural gas consumption is used for the production of ammonia.
Consumption of these fuels for non-energy purposes is presented in the Industrial Processes chapter, and is removed
from the energy and non-energy consumption estimates within the Energy chapter. ..
Second, a portion of industrial coal accounted for in EIA combustion figures is actually used to make
"synthetic natural gas" via coal gasification. The energy in this gas enters the natural gas stream, and is accounted
for in natural gas consumption statistics. Because this energy is already accounted for as natural gas, it is deducted
from industrial coal consumption to avoid double counting. This makes the figure for other industrial coal
consumption in this report slightly lower than most EIA sources.
A-1
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Third, ethanol has been added to the motor gasoline stream for several years, but prior to 199? this addition
was not captured in EIA motor gasoline statistics. Starting in 1993, ethanol was included in gasoline statistics.
However, because ethanol is a biofuel, which is assumed to result in no net CO2 emissions, the amount of ethanol
added is subtracted from total gasoline consumption. .Thus, motor gasoline consumption statistics!given in this
report may be slightly lower than in EIA sources. i '•
Fourth, EIA natural gas consumption statistics include "biomass gas," which is upgraded landfill methane
that is sold to pipelines. However, because this gas is biogenic, the biomass gas total is deducted from natural gas
consumption. The subtraction is done only from natural gas in the industrial sector, as opposed to all end-sectors,
because the biogas amount is small. Due to this adjustment-and the ammonia adjustment mentioned previously-
industrial natural gas consumption in this report is slightly lower than in EIA sources.
There are also three basic differences between the consumption figures presented in Table A-l through
Table A-l 1 and those recommended in the IPCC emission inventory methodology.
First, consumption data in the U.S. inventory are presented using higher heating values (HHV)1 rather than
the lower heating values (LHV)2 reflected in the IPCC emission inventory methodology. This convention is
followed because data obtained from EIA are based on HHV. Of note, however, is that EIA renewable energy
statistics are often published using LHV. The difference between the two conventions relates to the treatment of the
heat energy that is consumed in the process of evaporating the water contained in the fuel. The simplified
convention used by the International Energy Agency for converting from HHV to LHV is to multiply the energy
content by 0.95 for petroleum and coal and by 0.9 for natural gas.
Second, while EIA's energy use data for the United States includes only the 50 U.S. states and the District
of Columbia, the data reported to the Framework Convention on Climate Change are to include energy consumption
within territories. Therefore, consumption estimates for U.S. territories were added to domestic consumption of
fossil fuels. Energy consumption data from U.S. territories are presented in Column 7 of Table A-l through Table
A- 11. It is reported separately from domestic sectoral consumption, because it is collected separately by EIA with
no sectoral disaggregation. < ;
Third, the domestic sectoral consumption data in Table A-l through Table A- 11 include bunker fuels used
for international transport activities and non-energy uses of fossil fuels. The IPCC requires countries to estimate
emissions from international bunker fuels separately and exclude these emissions from national totals, so
international bunker fuel emissions have been estimated in Table A-12 and deducted from national estimates (see
Step 4). Similarly, fossil fuels used to produce non-energy products that store carbon rather than release it to the
atmosphere are provided in Table A- 13 and deducted from national emission estimates (see Step 3). The final fate
of these fossil fuel based products is dealt with under the waste combustion source category in cases where the
products are combusted through waste management practices.
1
Step 2: Determine the Carbon Content of All Fuels
The carbon content of combusted fossil fuels was estimated by multiplying energy consumption (Columns
2 through 8 of Table A-l through Table A- 11) by fuel-specific carbon content coefficients (see Table A-14 and
Table A-15) that reflect the amount of carbon per unit ;of energy in each fuel. The resulting carbon contents are
sometimes referred to as potential emissions, or the maximum amount of carbon that could potentially be released to
the atmosphere if all carbon in the fuels were oxidized. ;The carbon content coefficients used in the U.S. inventory
were derived by EIA from detailed fuel information and are similar to the carbon content coefficients contained in
the IPCC's default methodology (IPCC/UNEP/OECD/IEA 1997), with modifications reflecting fuel qualities
specific to the United States. I
t
Step 3: Adjust for the amount of Carbon Stored in Products
Depending on the end-use, non-energy uses of fossil fuels can result in long term storage of some or all of
the carbon contained in the fuel. For example, asphalt made from petroleum can sequester up to 100 percent of the
1 Also referred to as Gross Calorific Values (GCV).
2 Also referred to as Net Calorific Values (NCV).
A-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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carbon contained in the petroleum feedstock for extended periods of time. Other non-energy fossil fuel products,
such as lubricants or plastics also store carbon, but can lose or emit some of this carbon when they are used and/or
burned as waste.3
The amount of carbon in non-energy fossil fuel products was based upon data that addressed the fraction of
carbon that remains in products after they are manufactured, with all non-energy use attributed to the industrial,
transportation, and territories end-use sectors. This non-energy consumption is presented in Table A- 13. This data
were then multiplied by fuel-specific carbon content coefficients (Table A-14 and Table A-15) to obtain the carbon
content of the fuel, or the maximum amount of carbon that could remain in non-energy products (Column 4 of Table
A- 13). This carbon content was then multiplied by the fraction of carbon assumed to actually have remained in
products (Column 5 of Table A- 13), resulting in the final estimates by sector and fuel type, which are presented in
Column 6 of Table A- 13. A detailed discussion of carbon stored in products is provided in the Energy chapter and
in Annex B.
Step 4: Subtract Carbon in International Bunker Fuels
Emissions from international transport activities, or international bunker fuel consumption, are not included
in national totals, as required by the IPCC (IPCC/UNEP/OECD/IEA 1997). There is currently disagreement
internationally as to how these emissions should be allocated, and until this issue is resolved, countries are asked to
report them separately. EIA energy statistics, however, include these bunker fuels—-jet fuel for aircraft, and
distillate fuel oil and residual fuel oil for marine shipping—as part of fuel consumption by the transportation end-use
sector. To compensate for this inclusion, international bunker fuel emissions4 were calculated separately (see Table
A-12) and the carbon content of these fuels was subtracted from the transportation end-use sector. International
bunker fuel emissions from military activities were developed using data provided by the Department of Defense as
described in the International Bunker Fuels section of the Energy chapter and in Annex I. The calculations of
international bunker fuel emissions followed the same procedures used for other fuel emissions (i.e., estimation of
consumption, determination of carbon content, and adjustment for the fraction of carbon not oxidized).
Step 5: Account for Carbon that Does Not Oxidize During Combustion
Because combustion processes are not 100 percent efficient, some of the carbon contained in fuels is not
emitted in a gaseous form to the atmosphere. Rather, it remains behind as soot, particulate matter and ash. The
estimated fraction of carbon not oxidized in U.S. energy conversion processes due to inefficiencies during
combustion ranges from 0.5 percent for natural gas to 1 percent for petroleum and coal. Except for coal these
assumptions are consistent with the default values recommended by the IPCC (IPCC/UNEP/OECD/IEA 1997). In
the United States, unoxidized carbon from coal combustion was estimated to be no more than one percent (Bechtel
1993).
Table A-14 presents fractions oxidized by fuel type, which are multiplied by the net carbon content of the
combusted energy to give final emissions estimates.
Of the fraction of carbon that is oxidized (e.g., 99 to 99.5 percent), the vast majority is emitted in its fully
oxidized form as carbon dioxide (CO2). A much smaller portion of this "oxidized" carbon is also emitted as carbon
monoxide (CO), methane (CH4), and non-methane volatile organic compounds (NMVOCs). These partially
oxidized or unoxidized carbon compounds when in the atmosphere, though, are generally oxidized to CO2 through
atmospheric processes (e.g., reaction with hydroxyl (OH)).5
3 See Waste Combustion section of the Energy chapter for a discussion of emissions from the combustion of plastics in
the municipal solid waste stream.
4 Refer to the International Bunker Fuels section of the Energy chapter for a description of the methodology for
distinguishing between bunker and non-bunker fuel consumption.
5 See indirect CO2 from CH4 oxidation section in Energy chapter for a discussion of proper accounting of carbon from
hydrocarbon and CO emissions.
A-3
-------
Step 6: Summarize Emission Estimates
Actual CO2 emissions in the United States were summarized by major fuel (i.e., coal, petroleum, natural
gas, geothermal) and consuming sector (i.e., residential, commercial, industrial, transportation, electricity
generation, and U.S. territories). Adjustments for international bunker fuels and carbon in non-energy products were
made. Emission estimates are expressed in teragrams 0f carbon dioxide equivalents (Tg CO2 Eq.).
To determine total emissions by final end-use sector, emissions from electricity generation were distributed
to each end-use sector according to its share of aggregate electricity consumption (see Table A-16). This pro-rated
approach to allocating emissions from electricity generation may overestimate or underestimate emissions for
particular sectors due to differences in the average carbon content of fuel mixes burned to generate electricity.
A-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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Taile A-12:2000 COz Emissiins From International Banker Fuel Consumption
Fuel Type
Distillate Fuel Oil
Jet Fuel
Residual Fuel Oil
Total
Bunker Fuel Carbon Content
Consumption Coefficient
(TBtu) (Tg Carbon/QBtu)1
115 19.95
816 19.33
444 21.49
1,375
Potential
Emissions (Tg Fraction
Carbon) Oxidized
2.3 0.99
15.8 0.99
9.5 0.99
27.6
Emissions ,
(TqCOzEq.)
8.3
57.3
34.6
100.2
Note: See Annex I for additional information on military bunkers.
Table A-13: 2000 Carbon In Hen-Energy Products
1
Fuel Type
Industry
Industrial Coking Coal
Natural Gas
Asphalt & Road Oil
LPG
Lubricants
Pentanes Plus
2 3
4
Carbon Content Potential
Non-energy Use Coefficient Emissions
(TBtu) (Tg Carbon/QBtu) (Tg Carbon)
5,512.4
26.4 !
342.4
1,275.7
1,707.3
189.9
286.8
103.6
25.56 0.7
14.47 5.0
20.62 26.3
16.87 28.8
20.24 3.8
18.24 5.2
5
6
Fraction Carbon Stored (Tg
Sequestered" COz Eq.)
0.75
0.63
1.00
0.63
0.09
0.63
265.6
1.9
11.5
96.4
66.8
1.3
12.1
Petrochemical Feedstocks
Naphtha (<401 deg. F)
Other Oil (>401 deg. F)
Still Gas
Petroleum Coke
Special Naphtha
Other (Wax/Misc.)
Distillate Fuel Oil
Residual Fuel
Waxes
Miscellaneous
Transportation
Lubricants
U.S. Territories
Lubricants
Other Petroleum (Misc.)
Total
564.2
664.1
7.4
141.4
97.4
7.0 '
50.3
33.1
119.2
179.4
179.4
223.8
1.4
18.14 10.2
19.95 13.2
17.51 0.1
27.85 3.9
19.86 1.9
19.95 0.1
21.49 1.1
19.81 0.7
20.23 2.4
3.6
20.24 3.6
4.5
20.24 0.0
222.5 : variable 4.5
5,915.6
111.7
0.63
0.63
0.80
0.50
0.00
0.50
0.50
1.00
1.00
0.09
0.09
1.00
23.7
30.7
0.4
7.2
0.0
0.3
2.0
2.4
8.8
1.2
1.2
16.5
0.0
16.5
283.4
'See Annex B for additional information.
' One QBtu is one quadrillion Btu, or 1015 Btu. This unit is commonly referred to as a "Quad."
A-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table A-14: Key Assumptions for Estimating Carbon Dioxide Emissions
Carbon Content Coefficient
(Tg Carbon/QBtu) Fraction Oxidized
Coal
Residential Coal
Commercial Coal
Industrial Coking Coal
Industrial Other Coal
Coke Imports
Transportation Coal
Utility Coal
U.S. Territory Coal (bit)
Natural Gas
Petroleum
Asphalt & Road Oil
Aviation Gasoline
Distillate Fuel Oil
Jet Fuel
Kerosene
LPG
LPG (energy use/Territories)
LPG (non-energy use)
Lubricants
Motor Gasoline
Residual Fuel
Other Petroleum
AvGas Blend Components
Crude Oil
MoGas Blend Components
Misc. Products
Misc. Products (Territories)
Naphtha (<401 deg. F)
Other Oil (>401deg.F)
Pentanes Plus
Petrochemical Feedstocks
Petroleum Coke
Still Gas
Special Naphtha
Unfinished Oils
Waxes
Other Wax & Misc.
Geothermal
[a]
[a]
[a]
[a]
27.85
NC
[a]
25.14
14.47
20.62
18.87
19.95
[a]
19.72
[a]
[a]
[a]
20.24
[a]
21.49
18.87
[a]
[a]
[a]
variable
18.14
19.95
18.24
19.37
27.85
17.51
19.86
[a]
19.81
19.81
2.05
0.99
0.99
0.99
0.99
0.99
NC
0.99
0.99
0.995
0.99
0.99
0.99
0.99
0.99
0.99
0.99
-
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
1.00
vjKmiiKimai *•••"•
Sources: Carbon coefficients from EIA. Combustion efficiency for coal from Bechlel (1993) and for petroleum and natural gas from IPCC
(IPCC/UNEP/OECD/IEA1997).
- Not applicable
NC (Not Calculated)
[a] These coefficients vary annually due to fluctuations in fuel quality (seeTable A-15).
A-17
-------
Table A-15: Annually Variable Carbon Content Coefficients by Year (Tg Carbon/QBtul
Fuel Type
Residential Coal
Commercial Coal
Industrial Coking Coal
Industrial Other Coal
Utility Coal
LPG
LPG (energy use/Territories)
LPG (non-energy use)
Motor Gasoline
Jet Fuel
MoGas Blend Components
Misc. Products
Unfinished 08s
Crude Oil
Source: EIA (2001 a) and EIA (2001 c)
1990
25.92
25.92
25.51
25.58
25.68
16.99
17.21
16.83
19.41
19.40
19.41
20.16
20.16
20.16
1991
26.00
26.00
25.51
25.59
25.69
16.98
17.21
16.84
19.41
19.40
19.41
20.18
20.18
20.18
1992
26.13
26.13
25.51
25.62
25.69
16.99
17.21
16.84
19.42
19.39
19.42
20.22
20.22
20.22
i 1993
25.97
! 25.97
! 25.51
25.61
i 25.71
16.97
1 17,22
1 16.80
i 19.43
i 19.37
! 19.43
; 20.22
! 20.22
i 20.22
1994
25.95
25.95
25.52
25.63
25.72
17.01
17.22
16.88
19.45
19.35
19.45
20.21
20.21
20.21
1995
26.00
26.00
25.53
25.63
25.74
17.00
17.20
16.87
19.38
19.34
19.38
20.23
20.23
20.23
1996
25.92
25.92
25.55
25.61
25.74
16.99
17.20
16.86
19.36
19.33
19.36
20.25
20.25
20.25
1997
26.00
26.00
25.56
25.63
25.76
16.99
17.18
16.88
19.35
19.33
19.35
20.24
20.24
20.24
1998
26.00
26.00
25.56
25.63
25.76
16.99
17.18
16.87
19.33
19.33
19.33
20.24
20.24.
20.24
1999
26.00
26.00
25.56
25.63
25.76
16.99
17.18
16.88
19.33
19.33
19.33
20.19
20.19
20.19
2000
26.00
26.00
25.56
25.63
25.76
16.99
17.18
16.87
19.34
19.33
19.34
20.23
20.23
20.23
Table A-16: Electricity Consumption by End-Use Sector (Billion Kilowatt-Hours)
End-Use Sector 1990
Residential 924
Commercial 839
Industrial 946
Transportation 4
U.S. Territories'
Total 2,713
1991
955
856
947
4
-
2,762
1992
936
851
973
4
-
2,763
1993
995
886
977
4
-
2,861
1994
1,008
i 914
i 1,008
1 4
!
2,935
1995
1,043
954
1,013
4
.
3,013
1996
1,
1,
083
981
034
4
-
3,101
'EIA data on fuel consumption for electricity generation does not include the U.S. territories.
- Not applicable
Source: EIA (2001a)
I
i
i
1
1
i
1997
1,076
1,028
1,038
4
.
3,146
1998
1,130
1,079
1,051
4
.
3,264
1999
1,145
1,105
1,058
4
3,312
2000
1,192
1,135
1,068
4
3,398
A-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX B
Methodology for Estimating Carbon Stored in Products from Non-Energy Uses of
Fossil Fuels
Carbon storage associated with the non-energy use of fossil fuels was calculated by multiplying each fuel's
potential emissions (i.e., each fuel's total carbon content) by a fuel-specific storage factor. This Annex explains the
methods and data sources employed in developing the storage factors for asphalt and road oil, lubricants,
petrochemical feedstocks, liquefied petroleum gases (LPG), pentanes plus, and natural gas used for chemical
manufacturing plant feedstocks (i.e., not used as fuel.) The storage factors for the remaining non-energy fuel uses
are based on values reported by Marland and Rotty (1984).
Table B-11: Fuel Types and Percent of Cardan Stored for Non-Energy Uses
Fuel Type
Industrial Coking Coal3
Natural Gas to Chemical Plants
Nitrogenous Fertilizers
Other Uses
Asphalt & Road Oil
Liquefied Petroleum Gas (LPG)
Lubricants
Penlanes Plus
Petrochemical Feedstocks
Naphtha (b.p.<401° F)
Other Oil (b.p.>40r F)
Petroleum Cokeb
Special Naphtha
Other
Distillate Fuel Oil
Residual Fuel
Waxes
Miscellaneous Products
Storage Factor
75%
63%
100%
63%
9%
63%
63%
63%
50%
50%
50%
100%
100%
- Not applicable
a Includes processes for which specific coking coal consumption and emission factor data are not available. Consumption of coking coal for
production of iron and steel is covered in the Industrial Processes chapter.
" Includes processes for which specific petroleum coke consumption and emission factor data are not available (e.g., carbon fibers and textiles,
refractory, electric motor parts, brake parts, batteries). Consumption of petroleum coke for production of primary aluminum anodes, electric arc
furnace anodes, titanium dioxide, and ferroalloys is covered in the Industrial Processes chapter.
The following sections describe the selected non-energy uses in greater detail, outlining the methods
employed and data used in estimating each storage factor. Several of the fuel types tracked by EIA—petrochemical
feedstocks, pentanes plus, LPG, and natural gas—are used in organic chemical synthesis and in other manufacturing
processes. Because the methods and data used to analyze them overlap, they are handled as a group and are
discussed first. Discussions of the storage factors for asphalt and road oil and lubricants follow.
B-1
-------
Petrochemical Feedstocks, Pentanes Plus, Liquefied Petroleum Gases, and Natural Gas
Petrochemical feedstocks, pentanes plus, liquefied petroleum gases (LPG) and natural gas1 are used in the
manufacture of a wide variety of man-made chemicals and products. Plastics, rubber, synthetic fibers, solvents,
paints, fertilizers, Pharmaceuticals, and food additives are just a few of the derivatives of these four fuel types.
Chemically speaking, these fuels are diverse, ranging from simple natural gas (i.e., predominantly methane, CH4) to
heavier, more complex naphthas and other oils.2 The! storage factor for petrochemical feedstocks, pentanes plus,
LPG, and natural gas used for purposes other than fuel is estimated based on data for the year 1998, which is the
latest year for which data are available from several key data sources concerning consumption for non-fuel uses.
The four fuel categories constituted approximately 234.2 Tg CO2 Eq., or 49 percent, of the 478.22 Tg CO2
Eq. of non-energy fuel consumption in 1998 (including net exports of petrochemical feedstocks). Of this amount for
the four fuels, 18.8 Tg CO2 Eq. was exported, resulting in a net U.S. consumption of 215.4 Tg CO2 Eq. in 1998. Of
this net consumption, 136.3 Tg CO2 Eq. ended up stored in products—including products subsequently combusted
for waste disposal—while the remaining 79.1 Tg CO2 Eq. was emitted to the atmosphere directly as CO2 (e.g.,
through combustion of industrial byproducts) or indirectly as CO2 precursors (e.g., through evaporative product
use). The indirect emissions include a variety of organic gases such as volatile organic compounds (VOCs) and
carbon monoxide (CO), which eventually oxidize into CO2 in the atmosphere. For 1998 the storage factor for the
four fuel categories was 63.3 percent; this factor was assumed to remain constant. The derivation of the storage
factor is described in the following sections.
Methodology and Data Sources
An empirically determined storage factor was Developed for the carbon consumed for non-energy end uses
of petrochemical feedstocks, pentanes plus, LPG, and natural gas (henceforth referred to as feedstocks). The storage
factor is equal to the ratio of carbon stored in the final products to total carbon content for the non-energy fossil fuel
feedstocks used in industrial processes, after adjusting for net exports of feedstocks. Only one aggregate storage
factor was calculated for the four fuel feedstock types. The feedstocks were grouped because of the overlap of their
derivative products. Due to the many reaction pathways involved in producing petrochemical products (or wastes),
it becomes extraordinarily complex to link individual prbducts (or wastes) to their parent fuel feedstocks.
Import and export data for feedstocks were obtained from the Energy Information Administration (EIA)
and from the National Petroleum Refiners Association (NPRA) for the major categories of petrochemical feedstocks
(EIA 2001a, NPRA 2001). The EIA tracks imports and exports of petrochemical feedstocks in its publication
Petroleum Supply Annual (EIA 2001c), including butanes, butylenes, ethane, ethylene, propane, propylene, LPG,
and naphthas (i.e., most of the large volume primary chemicals produced by petroleum refineries). These imports
and exports are already factored into the U.S. fuel consumption statistics. However, EIA does not track imports and
exports of chemical intermediates and products produced by the chemical industry (e.g., xylenes, vinyl chloride, and
polypropylene resins), which were derived from the primary chemicals produced by the refineries. For these
products, the NPRA data were used. NPRA notes that their data set does not cover all imports and exports, due to
the extremely broad range of products and the large number of importers and exporters; they estimate that their data
set accounts for roughly 75 percent of the total mass imports and exports of feedstocks. Therefore, after calculating
the net carbon flows from the NPRA data, the estimate was adjusted (i.e., by 100/75, or 1.33) to account for 100
percent of the total. Overall, the United States is a net exporter of chemical intermediates and products. Net exports
of these materials amounted to 18.8TgCO2in 1998, corresponding to 8 percent of the total domestic fuel feedstocks
production of 234.2 Tg CO2. Net domestic consumption of fuel feedstocks (i.e., adjusted for net exports of
intermediates and products) amounted to 215.4 Tg CO2 in 1998.
The overall storage factor for the feedstocks was determined by developing a mass balance on the carbon in
feedstocks, and characterizing products, uses, and environmental releases as resulting in either storage !or emissions.
1 Natural gas has two categories of non-energy consumption: for fertilizer and for other chemical syntheses. Only
natural gas that is supplied to chemical plants for other uses is included here. Natural gas used for fertilizer is not included
because it covered in the Industrial Processes chapter. ;
2 Naphthas are compounds distilled from petroleum containing 4 to 12 carbon atoms per molecule and having a boiling
point less than 401° F. Other oils are distillates containing 12 io 25 carbon atoms per molecule and having a boiling point preater
than401°F. [
B-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
The total carbon in the system is estimated by multiplying net domestic consumption—reported by EIA and then
adjusted by assuming 8 percent net exports—by the carbon content of each of the feedstocks (i.e., petrochemical
feedstocks-naptha, petrochemical feedstocks-other oils, LPG, pentanes plus, natural gas). Carbon content values for
the fuel feedstocks are discussed in Annex A.
Next, carbon pools and releases in a variety of products and processes were characterized. Plastics,
synthetic rubber, synthetic fibers, carbon black, industrial non-methane volatile organic compound (NMVOC)
emissions, industrial toxic chemical (i.e., TRI) releases, pesticides, and organic solvents were identified as the major
product categories.3
The carbon in each product or waste produced was categorized as either stored or emitted. The aggregate
storage factor is the carbon-weighted average of storage across fuel types. As discussed later in the section on
uncertainty, data were not available for all of the non-energy end uses of fuel feedstocks, so the uses analyzed
represent a sample of the total carbon consumed. The sample accounts for 195.0 Tg CO2Eq., or 91 percent, of the
215.4 Tg CO2 Eq. of carbon within these fuel feedstock types that is consumed for non-energy purposes. The
remaining 9 percent (18.8 Tg CO2 Eq.) that is "unaccounted for" is assumed to be emitted, not stored. The total
amount of carbon that is stored in products, including the amount subsequently lost to waste disposal, corresponds to
136.3 Tg CO2 Eq. Emissions of CO2 from waste disposal are accounted for separately in the Inventory and are
discussed in the Waste Combustion section of the Energy chapter.
The following sections provide details on the calculation steps, assumptions, and data sources employed in
estimating and classifying the carbon in each product and waste. Summing the carbon stored and dividing it by the
total fuel feedstock carbon used yields the overall storage factor, as shown in Table B-2 and the equation below.
The major products and their carbon contents are also shown in the Table.
Overall Storage Factor = Carbon Stored / Total Carbon = 136.3 Tg CO2Eq. / 215.4 Tg CO2 Eq. = 63.3%
Table B-2: Carbon Stored and Emitted by Products from Petrochemical Feedstocks, Pentanes Plus, LPG, and Natural
Gas in 19)98 [TgdhEn.l
Product/Waste Type
Plastics
Synthetic Rubber
Synthetic Fiber
Carbon Black
Pesticides
Industrial Releases
Industrial VOCs
TRI Releases
Non-Combustion CO
Solvent VOCs
Energy Recovery
Hazardous Waste Incin.
"Unaccounted for"*
Total
Carbon Stored
110.4
7.7
11.8
5.9
0.4
-
0.1
-
-
-
-
136.3
Carbon Emitted
-
-
-
•
0.2
-
4.0
1.0
1.3
9.2
41.1
1.9
20.4
79.1
- Not applicable
* Unaccounted for carbon was assumed to be emitted.
Note: Totals may not sum due to independent rounding.
3 For the most part, the releases covered by the U.S. Toxic Release Inventory (TRI) represent air emissions or water
discharges associated with production facilities. Similarly, VOC emissions are generally associated with production facilities.
These emissions could have been accounted for as part of the Waste chapter, but because they are not necessarily associated with
waste management, they were included here. Toxic releases are not a "product" category, but they are referred to as such for ease
of discussion.
B-3
-------
Plastics
\
Data on annual production of plastics were taken from the American Plastics Council, as published in
Chemical & Engineering News and through direct copimunication with the APC (APC 2000, Eldredge-Roebuck
2000). These data were organized by year and resin type (see Table B-3). A carbon content was assigned for each
resin. These contents were based on molecular formulas and are listed in Table B-4 and Table B-5. In cases where
the resin type is generic, referring to a group of chemicals and not a single polymer (e.g., phenolic resins, other
styrenic resins), a representative compound was chosen. For engineering resins and other resins, a weighted carbon
content of 65 percent was assumed (i.e., it was assumed that these resins had the same content as those for which a
representative compound could be assigned). i
There were no emissive uses of plastics identified, so 100 percent of the carbon was considered stored in
products. However, an estimate of emissions related to, the combustion of these plastics in the municipal solid waste
stream can be found in the Waste Combustion section of the Energy chapter.
Table B-3:1998 Plastic Resin Production (Tu dry weight) and Carbon Stared ITg Cft Eq.l
Resin Type 1998 Production a
Epoxy 0.29
Polyester (Unsaturated) 0.78
Urea
Melamine
Phenolic
Low-Density Polyethylene (LDPE)
Linear Low-Density Polyethylene (LLDPE)
High Density Polyethylene (HOPE)
Polypropylene (PP)
Acrylonilrile-butadiene-styrene(ABS)
Styrene-acrylonitrile (SAN)
Other Styrenics
Polystyrene (PS)
Nylon
Polyvinyl chloride (PVC) b
Thermoplastic Polyester
Engineering Resins
1.17
0.13
1.79
3.44
3.28
5.86
6.27
0.65
0.06
0.75
2.83
0.58
6.58
2.01
1.25
All Other ' 3.88
Total 41.59
Carbon Stored
0.8
1.8
1.5
0.1
5.0
10.8
10.3
18.4
19.7
2.0
0.2
2.5
9.6
1.4
9.3
4.6
3.0
9.4
110.4
* Includes production from Canada for ABS, SAN, PVC, PP, Phenolic, Urea, Melamine, and Thermoplastic Polyester
b Includes copolymers j
Note: Totals may not sum due to independent rounding. [
B-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table B 4: Assigned Carbon Contents of Plastic Resins [by weight)
Resin Type
Carbon
Content
Source of Carbon Content Assumption
Epoxy
Polyester (Unsaturated)
Urea
Melamine
Phenolic
Low-Density Polyethylene (LDPE)
Linear Low-Density Polyethylene (LLDPE)
High Density Polyethylene (HOPE)
Polypropylene (PP)
Acrylonitrile-Butadiene-Styrene(ABS)
Styrene-Acrylonitrile (SAN)
Other Styrenics
Polystyrene (PS)
Nylon
Polyvinyl Chloride (PVC)
Thermoplastic Polyester
Engineering Resins
All Other
76% Typical epoxy resin made from epichlorhydrin and bisphenol A
63% Poly (elhylene terepthalate) (PET)
34% 50% carbamal, 50% N-(hydroxymethyl) urea *
29% Trimethylol melamine *
77% Phenol
86% Polyethylene
86% Polyethylene
86% Polyethylene
86% Polypropylene
85% 50% styrene, 25% acrylonitrile, 25% butadiene
80% 50% styrene, 50% acrylonitrile
92% Polystyrene
92% Polystyrene
65% Average of nylon resins (see Table B-5)
38% Polyvinyl chloride
63% Polyethylene terephthalate
s 66% Weighted average of other resin production
66% Weighted average of other resin production
'Does not include alcoholic hydrogens.
Table Bi-5: Major Nylon Resins and their Carbon Contents (by weight!
Resin
Carbon Content
Nylon 6
Nylon 6,6
Nylon 4
Nylon 6,10
Nylon 6,11
Nylon 6,12
Nylon 11
64%
64%
52%
68%
69%
70%
72%
Synthetic Rubber
Data on annual consumption of synthetic rubber were obtained from the International Institute of Synthetic
Rubber Producers (IISRP) press release "Synthetic Rubber Use Growth to Continue Through 2004, Says IISRP and
RMA" (IISRP 2000). Due to the fact that production data for synthetic rubber were unavailable, consumption was
assumed to equal production. These data were organized by year and elastomer type. A carbon content was
assigned for each elastomer type. These contents, based on stoichiometry, are listed in Table B-6. For the "Others"
category, a weighted carbon content was calculated from total 1998 consumption data.
There were no emissive uses of rubber identified, so 100 percent of the carbon was assumed stored.
However, emissions related to the combustion of scrap tires and rubber consumer goods can be found in the Waste
Combustion section of the Energy chapter.
B-5
-------
Table B-G:1998 Robber Gonsumptiin, Carbon Content, and Carban Stared
Elastomer Type
SBR Solid
Polybutadiene
EUiylene Propylene
Polychloroprene
NBR Solid
Polyisoprene
Others
Total
1998 Consumption
(Thousand Metric Tons) *
908
561!
320;
69,
87
ye;
369
2,392
Carbon
Content
91%
89%
86%
59%
77%
88%
88%
-
Carbon Stored
(TgCOzEq.)
3.0
1.8
1.0
0.1
0.2
0.3
1.2
7.7
* Includes consumption in Canada.
- Not applicable
Note: Totals may not sum due to independent rounding.
Synthetic Fibers [
Annual synthetic fiber production data were obtained from the Fiber Economics Bureau, as 'published in
Chemical & Engineering News and exhibited on the FiberSource website (FEE 2000). These data are organized by
year and fiber type. For each fiber, a carbon content was assigned based on stoichiometry (see Table B-7). For
polyester, the carbon content for poly(ethylene terephthalate) (PET) was used as a representative compound. For
nylon, the average carbon content of nylon 6 and nylon 6,6 was used, since these are the most widely produced
nylon fibers. Cellulosic fibers, such as acetate and rayon, have been omitted from the synthetic fibers' carbon
accounting because much of their carbon is of biogenic; origin. These fibers account for only 4 percent of overall
fiber production by weight.
There were no emissive uses of fibers identified, so 100 percent of the carbon was considered stored.
However, emissions related to the combustion of textiles in the municipal solid waste stream is accounted for under
the Waste Combustion section of the Energy chapter. !
Table B-7:1998 Fiber ProdDctien, Carben Cement and Carbon stored
Fiber Type
Polyester
Nylon
Olefin
Acrylic
Total
Carbon Stored
Production (Tq) Carbon Content fTq COz Eq.)
1.8
1.3
1.3
0.2
4.6
63% 4.1
64% 3.0
86% 4.1
68% 0.5
: - 11.7
• Not applicable
Note: Totals may not sum due to independent rounding
Carbon Black i
i
Carbon black is a finely divided solid form of carbon produced from the partial oxidation of heavy oil
fractions.4 It is used primarily in manufacture of tire trpads and other abrasion resistant rubber products, but can
also be used in pigments for paints and inks. In 1998, carbon black ranked 35th in chemical production in the United
States with 1,610,280 metric tons produced (CMA 1999). Since carbon black is essentially pure carbon, its carbon
content was assumed to be 100 percent. Also, since it is used in solid products and resists degradation, it was
considered 100 percent stored. For 1998, carbon stored as a result of carbon black production was estimated to be
5.9TgC02Eq. ;
Carbon black can also be produced from the cracking of natural gas, but this method is uncommon.
B-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Energy Recovery
The amount of fuel feedstocks that are combusted for energy recovery was estimated from data included in
EIA's Manufacturers Energy Consumption Survey (MEGS) for 1998 (EIA 2001b). Fuel feedstocks may be
combusted for energy recovery because the chemical reactions in which fuel feedstocks are used are not 100 percent
efficient. These chemical reactions may generate unreacted raw material feedstocks or generate byproducts that
have a high energy content. The chemical industry and many downstream industries are energy-intensive, and
therefore unreacted feedstocks or byproducts of production may be combusted for energy recovery in industrial
boilers. Also, hazardous waste regulations provide a strong incentive—and in some cases require—burning of
organic wastes generated from chemical production processes. Combustion of hazardous waste without energy
recovery is referred to as "incineration," and is discussed separately in this Annex.
MECS data include data on the consumption for energy recovery of "other" fuels in the petroleum and coal
products, chemicals, primary metals, nonmetallic minerals, and other manufacturing sectors. These "other" fuels
include refinery still gas; waste gas; waste oils, tars, and related materials; petroleum coke, coke oven and blast
furnace gases; and other uncharacterized fuels. Fuel use of petroleum coke is included separately in the fuel use
data provided annually by EIA, and energy recovery of coke oven gas and blast furnace gas (i.e., byproducts of the
iron and steel production process) is addressed in the Iron and Steel production section in the Industrial Processes
chapter. Consumption of refinery still gas and "other" fuels in the refinery sector is also included separately in the
fuel use data from EIA. Therefore these categories of "other" fuels are addressed elsewhere in the inventory and not
considered as part of the petrochemical feedstocks energy recovery discussion. The remaining categories of fuels
included in the 1998 MECS data (Table B-8) including waste gas; waste oils, tars, and related materials; and other
uncharacterized fuels are assumed to be petrochemical feedstocks burned for energy recovery. The conversion
factors listed in Annex A were used to convert the Btu values for each fuel feedstock to Tg CO2. Petrochemical
feedstocks combusted for energy recovery corresponded to 41.1 Tg CO2 Eq. in 1998.
Table B 8: Summary if 1998 MECS Data for Other Fuels used in Manufacturing/Energy Recovery [Trillion Btu)
Subsector and Industry
Printing and Related Support
Petroleum and Coal Products
Chemicals
Plastics and Rubber Products
Nonmetallic Mineral Products
Primary Metals
Fabricated Metal Products
Machinery
Computer and Electronic Products
Electrical Equipment, Appliances, Components
Transportation Equipment
Total
Carbon Content (Tg/QBTU)
Fraction Oxidized
Total Carbon (Tg)
Total Carijon (Non-Refining)
NAICS
Code
323
324
325
326
327
331
332
333
334
335
336
Waste
Gas"
0
0
416
0
2
2
1
0
0
1
1
423
18.1
99%
7.6
7.6
Waste
Oils/Tarsc
1
1
16
0
9
2
0
1
0
1
2
33
20.6
99%
0.7
0.7
Refinery
Still Gas"
0
1399
0
0
0
0
0
0
0
0
0
1399
17.5
99%
24.2
0.0
Net
Steam6
0
0
194
0
0
0
0
0
0
0
0
194
0
0%
0.0
0.0
Other
Fuels'-a
0
324a
118a
0
14
22
0
0
0
0
0
478
19.4
99%
9.2
3.0
a EIA personal communication, 2001.
b C content assumed to be naphtha <401F.
c C content assumed to be asphalt and road oil.
d Refinery "other" fuel consumption is reported elsewhere in the inventory and is excluded from the total carbon. The total non-refining
carbon excludes all "other" fuel consumption under NAICS Code 325 (Petroleum and Coal Products).
e Net steam is reported elsewhere in the inventory and is excluded from the total carbon content estimate.
'Assumed to be petrochemical feedstocks.
9 Includes net steam, except for NAICS Code 325 (Chemicals). Net steam for other sectors assumed to be negligible.
Note: Totals may not sum due to independent rounding.
total
Industrial and Solvent Evaporation Volatile Organic Compound Emissions
Data on annual non-methane volatile organic compound (NMVOC) emissions were obtained from the
National Air Quality and Emissions Trends Report (EPA 2000b). NMVOC emissions were organized by end-use
B-7
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category. NMVOC emissions from solvent utilization were considered to be a result of non-energy use of
petrochemical feedstocks. The end-use categories that represent "Industrial NMVOC Emissions" include chemical
and allied products, petroleum and related industries, and other industrial processes. These categories are non-
energy uses of the four fuel types; other categories where VOCs could be emitted due to combustion of fossil fuels
were excluded to avoid double counting. \
Because solvent evaporation and industrial NMVOC emission data are provided in tons of total NMVOCs,
assumptions were made concerning the average carbon content of the NMVOCs for each category of emissions.
The assumptions for calculating the carbon fraction of industrial and solvent utilization emissions were made
separately and differ significantly. For industrial NMVOC emissions, the carbon content of 85 percent was
assumed. This value was chosen to reflect the carbon content of an average volatile organic compound based on the
list of the most abundant, NMVOCs provided in the Trends Report. The list contains only pure hydrocarbons,
including saturated alkanes (carbon contents ranging from 80 to 85 percent based upon carbon number), alkenes
(carbon contents equal 85.7 percent), and some aroma^ics (carbon contents approximately 90 percent, depending
upon substitution). '. '
EPA (2000b) solvent evaporation emissions data were used directly to estimate the carbon content of
solvent emissions. The EPA data identify solvent emissions by compound or compound category for six different
solvent end-use categories: degreasing, graphic arts, dry cleaning, surface coating, other industrial processes, and
non-industrial processes. The percent carbon of each compound identified in the EPA solvent evaporation
emissions data was calculated based on the stoichiometry of the individual compound (e.g., the carbon content of
methlyene chloride is 14 percent; the carbon content |of toluene is 91 percent). For solvent emissions that are
identified in the EPA data only by chemical category (e.g., butanediol derivatives) a single individual compound
was selected to represent each category, and the carbon content of the category was estimated based on the carbon
content of the representative compound. The overall carbon content of the solvent evaporation emissions is
estimated to be 56 percent. !
The results of the industrial and solvent NMVOC emissions analysis are provided in Table B-9.
Table B-9:1998 Industrial and SiEvent HMVOC Emissions
Activity
Thousand short tons
{Carbon
Content
Carbon Emitted (Tg
C02Eq.)
Industrial NMVOCs3
Solvent Evaporation11
1,417
4,950
85%
56%
4.0
9.3
1 Includes emissions from chemical and allied products, petroleum and related industries, and other industrial processes categories.
b Includes solvent usage and solvent evaporation emissions from degreasing, graphic arts, dry cleaning, surface coating, other industrial
processes, and non-industrial processes. :
|
Hazardous Waste Incineration
Hazardous wastes are defined by the EPA under the Resource Conservation and Recovery Act (RCRA).5
Industrial wastes, such as rejected products, spent reagents, reaction by-products, and sludges from wastewater or air
pollution control, are federally regulated as hazardous Wastes if they are found to be ignitable, corrosive, reactive, or
toxic according to standardized tests or studies conducted by the EPA.
Hazardous wastes must be treated prior to disposal according to the federal regulations established under
the authority of RCRA. Combustion is one of the most common techniques for hazardous waste treatment,
particularly for those wastes that are primarily organic in composition or contain primarily organic contaminants.
Generally speaking, combustion devices fall into two categories: incinerators that burn waste solely for the purpose
of waste management, and boilers and industrial furnaces (BIFs) that burn waste in part to recover energy from the
waste. More than half of the hazardous waste combusted in the U.S. is burned in BIFs; these processes are included
in the energy recovery calculations described above.
The EPA's Office of Solid Waste requires biennial reporting of hazardous waste management activities,
and these reports provide estimates of the amount of hazardous waste burned for incineration or energy recovery.
1 [42 U.S.C. §6924, SDWA §3004]
B-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
EPA stores this information in its Biennial Reporting System (BRS) database (EPA 2000a). Combusted
hazardous wastes are identified based on EPA-defined management system types M041 through M049
(incineration). Combusted quantities are grouped into four representative waste form categories based on the form
codes reported in the BRS: aqueous liquids, organic liquids and sludges, organic solids, and inorganic solids. To
relate hazardous waste quantities to carbon emissions, "fuel equivalent" factors were derived for hazardous waste by
assuming that the hazardous wastes are simple mixtures of a common fuel, water, and noncombustible ash. For
liquids and sludges, crude oil is used as the fuel equivalent and coal is used to represent solids.
Fuel equivalent factors were multiplied by the tons of waste incinerated to obtain the tons of fuel
equivalent. Multiplying the tons of fuel equivalent by the appropriate carbon content factors from Marland and
Rotty (1984) yields tons of carbon emitted. Implied carbon content is calculated by dividing the tons of carbon
emitted by the associated tons of waste incinerated.
Waste quantity data for hazardous wastes were obtained from the EPA's BRS database for reporting years
1989, 1991, 1993, 1995, and 1997 (EPA 2000a). Combusted waste quantities were obtained from Form GM
(Generation and Management) for wastes burned on site and Form WR (Wastes Received) for waste received from
off-site for combustion. For each of the waste types, assumptions were developed on average waste composition
(see Table B-10). Carbon emission factors for equivalent fuels were obtained from Marland and Rotty (1984).
Regulations require incinerators to achieve at least 99.99 percent destruction of organics; this formed the basis for
assuming the fraction of carbon oxidized. A least-squares linear regression from the time series 1989 through 1997
was used to estimate emissions for 1998.
Table Bi-10: Assumed Composition of Combusted Hazardous Waste by Weight (Percent]
Waste Type
Aqueous Waste
Organic Liquids and Sludges
Organic Solids
Inorqanic Solids
Water Noncombustibles Fuel Equivalent
90
40
20
20
5
20
40
70
5
40
40
10
Non-Combustion Carbon Monoxide Emissions
Carbon monoxide (CO) emissions data were obtained from the National Air Quality and Emissions Trends
Report (EPA 2000a). There are four categories of CO emissions in EPA (2000a) that are classified as process-
related emissions not related to fuel combustion. These include chemical and allied products manufacturing, metals
processing, petroleum and related industries, and other industrial processes. Some of these CO emissions are
accounted for in the Industrial Processes section of this report, and are therefore not accounted for in this section,
including total carbon emissions from the primary aluminum, titanium dioxide, iron and steel, and ferroalloys
production processes. The total carbon (CO and CO2) emissions from oil and gas production and asphalt
manufacturing are also accounted for elsewhere in this Inventory. Sustainably harvested biogenic emissions (e.g.,
pulp and paper process emissions) are also excluded from calculation of CO emissions in this section. Those CO
emissions that are not accounted for elsewhere are considered to be byproducts of non-fuel use of feedstocks and are
included in the calculation of the petrochemical feedstocks storage factor. Table B-l 1 lists the industrial processes
and CO emissions that remain after excluding those reported in the Industrial Processes chapter, or where the carbon
originates from sustainably harvested biogenic sources.
B-9
-------
Table B-11: Carbon Monoxide Hon-CBmbustion Emissions (Ggl
Source
1998
Chemical and Allied Products
Organic Chemical Manufacture
Inorganic Chemical Manufacture, Other
Polymer and Resin Manufacture
Agricultural Chemical Manufacture
Paint, Varnish, Lacquer Manufacture
Pharmaceutical Manufacture
Other Chemical Manufacture
Metals Processing
Nonferrous Metals Processing, Other
Metals Processing NEC
Petroleum and Related Industries
Petroleum Refineries and Related Industry
Other Industrial Processes
Rubber and Misc. Plastic Products
Mineral Products
Machinery Products
Electronic Equipment
Transportation Equipment
Misc. Industrial Processes
83.6
I 2.7
| 4.5
Ml.8
;23.6
1
(145.5
| 40.0
300.9
169.1
0.91
118.2
Total
Total fTg CO; Eg.)
801.7
I 1.3
Pesticides ',
i
Pesticide consumption data were obtained from the 1996/1997 Pesticides Industry Sales and Usage (EPA
1999) report. Although some production data were available, consumption data were used because these data
provided information on active ingredients. Active ingredient compound names and consumption weights were
available for the top 25 agriculturally-used pesticides and top 9 pesticides used in the home and garden and the
industry/commercial/government categories. Since the report provides a range of consumption for each active
ingredient, the midpoint was used to represent actual consumption. Each of these compounds was assigned a carbon
content value based on stoichiometry. If the compound contained aromatic rings substituted with chlorine or other
halogens, then the compound was considered persistent and assigned a 100 percent carbon storage factor. All other
pesticides were assumed to release their carbon to the atmosphere. Nearly one-third of total pesticide active
ingredient consumption was not specified by chemical type in the Sales and Usage report (EPA 1999). This
unspecified portion of the active ingredient consumption was treated as a single chemical and assigned a carbon
content and a storage factor based on the weighted average of the known chemicals' values.
Table B-12:flctive Ingredient Consumption in Pesticides (Million Ids.) and Carbon Emitted aid Stored (Tg CO- EuJ
Pesticide Use
Active Ingredient
Carbon Emitted
Carbon Stored
Agricultural Uses *
Non-Agricultural Usesb
Home & Garden
Industry/Gov't/Commercial
Other
551.0
84.5
34.0
50.5
334.5
0.1
0.1
0.2
0.1
Total
970.0
0.2
0.4
+ Less than 0.05 Tg COz Eq.
M997 estimate (EPA 1999).
•"Approximate quantities, 1995/1996 estimates (EPA 1999).
Note: Totals may not sum due to independent rounding.
TRI Releases
Carbon is also found in toxic substances released by industrial facilities. The Toxic Release Inventory
(TRI), maintained by the EPA, tracks these releases by chemical and environmental release medium (i.e., land, air,
B-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
or water) on a biennial basis (EPA 2000b). By examining the carbon contents and receiving media for the top 35
toxic chemicals released, which account for 90 percent of the total mass of chemicals, the quantity of carbon stored
and emitted in the form of toxic releases can be estimated.
The TRI specifies releases by chemical, so carbon contents were assigned to each chemical based on
stoichiometry. The TRI also classifies releases by disposal location as either off-site or on-site. The on-site releases
are further subdivided into air emissions, surface water discharges, underground injection, and releases to land; the
latter is further broken down to disposal in a RCRA Subtitle C (i.e., hazardous waste) landfill or to "Other On-Site
Land Disposal."6 The carbon released in each disposal location is provided in Table B-13.
Each on-site classification was assigned a storage factor. A one hundred percent storage factor was applied
to disposition of carbon to Underground Injection and to Disposal to RCRA-permitted Landfills, while the other
disposition categories were assumed to result in an ultimate fate of emission as CO2 (i.e., a storage factor of zero
was applied to these categories.) The release allocation is not reported for off-site releases; therefore, the approach
was to develop a carbon-weighted average storage factor for the on-site carbon and apply it to the off-site releases.
For the remaining 10 percent of the TRI releases, the weights of all chemicals were added and an average
carbon content value, based upon the top 35 chemicals' carbon contents, was applied. The storage and emission
allocation for the remaining 10 percent of the TRI releases was carried out in the same fashion as for the 35 major
chemicals.
Table B-13:1998 TRI Releases by Disposal Location (Gg CD? En.l
Disposal Location
Carbon Stored
Carbon Emitted
Air Emissions
Surface Water Discharges
Underground injection
RCRA Subtitle C Landfill Disposal
Other On-Site Land Releases
Off-site Releases
89.4
1.4
6.4
924.0
6.7
15.9
36.0
Total
97.2
982.6
- Not applicable
Note: Totals may not sum due to independent rounding.
Uncertainty
There are several cross-cutting sources of uncertainty that pervade the characterization of a storage factor
for feedstocks. The aggregate storage factor for petrochemical feedstocks, pentanes plus, liquefied petroleum gases,
and natural gas is based on only a partial sampling of the products derived from these fossil fuel feedstocks and
imports and exports of petrochemical feedstocks. Including consideration of petrochemical feedstocks that are
exported and feedstocks that are burned for energy recovery, approximately 91 percent of the carbon consumed
across these four fuel types for non-energy uses is accounted for. The remaining "unaccounted-for" carbon could
have a variety of fates. For the purposes of this inventory, all of the unaccounted for carbon was assumed to be
emitted, and using this assumption the overall storage factor is 63.3 percent. If the assumption had been made that
the products which contained the unaccounted for carbon would store and emit carbon in the same ratio as the
investigated products, the overall storage factor would have been 69.9 percent, rather than 63.3 percent.
With respect to the "unaccounted for" carbon, there are uncertainties associated with the EIA and NPRA
data for net imports and exports of feedstocks that could affect the calculation of the storage factor. To a lesser
extent, there are uncertainties associated with the simplifying assumptions made for each end use category carbon
estimate. Generally, the estimate for a product is subject to one or both of the following uncertainties:
• The value used for estimating the carbon content has been assumed or assigned based upon a representative
compound.
6 Only the top 9 chemicals had their land releases separated into RCRA Landfills and Other Land Disposal. For the
remaining chemicals, it was assumed that the ratio of disposal in these two categories was equal to the carbon-weighted average
of the land disposal fate of the top 9 chemicals (i.e., 8 percent attributed to RCRA Landfills and 92 percent in the "Other"
category).
B-11
-------
• The split between carbon storage and emission has been assumed based on an examination of the
environmental fate of the products in each end use category.
Another cross-cutting source of uncertainty is that the estimate of the balance between storage and
emissions is based on data for only for a single year, 1998. This specific year may not be representative of storage
for the entire decade. :
i
Sources of uncertainty associated with specific elements of the analysis are discussed below.
i
Imports/Exports \
Import and export data for petrochemical feedstocks were obtained from EIA and the National Petroleum
Refiners Association for the major categories of petrochemical feedstocks (EIA 2001a, NPRA 2001). However, the
NPRA believes that the import and export data that they provide account for only 75 percent of the total imports and
exports of petrochemical feedstocks. The NPRA data provided were adjusted to account for 100 percent of the total,
though this adjustment represents a source of uncertainty in the estimate of net exports. Net exports could be lower
or higher than that estimated depending upon how comprehensive the combined EIA and NPRA data are in tracking
total imports and exports of petrochemical feedstocks, j
Oxidation Factors
i
Oxidation factors have been applied to non-energy uses of petrochemical feedstocks in the same manner as
for energy uses. However, this "oxidation factor" may:be inherent in the storage factor applied when calculation
emissions from non-energy consumption, which would result in a double-counting of the unoxidized carbon.
Oxidation factors are small corrections, on the order of 1 percent, and therefore application of oxidation factors to
non-energy uses may result in a slight underestimation of carbon emissions from non-energy uses.
Plastics
\
Uncertainty in the carbon storage estimate for plastics arises primarily from three factors. First, the
production data for acrylonitrile-butadiene-styrene, styrene-acrylonitrile, polyvinyl chloride, polypropylene,
phenolic, urea, melamine, and thermoplastic polyester reiins include Canadian production and may overestimate the
amount of plastic produced from U.S. fuel feedstocks. Second, the assumed carbon content values are estimates for
representative compounds, and thus do not account for the many formulations of resins available. This uncertainty
is greater for resin categories that are generic (e.g., phenolics, other styrenics, nylon) than for resins with more
specific formulations (e.g., polypropylene, polyethylene). Lastly, the assumption that all of the carbon contained in
plastics is stored ignores certain end uses (e.g., adhesiyes and coatings) where the resin may be released to the
atmosphere; however, these end uses are likely to be small relative to use in plastics.
Rubber >
Similar to plastics, uncertainty results from using consumption data for the United States and Canada,
rather than just domestic consumption, which may overestimate the amount of rubber produced from U.S. fuel
feedstocks. There are also uncertainties as to the assignment of carbon content values; however, they are much
smaller than in the case of plastics. There are probably fewer variations in rubber formulations than in plastics, and
the range of potential carbon content values is much narrower. Lastly, assuming that all of the carbon contained in
rubber is stored ignores the possibility of volatilization or degradation during product lifetimes. However, the
proportion of the total carbon that is released to the atmosphere during use is probably negligible.
Fiber |
i
A small degree of uncertainty arises from the assignment of carbon content values; however, the magnitude
of this uncertainty is less than that for plastics or rubber. Although there is considerable variation in final textile
products, the stock fiber formulations are standardized and proscribed explicitly by the Federal Trade Commission.
B-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Energy Recovery
The amount of feedstocks combusted for energy recovery was estimated from data included in the
Manufacturers Energy Consumption Survey (MECS) for 1998 (EIA 200 Ib). MEGS is a comprehensive survey
intended to represent U.S. industry as a whole, but because EIA does not receive data from all manufacturers (i.e., it
is a sample rather than a census), EIA must extrapolate from the sample. Also, the "other" fuels are identified in the
1998 MECS data in broad categories, including refinery still gas; waste gas; waste oils, tars, and related materials;
petroleum coke, coke oven and blast furnace gases; and other uncharacterized fuels, and the industries using these
"other" fuels are also identified only in broad categories, including the petroleum and coal products, chemicals,
primary metals, nonmetallic minerals, and other manufacturing sectors. The "other" fuel consumption data are
reported in BTUs (energy units) and there is uncertainty concerning the selection of a specific conversion factor for
each broad "other" fuel category to convert energy units to mass units.
NMVOCs (Solvent Evaporation and Industry)
The principal sources of uncertainty in estimating CO2 emissions from solvent evaporation and industry are
in the estimates of total NMVOC emissions and in the application of factors for the carbon content of these
emissions. Solvent evaporation and industrial NMVOC emissions reported by EPA are based on a number of data
sources and emission factors, and may underestimate or overestimate emissions. The carbon content for solvent
evaporation emissions is calculated directly from the specific solvent compounds identified by EPA as being
emitted, and is thought to have relatively low uncertainty. The carbon content for industrial emissions has more
uncertainty, however, as it is calculated from the average carbon content of an average volatile organic compound
based on the list of the most abundant measured NMVOCs provided in EPA (2000b).
Hazardous Waste
The greatest uncertainty in the hazardous waste combustion analysis is introduced by the assumptions
about the composition of combusted hazardous wastes, including the characterization that hazardous wastes are
similar to mixtures of water, noncombustibles, and fuel equivalent materials. Another limitation is the assumption
that all of the carbon that enters hazardous waste combustion is emitted—some small fraction is likely to be
sequestered in combustion ash—but given that the destruction and removal efficiency for hazardous organics is
required to meet or exceed 99.99 percent, this is a minor source of uncertainty. Carbon emission estimates from
hazardous waste should be considered central value estimates that are likely to be accurate to within +50 percent.
Pesticides
The largest source of uncertainty involves the assumption that a pesticide's active ingredient carbon is
either 0 percent stored or 100 percent stored. This split is a generalization of chemical behavior, based upon active-
ingredient molecular structure, and not on compound-specific environmental data. The mechanism by which a
compound is bound or released from soils is very complicated and can be affected by many variables, including the
type of crop, temperature, delivery method, and harvesting practice. Another smaller source of uncertainty arises
from the carbon content values applied to the unaccounted for portion of active ingredient. Carbon contents vary
widely among pesticides, from 7 to 72 percent, and the remaining pesticides may have a chemical make-up that is
very different from the 32 pesticides that have been examined.
TRI
The major uncertainty in using the TRI data are the possibility of double counting of emissions that are
already accounted for in the NMVOC data (see above) and in the storage and emission assumptions used. The
approach for predicting environmental fate simplifies some complex processes, and the balance between storage and
emissions is very sensitive to the assumptions on fate. Extrapolating from known to unknown characteristics also
introduces uncertainty. The two extrapolations with the greatest uncertainty are: 1) that the release media and fate of
the off-site releases were assumed to be the same as for on-site releases, and 2) that the carbon content of the least
frequent 10 percent of TRI releases was assumed to be the same as for the chemicals comprising 90 percent of the
releases. However, the contribution of these chemicals to the overall estimate is small. The off-site releases only
B-13
-------
account for 3 percent of the total releases, by weight, and, by definition, the less frequent compounds only account
for 10 percent of the total releases.
Asphalt and Road Oil
Asphalt is one of the principal non-energy uses of fossil fuels. The term "asphalt" generally refers to a
mixture of asphalt cement and a rock material aggregate, a volatile petroleum distillate, or water. For the purposes
of this analysis, "asphalt" is used interchangeably with asphalt cement, a residue of crude oil. According to EIA
(2000d), approximately 100 Tg CO2 Eq. has been used in the production of asphalt cement annually. Though minor
amounts of carbon are emitted during production, asphalt has an overall carbon storage factor of almost 100 percent.
Paving is the primary application of asphalt cement, comprising 86 percent of production. The three types
of asphalt paving produced in the United States are hot mix asphalt (HMA), cut-backs, and emulsified asphalt.
HMA, which makes up 90 percent of total asphalt paving (EPA 2000d), contains asphalt cement mixed with an
aggregate of rock materials. Cut-back asphalt is composed of asphalt cement thinned with a volatile petroleum
distillate (e.g., naphtha). Emulsified asphalt contains only asphalt cement and water. Roofing products are the other
significant end use of asphalt cement, accounting for approximately 14 percent of U.S. production (Kelly 2000). No
data were available on the fate of carbon in asphalt roofing; it was assumed that it has the same fate as carbon in
asphalt paving applications. j
t
i
Methodology i
A carbon storage factor was calculated for each type of asphalt paving. The fraction of carbon emitted by
each asphalt type was multiplied by consumption data for asphalt paving (EPA 2000d, EIIP 1998) to come up with a
weighted average carbon storage factor for asphalt as a^hole.
The fraction of carbon emitted by HMA was determined by first calculating the organic emissions (volatile
organic compounds [VOCs], carbon monoxide, polycyclic aromatic hydrocarbons [PAHs], hazardous air pollutants
[HAPs], and phenol) from HMA paving, using emission factors reported in EPA (2000d) and total HMA
production.7 The next step was to estimate the carbon jcontent of the organic emissions. This calculation was based
on stpichiometry for carbon monoxide (CO) and phenol, and an assumption of 85 percent carbon content for PAHs
and HAPs. The carbon content of asphalt paving is a function of the proportion of asphalt cement in asphalt paving
and the proportion of carbon in asphalt cement. For the former factor, a 5 percent asphalt cement content was
assumed based on personal communication with an expert from the National Asphalt Paving Association (Connolly
2000). For the latter factor, all paving types were characterized as having a mass fraction of 85 percent carbon in
asphalt cement, based on the assumption that asphalt is'primarily composed of saturated paraffinic hydrocarbons. By
combining these estimates, the result is that over 99.99 percent of the carbon in asphalt cement was retained (i.e.,
stored), and less than 0.01 percent was emitted. |
Cut-back asphalt is produced in three forms! (i.e., rapid, medium and slow cure). All three forms emit
carbon only from the volatile petroleum distillate used to thin the asphalt cement (EPA 1995)j Because the
petroleum distillates are not included in the EIA statistics for asphalt, the storage factor for cut-back is assumed to
be 100 percent. I
i
It was also assumed that there was no loss of carbon from emulsified asphalt (i.e., the storage factor is 100
percent) based on personal communication with an expert from Akzo Nobel Coatings, Inc. (James 2000).
Data Sources
Data on asphalt and road oil consumption and carbon content factors were supplied by the EIA. Hot mix
asphalt production and emissions factors were obtained from "Hot Mix Asphalt Plants Emissions Assessment
Report" from the EPA publication AP-42 (EPA 2000d). The asphalt cement content of HMA was provided by Una
Connolly of National Asphalt Paving Association (Connolly 2000). The consumption data for cut-back and
emulsified asphalts were taken from a Moulthrop, et al: study used as guidance for estimating air pollutant emissions
7 The emission factors are expressed as a function ;of asphalt paving tonnage (i.e., including the rock aggregate as well
as the asphalt cement). i ;
B-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
from paving processes (EIIP 1998). "Asphalt Paving Operation" AP-42 (EPA 1995) provided the emissions source
information used in the calculation of the carbon storage factor for cut-back asphalt. The storage factor for
emulsified asphalt was provided by Alan James of Akzo Nobel Coatings, Inc. (James 2000).
Uncertainty
The principal source of uncertainty is that the available data are from short-term studies of emissions
associated with the production and application of asphalt. As a practical matter, the cement in asphalt deteriorates
over time, contributing to the need for periodic re-paving. Whether this deterioration is due to physical erosion of
the cement and continued storage of carbon in a refractory form or physicochemical degradation and eventual
release of CO2 is uncertain. Long-term studies may reveal higher lifetime emissions rates associated with
degradation.
Many of the values used in the analysis are also uncertain and are based on estimates and professional
judgment. For example, the asphalt cement input for HMA was based on expert advice indicating that the range is
variable—from about 3 to 5 percent—with actual content based on climate and geographical factors (Connolly
2000). Over this range, the effect on the calculated carbon storage factor is minimal (on the order of 0.1 percent).
Similarly, changes in the assumed carbon content of asphalt cement would have only a minor effect.
The consumption figures for cut-back and emulsified asphalts are based on information reported for 1994.
More recent trends indicate a decrease in cut-back use due to high VOC emission levels and a related increase in
emulsified asphalt use as a substitute. However, because the carbon storage factor of each is 100 percent, use of
more recent data would not affect the overall result.
Lubricants
Lubricants are used in industrial and transportation applications. They can be subdivided into oils and
greases, which differ in terms of physical characteristics (e.g., viscosity), commercial applications, and
environmental fate. According to EIA (2000), the carbon content of U.S. production of lubricants: hi 1999 was
approximately 28 Tg CO2 Eq. Based on apportioning oils and greases to various environmental fates, and
characterizing those fates as resulting in either long-term storage or emissions, the overall carbon storage factor was
estimated to be 9 percent; thus, storage in 1999 was about 3 Tg CO2 Eq.
Methodology
For each lubricant category, a storage factor was derived by identifying disposal fates and applying
assumptions as to the disposition of the carbon for each practice. An overall lubricant carbon storage factor was
calculated by taking a production-weighted average of the oil and grease storage factors.
Oils
Regulation of used oil in the United States has changed dramatically over the past 15 years.8 The effect of
these regulations and policies has been to restrict land filling and dumping, and to encourage collection of used oil.
Given the relatively inexpensive price of crude oil, the economics have not favored re-refining—instead, most of the
used oil that has been collected has been combusted.
Table B-14 provides an estimated allocation of the fates of lubricant oils, along with an estimate of the
proportion of carbon stored in each fate. The ultimate fate of the majority of oils (about 84 percent) is combustion,
either during initial use or after collection as used oil. Combustion results in 99 percent oxidation to CO2, with
correspondingly little long-term storage of carbon in the form of ash. Dumping onto the ground or into storm
sewers, primarily by "do-it-yourselfers" who change their own oil, is another fate that results in conversion to CO2
given that the releases are generally small and most of the oil is biodegraded. In the landfill environment, which
tends to be anaerobic, within municipal landfills, it is assumed that 90 percent of the oil persists in an undegraded
form. Re-refining adds a recycling loop to the fate of oil; it was assumed that about 97 percent of the carbon in re-
8 For example, the U.S. EPA "RCRA (Resource Conservation and Recovery Act) On-line" web site
(http://www^epa.gov/rcraonline/) has over 50 entries on used oil regulation and policy for 1994 through 2000.
B-15
-------
refined oil is ultimately oxidized. Because of the dominance of fates that result in eventual release as CO2, only
about 3 percent of the carbon in oil lubricants goes into Ibng-term storage.
Table B-14: Commercial and Environmental Fate ef Oil Lubricants (Percent)
Fate of Oil
Combusted During Use
Not Combusted During Use
Combusted as Used Oil*
Dumped on the ground or in storm sewers
Landfilted
Re-refined into lube oil base stock and other products
Portion of Total
Oil
20
| 80
! 64
1 6
! 2
! 8
Carbon Stored
1
1
0
90
3
Weighted Average
2.9
* (e.g., in boilers or space heaters)
- Not applicable
Greases j
Table B-15 provides analogous estimates for lubricant greases. Unlike oils, grease is generally not
combusted during use, and combustion for energy recovery and re-refining are thought to be negligible. Although
little is known about the fate of waste grease, it was assumed that 90 percent of the non-combusted portion is
landfilled, and the remainder is dumped onto the ground'or storm sewers. Because much of the waste grease will be
in containers that render it relatively inaccessible to biodegradation, it was assumed that 90 percent and 50 percent
of the carbon in landfilled and dumped grease, respectively, would be stored. The overall storage factor is 82
percent for grease. i
Table B-15: Commercial and Environmental Fate ef Grease Lubricants [Percent]
Fate of Grease Total Grease Carbon Stored
Combusted During Use
Not Combusted During Use
Landfilled
Dumped on the ground or in storm sewers
5
95
85.5
9.5
Weighted Average '
• Not applicable
1
90
50
81.8
Having derived separate storage factors for oil and grease, the last step was to estimate the weighted
average for lubricants as a whole. No data were found apportioning the mass of lubricants into these two categories,
but the U.S. Census Bureau does maintain records of ^he value of production of lubricating oils and lubricating
greases. Assuming that the mass of lubricants can be allocated according to the proportion of value of production
(92 percent oil, 8 percent grease), applying these weights to the storage factors for oils and greases (3 percent and 82
percent) yields an overall storage factor of 9 percent. [
Data Sources
The estimated volume of lubricants produced annually is based on statistics provided by El A (2000), which
conducts surveys of lubricating oil and grease consumption. Information on the value of lubricating oil and grease
production was obtained from reports by the U.S. Census Bureau (1999).
The characterization of fate is based primarily on professional judgment of an EPA regulatory analyst with
experience in used oil (Rinehart 2000). For the proportions combusted, one percent was assumed to remain un-
oxidized in combustion processes (EIIP 1999); for other fates, estimates are based on professional judgment. The
assumption that landfilled oil and grease results in 90 percent storage is based on analogy with the persistence of
petroleum in native petroleum-bearing strata, which are both anaerobic. The assumption that oil dumped on the
ground or in storm sewers is completely degraded is based on the observation that land farming—application to
soil—is one of the most frequently used methods for degrading refinery wastes. The lower degradation rate for
grease is based on the observation that greases contain longer chain paraffins, which are more persistent. Re-refined
oil was assumed to have a storage factor equal to the weighted average for the other fates (i.e., after re-refining, the
oil would have the same probability of combustion, landfilling, or dumping as virgin oil).
B-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Uncertainty
The principal sources of uncertainty for the disposition of lubricants are the estimates of the commercial
use, post-use, and environmental fate of lubricants, which, as noted above, are largely based on assumptions and
judgment. There is no comprehensive system to track used oil and greases, which makes it difficult to develop a
verifiable estimate of the commercial fates of oil and grease. The environmental fate estimates for percent of carbon
stored are less uncertain, but also introduce uncertainty in the estimate.
The assumption that the mass of oil and grease can be divided according to their value also introduces
uncertainty. Given the large difference between the storage factors for oil and grease, changes in their share of
total lubricant production has a large effect on the weighted storage factor.
B-17
-------
B-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX C
Methodology for Estimating Emissions of CH4, N20, and Ambient Air Pollutants from
Stationary Combustion
Estimates of CH4 and NzO Emissions
Methane (CH4) and nitrous oxide (N2O) emissions from stationary combustion were estimated using IPCC
emission factors and methods. Estimates were obtained by multiplying emission factors—by sector and fuel type—-
by fossil fuel and wood consumption data. This "top-down" methodology is characterized by two basic steps,
described below. Data are presented in Table C-l through Table C-5.
Step 1: Determine Energy Consumption by Sector and Fuel Type
Greenhouse gas emissions from stationary combustion activities were grouped into four sectors: industrial,
commercial, residential, and electricity generation. For CH4 and N2O, estimates were based upon consumption of
coal, gas, oil, and wood. Energy consumption data were obtained from EIA's Annual Energy Review (EIA 2001),
and adjusted from higher to lower heating values by multiplying by 0.9 for natural gas and by 0.95 for coal and
petroleum fuel. This is a simplified convention used by the International Energy Agency. Table C-l provides
annual energy consumption data for the years 1990 through 2000.
Step 2: Determine the Amount of CHU and N20 Emitted
Activity data for each sector and fuel type were then multiplied by emission factors to obtain emissions
estimates. Emission factors were taken from the Revised 1996 IPCC Guidelines (TPCC/UNEP/OECD/IEA 1997).
Table C-2 provides emission factors used for each sector and fuel type.
Estimates of NO* CO, and NMVOC Emissions
For ambient air pollutants, the major source categories included were those identified in EPA (2001): coal,
fuel oil, natural gas, wood, other fuels (i.e., bagasse, liquefied petroleum gases, coke, coke oven gas, and others),
and stationary internal combustion, which includes emissions from internal combustion engines not used in
transportation. EPA (2001) periodically estimates emissions of NOX, CO, and NMVOCs by sector and fuel type
using a "bottom-up" estimating procedure. In other words, the emissions were calculated either for individual
sources (e.g., industrial boilers) or for many sources combined, using basic activity data (e.g., fuel consumption or
deliveries, etc.) as indicators of emissions. EPA (2001) projected emissions for years subsequent to their bottom-up
estimates. The national activity data used to calculate the individual categories were obtained from various sources.
Depending upon the category, these activity data may include fuel consumption or deliveries of fuel, tons of refuse
burned, raw material processed, etc. Activity data were used in conjunction with emission factors that relate the
quantity of emissions to the activity.
Table C-3 through Table C-5 present ambient air pollutant emission estimates for 1990 through 2000.
The basic calculation procedure for most source categories presented in EPA (2001) is represented by the
following equation:
where,
Ep,s = As
EF
- Cp,s/100)
E
p
s
A
EF
C
emissions
pollutant
source category
activity level
emission factor
percent control efficiency
C-1
-------
The EPA currently derives the overall emission control efficiency of a category from a variety of sources,
including published reports, the 1985 National Acid Precipitation and Assessment Program (NAPAP) emissions
inventory, and other EPA databases. The U.S. approach for estimating emissions of NOX, CO, and NMVOCs from
stationary combustion as described above is similar to the methodology recommended by the IPCC
(IPCC/UNEP/OECD/IEA 1997).
Table G-1: Fuel Consumption by Stationary Combustion far Calculating CH. and N2n Emissions ITBtuJ
Fuel/End-Use Sector
1990!
1995
1996
1997
1998
1999
2000
Coal
Residential
Commercial
Industry
Electricity Generation
Petroleum
Residential
Commercial
Industry
Electricity Generation
Natural Gas
Residential
Commercial
Industry
Electricity Generation
Wood
Residential
Commercial
Industrial
Electricity Generation
18,1691
621
931
1,4781
16,5361
11,6551
1,2661
9071
8,1521
1,3291
18,2301
4,5191
2,6981
6,9631
4,0501
1,8721
5811
371
1,2541
NO I
19,196
53
80
1,427
17,635
11,277
1,361
715
8,382
819
21,087
4,984
3,117
7,743
5,243
2,044
596
45
1,402
NO
20,117
54
82
1,370
18,610
11,941
1,457
741
8,858
885
21,475
5,390
3,250
8,052
4,783
2,085
595
49
1,441
NO
20,660
58
87
1,381
19,135
12,186
1,432
705
9,056
993
21,522
5,125
3,310
7,966
5,122
1,993
433
47
1,513
NO
20,862
44
66
1,317
19,434
12,199
1,324
665
8,857
1,354
20,871
4,669
3,098
7,366
5,737
1,998
387
47
1,564
NO
20,940
47
70
1,271
19,553
12,376
1,456
672
8,895
1,352
21,146
4,858
3,130
7,279
5,880
2,177
414
51
1,711
NO
Note: Totals may not sum due to independent rounding.
NO (Not occurring)
Table C-2: CHU and HzO Emission Factors by Fuel Type and Sector fg/GJr
21,722
47
70
1,119
20,487
12,067
1,492
723
8,657
1,195
22,233
5,081
3,425
7,250
6,477
2,187
433
52
1,702
NO
Fuel/End-Use Sector
Coal
Residential
Commercial
Industry
Eeclricity Generation
Petroleum
Residential
Commercial
Industry
Electricity Generation
Natural Gas
Residential
Commercial
Industry
Electricity Generation
Wood
Residential
Commercial
Industrial
Electricity Generation
1 GJ (Gigajoule) = 109 joules.
CH4
300
10
10
1
10
10
2
3
5
5
5
1
300
300
30
30
N20
1.4
1.4
1.4
1.4
0.6
0.6
0.6
0.6
0.1
0.1
0.1
o.i ;
4.0
4.0
4.0
4.0 :
One joule = 9.486* 1 0"4 Btu
C-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table C-3: HO. Emissions from Stationary Combustion ICgl
Sector/Fuel Type
Electricity Generation
Coal
Fuel Oil
Natural gas
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Commercial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Residential
Coalb
Fuel Oil"
Natural Gasb
Wood
Other Fuels3
Total
1990
6,045
5,119
200
513
NO
213
2,754
530
240
1,072
IE
119
792
336
36
88
181
IE
31
749
IE
IE
IE
42
708
9,884
1991
5,914
5,043
192
526
NO
152
2,703
517
215
1,134
IE
117
720
333
33
80
191
IE
29
829
IE
IE
IE
45
784
9,779
1992
5,901
5,062
154
526
NO
159
2,786
521
222
1,180
IE
115
748
348
35
84
204
IE
25
879
IE
IE
IE
48
831
9,914
1993
6,034
5,211
163
500
NO
160
2,859
534
222
1,207
IE
113
783
360
37
84
211
IE
28
827
IE
IE
IE
40
787
10,080
1994
5,956
5,113
148
536
NO
159
2,855
546
219
1,210
IE
113
767
365
36
86
215
IE
28
817
IE
IE
IE
40
777
9,993
1995
5,792
5,061
87
510
NO
134
2,852
541
224
1,202
IE
111
774
365
35
94
210
IE
27
813
IE
IE
IE
44
769
9,822
1996
5,566
5,057
107
259
NO
143
2,864
493
204
1,093
IE
109
965
367
31
87
224
IE
24
726
IE
IE
IE
27
699
9,522
1997
5,691
5,120
132
289
NO
150
2,814
487
196
1,079
IE
104
948
374
32
88
229
IE
25
699
IE
IE
IE
27
671
9,577
1998
5,628
4,932
202
346
NO
149
2,768
475
190
1,066
IE
104
933
353
34
73
220
IE
26
651
IE
IE
IE
27
624
9,400
1999
5,128
4,472
171
336
NO
151
2,840
489
. 194
1,089
IE
, 107
961
371
34
• 72
240
IE
25
683
IE
IE
IE
27
. 656
9,022
2000
4,763
4,149
140
320
NO
154
2,924
493
207
1,137
IE
112
976
376
34
73
244
IE
26
677
IE
IE
IE
30
647
8,740
IE (Included elsewhere)
NO (Not occurring)
3 "Other Fuels" include LPG, waste oil, coke oven gas, coke, and non-residential wood (EPA 2001).
b Coal, fuel oil, and natural gas emissions are included in the "Other Fuels" category (EPA 2001).
Note: Totals may not sum due to independent rounding.
C-3
-------
Table C-4: GO EmlssiiDsfrim stationary CimbasUin (Ggl
Sector/Fuel Type
Electricity Generation
Coal
Fuel Oil
Natural gas
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Commercial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Residential
Coal"
Fuel Oilb
Natural Gasb
Wood
Other Fuels3
Total
1990
329
213
18
46
NO
52
798
95
67
205
IE
253
177
205
13
16
40
IE
136
3,668
IE
IE
IE
3,430
238
4,999
1991
317
212
17
46
NO
41
835
92
54
257
IE
242
189
196
13
16
40
IE
128
3,965
IE
IE
IE
3,711
255
5,313
1992
318
214
14
47
NO
43
867
92
58
272
IE
239
205
204
13
16
46
IE
128
4,195
IE
IE
IE
3,930
265
5,583
1993
329
224
! 15
1 45
NO
i 46
946
i 92
I 60
1292
1 IE
259
'243
J207
[14
i 16
48
I IE
129
3,586
i IE
: IE
IE
3,337
[249
5,068
1994
335
224
13
48
NO
50
944
91
60
306
IE
260
228
212
13
16
49
IE
134
3,515
IE
IE
IE
3,272
243
5,007
1995
338
227
9
49
NO
52
958
88
64
313
IE
270
222
211
14
17
49
IE
132
3,876
IE
IE
IE
3,628
248
5,383
1996
363
228
11
72
NO
53
1,080
100
49
308
IE
317
'306
130
13
17
58
IE
42
2,364
IE
IE
IE
2,133
231
3,936
1997
376
233
13
76
NO
54
1,055
99
47
308
IE
302
299
133
13
18
59
IE
44
2,361
IE
IE
IE
2,133
229
3,926
1998
379
220
17
88
NO
54
1,044
96
46
305
IE
303
294
130
14
15
57
IE
44
2,352
IE
IE
IE
2,133
220
3,905
1999
367
208
17
87
NO
55
1,067
99
47
308
IE
309
303
135
14
15
62
IE
45
2,359
: IE
IE
IE
2,133
226
3,928
2000
380
212
16
95
NO
56
1,108
100
50
327
IE
322
308
137
14
15
63
IE
46
2,515
IE
IE
IE
2,292
??3
4,140
IE (Included elsewhere)
NO (Not occurring)
a "Other Fuels" include LPG, waste oil, coke oven gas, coke, and non-residential wood (EPA 2001).
b Coal, fuel oil, and natural gas emissions are included in the "Other Fuels" category (EPA 2001).
Note: Totals may not sum due to independent rounding.
C-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table C-!j: HMUOC Emissions from statianary Combustion iGg)
Sector/Fuel Type
Electricity Generation
Coal
Fuel Oil
Natural gas
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Commercial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Residential
Coalb
Fuel Oil"
Natural Gasb
Wood
Other Fuels3
Total
1990
43
25
5
2
NO
11
165
7
11
52
IE
46
49
18
1
3
7
IE
8
686
IE
IE
IE
651
35
912
1991
40
25
5
2
NO
9
177
5
10
54
IE
47
61
18
1
2
8
IE
7
739
IE
IE
IE
704
35
975
1992
40
25
4
2
NO
9
169
7
11
47
IE
45
60
20
1
3
9
IE
7
782
IE
IE
IE
746
36
1,011
1993
41
26
4
2
NO
9
169
5
11
46
IE
46
60
22
1
3
10
IE
8
670
IE
IE
IE
633
36
901
1994
41
26
4
2
NO
9
178
7
11
57
IE
45
58
21
1
3
10
IE
8
657
IE
IE
IE
621
36
898
1995
40
26
2
2
NO
9
187
5
11
66
IE
45
59
21
1
3
10
IE
8
726
IE
IE
IE
689
37
973
1996
44
25
3
7
NO
9
162
6
8
54
IE
32
63
24
1
3
13
IE
8
788
IE
IE
IE
756
33
1,020
1997
47
26
4
7
NO
10
160
6
7
54
IE
31
62
24
1
3
13
IE
8
787
IE
IE
IE
756
32
1,019
1998
50
26
5
9
NO
10
159
6
7
54
IE
31
61
24
1
3
12
IE
8
786
IE
IE
IE
756
30
1,018
1999
50
26
5
9
NO
10
162
6
7
54
IE
32
63
26
1
3
14
, IE
9
787
IE
IE
IE
756
31
1,025
2000
51
27
4
10
NO
10
169
6
8
57
IE
34
64
26
1
3
14
IE
9
843
IE
IE
IE
812
31
1,089
IE (Included elsewhere)
NO (Not occurring)
3 "Other Fuels" include LPG, waste oii, coke oven gas, coke, and non-residential wood (EPA 2001).
b Coal, fuel oil, and natural gas emissions are included in the "Other Fuels" category (EPA 2001).
Note: Totals may not sum due to independent rounding.
C-5
-------
C-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX D
Methodology for Estimating Emissions of CH4r N20, and Ambient Air Pollutants from
Mobile Combustion
Estimates of CHU and NzO Emissions
Greenhouse gas emissions from mobile combustion are reported by transport mode (e.g., road, rail, air, and
water), vehicle type, and fuel type. The EPA does not systematically track emissions of CHU and N2O as is done in
EPA (2001) for ambient air pollutants; therefore, estimates of these gases were developed using a methodology
similar to that outlined in the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).
Activity data were obtained from a number of U.S. government agency publications. Depending on the
category, these basic activity data included such information as fuel consumption, fuel deliveries, and vehicle miles
traveled (VMT).
Highway Vehicles
Step 1: Determine Vehicle Miles Traveled by Vehicle Type, Fuel Type, and Model Year
Vehicle miles traveled (VMT) by vehicle type were obtained from the Federal Highway Administration's
(FEW A) Highway Statistics (FHWA 1996 through 2001). As these vehicle categories are not fuel-specific, VMT
for each vehicle type was disaggregated by fuel type using fuel economy and consumption data, so that the
appropriate emission factors could be applied. First, fuel economy and consumption data from FHWA's Highway
Statistics were disaggregated by fuel type using a number of sources, including the Department of Energy's (DOE)
Transportation Energy Data Book (DOE 1993 through 2001), FHWA's Highway Statistics (FHWA 1996 through
2001), EPA and DOE's Fuel Economy 2001 Datafile (EPA, DOE 2001), and the Vehicle Inventory and Use Survey
(Census 1997). These data were used to distribute national VMT estimates across vehicle categories.1
National VMT data for gasoline and diesel highway vehicles are presented in Table D- 1 and Table D-2,
respectively. Total VMT for each highway category (i.e., gasoline passenger cars, light-duty gasoline trucks, heavy-
duty gasoline vehicles, diesel passenger cars, light-duty diesel trucks, heavy-duty diesel vehicles, and motorcycles)
were distributed across 25 model years based on the VMT distribution by vehicle age shown in Table D-3. This
distribution was derived by weighting the temporally fixed age distribution of the U.S., vehicle fleet according to
vehicle registrations (Table D-3) by the average annual age-specific vehicle mileage accumulation of U.S. vehicles
(Table D-4). Both were obtained from EPA's Mobile6 model (EPA 2000).
Activity data for gasoline passenger cars and light-duty trucks in California were developed separately due
to the different emission control technologies deployed in that state relative to the rest of the country. Unlike the
rest of the United States, beginning in model year 1994, a fraction of the computed California VMT for gasoline
passenger cars and light-duty trucks was attributed to low emission vehicles (LEVs). LEVs have not yet been
widely deployed in other states. The percent of national VMT represented by California for each year was obtained
from the Federal Highway Administration (FHWA 1996 through 2001), and applied to national VMT estimates to
estimate California VMT for gasoline passenger cars and light-duty trucks (presented in Table D- 1 ).
Step 2: Allocate VMT Data to Control Technology Type
VMT by vehicle type for each model year were distributed across various control technologies as shown in
Table D-7 through Table D-l 1. Again, California gasoline-fueled passenger cars and light-duty trucks were treated
separately due to that state's distinct vehicle emission standards — including the introduction of Low Emission
Vehicles (LEVs) in 1994 — compared with the rest of the United States. The categories "Tier 0" and "Tier 1" were
' This methodology is presented in more detail in ICF (2001).
D-1
-------
substituted for the early three-way catalyst and advanced three-way catalyst categories, respectively, as defined in
the Revised 1996 IPCC Guidelines. Tier 0, Tier 1, and LEV are actually U.S. emission regulations, rather than
control technologies; however, each does correspond to particular combinations of control technologies and engine
design. Tier 1 and its predecessor Tier 0 both apply to vehicles equipped with three-way catalysts. The introduction
of "early three-way catalysts," and "advance three-^ay catalysts" as described in the Revised 1996 IPCC
Guidelines, roughly correspond to the introduction of Tier 0 and Tier 1 regulations (EPA 1998).
I
Step 3: Determine the Amount of CH4 and N20 Emitted by Vehicle, Fuel, and Control Technology Type
VMT for each highway category each year as described in Step 1 (see Table D-5) were first converted to
vehicle kilometers traveled (VKT) so that IPCC emission factors could be applied. Emissions of CH4 and N2O were
then calculated by multiplying emission factors in IPCC/UNEP/OECD/IEA (1997) by the IPCC emission factors,
which were derived from the EPA's MOBILESa mobile source emissions model (EPA 1997). The MOBILESa
model uses information on ambient temperature, diurnal temperature range, altitude, vehicle speeds, national vehicle
registration distributions, gasoline volatility, emission cpntrol technologies, fuel composition, and the presence or
absence of vehicle inspection/maintenance programs in o'rder to produce these factors.
Emissions of N2O—in contrast to CH4, CO, N0X, and NMVOCs—have not been extensively studied and
are currently not well characterized. The limited number of studies that have been performed on highway vehicle
emissions of N2O have shown that emissions are generally greater from vehicles with catalytic converter systems
than those without such controls, and greater from aged than from new catalysts. These systems control tailpipe
emissions of NOX (i.e., NO and NO2) by catalytically reducing NOX to N2. Suboptimal catalyst performance, caused
by as yet poorly understood factors, results in incomplete reduction and the conversion of some NOX to N2O rather
than to N2. Fortunately, newer vehicles with catalyst and engine designs meeting the more recent Tier 1 and LEV
standards have shown reduced emission rates of both NQX and N2O compared with earlier catalyst designs.
In order to better characterize the process by which N2O is formed by catalytic controls and to develop a
more accurate national emission estimate, the EPA's Office of Transportation and Air Quality—at its National
Vehicle and Fuel Emissions Laboratory (NVFEL)—conducted a series of tests in order to measure emission rates of
N2O from used Tier 1 and LEV gasoline-fueled passenger cars and light-duty trucks equipped with catalytic
converters. These tests and a review of the literature were used to develop the emission factors for N2O (EPA
1998). The following references were used in developing the N2O emission factors for gasoline-fueled highway
passenger cars presented in Table D-12: !
• LEVs. Tests performed at NVFEL (EPA 19|98)2
• Tierl. Tests performed at NVFEL (EPA 1998)
• Tier 0. Smith and Carey (1982), Barton and Simpson (1994), and one car tested at NVFEL (EPA
1998) [
• Oxidation Catalyst. Smith and Carey (1982), Urban and Garbe (1980)
• Non-Catalyst. Prigent and de Soete (1989), Dasch (1992), and Urban and Garbe (1979)
Nitrous oxide emission factors for other types of gasoline-fueled vehicles—light-duty trucks, heavy-duty
vehicles, and motorcycles—were estimated by adjusting the factors for gasoline passenger cars, as described above,
by their relative fuel economies. This adjustment was performed using miles per gallon data derived from (DOE
1993 through 2001), (FHWA 1996 through 2001), (EP^., DOE 2001), and (Census 1997) shown in Table D-13.
Data from the literature and tests performed at NVFEL support the conclusion that light-duty trucks:have higher
emission rates than passenger cars. However, the use of fuel-consumption ratios to determine emission factors is
considered a temporary measure only, to be replaced as soon as real data are available.
2 LEVs are assumed to be operated using low-sulfur fuel (i.e., Indolene at 24 ppm suliur). All other NVFEL tests were
performed using a standard commercial fuel (CAAB at 285 ppm suliur). Emission tests by NVFEL have consistently exhibited
higher N2O emission rates from higher sulfur fuels on Tier 1 and LEV vehicles.
D-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000 ~~~
-------
The resulting N2O emission factors employed for gasoline highway vehicles are lower than the U.S. default
values presented in the Revised 1996 IPCC Guidelines, but are higher than the European default values, hoth of
which were published before the more recent tests and literature review conducted by the NVFEL. The U.S.
defaults in the Guidelines were based on three studies that tested a total of five cars using European rather than U.S.
test procedures.
Nitrous oxide emission factors for diesel highway vehicles were taken from the European default values
found in the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). Little data addressing N2O emissions
from U.S. diesel-fueled vehicles exists, and in general, European countries have had more experience with diesel-
fueled vehicles.
Compared to regulated tailpipe emissions, relatively little data are available to estimate emission factors for
N2O. Nitrous oxide is not a regulated ambient air pollutant, and measurements of it in automobile exhaust have not
been routinely collected. Further testing is needed to reduce the uncertainty in nitrous oxide emission factors for all
classes of vehicles, using realistic driving regimes, environmental conditions, and fuels.
Non-Highway Vehicles
Activity data for non-highway vehicles were based on annual fuel consumption statistics by transportation
mode and fuel type. Consumption data for distillate and residual fuel oil by ships and boats (i.e., vessel bunkering),
construction equipment, farm equipment, and locomotives were obtained from EIA (2000b). In the case of ships
and boats, the EIA (2000b) vessel bunkering data were reduced by the amount of fuel used for international
bunkers.3 Data on the consumption of jet fuel in aircraft were obtained directly from DOT/BTS, as described under
CO2 from Fossil Fuel Combustion, and were reduced by the amount allocated to international bunker fuels. Data on
aviation gasoline consumed in aircraft were taken from FAA (2000). Data on the consumption of motor gasoline by
ships and boats, construction equipment, farm equipment, and locomotives data were drawn from FHWA (1996
through 2000). The activity data used for non-highway vehicles are included in Table D-6.
Emissions of CH4 and N2O from non-highway vehicles were calculated by multiplying U.S. default
emission factors in the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) by activity data for each
vehicle type (see Table D-13).
Table D-14 and Table D-15 provide complete emissions of CH4 and N2O emissions, respectively, for 1990
through 2000.
Estimates of NOX, CO, and NMVOC Emissions
The emission estimates of NOX, CO, and NMVOCs for mobile combustion were taken directly from the
EPA's National Air Pollutant Emissions Trends, 1900-2000 (EPA 2001). This EPA report provides emission
estimates for these gases by sector and fuel type using a "top down" estimating procedure whereby emissions were
calculated using basic activity data, such as amount of fuel delivered or miles traveled, as indicators of emissions.
Table D-16 through Table D-18 provide complete emissions estimates for 1990 through 2000.
1 See International Bunker Fuels section of the Energy Chapter.
D-3
-------
TaUlB D-1: vehicle Miles Traveled for Gasaline Highway Vehicles tiff Miles!
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Passenger
Cars"
1,227.0
1,186.3
1,200.9
1,205.1
1,234.2
1,264.3
1,295.9
1,325.5
1,371.8
1,385.4
1,414.8
Light-Duty Heavy-Duty \ Passenger Cars Light-Duty
Trucks3 Vehicles Motorcycles (CA)b Trucks (CA)b
491.1
556.7
607.0
640.6
657.1
679.9
704.3
733.7
751.1
776.9
796.5
30.2
32.1
31.0
30.3
30.6
30.5
30.6
30.6
31.1
31.2
30.2
8.7
i 8.8
i 9.1
' 9.3
' 9.5
: 9.8
i 9.9
; 10.1
i 10.3
10.6
10.5
168.5
159.9
158.9
158.2
160.9
162.8
163.2
166.3
167.6
173.9
177.6
67.4
75.0
80.3
84.1
85.7
87.5
88.7
92.1
91.7
97.5
100.0
a Excludes California
b California VMT for passenger cars and light-duty trucks were disaggregated from national VMT using data from FHWA (1996 through 2001)
Source: Derived from FHWA (1996 through 2001). '.
Table D-2: Vehicle Miles Traveled far Diesel Highway Vehicles [Iff Miles!
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Passenger Light-Duty
Cars Trucks
13.6
12.4
12.3
12.1
11.7
11.2
10.8
10.7
10.2
9.9
9.5
16.0
17.6
19.5
21.1
21.8
22.6
23.5
25.0
25.4
26.6
27.5
Heavy-Duty
Vehicles
121.7
123.2
128.1
135.8
146.0
154.0
158.9
167.7
172.3
179.1
183.2
Source: Derived from FHWA (1996 through 2001).
D-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table D-3: Age Distribution by Vehicle/Fuel Type for Highway Vehicles
Vehicle Age
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Total
LDGV
5,3%
7.1%
7.1%
7.1%
7.0%
7.0%
6.9%
6.8%
6.6%
6.3%
5.9%
5.4%
4.6%
3.6%
2.9%
2.3%
1.8%
1.4%
1.1%
0.9%
0.7%
0.6%
0.4%
0.4%
1.0%
100.0%
LDGT
5.8%
7.6%
7.5%
7.3%
7.1%
6.8%
6.5%
6.1%
5.7%
5.2%
4.7%
4.2%
3.6%
3.1%
2.6%
2.2%
1.8%
1.4%
1.2%
1.1%
1.1%
1.0%
1.0%
0.9%
4.6%
100.0%
HDGV
4.9%
8.9%
8.1%
7.4%
6.8%
6.2%
5.6%
5.1%
4.7%
4.3%
3.9%
3.6%
3.3%
3.0%
2.7%
2.5%
2.3%
2.1%
1.9%
1.7%
1.6%
1.5%
1.3%
1.2%
5.4%
100.0%
LDDV
5.3%
7.1%
7.1%
7.1%
7.0%
7.0%
6.9%
6.8%
6.6%
6.3%
5.9%
5.4%
4.6%
3.6%
2.9%
2.3%
1.8%
1.4%
1.1%
0.9%
0.7%
0.6%
0.4%
0.4%
1.0%
100.0%
LDDT
5.9%
7.4%
6.9%
6.4%
6.0%
5.6%
5.2%
4.8%
4.5%
4.2%
3.9%
3.6%
3.4%
3.2%
2.9%
2.7%
2.5%
2.4%
2.2%
2.1%
1.9%
1.8%
1.7%
1.6%
7.3%
100.0%
HDDV
4.2%
7.8%
7.2%
6.7%
6.2%
5.8%
5.3%
5.0%
4.6%
4.3%
4.0%
3.7%
3.4%
3.2%
2.9%
2.7%
2.5%
2.4%
2.2%
2.0%
1.9%
1.8%
1.6%
1.5%
7.2%
100.0%
MC
14.4%
16.8%
13.5%
10.9%
8.8%
7.0%
5.6%
4.5%
3.6%
2.9%
2.3%
9.7%
0.0%
0,0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
100.0%
LDGV (gasoline passenger cars, also referred to as light-duty gas vehicles)
LDGT (light-duty gas trucks)
HDGV (heavy-duly gas vehicles)
LDDV (diesel passenger cars, also referred to as light-duty diesel vehicles)
LDDT (light-duty diesel trucks)
HDDV (heavy-duty diesel vehicles)
MC (motorcycles)
Note: Based on vehicle registrations provided by EPA (2000).
D-5
-------
Table D-4: Annaal Age-specific Vehicle Mileage Accumulation of D.S. Vehicles (Miles!
Vehicle Age
1
2
3
4
5
6
7
8
9
10
11
12
13
.14
15
16
17
18
19
20
21
22
23
24
25
LDGV
14,910
14,174
13,475
12,810
12,178
11,577
11,006
10,463
9,947
9,456
8,989
8,546
8,124
7,723
7,342
6,980
6,636
6,308
5,997
5,701
5,420
5,152
4,898
4,656
4,427
LDGT
19,906
18,707
17,559
16,462
15,413
14,411
13,454
12,541
11,671
10,843
10,055
9,306
8,597
7,925
7,290
6,690
6,127
5,598
5,103
4,642
4,214
3,818
3,455
3,123
2,822
HDGV
20,218
18,935
17,100
16,611
15,560
14,576
13,655
12,793
11,987
11,231
10,524
9,863
9,243
8,662
8,028
7,610
7,133
6,687
6,269
5,877
5,510
5,166
4,844
4,542
4,259
LDDV
14,910
14,174
13,475
12,810
12,178
11,577
11,006
10,463
9,947
9,456
8,989
8,546
8,124
7,723
7,342
6,980
6,636
6,308
5,997
5,701
5,420
5,152
4,898
4,656
4,427
LDDT
126,371
24,137
22,095
20,228
18,521
16,960
15,533
14,227
13,032
11,939
10,939
10,024
9,186
8,420
7,718
7,075
6,487
5,948
5,454
5,002
4,588
4,209
3,861
3,542
3,250
HDDV
28,787
26,304
24,038
21,968
20,078
18,351
16,775
15,334
14,019
12,817
11,719
10,716
9,799
8,962
8,196
7,497
6,857
6,273
5,739
5,250
4,804
4,396
4,023
3,681
3,369
MC
4,786
4,475
4,164
3,853
3,543
3,232
2,921
2,611
2,300
1,989
1,678
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
Source: EPA (2000).
Table D-5: VMT Disiribuilin by Vehicle Age and Vehicle/Fuel Type
Vehicle Age
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
LDGV
7.51%
9.52%
9.05%
8.59%
8.14%
7.68%
7.22%
6.72%
6.20%
5.64%
5.03%
4.38%
3.54%
2.67%
2.01%
1.52%
1.14%
0.86%
0.65%
0.49%
0.37%
0.28%
0.21%
0.16%
0.43%
Total 100.0%
Note:
LDGT
9.41%
11.56%
10.62%
9.70%
8.80%
7.92%
7.04%
6.19%
5.36%
4.57%
3.82%
3.14%
2.52%
1.99%
1.54%
1.16%
0.87%
0.64%
0.50%
0.43%
0.37%
0.32%
0.27%
0.23%
1.04%
100.0%
Estimated by weighting data in Table D
HDGV
7.89%
13.48%
11.11%
9.85%
8.43%
7.21%
6.16%
5.27%
4.51%
3.86%
3.31%
2.83%
2.42%
2.07%
1.76%
1.52%
1.30%
1.12%
0.96%
0.82%
0.70%
0.60%
0.52%
0.44%
1.85%
100.0%
LDDV
7.51%
9.52%
9.05%
8.59%
8.14%
7.68%
7.22%
6.72%
6.20%
5.64%
5.03%
4.38%
3.54%
2.67%
2.01%
1.52%
1.14%
0.86%
0.65%
0.49%
0.37%
0.28%
0.21%
0.16%
0.43%
100.0%
LDDT
11.50%
13.07%
11.15%
9.51%
8.11%
6.92%
5.90%
5.04%
4.30%
3.67%
3.13%
£.67%
2.28%
1.95%
1.66%
1.42%
1.21%
1.04%
0.89%
0.76%
0.65%
0.55%
0.47%
0.40%
1.75%
100.0%
HDDV
8.27%
14.00%
11.86%
10.05%
8.52%
7.22%
6.13%
5.20%
4.41%
3.74%
3.18%
2.70%
2.29%
1.94%
1.65%
1.40%
1.19%
1.01%
0.86%
0.73%
0.62%
0.53%
0.45%
0.38%
1.65%
100.0%
MC
19.39%
21.15%
15.82%
11.82%
8.77%
6.37%
4.60%
3.31%
2.33%
1.62%
1.09%
3.73%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
100.0%
-3 by data in Table D-4,
D-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table D 6: Fuel Consumniion far Hon-Highway Vehicles by Fuel Type [gallons!
Vehicle Type/Year
Aircraft
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Ships and Boats
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Construction Equip.
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Farm Equipment
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Locomotives
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Residual
0
0
0
0
0
0
0
0
0
0
0
1,521,437,386
1,486,167,178
2,347,064,583
2,758,924,466
2,499,868,472
2,994,692,916
2,286,349,693
1,011,486,526
727,907,222
2,388,334,968
4,580,188,492
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
25,422
6,845
8,343
4,065
5,956
6,498
9,309
3,431
2,587
3,540
Diesel
0
0
0
0
0
0
0
0
0
0
0
1,697,600,270
1,693,361,391
1,706,143,771
1,546,310,902
1,630,092,618
1,518,608,116
1,839,335,006
1,801,798,270
1,597,011,188
1,855,327,478
1,889,097,816
1,581,500,000
1,492,000,000
1,514,205,000
1,526,043,000
1,531,300,000
1,472,827,000
1,645,647,000
1,678,482,000
1,749,317,000
1,723,597,000
1,899,837,000
3,164,200,000
3,144,200,000
3,274,811,000
3,077,122,000
3,062,436,000
3,093,224,000
3,225,029,000
3,206,359,000
2,965,006,000
2,805,157,000
3,079,664,000
3,210,111,000
3,026,292,000
3,217,231,000
2,906,998,000
3,063,441,000
3,191,023,000
3,266,861,000
3,067,400,000
2,833,276,000
2,789,926,000
Jet Fuel
18,280,476,364
17,511,325,335
17,281,746,858
17,421,015,955
18,270,975,739
17,806,704,239
18,746,820,369
18,601,073,081
19,057,517,441
19,423,591,168
20,474,811,494
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Gasoline3
374,216,115
347,126,395
341,582,453
319,448,684
317,306,704
329,318,581
310,796,773
330,284,570
295,344,794
325,912,623
301,892,666
1,300,400,000
1,709,700,000
1,316,170,000
873,687,000
896,700,000
1,060,394,000
993,671,000
987,193,000
956,232,000
956,232,001
1,124,269,000
318,200,000
287,200,000
272,900,000
245,299,000
272,852,000
280,046,000
283,911,000
300,491,000
234,705,000
177,758,000
191,516,000
812,800,000
776,200,000
805,500,000
845,320,000
911,996,000
926,732,000
918,085,000
984,450,000
906,941,000
702,700,000
652,256,000
0
0
0
0
0
0
0
0
0
0
D-7
-------
2000
Other"
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
7,158
0
0
0
0
0
0
0
0
0
0
0
3,070,766,000
i
926,800,000
955,400,000
773,437,000
797,140,000
905,842,000
800,335,000
741,326,000
706,754,000
682,865,000
685,634,000
610,078,000
0
0
0
0
0
0
0
0
0
0
0
0
0
1,205,400,000
1,097,700,000
1,219,300,000
1,025,087,667
1,039,309,667
1,071,596,667
1,081,639,667
1,097,257,667
1,139,228,667
1,021,835,667
1,040,137,667
- Not applicable
4 For aircraft, this is aviation gasoline. For all other categories, this is motor gasoline.
b Other includes snowmobiles and industrial fuel consumption.
Table D-7: Central Technology Assignments for Gasoline Passenger Cars (Percent of UMT1*
Model Years Non-catalyst Oxidation Tier 0 "fieri
1973-1974
1975
1976-1977
1978-1979
1980
1981
1982
1983
1984-1993
1994
1995
1996-2000
100%
20%
15%
10%
5%
85%
90%
88%
15%
14%
12%
7% i
85%
86%
88% I
100% i
60% !
20% |
40%
80%
100%
" Excluding California VMT
- Not applicable i
Table D-8: Control Technology Assignments for Gasoline Light-Duty Trucks (Percent of WHTF
Model Years Non-catalyst Oxidation
TierO
Tierl
1973-1974
1975
1976
1977-1978
1979-1980
1981
1982
1983
1984
1985
1986
1987-1993
1994
1995
1996-2000
100%
30%
20%
25%
20%
70%
80%
75%
80%
95%
90%
80%
70%
60%
50%
5%
5%
10% l
20% I
30% |
40% I
50% I
95% !
60% '
20% l
40%
80%
100%
' Excluding California VMT
-Not applicable.
D-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table D-!9: Control Technology Assignments for California Gasoline Passenger Cars and Light-Duty Trucks (Percent
of VMT)
Model Years
1973-1974
1975-1979
1980-1981
1982
1983
1984-1991
1992
1993
1994
1995
1996-2000
Non-catalyst
100%
-
-
-
-
.
.
-
.
.
-
Oxidation
-
100%
15%
14%
12%
-
-
-
-
.
-
TierO
-
-
85%
86%
88%
100%
60%
20%
-
-
-
Tierl
• -
-
-
-
-
-
40%
80%
90%
85%
80%
LEV
-
-
-
-
-
-
-
-
10%
15%
20%
* Excluding California VMT
- Not applicable
Table D-10: Control Technology Assignments for Gasoline Heavy-Duty Vehicles (Percent of VMTI
Model Years
£1981
1982-1984
1985-1986
1987
1988-1989
1990-2000
Uncontrolled
100%
95%
Non-catalyst
95%
70%
60%
45%
Oxidation
5%
5%
15%
25%
30%
TierO
15%
15%
25%
" Excluding California VMT
- Not applicable
Table D-11: Control Technology Assignments for Diesel Highway and Motorcycle VMT
Vehicle Type/Control Technology Model Years
Diesel Passenger Cars and Light-Duty Trucks
Uncontrolled
Moderate control
Advanced control
Heavy-Duty Diesel Vehicles
Uncontrolled
Moderate control
Advanced control
Motorcycles
Uncontrolled
Non-catalyst controls
1966-1982
1983-1995
1996-2000
1966-1972
1983-1995
1996-2000
1966-1995
1996-2000
D-9
-------
Table 0-12: Emission Factars [g/kml far CH» and N2n and Fuel Economy [miles ncr gallon! far Highway Mobile
GimnDstlen
Vehicle Type/Control Technology
Gasoline Passenger Cars
Low Emission Vehicles3
Tierl"
TierO11
Oxidation Catalyst
Non-Catalyst
Uncontrolled
Gasoline Light-Duty Trucks
Low Emission Vehicles3
Tierl"
TierO"
Oxidation Catalyst
Non-Catalyst
Uncontrolled
Gasoline Heavy-Duty Vehicles
TierO"
Oxidation Catalyst?
Non-Catalyst Control
Uncontrolled
Diesel Passenger Cars
Advanced
Moderate
Uncontrolled
Diesel Light Trucks
Advanced
Moderate
Uncontrolled
Diesel Heavy-Duty Vehicles
Advanced
Moderate
Uncontrolled
Motorcycles
Non-Catalyst Control
Uncontrolled
N20
0.0176
0.0288
0.0507
0.0322
0.0103
0.0103
0.0220
0.0361
0.0635
0.0403
0.0129
0.0129
0.1085
0.0689
0.0220
0.0220
0.0100
0.0100
0.0100
0.0200
0.0200
0.0200
0.0300
0.0300
0.0300
0.0044
0.0044
CH4
0.025
0.030
0.040
0.070
0.120
0.135
\
i
0.030
0.035
0.070
0.090
0.140
0.135
0.075
0.090
0.125
0.270
O.J31
0.01
0.01
I
0.01
0.01
0.01
i
0.04
0.05
0.06
0.13
0.26
MPG
21.99
17.56
7.60
19.38
15.48
5.66
50.00
"Applied to California VMT only. ,
" The categories Tier 0" and Tier 1" were substituted for the Dearly three-way catalyst and advanced three-way catalyst categories,
respectively, as defined in the Revised 1996IPCC Guidelines.
c Methane emission factor assumed based on light-duty trucks oxidation catalyst value.
D-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table B-13: Emission Factors fir CH, and N2Q Emissions from Non-Highway Mobile Combustion Ig gas/kg lucll
Vehicle Type/Fuel Type
Ships and Boats
Residual
Distillate
Gasoline
Locomotives
Residual
Diesel
Coal
Farm Equipment
Gas/Tractor
Other Gas
Diesel/Tractor
Other Diesel
Construction
Gas Construction
Diesel Construction
Other Non-Highway
Gas Snowmobile
Gas Small Utility
Gas HD Utility
Diesel HD Utility
Aircraft
Jet Fuel
Aviation Gasoline
N20
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.1
0.04
CH4
0.23
0.23
0.23
0.25
0.25
0.25
0.45
0.45
0.45
0.45
0.18
0.18
0.18
0.18
0.18
0.18
0.087
2.64
Table D-14: CH, Emissions from Mobile Combustion ITg CO? Eq.l
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duly Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
1990
4.2
2.4
1.6
0.2
0.1
0.2
+
+
0.2
0.4
0.1
0.1
0.1
+
0.2
+
4.9
1991
4.2
2.2
1.7
0.2
0.1
0.2
+
+
0.2
0.4
0.1
0.1
0.1
+
0.1
+
4.9
1992
4.2
2.1
1.8
0.2
0.1
0.2
+
+
0.2
0.4
0.1
0.1
0.1
+
0.1
+
4.9
1993
4.2
2.1
1.9
0.2
0.1
0.2
+
+
0.2
0.4
0.1
+
0.1
+
0.1
+ .
4.9
1994
4.1
2.0
1.9
0.1
0.1
0.3
+
+
0.3
0.4
0.1
0.1
0.1
+
0.1
+
4.8
1995
4.1
2.0
1.8
0.1
0.1
0.3
+
+
0.3
0.4
0.1
0.1
0.1
+
0.1
+
4.8
1996
3.9
2.0
1.7
0.1
0.1
0.3
+
+
0.3
0.4
0.1
0.1
0.1
+
0.1
+
4.7
1997
3.8
1.9
1.7
0.1
0.1
0.3
+
+
0.3
0.4
0.1
0.1
0.1
+
0.2
+
4.6
1998
3.8
1.9
1.6
0.1
0.1
0.3
+
+
0.3
0.4
0.1
+
0.1
+
0.1
+
4.5
1999
3.7
1.9
1.6
0.1
0.1
0.3
+
+
0.3
0.4
0.1
+
0.1
+
0.2
+
4.4
2000
3.6
1.9
1.5
0.1
0.1
0.3
+
+
0.3
0.5
0.1
0.1
0.1
+
0.2
+
4.4
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
* "Other" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty
diesel powered utility equipment.
D-11
-------
Table D-15: NzO Emissions from Mobile Combustion (Tg
FueJ Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
1990
45.8
31.0
14.2
0.5
+
2.1
0.1
0.2
1.8
2.9
0.4
0.3
0.3
0.1
1.7
0.1
50.7
1991
48.1
30.8
16.7
0.6
+
2.1
0.1
0.2
1.8
2.8
0.4
0.2
0.3
0.1
1.6
0.1
53.0
1992
51.1
31.8
18.6
0.6
+
2.2
0.1
0.2
1.9
2.9
iOzEu.]
1993
53.1
32.4
20.1
0.6
+
2.3
0.1
0.2
2.0
2.9
0.4 [ 0.4
0.3
0.3
0.1
1.6
0.1
56.2
0.2
0.3
0.1
1.6
0.1
58.3
1994
54.3
33.0
20.6
0.7
+
2.5
0.1
0.2
2.2
2.9
0.4
0.2
0.3
0.1
1.7
0.1
59.8
1995
54.6
33.1
20.8
0.7
+
2.6
0.1
0.2
2.3
3.0
0.5
0.3
0.3
0.1
1.7
0.1
60.1
1996
54.2
32.7
20.7
0.7
+
2.7
0.1
0.2
2.4
3.0
0.4
0.3
0.3
0.1
1.8
0.1
59.8
1997
53.7
32.2
20.7
0.8
+
2.8
0.1
0.2
2.5
2.9
0.3
0.2
0.3
0.2
1.7
0.1
59.4
1998
53.1
32.0
20.3
0.8
+
2.9
0.1
0.3
2.6
2.8
0.3
0.2
0.3
0.2
1.8
0.1
58.8
1999
52.4
31.2
20.4
0.8
+
3.0
+
0.3
2.7
3.0
0.4
0.2
0.3
0.1
1.8
0.1
58.4
2000
51.6
30.6
20.1
0.8
+
3.1
+
0.3
2.7
3.4
0.6
0.2
0.3
0.2
1.9
0.1
58.0
+ Does not exceed 0.05 Tg COz Eq.
Note: Totals may not sum due to independent rounding. i
* "Other" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty
diesel powered utility equipment. |
Table D-16: NO, Emissions from Mobile Combustion, 1990-2000 IGg)
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft3
Other6
Total
1990
4,418
2,723
1,408
277
10
2,123
26
57
2,040
4,358
908
843
819
1,003
143
642
10,900
1991
4,744
2,774
1,669
291
10
2,112
30
10
2,072
4,729
955
842
837
1,020
141
934
11,585
1992
4,909
2,800 ;
1,818
281
11
2,129
30
10
2,089
5,045
926 •
858
854 !
1,036 1
142 !
1,230
12,084
1993
5,047
2,817
1,933
286
11
2,174
30
11
2,133
5,343
886
857
870
1,052
142
1,536
12,565
1994
5,156
2,867
1,959
318
11
2,261
31
11
2,219
5,705
898
859
886
1,069
146
1,848
13,123
1995
4,867
2,750
1,807
300
11
2,351
31
11
2,308
6,112
905
898
901
1,090
150
2,168
13,329
1996
4,747
2,716
1,550
470
11
3,230
13
7
3,210
6,361
1,041
704
852
1,153
73
2,537
14,338
1997
4,756
2,706
1,580
458
11
3,338
10
6
3,322
6,677
1,043
704
851
1,159
73
2,846
14,771
1998
4,629
2,649
1,545
424
11
3,368
8
5
3,355
6,979
1,044
704
844
1,155
73
3,159
14,976
1999
4,496
2,552
1,520
413
11
3,317
6
5
3,306
7,274
1,033
704
829
1,137
73
3,498
15,087
2000
4,388
2,519
1,459
398
12
3,004
6
4
2,994
7,549
1,041 '
704
815
1,114
76
3,799
14,941
1 Aircraft estimates include only emissions related to LTO cycles, andjtherefore do not include cruise altitude emissions.
b "Other" includes gasoline powered recreational, industrial, lawn and garden, light commercial, logging, airport service, other equipment; and
diesel powered recreational, industrial, lawn and garden, light construction, airport service.
Note: Totals may not sum due to independent rounding.
D-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table D17: CO Emissions from Mobile Combustion, 1990-2000 (Go)
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft3
Other"
Total
1990
51,840
31,576
15,530
4,562
172
1,180
20
42
1,119
16,503
2,041
110
527
1,148
820
11,857
69,523
1991
55,949
32,208
18,709
4,871
161
1,204
24
8
1,172
16,860
2,053
109
537
1,171
806
12,184
74,012
1992
54,326
30,466
19,538
4,160
162
1,227
24
8
1,195
17,236
2,054
113
547
1,194
818
12,511
72,789
1993
54,852
29,933
20,679
4,067
172
1,243
25
9
1,209
17,592
2,053
108
557
1,216
821
12,837
73,687
1994
55,750
30,048
20,515
5,011
176
1,315
26
9
1,280
17,959
2,060
104
566
1,238
830
13,162
75,024
1995
48,375
26,854
17,630
3,722
169
1,349
27
9
1,313
18,348
2,065
103
575
1,258
855
13,492
68,072
1996
47,443
26,285
15,307
5,679
171
1,899
11
6
1,882
25,586
2,137
70
458
1,452
327
21,141
74,927
1997
46,392
25,809
15,376
5,034
173
1,976
9
5
1,961
25,396
2,154
70
459
1,413
327
20,974
73,764
1998
45,496
25,606
15,375
4,338
177
2,005
7
'. 5
1,993
25,296
2,169
70
460
1,379
327
20,892
72,797
1999
43,075
24,043
14,998
3,868
166
2,050
6
4
2,040
25,440
2,076
70
468
1,336
327
21,163
70,565
2000
41,944
24,058
14,367
3,338
181
2,026
5
4
2,017
25,326
2,070
70
465
1,290
331
21,100
69,296
a Aircraft estimates include only emissions related to LTD cycles, and therefore do not include cruise altitude emissions.
b "Other" includes gasoline powered recreational, industrial, lawn and garden, light commercial, logging, airport service, other equipment; and
diesel powered recreational, industrial, lawn and garden, light construction, airport service.
Note: Totals may not sum due to independent rounding.
Table D-18: HMVOCs Emissions from Mobile Combustion, 1990-2000 IGgl
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft3
Other"
Total
1990
5,545
3,298
1,829
368
51
300
8
21
270
2,309
743
48
133
204
163
1,018
8,154
1991
5,753
3,240
2,103
378
33
288
10
4
275
2,341
748
47
133
208
161
1,045
8,383
1992
5,416
2,953
2,129
304
30
289
10
4
274
2,353
729
49
132
212
162
1,068
8,058
1993
5,470
2,901
2,241
296
31
289
10
5
274
2,381
731
47
132
216
160
1,095
8,140
1994
5,654
2,989
2,257
375
33
300
11
5
284
2,424
747
45
131
220
159
1,122
8,378
1995
4,980
2,714
1,937
295
34
296
11
5
280
2,449
738
45
130
225
161
1,150
7,725
1996
4,704
2,608
1,621
442
33
323
4
3
316
3,458
871
27
112
249
29
2,169
8,485
1997
4,632
2,578
1,623
398
33
301
4
3
295
3,324
877
27
110
240
29
2,041
8,257
1998
4,647
2,626
1,622
363
35
287
3
2
282
3,224
884
27
' 106
. 229
29
1,950
8,158
1999
4,573
2,599
1,596
340
38
264
3
2
259
3,125
844
27
100
214
29
1,911
7,962
2000
4,333
2,500
1,501
293
38
236
2
2
232
3,069
833
27
93
199
26
1,891
7,638
a Aircran. esumaies inciuae oniy emibbiuiib leiaieu iu m u LJUBS, aim mcieiuic uu HUI HH.IUUC oiuuc auuuuc ^....JOIUM-..
b "Other" includes gasoline powered recreational, industrial, lawn and garden, light commercial, logging, airport service, other equipment; and
diesel powered recreational, industrial, lawn and garden, light construction, airport service.
Note: Totals may not sum due to independent rounding.
Definitions of Emission Control Technologies and Standards
The N2O and CH4 emission factors used depend on the level of control technology or the emission standard
in place for each vehicle type. Table D-7 through Table D-ll show the years in which these technologies or
standards were in place and the penetration level for each vehicle type, and these categories are defined below.
Zero Emission Control
The category below is assigned to specific model years of gasoline or diesel vehicles for which no
emissions control technologies had yet been employed.
D-13
-------
Uncontrolled
Vehicles manufactured prior to the implementation of pollution control technologies are designated as uncontrolled.
Gasoline light-duty cars and trucks (pre-1973), gasoline [heavy-duty vehicles (pre-1984), diesel vehicles (pre-1983),
and motorcycles (pre-1996) are assumed to not have significant control technologies in place.
Gasoline Emission Controls
Below are the control technologies and emissions standards applicable to gasoline vehicles.
Non-catalyst
These emission controls were common in gasoline passenger cars and light-duty gasoline trucks during
model years (1973-1974) but phased out thereafter, in heavy-duty gasoline vehicles beginning in the mid-1980s, and
in motorcycles beginning in 1996. This technology | reduces hydrocarbon (HC) and carbon monoxide (CO)
emissions through adjustments to ignition timing and kir-fuel ratio, air injection into the exhaust manifold, and
exhaust gas recirculation (EGR) valves, which also helps'meet vehicle NOX standards (EPA 1994b).
Oxidation catalyst !
This control technology designation represents the introduction of the catalytic converter, and was the most
common technology in gasoline passenger cars and light-duty gasoline trucks made from 1975 to 1980 (cars) and
1975 to 1985 (trucks). This technology was also used in some heavy-duty gasoline vehicles between 1982 and the
present. The two-way catalytic converter oxidizes HC 'and CO, significantly reducing emissions over 80 percent
beyond non-catalyst-system capacity (EPA 1993). One rbason unleaded gasoline was introduced in 1975 was due to
the fact that oxidation catalysts cannot function properly with leaded gasoline (EPA 1994a).
TierO \
t
This emission standard from the Clean Air Act; was met through the implementation of early "three-way"
catalysts, therefore this technology was used in gasoline passenger cars and light-duty gasoline trucks sold
beginning in the early 1980s, and remained common until 1994. This more sophisticated emission control system
improves the efficiency of the catalyst by converting CO and HC to CO2 and H2O, reducing NOX to nitrogen and
oxygen, and using an on-board computer and oxygen sensor (EPA 1994a). In addition, this type of catalyst includes
a carburetor with electronic "trim" (IPCC 1996). New cars with three-way catalysts met the Clean Air Act's
amended standards (enacted in 1977) of reducing HC to Q.41 g/mile by 1980, CO to 3.4 g/mile by 1981 and NOX to
Ig/milebyl981.
fieri ;
This emission standard created through the 1990 amendments to the Clean Air Act called for a 40 percent
reduction from the 1981 standard. This was met through the use of more advanced 3-way catalysts, and applied to
light-duty gasoline vehicles beginning in 1994. This catalyst includes electronically controlled fuel injections and
ignition timing, EGR, and air injection. The Tier 1 standards reduce NOX emissions to 0.6 g/mile for cars and 0.6 to
1.53 g/mile for trucks (EPA 1999). j
Low Emission Vehicles (LEV)
This emission standard provides the highest mobile emission control in effect currently at the national
level. Applied to light-duty gasoline passenger cars and trucks beginning in small numbers in the mid-1990's, LEV
includes multi-port fuel injection with adaptive learning, an advanced computer diagnostics systems and heated
catalysts with secondary air injection (IPCC 1997). Currently, only California is assumed to have a significant level
of LEV vehicles. Ultra-low emission vehicles (ULEVs) and zero emission vehicles (ZEVs) are not incorporated into
this analysis, as the number of these vehicles is not assumed to be significant.
D-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Diesel Emission Controls
Below are the two levels of emissions control for diesel vehicles.
Moderate control
Improved injection timing technology and combustion system design for light- and heavy-duty diesel
vehicles (generally in place in model years 1983 to 1995) are considered moderate control technologies (IPCC
1997). These controls were implemented to meet emission standards for diesel trucks and buses adopted by the EPA
in 1985 to be met in 1991 and 1994.
Advanced control
EGR and modern electronic control of the fuel injection system are designated as advanced control
technologies. These technologies provide diesel vehicles with the current highest level of emission control, and were
used in model years beginning in 1996.
References
EPA (1993) Automobiles and Carbon Monoxide. Office of Mobile Sources, January, EPA 400-F-92-005.
(Available on the internet at .)
EPA (1994a) Automobile Emissions: An Overview. Office of Mobile Sources, August, EPA 400-F-92-007.
(Available on the internet at .)
EPA (1994b) Milestones in Auto Emissions Control. Office of Mobile Sources, August, EPA 400-F-92-014.
(Available on the internet at .)
EPA (1998) Emissions of Nitrous Oxide from Highway Mobile Sources: Comments on the Draft Inventory of U.S.
Greenhouse Gas Emissions and Sinks, 1990-1996. Office of Mobile Sources, Assessment and Modeling Division,
August, EPA420-R-98-009. (Available on the internet at .)
EPA (1999) Emission Facts: The History of Reducing Tailpipe Emissions. Office of Mobile Sources, May, EPA
42Q-F-99-017. (Available on the internet at )
IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Paris:
Intergovernmental Panel on Climate Change, United Nations Environment Programme, Organization for Economic
Co-Operation and Development, International Energy Agency.
D-15
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D-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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ANNEX E
Methodology for Estimating CH4 Emissions from Coal Mining
The methodology for estimating methane emissions from coal mining consists of two distinct steps. The
first step addresses emissions from underground mines. For these mines, emissions are estimated on a mine-by-
mine basis and then are summed to determine total emissions. The second step of the analysis involves estimating
methane emissions for surface mines and post-mining activities. In contrast to the methodology for underground
mines, which uses mine-specific data, the surface mine and post-mining activities analysis consists of multiplying
basin-specific coal production by basin-specific emission factors.
Step 1: Estimate Methane Liberated and Methane Emitted from Underground Mines
Underground mines generate methane from ventilation systems and from degasification systems. Some
mines recover and use methane generated from degasification systems, thereby reducing emissions to the
atmosphere. Total methane emitted from underground mines equals the methane liberated from ventilation systems,
plus the methane liberated from degasification systems, minus methane recovered and used.
Step 1.1: Estimate Methane Liberated from Ventilation Systems
All coal mines with detectable methane emissions1 use ventilation systems to ensure that methane levels
remain within safe concentrations. Many coal mines do not have detectable levels of methane, while others emit
several million cubic feet per day (MMCFD) from their ventilation systems. On a quarterly basis, the U.S. Mine
Safety and Health Administration (MSHA) measures methane emissions levels at underground mines. MSHA
maintains a database of measurement data from all underground mines with detectable levels of methane in their
ventilation air. Based on the four quarterly measurements, MSHA estimates average daily methane liberated at each
of the underground mines with detectable emissions.
For the years 1990 through 1996 and 1998 through 2000, MSHA emissions data were obtained for a large
but incomplete subset of all mines with detectable emissions. This subset includes mines emitting at least 0.1
MMCFD for some years and at least 0.5 MMCFD for other years, as shown in Table E-l. Well over 90 percent of
all ventilation emissions were concentrated in these subsets. For 1997, the complete MSHA database for all 586
mines with detectable methane emissions was obtained. These mines were assumed to account for 100 percent of
methane liberated from underground mines. Using the complete database from 1997, the proportion of total
emissions accounted for by mines emitting less than 0.1 MMCFD or 0.5 MMCFD was estimated (see Table E-l).
The proportion was then applied to the years 1990 through 2000 to account for the less than 10 percent of ventilation
emissions coming from mines without MSHA data.
For 1990-1999, average daily methane emissions were multiplied by 365 to determine the annual emissions
for each mine. For 2000, MSHA provided quarterly emissions. The average daily methane emissions were
multiplied by the number of days corresponding to the number of quarters the mine vent was operating. For
example, if the mine vent was operational in one out of the four quarters, the average daily methane emissions were
multiplied by 92 days. Total ventilation emissions for a particular year were estimated by summing emissions from
individual mines.
1 MSHA records coal mine methane readings with concentrations of greater than 50 ppm (parts per million) methane.
Readings below this threshold are considered non-detectable.
E-1
-------
Table E-1: Mine-Specific Data Dsed le Estimate Ventilation Emissions
Year
Individual Mine Data Used
1990 All Mines Emitting at Least 0.1 MMCFD (Assumed to Account for 97.8% of Total)*
1991 1990 Emissions Factors Used Instead of Mine-SpecifioData
1992 1990 Emissions Factors Used Instead of Mine-SpecificiData
1993 All Mines Emitting at Least 0.1 MMCFD (Assumed to Apcount for 97.8% of Total)*
1994 All Mines Emitting at Least 0.1 MMCFD (Assumed to Afccounl for 97.8% of Total)*
1995 All Mines Emitting at Least 0.5 MMCFD (Assumed to Account for 94.1 % of Total)*
1996 All Mines Emitting at Least 0.5 MMCFD (Assumed to Apcount for 94.1% of Total)*
1997 All Mines with Delectable Emissions (Assumed to Account for 100% of Total)
1998 All Mines Emitting at Least 0.1 MMCFD (Assumed to Apcount for 97.8% of Total)*
1999 All Mines Emitting at Least 0.1 MMCFD (Assumed to Account for 97.8% of Total)*
2000 AH Mines Emitting at Least 0.1 MMCFD (Assumed to Account for 97.8% of Total)*
* Factor derived from a complete set of individual mine data collected for 1997.
Step 1.2: Estimate Methane Liberated from Degasification Systems
Coal mines use several different types of degasification systems to remove methane, including vertical
wells and horizontal boreholes to recover methane prior to mining of the coal seam. Gob wells and cross-measure
boreholes recover methane from the overburden (i.e., GDB area) after mining of the seam (primarily in longwall
mines). :
MSHA collects information about the presence and type of degasification systems in some mines, but does
not collect quantitative data on the amount of methane liberated. Thus, the methodology estimated degasification
emissions on a mine-by-mine basis based on other sources of available data. Many of the coal mines employing
degasification systems have provided EPA with information regarding methane liberated from their degasification
systems. For these mines, this reported information wa^ used as the estimate. In other cases in which mines sell
methane recovered from degasification systems to a pipeline, gas sales were used to estimate methane liberated from
degasification systems (see Step 1.3). Finally, for those ;mines that do not sell methane to a pipeline and have not
provided information to EPA, methane liberated from degasification systems was estimated based on the type of
system employed. For example, for coal mines employing gob wells and horizontal boreholes, the methodology
assumes that degasification emissions account for 40 percent of total methane liberated from the mine.
Step 1.3: Estimate Methane Recovered from Degasification Systems and Used (Emissions Avoided)
In 2000, ten active coal mines had methane recovery and use projects and sold the recovered methane to a
pipeline. One coal mine also used some recovered methane in a thermal dryer in addition to selling gas to a
pipeline. In order to calculate emissions avoided from pipeline sales, information was needed regarding the amount
of gas recovered and the number of years in advance of mining that wells were drilled. Several state agencies
provided gas sales data, which were used to estimate emissions avoided for these projects. Additionally, coal mine
operators provided information on gas sales and/or the number of years in advance of mining. Emissions avoided
were attributed to the year in which the coal seam was mined. For example, if a coal mine recovered and sold
methane using a vertical well drilled five years in advance of mining, the emissions avoided associated with those
gas sales (cumulative production) were attributed to the \Yell up to the time it was mined through (e.g., five years of
gas production). Where individual well data is not available, estimated percentages of the operator's annual gas
sales within the field around the coal mine are attributed, to emissions avoidance. For some mines, individual well
data were used to assign gas sales to the appropriate emissions avoided year. In most cases, coal mine operators
provided this information, which was then used to estimate emissions avoided for a particular year. Additionally,
several State agencies provided production data for individual wells.
i
i
Step 2: Estimate Methane Emitted from Surface Mines and Post-Mining Activities
Mine-specific data were not available for estimating methane emissions from surface coal mines or for
post-mining activities. For surface mines and post-mining activities, basin-specific coal production was multiplied
by a basin-specific emission factor to determine methane emissions.
E-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Step 2.1: Define the Geographic Resolution of the Analysis and Collect Coal Production Data
The first step in estimating methane emissions from surface mining and post-mining activities was to define
the geographic resolution of the analysis and to collect coal production data at that level of resolution.; The analysis
was conducted by coal basin as defined in Table E-2, which presents coal basin definitions by basin and by state.
The Energy Information Agency's (EIA) Coal Industry Annual reports state- and county-specific
underground and surface coal production by year. To calculate production by basin, the state level data were
grouped into coal basins using the basin definitions listed in Table E-2. For two states—West Virginia and
Kentucky—county-level production data was used for the basin assignments because coal production occurred from
geologically distinct coal basins within these states. Table E-3 presents the coal production data aggregated by
basin.
Step 2.2: Estimate Emissions Factors for Each Emissions Type
Emission factors for surface mined coal were developed from the in situ methane content of the surface
coal in each basin. Based on an analysis presented in EPA (1993), surface mining emission factors were estimated
to be from 1 to 3 times the average in situ methane content in the basin. For this analysis, the surface mining
emission factor was determined to be twice the in situ methane content in the basin. Furthermore, the post-mining
emission factors used were estimated to be 25 to 40 percent of the average in situ methane content in the basin. For
this analysis, the post-mining emission factor was determined to be 32.5 percent of the in situ methane content in the
basin. Table E-4 presents the average in situ content for each basin, along with the resulting emission factor
estimates.
Step 2.3: Estimate Methane Emitted
The total amount of methane emitted was calculated by multiplying the coal production in each basin by
the appropriate emission factors.
Total annual methane emissions is equal to the sum of underground mine emissions plus surface mine
emissions plus post-mining emissions. Table E-5 and Table E-6 present estimates of methane liberated, used, and
emitted for 1990 through 2000. Table E-7 provides emissions by state.
E-3
-------
Table E-2: Dial Basin Definitions by Basin and by State
Basin
States
Northern Appalachian Basin
Central Appalachian Basin
Warrior Basin
Illinois Basin
South West and Rockies Basin
North Great Plains Basin
West Interior Basin
Northwest Basin
Maryland, Ohio, Pennsylvania, West Virginia North
Kentucky East, Tennessee, Virginia, West Virginia South
Alabama, Mississippi
Illinois, Indiana, Kentucky West
Arizona, California, Colorado, New Mexico, Utah
Montana, North Dakota, Wyoming'
Arkansas, Iowa, Kansas, Louisiana, Missouri, Oklahoma, Texas
Alaska, Washington
State
Basin
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Illinois
Indiana
Iowa
Kansas
Kentucky East
Kentucky West
Louisiana
Maryland
Mississippi
Missouri
Montana
New Mexico
North Dakota
Ohio
Oklahoma
Pennsylvania.
Tennessee
Texas
Utah
Virginia
Washington
West Virginia South
West Virginia North
Wyoming
Warrior Basin
Northwest Basin i
South West and Rockies Basin
West Interior Basin :
South West and Rockies Basin
South West and Rockies Basin
Illinois Basin
Illinois Basin j
West Interior Basin ;
West Interior Basin ,
Central Appalachian Basin
Illinois Basin
West Interior Basin I
Northern Appalachian Basin
Warrior Basin
West Interior Basin
North Great Plains Basin
South West and Rockies Basin
North Great Plains Basin
Northern Appalachian Basin
West Interior Basin '
Northern Appalachian Basin
Central Appalachian Basin
West Interior Basin :
South West and Rockfes Basin
Central Appalachian Basin
Northwest Basin
Central Appalachian Basin
Northern Appalachian Basin
North Great Plains Basin
E-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table E-3: Annual Coal Production (Thousand Shan Tons)
Underground Coal Production
Basin
N. Appalachia
Cent. Appalachia
Warrior
Illinois
S. West/Rockies
N. Great Plains
West Interior
Northwest
Total
1990
103,865
198,412
17,531
69,167
32,754
1,722
105
0
423,556
1991
103,450
181,873
17,062
69,947
31,568
2,418
26
0
406,344
1992
105,220
177,777
15,944
73,154
31,670
2,511
59
0
406,335
Surface Coal Production
Basin
N. Appalachia
Cent. Appalachia
Warrior
Illinois
S. West/Rockies
N. Great Plains
West Interior
Northwest
Total
1990
60,761
94,343
11,413
72,000
43,863
249,356
64,310
6,707
602,753
1991
51,124
91,785
10,104
63,483
42,985
259,194
61,889
6,579
587,143
1992
50,512
95,163
9,775
58,814
46,052
258,281
63,562
6,785
588,944
1993
77,032
164,845
15,557
55,967
35,409
2,146
100
0
351,056
1993
48,641
94,433
9,211
50,535
48,765
275,873
60,574
6,340
594,372
1994
100,122
170,893
14,471
69,050
41,681
2,738
147
0
399,102
1994
44,960
106,129
8,795
51,868
49,119
308,279
58,791
6,460
634,401
1995
98,103
166,495
17,605
69,009
42,994
2,018
25
0
396,249
1995
39,372
106,250
7,036
40,376
46,643
331,367
59,116
6,566
636,726
1996
106,729
171,845
18,217
67,046
43,088
2,788
137
0
409,850
1996
39,788
108,869
6,420
44,754
43,814
343,404
60,912
6,046
654,007
1997
112,135
177,720
18,505
64,728
44,503
2,854
212
0
420,657
1997
40,179
113,275
5,963
46,862
48,374
349,612
59,061
5,945
669,271
1998
116,718
171,279
17,316
64,463
45,983
1,723
247
0
417,729
1998
41,043
108,345
5,697
47,715
49,635
385,438
57,951
5,982
699,608
1999
107,575
157,058
14,799
63,529
46,957
1,673
200
0
391,791
1999
33,928
107,507
4,723
40,474
50,349
407,683
58,309
5,666
708,639
2000
105,374
150,584
15,895
53,720
45,742
1,210
241
0
372,766
2000
34,908
110,479
4,252
33,631
49,587
407,670
54,170
5,911
700,608
Total Coal Production
Basin
N. Appalachia
Cent. Appalachia
Warrior
Illinois
S. West/Rockies
N. Great Plains
West Interior
Northwest
1990
164,626
292,755
28,944
141,167
76,617
251,078
64,415
6,707
1991
154,574
273,658
27,166
133,430
74,553
261,612
61,915
6,579
1992
155,732
272,940
25,719
131,968
77,722
260,792
63,621
6,785
1993
125,673
259,278
24,768
106,502
84,174
278,019
60,674
6,340
1994
145,082
277,022
23,266
120,918
90,800
311,017
58,938
6,460
1995
137,475
272,745
24,641
109,385
89,637
333,385
59,141
6,566
1996
146,517
280,714
24,637
111,800
86,902
346,192
61,049
6,046
1997
152,314
290,995
24,468
111,590
92,877
352,466
59,273
5,945
1998
157,761
279,624
23,013
110,176
95,618
387,161
58,198
5,982
1999
141,145
262,660
19,499
103,966
96,207
406,324
58,509
5,665
2000
140,282
261,063
20,147
87,351
95,239
408,880
54,411
5,911
Total
1,026,309 993,487 995,279 945,428 1,033,503 1,032,975 1,063,857 1,089,928 1,118,132 1,093,975 1,073,374
Source for 1990-99 data: EIA (1990-99), Coal Industry Annual. U.S.Department of Energy, Washington, DC, Table 3.
Source for 2000 data: EIA (2001) Personal Communication on August 29,2001, U.S. Department of Energy, Washington, DC.
Note: Totals may not sum due to independent rounding.
Table E-41: Coal Surface and Post-Mining Methane Emission Factors Iff per Short Ten)
Surface Average Underground Average Surface Mine Post-Mining Post Mining
Basin in situ Content In situ Content Factors Surface Factors Underground
Northern Appalachia
Central Appalachia
Warrior
Illinois
S. West/Rockies
N. Great Plains
West Interior
Northwest
49.3
49.3
49.3
39.0
15.3
3.2
3.2
3.2
171.7
330.7
318.0
57.20
225.8
41.67
41.67
41.67
98.6
98.6
98.6
78.0
30.6
6.4
6.4
6.4
16.0
16.0
16.0
12.7
5.0
1.0
1.0
1.0
55.8
107.5
103.4
18.6
73.4
13.5
13.5
13.5
Source: EPA (1993), Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to Congress, U.S. Environmental
Protection Agency, Air and Radiation, April.
E-5
-------
Table E-5: Underground Dial Mining Methane Emissions (Billion Cubic Feel]
Activity
Ventilation Output
Adjustment Factor for Mine Data'
Adjusted Ventilation Output
Degasification System Liberated
Total Underground Liberated
Recovered & Used
Total
' Refer to Table E-1.
1990 1991 1992 1993 1994
112 NA NA 95 96
97.8% NA NA 97.8% 97.8%
114 NA NA 97 98
54 NA NA 45 46
167 164 162 142 144
(14) (15) (17) (23) (27)
154 149 1^4 119 117
1995 1996 1997
102 90 96
91.4% 91.4% 100%
111 99 96
46 50 42
157 149 138
(30) (36) (28)
127 113 110
1998
94
97.8%
96
49
146
(35)
110
1999 2000
92 87
97.8% 97.8%
94 89
41 45
135 134
(32) (36)
103 98
Note: Totals may not sum due to independent rounding.
Table E-6: Total Coal Mining II
Activity
Underground Mining
Surface Mining
Post-Mining (Underground)
Post-Mining (Surface)
Total
lethane Emissions (Billie
1990 1991 1992
154 149 144
25 23 23
33 31 30
444
216 209 201
Note: Totals may not sum due to independent rounding.
i Cubic Feet!
1993 1994 1995
119 117 127
23 24 22
27 30 30
444
173 175 183
1996 1997 1998
113 110 110
23 24 23
31 32 31
444
172 170 163
1999
103
22
29
4
161
21900
98
22
28
4
150
Table E-7: Tiial Dial Mining Methane Emissions by State (Million Cubic Feet!
State 19901E
Alabama 33,1 75 |k.
Alaska 13||
Arizona 402lt
Arkansas OB
California 2B
Colorado 10-117B
Illinois 10.643B
Indiana 3,149^
Iowa 3B|
Kansas sBI
Kentucky 21,22g|||
Louisiana 24B1
Maryland 510.B
Mississippi -•jj
Missouri 20B
Montana 280H:
New Mexico 905 •|j
North Dakota 21?B
Ohio 4.710B
Oklahoma 13fife
Pennsylvania 22,573 E
Tennessee 800 ••
Texas ^IsHjj
Utah 4<562B
Virginia 45,883 ^
Washington 37 ••
West Virginia 55,280 •1
Wyoming 1.382B
Total 216,350 IE
1993 1994
26,694 30,283
12 12
433 464
0 0
-
7,038 9,029
8,737 10,624
2,623 2,791
1 0
3 2
19,823 21,037
23 26
245 256
-
5 6
267 310
1,186 1,223
238 240
4,110 4,377
14 52
26,437 24,026
350 338
406 389
4,512 3,696
30,457 26,765
35 36
37,803 36,854
1,578 1,782
I 173,029 174,622
1995 1996
39,334 29,928
13 11
425 371
0 0
-
8,541 5,795
11,106 10,890
2,106 2,480
-
2 2
19,103 18,292
28 24
259 287
-
4 5
294 283
980 856
224 222
3,900 3,992
14 14
27,086 26,567
366 418
392 410
3,541 4,061
19,893 19,847
36 34
42,992 42,870
1,977 2,090
182,616 169,750
1997 1998
26,440 27,058
11 10
417 403
0 0
0
9,057 9,057
8,571 7,859
3,088 3,239
0
3 3
20,089 19,240
26 24
296 282
0
3 3
305 319
961 1,026
220 223
4,313 4,244
132 137
30,339 29,853
390 309
397 391
4,807 5,060
16,972 14,087
33 35
40,197 43,511
2,122 2,351
169,190 168,725
1999
26,209
12
419
0
0
9,296
7,812
2,980
0
3
18,255
22
260
2
3
306
1,042
232
3,820
209
24,088
349
395
4,851
13,539
31
41,500
2,520
158,153
2000
23,997
12
466
0
0
10,677
8,531
2,492
0
1
16,910
27
345
92
3
285
972
233
3,443
208
25,352
306
361
4,045
12,179
32
37,490
2,533
151,397
Does not exceed 0.5 Million Cubic Feet
Note: The emission estimates provided above are inclusive of emissions from underground mines, surface mines and post-mining activities.
The following states have neither underground nor surface mining and thus report no emissions as a result of coal mining: Connecticut,
Delaware, Florida, Georgia, Hawaii, Idaho, Maine, Massachusetts,' Michigan, Minnesota, Nebraska, Nevada, New Hampshire, New Jersey,
New York, North Carolina, Oregon, Rhode Island, South Carolina, South Dakota, Vermont, and Wisconsin. Emission estimates are not given
for 1991 and 1992 because underground mine data was not available for those years.
E-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX F
Methodology for Estimating CH4 Emissions from Natural Gas Systems
The following steps were used to estimate methane emissions from natural gas systems.
Step 1: Calculate Emission Estimates for Base Year 1992 Using GRI/EPA Study
The first step in estimating methane emissions from natural gas systems was to develop a detailed base year
estimate of emissions. The study by GRI/EPA (1996) divides the industry into four stages to construct a detailed
emission inventory for the year 1992. These stages include: field production, processing, transmission and storage
(i.e., both underground and liquefied gas storage), and distribution. This study produced emission factors and
activity data for over 100 different emission sources within the natural gas system. Emissions for 1992 were
estimated by multiplying activity levels by emission factors for each system component and then summing by stage.
Since publication, the EPA has updated 1992 activity data for some of the components in the system. Table F-l
displays the 1992 GRI/EPA activity levels and emission factors for venting and flaring from the field production
stage, and the current EPA activity levels and emission factors. These data are shown to illustrate the kind of data
used to calculate emissions from all stages.
Step 2: Collect Aggregate Statistics on Main Driver Variables
As detailed data on each of the over 100 sources were not available for the period 1990 through 1999,
activity levels were estimated using aggregate statistics on key drivers, including: number of producing wells (IP A A
1990 through 2000, EIA 2000), number of gas plants (AGA 1990 through 1998; PennWell Corporation 1999, 2000,
2001), miles of transmission pipeline (OPS 1998, 1999, 2000, 2001), miles of distribution pipeline, (OPS, 2001),
miles of distribution services (OPS, 2001), and energy consumption (EIA 1998, 1999, 2000, 2001). Data on the
distribution of gas mains and services by material type was not available for 1990 through 1992 from OPS. For
those years, the distribution by type was back calculated from 1993 using compound growth rates determined for the
years 1993 through 2000. Table F-2 provides the activity levels of some of the key drivers in the natural gas
analysis.
Step 3: Estimate Emission Factor Changes Over Time
For the period 1990 through 1995, the emission factors were held constant, based on 1992 values.
However, the natural gas industry is experiencing ongoing broad based technology improvements, which are
expected to continue. These improvements have increased operating efficiency, thus reducing methane emissions.
An assumed improvement in technology and practices was estimated to reduce emission factors by 5 percent by the
year 2020. This assumption, annualized, amounts to a 0.2 percent decline in the 1996 emission factor, a 0.4 percent
decline in the 1997 emission factor, a 0.6 percent decline in the 1998 emission factor and a 0.8 percent decline in the
1999 emission factor, all relative to 1995 emission factors.
Step 4: Estimate Emissions for Each Year and Stage
Emissions from each stage of the natural gas industry were estimated by multiplying the activity factors by
the appropriate emission factors, summing all sources for each stage, and then subtracting the Natural Gas STAR
emission reductions.1 Methane reductions from the Natural Gas STAR program for the years 1994 through 2000 are
presented in Table F- 3. Emission reductions by project are reported by industry partners using actual,measurement
data or equipment-specific emission factors. Before incorporating the reductions into the Inventory, quality
assurance and quality control checks are undertaken to identify errors, inconsistencies, or irregular data. Total
1 It is assumed that the 5 percent decline in the emissions factor from 1995 to 2020 does not reflect emission
reductions attributed to Natural Gas STAR. The emission factor decline accounts for regular technology imprpvements only.
This assumption is being investigated for future inventories.
F-1
-------
emissions were estimated by adding the emission estimates from each stage. Table F-4 illustrates emission
estimates for venting and flaring emissions from the field production stage using this methodology. Table F-5
presents total natural gas production and associated methane emissions.
F-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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F-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX G
Methodology for Estimating CH4 Emissions from Petroleum Systems
The methodology for estimating methane emissions from petroleum systems is based on the 1999 EPA
draft report, Estimates of Methane Emissions from the U.S. Oil Industry (EPA 1999) and Radian's Study, Methane
Emissions from the U.S. Petroleum Industry (Radian 1996). Seventy activities that emit methane from petroleum
systems were examined for these reports. Most of the activities analyzed involve crude oil production field
operations, which accounted for 97 percent of total oil industry emissions. Crude transportation and refining
accounted for the remaining emissions at about one and two percent each, respectively.
The following steps were taken to estimate methane emissions from petroleum systems.
Stepl: Determine Emission Factors for all activities
The emission factors for 1995 are taken from the 1999 EPA draft report, which contains the most recent
and comprehensive determination of emission factors for the seventy methane emitting activities in the oil industry.
The emission factors determined for 1995 are assumed to be representative of emissions from each source type over
the period 1990 through 2000. Therefore, the same emission factors are used for each year throughout this period.
Step 2: Determine Activity Levels for Each Year
Activity levels change from year to year. Some factors change in proportion to crude oil rates: production,
transportation, or refinery runs. Some change in proportion to the number of facilities: oil wells or petroleum
refineries. Some factors change proportional to both rate and number of facilities.
For fifty-seven of the seventy activities, activity levels for 1995 are taken from EPA. For the remaining
thirteen activities, the activity level for 1993 is taken from Radian (1996). These thirteen activity levels were
derived from field data collected in 1993, along with.1993 crude oil production and number of wells.
For both sets of data, a determination was made on a case-by-case basis, as to which measure of petroleum
industry activity best reflects the change in annual activity relative to the base years (1993 and 1995). Publicly
reported data from the Minerals Management Service (MMS), Energy Information Administration (EIA), American
Petroleum Institute (API) and the Oil & Gas Journal (O&GJ) were used to extrapolate the activity levels from the
base year to each year between 1990 to 2000. Data used include total domestic crude oil production, number of
domestic crude oil wells, total imports and exports of crude oil, and total petroleum refinery crude runs. For a small
number of sources, 2000 data were not yet available. In these cases, the 2000 activity factors were used. In the few
cases where no data was located, activity data based on oil industry expert judgment were used.
Step 3: Estimate Methane Emissions for Each Activity for Each Year
Annual emissions from each of the 70 petroleum system activities analyzed were estimated by multiplying
the activity data for each year by the corresponding emission factor. These annual emissions for each activity are
then summed to estimate the total annual methane emissions. Table G-l, Table G-2, and Table G-3 provide the
2000 activity factors, emission factors, and emission estimates.
Table G-4 provides a summary of emission estimates for the years 1990 through 2000.
G-1
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ANNEX H
Methodology for Estimating C02 Emissions from Municipal Solid Waste Combustion
Emissions of CO2 from MS W combustion include CO2 generated by the combustion of plastics, synthetic
rubber and synthetic fibers in MSW, and combustion of synthetic rubber and carbon black in tires. Combustion of
MSW also results in emissions of N2O. The methodology for calculating emissions from each of these waste
combustion sources is described in this Annex.
COz from Plastics Combustion
In the report, Characterization of Municipal Solid Waste in the United States (EPA 2000c), the flows of
plastics in the U.S. waste stream are reported for seven resin categories. The 1998 quantity generated, recovered,
and discarded for each resin is shown in Table H-l. The EPA report does not provide estimates for individual
materials landfilled and combusted, although it does provide such an estimate for the waste stream as a whole. To
estimate the quantity of plastics landfilled and combusted, total discards were apportioned based on the proportions
of landfilling and combustion for the entire U.S. waste stream in 1998 (76 percent and 24 percent, respectively).
Emissions for 1990 through 1997 were calculated using the same approach. Figures for 1999 and 2000 are
calculated using 1998 resin ratios and forecasted from 1998 figures for generation and recovery using a 2.85 percent
annual growth rate for plastics generation and a 5.4 percent growth rate for the plastics recovery rate, based on
reported trends (EPA 2000c).
Table H-1:1998 Plastics in the Municipal Solid Waste Stream by Resin [fig)
Waste Pathway
Generation
Recovery
Discard
Landfill
Combustion
Recovery*
Discard*
Landfill*
Combustion*
PET
2,023
354
1,669
1,269
401
17%
83%
63%
20%
HOPE
4,500
399
4,101
3,116
984
9%
91%
69%
22%
PVC
1,243
0
1,243
945
298
0%
100%
76%
24%
LDPE/
LLDPE
4,844
127
4,717
3,585
1,132
3%
97%
74%
23%
PP
2,576
154
2,422
1,841
581
6%
94%
71%
23%
PS
1,969
18
1,950
1,482
468
1%
99%
75%
24%
Other
3,139
45
3,094
2,351
742
1%
99%
75%
24%
Total
20,294
1,098
19,196
14,589
4,607
5%
95%
72%
23%
*As a percent of waste generation.
Note: Totals may not sum due to independent rounding. Abbreviations: PET (polyethylene terephthalate), HOPE (high density polyethylene),
PVC (polyvinyl chloride), LDPE/LLDPE (linear low density polyethylene), PP (polypropylene), PS (polystyrene).
Fossil fuel-based CO2 emissions for 1998 were calculated as the product of plastic combusted, carbon
content, and fraction oxidized (see Table H-2). The carbon content of each of the six types of plastics is listed, with
the value for "other plastics" assumed equal to the weighted average of the six categories. The fraction oxidized
was assumed to be 98 percent.
Table H-2:1998 Plastics Combusted IGg), Carbon Content [%), and Carbon Combusted (eg)
Factor
Quantity Combusted
Carbon Content of Resin
Carbon in Resin Combusted
Emissions (Tg COz Eq.)b
PET
401
63%
250
0.9
HOPE
984
86%
844
3.0
PVC
298
38%
115
0.4
LDPE/
LLDPE
1,132
86%
970
3.5
PP
581
86%
498
1.8
PS
468
92%
432
1.6
Other
742
66% =
489
1.8
Total
4,607
3,598
12.9
' Weighted average of other plastics produced in 1998 production.
b Assumes a fraction oxidized of 98 percent.
H-1
-------
COz from Combustion of Synthetic Rubber and Carbon Black in Tires
Emissions from tire combustion require two pieces of information: the amount of tires combusted and the
carbon content of the tires. The Scrap Tire Use/Disposal Study 1998/1999 Update (STMC 1999) reports that 114
million of the 270 million scrap tkes generated in 1998 (approximately 42 percent of generation) were used for fuel
purposes. Using STMC estimates of average tire composition and weight, the weight of synthetic rubber and carbon
black in scrap tines was determined. Synthetic rubber in tires was estimated to be 90 percent carbon by weight,
based on the weighted average carbon contents of the major elastomers used in new tire consumption (see Table H-
3).' Carbon black is 100 percent carbon. Multiplying the proportion of scrap tires combusted by the total carbon
content of the synthetic rubber and carbon black portion of scrap tires yielded CO2 emissions, as shown in Table H-
4. Note that the disposal rate of rubber in tires (0.4 Tg/yr) is smaller than the consumption rate for tires based on
summing the elastomers listed in Table H-3 (1.3 Tg/yr); th'is is due to the fact that much of the rubber is lost through
tire wear during the product's lifetime and due to the la'g time between consumption and disposal of tires. Tire
production and fuel use for 1999 and 2000 were extrapolated from trend data for 1994 through 1998.
Table H-3: Elastomers Consumed in 1998 (Go)
Elastomer
Styrene butadiene rubber solid
For Tires
For Other Products*
Polybutadiene
For Tires
For Other Products
EthylenePropylene
For Tires
For Other Products
Polychloroprene
For Tires
For Other Products
Nilrile butadiene rubber solid
For Tires
For Olher Products
Polyisoprene
For Tires
For Other Products
Others
For Tires
For Other Products
Total
Carbon
Consumed Content
908 91%
743 | 91%
165 j 91%
561 ' 89%
404
157
320
89%
89%
86%
10 86%
310 86%
69
0
69
87
1
59%
59%
59%
77%
77%
86 77%
78 88%
65 88%
13
88%
369 88%
63 : 88%
306 88%
2,392
Carbon
Equivalent
828
677
151
499
359
140
274
8
266
40
0
40
67
1
67
69
57
12
324
56
268
2,101
"Used to calculate carbon content of non-lire rubber products in municipal solid waste.
- Not applicable ,
Table H-4: Scrap Tire Constituents and COz Emissions from Scrap Tire Combustion in 1998
Material
Weight of Material
Carbon Content
Percent Combusted
Emissions
fTgCQ2Eq.r
Synthetic Rubber
Carbon Black
0.4
0.5
90%
100%
42%
42%
1.1
1.7
Total
0.8
2.9
* Assumes a fraction oxidized of 98 percent.
-Not applicable
1 The carbon content of tires (1,158,000 Tg) divided by for the mass of tires (1,285,000 Tg) equals 90 percent.
H-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
C02 from Combustion of Synthetic Rubber in Municipal Solid Waste
Similar to the methodology for scrap tires, CO2 emissions from synthetic rubber in MSW were estimated
by multiplying the amount of rubber combusted by an average rubber carbon content. The amount of rubber in the
MSW stream was estimated from data provided in the Characterization of Municipal Solid Waste in the United
States (EPA 2000c). The report divides rubber found in MSW into three product categories: other durables (not
including tires), non-durables (which includes clothing and footwear and other non-durables), and .containers and
packaging. Since there was negligible recovery for these product types, all the waste generated can be considered
discarded. Similar to the plastics method, discards were apportioned based on the proportions of landfilling and
combiistion for the entire U.S. waste stream (76 percent and 24 percent, respectively). The report aggregates rubber
and leather in the MSW stream; an assumed synthetic rubber content was assigned to each product type, as shown in
Table H-5.2 A carbon content of 85 percent was assigned to synthetic rubber for all product types, according to the
weighted average carbon content of rubber consumed for non-tire uses (see Table H-4). For 1999 arid 2000, waste
generation values were not available so an average annual rate of increase in generation of synthetic rubber in MSW
of 1.85 percent (based on statistics in EPA 2000c) was used to project generation in these years.
Table H-5: Rubber and Leather in Municipal Solid Waste in 1998
Product Type
Durables (not Tires)
Non-Durables
Clothing and Footwear
Other Non-Durables
Containers and Packaging
Total
Carbon Content (%)
Generation (Gg) Synthetic Rubber (%)
2,141
744
526
218
18
2,903
100%
100%
25%
75%
100%
•
85%
85%
85%
85%
85%
-
Emissions
(TgCOzEq.)*
1.6
0.2
0.1
0.1
+
1.8
'Assumes a fraction oxidized of 98 percent.
+ Less than 0.05 Tg COz Eq.
- Not applicable
COz from Combustion of Synthetic Fibers
Carbon dioxide emissions from synthetic fibers were estimated as the product of the amount of synthetic
fiber discarded annually and the average carbon content of synthetic fiber. Fiber in the MSW stream was estimated
from data provided in the Characterization of Municipal Solid Waste in the United States (EPA 2000c) for textiles.
The amount of synthetic fiber in MSW was estimated by subtracting (a) the amount recovered from (b) the waste
generated (see Table H-6). As with the other materials in the MSW stream, discards were apportioned based on the
proportions of landfilling and combustion for the entire U.S. waste stream (76 percent and 24 percent, respectively).
It was assumed that approximately 55 percent of the fiber was synthetic in origin, based on information received
from the Fiber Economics Bureau (DeZan 2000). An average carbon content of 70 percent was assigned to
synthetic fiber using the production-weighted average of the carbon contents of the four major fiber types (polyester,
nylon, olefin, and acrylic) produced in 1998 (see Table H-7). The equation relating CO2 emissions to the amount of
textiles combusted is shown below. Since 1999 and 2000 values were not provided in the Characterization report,
generation and recovery rates were forecast by applying their respective average annual growth rates for 1990
through 1998 to the 1998 values.
CO2 Emissions from the Combustion of Synthetic Fibers = Annual Textile Combustion (Gg) x
(Percent of Total Fiber that is Synthetic) x (Average Carbon Content of Synthetic Fiber) x
(44gC02/12gC)
2 As a biogenic material, the combustion of leather is assumed to have no net carbon dioxide emissions.
H-3
-------
Table H-6: Textiles in MSW IGgj
Year
Generation
Recovery
Discards
Combustion
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999'
2000'
2,884
3,064
3,225
3,458
3,674
3,674
3,832
4,090
4,269
4,372
4,490
328
341
354
368
382
447
472
526
551
566
584
2,557
2,723
2,901
3,090
3,291
3,227
3,361
3,564
3,781
3,805
3,906
614
654
696
742
790
774
807
855
892
913
937
'Projected using 1998 data and the 1997 to 2000 Average Annual Growth Rate for Generation I
Table H-7: Synthetic Fiber Production in 1998
Fiber
Polyester
Nylon
Olefin
Acrylic
Total
Production
(Tq)
1.8
1.3
1.3
0.2
4.6
Carbon
Content
63%
64%
86%
68%
-
Carbon Equivalent (Tg
C02 Eq.)
: 4.1
3.0
; 4.1
! 0.5
I 11.7
-Not applicable
NzO from Municipal Solid Waste Combustion
Estimates of N2O emissions from MSW combiistion in the United States are based on the methodology
outlined in the EPA's Compilation of Air Pollutant Emission Factors (EPA 1997). According to this methodology,
emissions of N2O from MSW combustion are the produbt of the mass of MSW combusted, an emission factor of
NjO emitted per unit mass of waste combusted, and an N2O emissions control removal efficiency. For MSW
combustion in the United States, an emission factor of 30 g N2O/metric ton MSW and an estimated emissions
control removal efficiency of zero percent were used. No information was available on the mass of waste
combusted in 2000. It was assumed for the purposes of jthis calculation that the mass of waste combusted in 2000
was the same as estimated for 1999.
H-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX I
Methodology for Estimating Emissions from International Bunker Fuels used by the
U.S. Military
Bunker fuel emissions estimates for the Department of Defense (DoD) were developed using data primarily
generated by the Defense Energy Support Center for aviation and naval fuels (DESC 2001). The Defense Energy
Support Center (DESC) of the Defense Logistics Agency (DLA) prepared a special report based on data in the
Defense Fuels Automated Management System (DFAMS). DFAMS contains data for 1995 through 2000, but the
data set was not complete for years prior to 1995. Fuel quantities for 1990 to 1994 were estimated based on a back-
calculation of the 1995 DFAMS values using DLA aviation and marine fuel procurement data. The back-calculation
was refined last year to better account for the jet fuel conversion from JP4 to JP8 that occurred within the DoD
between 1992 and 1995. Data for marine fuel consumption in 2000 were obtained from the Naval Operations Navy
Strategic Mobility/Combat Logistics Division (N42 2001).
Gasoline and diesel fuel totals presented in Table 1-1 were estimated using data provided by the military
services. The 1991 through 1995 data points were interpolated from the inventory data. The 1997 through 1999
motor gasoline and diesel fuel data were extrapolated from the 1996 inventory data. Growth factors used for other
diesel and gasoline were 5.2 percent and -21.1 percent, respectively. Data sets for other diesel and gasoline
consumed by the military in 2000 were estimated based on Air Force ground fuels consumption trends. This method
produced a result that was more consistent with expected consumption for 2000.
Step 1: Omit Extra-Territorial Fuel Deliveries
Beginning with the complete DFAMS data set for each year, the first step in the development of DoD
related emissions from international bunker fuels was to identify data that would be representative of international
bunker fuel consumption as that term is defined by decisions of the UNFCCC (i.e., fuel sold to a vessel, aircraft, or
installation within the United States or its territories and used in international maritime or aviation transport).
Therefore, fuel data were categorized by the location of fuel delivery in order to identify and omit all extra-territorial
fuel transactions/deliveries (i.e., sales abroad). Table 1-1 displays the fuels that remain at the completion of Step 1,
summarized by fuel type.
Step 2: Omit Fuel Transactions Received by Military Services that are not Considered to be International
Bunker Fuels
Next, fuel transaction/delivery records were sorted by Military Service. The following assumptions were
made regarding bunker fuel use by Service, leaving only the Navy and Air Force as users of military international
bunker fuels.
• Only fuel delivered to a ship, aircraft, or installation in the United States can be a potential international
bunker fuel. Fuel consumed in international aviation or marine transport should be included in the bunker
fuel estimate of the country where the ship or aircraft was fueled. Fuel consumed entirely within a
country's borders is not bunker fuel.
• Based on discussions with the Army staff, only an extremely small percentage of Army aviation emissions,
and none of its watercraft emissions, qualified as bunker fuel emissions. The magnitude of these emissions
was judged to be insignificant when compared to Air Force and Navy emissions. Based on this, Army
bunker fuel emissions are assumed to be zero.
• Marine Corps aircraft operating while embarked consume fuel reported as delivered to the Navy. Bunker
fuel emissions from embarked Marine Corps aircraft are reported in the Navy bunker fuel estimates.
Bunker fuel emissions from other Marine Corps operations and training are assumed to be zero.
• Bunker fuel emissions from other DoD and non-DoD activities (i.e., other federal agencies) that purchase
fuel from DESC are assumed to be zero.
1-1
-------
Step 3: Omit Land-Based Fuels j
Navy and Air Force land-based fuel consumption (i.e., fuel not used by ships or aircraft) were also omitted.
The remaining fuels, listed below, were potential military international bunker fuels.
• Marine: naval distillate fuel (F76), marine gas oil (MGO), and intermediate fuel oil (IFO).
• Aviation: jet fuels (JP8, JP5, JP4, JAA, JA1, and JAB).
At the completion of step 3 of the 2000 estimate, it was apparent that the Navy maritime data provided by
DESC were abnormal compared to those data for each year from 1995 to 1999. The Navy fuels and logistics office
identified a separate data set that was used to compare ;the DESC 2000 data for Navy maritime fuel consumption.
After comparing the 2000 data from DESC to that fronvthe Navy, it was determined that the Navy data (N42 2001)
should be used as the source of the 2000 maritime values. However, DoD will continue to investigate the 2000
maritime data from DESC, which Navy fuels experts consider an anomaly.
I
Step 4: Determine Bunker Fuel Percentages |
Next it was necessary to determine what percent of the marine and aviation fuels were used as international
bunker fuels. Military aviation bunkers include international operations (i.e., sorties that originate in the United
States and terminate in a foreign country), operations cojnducted from naval vessels at sea, and operations conducted
from U.S. installations principally over international water in direct support of military operations at sea (e.g., anti-
submarine warfare flights). For the Air Force, a bunker fuel weighted average was calculated based on flying hours
by major command. International flights were weighted^by an adjustment factor to reflect the fact that they typically
last longer than domestic flights. In addition, a fuel use correction factor was used to account for the fact that
transport aircraft burn more fuel per hour of flight than most tactical aircraft. The Air Force bunker fuel percentage
was determined to be 13.2 percent. This percentage was multiplied by total annual Air Force aviation fuel delivered
for U.S. activities, producing an estimate for international bunker fuel consumed by the U.S. Air Force. The naval
aviation bunker fuel percentage of total fuel was calculated using flying hour data from Chief of Naval Operations
Flying Hour Projection System Budget Analysis Report for FY 1998 (N45 1998), and estimates of bunker fuel
percent of flights provided by the fleet. The naval aviation bunker fuel percentage, determined to be 40.4 percent,
was multiplied by total annual Navy aviation fuel delivered for U.S. activities, yielding total Navy aviation bunker
fuel consumed.
For marine bunkers, fuels consumed while ships were underway were assumed to be bunker fuels. For
2000, the Navy reported that 79 percent of vessel operations were underway, while the remaining 21 percent of
operations occurred in port (i.e., pierside). Therefore, the Navy maritime bunker fuel percentage was determined to
be 79 percent for 2000. The percentage of time underway may vary from year-to-year and the 2000 value represents
a change from previous years, for which the bunker fuel percentage of 87 percent was applied. Table 1-2 and Table
1-3 display DoD bunker fuel totals for the Navy and Air (Force.
i
Step 5: Calculate Emissions from Military International Bunker Fuels
Bunker fuel totals were multiplied by appropriate emission factors to determine greenhouse gas emissions
(see Table 1-4 and Table 1-5). j
The rows labeled 'U.S. Military' and 'U.S. Military Naval Fuels' within Table 2-43 and Table 2-44 in the
Energy Chapter were based on the international bunker.fuel totals provided in Table 1-2 and Table 1-3, below. Total
COa emissions from military bunker fuels are presented in Table 1-6. Carbon dioxide emissions from aviation
bunkers and distillate marine bunkers presented in Table 2-42 are the total of military plus civil aviation and civil
marine bunker fuels, respectively. The military component of each total is based on fuels tallied in Table 1-2 and
Table 1-3. j
1-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
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-------
Table 1-2: Total D.S. Military Aviatiin Bunker Fuel (Million Gallons)
Fuel Type/Service
JP8
Navy
Air Force
JP5
Navy
Air Force
JP4
Navy
Air Force
JAA
Navy
Air Force
JA1
Navy
Air Force
JAB
Navy
Air Force
Navy Subtotal
Air Force Subtotal
Total
1990
56.74
56.74
+
370.53
365.29
5.25
420.77
0.02
420.75
13.70
8.45
5.25
+
+
+
+
+
+
430.50
431.25
861.75
1991
56.30
56.30
+
367.66
362.46
5.21
417.52
0.02
417.50
13.60
8.39
5.21
+
+
+
+
+
+
427.17
427.91
855.08
1992
46.40
46.08
0.32
300.92
296.66
4.26
341.40
0.02
341.39
11.13
6.86
4.27
+
+
+
+
+
+
349.62
350.23
699.85
1993
145.33
44.56
100.77
290.95
286.83
4.12
229.64
0.02
229.62
10.76
6.64
4.12
+
+
+
+
+
+
338.04
338.63
676.68
1994
223.99
40.06
183.93
261.57
257.87
3.70
113.11
0.01
113.10
9.67
5.97
3.71
+
+
+
+
+
+
303.91
304.44
608.35
1995
300.40
38.25
262.15
249.78
246.25
3.54
21.50
0.01
21.49
9.24
5.70
3.54
+
+
+
+
+
+
290.21
290.72
580.93
1996
308.81
39.84
268.97
219.40
216.09
3.31
1.05
+
1.05
10.27
6.58
3.69
+
+
+
+
+
+
262.51
277.02
539.53
1997
292.01
46.92
245.09
194.16
191.15
3.01
0.05
+
0.05
9.42
5.88
3.54
+
+
+
+
+
H-
243.95
251.70
495.65
1998
306.39
53.81
252.59
184.38
181.36
3.02
0.03
+
0.03
10.84
6.63
4.21
0.01
•H
0.01
+
+
+
241.80
259.86
501.66
1999
301.35
55.46
245.89
175.37
170.59
4.77
0.02
+
0.02
10.78
6.32
4.47
+
+
+
+
+
+
232.37
255.14
487.52
2000
307.57
53.38
254.19
160.35
155.60
4.74
0.01
+
0.01
12.46
7.95
4.51
0.03
0.02
0.01
+
+
+
216.90
263.50
480.40
+ Does not exceed 0.005 million gallons.
Note: Totals may not sum due to independent rounding. '
Table 1-3: Tetal U.S. DoD Maritime Bunker Fuel (Million Gallons)
Marine Distillates
Navy-MGO
Navy-F76
Naw-IFO
Total
1990
522.37
522.37
1991
481.15
481.15
1992
491.47
491.47
1993
448.27
448.27
' 1994
|364.01
364.01
1995
333.82
333.82
1996
30.34
331.88
4.63
366.85
1997
35.57
441.65
7.07
484.29
1998
31.88
474.23
11.61
517.72
1999
39.74
465.97
5.29
511.00
2000
77.11
434.16
26.08
537.35
+ Does not exceed 0.005 million gallons.
Note: Totals may not sum due to independent rounding. :
Table 1-4: Aviation and Marine Carbon Contents trg carton/QBiu) and Fraction Oxidized
Mode (Fuel)
Carbon Content Fraction
Coefficient Oxidized
Aviation (Jet Fuel)
Marine (Distillate)
variable
19.95
0.99
0.99
Table 1-5: Annual Yariable Carbon Content Coefficient for let Fuel (Tg Carben/QBtm
~Fui 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000
Jet Fuel
19.40 19.40 19.39
19.37
19.35 19.34 19.33
19.33
19.33 19.33 19.33
Table 1-6: Total U.S. DoB CO? Emissions from Bunker Fuels (Tg CO? En.l
Mode
1990 1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Aviation
Marine
8.2
5.2
8.1
4.8
6.6
4.9
6.4
4.5
5.8
3.7
5.6
3.4
5.2
3.7
4.8
4.9
4.8
5.2
4.7
5.1
4.6
5.4
Total
13.4
12.9
11.6
10.9
9.5
8.9
8.9
9.6
10.0
9.8
10.0
Note: Totals may not sum due to independent rounding.
I-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX J
Methodology for Estimating HFC, and PFC Emissions from Substitution of Ozone
Depleting Substances
The Vintaging Model was developed as a tool for estimating the annual chemical emissions from industrial
sectors that have historically used ozone depleting substances (ODSs) in their products. Under the terms of the
Montreal Protocol and the Clean Air Act Amendments of 1990, the domestic production of ODSs, CFCs, halons,
carbon tetrachloride, methyl chloroform, and hydrochlorofluorocarbons (HCFCs) - has been drastically reduced,
forcing these industrial sectors to transition to more ozone friendly chemicals. As these industries have moved
toward ODSs alternatives such as hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs), the Vintaging Model
has evolved into a tool for estimating the rise in consumption and emissions of these alternatives, and the decline of
ODS consumption and emissions.
The Vintaging Model estimates emissions from six industrial sectors: refrigeration and air-conditioning,
foams, aerosols, solvents, fire extinguishing, and sterilization. Within these sectors, there are over 40 independently
modeled end-uses. The model requires information on the market growth for each of the end-uses, as well as a
history of the market transition from ODSs to alternatives. As ODSs are phased out, a percentage of the market
share originally filled by the ODSs is allocated to each of its substitutes.
The model, named for its method of tracking the emissions of annual "vintages" of new equipment that
enter into service, is a "bottom-up" model. It models the consumption of chemicals based on estimates of the
quantity of equipment or products sold, serviced, and retired each year, and the amount of the chemical required to
manufacture and/or maintain the equipment. The Vintaging Model makes use of this market information to build an
inventory of the in-use stocks of the equipment in each of the end-uses. Emissions are estimated by applying annual
leak rates, service emission rates, and disposal emission rates to each population of equipment. By aggregating the
emission and consumption output from the different end-uses, the model produces estimates of total annual use and
emissions of each chemical.
The Vintaging Model synthesizes data from a variety of sources, including data from the ODS Tracking
System maintained by the Global Programs Division and information from submissions to EPA under the
Significant New Alternatives Policy (SNAP) program. Published sources include documents prepared by the United
Nations Environment Programme (UNEP) Technical Options Committees, reports from the Alternative
Fluorocarbons Environmental Acceptability Study (AFEAS), and proceedings from the international conferences on
ozone protection technologies and Earth Technologies Forum. EPA also coordinates extensively with numerous
trade associations and individual companies. For example, the Alliance for Responsible Atmospheric Policy, the
Air-Conditioning and Refrigeration Institute, the Association of Home Appliance Manufacturers, the American
Automobile Manufacturers Association, and many of their member companies, have provided valuable information
over the years. In some instances the unpublished information that the EPA uses in the model is classified as
Confidential Business Information (CBI). The annual emissions inventories of chemicals are aggregated in such a
v^ay that CBI cannot be inferred. Full public disclosure of the inputs to the Vintaging Model would jeopardize the
security of the CBI that has been entrusted to the EPA.
The following sections discuss the forms of the emission estimating equations used in the Vintaging Model
for each broad end-use category. These equations are applied separately for each chemical used within each of
approximately 40 different end-uses. In the majority of these end-uses, more than one ODS substitute chemical is
used.
In general, the modeled emissions are a function of the amount of chemical consumed in each end-use
market. Estimates of the consumption of ODS alternatives can be inferred by extrapolating forward in time from the
amount of regulated ODSs used in the early 1990s. Using data gleaned from a variety of sources, assessments are
made regarding which alternatives will likely be used, and what fraction of the ODS market in each end-use will be
captured by a given alternative. By combining this with estimates of the total end-use market growth, a
consumption value can be estimated for each chemical used within each end-use.
J-1
-------
Alternatively, "top-down" information on total U.S. consumption of a given chemical is sometimes
available. This data can be used by estimating the fraction of this total that is consumed within each end-use. These
allocation schemes are guided by EP A's synthesis of the ;data available through the aforementioned sources.
Methodology
The methodology used by the vintaging model to calculate emissions varies by end-use sector.
methodologies and specific equations used by end-use sector are presented below.
The
Refrigeration and Air-Conditioning
For refrigeration and air conditioning products, emission calculations are split into two categories:
emissions during equipment lifetime, which arise from annual leakage and service losses, and disposal emissions,
which occur at the time of discard. Two separate steps are required to calculate the lifetime emissions from leakage
and service, and the emissions resulting from disposal!of the equipment. These lifetime emissions and disposal
emissions are summed to calculate the total emissions frt>m refrigeration and air-conditioning. As new technologies
replace older ones, it is generally assumed that there are improvements in their leak, service, and disposal emission
rates.
Step 1: Calculate lifetime emissions
Lifetime emissions from any piece of equipment include both the amount of chemical leaked during
equipment operation and during service recharges. Einissions from leakage and servicing can be expressed as
follows: !
j = (la + ls) X 2) QCj-i+i for i=l-+k
Where,
Es = Emissions from Equipment Serviced.) Emissions in year j from normal leakage and servicing
(including recharging) of equipment. I
/„ = Annual Leak Rate. Average annual le^k rate during normal equipment operation (expressed as a
percentage of total chemical charge). j
/, = Service Leak Rate. Average leakage' during equipment servicing (expressed as a percentage of
total chemical charge). I
Qc - Quantity of Chemical in New Equipment. Total amount of a specific chemical used to charge new
equipment in a given year,./, by weight.
K = Lifetime. The average lifetime of the equipment.
Step 2: Calculate disposal emissions
The disposal emission equations assume that a [certain percentage of the chemical charge will be emitted to
the atmosphere when that vintage is discarded. Disposal emissions are thus a function of the quantity of chemical
contained in the retiring equipment fleet and the proportion of chemical released at disposal:
Edj =
x [1 - (rm x re)]
Where,
Ed = Emissions from Equipment Disposed.
Emissions in year./ from the disposal of equipment.
Qc = Quantity of Chemical in New Equipment. Total amount of a specific chemical used to charge new
equipment in a given year,./, by weight. |
rm = Chemical Remaining. Amount of chemical remaining in equipment at the time of disposal
(expressed as a percentage of total chemical charge)
J-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
re = Chemical Recovery Rate. Amount of chemical that is recovered just prior to disposal (expressed
as a percentage of chemical remaining at disposal (rmj)
k = Lifetime. The average lifetime of the equipment.
Step 3: Calculate total emissions
Finally, lifetime and disposal emissions are summed to provide an estimate of total emissions.
Where,
E = Total Emissions. Emissions from refrigeration and air conditioning equipment in year/
Es = Emissions from Equipment Serviced. Emissions in year j from normal leakage and servicing
(recharging) of equipment.
Ed = Emissions from Equipment Disposed. Emissions in year/ from the disposal of equipment.
Aerosols
All HFCs and PFCs used in aerosols are assumed to be emitted in the year of manufacture. Since there is
currently no aerosol recycling, it is assumed that all of the annual production of aerosol propellants is released to the
atmosphere. The following equation describes the emissions from the aerosols sector.
Where,
E = Emissions. Total emissions of a specific chemical in year j from use in aerosol products, by
weight.
Qc = Quantity of Chemical. Total quantity of a specific chemical contained in aerosol products sold in
year j, by weight.
Solvents
Generally, most solvents are assumed to remain in the liquid phase and are not emitted as gas. Thus,
emissions are considered "incomplete," and are a fixed percentage of the amount of solvent consumed in a year.
The remainder of the consumed solvent is assumed to be reused or disposed without being released to the
atmosphere. The following equation calculates emissions from solvent applications.
Ej = / x QCj
Where,
E = Emissions. Total emissions of a specific chemical in year j from use in solvent applications, by
weight.
L = Percent Leakage. The percentage of the total chemical that is leaked to the atmosphere.
Qc = Quantity of Chemical. Total quantity of a specific chemical sold for use in solvent applications in
the year j, by weight.
Fire Extinguishing
Total emissions from fire extinguishing are assumed, in aggregate, to equal a percentage of the total
quantity of chemical in operation at a given time. For modeling purposes, it is assumed that fire extinguishing
equipment leaks at a constant rate for an average equipment lifetime. This percentage varies for streaming and
flooding equipment.
J-3
-------
Where,
Step 1: Calculate emissions from streaming equipment
EJ = lse x D Qcj-n-1 for i=l->k
i
E = Emissions. Total emissions of a specific chemical in year j for streaming fire extinguishing
equipment, by weight. ;
lse = Percent Leakage. The percentage of the total chemical in operation that is leaked to the atmosphere.
Qc - Quantity of Chemical from streaming equipment. Total amount of a specific chemical used in new
streaming fire extinguishing equipment in a given year, j, by weight.
k — Lifetime. The average lifetime of the equipment.
Step 2: Calculate emissions from flooding equipment
r
Ej = Ife x 2 Qcj.i+1 for J=7->fc
Where,
E = Emissions. Total emissions of a spebific chemical in year j for flooding fire extinguishing
equipment, by weight. \
i *
If = Percent Leakage. The percentage of 'the total chemical in operation that is leaked to the
atmosphere.
Qc = Quantity of Chemical from flooding equipment Total amount of a specific chemical used in new
flooding fire extinguishing equipment in a given year, j, by weight.
k = Lifetime. The average lifetime of the equipment.
Foam Blowing
Foams are given emission profiles depending on the foam type (open cell or closed cell). Open cell foams
are assumed to be 100 percent emissive in the year of manufacture. Closed cell foams are assumed to emit a portion
of their total HFC or PFC content upon manufacture, a portion at a constant rate over the lifetime of the foam, and a
portion at disposal. [
Step 1: Calculate emissions from open-cell foam
Emissions from open-cell foams are calculated using the following equation.
Where,
E = Emissions. Total emissions of a specific chemical in year j used for open-cell foam blowing, by
weight. |
Qc = Quantity of Chemical. Total amount of a specific chemical used for open-cell foam blowing in
year j, by weight.
Step 2: Calculate emissions from closed-cell foam
Emissions from closed-cell foams are calculated using the following equation.
Ej =
for i=l
J-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Where,
E = Emissions. Total emissions of a specific chemical in year j for closed-cell foam blowing, by
weight.
ef = Emission Factor. Percent of foam's original charge emitted in each year (1 — >&). This emission
factor is generally variable, including a rate for manufacturing emissions (occurs in the first year of
foam life), annual emissions (every year throughout the foam lifetime), and disposal emissions (occurs
during the final year of foam life).
Qc = Quantity of Chemical. Total amount of a specific chemical used in closed-cell foams in year/
k = Lifetime. Average lifetime of foam product.
Sterilization
For sterilization applications, all chemicals that are used in the equipment in any given year are assumed to
be emitted in that year, as shown in the following equation.
Where,
E = Emissions. Total emissions of a specific chemical in year/ from use in sterilization equipment, by
weight.
Qc = Quantity of Chemica/. Total quantity of a specific chemical used in sterilization equipment in year
j, by weight.
Model Output
By repeating these calculations for each year, the Vintaging Model creates annual profiles of use and
emissions for ODS and ODS substitutes. The results can be shown for each year in two ways: 1) on a chemical-by-
chemical basis, summed across the end-uses, or 2) on an end-use basis. Values for use and emissions are calculated
both in metric tons and in teragrams of carbon dioxide equivalents (Tg CO2 Eq.). The conversion of metric tons of
chemical to Tg CO2 Eq. is accomplished through a linear scaling of tonnage by the global warming potential (GWP)
of each chemical.
Throughout its development, the Vintaging Model has undergone annual modifications. As new or more
accurate information becomes available, the model is adjusted in such a way that both past and future emission
estimates are often altered.
J-5
-------
J-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX K
Methodology for Estimating CH4 Emissions from Enteric Fermentation
Methane emissions from enteric fermentation were estimated for five livestock categories: cattle, horses,
sheep, swine and goats. Emissions from cattle represent the majority of U.S. emissions, consequently, the more
detailed IPCC Tier 2 methodology was used to estimate emissions from cattle and the IPCC Tier 1 methodology was
use to estimate emissions from the other types of livestock.
Estimate Methane Emissions from Cattle
This section describes the process used to estimate methane emissions from cattle enteric fermentation. A
model based on recommendations provided in IPCC/UNEP/OECD/IEA (1997) and IPCC (2000) was developed that
uses information on population, energy requirements, digestible energy, and methane conversion rates to estimate
methane emissions. The emission methodology consists of the following three steps: (1) characterize the cattle
population to account for animal population categories with different emissions profiles; (2) characterize cattle diets
to generate information needed to estimate emissions factors; and (3) estimate emissions using these data and the
IPCC Tier 2 equations.
Stepl: Characterize U.S, Cattle Population
Each stage in the cattle lifecycle was modeled to simulate the cattle population from birth to slaughter.
This level of detail accounts for the variability in methane emissions associated with each life stage. Given that the
time in which cattle can be in a stage can be less than one year (e.g., beef calves are weaned at 7 months), the stages
are modeled on a per month basis. The type of cattle use also impacts methane emissions (e.g., beef versus dairy).
Consequently, cattle life stages were modeled for several categories of dairy and beef cattle. These categories are
listed in Table K-l.
Table K-1: Cattle Population Categories Used for Estimating Methane Emissions
Dairy Cattle
Beef Cattle
Calves
Heifer Replacements
Cows
Calves
Heifer Replacements
Heifer and Steer Stockers
Animals in Feedlots
Cows
Bulls
The key variables tracked for each of these cattle population categories (except bulls1) are as follows:
Calving rates: The number of animals born on a monthly basis was used to initiate monthly cohorts and to
determine population age structure. The number of calves born each month was obtained by multiplying
annual births by the percentage of births by month. Annual birth information was taken from USDA
(2001a). Average percentage of births by month for beef from USDA (USDA/APHIS/VS 1998, 1994,
1993) were used for 1990 through 2000. For dairy animals, birth rates were assumed constant throughout
the year. Whether calves were born to dairy or beef cows was estimated using the dairy cow calving rate
and the total dairy cow population to determine the percent of births attributable to dairy cows, with the
remainder assumed to be attributable to beef cows.
Average weights and weight gains: Average weights were tracked for each monthly age group using
starting weight and monthly weight gain estimates. Weight gain (i.e., pounds per month) was estimated
based on weight gain needed to reach a set target weight, divided by the number of months remaining
before target weight was achieved. Birth weight was assumed to be 88 pounds for both beef and dairy
1 Only end-of-year census population statistics and a national emission factors are used to estimate methane emissions from the
bull population.
K-1
-------
animals. Weaning weights were estimated to range from 480 to 575 pounds. Other reported target weights
were available for 12, 15, 24, and 36 month-old ainimals. Live slaughter weights were derived from dressed
slaughter weight data (USDA 2001c, 2000c). [Live slaughter weight was estimated as dressed weight
divided by 0.63. ]
• Feedlot placements: Feedlot placement statistics [were available that specify placement of animals from the
stocker population into feedlots on a monthly basis by weight class. The model used these data to shift a
sufficient number of animals from the stocker cohorts into the feedlot populations to match the reported
data. After animals are placed in feedlots they progress through two steps. First, animals spend time on a
step-up diet to become acclimated to the new feed type. Animals are then switched to a finishing diet for a
period of time before they are slaughtered. The length of time an animal spends in a feedlot depends on the
Start weight (i.e., placement weight), the rate of \jveight gain during the start-up and finishing phase of diet,
and the end weight (as determined by weights at; slaughter). Weight gain during start-up diets is estimated
to be 2.8 to 3 pounds per day. Weight gain during finishing diets is estimated to be 3 to 3.3 pounds per day
(Johnson 1999). All animals are estimated to spend 25 days in the step-up diet phase (Johnson 1999).
Length of time finishing can be calculated based on start weight, weight gain per day, and target slaughter
weight.
• Pregnancy and lactation: Energy requirements and hence, composition of diets, level of intake, and
emissions for particular animals, are greatly influenced by whether the animal is pregnant or lactating.
Information is therefore needed on the percentage of all mature animals that are pregnant each month, as
well as milk production, to estimate methane emissions. A weighted average percent of pregnant cows
each month was estimated using information ori births by month and average pregnancy term. For beef
cattle, a weighted average total milk production per animal per month was estimated using information on
typical lactation cycles and amounts (NRC 1999), and data on births by month. This results in a range of
weighted monthly lactation estimates expressed is Ibs/animal/month. The monthly estimates from January
to December are 3.33, 5.06, 8.70, 12.01, 13.58,;13.32, 11.67, 9.34, 6.88, 4.45, 3.04, and 2.77. Monthly
estimates for dairy cattle were taken from USDA monthly milk production statistics.
• Death rates: This factor is applied to all heifer atjd steer cohorts to account for death loss within the model
on a monthly basis. The death rates are estimated by determining the death rate that results in model
estimates of the end-of-year population for cows that match the published end-of-year population census
statistics.
• Number of animals per category each month: The population of animals per category is calculated based
on number of births (or graduates) into the monthly age group minus those animals that die or are
slaughtered and those that graduate to next category (including feedlot placements). These monthly age
groups are tracked in the enteric fermentation model to estimate emissions by animal type on a regional
basis. Table K-2 provides the cattle population!estimates as output from the enteric fermentation model
from 1990 through 2000. This table includes the population categories used in the model to estimate total
emissions, including tracking emissions that occur the following year for feedlot animals placed late in the
year. Dairy lactation estimates for 1990 through 2000 are shown in Table K-3. Table K-4 provides the
target weights used to track average weights of cattle by animal type. Table K-5 provides a summary of the
reported feedlot placement statistics for 2000.
Cattle population data were taken from U.S. Department of Agriculture (USDA) National Agricultural
Statistics Service (NASS) reports. The USDA publishes monthly, annual, and multi-year livestock population and
production estimates. Multi-year reports include revisions to earlier published data. Cattle and calf populations,
feedlot placement statistics (e.g., number of animals placed in feedlots by weight class), slaughter numbers, and
lactation data were obtained from the USDA (1990-2001). Beef calf birth percentages were obtained from the
National Animal Health Monitoring System (NAHMS) (JUSDA/APHIS/VS 1998, 1994, 1993). Estimates of the
number of animals in different population categories of the model differ from the reported national population
statistics. This difference is due to model output indicating the average number of animals in that category for the
year rather than the end of year population census. :
K-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Step 2: Characterize U.S. Cattle Population Diets
To support development of digestible energy (DE, the percent of gross energy intake digestible to the
animal) and methane conversion rate (Ym, the fraction of gross energy converted to methane) values for each of the
cattle population categories, data were collected on diets considered representative of different regions. For both
grazing animals and animals being fed mixed rations, representative regional diets were estimated using information
collected from state livestock specialists and from USDA (1996a). The data for each of the diets (e.g., proportions
of different feed constituents, such as hay or grains) were used to determine chemical composition for use in
estimating DE and Ym for each animal type. Additional detail on the regional diet characterization is provided in
EPA (2000).
DE and Ym were used to estimate methane emissions from enteric fermentation and vary by diet and animal
type. The IPCC recommends Ym values of 3.5 to 4.5 percent for feedlot cattle and 5.5 to 6.5 percent for all other
cattle. Given the availability of detailed diet information for different regions and animal types in the United States,
DE and Ym values unique to the United States2 were developed. Table K-6 shows the regional DE, the Ym, and
percent of total U.S. cattle population in each region based on 2000 data.
DE and Ym values were estimated for each cattle population category based on physiological modeling and
expert opinion. DE and Ym values for dairy cows and most grazing animals were estimated using a model (Donovan
and Baldwin 1999) that represents physiological processes in the ruminant animals. The three major categories of
input required by the model are animal description (e.g., cattle type, mature weight), animal performance (e.g.,
initial and final weight, age at start of period), and feed characteristics (e.g., chemical composition, habitat, grain or
forage). Data used to simulate ruminant digestion is provided for a particular animal that is then used to represent a
group of animals with similar characteristics. The model accounts for differing diets (i.e., grain-based, forage-based,
range- based), so that Ym values for the variable feeding characteristics within the U.S. cattle population can be
estimated.
For feedlot animals, DE and Ym values were taken from Johnson (1999). In response to peer reviewer
comments (Johnson 2000), values for dairy replacement heifers are based on EPA (1993).
Step 3: Estimate Methane Emissions from Cattle
Emissions were estimated in three steps: a) determine gross energy intake using the IPCC (2000) equations,
b) determine an emissions factor using the GE values and other factors, and c) sum the daily emissions for each
animal type. The necessary data values include:
• Body Weight (kg) ;
• Weight Gain (kg/day)
• Net Energy for Activity (Ca)3
• Standard Reference Weight4 (Dairy = 1,324 kg; Beef = 1,195 kg)
• Milk Production (kg/day)
• Milk Fat (percent of fat in milk = 4)
• Pregnancy (percent of population that is pregnant)
• DE (percent of gross energy intake digestible)
• Ym (the fraction of gross energy converted to methane)
2 In some cases, the Ym values used for this analysis extend beyond the range provided by the IPCC. However, EPA
believes that these values are representative for the U.S. due to the research conducted to characterize the diets of U.S. cattle and
to assess the Ym values associated with different animal performance and feed characteristics in the United States.
3 Zero for feedlot conditions, 0.17 for grazing conditions, 0.37 for high quality grazing conditions. Ca factor for dairy
cows is weighted to account for the fraction of the population in the region that grazes during the year.
4 Standard Reference Weight is used in the model to account for breed potential.
K-3
-------
Step 3a: Gross Energy, GE j
As shown in the following equation, Gross Energy (GE) is derived based on the net energy estimates and
the feed characteristics. Only variables relevant to each animal category are used (e.g., estimates for feedlot animals
do not require the NEi factor). All net energy equations are provided in IPCC (2000).
GE = [((NEm+ NEmobilizcd+ NEa+ NE,+ NEP) / {NEma/DE}) + (NEg/ {NEga/DE})] / (DE / 100)
Where,
GE = gross energy (MJ/day)
NEm= net energy required by the animal for maintenance (MJ/day)
NEmofciiJH.d3 net energy due to weight loss (mobilized) (MJ/day)
NEa= net energy for animal activity (MJ/day)
NEi= net energy for lactation (MJ/day)
NEP = net energy required for pregnancy (MJ/day) I
{NEma/DE} = ratio of net energy available in a diet for maintenance to digestible energy consumed
NEg= net energy needed for growth (MJ/day)
{NEg/DE} = ratio of net energy available for growth in a diet to digestible energy consumed
DE = digestible energy expressed as a percentage if gross energy (percent)
Step 3b: Emission Factor \
The emissions factor (DayEmit) was determined1 using the GE value and the methane conversion factor
for each category. This is shown in the following equation:
DayEmit = [GE x Ym] / [55.65 MJ/kg CH4]
Where,
DayEmit = emission factor (kg CBU/head/day)
GE = gross energy intake (MJ/head/day)
Yra= methane conversion rate which is the fraction of gross energy in feed converted to methane (percent)
The daily emission factors were estimated for each animal type, weight and region. The implied national
annual average emission factors for each of the animal categories are shown in Table K-7. The implied factors are
not used in the inventory, but are provided for comparative purposes only.
Step 3c: Estimate Total Emissions j
Emissions were summed for each month and for each population category using the daily emission factor
for a representative animal and the number of animals in the category. The following equation was used:
Where,
Emissions = DayEmit x Days/Month x SubPop
j
DayEmit = the emission factor for the subcategory (kg CH4/head/day)
Days/Month = the number of days in the month
SubPop = the number of animals in the subcategory during the month
K-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 11990-2000
-------
This process was repeated for each month, and the totals for each subcategory were summed to achieve an
emissions estimate for the entire year. The estimates for each of the 10 subcategories of cattle are listed in Table K-
8. The emissions for each subcategory were then summed to estimate total emissions from beef(cattle and dairy
cattle for the entire year. The total emissions from 1990 through 2000 are shown in Table K-9.
Emission Estimates from Other Livestock
All livestock population data, except for horses, were taken from U.S. Department of Agriculture (USDA)
National Agricultural Statistics Service (NASS) reports. For each animal category, the USDA publishes monthly,
annual, and multi-year livestock population and production estimates. Multi-year reports include revisions to earlier
published data. Recent reports were obtained from the USDA Economics and Statistics System, while historical
data were downloaded from the USDA-NASS. The Food and Agriculture Organization (FAO) publishes horse
population data. These data were accessed from the FAOSTAT database at http://apps.fao.org/. Methane emissions
from sheep, goats, swine, and horses were estimated by multiplying published national population estimates by the
national emission factor for each year. Table K-10 shows the populations used for these other livestock from 1990
to 2000 and Table K-l 1 shows the emission factors used for these other livestock.
A complete time series of enteric fermentation emissions from livestock is shown in Table K-l 2 (Tg CO2
Eq.) and Table K-13 (Gg).
Tablu K-2: Estimates of Average Annual Populations of U.S. Cattle (Thousand Head?
Livestock Type
Calves 0-6 months
Dairy
Cows
Replacements 7-11 months
Replacements 12-23 months
Beef
Cows
Replacements 7-11 months
Replacements 12-23 months
Steer Stackers
Heifer Stockers
Total Adjusted Feedlorj1
Bulls
Total Placements^
1990
22,561
10,015
1,214
2,915
32,454
1,269
2,967
7,864
4,806
10,574
2,180
25,587
1991
22,531
9,965
1,219
2,874
32,520
1,315
3,063
7,362
4,572
10,461
2,198
25,396
1992
22,707
9,728
1,232
2,901
33,007
1,402
3,182
8,458
4,809
10,409
2,220
25,348
1993
23,004
9,658
1,230
2,926
33,365
1,465
3,393
8,786
4,944
9,901
2,239
25,586
1994
23,346
9,528
1,228
2,907
34,650
1,529
3,592
7,900
4,715
10,775
2,306
26,615
1995
23,468
9,487
1,220
2,905
35,156
1,492
3,647
8,700
5,083
11,344
2,392
27,623
1996
23,255
9,416
1,205
2,877
35,228
1,462
3,526
8,322
4,933
11,353
2,392
27,580
1997
22,810
9,309
1,182
2,838
34,271
1,378
3,391
7,839
4,987
11,528
2,325
28,518
1998
22,674
9,191
; 1,194
; 2,797
33,683
1,321
: 3,212
7,647
4,838
' 11,517
2,235
.27,111
1999
22,655
9,133
1,188
2,846
33,745
1,303
3,110
7,203
4,671
12,858
2,241
29,424
2000
22,564
9,190
1,194
2,811
33,569
1,313
3,097
6,798
4,407
12,774
2,197
27,921
Source: Enteric Fermentation Model.
a Populations represent the average of each population category throughout the year.
b Total Adjusted Feedlot = Average number in feedlots accounting for current year plus the population carried over from the previous year (e.g.,
the "next year" population numbers from this table are added into the following years "adjusted numbers").
c Placements represent a flow of animals from backgrounding situations to feedlots rather than an average annual population estimate.
d Reported placements from USDA are adjusted using a scaling factor based on the slaughter to placement ratio.
Table K-3: Dairy Lactation by Region Ubs- year/cowl*
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
California
18,800
18,771
19,072
18,852
20,203
19,573
19,161
19,829
19,442
20,788
21,169
West
16,769
16,631
17,838
17,347
17,890
17,724
18,116
18,248
18,377
19,330
20,828
Northern Great
Plains
13,502
13,316
13,597
14,109
14,496
14,650
14,872
15,013
15,489
15,910
17,196
Southcentral
12,397
12,389
12,710
13,034
13,236
13,228
13,215
, 13,212
13,580
13,476
15,323
Northeast
14,058
14,560
15,135
14,937
15,024
15,398
15,454
15,928
16,305
16,571
17,544
Midwest
14,218
14,555
15,028
15,203
15,374
15,728
15,596
16,027 .
16,494
16,655
17,255
Southeast
12,943
12,850
13,292
13,873
14,200
14,384
14,244
14,548
14,525
14,930
15,201
Source: USDA (2001d).
' Beef lactation data were developed using the methodology described in the text.
K-5
-------
Tittle K-4: Target Weights fir Use in Estimating Auerage Weights and Weight Gains libs!
Cattle Type
Typical Weights
Beef Replacement Heifer Data
Replacement Weight at 15 months
Replacement Weight at 24 months
Mature Weight at 36 months
Dairy Replacement Heifer Data
Replacement Weight at 15 months
Replacement Weight at 24 months
Mature Weight at 36 months
Stackers Data - Grazing/Forage Based Only
Steer Weight Gain/Month to 12 months
Steer Weight Gain/Month to 24 months
Heifer Weight Gain/Month to 12 months
Heifer Weight Gain/Month to 24 months
715
1,078
1,172
800
1,225
1,350
45
35
35
30
Source: Feedstuffs (1998), Western Dairyman (1998), Johnson (1999), NRC (1999).
Table K-5: Feedlit Placements in the United States far 2000T (Number ef animals placed in Thousand Head!
Weight When Placed
< 600 IDS
600 -700 IDS
700 -800 Ibs
> 800 IDS
Total
Jan
489
691
654
382
2,216
Feb Mar
351 333
476 411
596 717
457 570
1,880 2,031
Apr
301
310
577
519
1,707
May
382
471
794
658
2,305
Jun
347
380
498
439
1,664
Jul
424
386
592
505
1,907
Aug
573
504
691
672
2,440
Sep Oct
775 1066
612 755
681 531
618 477
2,686 2,829
Nov
757
559
405
293
2,014
Dec
504
516
406
273
1,699
Total
6,302
6,071
7,142
5,863
25,378
Source: USDA (2001g).
Note: Totals may not sum due to independent rounding. ',
' Data were available for 1996 through 2000. Data for 1990 to 1995 were based on the average of monthly placements from the 1996 to 1998
reported figures. '
K-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table K-6: Regional Digestible Energy IDE), Methane Conversion Rates (M and population percentages far Cattle
in 20011
Animal Type
Beef Repl. Heif.a
Dairy Repl. Heif.a
Steer Stackers3
Heifer Stackers3
Steer Feedlot6
Heifer Feedlote
Beef Cows3
Dairy Cows6
Steer Step-Up6''
Heifer Step-Up6
Data
DE"
Yrrf
Pop.d
DE
Ym
Pop.
DE
Ym
Pop.
DE
Ym
Pop.
DE
Ym
Pop.
DE
Ym
Pop.
DE
Ym
Pop.
DE
Yn
Pop.
DE
Ym
DE
Ym
California
67
8.0%
3%
66
5.9%
18%
67
8.0%
4%
67
8.0%
2%
85
3.0%
3%
85
3.0%
3%
67
8.0%
2%
69
4.8%
16%
76
5.5%
76
5.5%
West
66
7.4%
11%
66
5.9%
11%
66
7.4%
8%
66
7.4%
7%
85
3.0%
7%
85
3.0%
7%
66
7.4%
9%
66
5.8%
13%
76
5.5%
76
5.5%
Northern
Great Plains
68
8.0%
31%
66
5.6%
5%
68
8.0%
41%
68
8.0%
50%
85
3.0%
47%
85
3.0%
47%
68
8.0%
28%
69
5.8%
5%
76
5.5%
76
5.5%
Southcentral
66
8.3%
24%
64
6.4%
4%
66
. 8.3%
23%
66
8.3%
22%
85
3.0%
24%
85
3.0%
24%
66
8.3%
26%
68
5.7%
6%
76
5.5%
76
5.5%
Northeast
64
8.4%
2%
68
6.3%
19%
64
8.4%
2%
64
8.4%
1%
85
3.0%
1%
85
3.0%
1%
64
8.4%
2%
69
5.8%
19%
76
5.5%
76
5.5%
Midwest
68
8.0% .
13%
66
5.6%
36% '*
68
8.0%
18%
68
8.0%
15% •
85
3.0%
17%
85
3.0%
17%
68
8.0% :
14% •
69
5.8%
34%
76
5.5%
76
5.5%
Southeast
68
7.8%
16%
66
6.9%
7%
68
7.8%
4%
68
7.8%
4%
85
3.0%
1%
85
3.0%
1%
68
7.8%
19%
68
5.6%
8%
76
5.5%
76
5.5%
1 Beef and Dairy grazing DE and Ym values were applied to all grazing beef animals. It was assumed that pasture quality remains relatively
consistent at a regional scale.
b Digestible Energy in units of percent GE (MJ/Day).
c Methane Conversion Rate is the fraction of GEin feed converted to methane.
d Estimated percent of each subcategory population present in each region.
6 DE and Ym values for 1990 through 1992 are values from the previous livestock characterization reported in the 1993 Report to Congress.
Values for 1993 through 1995 are the mean of current values and the 1993 Report to Congress values. Values for 1996 through 2000 are
values from the most recent livestock characterization.
f Characteristics of heifer and steer step-up diets (i.e., diets fed to animals entering feedlots) were assessed nationally to account for the
difference between initial and finishing diets for feedlot animals.
K-7
-------
Table K-7: Implied Emission Factors for Cattle in the Moiled states (kg CK/head/yr)
Animal Category
Carves 0-6 months
Dairy
Cows
Replacements 7-11 months
Replacements 12-23 months
Beef
Cows
Replacements 7-11 months
Replacements 12-23 months
Steer Stockers
Heifer Stockers
Total Feedlot
Bulls
1990
0
113
40
63
83
47
73
63
56
47
100
1991
0
114
40
63
83
47
73
63
56
47
100
1992
0
117
40
63
83
47
73
64
56
47
100
1993
0
111
40
63
83
47
73
64
t 56
40
;100
1994
0
113
40
63
83
47
73
63
56
39
100
1995
0
113
40
63
83
47
73
64
57
39
100
1996
0
107
40
63
83
47
73
64
56
34
100
1997
0
109
40
63
83
47
73
63
57
33
100
1998
0
110
40
63
83
48
74
63
56
34
100
1999
0
111
40
63
82
47
74
63
56
33
100
2000
0
115
40
63
83
47
73
63
56
32
100
"0" = assumed to be zero. j
Source: Enteric Fermentation Model.
Table K-8: CH* Emissions from Cattle (Ggl
Cattle Type
Dairy
Cows
Replacements 7-11 months
Replacements 12-23 months
Beef
Cows
Replacements 7-11 months
Replacements 12-23 months
Steer Stockers
Heifer Stockers
Feedlot Cattle
Bulls
Total
1990
1,369
1,136
49
184
4,444
2,682
59
217
499
268
499
218
5,812
1991
1,370
1,140
49
181
4,408
2,687
62
224
467
255
494
220
5,778
1992
1,368
1,135
49
183
4,550
2,728
66
233
539
270
492
222
5,918
1993
1,307
1,073
49
185
4,536
2,758
69
248
561
279
398
224
5,843
1994
1,307
1,074
49
184
4,615
2,865
72
263
502
266
419
231
5,923
1995
1,308
1,076
49
184
4,768
2,907
70
267
556
288
442
239
6,077
1996
1,241
1,010
48
182
4,673
2,912
68
258
529
278
389
239
5,914
1997
1,240
1,013
48
179
4,541
2,832
65
248
497
282
385
233
5,780
1998
1,234
1,010
48
177
4,453
2,784
63
238
484
273
387
223
5,688
1999
1,246
1,018
48
180
4,429
2,777
62
230
453
262
421
224
5,675
2000
1,283
1,058
48
177
4,365
2,774
61
226
428
248
408
220
5,648
Note: Totals may not sum due to independent rounding.
Table K-9: Cattle Emissions [Tg Cth Ea.l
Cattle Type
Dairy
Beef
Total
1990
28.7
93.3
1991
28.8
92.6
122.1 121.3
1992
28.7
95.5
124.3
1993
27i4
95,3
122.7
1994
1995
27.4 27.5
96.9 100.1
124.4 127.6
1996
26.1
98.1
124.2
1997
26.0
95.4
121.4
1998
25.9
93.5
119.4
1999
26.2
93.0
119.2
2000
26.9
91.7
118.6
Note: Totals may not sum due to independent rounding.
Table K-10: Other Livestock Populations 1990-2000 (Thousand Head!
Livestock Type 1990
Sheep 11,358
Goats 2,516
Horses 5,150
Swine 53,941
1991
1992
11,174 10,797
2,516 2,516
5,180 5,200
56,476 58,532
1993
10,201
2,410
5,210
58,016
1994
9,836
2,305
5,190
59,951
1995
8,989
2,200
5,210
58,899
1996 1997
1998
8,465 8,024 7,825
2,095 1,990 1,990
5,230 5,230 5,250
56,220 58,728 61,991
1999
7,215
1,990
5,317
60,245
2000
7,032
1,990
5,320
58,892
Source: USDA (2001b,e-f, 2000b,e 1999d-e,h, 1998, b-c, 1994a-b), FAD (2000,2001).
K-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks': 1990-2000
-------
Tablei K-11: Emissiin Factors far Other Livestock (kg db/head/year)
Livestock Type
Emission Factor
Sheep
Goats
Horses
Swine
8
5
18
1.5
See Table K-7 for emission factors for cattle.
Source: IPCC(2000).
Tabli i K-12: CH* Emissions from Enteric Fermentation CTg C% Eq.l
Livestock Type
Beef Cattle
Dairy Cattle
Horses
Sheep
Swine
Goats
Total
1990
93.3
28.7
1.9
1.9
1.7
0.3
127.9
1991
92.6
28.8
2.0
1.9
1.8
0.3
127.2
1992
95.5
28.7
2.0
1.8
1.8
0.3
130.9
1993
95.3
27.4
2.0
1.7
1.8
0.3
128.5
1994
96.9
27.4
2.0
1.7
1.9
0.2
130.1
1995
100.1
27.5
2.0
1.5
1.9
0.2
133.2
1996
98.1
26.1
2.0
1.4
1.8
0.2
129.6
1997
95.4
26.0
2.0
1.3
1.8
0.2
126.8
1998
93.5
25.9 •
2.0
1.3
2.0
0.2 •
124.9
1999
93.0
26.2
2.0
1.2
1.9
0.2
124.5
2000
91.7
26.9
2.0
1.2
1.9
0.2
123.9
Tabln K-13: CHi Emissions from Enteric Fermentation (Gg)
Livestock Type
Beef Cattle
Dairy Cattle
Horses
Sheep
Swine
Goats
Total
1990
4,444
1,369
93
91
81
13
6,089
1991
4,408
1,370
93
89
85
13
6,058
1992
4,550
1,368
94
86
88
13
6,198
1993
4,536
1,307
94
82
87
12
6,118
1994
4,615
1,307
93
79
90
12
6,196
1995
4,768
1,308
94
72
88
11
6,342
1996
4,673
1,241
94
68
84
10
6,171
1997
4,541
1,240
94
64
88
10
6,037
1998
4,453
1,234
95
63
93
10
5,948
1999
4,429
1,246
96
58
90
10
5,929
2000
4,365
1,283
96
56
88
10
5,898
K-9
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K-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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ANNEX L
Methodology for Estimating CH4 and N20 Emissions from Manure Management
This annex presents a discussion of the methodology used to calculate methane and nitrous oxide emissions
from manure management systems. More detailed discussions of selected topics may be found in supplemental
memoranda in the supporting docket to this inventory.
The following steps were used to estimate methane and nitrous oxide emissions from the management of
livestock manure. Nitrous oxide emissions associated with pasture, range, or paddock systems and daily spread
systems are included in the emissions estimates for Agricultural Soil Management.
Step 1: Livestock Population Characterization Data
Annual animal population data for 1990 through 2000 for all livestock types, except horses and goats, were
obtained from the USDA National Agricultural Statistics Service (USDA, 1994a-b, 1995a-b, 1998a-b, 1999a-c,
2000a-g, 2001a-f). The actual population data used in the emissions calculations for cattle and swine were
downloaded from the USDA National Agricultural Statistics Service Population Estimates Data Base
(). Horse population data were obtained from the FAOSTAT database (FAO
2001). Goat population data for 1992 and 1997 were obtained from the Census of Agriculture (USDA 1999d).
Information regarding poultry turnover (i.e., slaughter) rate was obtained from state Natural Resource Conservation
Service personnel (Lange 2000).
A summary of the livestock population characterization data used to calculate methane and nitrous oxide
emissions is presented in Table L-l.
Dairy Cattle: The total annual dairy cow and heifer state population data for 1990 through 2000 are
provided in various USDA National Agricultural Statistics Service reports (USDA 1995a, 1999a, 2000a-b, 2001a-b).
The actual total annual dairy cow and heifer state population data used in the emissions calculations were
downloaded from the U.S. Department of Agriculture National Agricultural Statistics Service Published Estimates
Database () for Cattle and Calves. The specific data used to;estimate dairy
cattle populations are "Cows That Calved - Milk" and "Heifers 500+ Lbs - Milk Repl."
Beef Cattle: The total annual beef cattle population data for each state for 1990 through 2000 are provided
in various USDA National Agricultural Statistics Service reports (USDA 1995a, 1999a, 2000a-b, 2001a-b). The
actual data used in the emissions calculations were downloaded from the U.S. Department of Agriculture National
Agricultural Statistics Service Published Estimates Database (), Cattle and
Calves. The specific data used to estimate beef cattle populations are: "Cows That Calved—Beef," ; "Heifers 500+
Lbs—Beef Repl," "Heifers 500+ Lbs—Other," and "Steers 500+ Lbs." Additional information, regarding the
percent of beef steer and heifers on feedlots was obtained from contacts with the national USDA office (Milton
2000).
For all beef cattle groups (cows, heifers, steer, bulls, and calves), the USDA data provide cattle inventories
from January and July of each year. Cattle inventory changes over the course of the year, sometimes significantly,
as new calves are born and as fattened cattle are slaughtered; therefore, to develop the best estimate for the annual
animal population, the average inventory of cattle by state was calculated. USDA provides January inventory data
for each state; however, July inventory data is only presented as a total for the United States. In order to estimate
average annual populations by state, a "scaling factor" was developed that adjusts the January state-level data to
reflect July inventory changes. This' factor equals the average of the US January and July data divided by the
January data. The scaling factor is derived for each cattle group and is then applied to the January state-level data to
arrive at the state-level annual population estimates.
Swine: The total annual swine population data for each state for 1990 through 2000 are provided in various
USDA National Agricultural Statistics Service reports (USDA 1994a, 1998a, 2000c, 2001c). The USDA data
provides quarterly data for each swine subcategory: breeding, market under 60 pounds (less than 27 kg), market 60
to 119 pounds (27 to 54 kg), market 120 to 179 pounds (54 to 81 kg), and market 180 pounds and over (greater than
L-1
-------
82 kg). The average of the quarterly data was used in the emissions calculations. For states where only December
inventory is reported, the December data were used directly. The actual data used in the emissions calculations were
downloaded from the U.S. Department of Agriculture National Agricultural Statistics Service Published Estimates
Database (), Hogs and Pigs.
Sheep: The total annual sheep population data Tor each state for 1990 through 2000 were obtained from
USDA National Agricultural Statistics Service (USDA 1094b, 1999c, 2000f, 2001f). Population data for lamb and
sheep on feed are not available after 1993. The number of lamb and sheep on feed for 1994 through 2000 were
calculated using the average of the percent of lamb and Sheep on feed from 1990 through 1993. In addition, all of
the sheep and lamb "on feed" are not necessarily on "feedlots"; they may be on pasture/crop residue supplemented
by feed. Data for those animals on feed that are on feedlpts versus pasture/crop residue were provided only for lamb
in 1993. To calculate the populations of sheep and lamb on feedlots for all years, it was assumed that the percentage
of sheep and lamb on feed that are on feedlots versus pasture/crop residue is the same as that for lambs in 1993
(Anderson 2000). \
Goats: Annual goat population data by state were available for only 1992 and 1997 (USDA 1999d). The
data for 1992 were used for 1990 through 1992 and the |lata for 1997 were used for 1997 through 2000. Data for
1993 through 1996 were extrapolated using the 1992 and |l997 data.
Poultry: Annual poultry population data by statjs for the various animal categories (hens 1 year and older,
pullets of laying age, pullets 3 months old and older not of laying age, pullets under 3 months of age, other chickens,
broilers, and turkeys) were obtained from USDA National Agricultural Statistics Service (USDA 1995b, 1998b,
1999b, 2000d-e, 2000g, 2001d-e). The annual population data for boilers and turkeys were adjusted for turnover
(i.e., slaughter) rate (Lange 2000). !
Horses: The Food and Agriculture Organization (FAO) publishes annual horse population data, which
were accessed from the FAOSTAT database at (FAO 2001).
Step 2: Waste Characteristics Data
Methane and nitrous oxide emissions calculations are based on the following animal characteristics for
each relevant livestock population: \
Volatile solids excretion rate (VS) j
Maximum methane producing capacity (B0) for U.S. animal waste
Nitrogen excretion rate (Ncx)
Typical animal mass (TAM)
Annual state-specific milk production rate |
Published sources were reviewed for U.S.-specific livestock waste Characterization data that would be
consistent with the animal population data discussed in [Step 1. Data from the National Engineering Handbook,
Agricultural Waste Management Field Handbook (USDA 1996a) were chosen as the primary source of waste
characteristics. In some cases, data from the American Society of Agricultural Engineers, Standard D384.1 (ASAE
1999) were used to supplement the USDA data. The volatile solids and nitrogen excretion data for breeding swine
are a combination of the types of animals that make up thiis animal group, namely gestating and farrowing swine and
boars. It is assumed that a group of breeding swine is typically broken out as 80 percent gestating sows, 15 percent
farrowing swine, and 5 percent boars (Safley 2000). !
Table L-2 presents a summary of the waste characteristics used in the emissions estimates.
The method for calculating volatile solids production from dairy cows is based on the relationship between
milk production and volatile solids production. Cows that produce more milk per year also produce more volatile
solids in their manure due to their increased feed. Figure 4-1 in the Agricultural Waste Management Field
Handbook (USDA 1996a) was used to determine the mathematical relationship between volatile solids production
and milk production for a 1,400-pound dairy cow. The resulting best fit equation is logarithmic, shown in Figure L-
1. I
L-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Figure 1-1: Uelatile Solids Profluctiin
,000
y = 7.1003Ln(x)-57.844
15,000
16,000 17,000 18,000
Milk Production, Ib/yr
19,000 20,000
Annual milk production data, published by USDA's National Agricultural Statistics Service (USDA
200 Ig), was accessed for each state and for each year of the inventory. State-specific volatile solids production rates
were then calculated for each year of the inventory and used instead of a single national volatile solids excretion rate
constant. Table L-3 presents the volatile solids production rates used for 2000.
Step 3: Waste Management System Usage Data
Estimates were made of the distribution of wastes by management system and animal type using the
following sources of information: :
• State contacts to estimate the breakout of dairy cows on pasture, range, or paddock, and the percent of
wastes managed by daily spread systems (Deal 2000, Johnson 2000, Miller 2000, Stettler 2000,
Sweeten 2000, Wright 2000) '•
• Data collected for EPA's Office of Water, including site visits, to medium and large beef feedlot, dairy,
swine, and poultry operations (EPA 200la)
• Contacts with the national USDA office to estimate the percent of beef steer and heifers on feedlots
(Milton 2000)
• Survey data collected by USDA (USDA 1998d, 2000h) and re-aggregated by farm size and geographic
location, used for small operations
• Survey data collected by the United Egg Producers (UEP 1999) and USDA (2000i) and previous EPA
estimates (EPA 1992) of waste distribution for layers
• Survey data collected by Cornell University on dairy manure management operations in New York
(Poe 1999)
• Previous EPA estimates of waste distribution for sheep, goat, and horse operations (EPA 1992)
Beef Feedlots: Based on EPA site visits and state contacts, beef feedlot manure is almost exclusively
managed in drylots. Therefore, 100 percent of the manure excreted at beef feedlots is expected to be deposited in
drylots and generate emissions. In addition, a portion of the manure that is deposited in the drylot will run off the
drylot during rain events and be captured in a waste storage pond. An estimate of the runoff has been made by
L-3
-------
EPA's Office of Water for various geographic regions of the United States. These runoff numbers were used to
estimate emissions from runoff storage ponds located at beef feedlots (EPA 2001a).
Dairy Cows: Based on EPA site visits and state 'contacts, manure from dairy cows at medium (200 through
700 head) and large (greater than 700 head) operations' are managed using either flush systems or scrape/slurry
systems. In addition, they may have a solids separator in place prior to their storage component. Estimates of the
percent of farms that use each type of system (by geographic region) were developed by EPA's Office of Water, and
were used to estimate the percent of wastes managed in lagoons (flush systems), liquid/slurry systems (scrape
systems), and solid storage (separated solids). (EPA 2001a). Manure management system data for small (fewer
than 200 head) dairies were obtained from USDA (USDA 2000h). These operations are more likely to use
liquid/slurry and solid storage management systems tlhan anaerobic lagoon systems. The reported manure
management systems were deep pit, liquid/slurry (also includes slurry tank, slurry earth-basin, and aerated lagoon),
anaerobic lagoon, and solid storage (also includes manure jpack, outside storage, and inside storage).
The percent of wastes by system was estimated using the USDA data broken out by geographic region and
farm size. Farm-size distribution data reported in the 1992 and 1997 Census of Agriculture (USDA 1999e) were
used to determine the percentage of all dairies using the various manure management systems. Due to lack of
additional data for other years, it was assumed that the dkta provided for 1992 were the same as that for 1990 and
1991, and data provided for 1997 were the same as that for 1998,1999, and 2000. Data for 1993 through 1996 were
extrapolated using the 1992 and 1997 data. ;
Data regarding the use of daily spread and pasture, range, or paddock systems for dairy cattle were obtained
from personal communications with personnel from several organizations. These organizations include state NRCS
offices, State extension services, state universities, USDA Rational Agricultural Statistics Service (NASS), and other
experts (Deal 2000, Johnson 2000, Miller 2000, Stettler 2000, Sweeten 2000, and Wright 2000). Contacts at Cornell
University provided survey data on dairy manure management practices in New York (Poe 1999). Census of
Agriculture population data for 1992 and 1997 (USDA 1999e) were used in conjunction with the state data obtained
from personal communications to determine regional percentages of total dairy cattle and dairy wastes that are
managed using these systems. These percentages were applied to the total annual dairy cow and heifer state
population data for 1990 through 2000, which were obtained from the USDA National Agricultural Statistics
Service (USDA 1995a, 1999a, 2000a-b, 2001a-b). '
Of the dairies using systems other than daily spread and pasture, range, or paddock systems, some dairies
reported using more than one type of manure management system. Therefore, the total percent of systems reported
by USDA for a region and farm size is greater than 100 percent. Typically, this means that some of the manure at a
dairy is handled in one system (e.g., a lagoon), and some jof the manure is handled in another system (e.g., drylot).
However, it is unlikely that the same manure is moved from one system to another. Therefore, to avoid double
counting emissions, the reported percentages of systems In use were adjusted to equal a total of 100%, using the
same distribution of systems. For example, if USDA reported that 65 percent of dairies use deep pits to manage
manure and 55 percent of dairies use anaerobic lagoons to1 manage manure, it was assumed that 54 percent (i.e., 65
percent divided by 120 percent) of the manure is managed] with deep pits and 46 percent (i.e., 55 percent divided by
120 percent) of the manure is managed with anaerobic lagoons (ERG 2000).
Dairy Heifers: The percent of dairy heifer operations that are pasture, range, or paddock or that operate as
daily spread was estimated using the same approach as dairy cows. Similar to beef cattle, dairy heifers are housed
on drylots when not pasture based. Based on data from EPA's Office of Water (EPA 2001a), it was assumed that
100% of the manure excreted by dairy heifers is deposited in drylots and generates emissions. Estimates of runoff
have been made by EPA's Office of Water for various geographic regions of the US (EPA 200 la).
Swine: Based on data collected during site visits for EPA's Office of Water (ERG 2000), manure from
swine at large (greater than 2000 head) and medium (200 through 2000 head) operations are primarily managed
using deep pit systems, liquid/slurry systems, or anaerobic (lagoons. Manure management system data were obtained
from USDA (USDA 1998d). It was assumed those operations with less than 200 head use pasture, range, or paddock
systems. The percent of waste by system was estimated using the USDA data broken out by geographic region and
farm size. Farm-size distribution data reported in the 19^2 and 1997 Census of Agriculture (USDA 1999e) were
used to determine the percentage of all swine utilizing the various manure management systems. The reported
manure management systems were deep pit, liquid/slurry (also includes above- and below-ground slurry), anaerobic
lagoon, and solid storage (also includes solids separated from liquids).
L-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Some swine operations reported using more than one management system; therefore, the total percent of
systems reported by USD A for a region and farm size is greater than 100 percent. Typically, this means that some
of the manure at a swine operation is handled in one system (e.g., liquid system), and some of the manure is handled
in another system (e.g., dry system). However, it is unlikely that the same manure is moved from one system to
another. Therefore, to avoid double counting emissions, the reported percentages of systems in use were adjusted to
equal a total of 100 percent, using the same distribution of systems, as explained under "Dairy Cows".
i
Sheep: It was assumed that all sheep wastes not deposited on feedlots were deposited on pasture, range, or
paddock lands (Anderson 2000).
Goats/Horses: Estimates of manure management distribution were obtained from 'EPA's previous
estimates (EPA 1992).
Poultry - Layers: Waste management system data for layers for 1990 were obtained from Appendix H of
Global Methane Emissions from Livestock and Poultry Manure (EPA 1992). The percentage of layer operations
using a shallow pit flush house with anaerobic lagoon or high-rise house without bedding was obtained for 1999
from United Egg Producers, voluntary survey, 1999 (UEP 1999). These data were augmented for key poultry states
(AL, AR, CA, FL, GA, IA, IN, MN, MO, NC, NE, OH, PA, TX, and WA) with USDA data (USDA 2000i). It was
assumed that the change in system usage between 1990 and 1999 is proportionally distributed among those years of
the inventory. It was assumed that system usage in 2000 was equal to that estimated for 1999. It w,as also assumed
that 1 percent of poultry wastes are deposited on pasture, range, or paddock lands (EPA 1992).
Poultry - Broilers/Turkeys: The percentage of turkeys and broilers on pasture or in high-rise houses
without bedding was obtained from Global Methane Emissions from Livestock and Poultry Manure (EPA1992). It
was assumed that 1 percent of poultry wastes are deposited in pastures, range, and paddocks (EPA 1992).
Step 4: Emission Factor Calculations
Methane conversion factors (MCFs) and nitrous oxide emission factors (EFs) used in the emission
calculations were determined using the methodologies shown below:
Methane Conversion Factors (MCFs)
Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC
2000) for anaerobic lagoon systems published default methane conversion factors of 0 to 100 percent, which reflects
the wide range in performance that may be achieved with these systems. There exist relatively few data points on
which to determine country-specific MCFs for these systems. Therefore, a climate-based approach was identified to
estimate MCFs for anaerobic lagoon and other liquid storage systems.
The following approach was used to develop the MCFs for liquid systems, and is based on the van't Hoff-
Arrhenius equation used to forecast performance of biological reactions. One practical way of estimating MCFs for
liquid manure handling systems is based on the mean ambient temperature and the van't Hoff-Arrhenius equation
with a base temperature of 30°C, as shown in the following equation (Safley and Westerman 1990): •
Where,
T! = 303.16K
T2 = ambient temperature (K) for climate zone (in this case, a weighted value for each state)
E = activation energy constant (15,175 cal/mol)
R = ideal gas constant (1.987 cal/K mol)
The factor "f" represents the proportion of volatile solids that are biologically available for conversion to
methane based on the temperature of the system. The temperature is assumed equal to the ambient temperature. For
colder climates, a minimum temperature of 5°C was established for uncovered anaerobic lagoons and 7.5°C for
other liquid manure handling systems. For those animal populations using liquid systems (i.e., dairy cow, dairy
L-5
-------
heifer, layers, beef on feedlots, and swine) monthly average state temperatures were based on the counties where the
specific animal population resides (i.e., the temperatures Were weighted based on the percent of animals located in
each county). The average county and state temperature data were obtained from the National Climate Data Center
(NOAA 2001), and the county population data were based'on 1992 and 1997 Census data (USDA 1999e). County
population data for 1990 and 1991 were assumed to be the same as 1992; county population data for 1998 through
2000 were assumed to be the same as 1997; and county population data for 1993 through 1996 were extrapolated
based on 1992 and 1997 data. >
Annual MCFs for liquid systems are calculated jas follows for each animal type, state, and year of the
inventory: :
1) Monthly temperatures are calculated by using county-level temperature and population data. The
weighted-average temperature for a state;is calculated using the population estimates and average
monthly temperature in each county.
2) Monthly temperatures are used to calculate a monthly van't Hoff-Arrhenius "f" factor, using the
equation presented above. A minirnunij temperature of 5°C is used for anaerobic lagoons and
7.5°C is used for liquid/slurry and deep pit systems.
3) Monthly production of volatile solids that are added to the system is estimated based on the
number of animals present and, for lagoon systems, adjusted1 for a management and design
practices factor. This factor accounts for other mechanisms by which volatile solids are removed
from the management system prior to conversion to methane, such as solids being removed from
the system for application to cropland.; This factor, equal to 0.8, has been estimated using
currently available methane measurement data from anaerobic lagoon systems in the United States
(ERG 2001). I
4) The amount of volatile solids available for conversion to methane is assumed to be equal to the
amount of volatile solids produced during the month (from Step 3). For anaerobic lagoons, the
amount of volatile solids available also inbludes volatile solids that may remain in the system from
previous months.
5) The amount of volatile solids consumed during the month is equal to the amount available for
conversion multiplied by the "f' factor, j
r
6) For anaerobic lagoons, the amount of volatile solids carried over from one month to the next is
equal to the amount available for conversion minus the amount consumed.
7) The estimated amount of methane generated during the month is equal to the monthly volatile
solids consumed multiplied by the maximum methane potential of the waste (B0).
8) The annual MCF is then calculated as:
MCF (annual) = CH4 generated (^ua!) / (VS generated (anmlai) x B0)
In order to account for the carry over of volatile solids from the year prior to the inventory year for which
estimates are calculated, it is assumed in the MCF calculation for lagoons that a portion of the volatile solids from
October, November, and December of the year prior to the inventory year are available in the lagoon system starting
January of the inventory year. ;
Following this procedure, the resulting MCF accounts for temperature variation throughout the year,
residual volatile solids in a system (carryover), and management and design practices that may reduce the volatile
solids available for conversion to methane. The methane'conversion factors presented in Table L-4 by state and
waste management system represent the average MCF for 2000 by state for all animal groups located in that state.
However, in the calculation of methane emissions, specific MCFs for each animal type in the state are used.
Nitrous Oxide Emission Factors
Nitrous oxide emission factors for all manure management systems were set equal to the default IPCC
factors (IPCC 2000).
L-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Step 5: Weighted Emission Factors
For beef cattle, dairy cattle, swine, and poultry, the emission factors for both methane and nitrous oxide
were weighted to incorporate the distribution of wastes by management system for each state. The following
equation was used to determine the weighted MCF for a particular animal type in a particular state: ,
MCFanimal, slate = /"" (MCFsyslem, slate X %Maniireanimal, system, state)
£-J^
system
Where:
MCFantaai, state = Weighted MCF for that animal group and state
MCFsystem, state = MCF for that system and state (see Step 4)
% Manureantaai, system, state = Percent of manure managed in the system for that animal group in that state
(expressed as a decimal)
The weighted nitrous oxide emission factor for a particular animal type in a particular state was determined
as follows:
EF animal, state — / (EFsystem X /O MdnUTSanimal, system, state)
system '•
Where,
EFanimai, state = Weighted emission factor for that animal group and state ;
EFSystem= Emission factor for that system (see Step 4) \
% Manureanimai, system, state - Percent of manure managed in the system for that animal group in that state
(expressed as a decimal)
Data, for the calculated weighted factors for 1992 came from the 1992 Census of Agriculture, combined
with assumptions on manure management system usage based on farm size, and were also used for 1990 and 1991.
Data for the calculated weighted factors for 1997 came from the 1997 Census of Agriculture, combined with
assumptions on manure management system usage based on farm size, and were also used for 1998,1999, and 2000.
Factors for 1993 through 1996 were calculated by interpolating between the two sets of factors. A summary of the
weighted MCFs used to calculate beef feedlot, dairy cow and heifer, swine, and poultry emissions for 2000 are
presented in Table L-5.
Step 6: Methane and Nitrous Oxide Emission Calculations
For beef feedlot cattle, dairy cows, dairy heifers, swine, and poultry, methane emissions were calculated for
each animal group as follows:
Methane animal group — '^(Population XVSXBoXMCFammal.slateXQ.662~) ;
state
Where:
ma! group = methane emissions for that animal group (kg CEU/yr)
Population = annual average state animal population for that animal group (head)
VS = total volatile solids produced annually per animal (kg/yr/head)
B0 = maximum methane producing capacity per kilogram of VS (m3 CHVkg VS)
MCFanimai, 5^^ = weighted MCF for the animal group and state (see Step 5)
0.662 = conversion factor of m3 CH4 to kilograms CH4 (kg CH4 /m3 CH4)
Methane emissions from other animals (i.e., sheep, goats, and horses) were based on the 1990 methane
emissions estimated using the detailed method described in Anthropogenic Methane Emissions in the United States:
L-7
-------
Estimates for 1990, Report to Congress (EPA 1993).; This approach is based on animal-specific manure
characteristics and management system data. This process was not repeated for subsequent years for these other
animal types. Instead, national populations of each of the animal types were used to scale the 1990 emissions
estimates to the period 1991 through 2000. ;
Nitrous oxide emissions were calculated for each 'animal group as follows:
NitrOUS Oxide ommal group = ^T (Population X Net X EFanlmal, stale X 44 / 28)
Where:
Nitrous Oxideonimai group = nitrous oxide emissions for that animal group (kg/yr)
Population = annual average state animal population for that animal group (head)
Ncx = total Kjeldahl nitrogen excreted annually per animal (kg/yr/head)
EFanim,it state = weighted nitrous oxide emission factor for the animal group and state, kg N2O-N/kg N
excreted (see Step 5) :
44/28 = conversion factor of N2O-N to N2O |
Emission estimates are summarized in Table L-6 and Table L-7.
L-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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Table L-3: Estimated Dairy Cow Volatile Solids Production Rate By State for 2000
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Volatile Solids1 (kq/day/1000 kq)
7.07
7.28
9.32
6.52
9.20
9.30
8.48
7.42
7.67
7.93
7.23
9.11
8.22
7.88
8.46
8.00
6.65
6.38
8.00
7.80
8.10
8.65
8.31
7.49
7.34
8.23
7.86
8.66
8.15
7.97
9.14
8.20
8.01
7.21
8.09
7.18
8.60
8.40
7.67
7.79
7.78
7.38
7.93
8.25
8.24
7.73
9.54
7.65
8.18
6.94
1 Volatile solids production estimates based on state average annual milk production rates, combined with a
mathematical relationship of volatile solids to milk production (USDA 1996a).
L-11
-------
TaUle L-4: Methane Cmversion Factors By State for liquid Systems? fir 2000
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyominq
Liquid/Slurry and Deep Pit Anaerobic Lagoon
0.4122 0.7538
0.1472 0.4677
0.4919 0.7689
0.3823 0.7536
0.3440 0.7330
0.2336 0.6705
0.2337 0.6642
0.2927 0.7124
0.5193
0.7684
0.3919 0.7411
0.5827 0.7869
0.2247 0.6570
0.2870 0.7128
0.2714 0.6976
0.2627 0.6981
0.3439 0.7515
0.3151
0.7241
0.4790 0.7631
0.1917 0.6025
0.2786 ! 0.6999
0.2243
0.2295
0.6523
0.6576
0.2335 0.6675
0.4308 0.7584
0.3245 0.7361
0.2073
0.2856
0.6337
0.7197
0.2466 0.6787
0.2007 0.6176
0.2605 ' 0.6896
0.3272 0.7328
0.2167 i 0.6402
0.3346
0.2165
0.2573
0.3933
0.2112
0.2485
0.2420
0.3831
0.2496
0.3390
0.4622
0.2673
0.1965
0.2829
0.2126
0.2607
0.2278
0.7255
0.6482
0.6841
0.7602
0.6291
0.6764
0.6765
0.7401
0.6911
0.7367
0.7613
0.7029
0.6090
0.7009
0.6329
0.6850
0.6595
0.2184 ! 0.6513
2 As defined by IPCC (EPCC 2000).
L-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
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L-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX M
Methodology for Estimating N20 Emissions from Agricultural Soil Management
Nitrous oxide (N2O) emissions from agricultural soil management covers activities that add nitrogen (N) to
soils, and thereby enhance natural emissions of N2O. The IPCC methodology (IPCC/UNEP/OECD/IEA 1997, IPCC
2000), which is used here, divides this source category into three components: (1) direct N2O emissions from
managed soils; (2) direct N2O emissions from pasture, range, and paddock livestock manure; and (3) indirect N2O
emissions from soils induced by applications of nitrogen.
There are five steps in estimating N2O emissions from agricultural soil management. First, the activity data
are derived for each of the three components. Note that some of the data used in the first component are also used in
the third component. In the second, third, and fourth steps, N2O emissions from each of the three components are
estimated. In the fifth step, emissions from the three components are summed to estimate total emissions. The
remainder of this annex describes these steps, and data used in these steps, in detail.
Step 1: Derive Activity Data
The activity data for this source category are annual amounts of nitrogen added to soils for each relevant
activity, except for histosol cultivation, for which the activity data are annual histosol areas cultivated.1 The activity
data are derived from statistics, such as fertilizer consumption data or livestock population data, and various factors
used to convert these statistics to annual amounts of nitrogen, such as fertilizer nitrogen contents or livestock
excretion rates. Activity data were derived for each of the three components, as described below.
Step la: Direct NzO Emissions from Managed Soils.
The activity data for this component include: a) the amount of nitrogen in synthetic and organic
commercial fertilizers that are applied annually, b) the amount of nitrogen in livestock manure that is applied
annually through both daily spread operations and the eventual application of manure that had been stored in manure
management systems, c) the amount of nitrogen in sewage sludge that is applied annually, d) the amount of nitrogen
in the aboveground biomass of nitrogen-fixing crops that are produced annually, e) the amount of nitrogen in crop
residues that are retained on soils annually, and f) the area of histosols cultivated annually.
Application of synthetic and organic commercial fertilizer: Annual commercial fertilizer consumption data
for the United States were taken from annual publications of synthetic and organic fertilizer statistics (TVA 1991,
1992a, 1993, 1994; AAPFCO 1995, 1996, 1997, 1998, 1999, 2000b) and a recent AAPFCO database (AAPFCO
2000a). These data were manipulated in several ways to derive the activity data needed for the inventory. First, the
manure and sewage sludge portions of the organic fertilizers were subtracted from the total organic fertilizer
consumption data because these nitrogen additions are accounted for under "manure application" and "sewage
sludge application."2 Second, the organic fertilizer data, which are recorded in mass units of fertilizer, had to be
converted to mass units of nitrogen by multiplying by the average organic fertilizer nitrogen contents provided in the
annual fertilizer publications. These nitrogen contents are weighted average values, so they vary from year-to-year
(ranging from 2.3 percent to 3.9 percent over the period 1990 through 2000). The synthetic fertilizer data are
recorded in units of nitrogen, so these data did not need to be converted. Lastly, both the synthetic and organic
fertilizer consumption data are recorded in "fertilizer year" totals (i.e., July to June); therefore, the data were
converted to calendar year totals. This was done by assuming that approximately 35 percent of fertilizer usage
occurred from July to December, and 65 percent from January to June (TVA 1992b). July to December values were
1 Histosols are soils with a high organic carbon content. All soils with more than 20 to 30 percent organic matter by
weight (depending on the clay content) are classified as histosols (Brady and Weil 1999).
2 Organic fertilizers included in these publications are manure, compost, dried blood, sewage sludge, tankage, and
"other." (Tankage is dried animal residue, usually freed from fat and gelatin). The manure and sewage sludge used as
commercial fertilizer are accounted for elsewhere, so these were subtracted from the organic fertilizer statistics to avoid double
counting.
M-1
-------
not available for calendar year 2000, so a "least squares line" statistical extrapolation using the previous ten years of
data was used to arrive at an approximate value. Annual ;consumption of commercial fertilizers—synthetic and non-
manure/non-sewage organic—in units of nitrogen and on a calendar year basis are presented in Table M-l.
Application of livestock manure: To estimate the amount of livestock manure nitrogen applied to soils, it
was assumed that all of the manure produced by livestock would be applied to soils with two exceptions. These
exceptions were: (1) the portion of poultry manure that is used as a feed supplement for ruminants, and (2) the
manure that is deposited on soils by livestock on pasture,; range, and paddock. In other words, all of the manure that
is managed, except the portion of poultry manure that is used as a feed supplement, is assumed to be applied to soils.
The amount of managed manure for each livestock type was calculated by determining the population of animals
that were on feedlots or otherwise housed in order to collect and manage the manure. In some instances, the number
of animals in managed systems was determined by subtracting the number of animals in pasture, range, and paddock
from the total animal population for a particular animal type.
Annual animal population data for all livestocjc types, except horses and goats, were obtained from the
USDA National Agricultural Statistics Service (USDA 1994b,c; 1995a,b; 1998a; 1998c; 1999a-c; 2000a-g; 2001b-
g). Horse population data were obtained from the FAOSTAT database (FAO 2001). Goat population data were
obtained from the Census of Agriculture (USDA 1999d). Information regarding poultry turnover (i.e., slaughter)
rate was obtained from state Natural Resource Conservation Service personnel (Lange 2000). Additional population
data for different farm size categories for dairy and swine were obtained from the Census of Agriculture
(USDA 1999e). j
Information regarding the percentage of manure handled using various manure management systems for
dairy cattle, beef cattle, and sheep was obtained from communications with personnel from state Natural Resource
Conservation Service offices, state universities, National'Agricultural Statistics Service, and other experts (Poe et al.
1999, Anderson 2000, Deal 2000, Johnson 2000, Mille^ 2000, Milton 2000, Stettler 2000, Sweeten 2000, Wright
2000). Information regarding the percentage of manure handled using various manure management systems for
swine, poultry, goats, and horses was obtained from Safley et al. (1992). A more detailed discussion of manure
management system usage is provided in Annex L. !
Once the animal populations for each livestock type and management system were estimated, these
populations were then multiplied by an average animal mass constant (USDA 1996, USDA 1998d, ASAE 1999,
Safley 2000) to derive total animal mass for each animal type in each management system. Total Kjeldahl nitrogen3
excreted per year for each livestock type and management system was then calculated using daily rates of nitrogen
excretion per unit of animal mass (USDA 1996, ASAE 1999). The total poultry manure nitrogen in managed
systems was reduced by the amount assumed to be used as a feed supplement (i.e., 4.2 percent of the managed
poultry manure; Carpenter 1992). The annual amounts ;of Kjeldahl nitrogen were then summed over all livestock
types and management systems to derive estimates of therannual manure nitrogen applied to soils (Table M-2).
Application of sewage sludge: Estimates of aijnual nitrogen additions from land application of sewage
sludge were derived from periodic estimates of sludge generation and disposal rates that were developed by EPA.
Sewage sludge is generated from the treatment of raw [ sewage in public or private wastewater treatment works.
Based on a 1988 questionnaire returned from 600 publicly owned treatment works (POTWs), the EPA estimated that
5.4 million metric tons of dry sewage sludge were generated by POTWs in the United States in that year (EPA
1993). Of this total, 43.7 percent was applied to land,! including agricultural applications, compost manufacture,
forest land application, the reclamation of mining areasj and other forms of surface disposal. A subsequent EPA
report (EPA, 1999) compiled data from several national! studies and surveys, and estimated that approximately 6.7
and 6.9 million metric tons of dry sewage sludge were generated in 1996 and 1998, respectively, and projected that
approximately 7.1 million metric tons would be generated in 2000. The same study concluded that 60 percent of the
sewage sludge generated in 1998 was applied to land (based on the results of a 1995 survey), and projected that 63
percent would be land applied in 2000. These EPA estimates of sludge generation and percent land applied were
linearly interpolated to derive estimates for each year in the 1990 to 2000 period. To estimate annual amounts of
nitrogen applied, the annual amounts of dry sewage sludge applied were multiplied by an average nitrogen content
of 3.3 percent (Metcalf and Eddy, Inc. 1991). Final estimates of annual amounts of sewage sludge nitrogen applied
to land are presented in Table M-l. ;
3 Total Kjeldahl nitrogen is a measure of organically bound nitrogen and ammonia nitrogen in both the solid and liquid
wastes.
M-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Production of nitrogen-fixing crops: Annual production statistics for beans, pulses, and alfalfa were taken
from U.S. Department of Agriculture crop production reports (USDA 1994a, 1998b, 2000i, 2001a). Annual
production statistics for the remaining nitrogen-fixing crops (i.e., the major non-alfalfa forage crops, specifically red
clover, white clover, birdsfoot trefoil, arrowleaf clover, and crimson clover) were derived from information in a
book on forage crops (Taylor and Smith 1995, Pederson 1995, Beuselinck and Grant 1995, Hoveland and Evers
1995), and personal communications with forage experts (Cropper 2000, Evers 2000, Gerrish 2000, Hoveland 2000,
and Pederson 2000).
The production statistics for beans, pulses, and alfalfa were in tons of product, which needed to be
converted to tons of aboveground biomass nitrogen. This was done by multiplying the production statistics by one
plus the aboveground residue to crop product mass ratios, dry matter fractions, and nitrogen contents. The residue to
crop product mass ratios for soybeans and peanuts, and the dry matter content for soybeans, were obtained from
Strehler and Stutzle (1987). The dry matter content for peanuts was obtained through personal communications with
Ketzis (1999). The residue to crop product ratios and dry matter contents for the other beans and pulses were
estimated by taking averages of the values for soybeans and peanuts. The dry matter content for alfalfa was
obtained through personal communications with Karkosh (2000). The IPCC default nitrogen content of 3 percent
(IPCC/UNEP/OECD/IEA 1997) was used for all beans, pulses, and alfalfa.4
The production statistics for the non-alfalfa forage crops were derived by multiplying estimates of areas
planted by estimates of annual yields, in dry matter mass units. These derived production statistics were then
converted to units of nitrogen by applying the IPCC default nitrogen content of 3 percent (IPCC/UNEP/OECD/IEA
1997).
The final estimates of annual aboveground biomass production, in units of nitrogen, are presented in Table
M-3. The residue to crop product mass ratios and dry matter fractions used in these calculations are presented in
Table M-6.
Retention of crop residue: It was assumed that 90 percent of residues from corn, wheat, barley, sorghum,
oats, rye, millet, soybeans, peanuts, and other beans and pulses are left on the field after harvest (e.g., rolled into the
soil, chopped and disked into the soil, or otherwise left behind) (Karkosh 2000).5 It was also assumed that 100
percent of unburned rice residue is left on the field.6
The derivation of residue nitrogen activity data was very similar to the derivation of nitrogen-fixing crop
activity data. Crop production statistics were multiplied by aboveground residue to crop product mass ratios,
residue dry matter fractions, residue nitrogen contents, and the fraction of residues left on soils. Annual production
statistics for all crops except rice in Florida were taken from U.S. Department of Agriculture reports (USDA 1994a,
1998b, 2000i, 200la). Production statistics for rice in Florida, which are not recorded by USDA, were estimated by
applying an average rice crop yield for Florida (Smith 2001) to annual Florida rice acreages (Schueneman 1999,
2001). Residue to crop product ratios for all crops were obtained from, or derived from, Strehler and Stutzle (1987).
Dry matter contents for wheat, rice, corn, and barley residue were obtained from Turn et al. (1997). Soybean and
millet residue dry matter contents were obtained from Strehler and Stutzle (1987). Peanut, sorghum, oat, and rye
residue dry matter contents were obtained through personal communications with Ketzis (1999).. Dry matter
contents for all other beans and pulses were estimated by averaging the values for soybeans and peanuts. The
residue nitrogen contents for wheat, rice, corn, and barley are from Turn et al. (1997). The nitrogen content of
soybean residue is from Barnard and Kristoferson (1985), the nitrogen contents of peanut, sorghum, oat, and rye
residue are from Ketzis (1999), and the nitrogen content of millet residue is from Strehler and Stutzle (1987).
Nitrogen contents of all other beans and pulses were estimated by averaging the values for soybeans and peanuts.
Estimates of the amounts of rice residue burned annually were derived using information obtained from agricultural
4 This nitrogen content may be an overestimate for the residue portion of the aboveground biomass of the beans and
pulses. Also, the dry matter fractions used for beans and pulses were taken from literature on crop residues, and so may be
underestimates for the product portion of the aboveground biomass.
5 Although the mode of residue application would likely affect the magnitude of N2O emissions, an emission
estimation methodology that accounts for this has not been developed.
6 Some of the rice residue may be used for other purposes, such as for biofuel or livestock bedding material. Research
to obtain more detailed information regarding final disposition of rice residue, as well as the residue of other crops, will be
undertaken for future inventories.
M-3
-------
extension agents in each of the rice-growing states (see Agricultural Residue Burning section of Agriculture Chapter
for more detail). j
The final estimates of residue retained on soil, ;in units of nitrogen (N), are presented in Table M-4. The
residue to crop product mass ratios, residue dry matter fractions, and residue nitrogen contents used in these
calculations are presented in Table M-6. i
Cultivation of histosols: Estimates of the areas of histosols cultivated in 1982, 1992, and 1997 were
obtained from the USDA's 1997 National Resources Inventory (USDA 2000h, as extracted by Eve 2001, and
revised by Ogle 2002).7 These areas were grouped by proad climatic region8 using temperature and precipitation
estimates from Daly et al. (1994, 1998), and then further aggregated to derive a temperate total and a sub-tropical
total. These final areas were then linearly interpolate4 to obtain estimates for 1990 through 1996, and linearly
extrapolated to obtain area estimates for 1998 through 2000 (Table M-5).
Step 1b: Direct NzO Emissions from Pasture, Range, and Paddock Livestock Manure.
Estimates of N2O emissions from this component were based on livestock manure that is not managed in
manure management systems, but instead is deposited directly on soils by animals in pasture, range, and paddock.
The livestock included in this component were: dairy cattle, beef cattle, swine, sheep, goats, poultry, and horses.
Dairy Cattle: Information regarding dairy farm grazing was obtained from communications with personnel
from state Natural Resource Conservation Service offices, state universities, and other experts (Poe et al. 1999, Deal
2000, Johnson 2000, Miller 2000, Stettler 2000, Sweefen 2000, Wright 2000). Because grazing operations are
typically related to the number of animals on a farm, farm-size distribution data reported in the 1992 and 1997
Census of Agriculture (USDA 1999e) were used in conjunction with the state data obtained from personal
communications to determine the percentage of total dairy cattle that graze. An overall percent of dairy waste that is
deposited in pasture, range, and paddock was developed! for each region of the United States. This percentage was
applied to the total annual dairy cow and heifer state population data for 1990 through 2000, which were obtained
from the USDA National Agricultural Statistics Service (USDA 1995a; 1999a; 2000a,b; 2001b,c).
Beef Cattle: To determine the population of [beef cattle that are on pasture, range, and paddock, the
following assumptions were made: 1) beef cows, bulls; and calves were not housed on feedlots; 2) a portion of
heifers and steers were on feedlots; and 3) all beef cattle that were not housed on feedlots were located on pasture,
range, and paddock (i.e., total population minus population on feedlots equals population of pasture, range, and
paddock) (Milton 2000). Information regarding the percentage of heifers and steers on feedlots was obtained from
USDA personnel (Milton 2000) and used in conjunction with USDA National Agricultural Statistics Service
population data (USDA 1995a; 1999a; 2000a,b; 2001b,c) to determine the population of steers and heifers on
pasture, range, and paddock. :
Swine: Based on the assumption that smaller facilities are less likely to utilize manure management
systems, farm-size distribution data reported in the 1992\and 1997 Census of Agriculture (USDA 1999e) were used
to determine the percentage of all swine whose manure [is not managed (i.e., the percentage on pasture, range, and
paddock). These percentages were applied to the average of the quarterly USDA National Agricultural Statistics
Service population data for swine (USDA 1994b, 1998a, 2000e, 200Id) to determine the population of swine on
pasture, range, and paddock. !
Sheep: It was assumed that all sheep and lamb manure not deposited on feedlots was deposited on pasture,
range, and paddock (Anderson 2000). Sheep population data were obtained from the USDA National Agricultural
Statistics Service (USDA 1994c, 1999c, 2000g, 2001f). .However, population data for lamb and sheep on feed were
not available after 1993. The number of lamb and sheep on feed for 1994 through 2000 were calculated using the
average of the percent of lamb and sheep on feed from [1990 through 1993. In addition, all of the sheep and lamb
"on feed" were not necessarily on "feedlots"; they mayj have been on pasture/crop residue supplemented by feed.
Data for those feedlot animals versus pasture/crop residue were provided only for lamb in 1993. To calculate the
7 These areas do not include Alaska, but Alaska's cropland area accounts for less than 0.1 percent of total U.S.
cropland area, so this omission is not significant.
8 These climatic regions were: 1) cold temperate, dry, 2) cold temperate, moist, 3) sub-tropical, dry, 4) sub-tropical,
moist, 5) warm temperate, dry, and 6) warm temperate, moist.
M-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
populations of sheep and lamb on feedlots for all years, it was assumed that the percentage of sheep and lamb on
feedlots versus pasture/crop residue is the same as that for lambs in 1993 (Anderson 2000).
Goats: It was assumed that 92 percent of goat manure was deposited on pasture, range, and paddock
(Safley et al. 1992). Annual goat population data by state were available for only 1992 and 1997 (USDA 1999d).
The data for 1992 were used for 1990 through 1992 and the data for 1997 were used for 1997 through 2000. Data
for 1993 through 1996 were extrapolated using the 1992 and 1997 data.
Poultry: It was assumed that one percent of poultry manure was deposited on pasture, range, and paddock
(Safley et al. 1992). Poultry population data were obtained from USDA National Agricultural Statistics Service
(USDA 1995b, 1998a, 1999b, 2000c, 2000d, 2000f, 2001f). The annual population data for boilers and turkeys
were adjusted for turnover (i.e., slaughter) rate (Lange 2000).
Horses: It was assumed that 92 percent of horse manure was deposited on pasture, range, and paddock
(Safley et al. 1992). Horse population data were obtained from the FAOSTAT database (FAO 2001).;
For each animal type, the population of animals within pasture, range, and paddock systems was multiplied
by an average animal mass constant (USDA 1996, ASAE 1999, USDA 1998d, Safley 2000) to derive total animal
mass for each animal type. Total Kjeldahl nitrogen excreted per year was then calculated for each animal type using
daily rates of nitrogen excretion per unit of animal mass (USDA 1996, ASAE 1999). Annual nitrogen excretion was
then summed over all animal types to yield total nitrogen in pasture, range, and paddock manure (Table M-2).
Step 1c: Indirect AfeO Emissions from Soils Induced by Applications of Nitrogen.
This component accounts for N2O that is emitted indirectly from nitrogen applied as commercial fertilizer,
sewage sludge, and livestock manure. Through volatilization, some of this nitrogen enters the atmosphere as NH3
and NOX, and subsequently returns to soils through atmospheric deposition, thereby enhancing N2O production.
Additional nitrogen is lost from soils through leaching and runoff, and enters groundwater and surface water
systems, from which a portion is emitted as N2O. These two indirect emission pathways are treated separately,
although the activity data used, except for livestock manure, are identical. The activity data for commercial
fertilizer and sewage sludge are the same as those used in the calculation of direct emissions from managed soils
(Table M-l). The activity data for livestock manure are different from those used in other calculations. Here, total
livestock manure (i.e., the sum of applied manure, manure in pasture, range, and paddock, and manure used as a
livestock feed supplement) is used in the volatilization and deposition calculation; and livestock manure applied or
deposited on soils (i.e., the sum of applied manure and manure in pasture, range, and paddock) in the leaching and
runoff calculation. These data are presented in Table M-2.
Table M-1: Commercial Fertilizer Consumption & Land Application of Sewage Sludge H5g H)
Fertilizer Type
Synthetic
Other Organics*
Sewaqe Sludqe
1990
10,104
5
91
1991
10,275
9
98
1992
10,352
6
106
1993
10,719
5
113
1994
11,160
8
121
1995
10,798
11
129
1996
11,156
13
133
1997
11,172
15
135
1998
11,193
13
137
1999
11,229
11
142
2000
11,241
12
148
* Excludes manure and sewage sludge used as commercial fertilizer.
Table M-2: Livestock Manure Nitrogen (Ggl
Activity
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000
Applied to Soils
Pasture, Range, & Paddock
Total Manure
2,608 2,678 2,685 2,720 2,737 2,708 2,743 2,799 2,829 2,828 2,869
4,152 4,171 4,266 4,308 4,416 4,478 4,470 4,334 4,245 4,206 4,152
6,792 6,881 6,984 7,062 7,188 7,219 7,249 7,170 7,111 7,072 7,059
M-5
-------
Table H-3: JUuvegraund Blimass Nitragen in Nitragen-Fixing Craps (Ggl
Crop Type
Soybeans
Peanuts
Dry Edible Beans
Diy Edible Peas
Austrian Winter Peas
Lentils
Wrinkled Seed Peas
Alfalfa
Red Clover
White Clover
Birdsfoot Trefoil
Arrowleaf Clover
Crimson Clover
Total
1990
4,241
84
98
7
+
3
3
1,730
513
2,735
99
67
21
9,600
1991
4,374
115
102
11
+
5
3
1,729
513
2,735
99
67
21
9,774
1992
4,823
100
68
8
+
5
2
1,642
513
2,735
99
67
21
10,082
1993
4,117
79
66
10
+
6
3
1,662
513
2,735
99
65
19
9,375
i 1994
5,538
99
87
; 7
I +
! 6
2
' 1,683
i 513
: 2,735
99
' 63
18
i 10,850
1995
4,788
81
93
14
+
7
3
1,746
513
2,735
99
61
17
10,156
1996
5,241
86
84
8
+
4
2
1,642
513
2,735
99
58
16
10,488
1997
5,921
83
89
17
+
7
2
1,655
513
2,735
99
56
14
11,192
1998
6,036
93
92
18
+
6
2
1,708
513
2,735
99
54
13
11,368
1999
5,844
90
100
14
+
7
2
1,740
513
2,735
99
52
12
11,207
2000
6,099
77
80
11
+
9
2
1,642
513
2,735
99
50
11
11,327
+ Less than 0.5 Gg N.
Note: Totals may not sum due to independent rounding. ,
Table M-4: Hitragen In Crap Residues Retained an Sails (Gal
Product Type
Com
Wheal
Barley
Sorghum
Oats
Rye
Millet
Rice
Soybeans
Peanuts
Dry Edible Beans
Dry Edible Peas
Austrian Winter Peas
Lentils
Wrinkled Seed Peas
Total
+ Less than 0.5 Gg N.
1990 1991 1992 1993
957 902 1,143 765
501 364 453 440
71 78 77 67
180 184 275 168
39 27 32 23
2222
3333
51 53 61 52
1,982 2,045 2,254 1,924
13 18 16 13
11 12 8 7
1111
+ + + +
+ 111
+ + + +
3,814 3,689 4,326 3,466
1994 1995 1996 1997
1,213 893 1,114 1,111
426 401 418 456
63 61 66 61
203 144 250 199
25 18 17 18
2211
3333
65 60 57 66
2,588 2,238 2,450 2,767
16 13 14 13
10 10 10 10
1212
+ + + +
11 + 1
+ + + +
4,616 3,845 4,402 4,709
1998
1,177
468
59
164
18
2
3
69
2,821
15
10
2
+
1
+
4,810
1999
1,138
422
47
187
16
2
3
75
2,731
14
11
2
+
1
+
4,650
2000
1,203
408
54
148
16
1
1
69
2,851
12
9
1
+
1
+
4,775
Note: Totals may not sum due to independent rounding.
Talle M-5: Cnltlvated Histasal Area [Tnausand Hectares)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
Temperate Area Sub-Tropical Area
432 192
431 193
429 194
431 194
433 195
435 195
437 196
439 196
441 197
443 197
445 197
M-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table M-6: Key Assumptions for Nitrogen-Fixing Grip Production and Crop Residue
Residue/Crop Ratio Residue Dry Residue Nitrogen Fraction
Crop Matter Fraction
Soybeans
Peanuts
Dry Edible Beans
Dry Edible Peas
Austrian Winter Peas
Lentils
Wrinkled Seed Peas
Alfalfa
Com
Wheat
Barley
Sorghum
Oats
Rye
Millet
Rice
2.1
1.0
1.55
1.55
1.55
1.55
1.55
0
1.0
1.3
1.2
1.4
1.3
1.6
1.4
1.4
0.87
0.86
0.87
0.87
0.87
0.87
0.87
0.85
0.91
0.93
0.93
0.91
0.92
0.90
0.89
0.91
0.023
0.0106
0.0062
0.0062
0.0062
0.0062
0.0062
NA
0.0058
0.0062
0.0077
0.0108
0.007
0.0048
0.007
0.0072
Note: For the derivation of activity data for nitrogen-fixing crop production, the IPCC default nitrogen content of aboveground biomass (3
percent) was used.
Step 2: Estimate Direct N20 Emissions from Managed Soils Due to Nitrogen Additions and Cultivation of
Histosols
In this step, N2O emissions were calculated for each of two parts (direct N2O emissions due to nitrogen
additions and direct N2O emissions due to histosol cultivation), which were then summed to yield total direct N2O
emissions from managed soils (Table M-7).
Step 2a: Direct NzO Emissions Due to Nitrogen Additions.
To estimate these emissions, the amounts of nitrogen applied were each reduced by the IPCC default
fraction of nitrogen that is assumed to volatilize, the unvolatilized amounts were then summed, and the total
unvolatilized nitrogen was multiplied by the IPCC default emission factor of 0.0125 kg N2O-N/kg Nitrogen
(IPCC/UNEP/OECD/IEA 1997). The volatilization assumptions are described below.
• Application of synthetic and organic commercial fertilizer: The total amounts of nitrogen applied in
the form of synthetic commercial fertilizers and non-manure/non-sewage organic commercial
fertilizers were reduced by 10 percent and 20 percent, respectively, to account for the portion that
volatilizes to NH3 and NOX (IPCC/UNEP/OECD/IEA 1997).
• Application of livestock manure: The total amount of livestock manure nitrogen applied to soils was
reduced by 20 percent to account for the portion that volatilizes to NHs and NOX
(IPCC/UNEP/OECD/IEA 1997).
• Application of sewage sludge: The total amount of sewage sludge nitrogen applied to soils was
reduced by 20 percent to account for the portion that volatilizes to NHj and NOX
(IPCC/UNEP/OECD/IEA 1997, IPCC 2000).
• Production of nitrogen-fixing crops: None of the nitrogen in the aboveground biomass of nitrogen-
fixing crops was assumed to volatilize.
• Retention of crop residue: None of the nitrogen in retained crop residue was assumed to volatilize.
Step 2b: Direct NzO Emissions Due to Cultivation of Histosols.
To estimate annual N2O emissions from histosol cultivation, the temperate histosol area was multiplied by
the IPCC default emission factor for temperate soils (8 kg N2O-N/ha cultivated; IPCC 2000), and the sub-tropical
M-7
-------
histosol area was multiplied by the average of the temperate and tropical IPCC default emission factors (12 kg N2O-
N/ha cultivated; IPCC 2000). |
Step 3: Estimate Direct NzO Emissions from Pasture, Range, and Paddock Livestock Manure
To estimate direct N2O emissions from soils due to the deposition of pasture, range, and paddock manure,
the total nitrogen excreted by these animals was multiplied by the IPCC default emission factor (0.02 kg N2O-N/kg
N excreted) (see Table M-8). ;
Step 4: Estimate Indirect !\kO Emissions Induced by Applications of Nitrogen
In this step, N2O emissions were calculated ifor each of two parts (indirect N2O emissions due to
volatilization of applied nitrogen and indirect N2O emissions due to leaching and runoff of applied nitrogen), which
were then summed to yield total direct N2O emissions frotn managed soils.
Step 4a: Indirect Emissions Due to Volatilization.
To estimate these emissions, first the amounts of commercial fertilizer nitrogen and sewage sludge nitrogen
applied, and the total amount of manure nitrogen produced, were each multiplied by the IPCC default fraction of
nitrogen that is assumed to volatilize to NH3 and NOX (10 percent for synthetic fertilizer nitrogen; and 20 percent for
nitrogen in organic fertilizer, sewage sludge, and livestocfc manure). Next, the volatilized amounts of nitrogen were
summed, and then the total volatilized nitrogen was multiplied by the IPCC default emission factor of 0.01 kg N20-
N/kg N (IPCC/UNEP/OECD/IEA 1997). These emission1 estimates are presented in (Table M-9).
Step 4b: Indirect Emissions Due to Leaching and Runoff.
To estimate these emissions, first the amounts of commercial fertilizer nitrogen and sewage sludge nitrogen
applied, and the total amount of manure nitrogen applied or deposited, were each multiplied by the IPCC default
fraction of nitrogen that is assumed to leach and runoff (30 percent for all nitrogen). Next, the leached/runoff
amounts of nitrogen were summed, and then the total nitrogen was multiplied by the IPCC default emission factor of
0.025 kg N20-N/kg N (IPCC/UNEP/OECD/IEA 1997). These emission estimates are presented in (Table M-9).
Table H-7: Direct H20 Emissions from Managed Soils tig CO? En.)
Activity
Commercial Fertilizers'
Livestock Manure
Sewage Sludge
Nitrogen Fixation
Crop Residue
Histosol Cultivation
Total
1990
55
13
+
58
23
3
153
1991
56
13
+
60
22
3
155
1992
57
13
1
61
26
3
161
1993
59
1 13
1
57
21
, 3
154
1994
61
13
1
66
28
3
172
1995
59
13
1
62
23
3
161
1996
61
13
1
64
27
3
169
1997
61
13
1
68
29
3
175
1998
61
14
1
69
29
3
177
1999
62
14
1
68
28
3
176
2000
62
14
1
69
29
3
177
+ Less than 0.5 TgCOzEq.
Note: Totals may not sum due to independent rounding. ;
* These data do not include sewage sludge and livestock manure used as commercial fertilizers, to avoid double counting.
Table M-8: Direct HiO Emissions frem Pasture, Range, and Paddeck Livestock Manure [Tg Eft En.)
Animal Type
Beef Cattle
Dairy Cows
Swine
Sheep
Goats
Poultry
Horses
1990
35
2
+
2
1991
35
2
1
+
2
1992
36
2
1
+
2
1993 1994
37 38
2
+
2
+
2 2
1995
39
1
*
2
1996
39
1
+
2
1997
38
1
+
2
1998
37
1
+
2
1999
37
1
+
2
2000
36
1
+
2
Total
40
41
42
42
43
44
44
42
41
41
40
+ Less than 0.5 Tg COz Eq.
Note: Totals may not sum due to independent rounding.
M-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table M-9: Indirect too Emissions ITg CO? Eq.)
Activity
Volatil. & Aim. Deposition
Comm. Fertilizers
Livestock Manure
Sewage Sludge
Surface Leaching & Runoff
Comm. Fertilizers
Livestock Manure
Sewaqe Sludqe
Total
1990
12
5
7
62
37
25
74
1991
12
5
7
63
38
25
75
1992
12
5
7
64
38
25
76
1993
12
5
7
65
39
26
78
1994
13
5
7
67
41
26
80
1995
12
5
7
66
39
26
79
1996
13
5
7
68
41
26
80
1997
13
5
7
67
41
26
80
1998
13
5
T
67
41
26
80
1999
13
5
7
67
41
26
1
80
2000
13
5
7
67
41
26
1
80
+ Less than 0.5 Tg COz Eq.
Note: Totals may not sum due to independent rounding.
Step 5: Estimate Total NzO Emissions
In this step, total emissions are calculated by summing direct emissions from managed soils, direct
emissions from pasture, range, and paddock livestock manure, and indirect emissions (Table M-10).
Table M-10: Total H;0 Emissions (Tg CO. Eq.l
Activity
Direct Emissions from Managed Soils
Direct Emissions from Pasture, Range,
and Paddock Livestock
Indirect Emissions
Total
1990
153
40
74
267
1991
155
41
75
270
1992
161
42
76
278
1993
154
42
78
273
1994
172
43
80
295
1995
161
44
79
283
1996
169
44
80
292
1997
175
42
80
297
1998
177
41
80
298
1999
176
41
80
296
2000
177
40
80
297
Note: Totals may not sum due to independent rounding.
M-9
-------
r
M-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX N
Methodology for Estimating Net Changes in Forest Carbon Stocks
This annex presents a discussion of the methodology used to calculate net changes in carbon stocks in trees
understory, forest floor, down dead wood, forest soils, and harvested wood (i.e., wood products and landfilled
wood). More detailed discussions of selected topics may be found in the references cited in this annex.
The details of carbon conversion factors and step-by-step details of calculating net CO2 flux for forests are
given in three steps. In addition, the modeling projection system is briefly described.
Step 1: Estimate Forest Carbon Stocks and Net Changes in Forest Carbon Stocks
Step 1a: Obtain Forest Inventory Data
Forest survey data in the United States by broad forest type and region for 1987 and 1997 were obtained
from U.S. Forest Service, Forest Inventory & Analysis (FIA) estimates of forest resources, published in Waddell et
al. (1989) and Smith et al. (2001). The FIA data include: (1) growing stock volume per acre by forest type (referred
to hereinafter as "growing stock volumes"); and (2) area by Timberland and other forest land, for general forest
types by region (referred to hereinafter as "forest areas"). For 2001, the same variables were obtained from model
results as described in Haynes et al. (200 Ib). (See The Forest Sector Modeling Projection System below) This
information was combined with separate estimates of carbon density (carbon mass per unit area) to compile
estimates of carbon stocks.
Step Ib: Estimate Carbon in Living and Standing Dead Trees
To estimate live tree biomass, equations that convert forest tree volumes to total live tree dry biomass
(Smith et al. in review) were applied to the growing stock volumes by forest type and region (obtained in Step la).
Tree biomass includes aboveground biomass and belowground biomass of coarse roots. The minimum size tree is
one-inch diameter at diameter breast height (1.3 meter). Trees less than one-inch diameter are counted as carbon in
understory vegetation. Biomass estimates were divided by two to obtain estimates of carbon in living trees (i.e., it
was assumed that dry biomass is 50 percent carbon). Standing dead tree biomass was calculated by applying
equations that estimate biomass for standing dead trees (Smith et al. in review) from growing stock volumes. Again
standing dead tree biomass was divided by two to estimate carbon in standing dead trees. Table N-l lists the
average living and standing dead tree carbon densities by forest type, as calculated by applying the equations to the
1997 data.
N-1
-------
Table N-1: Average D.S. Garben Densities if Forest Components* (metric tins C/lial
Region'/ForestType
Eastern
White-red-jack pine
Spruce-fir
Longleaf-slash pine
Loblolly-shortleafpine
Oak-pine
Oak-hickory
Oak-gum-cypress
Elm-ash-collonwood
Maple-beech-birch
Aspen-birch
Other forest types
Nonstocked
Western
Douglas-fir
Ponderosa pine
Western while pine
Fir-spruce
Hemlock-Sitka spruce
Larch
Lodgepole pine
Redwood
Hardwoods
Other forest types
Pinyon-juniper
Chaparral
Nonstocked
Live and Standing Dead Tree !
Carbon
77.1
59.8i
42.4 :
49.3:
57.3
76.3;
86.0
67.6
82.5
56.0
1.8
3.7
110.8
66.3
69.2
113.0
152.4
97.0
67.8
186.6
89.d
55.4
20.8
17.5
18.1
Forest Floor
Carbon
13.8
40.2
9.2
9.1
11.6
6.6
6.0
23.0
28.0
7.6
0 -1
3.5
30.7
20.3
25.8
37.4
34.1
30.2
23.9
26.9
9.9
28.2
21.1
25.7
24.4
Soil Organic
Carbonb
196.1
192.9
136.3
91.7
82.3
85.0
152.2
118.1
139.5
237.0
996
99.6
89.6
70.4
68.3
137.5
157.1
65.6
62.7
85.8
79.5
90.1
56.3
58.7
90.1
«EaasStem°Uniled Steles is defined as states east of, and including North Dakota. South Dakota. Nebraska, Kansas, Oklahoma, and Texas.
Western United Stales includes the remaining conterminous States. |
<>Soil includes both mineral soils and organic soils (i.e., histosols); carbon densities are to a depth of 1 meter.
Step 1c: Estimate Carbon in Understoiy Vegetation
To estimate carbon in understory vegetation, I equations based on Birdsey (1992) were applied to the
database that was used to produce the compiled forest statistics in Smith et al. (2001). Understory vegetation is
defined as all biomass of undergrowth plants in a forest, including woody shrubs and trees less than one-inch
diameter, measured at breast height. A ratio of understory carbon to live tree carbon was calculated, and multiplied
by 100 to display the percent that understory carbon is as:related to live tree carbon. The average percent understory
carbon to live tree carbon was calculated by region and forest type. This percent was multiplied by the live tree
carbon data in 1987 and 1997 to calculate understory carbon. These percentages are given in Table N-2. This
procedure was used instead of applying the Birdsey equations directly, because detailed databases are not available
for inventory years prior to 1987. Using average estimates results in consistent historical carbon estimates for all
survey years. >
Table H-2: Ratiis if Dnderstiry and Diwn Dead Wood Carbon to Live Tree Carbon* (percent!
Region/Forest Type
Northeast
While-red-jack pine
Spruce-fir
Longleaf-Slash pine
Loblolly-shortleafpine
Oak-pine
Ratio of Understory Ratio Of Down Dead Wood
Carbon to Live Tree Carbon to Ljve Tree Carbon
Carbon
2.5 j
2.6 j
2.5 1
2.5 (
2.8 |
10.8
13.3
10.8
10.8
12.9
N-2 Inventory of U.S. Greenhouse Gas Emissions and Sinjcs: 1990-2000
-------
Oak-hickory 2.4
Oak-gum-cypress 2.6
Elm-ash-cottonwood 2.6
Maple-beech-birch 1.9
Aspen-birch 2.7
Other Forest Types 8.9
Nonstocked 8.9
North Central
White-red-jack pine 1,8
Spruce-fir 2.2
Longleaf-Slash pine 2.4
Loblolly-shortleafpine 2.4
Oak-pine 1.9
Oak-hickory 2.3
Oak-gum-cypress 2.3
Elm-ash-cottonwood 2.2
Maple-beech-birch 2.2
Sftspen-birch 2.8
Other Forest Types 5.5
Nonstocked 5,5
Southeast
White-red-jack pine 6.8
Spruce-fir 6.8
Longleaf-Slash pine 6.8
Loblolly-shortleafpine 6.8
Oak-pine 5.2
Oak-hickory 4.4
Oak-gum-cypress 2.2
Elm-ash-cottonwood 2.2
Maple-beech-birch 4.4
Aspen-birch 2.2
Other Forest Types 11.9
Nonstocked 11.9
South Central
White-red-jack pine 5.9
Spruce-fir 5.9
Longleaf-Slash pine 5.9
Loblolly-shortleafpine 5.9
Oak-pine 4.4
Oak-hickory 3.7
Oak-gum-cypress 2.2
Elm-ash-cottonwood 2.2
Maple-beech-birch 3.7
Aspen-birch 2.2
Other Forest Types 16.9
Nonstocked 16.9
Pacific Northwest Eastside of Cascades
Douglas-fir 1.6
Ponderosa Pine 2.5
Western White Pine 1.6
Fir-Spruce 1.1
Hemlock-Sitka spruce 1.6
Larch 1.6
Lodgepole pine 2.6
Redwood 1.9
Other hardwoods 1.4
Unclassified & other 2.5
Pinyon-Juniper 10.7
Chaparral 9.7
Nonstocked 9.7
Pacific Northwest Westside of Cascades
Douglas-fir 2.0
10.9
11.1
11.1
11.1
13.6
3.8
3.8
9.8
17.4
7.4
7.4
7.2
9.6
9.6
10.8
10.8
13.3
4.1
4.1
23.9
23.9
23.9
23.9
28.0
24.2
21.8
21.8
24.2
21.8
2.0
2.0
18.6
18.6
18.6
18.6
17.3
15.0
15.7
15.7
15.0
15.7
1.7
1.7
10.0
12.6
10.0
15.7
10.0
10.0
21.3
25.8
8.9
12.6
3.7
2.1
2.1
11.9
N-3
-------
Ponderosa Pine
Western White Pine
Fir-Spruce
Hemlock-Sitka spruce
Larch
Lodgepole pine
Redwood
Other hardwoods
Unclassified & other
Pinyon-Juniper
Chaparral
Nonstocked
Rocky Mountain, Northern
Douglas-fir
Ponderosa Pine
Western White Pine
Fir-Spruce
Hemlock-Sitka spruce
Larch
Lodgepole pine
Redwood
Other hardwoods
Unclassified & other
Pinyon-Juniper
Chaparral
Nonstocked
Rocky Mountain, Southern
Douglas-fir
Ponderosa Pine
Western White Pine
Fir-Spruce
Hemlock-Sitka spruce
Larch
Lodgepole pine
Redwood
Other hardwoods
Unclassified & other
Pinyon-Juniper
Chaparral
Nonstocked
Pacific Southwest
Douglas-fir
Ponderosa Pine
Western White Pine
Fir-Spruce
Hemlock-Sitka spruce
Larch
Lodgepole pine
Redwood
Other hardwoods
Unclassified & other
Pinyon-Juniper
Chaparral
Nonstocked
2.5
2.5
1.0
1.0
2.0
1.7
2.0
4.5
1.7
20.2
14.2
14.2
2.6
2.4
2.2
1.7
2.0
2.2
2.4
2.2
1.9
2.2
16.1
16.1
16.1
2.8
4.1
2.8
2.2
2.8
2.8
3.1
2.8
9.2
10.7
9.8
9.8
2.6
2.3
2.6
2.2
2.6
2.6
4.6
2.6
4.4
2.8
9.9
15.3
15.3
2.5
18.1
18.1
13.7
11 Q
i i.y
16.4
11 Q
1 l.y
3.9
16.4
3.7
3.0
3.0
1Q "7
\J,L-
19.6
9.7
14.8
18.7
O "7
y./
19.6
Q 7
y./
14.2
9.7
3.2
o o
o,£
1 0
O.£
19.4
O*| C
c. l.b
19.4
n A
I/.4
19.4
1Q A
iy.4
12.8
1Q A
iy.4
26.7
3.3
3.9
0 Q
o.y
15.2
15.5
15.2
11.5
15.2
15.2
•in o
1U.O
15.2
Q 7
y./
11.5
3.1
3.5
0 C
O.D
10.8
" Based on data from 1997.
Step 1d: Estimate Carbon in Forest Floor
To estimate forest floor carbon, the forest floor equations (Smith and Heath, in review) were applied to the
dataset described in Step la. Forest floor carbon is the pool of organic carbon (litter, duff, humus, and small woody
N-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
debris) above the mineral soil and includes woody fragments with diameters of up to 7.5 cm. Table N-l shows the
average forest floor carbon densities by forest type, as calculated by applying the equations to the 1997 data.
Step 1e: Estimate Carbon in Down Dead Wood
To estimate carbon in down dead wood, a procedure similar to estimating carbon in understory vegetation
was used. Down dead wood is defined as dead wood pieces not attached to trees, greater than 7.5 cm diameter,
including stumps and roots of harvested trees. Down dead wood was estimated in the projections by using decay
rates applied to logging residue, along with equations that estimate down dead wood not related to harvesting. The
ratio of down dead wood carbon to live tree carbon was calculated, and multiplied by 100 to display the ratio as a
percentage. The average percentage of down dead wood carbon as compared to live tree carbon was calculated by
region and forest type. The percent was multiplied by the live tree carbon data based on the dataset described in step
la to calculate down dead wood carbon. These percentages are given in Table N-2. This procedure was used
because detailed databases are not available for older data. By using average estimates, carbon estimates from
historical data are consistent with carbon estimates from current FIA data.
Step If: Estimate Forest Soil Carbon :
To estimate forest soil carbon, soil carbon estimates for 1 meter depth were obtained from the STATSGO
database (USDA 1991). A forest type coverage (Powell et al. 1993) was overlaid onto the soil carbon estimates
derived from STATSGO. An average soil carbon estimate was then calculated by forest type. Soil organic carbon
of both mineral soils and organic soils (histosol soil order, characterized as soils that develop in wetland areas, and
have greater than 20 to 30 percent organic matter by weight, depending on clay content) was included. Coarse roots
were included with tree carbon estimates rather than with soils. The soil carbon estimates are given in Table N-l.
These estimates were multiplied by the area of forest land in each forest type for all years. Thus, any change in soil
carbon is purely a reflection of the changing forest land base.
Step 1g: Calculate Net Carbon Stock Changes
The next step was to calculate the average annual net carbon stock change for each forest carbon pool for
the years from 1990 through 2000. The net annual stock change for each pool for 1987 through 1997 was derived
by subtracting the 1987 stock from the 1992 stock, and dividing by the number of years between estimates (10
years). The stocks, by definition, correspond to the stock as of January 1 of the given year. The net annual stock
changes for 1997 through 2000 were derived in the same way using the 1997 and 2001 stocks.
Step 2: Estimate Harvested Wood Carbon Fluxes
The first step in estimating harvested wood (i.e., wood products and landfilled wood) carbon flux estimates
was to compile historical data on: the production of lumber, plywood and veneer, pulp and other products; product
and log imports and exports; and fuel wood (in terms of million cubic feet of roundwood equivalent beginning in the
year 1900, as described in Skog and Nicholson 1998). Data were obtained from USDA (1964), Ulrich (1989), and
Howard (2001). Projected products and roundwood use were obtained from the models used for the USDA Forest
Service 2000 Resource Planning Act Assessment (Haynes et al. 2001b, Ince 1994). Roundwood products include
logs, bolts, and other round timber generated from harvesting trees for industrial or consumer use. The harvested
wood-to-carbon conversion factors (as listed in Skog and Nicholson 1998) were applied to annual estimates and
projections to produce an estimate for carbon in roundwood in products. Roundwood consumed was categorized
according to product, such as lumber, railroad ties, and paper, because the time carbon remains in those products
differs substantially. The dynamics of carbon loss through decay or through disposal of the product is summarized
as the half-life of each product (Skog and Nicholson 1998). The resulting estimates can be applied to products to
derive the net carbon change in wood products and landfills. Note that, unlike forest carbon stock estimates, carbon
in harvested wood products estimates are derived as a carbon stock change. In other words, the annual roundwood
production is a change variable already before it is converted to carbon.
N-5
-------
Step 3: Sum the Results from Step 1 and Step 2 for the Total Net Flux from U.S. Forests
In the final step, net changes in forest carbon stocks are added to net changes in harvested wood carbon
stocks, to obtain estimates of total net forest flux (see Table N-3).
Table N-3: Net Clh Flux from U.S. rarest Carbon sticks ngjClk En.)
Description
1990 1991 1992 1993
1994
1995
1996 1997
1998
1999
2000
Forests (773.7) (773.7) (773.7) (773.7) j
Trees (469.3) (469.3) (469.3) (469.3)
Understory (11.0) (11.0) (11.0) (11.0)
Forest Floor (25.7) (25.7) (25.7) (25.7);
Down Dead Wood (55.0) (55.0) (55.0) (55.0)
Forest Soils (212.7) (212.7) (212.7) (212.7);
Harvested Wood (209.0) (198.0) (202.8) (203.9)
Wood Products (47.7) (40.7) (46.6) (54.6)
LandfilledWood (161.3) (157.3) (156.2) (149.2)'
(773.7) (773.7) (773.7)Ȥ0,f
(469.3) (469.3) (469.3)M4?J)
(11.0) (11.0) (11.0)Rmt
(25.7) (25.7) (25.7)f>'j9
(55.0) (55.0) (55.0)|T-
(212.7) (212.7) (212.7)yjS;.
(210.5) (205.3) (205.3)11212.
(60.9) (55.0) (55.0)
(149.6) (150.3) (150.3)
Total
(982.7) (971.7) (976.4) (977.5) (984.1) (979.0) (979.0) (7S1.7)i
Note: Parentheses indicate net carbon "sequestration" (i.e., accumulation into the carbon pool minus emissions or stock removal from the
carbon pool). The sum of the net slock changes in this table (i.e., tolal net flux) is an estimate of the actual net flux between the total forest
carbon pool and the atmosphere. Lightly shaded areas indicate values based on a combination of historical data and projections. Forest
values are based on periodic measurements; harvested wood estimates are based on annual surveys. Totals may not sum due to independent
rounding. ;
The Forest Sector Modeling Projection System
The modeling projection system is a set of models that has been used for the USDA Forest Service,
Resource Planning Act Assessment since the late 1980;'s (see Figure N-l). The models include an area change
model (Alig 1985), a timber market model (TAMM; Adams and Haynes 1980), a pulp and paper model (NAPAP;
Ince 1994) and an inventory model (ATLAS; Mills and Kincaid 1992). Many of these models are econometric
models, designed to project the demand and supply and prices in the forest sector. Results of the projection include
timber volume, forest areas, harvests, and primary produbt production. To see all the assumptions and results of the
modeling system for 2001, see Haynes et al. (2001b). j
The FORCARB model (Plantinga and Birdsey J1993, Heath and Birdsey 1993, and Heath et al. 1996) uses
data on timber volume, forest areas, and harvests from the modeling system to estimate carbon in trees using
biometrical relationships between carbon and live tree volume. FORCARB estimates carbon in all other forest
ecosystem components, producing carbon density estimates similar to those in Table N-l and Table N-2. The model
WOODCARB (Skog and Nicholson 1998) uses harvested roundwood product statistics, along with end-use, decay
rate, and duration information to estimate carbon in harvested wood.
This figure illustrates the models, data inputs,[and data outputs that compose the forest sector modeling
projection system. Names of model authors are in parentheses in each model box to facilitate identification of
model citations. Data that are external to the models are [marked with double lines.
N-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Figure N-1: Forest Sector Modeling Projection System
Macro Economic
Data
(consumption &
production of wood products)
Historical
harvested
roundwood
statistics
Forest Inventory
Data
(1) private Timberlands
(2) estimated forest growth
parameters
AREA
MODELS
(Alig)
timberiand
area
annual forest growth
WOODCARB
(Skog)
Harvest,
production,
trade,
end use,
recycling
timber removals
ATLAS
(Mills)
estimates of
_ fuelwood
harvests
Data for private
Timberlands and
some Woodlands:
(1) area (acres)
(2) harvested area
and volume
(3) growing stock
inventory
and increment
Carbon stocks in
harvested wood
Carbon stocks in:
(1) public Timberlands
(2) Reserved Forest Land
(3) Other Forest Land
Carbon stocks
in private Timberlands
and some Woodlands
Harvest data estimated
exogenously to
TAMM/ATLAS (harvests
on public Timberlands
Reserved Forest Land,
and Other Forest Land)
Soils data from
(1) STATSGO database
(2) FIA ecosystem data
(3) Other ecosystem data
from the literature
-------
N-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX O
Methodology for Estimating CH4 Emissions from Landfills
Landfill methane (CH4) is produced from a complex process of waste decomposition and subsequent
fermentation under anaerobic conditions. The amount and rate of methane production depends upon the
characteristics of the landfilled material and the surrounding environment. To estimate the amount of methane
produced in a landfill in a given year, the following information is needed: the quantity of waste in the landfill, the
landfill characteristics, the residence time of the waste in the landfill, and the landfill capacity.
The amount of methane emitted from a landfill is less than the amount generated. If no measures are taken
to extract the methane, a portion of it will oxidize as it travels through the top layer of the landfill cover. The
portion of the methane that oxidizes turns primarily to carbon dioxide (CO2). If the methane is; extracted and
combusted (e.g., flared or used for energy), then that portion of the methane produced in the landfill will not be
emitted as methane, but again, would be oxidized to CO2. In general, landfill-related CO2 emissions are of biogenic
origin and primarily result from the decomposition, either aerobic or anaerobic, of organic matter such as food or
yard wastes.1
Methane emissions are primarily driven by the quantity of waste in landfills. From an analysis of the
population of municipal solid waste (MSW) landfills, landfill-specific data were extracted and used in an emissions
model to estimate the amount of methane produced by municipal solid waste. Although not explicitly modeled,
methane emissions from industrial landfills were assumed to be seven percent of the total methane generated from
MSW at landfills. Total methane emissions were estimated by adding the methane from MSW landfills, subtracting
the amount recovered or used for energy or flared, subtracting the amount oxidized in the soil, and adding emissions
from industrial landfills. The steps taken to estimate emissions from U.S. landfills for the years 1990 through 2000
are discussed in greater detail below.
Step 1: Estimate Municipal Solid Waste-in-PIace Contributing to Methane Emissions
First, landfills were characterized as of 1990 based on a landfill survey (EPA 1988). Each landfill was
characterized in terms of its year of opening, waste acceptance during operation, year of closure, and design
capacity. Following characterization of the landfill population, waste was simulated to be placed in these landfills.
For 1990 through 2000, waste disposal estimates were based on annual BioCycle (2001) data. Landfills were
simulated to open and close based on waste disposal rates. If landfills reached thek design capacity, they were
simulated to close. New landfills were simulated to open when a significant shortfall in disposal capacity was
predicted. Simulated new landfills were assumed to be larger, on average, reflecting the trend toward fewer and
more centralized facilities. The analysis updated the landfill characteristics each year, calculating the total waste-in-
place and the profile of waste disposal over time. Table O-l shows the amount of waste landfilled each year and the
total estimated waste-in-place contributing to methane emissions.
Step 2: Estimate Landfill Methane Production
Emissions for each landfill were estimated by applying the emissions model (EPA 1993) to the landfill
waste-in-place contributing to methane production. The model estimates that landfilled waste generates methane for
30 years after disposal. Total emissions were then calculated as the sum of emissions from all landfills, open and
closed. .
Step 3: Estimate Industrial Landfill Methane Production
Industrial landfills receive waste from factories, processing plants, and other manufacturing activities.
Because no data were available on methane generation at industrial landfills, emissions from industrial landfills
were assumed to equal seven percent of the total methane emitted from MSW landfills (EPA 1993). The EPA
[ Emissions and sinks of biogenic carbon are accounted for in the Land-Use Change and Forestry chapter.
0-1
-------
landfill survey contained estimates of industrial waste (EPA 1988). The organic content of industrial waste
represents seven percent of the methane producing capacity of MSW. These emissions are shown in Table O-2.
Step 4: Estimate Methane Emissions Avoided
The estimate of methane emissions avoided was;based on landfill-specific data on flares and landfill gas-to-
energy (LFGTE) projects.
Step 4a: Estimate Methane Emissions Avoided through Flaring
The quantity of methane flared was based on data collected from flaring equipment vendors, including
information on the quantity of flares, landfill gas flow fates, and year of installation. To avoid double counting,
flares associated with landfills that had an LFGTE project were excluded from the flaring analysis. Total methane
recovered was estimated by summing the median landfill gas flow rate for each remaining flare. However, several
vendors provided information on the size of the flare rather than the landfill gas flow rate. To estimate a median
flare rate for flares associated with these vendors, the size of the flare was matched with the size and corresponding
flow rate provided by the other vendors. ;
Step 4b: Estimate Methane Emissions Avoided through Landfill gas-to-energy (LFGTE) projects
The quantity of methane avoided due to LFGTE systems was estimated based on information in a database
compiled by EPA's Landfill Methane Outreach Program (LMOP). Using data on landfill gas flow and energy
generation, the total direct methane emissions avoided were estimated.
To avoid double counting flares associated with LFGTE projects, the flare estimates were adjusted to
account for LFGTE projects for which an associated flareicould not be identified.
Step 5: Estimate Methane Oxidation j
As discussed above, a portion of the methane escaping from a landfill through its cover oxidizes in the top
layer of the soil. The amount of oxidation that occurs is uncertain and depends upon the characteristics of the soil
and the environment. For purposes of this analysis, it wa& assumed that ten percent of the methane produced, minus
the amount of gas recovered for flaring or LFGTE projects, was oxidized in the soil (Liptay et al. 1998).
Step 6: Estimate Total Methane Emissions
Total methane emissions were calculated by adding emissions from MSW and industrial waste, and
subtracting methane recovered and oxidized, as shown in Table O-2.
Takle 0-1: Municipal Solid Waste (MSW1 Contributing ti Methane Emissions (Ta unless athenwise noted)
Description
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000
Total MSW Generated3 266 255 265 278 293 296 297 309 340 347 371
Percent of MSW Landfilled" 77% 76% 72% 71% 67% 63% 62% 61% 61% 60% 61%
Total MSW Lartdlilled 205 194 191 198 196 187 184 188 207 208 226
MSW Contributing to Emissions" 4,926 5.027 5,162 , 5,292 5,428 5,559 5,676 5,790 5,906 6,035 6,147
a Source: BioCycle (2001). The data, originally reported in short tons, are converted to metric tons.
b The emissions model (EPA 1993) defines all waste that has been in p)ace for less than 30 years as contributing to methane emissions.
0-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table (1-2: Methane Emissions from Landfills (Gg)
Activity
MSW Generation
Large Landfills
Medium Landfills
Small Landfills
Industrial Generation
Potential Emissions
Emissions Avoided
Landfill Gas-to-Energy
Flare
Oxidation
Net Emissions
1990
11,599
4,780
5,545
1,273
731
12,330
(1,119)
(692)
(427)
(1,048)
10,162
1991
11,837
4,817
5,720
1,300
746
12,582
(1,387)
(728)
(659)
(1,045)
10,150
1992
12,168
4,883
5,954
1,332
767
12,935
(1,601)
(784)
(817)
(1,057)
10,277
1993
12,499
4,950
6,190
1,359
787
13,286
(1,848)
(855)
(994)
(1,065)
10,373
1994
12,847
5,038
6,424
1,385
809
13,657
(2,225)
(977)
(1,248)
(1,062)
10,370
1995
13,218
5,129
6,682
1,407
833
14,051
(2,682)
(1,017)
(1,665)
(1,054)
10,315
Note: Totals may not sum due to independent rounding.
Note: MSW generation in Table 0-2 represents emissions before oxidation. In other tables
account for oxidation.
1996
13,490
5,199
6,868
1,423
850
14,340
(3,244)
(1,171)
(2,073)
(1,025)
10,072
throughout
1997
13,774
5,280
7,057
1,438
868
14,642
(3,820)
(1,415)
(2,405)
(995)
9,827
the text,
1998
14,015
5,351
7,211
1,453
883
14,898
(4,362)
(1,729)
(2,633)
(965)
9,571i
1999
14,348
5,453
7,424
1,471
904
15,252
(4,607)
(1,984)
(2,623)
(974)
9,671
2000
14,617
5,520
7,614
1,483
921
15,538
(4,874)
(2,196)
(2,678)
(974)
9,690
MSW generation estimates
0-3
-------
0-4 inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX P
Key Source Analysis
This Annex provides an analysis of key sources of emissions found in this report in keeping with the
IPCC's Good Practice Guidance (IPCC 2000). In order to ensure accuracy and reliability of inventory estimates,
quality assurance and quality control (QA/QC) resources and activities should be directed to the key source
categories in a given country's greenhouse gas emissions inventory. A key source category is defined as a "[source
category] that is prioritized within the national inventory system because its estimate has a significant influence on a
country's total inventory of direct greenhouse gases in terms of the absolute level of emissions, the trend in
emissions, or both."1 By definition, key source categories are sources that have the greatest contribution to the
absolute overall level of national emissions. In addition, when an entire time series of emission estimates is
prepared, a thorough investigation of key source categories must also include accounting for the influence of trends
of individual source categories. Therefore, a trend assessment is also conducted based on an attempt to identify
source categories for which significant uncertainty in the estimate would have considerable effects on overall
emission trends. This analysis culls out source categories that diverge from the overall trend in national emissions.
Finally, a qualitative evaluation of key source categories should be performed, in order to capture any key source
categories that were not identified in either of the quantitative analyses.
The methodology for conducting a key source analysis, as defined by IPCC's Good Practice Guidance
(IPCC 2000), includes:
• Tier 1 approach (including both level and trend assessments);
• Tier 2 approach (including both level and trend assessments, and incorporating uncertainty analysis);
and
• Qualitative approach.
Following this introduction, the Annex will present and analyze key source categories; discuss Tier 1, Tier
2, and qualitative approaches to identifying key sources; provide level and trend assessment equations; and provide a
brief statistical evaluation of IPCG's quantitative methodologies for defining key sources.
Table P-l presents the key source categories for the United States using emissions data in this report, and
ranked according to their sector and global warming potential-weighted emissions in 2000. The table also identifies
the criteria used in identifying these source categories (i.e., level, trend, and/or qualitative assessments).
1 See chapter 7 "Methodological Choice and Recalculation" in IPCC (2000).
P-1
-------
Table P-1: Key Source Categories fir the United States [1990-20001 Based on Tier 1 Approach
IPCC Source Categories
Energy
COz Emissions from Stationary Combustion - Coal
COz Emissions from Stationary Combustion - Oil
Mobile Combustion: Road & Other
COz Emissions from Stationary Combustion - Gas
Mobile Combustion: Aviation
Fugitive Emissions from Oil & Gas Operations
Mobile Combustion: Marine
Fugitive Emissions from Coal Mining & Handling
Mobile Combustion: Road & Other
Indirect COz Emissions from CH4 Oxidation
International Bunker Fuels'"
Non-Energy Use of Fossil Fuelsb
Industrial Processes
COz Emissions from Other Industrial Processes
Emissions from Substitutes for Ozone Depleting Substances
COz Emissions from Cement Production
HFC-23 Emissions from HCFC-22 Manufacture
SFs Emissions from Electrical Equipment
PFC Emissions from Aluminum Production
NzO Emissions from Adipic Acid Production
PFC, HFC, and SFs Emissions from Semiconductor Manufacturing
Agriculture
Direct NzO Emissions from Agricultural Soils
CH4 Emissions from Enteric Fermentation in Domestic Livestock
Indirect NzO Emissions from Nitrogen Used in Agriculture
CH< Emissions from Manure Management
Waste
CH4 Emissions from Solid Waste Disposal Sites
COz Emissions from Waste Incineration
Subtotal
Total
Percent of Total
" Qualitative criteria.
b Emissions from these sources not included in totals.
Gas
COz
COz
COz
COz
COz
CH4
COz
CH4
N20
COz
Several
COz
COz
Several
COz
HFCs
SFs
PFCs
NzO
Several
NzO
CH4
N20
CH4
CH4
C02
Notes: Sinks (e.g., LUCF, Landfill Carbon Storage) are not included in this analysis. The Tier 1
Criteria 2000 Emissions
Level Trend Qual." (TgC02Eq.)
^ S C,T,Q 2,030.1
^ ' 640.7
^ ^ 1,503.2
^ S 1,162.9
' 196.5
S ^ 138.2
S S 89.9
^ S 61.0
^ 55.7
• 26.3
S 101.2
^ 409.6
^ S 107.6
^ v' 57.8
^ 41.1
^ S 29.8
V S 14.4
S 7.9
S S ' 8.1
S 7.4
^ 217.8
S S 123.9
S 79.8
S S 37.5
^ S 203.5
^ 22.5
6,843.4
7,001.2
98.0%
approach for identifying key source categories
does not directly include assessment of uncertainty in emissions estimates.
Table P-2 provides a complete listing of source categories by IPCC sector and with additional comments on
the criteria used in identifying key source categories. Specifically, the level assessment was performed for each year
that inventory data was available (i.e., 1990 to 2000). As; the emissions change over time, categories may fall under
or over the threshold for being key. The following points [should be noted regarding the key sources identified.
Due to the relative quantity of CO2 emissions from fossil fuel combustion—particularly from mobile source
and stationary combustion of coal, gas, and oil—these sources contributed most to each year's level assessment.
Additionally, the following sources were the largest contributors to the level assessments for each year (listed in
descending order): '
•> CH4 from solid waste disposal sites; I
• N2
-------
• Fugitive emissions from coal mining; and
• N2O emissions from mobile road source emissions.
The remaining key sources identified under the level assessment varied by year. The following four source
categories were determined to be key using the level assessment for only part of the complete times series:
• CO2 emissions from cement production (1991, 1993 to 1996); ;
• HFC and PFC emissions from substitutes for ozone depleting substances (1997 to 2000);
• HFC-23 emissions from HCFC-22 manufacture (1990, 1992, 1996,1998); and :
• CH4 emissions from manure management (1995). '
Although other sources have fluctuated by greater percentages since 1990, by virtue of their size, CO2
emissions from stationary combustion of coal, gas, and oil, and from mobile combustion from road vehicles are the
greatest contributors to the overall trend for 2000.
Another large contributor to the overall trend is emissions of substitutes for ozone depleting substances,
which are growing quickly with the Montreal Protocol phase-out of ozone depleting substances. Fugitive emissions
from coal mining and PFC emissions from aluminum manufacturing have decreased by approximately 30 and 56
percent, respectively from 1990 through 2000.
Six other source categories were determined to be key using the qualitative criteria. A brief discussion of
the reasoning for the qualitative designation is given below:
• International bunker fuels are fuels consumed for aviation or marine international transport activities,
and emissions from these fuels are reported separately from totals in accordance with IPCC guidelines.
If these emissions were included in the totals, bunker fuels would qualify as a key source according to
the Tier 1 approach. The amount of uncertainty associated with estimation of emissions from
international bunker fuels also supports the qualification of this source category as key.
• Non-energy uses of fossil fuels represent a significant percentage of the total carbon inventory, and the
idea that small changes in storage factors for these non-energy uses may result in large changes in
storage and emissions qualifies this source category as key. ,
• Nitrous oxide emissions from adipic acid plants have been dramatically reduced due to the installation
of emission control technologies on 3 of the 4 production facilities in the United States. These changes
in addition to the uncertainty in this emission source category suggest that it should be treated as key,
although it has also been identified using the trend assessment.
• Estimates of SF6 emissions from electrical equipment have been made using only a limited amount of
data; therefore, there is a significant degree of uncertainty associated with them. Although future
inventories are expected to incorporate improvements, the current lack of data and small margin under
which the category missed both the trend and level assessment thresholds suggests that it should be
treated as key.
• Emissions of HFCs, PFCs and SF6 from semiconductor manufacturing have increased significantly
from 1990 through 1999, almost tripling in size. This source category's potential future growth—in
addition to historical growth that has already led to list listing as key using the trend
assessment—suggests that it should be treated as key. I
• Estimated CH4 emissions from manure management have been significantly revised relative to the
previous greenhouse gas inventory. This revision is due to both changes in the estimation
methodology and data sources. The reduction in estimated emissions for the entire time 'series have by
approximately 50 to 60 percent, suggests that it should be treated as key, although it has also been
identified using the trend assessment. ;
Following the text of this Annex, Table P-3 through Table P-13 contain each individual year's level
assessment and contain further detail on where each source falls within the analysis. Table P-14 details the trend
assessment for 1990 through 2000. :
P-3
-------
Table P-2: U.S Greenhause Gas Inuentary Source Categories Based an Tier 1 Approach
i 2000 Key Source
Direct Emissions Category
IPCC Source Cateqories GHG (TgCOzEq.) Flaq? Criteria3 Comments
Energy
COz Emissions from Stationary Combustion - Coal COz
COz Emissions from Stationary Combustion - Oil COz
COz Emissions from Stationary Combustion - Gas COz
COz Emissions from Stationary Combustion - Geothermal COz
COz Emissions from Natural Gas Flaring COz
Non-COz Emissions from Stationary Combustion CH4
Non-COz Emissions from Stationary Combustion NzO
Mobile Combustion: Road & Other COz
Mobile Combustion: Road & Other CH4
Mobile Combustion: Road & Other NzO
Mobile Combustion: Aviation COz
Mobile Combustion: Aviation CH4
Mobile Combustion: Aviation NzO
Mobile Combustion: Marine COz
Mobile Combustion: Marine CH4
Mobile Combustion: Marine NzO
Fugitive Emissions from Coal Mining & Handling CH4
Fugitive Emissions from Oil & Gas Operations CH4
Indirect COz Emissions from CH4 Oxidation COz
2,030.1
640.7
1,162.9
+
6.1
7.5
14.9
1,503.2
4.1
55.7
196.5
0.2
1.9
89.9
0.1
0.6
61.0 v
138.2
26.3
International Bunker Fuels'1 Several 101.2 »
Non-Energy Use of Fossil Fuels'" COz
Industrial Processes
COz Emissions from Cement Production COz
COz Emissions from Lime Production COz
COz Emissions from Other Industrial Processes COz
CH4 Emissions from Other Industrial Processes CH4
NzO Emissions from Adipic Acid Production NzO
NzO Emissions from Nitric Acid Production NzO
409.6
41.1 v
13.3
107.6
1.7
8.1
19.8
PFC Emissions from Aluminum Production PFCs 7.9 »
SFe Emissions from Magnesium Production SFs
SFs Emissions from Electrical Equipment SFe
4.0
14.4
HFC, PFC, and SFe Emissions from Semiconductor Mfg. Several 7.4 »
Emissions from Substitutes for Ozone Depleting Substances Several 57.8 »
HFC-23 Emissions from HCFC-22 Manufacture HFCs 29.8
Agriculture
CH4 Emissions from Enteric Fermentation in Domestic Livestock CH4
CH4 Emissions from Manure Management CH4
NzO Emissions from Manure Management NzO
Direct NzO Emissions from Agricultural Soils NzO
Indirect NzO Emissions from Nitrogen Used in Agriculture NzO
CH4 Emissions from Rice Production CH4
CH4 Emissions from Agricultural Residue Burning CH4
NzO Emissions from Agricultural Residue Burning NzO
Waste
CH4 Emissions from Solid Waste Disposal Sites CH4
CH< Emissions from Wastewater Handling CH4
NzO Emissions from Wastewater Handling NzO
COz Emissions from Waste Incineration COz
NzO Emissions from Waste Incineration NzO
123.9
37.5
17.5
217.8
79.8
7.5
0.8
0.5
203.5
28.7
8.5
22.5
0.2
' L,T
' L,T
' L,T
' L,T
' L
' L
' L,T
' L,T
' L,T
' T
' Q
' Q
' L
' L,T
' T,Q
' T
' T,Q
' Q
' L,T
' L,T
' L,T
' L,Q
' L
' L
' L,T
' T
All years
All years
All years
All years
- All years
All years
All years
All years
All years
Level in 1991, 1993- 1997
All years
Level from 1997 -2000
Level in 1990, 1992,
1996, 1998
AH years
Level in 1995
All years
All years
All years
+ Does not exceed 0.05 Tg COz Eq.
• Qualitative criteria. i
b Emissions from these sources not included in totals.
Notes: Sinks (e.g., LUCF, Landfill Carbon Storage) are not included in this analysis. The Tier 1 approach for identifying key source categories
does not directly include assessment of uncertainty in emissions estimates.
P-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks; 1990-2000
-------
Tier 1 Approach
The Tier 1 method for identifying key source categories assesses the impacts of all IPCC-defmed source
categories on the level and trend of the national emission inventory for the 1990 through 2000 time-series, but works
independently of any formal uncertainty analysis. However, it is important to mention that although conducting a
key source analysis can be very valuable in improving the U.S. inventory, it would be ideal to undertake a full
uncertainty analysis in order to accurately identify all key sources and to be able to take into account the level of
uncertainty associated with each estimate.
When using a Tier 1 approach for the level, a pre-determined cumulative emissions threshold is used to
identify key source categories. When source categories are sorted in order of decreasing emissions, those that fall at
the top of the list and cumulatively account for 95 percent of emissions are considered key source categories. The
95 percent threshold was established based on an evaluation of several inventories, and was designed to establish a
general level where the key source category analysis covers 90 percent of inventory uncertainty. The Tier 1
approach for the trend uses a 95 percent contribution threshold of the cumulative contribution to the trend
assessment metric, which was also designed to establish a general level where the key source category analysis
covers 90 percent of inventory uncertainty. The Tier 1 method is completed using a simple spreadsheet analysis
based on equations for both level and trend assessments that are described in detail below. It is the current approach
that the United States is taking to identify key source categories of greenhouse gas emissions until a rigorous
uncertainty analysis is completed.
Level and Trend Assessments of Key Source Categories
Level Assessment
A level assessment was performed for years 1990 to 2000. Key sources were identified as any source
category which, when summed in descending order of magnitude for a given year, cumulatively add up to 95
percent of the total level assessment for that year. Level estimates are based upon the following equation:
Source Category Level Assessment = Source Category / Total Estimate
Where,
i
Lx,t = level assessment for source x in year t
EXjt = emissions estimate for source x in year t ;
Et = total emissions estimate for year t
j
Trend Assessment
A trend assessment was then conducted to evaluate how significantly the difference between the source
category's trend and the overall inventory trend affect the overall trend. This assessment was done by multiplying
the difference between the source category trend and the total inventory trend by the source category level
assessment. Trend assessments were based upon the following equation:
Source Category Trend Assessment = (Source Category Level Assessment) x
I (Source Category Trend - Total Trend) i
TXlt= Lx,,x I [((Ex,t- Ex,0) / Ex,t) - ((Et - E0) / E,)]
Where,
Tx?t = trend assessment for source x in year t"
P-5
-------
L,,! = level assessment for source x in year t
EX)t and E^o = emissions estimates for source x in year t and year 0, respectively
Et and E0= total emissions estimate for year t and year 0, respectively
0 = base year (e.g., 1990)
The following section of this annex evaluates these key source category analyses. The remainder of the
annex summarizes the key source categories identified by these analyses, and quantifies their contribution to total
level and trend assessments. :
Tier 2 Approach I
IPCC recommends that inventory agencies use the Tier 2 method for identifying key source categories if
nationally derived source-level uncertainties are measured. The Tier 2 approach is a more detailed analysis that
builds on the Tier 1 approach by multiplying the results ;of the Tier 1 analysis by the relative uncertainty of each
source category. This method is likely to reduce the nurtiber of key source categories under consideration. Using
the Tier 2 approach, key source categories represent 90 percent of the quantified uncertainty contribution, as
opposed to those that sum to the pre-determined cumulative emissions or trend threshold. A simple spreadsheet
version accounts for the uncertainty contribution by applying the source category percentage uncertainty estimates
to the Tier 1 level and trend assessments. [
A detailed, more complete assessment of uncertainty uses Monte Carlo uncertainty modeling. The U.S.
EPA is currently working on preparing such an analysis using procedures for gathering necessary data inputs and
estimating uncertainty using a Monte Carlo model developed with @Risk® software. The project, which is in the
initial phase of developing the uncertainty model, has; as its goal developing a simulation model to estimate
uncertainty for all source categories of the U.S. Inventory, and in total. The Monte Carlo model develops estimates
of uncertainty for inventory source categories based on (a) mathematical models used to estimate emissions for each
source category; (b) source category specific input parameters and emission estimates; and (c) the statistical
properties underlying the input parameters and estimates, j
Qualitative Approach
In addition to conducting a quantitative assessment like the ones described above, a variety of qualitative
criteria could be applied to identify additional key squrce categories. The following qualitative criteria for
identifying key source categories have been outlined in the Good Practice Guidance (IPCC 2000). A source
category should be identified as a key source if: j
• Mitigation techniques and technologies are being implemented to reduce emissions from the source
category that are expected to be reflected in the inventory estimates;
• Significant changes in emissions (i.e., growth or decline) from the source category is expected in the
future;
• High uncertainty is evident for the source category;
• Unexpectedly low or high emissions, or other order of magnitude discrepancies, are apparent for the
source category; and
• Major changes in estimation methodology or data have occurred.
In many cases, the results of this qualitative approach to identifying key source categories will overlap with
source categories already defined as key source categories through the quantitative analysis. However, the
qualitative method may illuminate a few additional key source categories, which should then be included in the final
list of key source categories. The application of such qualitative criteria are primarily intended to identify any
additional source categories that were "just under" the threshold criteria for the level assessment and not for
extremely minor source categories.
Six source categories are also considered key from a qualitative standpoint, these include:
e International Bunker Fuels, |
P-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
• Non-Energy Use of Fossil Fuels, ;
• N2O from adipic acid production,
• SF6 from electrical equipment,
• HFCs, PFCs, and SF« from semiconductor manufacturing, and ',
• CEU from manure management.
Of these sources, N2O from adipic acid production, SF6 from electrical equipment, and CELt from manure
management are also considered key sources in either the level or the trend assessments. Semiconductor
manufacture is not considered a key source in either the level or the trend assessments, but the rapid growth rate of
this industry identifies it as a qualitative key. Both international bunker fuels and non-fuel use of fossil fuels are
considered unique in that they are not included as a part of the inventory totals. Therefore they require additional
explanation in this analysis. International bunker fuel emissions are not included in national totals, and are not
considered in the level or trend analyses mentioned above, but are considered key from a qualitative standpoint due
to their unique position within the emissions accounting framework. Additionally, non-fuel use of fossil fuels is also
not included in the level or trend analyses. However, due to the significant quantity of fossil fuels consumed in the
United States that are not used to produce energy (generically referred to as feedstocks), it is imperative to
understand their fate and to determine how much of the consumption results in emissions, versus in stored carbon.
International Bunker Fuels
International bunker fuels are fuels consumed for aviation or marine international transport activities, and
emissions from these fuels are reported separately from totals in accordance with IPCC guidelines. If these
emissions were included in the totals, bunker fuels would qualify as a key source according to the Tier 1 approach,
as emissions for 2000 are estimated at 101.2 Tg CO2 Eq. An additional reason to treat bunker fuels as a key source
lies in the amount of uncertainty in these emission estimates. Difficulties in collecting this data and the use of
varying definitions of bunker fuels are a few of the uncertainties that could have a significant effect on total
emission trends.
Non-Energy Use of Fossil Fuel
Fossil fuel feedstocks including naphthas, liquefied petroleum gases, and natural gas are used in the
manufacture of a wide variety of man-made chemicals and products, in addition to their use as fuels. Non-fuel
feedstock uses of fossil fuels include manufacture of plastics, rubber, synthetic fibers, solvents, paints, fertilizers,
Pharmaceuticals, and food additives. Subsequent use or disposal of these products may result in either carbon
storage or carbon emissions. Industrial coking coal, petroleum coke, distillate and residual fuel oils, and other fossil
fuels .are also used for non-energy uses. Because non-fuel uses of these fuel types are diverse, the carbon storage
and carbon emissions from these non-fuel uses are difficult to characterize. ;
Non-energy uses of fossil fuels represent a significant percentage of the total carbon inventory. Potential
emissions of carbon from non-energy use increased from 319.9 Tg CO2 Eq. (87.25 Tg C) in 1990 to 409.6 Tg CO2
Eq. (111.70 Tg C) in 2000, an increase of 28 percent. In the same time frame, carbon stored in products from non-
energy use increased from 221.0 Tg CO2 Eq. (60.26 Tg C) to 283.2 Tg CO2 Eq. (77.23 Tg C), an increase of 28
percent. Small changes in storage factors for these non-energy uses may result in large changes in storage and
emissions. Therefore, non-energy use of fossil fuels is considered to be a key source from a qualitative standpoint.
Evaluation of Key Source Identification Methodologies
Level Assessment
The Tier 1 approach for level assessment defines the source category contribution as the percentage of total
inventory emissions from that source category. Only emission source categories are considered.2 To determine key
source categories, the level assessments are sorted in decreasing order, so that the source categories with the highest
2 The level assessment is intended to be applied to sources and to exclude sinks. Although the assessment would still
be valid if sinks were included (as unsigned values), the 95 percent threshold by which sources are deemed "key" would lose
significance because it is based on an analysis (Flusgrud et al. 1999) of selected inventories where sinks were excluded.
P-7
-------
level assessments appear first. The level assessments are summed until the threshold of 95 percent is reached; all
source categories that fall within that cumulative 95 percent are considered key source categories.
Since the Tier 1 approach does not explicitly incorporate uncertainties, the level assessment key source
categories will be the largest contributors to total emissions but will not necessarily have large contributions to the
total uncertainty. Focusing resources on improving the methodologies for estimating emissions from the source
categories with the largest emissions is undesirable if those emissions are estimated relatively precisely using the
current methodologies. Nevertheless, the analysis (reported in IPCC 2000) of several inventories that have source
category uncertainties showed that about 90 percent of the total uncertainty could be covered by the source
categories in the top 95 percent of emissions. '
It is important to note that this key source category analysis can be very sensitive to the definitions of the
source categories. If a large source category is split into many subcategories, then the subcategories may have
contributions to the total inventory that are too small for those source categories to be considered key. Similarly, a
collection of small, non-key source categories adding up to less than 5 percent of total emissions could become key
source categories if those source categories were aggregated into a single source category. A consistent approach to
addressing this issue is available in the Good Practice Guidance. Table 7.1 in IPCC (2000) provides guidance and a
suggested list of source categories for analysis, although countries are given some discretion based upon their
national circumstances. [
Some important components of other source categories were not included in the list of IPCC source
categories in the key source category chapter of IPCC's Good Practice Guidance (IPCC 2000). These source
categories include fossil fuel feedstocks, international bunkers, and emissions from territories. They are potentially
large source categories that often are derived from unique data sources, have a significant impact on the uncertainty
of the estimates, and therefore ought to be considered as potential key source categories.
i
Trend Assessment
The Tier 1 approach for trend assessment is defined as the product of the source category level assessment
(i.e., source category emissions as a fraction, or percentage, of total emissions) and the absolute difference between
the source category trend and the total trend. In turn, the source category trend is defined as the change in source
category emissions from the base year to the current year, as a percentage of current year emissions from that source
category. The total trend is the percentage change in total inventory emissions from the base year to the current
year. Thus, the source category trend assessment will be large if the source category represents a large percentage
of emissions and/or has a trend that is quite different!from the overall inventory trend. Only emissions source
categories are considered.3 To determine key source 'categories, the trend assessments are sorted in decreasing
order, so that the source categories with the highest trend assessments appear first. The trend assessments are
summed until the threshold of 95 percent is reached; all source categories that fall within that cumulative 95 percent
are considered key source categories. ,
It is important to note that the trend assessment calculation assumes that the base and current year source
category emission uncertainties are the same. Therefore, the trend assessment is a useful measure in cases where the
percentage uncertainties of the base and current year source category emission levels are thought to be the same.
However, its usefulness diminishes when individual source category uncertainties are different between the base
year and the current year. Such time series inconsistencies could result from changes in data quality or availability
over time. As more rigorous methods to determine uncertainties in emission estimates are applied, it may be
necessary to revisit the results of the trend assessments.
Another important caveat to the identification of key source categories through the trend assessment is that,
while each individual source category's trend assessment provides a measure of how sensitive the overall trend in
the inventory is to the trend of a particular source category, the sum of a number of trend assessments does not yield
the total sensitivity of the overall trend to changes in all of those source categories. In other words, the cumulative
percentages should not be considered a measure of the percentage contributions to the trend from those source
categories.
3 The trend assessment is intended to be applied to sources and to exclude sinks. Although the assessment would still
be valid if sinks were included (as unsigned values), the 95 percent threshold by which sources are deemed "key" would lose
significance because it is based on an analysis (Flusgrud et al. 1999) of selected inventories where sinks were excluded.
P-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
The trend assessment key source categories are also sensitive to the level of aggregation of the source
categories; and the IPCC list of source categories may exclude some important, potentially key source category
components.
References
Flugsrud, K., W. Irving, and K. Rypdal (1999) Methodological Choice in Inventory Preparation. Suggestions for
Good Practice Guidance. Statistics Norway Department of Economic Statistics. 1999/19.
IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories,
Intergovernmental Panel on Climate Change, National Greenhouse Gas Inventories Programme. '
P-9
-------
Table P-3:1990 Key Source Tier 1 Analysis - Level Assessment
1PCC Source Categories
COj-Emfssfons from Stationary Cprnbustiw^^Cpa^
Cj^^Emissions'from Stationary Combustion • Gas
IS^^i^ns^m^olyWastelW^saTSi&^'J^J^^-^
{freei NzOfemissFonl from^griculturaf Soffs """ *"" ™"~~™"^
MKfsCoqibustion. Aviation t „, ^ I „-»'
ijgtfve Emissions from Oil & Gas Operations
ikfiifeijii^^
^JiErjHslohsTS
•ujft Erp"5Sps"fprn'pg]|l Mining aj5d_Hingl!ng"
ssJlf^JliftSis'(ins' w°si»^k0s?2iisM'lifisr'cl££e ,
SifeJqqblslokkMd ^Olier"^'" "u "*"!*»
^^Jp'ssi^sfromHCFC^lanufacture^ "" *"_"*
COz Emissions from Cement Production
SFs Emissions from Electrical Equipment
Indirect COz Emissions from CH4 Oxidation
CH4 Emissions from Manure Management
CH4 Emissions from Wastewater Handling
PFC Emissions from Aluminum Production
NzO Emissions from Nitric Acid Production
NzO Emissions from Manure Management
Non-COz Emissions from Stationary Combustion
NzO Emissions from Adipic Acid Production
COz Emissions from Waste Incineration
COz Emissions from Lime Production
Non-COz Emissions from Stationary Combustion
CH4 Emissions from Rice Production
NzO Emissions from Wastewater Handling
SFs Emissions from Magnesium Production
COz Emissions from Natural Gas Flaring
Mobile Combustion: Road & Other
Direct Base Year
Greenhouse Estimate
Gas (Tq COz Eq.)
cor'
COz '
CQ2
CH41
T\b6 ~ *
*CH!
W
CH47
COz"
NzO
HFCs"
COz'
SFs
COz
CH4
CH4
PFCs
NzO
NzO
NzO
NzO
COz;
COzl
CH4
CH4|
NzO
SFe !
COz
CH4;
1,23549,"*
^ ,952.76
^^^662,46 (
"*> 193?4"9 *
""" ' 176,88 "
* "* __ 147,64 Jt
«^ ' "" "*"** 123".65~^
** ' 8?rt2
- 73.60 *•
" » 59513 ^
"" 48.86 ~
„ k """, ;34.98 „
33.28
31.23
30.90
29.19
24.25
18.11
17.85
16.03
12.82
14.89
14.09
11.24
7.90
7.12
7.04
5.50
5.51
4.67
Current Year
Estimate
(Tq COz Eq.)
"^ 1 {23M9
' - ~l13!41
<- 19314*
* "j47i64
127.8$
-'" " 123*65
s, " "87,f2!
73.60
- :• " 59,43
38.86
33.28
31.23
30.90
29.19
24.25
18.11
17.85
16.03
12.82
14.89
14.09
11.24
7.90
7.12
7.04
5.50
5.51
4.67
Level Cumulative
Assessment Total
*•*. 6M
* °'03^r. -
s , t. _^__
0,03
*^O.OZ
" j).02 ^ ^
jO.Qll*^'**
«~' ^ ^ >fl01 '
* 0,01
: " O.flt
" "0,01 * "
0.01
0.01
0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
'0,48
' 0,6l
0,74
' o.m
_ _^j
0,84
0,88
, 0,90
0J^
0.93
- OJI
km
0.96
0.96
0.97
0.97
0.98
0.98
0.98
0.98
0.99
0.99
0.99
0.99
0.99
0.99
1.00
1.00
1.00
1.00
PFC, HFC, and SFs Emissions from Semiconductor ;
Manufacturing
Mobile Combustion: Aviation
CH4 Emissions from Other Industrial Processes
Emissions from Substitutes for Ozone Depleting Substances
CH4 Emissions from Agricultural Residue Burning
NzO Emissions from Agricultural Residue Burning
Mobile Combustion: Marine
NzO Emissions from Waste Incineration
COz Emissions from Stationary Combustion - Geothermal Energy
Mobile Combustion: Aviation
Mobile Combustion: Marine
TOTAL
SFe
NzO
CH4
Several
CH4
NzO
NzO
NzO
co2;
CH4
CH4i
2.86
1.71
1.19
0.94
0.68
0.37
0.36
0.29
0.22
0.16
0.07
6,130.72
2.86
1.71
1.19
0.94
0.68
0.37
0.36
0.29
0.22
0.16
0.07
6,130.72
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
Note: Sinks (e.g., LUCF, Landfill Carbon Storage) are not included in this analysis.
P-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table P-4:1991 Key Source Tier 1 Analysis - Level Assessment
IPCC Source Categories
Direct Base Year Current Year
Greenhouse Estimate (Tg COz Estimate
Gas Eg.)
Level Cumulative
Assessment
Total
Se&
rfcul
""JMr
tm^. __ ;-i«ifck
" ~
SFe Emissions from Electrical Equipment
HFC-23 Emissions from HCFC-22 Manufacture
Indirect COz Emissions from CH4 Oxidation
CH4 Emissions from Manure Management
CH4 Emissions from Wastewater Handling
NzO Emissions from Nitric Acid Production
NzO Emissions from Manure Management
COz Emissions from Waste Incineration
PFC Emissions from Aluminum Production
Non-COz Emissions from Stationary Combustion
N20 Emissions from Adipic Acid Production
COz Emissions from Lime Production
Non-COa Emissions from Stationary Combustion
NzO Emissions from Wastewater Handling
CH4 Emissions from Rice Production
COa Emissions from Natural Gas Flaring
SFe Emissions from Magnesium Production
Mobile Combustion: Road & Other
PFC, HFC, and SFe Emissions from Semiconductor Manufacturing
Mobile Combustion: Aviation
CH4 Emissions from Other Industrial Processes
Emissions from Substitutes for Ozone Depleting Substances
CH4 Emissions from Agricultural Residue Burning
Mobile Combustion: Marine
NzO Emissions from Agricultural Residue Burning
NzO Emissions from Waste Incineration
COa Emissions from Stationary Combustion - Geothermal Energy
Mobile Combustion: Aviation
Mobile Combustion: Marine
SFe
HFCs
C02
CH4
CH4
NzO
N20
C02
PFCs
NzO
NzO
C02
CH4
NzO
CH4
COz
SFe
CH4
SFe
NzO
CH4
Several
CH4
NzO
NzO
NzO
COz
CH4
CH4
31.23
34.98
30.90
29.19
24.25
17.85
16.03
14.09
18.11
12.82
14.89
11.24
7.90
7.04
7.12
5.51
5.50
4.67
2.86
1.71
1.19
0.94
0.68
0.36
0.37
0.29
0.22
0.16
0.07
32.48
30.77
30.70
31.14
24.60
17.83
16.53
15.78
15.68
12.68
14.69
11.01
8.03
7.21
7.00
5.59
5.50
4.64
2.86
1.64
1.21
0.84
0.64
0.38
0.36
0.24
0.21
0.15
0.07
0.01
0.01
0.01
0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
0.96
0.96
0.97
0.97
0.98
0.98
0.98
0.98
0.99
0.99
0.99
0.99
0.99
0.99
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
TOTAL
6,130.72
6,075.18
1.00
Note: Sinks (e.g., LUCF, Landfill Carbon Storage) are not included in this analysis.
P-11
-------
Tafele P-5:1992 Key Source Tier 1 Analysis - Level Assessment
IPCC Source Categories
Direct Base Year Current Year
Greenhouse Estimate Estimate
Gas (TqCOzEq.) (TqCOzEq.)
\7GTr81
Level Cumulative
Assessment Total
ss|ofis loni Stationitytomffistiofr- Coal
' Road fc Other "" "' "'
n:Avjationi fwaimm_f
i fromWIf GaTdperaffohs"
COz
"COz
CH4
"W
CH4
1,235.49
193% ,;
' 176 88 Js%
im%m
657,85
^215.82
• 2V02.46!
167,01
,150.35*
5)2 EiwsslonsTforri Other IndusWaTProcesses
; ptlvel; missions from CoafMimng and* Hanflling
N£) f Ijsstons fromjteogai Usedjn Agriculture ^ _^ _
1 8e Com¥usiK»n Tearing"" "*' ^~, ***,J V7"*
Ste Combustion *Roa*d*& Otfier
ffC23ErrlssKsfrom"H"CFC22TvIanufactu7e"" " * -~~"«'
COz Emissions from Cement Production
Indirect COz Emissions from CH4 Oxidation
SFs Emissions from Electrical Equipment
CH4 Emissions from Manure Management
CH4 Emissions from Wastewater Handling
NzO Emissions from Nitric Acid Production
COz Emissions from Waste Incineration
NaO Emissions from Manure Management
Non-COz Emissions from Stationary Combustion
PFC Emissions from Aluminum Production
NjO Emissions from Adipic Acid Production
COz Emissions from Lime Production
Non-COz Emissions from Stationary Combustion
CH4 Emissions from Rice Production
NzO Emissions from Wastewater Handling
COz Emissions from Natural Gas Flaring
SFs Emissions from Magnesium Production
Mobile Combustion: Road & Other
PFC, HFC, and SFs Emissions from Semiconductor Manufacturing
Mobile Combustion: Aviation
Emissions from Substitutes for Ozone Depleting Substances
CH4 Emissions from Other Industrial Processes
CH4 Emissions from Agricultural Residue Burning
Mobile Combustion: Marine
NzO Emissions from Agricultural Residue Burning
NzO Emissions from Waste Incineration
COz Emissions from Stationary Combustion - Geothermal Energy
Mobile Combustion: Aviation
Mobile Combustion: Marine
"COz
CH* ~ "*""*'""
NzO , .
CO? - - " - x
NzO_ .. J
""flfts" *"" "~* ~* "
COz
COz
SF6
CH4
CH4
NzO
COz
NzO
NzO
PFCs
NzO
COz
CH4
CH4
NzO
COz
SF6
CH4
SF6
NzO
Several
CH4
CH4
NzO
NzO
NzO
COz
CH4
CH4
^"fT23»6t>
***' 87,12
" 73.60
" "59,43
't 48.8f
I r s4.a8
33.28
30.90
31.23
29.19
24.25
17.85
14.09
16.03
12.82
18.11
14.89
11.24
7.90
7.12
7.04
5.51
5.50
4.67
2.86
1.71
0.94
1.19
0.68
0.36
0.37
0.29
0.22
0.16
0.07
- -^ 11 3.82
1 ; 8U7 _
" x^ y»***»syv
** ^5^.35 *
T^Mi?
32.79
30.51
30.16
30.72
25.22
18.30
16.32
16.31
12.94
14.55
12.63
11.39
8.30
7.87
7.34
5.06
5.50
4.67
2.86
1.62
1.52
1.28
0.75
0.43
0.41
0.27
0.21
0.15
0.08
0.02, -
0,0%
0,01 '
v" 0.01 ' *
' '- O.OT "^ •*"
f\
^- 0.01 e^
0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
•ft°1
d$f
; 23
0,93
0.94
'0.9|
f 0 AS
0.96
0.96
0.97
0.97
0.98
0.98
0.98
0.98
0.99
0.99
0.99
0.99
0.99
0.99
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
TOTAL
6,130.72
6,194.77
Note: Sinks (e.g., LUCF, Landfill Carbon Storage) are not included in this analysis.
P-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table P-B: 1993 Key Source Tier 1 Analysis - Level Assessment
IPCC Source Categories
Direct
Greenhouse
Gas
Base Year
Estimate
(TgCOzEg.)
Current Year
Estimate Level
(Tg Ok Eg.) Assessment
Cumulative
Total
SFe Emissions from Electrical Equipment
HFC-23 Emissions from HCFC-22 Manufacture
Indirect COz Emissions from CH4 Oxidation
CH4 Emissions from Manure Management
CH4 Emissions from Wastewater Handling
NzO Emissions from Nitric Acid Production
COz Emissions from Waste Incineration
NzO Emissions from Manure Management
Non-COz Emissions from Stationary Combustion
NzO Emissions from Adipic Acid Production
PFC Emissions from Aluminum Production
COz Emissions from Lime Production
COz Emissions from Natural Gas Flaring
Non-COz Emissions from Stationary Combustion
NzO Emissions from Wastewater Handling
CH4 Emissions from Rice Production
SFe Emissions from Magnesium Production
Emissions from Substitutes for Ozone Depleting Substances
Mobile Combustion: Road & Other
PFC, HFC, and SFe Emissions from Semiconductor Manufacturing
Mobile Combustion: Aviation
CH4 Emissions from Other Industrial Processes
CH4 Emissions from Agricultural Residue Burning
Mobile Combustion: Marine
NzO Emissions from Agricultural Residue Burning
NzO Emissions from Waste Incineration
COz Emissions from Stationary Combustion - Geothermal Energy
Mobile Combustion: Aviation
Mobile Combustion: Marine
SFe
HFCs
COz
CH4
CH4
NzO
COz
NzO *
NzO
NzO
PFCs
COz
COz
CH4
NzO
CH4
SFe
Several
CH4
SFe
NzO
CH4
CH4
NzO
NzO
NzO
COz
CH4
CH4
31.23
34.98
30.90
29.19
24.25
17.85
14.09
16.03
12.82
14.89
18.11
11.24
5.51
7.90
7.04
7.12
5.50
0.94
4.67
2.86
1.71
1.19
0.68
0.36
0.37
0.29
0.22
0.16
0.07
34.09
31.82
29.48
31.64
25.59
18.57
17.18
16.73
13.14
13.92
13.86
11.64
6.55
7.82
7.45
7.02
5.37
5.24
4.65
3.58
1.63
1.40
0.60
0.43
0.34
0.26
0.19
0.14
0.08
: 0.01
0.01
<0.01
0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
! <0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01 .
<0.01
<0.01
<0.01
0.96
0.96
0.97
0.97
0.97
0.98
0.98
0.98
0.99
0.99
0.99
0.99
0.99
0.99
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
TOTAL
6,130.72 6,302.16 1.00
Note: Sinks (e.g., LUCF, Landfill Carbon Storage) are not included in this analysis.
P-13
-------
Table P-7:1994 Key Source Tier 1 Analysis - level Assessment
Current Year
IPCC Source Categories
rfssjwts from Stationary Combustion - Coal
^.., Combuslfcn: Road & Othei
ibjjjnlssio^s from Stationary Combustion - Gas
** from Stationary Combustion -pi]
Wm^rd Waste disposal Sites'
mS^bris from Agricultural Soils
I pbtte Combustion', Aviation
jjEjMve Ernlsste from OS & Gas Operati
" ......
ations
;JISf&"pt|ier™mj
rderneiifProtfuclori'
Direct
Greenhouse
Gas
Base Year
Estimate
q.)
Cumulative
Total
HFC-23 Emissions from HCFC-22 Manufacture
SFs Emissions from Electrical Equipment
CH4 Emissions from Manure Management
Indirect COz Emissions from CHi Oxidation
CH« Emissions from Wastewater Handling
NzO Emissions from Nitric Acid Production
COj Emissions from Waste Incineration
NjO Emissions from Manure Management
Non-COz Emissions from Stationary Combustion
NzO Emissions from Adipic Acid Production
PFC Emissions from Aluminum Production
COz Emissions from Lime Production
COz Emissions from Natural Gas Flaring
Emissions from Substitutes for Ozone Depleting Substances
CH4 Emissions from Rice Production
Non-COa Emissions from Stationary Combustion
NzO Emissions from Wastewater Handling
SFe Emissions from Magnesium Production
Mobile Combustion: Road & Other
PFC, HFC, and SFe Emissions from Semiconductor Manufacturing
Mobile Combustion: Aviation
CH4 Emissions from Other Industrial Processes
CH4 Emissions from Agricultural Residue Burning
NzO Emissions from Agricultural Residue Burning
Mobile Combustion: Marine
NzO Emissions from Waste Incineration
COz Emissions from Stationary Combustion - Geolhermal Energy
Mobile Combustion: Aviation
Mobile Combustion: Marine
HFCs
SFe
CH4
COz
CH4
NzO
COz
NzO
NzO
NzO
PFCs
COz
COz
Several
CH4
CH4
SFe
CH4
SFs
NzO
CH4
CH4
NzO
NzO
COz
CH4
CH4
34.98
31.23
29.19
30.90
24.25
17.85
14.09
16.03
12.82
14.89
18.11
11.24
5.51
0.94
7.12
7.90
7.04
5.50
4.67
2.86
1.71
1.19
0.68
0.37
0.36
0.29
0.22
0.16
0.07
TOTAL
6,130.72
1.00
Note: Sinks (e.g., LUCF, Landfill Carbon Storage) are not included in this analysis.
P-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table P-8:1995 Key Source Tier 1 Analysis - Level Assessment
IPCC Source Categories
Direct
Greenhouse
Gas
Base Year Current Year
Estimate Estimate Level Cumulative
(TgCOzEq.) (TgCOzEq.) Assessment Total
Indirect COz Emissions from CH4 Oxidation
HFC-23 Emissions from HCFC-22 Manufacture
CH4 Emissions from Wastewater Handling
SFs Emissions from Electrical Equipment
Emissions from Substitutes for Ozone Depleting Substances
NzO Emissions from Nitric Acid Production
C02 Emissions from Waste Incineration
NzO Emissions from Adipic Acid Production
NzO Emissions from Manure Management
Non-C02 Emissions from Stationary Combustion
C02 Emissions from Natural Gas Flaring
CO? Emissions from Lime Production
RFC Emissions from Aluminum Production
Non-COa Emissions from Stationary Combustion
NaO Emissions from Wastewater Handling
CH4 Emissions from Rice Production
PFC, HFC, and SFe Emissions from Semiconductor Manufacturing
SFe Emissions from Magnesium Production
Mobile Combustion: Road & Other
Mobile Combustion: Aviation
CH4 Emissions from Other Industrial Processes
CH4 Emissions from Agricultural Residue Burning
Mobile Combustion: Marine
NzO Emissions from Agricultural Residue Burning
NzO Emissions from Waste Incineration
Mobile Combustion: Aviation
COz Emissions from Stationary Combustion - Geothermal Energy
Mobile Combustion: Marine
COz
HFCs
CH4
SF6
Several
NzO
COz
NzO
NzO
NzO
COz
COz
PFCs
CH4
NzO
CH4
SF6
SF6
CH4
NzO
CH4
CH4
NzO
NzO
NzO
CH4
COz
CH4
v,
xs.s334
•29.19__1:
30.90
34.98
24.25
31.23
0.94
17.85
14.09
14.89
16.03
12.82
5.51
11.24
18.11
7.90
7.04
7.12
2.86
5.50
4.67
1.71
1.19
0.68
0.36
0.37
0.29
0.16
0.22
0.07
29.46
27.03
26.79
26.49
21.82
19.89
18.61
17.88
16.37
13.48
8.73
12.80
11.81
8.23
7.69
7.62
5.90
5.49
4.54
1.67
1.53
0.66
0.46
0.38
0.28
0.15
0.12
0.09
-Jw .
• ,8,01,
2#$L
•-%AiSU
jyar
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
0.96
0.96
0.97
0.97
0.97
0.98
0.98
0.98
0.99
0.99
0.99
0.99
0.99
0.99
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
TOTAL
6,130.72
6,481.81
1.00
Note: Sinks (e.g., LUCF, Landfill Carbon Storage) are not included in this analysis.
P-15
-------
Tahle P-9:1996 Key Siurce Tier 1 Analysis - Level Assessment
Direct
Greenhouse
Gas
Base Year
Estimate
(TgCOzEq.)
Current Year
Estimate
tTgCOzEq.)
Level
Assessment
Cumulative
Total
as
lnatjomBustt - 09
"
645.98
212<29f
211.50
180.16
150,67
129.5&
OsedWpcuIture
and Handling
, *», L.
CH4 Emissions from Manure Management
Emissions from Substitutes for Ozone Depleting Substances
Indirect COz Emissions from CH4 Oxidation
CI-U Emissions from Wastewaler Handling
SFs Emissions from Electrical Equipment
NzO Emissions from Nitric Acid Production
COz Emissions from Waste Incineration
NzO Emissions from Adipic Acid Production
NzO Emissions from Manure Management
Non-COz Emissions from Stationary Combustion
COz Emissions from Lime Production
COz Emissions from Natural Gas Flaring
PFC Emissions from Aluminum Production
Non-COz Emissions from Stationary Combustion
NzO Emissions from Waslewater Handling
CH« Emissions from Rice Production
SFs Emissions from Magnesium Production
PFC, HFC, and SFe Emissions from Semiconductor Manufacturing
Mobile Combustion: Road & Other
Mobile Combustion: Aviation
CH4 Emissions from Other Industrial Processes
CHi Emissions from Agricultural Residue Burning
NzO Emissions from Agricultural Residue Burning
Mobile Combustion: Marine
NzO Emissions from Waste Incineration
Mobile Combustion: Aviation
COz Emissions from Stationary Combustion - Geolhermal Energy
Mobile Combustion: Marine
CH<
Several
Cbz
CH4
NzO
Cbz
NzO
NzO
NzO
COz
COz
PFCs
CH4
NzO
CH4
SFe
CH4
NzO
CH4
C«4
NzO
NzO
NzO
CH4
COz
CH4
29.19
0.94
30.90
24.25
31.23
17.85
14.09
14.89
16.03
12.82
11.24
5.51
18.11
7.90
7.04
7.12
5.50
2.86
4.67
1.71
1.19
0.68
0.37
0.36
0.29
0.16
0.22
0.07
34.20
30.62
28.89
27.04
26.77
20.71
19.57
17.75
16.79
14.06
13.49
8.23
12.47
8.41
7.79
6.97
5.47
5.44
4.44
1.76
1.60
0.75
0.42
0.42
0.28
0.15
0.13
0.08
0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
0.96
0.97
0.97
0.97
0.98
0.98
0.98
0.99
0.99
0.99
0.99
0.99
0.99
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
TOTAL
6,130.72
6,669.76
1.00
Note: Sinks (e.g., LUCF, Landfill Carbon Storage) are not included in this analysis.
P-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table MO: 1997 Key Source Tier 1 Analysis - Level Assessment
IPCC Source Categories
Direct Base Year Current Year
Greenhouse Estimate Estimate Level Cumulative
Gas (TgCOaEg.) (TgCOzEg.) Assessment Total
("Corifbusflon^Cbal
k-*
J,692:6Q
' '§52,76"
•vcdr""^
^ V»rf*i "^SS^"
~,0%£|-
"""COz** *
• 7c§2 "71',
'"N20T '^-""Vi-
"> • • p-/,J?»^ i. $'# ~j_ tf
\t& „ \ ,s i / 213,41
^r^COW"! "^ T 176,88
- -ceV **.- -.SET- *
rogenyse&m Agriculture .'
'*N- '»*
'^ i
1,125.23
. , w.«3^ \f,M2
/V^Ma^s:; Ail
• s«™-> f|,Q2I, , v -0.8|
-'-57,61
"^0.02" /'S-'VW
\0jp1 - -- 0.9^
'^10.01; v:^ - 'o.01
- O.OV~ -'" 0,94
yS^KHKSSjsS 'Wi!iL>'W&5Si&5&-*« *v*^£SSia?S' *^'r*5SH.'^ ^r^J!^£L"
-------
Table P-11:1998 Key Siurce Tierl Analysis - Level Assessment
IPCC Source Categories
Direct
Greenhouse
Gas
Base Year
Estimate
(Tg Cg2 Eqj[
Current Year
Estimate Level
flj COz Eg.) Assessment
Cumulative
Total
rmssjons fromStaqonarv.Combusiion •
* ""'il1" '!i.i.V!'"*HlM jJ!Hlti'll«iiW:wlpll,* Jt HJt I* J* ^ „ , t* t-
iotis from, fijtrocjfi Used(|n Agriculture
COz Emissions from Cement Production
CH4 Emissions from Manure Management
Indirect COz Emissions from CH4 Oxidation
CH4 Emissions from Wastewater Handling
NzO Emissions from Nitric Acid Production N20
COz Emissions from Waste Incineration C02
SFs Emissions from Electrical Equipment SFs
Non-COz Emissions from Stationary Combustion N20
NzO Emissions from Manure Management N20
COz Emissions from Lime Production CQ2
PFC Emissions from Aluminum Production PFCs
NzO Emissions from Wastewater Handling N20
CH4 Emissions from Rice Production Cfy
NzO Emissions from Adipic Acid Production N20
Non-COz Emissions from Stationary Combustion CH4
PFC, HFC, and SFs Emissions from Semiconductor Manufacturing SFp
SFs Emissions from Magnesium Production SFfe
Mobile Combustion: Road & Other CH4
COz Emissions from Natural Gas Flaring C02
Mobile Combustion: Aviation N20
CH4 Emissions from Other Industrial Processes Cfy
CH4 Emissions from Agricultural Residue Burning CH4
NzO Emissions from Agricultural Residue Burning N2Q
Mobile Combustion: Marine N2Q
NzO Emissions from Waste Incineration NzO
Mobile Combustion: Aviation Cfy
COz Emissions from Stationary Combustion - Geothermal Energy C02
Mobile Combustion: Marine CH4
33.28
29.19
30.90
24.25
17.85
14.09
31.23
12.82
16.03
11.24
18.11
7.04
7.12
14.89
7.90
2.86
5.50
4.67
5.51
1.71
1.19
0.68
0.37
0.36
0.29
0.16
0.22
0.07
39.22
38.03
28.18
27.85
20.89
20.25
20.15
14.32
17.12
13.91
9.04
8.08
7.90
7.71
7.01
7.26
6.18
4.25
6.25
1.78
1.66
0.78
0.45
0.26
0.24
0.15
0.13
0.05
0.01
0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
0.96
0.97
0.97
0.97
0.98
0.98
0.98
0.99
0.99
0.99
0.99
0.99
0.99
0.99
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
TOTAL
6,130.72
6,756.19
1.00
Note: Sinks (e.g., LUCF, Landfill Carbon Storage) are not included in this analysis.
P-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table P-12:1999 Key Source Tier 1 Analysis - Level Assessment
IPCC Source Categories
Direct Base Year
Greenhouse Estimate
Gas _ (TgCOzEq.)
Current Year
Estimate Level Cumulative
(Tg COz Eg.) Assessment _ Total
feSMlgJl
COz Emissions from Cement Production COz
CH4 Emissions from Manure Management CH4
HFC-23 Emissions from HCFC-22 Manufacture HFCs
CH4 Emissions from Wastewater Handling CH4
Indirect COz Emissions from CH4 Oxidation COz
COz Emissions from Waste Incineration COz
NzO Emissions from Nitric Acid Production NzO
Non-COz Emissions from Stationary Combustion NzO
NzO Emissions from Manure Management NzO
SFe Emissions from Electrical Equipment SFe
COz Emissions from Lime Production COz
PFC Emissions from Aluminum Production PFCs
NzO Emissions from Wastewater Handling NzO
CH4 Emissions from Rice Production CH4
PFC, HFC, and SFe Emissions from Semiconductor Manufacturing SFe
Non-COz Emissions from Stationary Combustion CH4
NzO Emissions from Adipic Acid Production NzO
SFe Emissions from Magnesium Production SFe
Mobile Combustion: Road & Other CH4
COz Emissions from Natural Gas Flaring COz
Mobile Combustion: Aviation NzO
CH4 Emissions from Other Industrial Processes CH4
CH4 Emissions from Agricultural Residue Burning CH4
NzO Emissions from Agricultural Residue Burning NzO
Mobile Combustion: Marine NzO
NzO Emissions from Waste Incineration NzO
Mobile Combustion: Aviation CH4
Mobile Combustion: Marine CH4
COz Emissions from Stationary Combustion - Geothermal Energy COz
33.28
29.19
34.98
24.25
30.90
14.09
17.85
12.82
16.03
31.23
11.24
18.11
7.04
7.12
2.86
7.90
14.89
5.50
4.67
5.51
1.71
1.19
0.68
0.37
0.36
0.29
0.16
0.07
0.22
39.99
37.56
30.41
28.35
27.00
21.84
20.12
14.60
17.15
15.51
13.47
8.94
8.36
8.29
7.73
7.34
7.68
6.11
4.15
6.68
1.82
1.68
0.76
0.44
0.43
0.23
0.15
0.08
0.04
0.01
0.01
<0.01
<0.01
<0.01
<0.01
' <0.01
<0.01
. <0.01
<0.01
<0.01
<0.01
<0.01
' <0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
' <0.01
<0.01
. <0.01
. <0.01
<0.01
0.96
0.96
0.97
0.97
0.97
0.98
0.98
0.98
0.99
0.99
0.99
0.99
0.99
0.99
0.99
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
TOTAL
6,130.72
6,829.49
1.00
Note: Sinks (e.g., LUCF, Landfill Carbon Storage) are not included in this analysis.
P-19
-------
Table P-13:2000 Key Source Tier 1 Analysis - Level Assessment
IPCC Source Categories
gp^Errfssions from Stationary Combustion - Coal
pble Combustign- Road & Other ^
Bp^Ejjisstons from Stationary Combustion -G*as
5k Errtfesfofis fiwi Slatwnary Combustion - dil
Spa Nj>0 Emissions from Agricultural Soils
Sy-mfesiptis from S*pfid Waste Disposal Sites,
Hpn(e Combustion: Aviation
Stive*Ernissioi)s_from Oil & Gas dpe'rajions _ _
^l^ggy^ |rjjg, jTjjteJic Fermentation in^Dorjiesfic llvlgtcjck^ B
RLE-missions from dther Industrial Processes *
i j%j j * j * ^/ ** ' ^ *t« i w * ,
I obie_Combustiofi; Manne
| ffljec^NaO Emissions from^Nitrogert Used m Agriculture ^_
Mjye pmfssfbnTfrom Coal "Mining an3 Handling" "" ""
BssWis from Substitutes for Ozone Depleting Substances
/ ocfpydbmbustiolii, Roa 02
"I"" Q,OV
s* "- 1,01
T;:*f 0,01
- 0.01
*/ 0,01 ^
0.01
0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
<0.01
1.00
Cumulative
Total
~ " "6,58
:^:,o,6?
. - ' j'8^
0.8?
~ 0,8|
0*92
H!*0.9|
'„ ' . " 0,91
i>f j b 9|
0.96
0.96
0.97
0.97
0.98
0.98
0.98
0.98
0.99
0.99
0.99
0.99
0.99
0.99
0.99
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
Note: Sinks (e.g., LUCF, Landfill Carbon Storage) are not included in this analysis.
P-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
r
Table P-14:1990-2000 Key Source Tier 1 Analysis - Trend Assessment
IPCC Source Categories
Direct Base Year Current Year Percent
Greenhouse Estimate Estimate Trend Contribution to Cumulative
Gas (TqCOzEq.) (TgCOzEq.) Assessment Trend Total
Frativ? Emfesians ftorr^|& GjsjQpraflenss
?^*St**- *« .*«f ""SP... *>.. .^?V\. ^iTKo..t« :**:*™*".^i*!»»? 5.. Y.. '*•>
IOzfrBis|{&|'omka^RarjCoinfe|on'-5aaI ^OjQaj,^~% \'.
MqbJi>cM)Bsfior|'r|o|d<"i|]3tner H«.^Ijyl^^§%" ',_, * ~* * *
QlStfies jor Kpteg ^ ,w ~^
v *~ ^i1^,/\ \ ^Several --^^Tr^,
, .SI^BsB^sfemCptfMirijpgaritfHIiping"? GySu-jT- ", %f"rt?.12- ^^"~*®it'-
e^f|issJoj^jrei@her lftoHjstr^^^ses-^~^^6J;^ - ^ ^ •*----- - - -
!Fu0itiveErms'siQns from oil & Gas Operations!- N I^CHecT*' ' <^.'*"-
R2d~tjTOS)rislrornAdMc'Aiitl Procfuclfen"7r"
fco£BS^^ftiw ^fas!^Bn^rli^iw^'?^-:*<2
Mobile Combustion: Aviation
Indirect NaO Emissions from Nitrogen Used in
Agriculture
CH4 Emissions from Manure Management
PFC, HFC, and SFs Emissions from Semiconductor
Manufacturing
Direct NaO Emissions from Agricultural Soils
COa Emissions from Cement Production
SFs Emissions from Magnesium Production
Non-COz Emissions from Stationary Combustion
Mobile Combustion: Road & Other
CH4 Emissions from Wastewater Handling
NaO Emissions from Manure Management
Cm Emissions from Rice Production
NaO Emissions from Nitric Acid Production
COa Emissions from Lime Production
NaO Emissions from Wastewater Handling
CH4 Emissions from Other Industrial Processes
Non-COa Emissions from Stationary Combustion
COa Emissions from Natural Gas Flaring
COa Emissions from Stationary Combustion -
Geothermal Energy
Mobile Combustion: Marine
NaO Emissions from Waste Incineration
Mobile Combustion: Road & Other
Mobile Combustion: Marine
Mobile Combustion: Aviation
NaO Emissions from Agricultural Residue Burning
Mobile Combustion: Aviation
CH4 Emissions from Aqricultural Residue Burning
TOTAL
Jfj0 '• . ;
jf^pv.- * * °*ls
COa
NaO
CH4
SFe
NaO
COa
SFe
CH4
CH4
CH4
NaO
CH4
NaO
COa
NaO
CH4
NaO
COa
COa
NaO
NaO
NaO
CH4
NaO
NaO
CH4
CH4
SJ •"-"*•-•*- J4J9
-,"'-»«, l3i-l8C~ v
176.88
73.60
29.19
2.86
193.49
33.28
5.50
7.90
4.67
24.25
16.03
7.12
17.85
11.24
7.04
1.19
12.82
5.51
0.22
0.36
0.29
48.86
0.07
1.71
0.37
0.16
0.68
6,130.72
8,11 ,-T
V3K °22J7«"-'
196.45
79.81
37.46
7.37
217.75
41.07
4.00
7.50
4.09
28.70
17.52
7.50
19.79
13.32
8.46
1.67
14.93
6.06
0.02
0.63
0.23
55.74
0.12
1.92
0.46
0.16
0.79
7,001.22
-o" <0.01 \«ft^
"v*3PT ii^n
<0.01~
<0.01
<0.01 •
<0.01 !
<0.01
-------
P-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX Q
Global Warming Potential Values
Global Wanning Potentials (GWPs) are intended as a quantified measure of the globally averaged relative
radiative forcing impacts of a particular greenhouse gas. It is defined as the cumulative radiative forcing—both
direct and indirect effects—integrated over a period of time from the emission of a unit mass of gas relative to some
reference gas (IPCC 1996). Carbon dioxide (CO2) was chosen as this reference gas. Direct effects occur when the
gas itself is a greenhouse gas. Indirect radiative forcing occurs when chemical transformations involving the
original gas produce a gas or gases that are greenhouse gases, or when a gas influences other radiatively important
processes such as the atmospheric lifetimes of other gases. The relationship between gigagrams (Gg) of a gas and
Tg CO2 Eq. can be expressed as follows:
Tg C02 Eq = (Gg of gas)x (GWP)x
l,OOOGg
Where,
Tg CO2 Eq. = Teragrams of Carbon Dioxide Equivalents
Gg = Gigagrams (equivalent to a thousand metric tons)
GWP = Global Warming Potential
Tg = Teragrams ;
GWP values allow policy makers to compare the impacts of emissions and reductions of different gases.
According to the IPCC, GWPs typically have an uncertainty of roughly +35 percent, though some GWPs have larger
uncertainty than others, especially those in which lifetimes have not yet been ascertained. In the following decision,
the parties to the UNFCCC have agreed to use consistent GWPs from the IPCC Second Assessment jReport (SAR),
based upon a 100 year time horizon, although other time horizon values are available (see Table Q-l).'
In addition to communicating emissions in units of mass, Parties may choose also to use global
•warming potentials (GWPs) to reflect their inventories and projections in carbon dioxide-equivalent terms,
using information provided by the Intergovernmental Panel on Climate Change (IPCC) in its Second
Assessment Report. Any use of GWPs should be based on the effects of the greenhouse gases over a 100-
year time horizon. In addition, Parties may also use other time horizons.i >
Greenhouse gases with relatively long atmospheric lifetimes (e.g., CO2, CH4, N2O, MFCs, PFCs, and SF6)
tend to be evenly distributed throughout the atmosphere, and consequently global average concentrations can be
determined. The short-lived gases such as water vapor, carbon monoxide, tropospheric ozone, other ambient air
pollutants (e.g., NOX, and NMVOCs), and tropospheric aerosols (e.g., SO2 products and black carbon), however,
vary spatially, and consequently it is difficult to quantify their global radiative forcing impacts. GWP values are
generally not attributed to these gases that are short-lived and spatially inhomogeneous in the atmosphere.
1 Framework Convention on Climate Change; FCCC/CP/1996/15/Add.l; 29 October 1996; Report of the Conference
of the Parties at its second session; held at Geneva from 8 to 19 July 1996; Addendum; Part Two: Action taken by the Conference
of the Parties at its second session; Decision 9/CP.2; Communications from Parties included in Annex I to the Convention:
guidelines, schedule and process for consideration; Annex: Revised Guidelines for the Preparation of-National Communications
by Parties Included in Annex I to the Convention; p. 18. FCCC (1996)
Q-1
-------
Table Q-1: Global Wanning Pilentials [GWP1 and Atmospheric Lifetimes (Years! if Gases Used in this Repirt
Gas
Atmospheric Lifetime
100-year GWPa
20-year GWP
500-year GWP
Carbon dioxide (CO?)
Methane (CH^6
Nitrous oxide (NzO)
HFC-23
HFC-125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
CF4
CzFe
SFs
50-200
12±3
120
264
32.6
14.6
48.3
1.5
36.5
209
17.1
50,000
10,000
2,600
3,200
3,200
1
21
310
11,700
2,800
1,300
3,800
140
2,900
6,300
1,300
6,500
9,200
7,000
7,400
23,900
1
56
280
9,100
4,600
3,400
5,000
460
4,300
5,100
3,000
4,400
6,200
4,800
5,000
16,300
1
6.5
170
9,800
920
420
1,400
42
950
4,700
400
10,000
14,000
10,100
10,700
34,900
Source: IPCC (1996)
8 GWPs used in this report are calculated over 100 year time horizon
b The melhane GWP includes the direct effects and those indirect effects due to the production of tropospheric ozone and stratospheric water
vapor. The indirect effect due to the production of COz is not included.
Table Q-2 presents direct and net (i.e., direct an<3 indirect) GWPs for ozone-depleting substances (ODSs).
Ozone-depleting substances directly absorb infrared radiation and contribute to positive radiative forcing; however,
their effect as ozone-depleters also leads to a negative radiative forcing because ozone itself is a potent greenhouse
gas. There is considerable uncertainty regarding this indijrect effect; therefore, a range of net GWPs is provided for
ozone depleting substances. I
Table Q-2: HetlOO-year Global Warming Potentials for Select Ozone Depleting Substances*
Gas
Direct
Netm
Netmax
CFC-11
CFC-12
CFC-113
HCFC-22
HCFC-123
HCFC-124
HCFC-1415
HCFC-142D
CHCU
CCI4
CHaBr
Haton-1211
Haton-1301
4,600
10,600
6,000
1,700
120
620
700
2,400
140
1,800
5
1,300
6,900
(600)
'7,300
2,200
11,400
20
480
(5)
1,900
(560)
(3,900)
(2,600)
(24,000)
(76,000)
3,600
9,900
5,200
1,700
100
590
570
2,300
0
660
(500)
(3,600)
(9,300)
Source: IPCC (2001)
* Because these compounds have been shown to deplete stratospheric ozone, they are typically referred to as ozone depleting substances
(ODSs). However, they are also potent greenhouse gases. Recognizing Ittie harmful effects of these compounds on the ozone layer, in 1987 many
governments signed the Montreal Protocol on Substances that Deplete-the Ozone Layer to limit the production and importation of a number of
CFCs and other halogenated compounds. The United States furthered its commitment to phase-out ODSs by signing and ratifying the
Copenhagen Amendments to the MontrealProtocolm 1992. Under these amendments, the United States committed to ending the production and
importation of halons by 1994, and CFCs by 1996. The IPCC Guidelines and the UNFCCC do not include reporting instructions for estimating
emissions of ODSs because their use is being phased-out under the Montreal Protocol. The effects of these compounds on radiative forcing are
not addressed in this report '
The IPCC recently published its Third Assessment Report (TAR), providing the most current and
comprehensive scientific assessment of climate change (IPCC 2001). Within this report, the GWPs of several gases
were revised relative to the TPCC's Second Assessment: Report (SAR) (IPCC 1996), and new GWPs have been
calculated for an expanded set of gases. Since the SAR, the IPCC has applied an improved calculation of CO2
Q-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
F
radiative forcing and an improved CO2 response function (presented in WMO 1999). The OWPs^are drawn from
WMO (1999) and the SAR, with updates for those cases where new laboratory or radiative transfer results have been
published. Additionally, the atmospheric lifetimes of some gases have been recalculated. Because the revised
radiative forcing of CO2 is about 12 percent lower than that hi the SAR, the GWPs of the other gases relative to CO2
tend to be larger, taking into account revisions in lifetimes. However, there were some instances in which other
variables, such as the radiative efficiency or the chemical lifetime, were altered that resulted in further increases or
decreases in particular GWP values. In addition, the values for radiative forcing and lifetimes have been calculated
for a variety of halocarbons, which were not presented in the SAR. The changes are described in the TAR as
follows:
New categories of gases include fluorinated organic molecules, many of which are ethers that are
proposed as halocarbon substitutes. Some of the GWPs have larger uncertainties than that of others,
particularly for those gases where detailed laboratory data on lifetimes are not yet available. The direct GWPs
have been calculated relative to CO? using an improved calculation of the COz radiative forcing, the SAR
response function for a CO2 pulse, and new values for the radiative forcing and lifetimes for a number of
halocarbons.
Table Q-3 compares the lifetimes and GWPs for the SAR and TAR. As can be seen in Table Q-3, GWPs
changed anywhere from a decrease of 15 percent to an increase of 49 percent.
Q-3
-------
Table Q-3: Comparison of GWPs and lifetimes used in the SAR and the TAR
Gas
Carbon dioxide (002)
Methane (CHi)b
Nitrous oxide (NzO)
Hydrofluorocarbons
HFC-23
HFC-32
HFC-41
HFC-125
HFC-134
HFC-134a
HFC-143
HFC-143a
HFC-152
HFC-152a
HFC-161
HFC-227ea
HFC-236cb
HFC-236ea
HFC-236fa
HFC-245ca
HFC-245fa
HFC-365mfc
HFC-4310mee
lodocarbons
FIC-1311
Fully Fluorinated Species
SFe
CF4
CaFG
C3F8
QFio
c-C
-------
HFE-374pcf2
HFE-7100
HFE-7200
H-Galden 1040x
HG-10
HG-01
Others'1
NFs
SFsCFs
c-CsFe
HFE-227ea
HFE-236ea2
HFE-236fa
HFE-245fa1
HFE-263fb2
HFE-329mcc2
HFE-338mcf2
HFE-347-mcf2
HFE-356mec3
HFE-356pcc3
HFE-356pcf2
HFE-365mcf3
(CF3)2CHOCHF2
(CF3)2CHOCH3
-(CF2)4CH(OH)-
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
5.0
5.0
0.77
6.3
12.1
6.2
740
>1,000
>1,000
11
5.8
3.7
2.2
0.1
6.8
4.3
2.8
0.94
0.93
2.0
0.11
3.1
0.25
0.85
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
540
390
55
1,800
2,700
1,500
10,800
>17,500
>16,800
1,500
960
470
280
11
890
540
360
98
110
260
11
370
26
70
NA
NA
NA
NA
NA :
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA ;
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
a No single lifetime can be determined for carbon dioxide. (See IPCC 2001)
6 The methane GWP includes the direct effects and those indirect effects due to the production of tropospheric ozone and stratospheric water
vapor. The indirect effect due to the production of COa is not included.
c Methane and nitrous oxide have chemical feedback systems that can alter the length of the atmospheric response, in these cases, global
mean atmospheric lifetime (LT) is given first, followed by perturbation time (PT).
d Gases whose lifetime has been deterined only via indirect means of for whom there is uncertainty over the loss process.
Source: IPCC (2001)
NC (No Change)
NA (Not Applicable) ;
When the GWPs from the TAR are applied to the emission estimates presented in this report, total
emissions for the year 2000 are 7,044.3 Tg CO2 Eq., as compared to 7,001.2 Tg CO2 Eq. when the GWPs from the
SAR are used (a 0.6 percent difference). Table Q-4 provides a detailed summary of U.S. greenhouse gas emissions
and sinks for 1990 through 2000, using the GWPs from the TAR. The adjusted greenhouse gas emissions are shown
for each gas in units of Tg CO2 Eq. in Table Q-5. The correlating percent change in emissions of each gas is shown
in Table Q-6. The percent change in emissions is equal to the percent change in the GWP, however, in cases where
multiple gases are emitted in varying amounts the percent change is variable over the years, such as with substitutes
for ozone depleting substances. Table Q-7 summarizes the emissions and resulting change in emissions using
GWPs from the SAR or the TAR for 1990 and 2000.
Q-5
-------
Table Q-4: Recent Trends in U.S. Greenhinse Gas Emissions and Sinks using the TAR BWPs [To Cft EgJ
Gas/Source
19901
COz
FossB Fuel Combustion
Natural Gas Flaring
Cement Manufacture
Lime Manufacture
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Carbon Dioxide Consumption
Waste Combustion
Titanium Dioxide Production
Aluminum Production
Iron and Steel Production
Ferroalloys
Indirect COa
Ammonia Manufacture
Land-Use Change and Forestry (Sink)3
International Bunker Fuels'1
CH<
Stationary Sources
Mobile Sources
Coal Mining
Natural Gas Systems
Petroleum Systems
Petrochemical Production
Silicon Carbide Production
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Residue Burning
Landfills
Wastewater Treatment
International Bunker Fuels'1
NzO
Stationary Source
Mobile Sources
AdipicAcid
Nitric Acid
Manure Management
Agricultural Soil Management
Agricultural Residue Burning
Human Sewage
Waste Combustion
International Bunker Fuels'"
HFCs,PFCs,andSF6
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production
Semiconductor Manufacture1*
Electrical Transmission and Distribution6
Magnesium Production and Processing6
Total
+ Does not exceed 0.05 Tg CQz Eq.
• Sinks are only included in net emissions total, and are based partially on projected activity data. Parentheses indicate negative values (or
sequestration). '
b Emissions from International Bunker Fuels are not included in totals.
'HFC-23 emitted
" Emissions from HFC-23, CF<, C2F6,C3F8 SF6, and the addition of NF3
CSF$ emitted i
Note: Totals may not sum due to independent rounding. [
1995
5,305.9
5,085.0
8.7
36.8
12.8
7.0
4.3
1.0
18.6
1.7
! 5.3
74.4
1.9
29.5
18.9
(1,110.0)
101.0
720.2
9.0
5.2
80.5
137.6
I 26.5
1.7
145.9
38.1
8.3
0.7
237.3
29.3
0.1
400.8
12.9
57.7
17.1
19.0
15.6
270.6
0.4
7.3
0.3
0.8
97.8
22.6
10.9
27.7
6.8
24.6
5.1
6,524.8
1996
5,483.7
5,266.6
8.2
37.1
13.5
7.4
4.2
1.1
19.6
1.7
5.6
68.3
2.0
28.9
19.5
(1,108.1)
102.3
705.0
9.2
5.1
74.9
138.7
26.3
1.7
141.9
37.5
7.6
0.8
231.6
29.6
0.1
411.0
13.4
57.4
17.0
19.8
16.0
279.4
0.4
7.4
0.3
0.9
111.9
32.3
11.5
31.9
6.3
24.9
5.1
6,711.7
1997
5,568.0
5,339.6
7.6
38.3
13.7
8.4
4.4
1.3
21.3
1.8
5.6
76.1
2.0
28.4
19.5
(887.5)
109.9
693.7
8.2
5.0
74.6
134.4
26.3
1.8
138.8
39.3
8.2
0.8
226.0
30.2
0.2
410.4
13.6
57.0
11.0
20.3
16.3
284.1
0.4
7.6
0.2
0.9
117.6
39.9
10.1
30.8
7.6
22.7
6.4
6,789.6
1998
5,575.1
5,356.2
6.3
39.2
13.9
8.2
4.3
1.4
20.3
1.8
5.8
67.4
2.0
28.2
20.1
(885.9)
112.9
686.8
7.7
4.9
74.4
133.9
25.6
1.8
136.8
41.6
8.7
0.9
220.1
30.5
0.2
407.1
13.7
56.5
7.4
19.9
16.3
284.9
0.4
7.7
0.2
0.9
129.8
47.4
8.3
41.2
8.4
18.7
5.7
6,798.8
1999
5,665.5
5,448.6
6.7
40.0
13.5
9.1
4.2
1.6
21.8
1.9
5.9
64.4
2.0
27.0
18.9
(896.4)
105.3
679.6
8.0
4.8
69.8
129.9
24.4
1.8
136.4
41.1
9.1
0.8
222.4
31.0
0.1
404.4
13.9
56.0
7.3
19.2
16.4
282.9
0.4
8.0
0.2
0.9
122.9
54.4
8.2
31.2
9.0
14.4
5.7
6,872.3
2000
5,840.0
5,623.3
6.1
41.1
13.3
9.2
4.2
1.4
22.5
2.0
5.4
65.7
1.7
26.3
18.0
(902.5)
100.2
673.0
8.2
4.8
66.8
127.4
23.9
1.8
135.7
41.0
8.2
0.9
222.9
31.4
0.1
406.1
14.3
55.7
7.7
18.9
16.7
284.1
0.4
8.1
0.2
0.9
125.1
61.5
7.3
30.6
8.5
13.4
3.7
7,044.3
Q-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table Q-5: Change in U.S. Greenhouse Gas Emissiins and Sinks Using TAR vs SAR GWPs tig CQ> EnJ
Gas
C02
CH<
N20
HFCs, PFCs, and SF6*
Total
.
42.011(1!
1995
NC
62.6
(19.0)
(0.7)
42.9
1996
NC
61.3
(19.4)
0.1
41.9
1997
NC
60.3
(19.4)
0.6
41.6
1998
NC
59.7
(9.3)
2.1
42.6
1999
NC
: 59.1
(9.1)
; 2.9
42.8
2000
NC
58.5
(9.2)
3.8
43.1
NC (No change)
Includes NF3
Note: Totals may not sum due to independent rounding.
Table Q-6: Change in U.S. Greenhouse Gas Emissiins Dsing TAR vs SAR GWPs (Percent)
Gas/Source
C02
CH4
N20
HFCs, PFCs, and SF6
Substitution of Ozone Depleting Substances
Aluminum Production3
HCFC-22 Production"
Semiconductor Manufacture0
Electrical Transmission and Distribution"
Magnesium Production and Processing11
Total
1990
NC
9.5
(4.5)
(2.7)
(3.2)
(7.0)
2.6
15.9
(7.1)
(7.1)
-------
Table Q-B: CamparlsBn if Emissiins by Sectir using IPCC SAB and TAR GWP Ualiies (Tg Cft En.l
Sector
Energy
SAR GWP (Used in Inventory)
TAR GWP
Difference (%)
Industrial Processes
SAR GWP (Used in Inventoiy)
TAR GWP
Difference (%)
Agriculture
SAR GWP (Used in Inventory)
TAR GWP
Difference (%)
Land-Use Change and Forestry
SAR GWP (Used in Inventory)
TAR GWP
Difference (%)
Waste
SAR GWP (Used in Inventory)
TAR GWP
Difference (%)
Net Emisions (Sources and Sinks)
SAR GWP (Used in Inventory)
TAR GWP
Difference (%)
NC (No change)
1990S
B
5,141 .9B
5.162.6B
0.4%H
•
295.7B
291 .&•
-1-3%H
1
448.4BS
451
•
(1,097.7)H
(1,097.7) H
NCHi
B
244.7B
267.0B
9.1%B
•
5,033.0B
5,074.9B|
0.8%H
i 1995
I
i 5,452.4
1 5,471.6
I 0.4%
I 301.9
I 299.6
I -0:8%
476.4
479.6
0.7%
I
(1,110.0)
(1,110.0)
!NC
251.1
273.9
1 9.1%
5,371.8
5,414.7
I 0.8%
1996
5,629.9
5,648.6
0.3%
312.3
310.8
-0.5%
481.3
483.6
0.5%
(1,108.1)
(1,108.1)
NC
246.3
268.7
9.1%
5,561.7
5,603.6
0.7%
1997
5,697.9
5,716.2
0.3%
322.4
321.7
-0.2%
485.9
487.9
0.4%
(887.5)
(887.5)
NC
241.9
263.8
9.1%
5,860.5
5,902.1
0.7%
1998
5,709.5
5,727.6
0.3%
322.1
323.1
0.3%
487.6
489.7
0.4%
(885.9)
(885.9)
NC
236.9
258.3
9.0%
5,870.3
5,912.9
0.7%
1999
5,793.9
5,811.2
0.3%
310.8
312.6
0.6%
485.0
487.1
0.4%
(896.4)
(896.4)
NC
239.8
261.5
9.0%
5,933.1
5,975.9
0.7%
2000
5,962.6
5,979.4
0.3%
312.8
315.5
0.8%
485.1
487.1
0.4%
(902.5)
(902.5)
NC
240.6
262.4
9.0%
6,098.7
6,141.8
0.7%
Note: Totals may not sum due to independent rounding.
Q-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX R
Ozone Depleting Substance Emissions
Ozone is present in both the stratosphere,1 where it shields the earth from harmful levels of ultraviolet
radiation, and at lower concentrations in the troposphere,2 where it is the main component of anthropogenic
photochemical "smog." Chlorofluorocarbons (CFCs), halons, carbon tetrachloride, methyl chloroform, and
hydrochlorofluorocarbons (HCFCs), along with certain other chlorine and bromine containing compounds, have
been found to deplete the ozone levels in the stratosphere. These compounds are commonly referred to as ozone
depleting substances (ODSs). If left unchecked, stratospheric ozone depletion could result in a dangerous increase
of ultraviolet radiation reaching the earth's surface. In 1987, nations around the world signed the Montreal Protocol
on Substances that Deplete the Ozone Layer. This landmark agreement created an international framework for
limiting, and ultimately eliminating, the production of most ozone depleting substances. ODSs have historically
been used in a variety of industrial applications, including refrigeration and air conditioning, foam blowing, fire
extinguishing, as an aerosol propellant, sterilization, and solvent cleaning.
In the United States, the Clean Air Act Amendments of 1990 provide the legal instrument for
implementation of the Montreal Protocol controls. The Clean Air Act classifies ozone depleting substances as
either Class I or Class II, depending upon the ozone depletion potential (ODP) of the compound.3 The production of
CFCs, halons, carbon tetrachloride, and methyl chloroform—all Class I substances—has already ended in the United
States. However, large amounts of these chemicals remain in existing equipment,4 and stockpiles of the ODSs are
used for maintaining the equipment. In addition, U.S. regulations require the recovery of ODSs in order to minimize
"venting" to the atmosphere. As a result, emissions of Class I compounds will continue, albeit in ever decreasing
amounts, into the early part of the next century. Class II designated substances, all of which are
hydrochlorofluorocarbons (HCFCs), are being phased out at later dates because they have lower ozone depletion
potentials. These compounds serve as interim replacements for Class I compounds in many industrial applications.
The use and emissions of HCFCs in the United States is anticipated to increase over the next several years as
equipment that use Class I substances are retired from use. Under current controls, however, the production for
domestic use of all HCFCs in the United States will end by the year 2030.
In addition to contributing to ozone depletion, CFCs, halons, carbon tetrachloride, methyl chloroform, and
HCFCs are also potent greenhouse gases. However, the depletion of the ozone layer has a cooling effect on the
climate that counteracts the direct warming from tropospheric emissions of ODSs. Stratospheric ozone influences
the earth's radiative balance by absorption and emission of longwave radiation from the troposphere as well as
absorption of shortwave radiation from the sun.
The IPCC has prepared both direct GWPs and net (combined direct warming and indirect cooling) GWP
ranges for some of the most common ozone depleting substances (IPCC 1996). See Annex Q for a listing of the net
GWP values for CDS.
Although the IPCC emission inventory guidelines do not require the reporting of emissions of ozone
depleting substances, the United States believes that no inventory is complete without the inclusion of these
compounds. Emission estimates for several ozone depleting substances are provided in Table R-l.
1 The stratosphere is the layer from the top of the troposphere up to about 50 kilometers. Approximately 90 percent of
atmospheric ozone is within the stratosphere. The greatest concentration of ozone occurs in the middle of the stratosphere, in a
region commonly called the ozone layer.
2 The troposphere is the layer from the ground up to about 11 kilometers near the poles and 16 kilometers in equatorial
regions (i.e., the lowest layer of the atmosphere, where humans live). It contains roughly 80 percent of the mass of all gases in
the atmosphere and is the site for weather processes including most of the water vapor and clouds.
3 Substances with an ozone depletion potential of 0.2 or greater are designated as Class I. All other substances that
may deplete stratospheric ozone but which have an ODP of less than 0.2 are Class II.
4 Older refrigeration and air-conditioning equipment, fire extinguishing systems, meter-dose inhalers, and foam
products blown with CFCs/HCFCs may still contain ODS.
R-1
-------
Table R-1: EralssHns if Ozine Depleting substances (Gg)
Compound
Class 1
CFC-11
CFC-12
CFC-113
CFC-114
CFC-115
Carbon Telrachloride
Methyl Chlorofofm
Haton-1211
Haton-1301
Class U
HCFC-22
HCFC-123
HCFC-124
HCFC-141b
HCFC-142b
HCFC-225ca/cb
1990
53.5
112.6
52.7
4.7
4.2
32.3
316.6
1.0
1.8
34.0
+
+
1.3
0.8
+
1991
48.3
103.5
41.1
3.6
4.0
+
309.4
1.1
1.8
35.4
+
+
1.7
1.4
+
1992
45.1
80.5
34.2
3.0
3.8
21.7
216.6
1.0
1.7
35.2
0.1
0.2
1.7
1.9
+
1993
45.4
79.3
34.2
3.0
3.6
18.6
185.7
1.1
1.7
35.3
0.3
2.7
2.9
2.6
+
1994
36.6
57.6
17.1
1.6
3.3
15.5
154.7
1.0
1.4
37.7
0.5
5.3
6.2
3.3
+
1995
36.2
51.8
17.1
1.6
3.0
4.7
92.8
1.1
1.4
39.3
0.6
5.6
9.9
3.6
+
1996
26.6
35.5
+
0.3
3.2
+
H-
1.1
1.4
41.0
0.7
5.9
9.9
4.0
+
1997
25.1
23.1
+
0.1
2.9
+
+
1.1
1.3
42.4
0.8
6.2
8.8
4.3
H-
1998
24.9
21.0
+
0.1
2.7
+
+
1.1
1.3
43.8
0.9
6.4
9.7
4.7
+
1999
24.0
14.0
+
+
2.6
+
+
1.1
1.3
74.1
1.0
6.5
10.9
5.0
+
2000
22.8
17.2
+
+
2.3
+
+
1.1
1.3
79.1
1.1
6.5
10.9
5.4
+
+ Does not exceed 0.05 Gg '
Methodology and Data Sources
Emissions of ozone depleting substances were estimated using two simulation models: the Atmospheric
and Health Effects Framework (AHEF) and the EPA's Vintaging Model. AHEF contains estimates of U.S.
domestic use of each of the ozone depleting substances. These estimates were based upon data that industry reports
to the EPA and other published material. The annual consumption of each compound was divided into various end-
uses based upon historical trends and research into specific industrial applications. These end-uses include
refrigerants, foam blowing agents, solvents, aerosol propellants, sterilants, and fire extinguishing agents.
With the exception of aerosols, solvents, and certain foam blowing agents, emissions of ozone depleting
substances are not instantaneous, but instead occur gradually over time (i.e., emissions in a given year are the result
of both ODS use in that year and use in previous years). Each end-use has a certain release profile, which gives the
percentage of the compound that is released to the atmosphere each year until all releases have occurred. In
refrigeration equipment, for example, the initial charge is released or leaked slowly over the lifetime of the
equipment, which could be 20 or more years. In addition, not all of the refrigerant is ultimately emitted—some will
be recovered when the equipment is retired from operation. I
The AHEF model was used to estimate emissions of ODSs that were in use prior to the controls
implemented under the Montreal Protocol. This included ;CFCs, halons, carbon tetrachloride, methyl chloroform,
and HCFC-22. Certain HCFCs, such as HCFC-123, HCFC-124, HCFC-141b, HCFC-142b, HCFC-225ca and
HCFC-225cb, have also entered the market as interim substitutes for ODSs. Emissions estimates for these
compounds were taken from the EPA's Vintaging Model.
The Vintaging Model was used to estimate the use and emissions of various ODS substitutes, including
HCFCs. The model, named for its method of tracking the emissions of annual "vintages" of new equipment that
enter into service, is a "bottom-up" model. It models the consumption of chemicals based on estimates of the
quantity of equipment or products sold, serviced, and retired each year, and the amount of the chemical required to
manufacture and/or maintain the equipment. The Vintaging model makes use of this market information to build an
inventory of the in-use stocks of the equipment in each of the end-uses. Emissions are estimated by applying annual
leak rates, service emission rates, and disposal emission rates to each population of equipment, as in the AHEF. By
aggregating the emission and consumption output from the different end-uses, the model produces estimates of total
annual use and emissions of each chemical. Please see Annex J of this Inventory for a more detailed discussion of
the Vintaging Model.
Uncertainties
Uncertainties exist with regard to the levels of chemical production, equipment sales, equipment
characteristics, and end-use emissions profiles that are used by these models.
R-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEXS
Sulfur Dioxide Emissions
Sulfur dioxide (SO2) emitted into the atmosphere through natural and anthropogenic processes affects the
Earth's radiative budget through photochemical transformation into sulfate aerosols that can (1) scatter sunlight back
to space, thereby reducing the radiation reaching the Earth's surface; (2) affect cloud formation; and (3) affect
atmospheric chemical composition (e.g., stratospheric ozone, by providing surfaces for heterogeneous chemical
reactions). The overall effect of SO2 derived aerosols on radiative forcing is believed to be negative (IPCC 1996).
However, because SO2 is short-lived and unevenly distributed through the atmosphere, its radiative forcing impacts
are highly uncertain. Sulfur dioxide emissions have been provided below in Table S-l. .
The major source of SO2 emissions in the United States was the burning of sulfur containing fuels, mainly
coal. Metal smelting and other industrial processes also released significant quantities of SO2. As a result, the
largest contributors to U.S. emissions of SO2 were electric utilities, accounting for 63 percent in 2000 (see Table S-
2). Coal combustion accounted for approximately 94 percent of SO2 emissions from electric utilities in the same
year. The second largest source was industrial fuel combustion, which produced 4 percent of 2000 SO2 emissions.
Overall, SO2 emissions in the United States decreased by 23 percent from 1990 to 2000. The majority of this
decline came from reductions from electric utilities, primarily due to increased consumption of low sulfur coal from
surface mines in western states.
Sulfur dioxide is important for reasons other than its effect on radiative forcing. It is a major contributor to
the formation of urban smog and acid rain. As a contributor to urban smog, high concentrations of SO2 can cause
significant increases in acute and chronic respiratory diseases. In addition, once SO2 is emitted, ,it is chemically
transformed in the atmosphere and returns to earth as the primary contributor to acid deposition, or acid rain. Acid
rain has been found to accelerate the decay of building materials and paints, and to cause the acidification of lakes
and streams and damage trees. As a result of these harmful effects, the United States has regulated the emissions of
SO2 under the Clean Air Act. The EPA has also developed a strategy to control these emissions via four programs:
(1) the National Ambient Air Quality Standards program,1 (2) New Source Performance Standards,2 (3) the New
Source Review/Prevention of Significant Deterioration Program,3 and (4) the sulfur dioxide allowance program.4
References •
EPA (2001) National Air Pollutant Emissions Trends Report, 1900-2000, U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards, Research Triangle Park, NC. ;
1 [42 U.S.C § 7409, CAA § 109]
2 [42 U.S.C § 7411, CAA § 111]
3 [42 U.S.C § 7473, CAA § 163]
4 [42 U.S.C § 7651, CAA § 401]
S-1
-------
Ta&le S-1:Sflj Emissions (Ggl
Sector/Source
19901
1995
1996
1997
1998
1999
2000
Energy 20,1361
Stationary Combustion 18,4071
Mobile Combustion 1,3391
Oil and Gas Activities 3901
Industrial Processes 1,3061
Chemical Manufacturing 2691
Metals Processing 6581
Storage and Transport 61
Other Industrial Processes 3621
Miscellaneous' 111
Solvent Use 01
Degreasing 01
Graphic Arts 01
Dry Cleaning NAl
Surface Coating 01
Other Industrial 01
Non-Industrial NAl
Agriculture NA|
Agricultural Burning NAI
Waste 391
Waste Combustion 391
Landfills 01
Wastewater Treatment 01
Miscellaneous Waste 01
16,247
14,724
1,189
334
1,117
260
481
2
365
9
1
0
0
0
0
0
NA
NA
NA
43
42
0
1
0
16,641
14,726
1,612
304
958
: 231
354
5
! 354
15
1
0
0
0
0
1
NA
NA
NA
29
28
1
0
0
17,052
15,104
1,636
312
993
235
369
5
371
14
1
0
0
0
0
1
NA
NA
NA
30
29
1
0
0
17,157
15,192
1,655
310
996
237
367
5
376
11
1
0
0
0
0
1
NA
NA
NA
31
30
1
0
0
16,517
14,540
1,668
309
992
238
363
5
376
11
1
0
0
0
0
1
NA
NA
NA
31
30
1
0
0
Total
21,4811
Source: (EPA 2000)
* Miscellaneous includes other combustion and fugitive dust categories.
NA (Not Available)
Note: Totals may not sum due to independent rounding.
Table S-2: SO* Emissions frim Electric Utilities [Ggl
Fuel Type
Coal
Petroleum
Natural Gas
Misc. Internal Combustion
Other
Total
19901!::;'
13.807iR
580H
45 H|
NAB!
K432E2*
1995
10,526
375
8
50
NA
10,959
1996
11,073
417
6
48
4
11,549
1997
11,444
466
5
51
4
11,971
1998
11,313
691
5
52
110
12,171
1999
10,729
580
6
53
112
11,479
2000
9,728
464
8
54
80
10,333
Source: (EPA 2000)
Note: Totals may not sum due to independent rounding. \
15,435
13,496
1,626
314
1,031
243
373
5
392
19
1
0
0
0
0
1
NA
NA
NA
32
31
1
0
0
17,408
17,629
18,076
18,185
17,541
16,499
S-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX T
Complete List of Source Categories
Chapter/Source
Gas(es)
Energy
Carbon Dioxide Emissions from Fossil Fuel Combustion
Carbon Stored in Products from Non-Energy Uses of Fossil Fuels
Stationary Combustion (excluding C02)
Mobile Combustion (excluding CO?)
Coal Mining
Natural Gas Systems
Petroleum Systems
Municipal Solid Waste Combustion
Natural Gas Flaring and Ambient Air Pollutant Emissions from Oil and Gas Activities
Indirect C02 fom CH4 Oxidation
International Bunker Fuels
Wood Biomass and Ethanol Consumption
C02
C02 !
CH4, N20, CO, NOx, NMVOC
CH4, N20, CO, NOx, NMVOC
CH4
cm
CH4
C02, NzO
C02, CO, NOx, NMVOC
C02
C02, CH4, N20, CO, NOx, NMVOC
C02
Industrial Processes
Iron and Steel Production
Cement Manufacture
Ammonia Manufacture
Lime Manufacture
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Ferroalloy Production
Titanium Dioxide Production
Carbon Dioxide Consumption
Petrochemical Production
Silicon Carbide Production
Adipic Acid Production
Nitric Acid Production
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production
Semiconductor Manufacture
Electrical Transmission and Distribution
Magnesium Production and Processing
Industrial Sources of Ambient Air Pollutants
C02
C02
C02
C02
C02
C02
C02
C02
C02
N20
N20
MFCs, PFCsa
C02, CF4, C2Fe
HFC-23
HFCs, PFCs, SFe"
SFe
SFe ;
CO, NOx, NMVOC
Solvent Use
CO, NOx, NMVOC
Agriculture
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Soil Management
Agricultural Residue Burning
CH4, N20
CH4
N20
CH4, N2Q, CO. NOx
Land-Use Change and Forestry
Changes in Forest Carbon Stocks
Changes in Carbon Stocks in Urban Trees
Changes in Agricultural Soil Carbon Stocks
Changes in Yard Trimming Carbon Stocks in Landfills
C02 (sink)
C02 (sink)
C02 (sink)
CQ2 (sink)
Waste
Landfills
Wastewater Treatment
Human Sewage
Waste Sources of Ambient Air Pollutants
CH4
CH4
N20
CO, NOx, NMVOC
a In 1999, included HFC-23, HFC-125, HFC-134a, HFC-143a, HFC-152a, HFC-227ea, HFC-236fa, HFC-4310mee, C4ho, CeFw, PFC/PFPEs
b Included such gases as HFC-23, CF4, C2Fe, SFe '
T-1
-------
-------
ANNEX U
IPCC Reference Approach for Estimating C02 Emissions from Fossil Fuel
Combustion
It is possible to estimate carbon dioxide (CO2) emissions from fossil fuel consumption using alternative
methodologies and different data sources than those described in Annex A. For example, the UNFCCC reporting
guidelines request that countries, in addition to their "bottom-up" sectoral methodology, to complete a "top-down"
Reference Approach for estimating CC>2 emissions from fossil fuel combustion. Section 1.3 of the Revised 1996
IPCC Guidelines for National Greenhouse Gas Inventories: Reporting Instructions states, "If a detailed, Sectoral
Approach for energy has been used for the estimation of CO2 from fuel combustion you are still asked to
complete...the Reference Approach...for verification purposes" (IPCC/UNEP/OECD/IEA 1997).; This reference
method estimates fossil fuel consumption by adjusting national aggregate fuel production data for imports, exports,
and stock changes rather than relying on end-user consumption surveys. The basic principle is that once carbon-
based fuels are brought into a national economy, they are either saved in some way (e.g., stored in products, kept in
fuel stocks, or left unoxidized in ash) or combusted, and therefore the carbon in them is oxidized and released into
the atmosphere. Accounting for actual consumption of fuels at the sectoral or sub-national level is not required.
The following discussion provides the detailed calculations for estimating CO2 emissions from fossil fuel
combustion from the United States using the IPCC-recommended Reference Approach.
Step 1: Collect and Assemble Data in Proper Format
To ensure the comparability of national inventories, the IPCC has recommended that countries report
energy data using the International Energy Agency (IEA) reporting convention. National energy statistics were
collected in physical units from several DOE/EIA documents in order to obtain the necessary data on production,
imports, exports, and stock changes (EIA 2001a). :
It was necessary to make a number of modifications to these data to generate more accurate apparent
consumption estimates of these fuels. The first modification adjusts for consumption of fossil fuel feedstocks
accounted for in the Industrial Processes chapter, which include unspecified coal for coal coke used in iron and steel
production, natural gas used for ammonia production, and petroleum coke used in the production of aluminum,
ferroalloys, and titanium dioxide. The second modification adjusts for consumption of bunker fuels, which refer to
quantities of fuels used for international transportation estimated separately from U.S. totals. The third modification
consists of the addition of U.S. territories data that are typically excluded from the national aggregate energy
statistics. The territories include Puerto Rico, U.S. Virgin Islands, Guam, American Samoa, Wake Island, and U.S.
Pacific Islands. These data, as well as the production, import, export, and stock change statistics, are presented in
Table U-l. :
The carbon content of fuel varies with the fuel's heat content. Therefore, for an accurate estimation of CO2
emissions, fuel statistics were provided on an energy content basis (e.g., BTUs or joules). Because detailed fuel
production statistics are typically provided in physical units (as in Table U-l), they were converted to units of
energy before CO2 emissions were calculated. Fuel statistics were converted to their energy equivalents by using
conversion factors provided by DOE/EIA. These factors and their data sources are displayed in Table U-2. The
resulting fuel type-specific energy data are provided in Table U-3.
Step 2: Estimate Apparent Fuel Consumption
The next step of the IPCC Reference Approach is to estimate "apparent consumption" of fuels within the
country. This requires a balance of primary fuels produced, plus imports, minus exports, and adjusting for stock
changes. In this way, carbon enters an economy through energy production and imports (and decreases in fuel
stocks) and is transferred out of the country through exports (and increases in fuel stocks). Thus, apparent
consumption of primary fuels (including crude oil, natural gas liquids, anthracite, bituminous, subbituminous and
lignite coal, and natural gas) can be calculated as follows:
U-1
-------
Apparent Consumption = Production + Imports - Exports - Stock Change
Flows of secondary fuels (e.g., gasoline, residual fuel, coke) should be added to primary apparent
consumption. The production of secondary fuels, however, should be ignored in the calculations of apparent
consumption since the carbon contained in these fuels is already accounted for in the supply of primary fuels from
which they were derived (e.g., the estimate for apparent consumption of crude oil already contains the carbon from
which gasoline would be refined). Flows of secondary fuels should therefore be calculated as follows:
Secondary Consumption = Imports - Exports - Stock Change
Note that this calculation can result in negative numbers for apparent consumption of secondary fuels. This
result is perfectly acceptable since it merely indicates a net export or stock increase in the country of that fuel when
domestic production is not considered.
Next, the apparent consumption and secondary consumption need to be adjusted for feedstock uses of fuels
accounted for in the Industrial Processes chapter, international bunker fuels, and U.S. territory fuel consumption.
Bunker fuels and feedstocks accounted for in the Industrial Processes chapter are subtracted from these estimates,
while fuel consuption in U.S. territories is added.
i
The IPCC Reference Approach calls for estimating apparent fuel consumption before converting to a
common energy unit. However, certain primary fuels in the United States (e.g., natural gas and steam coal) have
separate conversion factors for production, imports, exports, and stock changes. In these cases, it is not appropriate
to multiply apparent consumption by a single conversion! factor since each of its components have different heat
contents. Therefore, United States fuel statistics were converted to their heat equivalents before estimating apparent
consumption. Results are provided in Table U-2. ;
Step 3: Estimate Carbon Emissions
Once apparent consumption is estimated, the remaining calculations are virtually identical to those for the
"bottom-up" Sectoral Approach (see Annex A). That is:
• Potential COj emissions were estimated using fuel-specific carbon coefficients (see Table U-3).1
• The carbon in products from non-energy uses of fossil fuels (e.g., plastics or asphalt) was then estimated
and subtracted (see Table U-4).
• Finally, to obtain actual CO2 emissions, net emissions were adjusted for any carbon that remained
unoxidized as a result of incomplete combustion (e.g., carbon contained in ash or soot).2
Step 4: Convert to COz Emissions \
Because the IPCC reporting guidelines recommend that countries report greenhouse gas emissions on a full
molecular weight basis, the final step in estimating CC>2 'emissions from fossil fuel consumption was converting
from units of carbon to units of CO2. Actual carbon emissions were multiplied by the molecular-to-atomic weight
ratio of COz to carbon (44/12) to obtain total carbon dioxide emitted from fossil fuel combustion in teragrams (Tg).
The results are contained in Table U-5. :
Comparison Between Sectoral and Reference Approaches
These two alternative approaches can both produce reliable estimates that are comparable within a few
percent. The major difference between methodologies employed by each approach lies in the energy data used to
derive carbon emissions (i.e., the actual surveyed consumption for the Sectoral Approach versus apparent
' Carbon coefficients from EIA were used wherever possible. Because EIA did not provide coefficients for coal, the
IPCC-recommended emission factors were used in the top-down calculations for these fuels. See notes in Table U-4 for more
specific source information.
2 For the portion of carbon that is unoxidized during coal combustion, the IPCC suggests a global average value of 2
percent. However, because combustion technologies in the United States are more efficient, the United States inventory uses 1
percent in its calculations for petroleum and coal and 0.5 percent for natural gas.
U-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
consumption derived for the Reference Approach). In theory, both approaches should yield identical results. In
practice, however, slight discrepancies occur. For the United States, these differences are discussed below.
Differences in Total Amount of Energy Consumed
Table U-73 summarizes the differences between the Reference and Sectoral approaches in estimating total
energy consumption in the United States. Although theoretically the two methods should arrive at the same estimate
for U.S. energy consumption, the Reference Approach provides an energy total that is 2.9 percent lower than the
Sectoral Approach for 2000. The greatest difference lies in the higher estimate of petroleum consumption with the
Sectoral Approach (3.5 percent).
There are several potential sources for the discrepancies in consumption estimates:
• Product Definitions. The fuel categories in the Reference Approach are different from those used in the
Sectoral Approach, particularly for petroleum. For example, the Reference Approach estimates apparent
consumption for crude oil. Crude oil is not typically consumed directly, but refined into other products. As
a result, the United States does not focus on estimating the energy content of the various grades of crude
oil, but rather estimating the energy content of the various products resulting from crude oil refining. The
United States does not believe that estimating apparent consumption for crude oil, and the resulting energy
content of the crude oil, is the most reliable method for the United States to estimate its energy
consumption. Other differences in product definitions include using sector-specific coal statistics in the
Sectoral Approach (i.e., residential, commercial, industrial coking, industrial other, and transportation
coal), while the Reference Approach characterizes coal by rank (i.e. anthracite, bituminous, etc.). Also, the
liquefied petroleum gas (LPG) statistics used in the bottom-up calculations are actually a composite
category composed of natural gas liquids (NGL) and LPG.
• Heat Equivalents. It can be difficult to obtain heat equivalents for certain fuel types, particularly for
categories such as "crude oil" where the key statistics are derived from thousands of producers in the
United States and abroad. For heat equivalents by coal rank, it was necessary to refer back to EIA's State
Energy Data Report 1992 (1994) because this information is no longer published.
• Possible inconsistencies in U.S. Energy Data. The United States has not focused its energy data collection
efforts on obtaining the type of aggregated information used in the Reference Approach. Rather, the
United States believes that its emphasis on collection of detailed energy consumption data is a more
accurate methodology for the United States to obtain reliable energy data. Therefore, top-down statistics
used in the Reference Approach may not be as accurately collected as bottom-up statistics applied to the
Sectoral Approach.
• Balancing Item. The Reference Approach uses apparent consumption estimates while the Sectoral
Approach uses reported consumption estimates. While these numbers should be equal, there always seems
to be a slight difference that is often accounted for in energy statistics as a "balancing item." !
Differences in Estimated CO2 Emissions
Given these differences in energy consumption data, the next step for each methodology involved
estimating emissions of CO2. Table U-8 summarizes the differences between the two methods in estimated carbon
emissions. :
As- mentioned above, for 2000, the Reference Approach resulted in a 2.9 percent lower estimate of energy
consumption in the United States than the Sectoral Approach. However, the resulting emissions estimate for the
Reference Approach was 0.6 percent lower. Both methods' estimates of natural gas emissions are almost exactly the
same, but coal emission estimates from the Reference Approach are lower than the Sectoral Approach, while higher
for petroleum. Potential reasons for these differences may include:
• Product Definitions. Coal data is aggregated differently in each methodology, as noted above. The format
used for the Sectoral Approach likely results in more accurate estimates than in the Reference Approach.
Also, the Reference Approach relies on a "crude oil" category for determining petroleum-related emissions.
for 1996.
' Although complete energy consumption data and calculations are not presented, comparison tables are also presented
U-3
-------
Given the many sources of crude oil in the United States, it is not an easy matter to track potential
differences in carbon content between many different sources of crude, particularly since information on
the carbon content of crude oil is not regularly collected.
• Carbon Coefficients. The Reference Approach relies on several default carbon coefficients by rank
provided by IPCC (IPCC/UNEP/OECD/IEA 1997), while the Sectoral Approach uses annually updated
category-specific coefficients by sector that are likely to be more accurate. Also, as noted above, the
carbon coefficient for crude oil is more uncertain than that for specific secondary petroleum products, given
the many sources and grades of crude oil consumed in the United States.
Although the two approaches produce similar results, the United States believes that the "bottom-up"
Sectoral Approach provides a more accurate assessment 'of CO2 emissions at the fuel level. This improvement in
accuracy is largely a result of the data collection techniques used in the United States, where there has been more
emphasis on obtaining the detailed products-based information used in the Sectoral Approach than obtaining the
aggregated energy flow data used in the Reference Approach. The United States believes that it is valuable to
understand both methods. .
References
EIA (2001a) Annual Energy Review 2000 and other EIA data. Energy Information Administration, U.S. Department
of Energy, Washington, DC. September, DOE/EIA- 0384(00)-annual.
EIA (2QQlb) Monthly Energy Review, Energy Information Administration, U.S. Department of Energy, Washington,
DC. November. DOE/EIA 0035(00)-monthly.
EIA (2000) Emissions of Greenhouse Gases in the United States 1999. Energy Information Administration, U.S.
Department of Energy, Washington, DC. Draft. Octobers, 1999, DOE/EIA-0535(99)-annual.
EIA (1995-2001) Petroleum Supply Annual, Energy Information Administration, U.S. Department of Energy,
Washington, DC, Volume I. DOE/EIA-0340.
EIA (1994) State Energy Data Report 1992, Energy Information Administration, U.S. Department of Energy,
Washington, DC. DOE/EIA 0214(92)-annual.
IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Paris:
Intergovernmental Panel on Climate Change, United Nations Environment Programme, Organization for Economic
Co-Operation and Development, International Energy Agency.
U-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
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Table U-5:2000 Non-Energy Carbon Stored in Products
Fuel Type
Coal
Natural Gas
Asphalt & Road Oil
LPG
Lubricants
Pentanes Plus
Petrochemical Feedstocks
Petroleum Coke
Special Naptha
Waxes/Misc.
Misc. U.S. Territories Petroleum
Total
Consumption for Carbon
Non-Energy Use Carbon Coefficients Content Fraction Carbon Stored
CTBtu) (TgCarbon/QBtu) (Tq Carbon) Sequestered (TaCO,Ea\
26.4
342.4
1,275.7
1,707.3
370.6
286.8
a
141.4
97.4
a
a
25.56
14.47
20.62
16.88
20.24
18.24
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27.85
19.86
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121
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135
16.5
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.. i-o. lermones petroleum, petrochemical Feedstocks and Waxes/Misc. are not shown because these categories are
aggregates of numerous smaller components.
Note: Totals may not sum due to independent rounding. ;
Table U-6: 2000 Reference Approach CO? Emissions from Fossil Fuel Consumption (Tg Cfc Eq. unless otherwise
noted!
Fuel Category
Coal
Petroleum
Natural Gas
Total
Potential
Emissions
1,986.4
2,720.3
1,218.8
5,925.5
Carbon
Sequestered
1.9
270.0
11.5
283.4
Net
Emissions
1,984.5
2,450.3
1,207.3
5,642.2
Fraction
Oxidized
99.0%
99.0%
99.5%
-
Total
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2,425.8
1,201.3
5,591.8
U-9
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ANNEX V
Sources of Greenhouse Gas Emissions Excluded
Although this report is intended to be a comprehensive assessment of anthropogenic1 sources and sinks of
greenhouse gas emissions for the United States, certain sources have been identified yet excluded from the estimates
presented for various reasons. Before discussing these sources, however, it is important to note that processes or
activities that are not anthropogenic in origin or do not result in a net source or sink of greenhouse gas emissions are
intentionally excluded from a national inventory of anthropogenic greenhouse gas emissions. In general, processes
or activities that are not anthropogenic are considered natural (i.e., not directly influenced by human activity) in
origin and, as an example, would include the following:
i
« Volcanic eruptions
• Carbon dioxide (CO2) exchange (i.e., uptake or release) by oceans
• Natural forest fires2 \
• Methane (CH4) emissions from wetlands not affected by human induced land-use changes ;
Some processes or activities may be anthropogenic in origin but do not result in net emissions • of
greenhouse gases, such as the respiration of CO2 by people or domesticated animals.3 Given a source category that
is both anthropogenic and results in net greenhouse gas emissions, reasons for excluding a source related to an
anthropogenic activity include one or more of the following: • ;
• There is insufficient scientific understanding to develop a reliable method for estimating emissions at a
national level.
• Although an estimating method has been developed, data were not adequately available to calculate
emissions.
• Emissions were implicitly accounted for within another source category (e.g., CO2 from Fossil Fuel
Combustion).
It is also important to note that the United States believes the exclusion of the sources discussed below
introduces only a minor bias in its overall estimate of U.S. greenhouse gas emissions.
Separate Cruise and LTD Emissions from the Combustion of Jet Fuel
The combustion of jet fuel by aircraft results in emissions of CEU, N2O, CO, NOX, and NMVOCs. The
emissions per mass of fuel combusted during landing/take-off (LTD) operations differ from those during aircraft
cruising. Accurate estimation of these emissions requires a detailed accounting of LTD cycles and fuel consumption
during cruising by aircraft model (e.g., Boeing 747-400) as well as appropriate emission factors. Sufficient data for
separately calculating near ground-level emissions during landing and take-off and cruise altitude emissions by
aircraft model were not available for this report. (See Revised 1996IPCC Guidelines for National Greenhouse Gas
Inventories: Reference Manual, pp. 1.93 - 1.96) '•
1 The term "anthropogenic", in this context, refers to greenhouse gas emissions and removals that are a direct result of
human activities or are the result of natural processes that have been affected by human activities (IPCC/UNEP/OECD/IEA
1997).
2 In some cases forest fires that are started either intentionally or unintentionally are viewed as mimicking natural
burning processes that have been suppressed by other human forest management activities. The United States does not consider
forest fires within its national boundaries to be a net source of greenhouse emissions.
3 Respiration of CO2 by biological organisms is simply part of the broader global carbon cycle that also includes uptake
of CO2 by photosynthetic organisms.
V-1
-------
COz from Burning in Coal Deposits and Waste Piles
Coal is periodically burned in deposits and waste piles. It has been estimated that the burning of coal in
deposits and waste piles would represent less than 1.3 percent of total U.S. coal consumption, averaged over ten-
years. Because there is currently no known source of data on the quantity of coal burned in waste piles and there is
uncertainty as to the fraction of coal oxidized during such burnings, these CO2 emissions are not currently estimated.
Further research would be required to develop accurate emission factors and activity data for these emissions to be
estimated (see Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual, p.
1.112-1.113). I
I
Fossil COz from Petroleum and Natural Gas Wells, COa Separated from Natural Gas, and C(h from Enhanced
Oil Recovery (EOR)
Petroleum and natural gas well drilling, petroleum and natural gas production, and natural gas
processing—including removal of COz—may result in emissions of CO2 that was at one time stored in underground
formations.
Carbon dioxide and other gases are naturally present in raw natural gas, in proportions that vary depending
on the geochemical circumstances that caused the formation of the gas. After the heavier gases are removed during
processing, small amounts of carbon dioxide may be allowed to remain in the natural gas. If the amount of CC>2
sufficiently lowers the heating value of the natural gas, it is typically extracted by amine scrubbing and, in most
cases, released into the atmosphere. These emissions can be estimated by calculating the difference between the
average carbon dioxide content of raw natural gas and the carbon dioxide content of pipeline gas. The Energy
Information Administration (EIA) estimates that annual CO2 emissions from scrubbing are about 15 Tg CO2 Eq.
Because of imprecision in the reporting of U.S. natural gas production and processing, emissions estimates from
energy production sources may be double-counted or under^-reported, and thus are uncertain.
Carbon dioxide is also injected into underground deposits to increase crude oil reservoir pressure in a field
technique known as enhanced oil recovery (EOR). It is thought that much of the injected CO2 may be effectively
and permanently sequestered, but the fraction of injected CD2 that is re-released remains uncertain. The fraction re-
released varies from well to well depending upon the field geology and the gas capture/re-injection technology
employed at the wellhead. Over time, carbon dioxide may also seep into the producing well and mix with the oil
and natural gas present there. If the gas portion of this mixture has a sufficiently high energy content, it may be
collected and sent to a natural gas plant; if not, it may be vented or flared. The EIA estimates that the amount of
C02 used for EOR is on the order of 44 Tg CO2 Eq., of which emissions would be some fraction yet to be defined.
This figure is based on the difference between U.S. Department of Commerce sales figures for industrial CO2 (62 Tg
C0j Eq.) minus the 18 Tg CO2 Eq. reported by the Freedonia Group that is used for purposes other than EOR.
Further research into EOR is required before the resulting CO2 emissions can be adequately quantified. (See Carbon
Dioxide Consumption in the Industrial Processes chapter).
Carbon Sequestration in Underground Injection Wells
Data for sequestration of carbon in underground injection wells is obtained from the EPA Toxic Release
Inventory (EIA 2000). The carbon content of wastes reported in the EPA TRI as being injected into underground
injection wells is estimated from the TRI data, and the carbon is assumed to be sequestered. The sequestration of
underground injection carbon is one of the many elements in calculating the storage factor for petrochemical
feedstock (see Annex B). The "base year" for this storage factor calculation is 1998 and only EPA TRA data for
calendar year 1998 is used in the storage factor calculation. Further research is required if the entire time series for
this potential sink is to be fully quantified.
CH4 from Abandoned Coal Mines
Abandoned coal mines are a source of CH4 emissions. In general, many of the same factors that affect
emissions from operating coal mines will affect emissions from abandoned mines such as the permeability and
gassiness of the coal, the mine's depth, geologic characteristics, and whether it has been flooded. A few gas
developers have recovered methane from abandoned mine workings; therefore, emissions from this source may be
V-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
significant. Further research and methodological development is needed if these emissions are to be bstimated. (See
Coal Mining in the Energy chapter.) •
i
COa from "Unaccounted for" Natural Gas '
There is a discrepancy between the amount of natural gas sold by producers and that reported as purchased
by consumers. This discrepancy, known as "unaccounted for" or unmetered natural gas, was assumed to be the sum
of leakage, measurement errors, data collection problems, undetected non-reporting, undetected over reporting, and
undetected under reporting. Historically, the amount of gas sold by producers has always exceeded that reportedly
purchased by consumers; therefore, some portion of unaccounted for natural gas was assumed to be a source of CO2
emissions. In other words, it was assumed that consumers were underreporting their usage of natural gas. In
DOE/EIA's energy statistics for 1996, however, reported consumption of natural gas exceeded the amount sold by
producers. Therefore, the historical explanation given for this discrepancy has lost credibility and unaccounted for
natural gas is no longer used to calculate CO2 emissions. -
COz from Shale Oil Production
Oil shale is shale saturated with kerogen.4 It can be thought of as the geological predecessor to crude oil.
Carbon dioxide is released as a by-product of the process of producing petroleum products from shale oil. As of
now, it is not cost-effective to mine and process shale oil into usable petroleum products. The only identified large-
scale oil shale processing facility in the United States was operated by Unocal during the years 1985 to 1990. There
have been no known emissions from shale oil processing in the United States since 1990 when the Unocal facility
closed.
CH4 from the Production of Carbides other than Silicon Carbide
Methane (CH4) may be emitted from the production of carbides because the petroleum coke used in the
process contains volatile organic compounds, which form CH4 during thermal decomposition. Methane emissions
from the production of silicon carbide were estimated and accounted for, but emissions from the production of
calcium carbide and other carbides were not. Further research is needed to estimate CELt emissions from the
production of calcium carbide and other carbides other than silicon carbide. (See Revised 1996IPCC Guidelines for
National Greenhouse Gas Inventories: Reference Manual, pp. 2.20 - 2.21) ;
COz from Calcium Carbide and Silicon Carbide Production
Carbon dioxide is formed by the oxidation of petroleum coke in the production of both calcium carbide and
silicon carbide. These CO2 emissions are implicitly accounted for with emissions from the combustion of petroleum
coke in the Energy chapter. There is currently not sufficient data on coke consumption to estimate emissions from
these sources explicitly. (See Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference
Manual, pp. 2.20 - 2.21) '
COz from Graphite Consumption in Ferroalloy and Steel Production
Emissions from "graphite" "wood" or "biomass" in calculating CO2 emissions from ferroalloy production,
iron and steel production or other "Industrial Processes" included in Chapter 3 of the inventory are not explicitly
calculated. It is assumed that 100% of the carbon used in ferroalloy production is derived from petroleum coke and
that all of the carbon used in iron and steel production is derived from coal coke or petroleum coke. It is possible
that some non-coke carbon is used in the production of ferroalloys and iron and steel, but no data are available to
conduct inventory calculations for sources of carbon other than petroleum coke and coal coke, used in these
processes.
4 Kerogen is fossilized insoluble organic material found in sedimentary rocks, usually shales, which can be converted
to petroleum products by distillation. >
V-3
-------
Non-fuel uses of coal coke and petroleum coke are accounted for in the Industrial Process chapter, either
directly for iron and steel, aluminum, ferroalloy, and titanium dioxide production, or indirectly by applying a storage
factor to "uncharacterized" non-fuel uses of petroleum coke and coal coke.
Non-fuel uses of wood and biomass are not accounted for in the Energy or Industrial Process chapters, as
all uses of wood and biomass are accounted for in the Land Use and Forestry chapter. It is assumed for the purposes
of the CC<2 emission calculation that no wood or other bipgenic carbon is used in any of these industrial processes.
Some biogenic carbon may be used in these industrial processes but sufficient data to estimate emissions are not
available.
Consumption of either natural or synthetic graphite is not explicitly accounted for in the Industrial Process
chapter. It is assumed that all of the carbon used in manufacturing carbon anodes for production of aluminum,
ferroalloys, and electric arc furnace (EAF) steel are derived directly from petroleum coke and coal tar pitch (a coal
coke byproduct), not from natural graphite or synthetic graphite sources. Some amount of carbon used in these
industrial processes may be derived from natural or synthetic graphite sources, but sufficient data to estimate
emissions are not currently available. :
NzO from Caprolactam Production
Caprolactam is a widely used chemical intermediate, primarily to produce nylon-6. All processes for
producing Caprolactam involve the catalytic oxidation of ammonia, with N2O being produced as a by-product.
Caprolactam production could be a significant source of N2O—it has been identified as such in the Netherlands.
More research is required to determine this source's significance because there is currently insufficient information
available on Caprolactam production to estimate emissions in the United States. (See Revised 1996IPCC Guidelines
for National Greenhouse Gas Inventories: Reference Manual, pp. 2.22 - 2.23)
NzO from Cracking of Certain Oil Fractions
In order to improve the gasoline yield in crude oil refining, certain oil fractions are processed in a
catcracker. Because crude oil contains some nitrogen, N2O emissions may result from this cracking process. There
is currently insufficient data to develop a methodology for estimating these emissions. (See Revised 1996 IPCC
Guidelines for National Greenhouse Gas Inventories: Reference Manual, p. 2.23)
CH4 from Coke Production
Coke production may result in CH4 emissions. Detailed coke production statistics were not available for
the purposes of estimating CHt emissions from this minor source. (See Petrochemical Production in the Industrial
Processes chapter and the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference
Manual, p. 2.23)
i
COz from Metal Production
Coke is used as a reducing agent in the production of some metals from their ores, including magnesium,
chromium, lead, nickel, silicon, tin, and zinc. Carbon dioxide may be emitted during the metal's production from
the oxidization of this coke and, in some cases, from the carbonate ores themselves (e.g., some magnesium ores
contain carbonate). The CO2 emissions from the carbonate ores are not presently accounted for, but their quantities
are thought to be minor. (See Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference
Manual, p. 2.37 - 2.38)
NzO from Acrylonitrile Production
Nitrous oxide may be emitted during acrylonitrile production. No methodology was available for
estimating these emissions, and therefore further research is needed if these emissions are to be included. (See
Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual, p. 2.22)
V-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
SFe from Aluminum Fluxing and Degassing
Occasionally, sulfur hexafluoride (SFe) is used by the aluminum industry as a fluxing and degassing agent
in experimental and specialized casting operations. In these cases it is normally mixed with argon, nitrogen, and/or
chlorine and blown through molten aluminum; however, this practice is not used by primary aluminum production
firms in the United States and is not believed to be extensively used by secondary casting firms. Where it does
occur, the concentration of SF6 in the mixture is small and a portion of the SFe is decomposed in the process (Waite
and Bernard 1990, Corns 1990). It has been estimated that 230 Mg of SF6 were used by the aluminum industry in
the United States and Canada (Maiss and Brenninkmeijer 1998); however, this estimate is highly uncertain.
SFe from Production/Leakage/Breakage of Soundproofed Double-glazed Windows ,
Sulfur hexafluoride (SF6) may be emitted from the production, breakage, or leakage of soundproof double-
glazed windows. No methodology was available for estimating these emissions, and therefore further research is
needed if these emissions are to be included.
SFe from Production/Leakage/Dismantling of Radar, Tracer and Night Vision Equipment
Sulfur hexafluoride (SF6) may be emitted from the production, leakage, and dismantling of radar, tracer,
and night vision equipment. Emissions from this source are believed to be minor, and no data were available for
estimating the emissions.
SFe from Applications in Sports Shoes, Tires, and Tennis Balls
Sulfur hexafluoride (SFS) may be emitted from application involving the production of sport shoes, tires,
and tennis balls. These emissions are believed to be minor, and no data were available for estimating emissions.
SFe from Applications to Trace Leakage of Pressure Vessels and Used as a Tracer Gas in Open Air
Sulfur hexafluoride (SF6) may be emitted from application involving tracer gasses to detect leakage from
pressure vessels and as a tracer gas in the open air. Although emissions from this source are believed to be minor,
emissions estimation data and methodologies were not available. :
Miscellaneous SF6 Uses
Sulfur hexafluoride may be used in foam insulation, for dry etching, in laser systems, for indoor air quality
testing, for laboratory hood testing, for chromatography, in tandem accelerators, in loudspeakers, in shock absorbers,
and for certain biomedical applications. Data need to be gathered and methodologies developed if these emissions
are to be estimated. A preliminary global assessment of aggregate emissions from these applications can be found in
Maiss, M. Brenninkmeijer, and C.A.M. Brenninkmeijer (1998).
CCh from Solvent Incineration
Carbon dioxide may be released during the incineration of solvents. Although emissions from this source
are believed to be minor, data need to be gathered and methodologies developed if these emissions are to be
estimated. Solvents are hazardous wastes, and emissions from solvent incineration were taken into account to
estimate the carbon the carbon storage factor for hazardous waste incineration. However, sufficient data is not
available to obtain a complete time series estimate for this source category. Further research is required for these
potential emissions to be fully quantified. '
NzO from Domestic House Animal Waste Deposited on Soils !
A substantial amount of liquid and solid waste is produced by domestic animals that are kept as pets. A
preliminary methodology was developed to estimate nitrous oxide (N2O) emissions from the deposition of domestic
house animal (i.e., dogs and cats) waste on lawns, fields and parks. Estimates calculated with this methodology
suggest that, in 1990, approximately 330 Gg of nitrogen originating as domestic house animal waste were deposited
on soils resulting in approximately 2.9 Tg CO2 Eq. of N2O emissions from soils. To estimate the amount of nitrogen
V-5
-------
deposited by domestic house animals, only those excretions that remained on land surfaces—as opposed to wastes
that were collected by owners and are managed as municipal solid waste—were included.
Annual dog and cat population numbers were obtained from the Pet Food Institute.5 Annual nitrogen
excretion rates were estimated from protein intake. The recommended protein intake for an average size adult of
each animal type6 was multiplied by the average amount of nitrogen per unit of protein (0.16 kg N/kg protein, from
the Revised 1996IPCC Guidelines) to estimate nitrogen consumption. It was then assumed that 95 percent of this
nitrogen was excreted, either in solid or liquid form (i.e., it was assumed that 5 percent was retained for fur and milk
production). Of the total nitrogen excretion, 90 percent was assumed to occur through liquid waste, with the balance
from solid waste7. Both cat and dog populations were divided into urban and rural fractions, using the metropolitan
and non-metropolitan human population categories, respectively, of the U.S. Census Bureau8. Both liquid and solid
wastes from the urban cat population, and solid waste from the urban dog population were assumed to be collected
(i.e., not deposited on soils). Nitrous oxide emission estimates from domestic house animal excretion were
calculated in the same manner as performed for estimating emissions from livestock excretion. Producing these
estimates involved making a number of simplifying assumptions regarding average animal size and protein
consumption, as well as the proportions of animal populations residing in urban and rural areas and the proportions
of wastes that are deposited on land. Further methodological development and data collection is required in order to
reduce the uncertainty involved in the domestic house animal excretion estimates.
COz from Food Scraps Disposed in Landfills
A certain amount of food scraps generated from food processing or as leftovers join the waste stream and
are landfilled. Nationally, an estimated 0.4 Tg CC>2 Eq. per year are stored in the form of organic carbon contained
in food scraps in landfills, acting as a carbon sink. A portion of the landfilled food scraps becomes a source of
methane emissions, which offset the sink estimates to an extent. Further data collection on the amount and
composition of food scraps generated and landfilled is required in order to reduce the uncertainty associated with
this estimate.
COz from Industrial Waste Combustion
Waste combustion is incorporated in two sections bf the energy chapter of the inventory: in the section on
CO* emissions from waste combustion, and in the calculation of emissions and storage from non-energy uses of
fossil fuels. The former section addresses fossil-derived materials (such as plastics) that are discarded as part of the
municipal wastestream and combusted (generally for energy recovery). The latter addresses two types of
combustion: hazardous waste incineration of organic materials (assumed to be fossil-derived), in which regulated
wastes are burned without energy recovery, and burning of fossil-derived materials for energy recovery. There is
one potentially significant category of waste combustion that is not included in our calculus: industrial non-
hazardous waste, burned for disposal (rather than energy recovery). Data are not readily available for this source;
further research is needed to estimate the magnitude of CC-2 ^emissions.
CH« from Land-Use Changes Including Wetlands Creation or Destruction
Wetlands are a known source of methane (CH,|) emissions. When wetlands are destroyed, CH4 emissions
may be reduced. Conversely, when wetlands are created (e.g., during the construction of hydroelectric plants), CH4
emissions may increase. Grasslands and forestlands may also be weak sinks for CBLt due to the presence of
methanotrophic bacteria that use CH4 as an energy source p.e., they oxidize CH4 to CO2). Currently, an adequate
scientific basis for estimating these emissions and sinks does not exist, and therefore further research and
methodological development is required.
5 Pet Food Institute (1999) Pet Incidence Trend Report. Pet Food Institute, Washington DC.
" Bright, S. (1999) Personal communication between Marco Alcaraz of ICF Consulting and Susan Bright of the Dupont
Animal Clinic, Washington, DC, August 1999.
' Swenson, M.J. and W.G. Reece, eds. (1993) Duke's Physiology of Domestic Animals. Cornell University Press. 11th
Edition. \
8 U.S. Census Bureau (1999)
V-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
NaO from Wastewater Treatment and Biological Processes
As a result of nitrification and denitrification processes, nitrous oxide (N2O) may be produced and emitted
from large-scale composting, small scale composting (e.g. households), post-composting of anaerobic digested
wastes, and both domestic and industrial wastewater treatment plants. Nitrogen-containing compounds are found in
composted wastes and wastewater due to the presence of both human excrement and other nitrogen- containing
constituents (e.g. garbage, industrial wastes, animal carcasses, etc.) The portion of emitted N2O that originates from
human excrement is currently estimated under the Human Sewage source category- based upon!average dietary
assumptions. The portion of emitted N2O that originates from other nitrogen-containing constituents is not currently
estimated. Further research and methodological development is needed if these emissions are to be accurately
estimated. ;
CH4 from Large and Small Scale Composting
Methane (CH4) may be released through large and small scale (e.g. household) composting. Detailed
composting data is necessary in order to estimate emissions but were not available. :
CH4 from Treatment of Dredging Sludge, Remediation of Groundwater, Intermediate Storage of Slaughter
Waste, Production of Process Water from Groundwater, and Post Composting of Anaerobic Digested Wastes.
Methane (CH4) may be released through the treatment of dredging sludge, remediation of groundwater,
intermediate storage of slaughter waste, production of process water from groundwater, and post composting of
anaerobic digested wastes. No methodology was available for estimating these emissions, and therefore further
research is needed if these emissions are to be included. ;
NzO from Applications of Anesthetics in Healthcare, Consumer Packaging of Whipped Cream, Fireworks,
Applications as Party-drug/Horns/Balloons, Laboratories, Engine Booster Fuel, and Explosives.
Nitrous oxide (N2O) may be released from anesthetic in healthcare (i.e. dentists, doctors, veterinarians, and
elderly care), consumer packaging of whipped cream, fireworks, applications as party-drug/horns/balloons,
laboratories, engine booster fuel, and explosives. Although emissions from these sources are believed to be minor,
emissions estimation data and methodologies were not available. '•
References
EPA (2000b). Toxics Release Inventory, 1998. U.S. Environmental Protection Agency, Office of Environmental
Information, Office of Information Analysis and Access, Washington, DC. Available online at
.
V-7
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V-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
ANNEX W
Constants, Units, and Conversions
Metric Prefixes
Although most activity data for the United States is gathered in customary U.S. units, these units are
converted into metric units per international reporting guidelines. The following table provides a guide for
determining the magnitude of metric units.
Table DIM: Guide to Metric Unit Prefixes
Prefix/Symbol
alto (a)
femto (f)
pico (p)
nano (n)
micro (|.i )
milli (m)
centi (c)
dec! (d)
deca (da)
hecto (h)
kilo (k)
mega (M)
giga (G)
tera (T)
peta (P)
exa (E)
Factor
10-18
io-15
10-12
io-9
10'6
10'3
io-2
io-1
10
IO2
103
10«
10«
10'2
1015
1018
Unit Conversions
kilogram
pound
short ton
metric ton
cubic meter
cubic foot
1 U.S. gallon
1 barrel (bbl)
1 barrel (bbl)
1 liter
1 foot
1 meteir =
1 mile =
1 kilometer =
2.205 pounds
0.454 kilograms
2,000 pounds
1,000 kilograms =
35.315 cubic feet
0.02832 cubic meters
3.785412 liters
0.159 cubic meters
42 U.S. gallons
0.1 cubic meters
0.3048 meters
3.28 feet
1.609 kilometers
0.622 miles
0.9072 metric tons
1.1023 short tons
1 acre = 43,560 square feet = 0.4047 hectares = 4,047 square meters
1 square mile = 2.589988 square kilometers
To convert degrees Fahrenheit to degrees Celsius, subtract 32 and multiply by 5/9
To convert degrees Celsius to Kelvin, add 273.15 to the number of Celsius degrees
W-1
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Density Conversions1
Methane
Carbon dioxide
1 cubic meter
1 cubic meter
0.67606 kilograms
1.85387 kilograms
Natural gas liquids 1 metric ton = 11.6 barrels ,= 1,844.2 liters
Unfinished oils 1 metric ton = 7.46 barrels != 1,186.04 liters
Alcohol 1 metric ton = 7.94 barrels ;= 1,262.36 liters
Liquefied petroleum gas 1 metric ton = 11.6 barrels = 1,844.2 liters
Aviation gasoline 1 metric ton = 8.9 barrels = 1,415.0 liters
Naphtha jet fuel 1 metric ton = 8.27 barrels ; = 1,314.82 liters
Kerosene jet fuel 1 metric ton = 7.93 barrels ;= 1,260.72 liters
Motor gasoline 1 metric ton = 8.53 barrels := 1,356.16 liters
Kerosene 1 metric ton = 7.73 barrels ;= 1,228.97 liters
Naphtha 1 metric ton = 8.22 barrels i = 1,306.87 liters
Distillate 1 metric ton = 7.46 barrels ' = 1,186.04 liters
Residual oil 1 metric ton = 6.66 barrels = 1,058.85 liters
Lubricants 1 metric ton = 7.06 barrels = 1,122.45 liters
Bitumen 1 metric ton = 6.06 barrels = 963.46 liters
Waxes 1 metric ton = 7.87 barrels = 1,251.23 liters
Petroleum coke 1 metric ton = 5.51 barrels = 876.02 liters
Petrochemical feedstocks 1 metric ton = 7.46 barrels = 1,186.04 liters
Special naphtha 1 metric ton = 8.53 barrels = 1,356.16 liters
Miscellaneous products 1 metric ton = 8.00 barrels = 1,271.90 liters
Energy Conversions
Converting Various Energy Units to Joules
The common energy unit used in international reports of greenhouse gas emissions is the joule. A joule is
the energy required to push with a force of one Newton for one meter. A terajoule (TJ) is one trillion (1012) joules.
A British thermal unit (Btu, the customary U.S. energy unit) is the quantity of heat required to raise the temperature
of one pound of water one degree Fahrenheit at or near 39r2 Fahrenheit.
2.388x10" calories !
23.88 metric tons of crude oil equivalent
947.8 million Btus :
277,800 kilowatt-hours i
1TJ;
Converting Various Physical Units to Energy Units
Data on the production and consumption of fuels are first gathered in physical units. These units must be
converted to their energy equivalents. The values in the following table of conversion factors can be used as default
factors, if local data are not available. See Appendix A of EIA's Annual Energy Review 1997 (EIA 1998) for more
detailed information on the energy content of various fuels.
'Reference: EIA(1998a)
W-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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Table W-2: Cinversiin Factors ti Energy Units (Heat Equivalents)
Fuel Type (Units)
Factor
Solid Fuels (Million Btu/Short ton)
Anthracite coal 22.573
Bituminous coal 23.89
Sub-bituminous coal 17.14
Lignite 12.866
Coke 24.8 '
Natural Gas (Btu/Cubic foot) 1,027
Liquid Fuels (Million Btu/Barrel)
Crude oil 5.800
Natural gas liquids and LRGs 3.777
Other liquids 5.825
Motor gasoline 5.253
Aviation gasoline 5.048
Kerosene 5.670
Jet fuel, kerosene-type 5.670 !
Distillate fuel 5.825
Residual oil 6.287 - ,
Naphtha for petrochemicals 5.248 ',
Petroleum coke 6.024 - '
Other oil for petrochemicals 5.825 ;
Special naphthas 5.248
Lubricants 6.065 '
Waxes 5.537
Asphalt 6.636 '•
Still gas 6.000 ;
Misc. products 5.796 '•
Note: For petroleum and natural gas, Annual Energy Review 1997 (EIA 1998b). For coal ranks, State Energy Data Report 1992 (EIA1993).
All values are given in higher heating values (gross calorific values).
References
EIA (1998a) Emissions of Greenhouse Gases in the United States, DOE/EIA-0573(97), Energy Information
Administration, U.S. Department of Energy. Washington, DC. October.
EIA (1998b) Annual Energy Review, DOE/EIA-0384(97), Energy Information Administration, U.S.
Department of Energy. Washington, DC. July. ;
EIA (1993) State Energy Data Report 1992, DOE/EIA-0214(93), Energy Information Administration, U.S.
Department of Energy. Washington, DC. December.
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W-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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ANNEX X
Abbreviations
AAPFCO American Association of Plant Food Control Officials
AFEAS Alternative Fluorocarbon Environmental Acceptability Study
AGA American Gas Association
ARC American Plastics Council
ASAE American Society of Agricultural Engineers
BEA Bureau of Economic Analysis, U.S. Department of Commerce
BODs Biochemical oxygen demand over a 5-day period
BTS Bureau of Transportation Statistics, U.S. Department of Transportation
Btu British thermal unit
CAAA Clean Air Act Amendments of 1990
CAPP Canadian Association of Petroleum Producers
C&EN Chemical and Engineering News
CFC Chlorofluorocarbon
CFR Code of Federal Regulations
CMA Chemical Manufacturer's Association
CMOP Coalbed Methane Outreach Program
CVD Chemical vapor deposition
DESC Defense Energy Support Cenler-DoD's defense logistics agency
DIC Dissolved inorganic carbon
DOC U.S. Department of Commerce
DoD U.S. Department of Defense
DOE U.S. Department of Energy
DOI U.S. Department of the Interior
DOT U.S. Department of Transportation
EIA Energy Information Administration, U.S. Department of Energy
ElIP Emissions Inventory Improvement Program
EOR Enhanced oil recovery
EPA U.S. Environmental Protection Agency
FAA Federal Aviation Administration
FAO Food and Agricultural Organization
FCCC Framework Convention on Climate Change
FEB Fiber Economics Bureau
FHWA Federal Highway Administration
GAA Governmental Advisory Associates
GCV Gross calorific value
GDP Gross domestic product
GHG Greenhouse gas
GRI Gas Research Institute
GSAM Gas Systems Analysis Model
GWP Global warming potential
HBFC Hydrobromofluorocarbon
HCFC Hydrochlorofluorocarbon
HDGV Heavy duty gas vehicle
HDDV Heavy duty diesel vehicle
HOPE High density polyethylene
HFC Hydrofluorocarbon
HFE Hydrofluoroethers
ICAO International Civil Aviation Organization
IEA International Energy Association
IISRP International Institute of Synthetic Rubber Products
ILENR Illinois Department of Energy and Natural Resources
IMO International Maritime Organization
IPAA Independent Petroleum Association of America
IPCC Intergovernmental Panel on Climate Change
LDDT Light duty diesel truck
LDDV Light duty diesel vehicle
LDGV Light duty gas vehicle
X-1
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LDGT Light duly gas truck
LOPE Low density polyethylene
LEV Low emission vehicles
LFG Landfill gas
LFGTE Landfill gas-to-energy
LLPDE Linear low density polyethylene
LMOP EPA's Landfill Methane Outreach Program
LPG Liquefied petroleum gas(es)
LTD Landing and take-off
LULUCF Land use, land-use change, and forestry
MC Motorcycle
MCF Methane conversion factor
MMS Minerals Management Service i
MMTCE Million metric tons carbon equivalent
MSHA Mine Safety and Health Administration ;
MSW Municipal solid waste
NAPAP National Acid Precipitation and Assessment Program j
NASS USDA's National Agriculture Statistics Service
NCV Net calorific value
NIAR Norwegian Institute for Air Research
NMVOC Non-methane volatile organic compound ;
NOx Nitrogen Oxides
NRCS Natural Resources Conservation Service
NSCR Non-selective catalytic reduction
NVFEL National Vehicle Fuel Emissions Laboratory
OAQPS EPA Office of Air Quality Planning and Standards
ODS Ozone depleting substances
OECD Organization of Economic Co-operation and Development
QMS EPA Office of Mobile Sources
ORNL Oak Ridge National Laboratory
OSHA Occupational Safely and Health Administration
OTA Office of Technology Assessment
PPC Precipitated calcium carbonate
PFC Perfluorocarbon
PFPE Perfluoropolyelher
POTW Publicly Owned Treatment Works ;
Ppmv Parts per million(106) by volume
Ppbv Parts per billion (109) by volume
Pplv Parts per trillion (1012) by volume
PVC Polyvinyl chloride
RCRA Resource Conservation and Recovery Act
SAE Society of Automotive Engineers
SBSTA Subsidiary Body for Scientific and Technical Advice
SCR Selective catalytic reduction
SNG Synthetic natural gas
SWANA Solid Waste Association of North America
Tbtu Trillion Btu
TgCOaEq Teragrams carbon dioxide equivalent
TJ Terajoule
TSOF Hazardous waste treatment, storage, and disposal facility
TVA Tennessee Valley Authority
UEP United Egg Producers
U.S. United Stales
USAF United Stales Air Force
USDA United Stales Department of Agriculture
USFS United Stales Foresl Service
USGS United Stales Geological Survey
UNEP United Nations Environmental Programme
UNFCCC United Nations Framework Convention on Climate Change
VAIP EPA's Voluntary Aluminum Industrial Partnership
VMT Vehicle miles traveled
WMO World Meteorological Organization
X-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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ANNEXY
Chemical Formulas
Table Y-1: Guide IB Ohemical Formulas
Symbol
Name
Al
AI203
Br
C
CH4
C2H6
CsHa
CF4
C2F6
c-CsFe
CsFs
C-C4F8
C5Fi2
C6Fl4
CFsl
CFCIs
CF2CI2
CFsCI
C2F3CI3
CClaCFs
C2F4CI2
C2F5CI
CHCI2F
CHF2CI
C2F3HCI2
C2F4HCI
C2FH3CI2
C2H3F2CI
CF3CF2CHCI2
CCIF2CF2CHCIF
CCI4
CHCICCb
CCI2CCI2
CHsCI
CHsCCIs
CH2CI2
CHCIs
CHFs
CH2F2
CH3F
C2HF5
C2H2F4
CH2FCF3
C2H3F3
C2H3F3
CH2FCH2F
C2H4F2
CH3CH2F
C3HF7
CF3CF2CH2F
Aluminum
Aluminum Oxide
Bromine
Carbon
Methane
Ethane
Propane
Peiiluoromethane
Perfluoroethane, hexafluoroethane
Perfluorocyclopropane
Perfluoropropane
Perfluorocyclobutane
Perfluorobutane
Perfluoropenlane
Perfluorohexane
Trifluoroiodomethane
Trichlorofluoromethane (CFC-11)
Dichlorodifluoromethane (CFC-12)
Chlorotrifluoromethane (CFC-13)
Trichlorotrifluoroethane (CFC-113)*
CFC-113a*
Dichlorotetrafluoroethane (CFC-114)
Chloropentafluoroethane (CFC-115)
HCFC-21
Chlorodifluoromethane (HCFC-22)
HCFC-123
HCFC-124
HCFC-141b
HCFC-142b
HCFC-225ca
HCFC-225cb
Carbon telrachloride
Trichloroethylene
Perchloroethylene, tetrachloroethene
Melhylchloride
Methylchloroform
Methylenechloride
Chloroform, trichloromethane
HFC-23
HFC-32
HFC-41
HFC-125
HFC-134
HFC-134a
HFC-143*
HFC-143a*
HFC-152'
HFC-152a'
HFC-161
HFC-227ea
HFC-236cb
Y-1
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CF3CHFCHF2
CsHzFs
CHFzCHzCFs
CF3CHzCFzCH3
CsHzFio
CFaOCHFz
CFzHOCFzH
CHsOCFs
CF3CHFOCF3
CFsCHCIOCHFz
CFaCHFOCHFz
CF3CHzOCF3
CHFzCHzOCFs
CFsCHzOCHFz
CHFzCFzOCH3
CF3CHzOCH3
CF3CFzOCFzCHFz
CF3CF2OCH2CF3
CF3CF2CF20CH3
CF3CF2OCH2CHFz
CFsCHFCFzOCft
CHFzCFzCFzOCHs
CHFzCFzOCHzCHFz
CHFzCFzCHzOCHFz
CF3CFzCHzOCH3
CHFzCF^CHzCHs
QFsOCzHs
CHFzOCFzOCzF^OCHFz
CHFzOCFzOCHFz
CHFzOCFzCF^CHFz
CH30CH3
CHjBrz
CHzBrCI
CHBrs
CHBfFz
CHsBr
CFzBrCI
CF3Br(CBrF3)
CFsl
CO
COz
CaCOs
CaMg(C03)z
CaO
CI
F
Fe
FezOs
FeSi
H,Hz
HzO
HzOz
OH
N,Nz
NH3
NH<»
HN03
NFs
NzO
HFC-236ea
HFC-236fa
HFC-245ca
HFC-245fa
HFC-365mfc
HFC-43-10mee
HFE-125
HFE-134
HFE-143a
HFE-227ea
HCFE-235da2
HFE-236ea2
HFE-236fa
HFE-245cb2
HFE-245fa1
HFE-245fa2
HFE-254cb2
HFE-263to2
HFE-329mcc2
HFE-338mcf2
HFE-347mcc3
HFE-347mcf2
HFE-356mec3
HFE-356pCC3
HFE-356pcf2
HFE-356pcf3
HFE-365mcf3
HFE-374pcf2 (
HFE-7100 :
HFE-7200
H-Galden 1040x
HG-10
HG-01 !
Dimethyl ether
Dibromomethane
Dibromochloromelhane
Tribrotnomelhane
Bromodifluorotnethane
Methylbromide
Bromodichloromelhane (Halon 1211)
Bromotrifluoromethane (Halon 1301)
FIC-1311
Carbon monoxide
Carbon dioxide
Calcium carbonate, Limestone
Dolomite
Calcium oxide, Lime
atomic Chlorine
Fluorine
Iron
Ferric oxide
Ferrosilicon .
atomic Hydrogen, molecular Hydrogen}
Water
Hydrogen peroxide
Hydroxyl
atomic Nitrogen, molecular Nitrogen
Ammonia
Ammonium ion
Nitric Acid
Nitrogen trifluoride i
Nitrous oxide
Y-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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NO
N02
N03
Na
Na2CC)3
NasAIFe
0,02
03
S
SFe
SFsCFs
S02
Si
SiC
Si02
Nitric oxide
Nitrogen dioxide
Nitrate radical
Sodium
Sodium carbonate, soda ash
Synthetic cryolite
atomic Oxygen, molecular Oxygen
Ozone
atomic Sulfur
Sulfuric acid
Sulfur hexafluoride
Trifluoromethylsulphur pentafluoride
Sulfur dioxide
Silicon
Silicon carbide
Quartz
* Distinct isomers.
Y-3
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Y-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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ANNEX Z
Glossary
Abiotic. 7 Nonliving. Compare biotic.
Absorption of radiation.1 The uptake of radiation by a solid body, liquid or gas. The absorbed energy may be
transferred or re-emitted.
Acid deposition. 6 A complex chemical and atmospheric process whereby recombined emissions of sulfur and
nitrogen compounds are redeposited on earth in wet or dry form. See acid rain.
Acid rain.6 Rainwater that has an acidity content greater than the postulated natural pH of about 5.6. It is formed
when sulfur dioxides and nitrogen oxides, as gases or fine particles in the atmosphere, combine with water
vapor and precipitate as sulfuric acid or nitric acid in rain, snow, or fog. The dry forms are acidic gases or
particulates. See acid deposition. ,
Acid solution. 7 Any water solution that has more hydrogen ions (H+) than hydroxide ions (OH-); any water
solution with a pH less than 7. See basic solution, neutral solution.
Acidic.7 See acid solution. :
Adiabatic process. 9 A thermodynamic change of state of a system such that no heat or mass is transferred across
the boundaries of the system. In an adiabatic process, expansion always results in cooling, and compression in
warming. ;
Aerosol.1&9 Particulate matter, solid or liquid, larger than a molecule but small enough to remain suspended in the
atmosphere. Natural sources include salt particles from sea spray, dust and clay particles as a result of
weathering of rocks, both of which are carried upward by the wind. Aerosols can also originate as a result of
human activities and are often considered pollutants. Aerosols are important in the atmosphere as nuclei for the
condensation of water droplets and ice crystals, as participants in various chemical cycles, and as absorbers and
scatters of solar radiation, thereby influencing the radiation budget of the Earth's climate system. See climate,
paniculate matter.
Afforestation.2 Planting of new forests on lands that have not been recently forested.
Air carrier 8 An operator (e.g., airline) in the commercial system of air transportation consisting of aircraft that
hold certificates of, Public Convenience and Necessity, issued by the Department of Transportation, to conduct
scheduled or non-scheduled flights within the country or abroad. '•
Air pollutant. See air pollution.
Air pollution. 7 One or more chemicals or substances in high enough concentrations in the air to harm humans,
other animals, vegetation, or materials. Such chemicals or physical conditions (such as excess heat or noise) are
called air pollutants. !
Albedo.9 The fraction of the total solar radiation incident on a body that is reflected by it. ,
Alkalinity.6 Having the properties of a base with a pH of more than 7. A common alkaline is baking soda.
Alternative energy. 6 Energy derived from nontraditional sources (e.g., compressed natural gas, solar,
hydroelectric, wind).
Anaerobic.6 A life or process that occurs in, or is not destroyed by, the absence of oxygen.
Anaerobic decomposition.2 The breakdown of molecules into simpler molecules or atoms by microorganisms that
can survive in the partial or complete absence of oxygen.
Anaerobic lagoon. 2 A liquid-based manure management system, characterized by waste residing in water to a
depth of at least six feet for a period ranging between 30 and 200 days. Bacteria produce methane in the
absence of oxygen while breaking down waste. \
Z-1
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Anaerobic organism.7 Organism that does not need oxygen to stay alive. See aerobic organism.
Antarctic "Ozone Hole." 6 Refers to the seasonal depletion of stratospheric ozone in a large area over Antarctica.
See ozone layer.
Anthracite.2 A hard, black, lustrous coal containing a high percentage of fixed carbon and a low percentage of
volatile matter. Often referred to as hard coal.
Anthropogenic.2 Human made. In the context of greenhouse gases, emissions that are produced as the result of
human activities.
Arable land.7 Land that can be cultivated to grow crops.
Aromatic.6 Applied to a group of hydrocarbons and their derivatives characterized by the presence of the benzene
ring. ;
Ash.6 The mineral content of a product remaining after complete combustion.
Asphalt.2 A dark-brown-to-black cement-like material containing bitumen as the predominant constituent. It is
obtained by petroleum processing. The definition includes crude asphalt as well as the following finished
products: cements, fluxes, the asphalt content of emulsions (exclusive of water), and petroleum distillates
blended with asphalt to make cutback asphalt.
Atmosphere.' The mixture of gases surrounding the Earth. The Earth's atmosphere consists of about 79.1 percent
nitrogen (by volume), 20.9 percent.oxygen, 0.036 percent carbon dioxide and trace amounts of other gases. The
atmosphere can be divided into a number of layers according to its mixing or chemical characteristics, generally
determined by its thermal properties (temperature). :> The layer nearest the Earth is the troposphere, which
reaches up to an altitude of about 8 kilometers (about 5 miles) in the polar regions and up to 17 kilometers
(nearly 11 miles) above the equator. The stratosphere, which reaches to an altitude of about 50 kilometers
(Similes) lies atop the troposphere. The mesosphere, which extends from 80 to 90 kilometers atop the
stratosphere, and finally, the thermosphere, or ionosphere, gradually diminishes and forms a fuzzy border with
outer space. There is relatively little mixing of gases between layers.
Atmospheric lifetime. See lifetime.
Atomic weight. 6 The average weight (or mass) of all the isotopes of an element, as determined from the
proportions in which they are present in a given element, compared with the mass of the 12 isotope of carbon
(taken as precisely 12.000), that is the official international standard; measured in daltons.
Atoms.7 Minute particles that are the basic building blocks of all chemical elements and thus all matter.
Aviation Gasoline. 8 All special grades of gasoline for use in aviation reciprocating engines, as given in the
American Society for Testing and Materials (ASTM) specification D 910. Includes all refinery products within
the gasoline range that are to be marketed straight or in blends as aviation gasoline without further processing
(any refinery operation except mechanical blending).; Also included are finished components in the gasoline
range, which will be used for blending or compounding into aviation gasoline.
Bacteria, 7 One-celled organisms. Many act as decomposers that break down dead organic matter into substances
that dissolve in water and are used as nutrients by plants.
Barrel (bbl). 6 A liquid-volume measure equal to 42 United States gallons at 60 degrees Fahrenheit; used in
expressing quantities of petroleum-based products.
Basic solution.7 Water solution with more hydroxide ions (OH-) than hydrogen ions (H+); water solutions with pH
greater than 7. See acid solution, alkalinity, acid.
Biodegradable. 7 Material that can be broken down into simpler substances (elements and compounds) by bacteria
or other decomposers. Paper and most organic wastes such as animal manure are biodegradable. See
nonbiodegradable.
Biofuel.3&7 Gas or liquid fuel made from plant material (biomass). Includes wood, wood waste, wood liquors,
peat, railroad ties, wood sludge, spent sulfite liquors,; agricultural waste, straw, tires, fish oils, tall oil, sludge
waste, waste alcohol, municipal solid waste, landfill gases, other waste, and ethanol blended into motor
gasoline.
1-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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Biogeochemical cycle. 7 Natural processes that recycle nutrients in various chemical forms from the environment,
to organisms, and then back to the environment. Examples are the carbon, oxygen, nitrogen, phosphorus, and
hydrologic cycles.
Biological oxygen demand (BOD). 7 Amount of dissolved oxygen needed by aerobic decomposers to break down
the organic materials in a given volume of water at a certain temperature over a specified time period. See
BODS.
Biomass.7 Total dry weight of all living organisms that can be supported at each tropic level in a food chain. Also,
materials that are biological in origin, including organic material (both living and dead) from above and below
ground, for example, trees, crops, grasses, tree litter, roots, and animals and animal waste.
Biomass energy.' Energy produced by combusting biomass materials such as wood. The carbon dioxide emitted
from burning biomass will not increase total atmospheric carbon dioxide if this consumption is done on a
sustainable basis (i.e., if in a given period of time, regrowth of biomass takes up as much carbon dioxide as is
released from biomass combustion). Biomass energy is often suggested as a replacement for fossil fuel
combustion. :
Biosphere.2&7 The living and dead organisms found near the earth's surface in parts of the lithosphere, atmosphere,
and hydrosphere. The part of the global carbon cycle that includes living organisms and biogenic organic
matter.
Biotic. 7 Living. Living organisms makeup the biotic parts of ecosystems. See abiotic.
Bitumen. 7 Gooey, black, high-sulfur, heavy oil extracted from tar sand and then upgraded to synthetic fuel oil. See
tar sand.
Bituminous coal.2 A dense, black, soft coal, often with well-defined bands of bright and dull material. The most
common coal, with moisture content usually less than 20 percent. Used for generating electricity, making coke,
and space heating.
BOE>5.2 The biochemical oxygen demand of wastewater during decomposition occurring over a 5-day period. A
measure of the organic content of wastewater. See biological oxygen demand.
British thermal unit (Btu). 3 The quantity of heat required to raise the temperature of one pound of water one
degree of Fahrenheit at or near 39.2 degrees Fahrenheit.
Bunker fuel. 2 Fuel supplied to ships and aircraft for international transportation, irrespective of the flag of the
carrier, consisting primarily of residual and distillate fuel oil for ships and jet fuel for aircraft.
Bus. ** A rubber-tired, self-propelled, manually steered vehicle that is generally designed to transport 30
individuals or more. Bus types include intercity, school and transit.
Capacity Factor.3 The ratio of the electrical energy produced by a generating unit for a given period of time to the
electrical energy that could have been produced at continuous full- power operation during the same period.
Carbon black.2 An amorphous form of carbon, produced commercially'by thermal or oxidative decomposition of
hydrocarbons and used principally in rubber goods, pigments, and printer's ink. ;
Carbon cycle. 2 All carbon reservoirs and exchanges of carbon from reservoir to reservoir by various chemical,
physical, geological, and biological processes. Usually thought of as a series of the four main reservoirs of
carbon interconnected by pathways of exchange. The four reservoirs, regions of the Earth in which carbon
behaves in a systematic manner, are the atmosphere, terrestrial biosphere (usually includes freshwater systems),
oceans, and sediments (includes fossil fuels). Each of these global reservoirs may be subdivided into smaller
pools, ranging in size from individual communities or ecosystems to the total of all living organisms (biota).
Carbon dioxide.2 A colorless, odorless, non-poisonous gas that is a normal part of the ambient air. Carbon dioxide
is a product of fossil fuel combustion. Although carbon dioxide does not directly impair human health, it is a
greenhouse gas that traps terrestrial (i.e., infrared) radiation and contributes to the potential for global warming.
See global -warming. <
Carbon equivalent (CE). ' A metric measure used to compare the emissions of the different greenhouse gases
based upon their global warming potential (GWP). Greenhouse gas emissions in the United States are most
Z-3
-------
commonly expressed as "million metric tons of carbon equivalents" (MMTCE). Global warming potentials are
used to convert greenhouse gases to carbon dioxide equivalents. See global warming potential, greenhouse gas.
Carbon flux.9 The rate of exchange of carbon between pools (i.e., reservoirs).
Carbon intensity. The relative amount of carbon emitted per unit of energy or fuels consumed.
Carbon pool.9 The reservoir containing carbon as a principal element in the geochemical cycle.
Carbon sequestration.' The uptake and storage of carbon. Trees and plants, for example, absorb carbon dioxide,
release the oxygen and store the carbon. Fossil fuels were at one time biomass and continue to store the carbon
until burned. See carbon sinks.
Carbon sinks.' Carbon reservoirs and conditions that take-in and store more carbon (i.e., carbon sequestration)
than they release. Carbon sinks can serve to partially offset greenhouse gas emissions. Forests and oceans are
large carbon sinks. See carbon sequestration.
Carbon tctrachloride (CClj). " A compound consisting of one carbon atom and four chlorine atoms. It is an
ozone depleting substance. Carbon tetrachloride was widely used as a raw material in many industrial
applications, including the production of chlorofluorocarbons, and as a solvent. Solvent use was ended in the
United States when it was discovered to be carcinogenic. See ozone depleting substance.
Chemical reaction. 7 Interaction between chemicals in which there is a change in the chemical composition of the
elements or compounds involved. ,
Chlorofluorocarbons (CFCs). 7 Organic compounds made up of atoms of carbon, chlorine, and fluorine. An
example is CFC-12 (CCypy, used as a refrigerant in refrigerators and air conditioners and as a foam blowing
agent. Gaseous CFCs can deplete the ozone layer when they slowly rise into the stratosphere, are broken down
by strong ultraviolet radiation, release chlorine atoms, and then react with ozone molecules. See Ozone
Depleting Substance.
Climate.1&9 The average weather, usually taken over a 30 year time period, for a particular region and time period.
Climate is not the same as weather, but rather, it is the average pattern of weather for a particular region.
Weather describes the short-term state of the atmosphere. Climatic elements include precipitation, temperature,
humidity, sunshine, wind velocity, phenomena such as fog, frost, and hail-storms, and other measures of the
weather. See -weather.
Climate change.' The term "climate change" is sometimes used to refer to all forms of climatic inconsistency, but
because the Earth's climate is never static, the term is more properly used to imply a significant change from
one climatic condition to another. In some cases, "climate change" has been used synonymously with the term,
"global warming"; scientists however, tend to use the term in the wider sense to also include natural changes in
climate. See global warming, greenhouse effect, enhanced greenhouse effect, radiative forcing.
Climate feedback.' An atmospheric, oceanic, terrestrial, or other process that is activated by direct climate change
induced by changes in radiative forcing. Climate feedbacks may increase (positive feedback) or diminish
(negative feedback) the magnitude of the direct climate change.
Climate lag.' The delay that occurs in climate change as a result of some factor that changes very slowly. For
example, the effects of releasing more carbon dioxide into the atmosphere may not be known for some time
because a large fraction is dissolved in the ocean and only released to the atmosphere many years later.
Climate sensitivity.' The equilibrium response of the climate to a change in radiative forcing; for example, a
doubling of the carbon dioxide concentration. See radiative forcing.
Climate system (or Earth system). ' The atmosphere, the oceans, the biosphere, the cryosphere, and the
geosphere, together make up the climate system.
Coal.2 A black or brownish black solid, combustible substance formed by the partial decomposition of vegetable
matter without access to air. The rank of coal, which includes anthracite, bituminous coal, subbituminous coal,
and lignite, is based on fixed carbon, volatile matter, and heating value. Coal rank indicates the progressive
alteration, or coalification, from lignite to anthracite. See anthracite, bituminous coal, subbituminous coal,
lignite. \
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Coal coke.2 A hard, porous product made from baking bituminous coal in ovens at temperatures as high as 2,000
degrees Fahrenheit. It is used both as a fuel and as a reducing agent in smelting iron ore in a blast furnace.
Conversion of solid coal to synthetic natural gas (SNG) or a gaseous mixture that can be
Coal gasification. 7
burned as a fuel. i
Coal liquefaction. 7 Conversion of solid coal to a liquid fuel such as synthetic crude oil or methanol.
Coalbed methane. 2 Methane that is produced from coalbeds in the same manner as natural gas;produced from
other strata. Methane is the principal component of natural gas.
Co-control benefit. 10 It is the additional benefit derived from an environmental policy that is designed to control
one type of pollution, while reducing the emissions of other pollutants as well. For example, a policy to reduce
carbon dioxide emissions might reduce the combustion of coal, but when coal combustion is reduced, so too are
the emissions of particulates and sulfur dioxide. The benefits associated with reductions in emissions of
particulates and sulfur dioxide are the co-control benefits of reductions in carbon dioxide.
Cogeneration. 7 Production of two useful forms of energy such as high-temperature heat and electricity from the
same process.
Combustion.2 Chemical oxidation accompanied by the generation of light and heat.
Commercial End-Use Sector: Defined economically, consists of business establishments that are not engaged in
transportation or in manufacturing or other types of industrial activities (e.g., agriculture, mining, or
construction). Commercial establishments include hotels, motels, restaurants, wholesale businesses, retail
stores, laundries, and other service enterprises; religious and nonprofit organizations; health, social, and
educational institutions; and Federal, State, and local governments. Street lights, pumps, bridges, and public
services are also included if the establishment operating them is considered commercial.
Compost.7 Partially decomposed organic plant and animal matter that can be used as a soil conditioner or fertilizer.
Composting. 7 Partial breakdown of organic plant and animal matter by aerobic bacteria to produce a material that
can be used as a soil conditioner or fertilizer. See compost.
Compound. 7 Combination of two or more different chemical elements held together by chemical bonds. See
element. See inorganic compound, organic compound.
Concentration. 7 Amount of a chemical in a particular volume or weight of air, water, soil, or other medium. See
parts per billion, parts per million.
Conference Of Parties (COP). 10 The supreme body of the United Nations Framework Convention on Climate
Change (UNFCCC). It comprises more than 170 nations that have ratified the Convention. Its first session was
held in Berlin, Germany, in 1995 and is expected to continue meeting on a yearly basis. The COP's role is to
promote and review the implementation of the Convention. It will periodically review existing commitments in
light of the Convention's objective, new scientific findings, and the effectiveness of national climate change
programs. See United Nations Framework Convention on Climate Change.
Conifer. 7 See coniferous trees.
Coniferous trees. 7 Cone-bearing trees, mostly evergreens, that have needle-shaped or scale-like leaves. They
produce wood known commercially as softwood. See deciduous trees.
Cooling Degree Days: The number of degrees per day that the average daily temperature is above 65° Fahrenheit.
The daily average temperature is the mean of the maximum and minimum temperatures for a 24 hour period.
(See Degree Days)
Criteria pollutant.2 A pollutant determined to be hazardous to human health and regulated under EPA's National
Ambient Air Quality Standards. The 1970 amendments to the Clean Air Act require EPA to describe the health
and welfare impacts of a pollutant as the "criteria" for inclusion in the regulatory regime. In this report,
emissions of the criteria pollutants CO, NOX, NMVOCs, and SO2 are reported because they are thought to be
precursors to greenhouse gas formation. '
Crop residue.2 Organic residue remaining after the harvesting and processing of a crop.
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Crop rotation.7 Planting the same field or areas of fields with different crops from year to year to reduce depletion
of soil nutrients. A plant such as corn, tobacco, or cotton, which remove large amounts of nitrogen from the
soil, is planted one year. The next year a legume such as soybeans, which add nitrogen to the soil, is planted.
Crude oil. 2 A mixture of hydrocarbons that exist in liquid phase in underground reservoirs and remain liquid at
atmospheric pressure after passing through surface separating facilities. See petroleum.
Deciduous trees. 7 Trees such as oaks and maples that lose their leaves during part of the year. See coniferous
trees.
Decomposition. 9 The breakdown of matter by bacteria and fungi. It changes the chemical composition and
physical appearance of the materials.
Deforestation.' Those practices or processes that result in the conversion of forested lands for non-forest uses.
This is often cited as one of the major causes of the enhanced greenhouse effect for two reasons: 1) the burning
or decomposition of the wood releases carbon dioxide; and 2) trees that once removed carbon dioxide from the
atmosphere in the process of photosynthesis are no longer present.
Dcgradablc.7 See biodegradable.
Degree Days (Population Weighted): Heating or cooling degree days weighted by the population of the area in
which the degree days are recorded. To compute State population-weighted degree days, each State is divided
into from one to nine climatically homogeneous divisions, which are assigned weights based on the ratio of the
population of the division to the total population of the State. Degree day readings for each division are
multiplied by the corresponding population weight for each division and those products are then summed to,
arrive at the State population-weighted degree day value. To compute national population-weighted degree
days, the Nation is divided into nine Census regions, each comprising from three to eight States, which are
assigned weights based on the ratio of the population of the Nation. Degree day readings for each region are
multiplied by the corresponding population weight for each region and those products are then summed to
arrive at the national population-weighted degree day value. (See Heating Degree Days, Cooling Degree Days,
and Degree Day Normals)
Degree Day Normals: Simple arithmetic averages of monthly or annual degree days over a long period of time
(usually the 30 year period of 1961 through 1990). The averages may be dimple degree day normals or
population-weighted degree day normals.
Desertification.' The progressive destruction or degradation of existing vegetative cover to form a desert. This can
occur due to overgrazing, deforestation, drought, and the burning of extensive areas. Once formed, deserts can
only support a sparse range of vegetation. Climatic effects associated with this phenomenon include increased
reflectivity of solar radiation, reduced atmospheric humidity, and greater atmospheric dust (aerosol) loading.
Distillate fuel oil. 2 A general classification for the petroleum fractions produced in conventional distillation
operations. Included are products known as No. 1, No. 2, and No. 4 fuel oils and No. 1, No. 2, and No. 4 diesel
fuels. Used primarily for space heating, on and off-highway diesel engine fuel (including railroad engine fuel
and fuel for agricultural machinery), and electric power generation.
Economy.7 System of production, distribution, and consumption of economic goods.
Ecosystem. 10 The complex system of plant, animal, fungal, and microorganism communities and their associated
non-living environment interacting as an ecological unit. Ecosystems have no fixed boundaries; instead their
parameters are set to the scientific, management, or policy question being examined. Depending upon the
purpose of analysis, a single lake, a watershed, or an entire region could be considered an ecosystem.
Electric Utility Sector: Privately and publicly owned establishments that generate, transmit, distribute, or sell
electricity primarily for use by the public and meet the definition of an electric utility. Electric utilities include
investor-owned, publicly owned, cooperative, and Federal utilities. Historically, they have generally been
vertically integrated companies that provide for generation, transmission, distribution, and/or energy services
for all customers in a designated service territory. Nonutility power producers are not included in the electric
utility sector.
Electrons. 7 Tiny particle moving around outside the nucleus of an atom. Each electron has one unit of negative
charge (-) and almost no mass.
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Element. 7 Chemicals such as hydrogen (H), iron (Fe), sodium (Na), carbon (C), nitrogen (N)>>or oxygen (O),
whose distinctly different atoms serve as the basic building blocks of all matter. There are 92 naturally
occurring elements. Another 15 have been made in laboratories. Two or more elements combine to form
compounds that make up most of the world's matter. See compound.
Emission inventory. A list of air pollutants emitted into a community's, state's, nation's, or the Earth's atmosphere
in amounts per some unit time (e.g. day or year) by type of source. An emission inventory has both political
and scientific applications.
Emissions coefficient/factor.2 A unique value for scaling emissions to activity data in terms of a standard rate of
emissions per unit of activity (e.g., grams of carbon dioxide emitted per barrel of fossil fuel consumed).
Emissions. 2 Releases of gases to the atmosphere (e.g., the release of carbon dioxide during fuel combustion).
Emissions can be either intended or unintended releases. See fugitive emissions.
Energy conservation. 7 Reduction or elimination of unnecessary energy use and waste. See energy-efficiency.
Energy intensity.5 Ratio between the consumption of energy to a given quantity of output; usually refers to the
amount of primary or final energy consumed per unit of gross domestic product. ;
Energy quality. 7 Ability of a form of energy to do useful work. High-temperature heat and the chemical energy in
fossil fuels and nuclear fuels are concentrated high quality energy. Low-quality energy such as low-temperature
heat is dispersed or diluted and cannot do much useful work.
Energy.3 The capacity for doing work as measured by the capability of doing work (potential energy) or the
conversion of this capability to motion (kinetic energy). Energy has several forms, some of which are easily
convertible and can be changed to another form useful for work. Most of the world's convertible energy comes
from fossil fuels that are burned to produce heat that is then used as a transfer medium to mechanical or other
means in order to accomplish tasks. In the United States, electrical energy is often measured in kilowatt-hours
(kWh), while heat energy is often measured in British thermal units (Btu).
Energy-efficiency. 6&s The ratio of the useful output of services from an article of industrial equipment to the
energy use by such an article; for example, vehicle miles traveled per gallon of fuel (mpg).
Enhanced greenhouse effect.! The concept that the natural greenhouse effect has been enhanced by anthropogenic
emissions of greenhouse gases. Increased concentrations of carbon dioxide, methane, and nitrous oxide, CFCs,
HFCs, PFCs, SF6, NF3, and other photochemically important gases caused by human activities such as fossil
fuel consumption, trap more infra-red radiation, thereby exerting a warming influence on the climate. See
greenhouse gas, anthropogenic, greenhouse effect, climate.
Enhanced oil recovery. 7 Removal of some of the heavy oil left in an oil well after primary and secondary
recovery. See primary oil recovery, secondary oil recovery.
Enteric fermentation. 2 A digestive process by which carbohydrates are broken down by microorganisms into
simple molecules for absorption into the bloodstream of an animal.
Environment. 7 All external conditions that affect an organism or other specified system during its lifetime.
Ethanol (C2H5OH). 8 Otherwise known as ethyl alcohol, alcohol, or grain spirit. A clear, colorless, flammable
oxygenated hydrocarbon with a boiling point of 78.5 degrees Celsius in the anhydrous state. In transportation,
ethanol is used as a vehicle fuel by itself (E100), blended with gasoline (E85), or as a gasoline octane enhancer
and oxygenate (10 percent concentration). !
Evapotranspiration.10 The loss of water from the soil by evaporation and by transpiration from the plants growing
in the soil, which rises with air temperature.
Exponential growth. 7 Growth in which some quantity, such as population size, increases by a constant percentage
of the whole during each year or other time period; when the increase in quantity over time is plotted, this type
of growth yields a curve shaped like the letter J.
Feedlot. 7 Confined outdoor or indoor space used to raise hundreds to thousands of domesticated livestock. See
rangeland.
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Fertilization, carbon dioxide.' An expression (sometimes reduced to 'fertilization') used to denote increased plant
growth due to a higher carbon dioxide concentration. ;
Fertilizer. 7 Substance that adds inorganic or organic plant nutrients to soil and improves its ability to grow crops,
trees, or other vegetation. See organic fertilizer. ',
Flaring.9 The burning of waste gases through a flare stack or other device before releasing them to the air.
Fluidized bed combustion (FBC). 7 Process for burning coal more efficiently, cleanly, and cheaply. A stream of
hot air is used to suspend a mixture of powdered coal and limestone during combustion. About 90 to 98 percent
of the sulfur dioxide produced during combustion is removed by reaction with limestone to produce solid
calcium sulfate.
Fluorocarbons. ' Carbon-fluorine compounds that often contain other elements such as hydrogen, chlorine, or
bromine. Common fluorocarbons include chlorofluorocarbons (CFCs), hydrochlorofluorocarbons (HCFCs),
hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs). See chlorofluorocarbons,
hydrochlorofluorocarbons, hydrofluorocarbons, perfluorocarbons.
Forcing mechanism.' A process that alters the energy balance of the climate system (i.e., changes the relative
balance between incoming solar radiation and outgoing infrared radiation from Earth). Such mechanisms
include changes in solar irradiance, volcanic eruptions, and enhancement of the natural greenhouse effect by
emission of carbon dioxide.
Forest. ' Terrestrial ecosystem (biome) with enough average annual precipitation (at least 76 centimeters or 30
inches) to support growth of various species of trees and smaller forms of vegetation.
Fossil fuel. A general term for buried combustible geologic deposits of organic materials, formed from decayed
plants and animals that have been converted to crude oil, coal, natural gas, or heavy oils by exposure to heat and
pressure in the earth's crust over hundreds of millions of years. See coal, petroleum, crude oil, natural gas.
Fossil fuel combustion.' Burning of coal, oil (including gasoline), or natural gas. The burning needed to generate
energy release carbon dioxide by-products that can include unburned hydrocarbons, methane, and carbon
monoxide. Carbon monoxide, methane, and many of the unburned hydrocarbons slowly oxidize into carbon
dioxide in the atmosphere. Common sources of fossil fuel combustion include cars and electric utilities.
Freon. See chlorofluorocarbon.
Fugitive emissions.2 Unintended gas leaks from the processing, transmission, and/or transportation of fossil fuels,
CFCs from refrigeration leaks, SFg from electrical power distributor, etc.
Gasohol. 7 Vehicle fuel consisting of a mixture of gasoline and ethyl or methyl alcohol; typically 10 to 23 percent
ethanol by volume.
General Aviation. 8 That portion of civil aviation, which encompasses all facets of aviation except air carriers. It
includes any air taxis, commuter air carriers, and air travel clubs, which do not hold Certificates of Public
Convenience and Necessity. See air carriers.
General circulation model (GCM). 1 A global, three-dimensional computer model of the climate system which
can be used to simulate human-induced climate change. GCMs are highly complex and they represent the
effects of such factors as reflective and absorptive properties of atmospheric water vapor, greenhouse gas
concentrations, clouds, annual and daily solar heating; ocean temperatures and ice boundaries. The most recent
GCMs include global representations of the atmosphere, oceans, and land surface.
Geosphcre.' The soils, sediments, and rock layers of the Earth's crust, both continental and beneath the ocean
floors.
Gcothermal energy. 7 Heat transferred from the earth's molten core to under-ground deposits of dry steam (steam
with no water droplets), wet steam (a mixture of steam and water droplets), hot water, or rocks lying fairly close
to the earth's surface.
Global Warming Potential (GWP).1 The index used to translate the level of emissions of various gases into a
common measure in order to compare the relative radiative forcing of different gases without directly
calculating the changes in atmospheric concentrations. GWPs are calculated as the ratio of the radiative forcing
that would result from the emissions of one kilogram of a greenhouse gas to that from the emission of one
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kilogram of carbon dioxide over a period of time (usually 100 years). Gases involved in complex atmospheric
chemical processes have not been assigned GWPs. See lifetime.
Global warming. 10 The progressive gradual rise of the earth's surface temperature thought to be caused by the
greenhouse effect and responsible for changes in global climate patterns. See enhanced greenhouse effect,
greenhouse effect, climate change.
Grassland. 7 Terrestrial ecosystem (biome) found in regions where moderate annual average precipitation (25 to 76
centimeters or 10 to 30 inches) is enough to support the growth of grass and small plants but not enough to
support large stands of trees.
Greenhouse effect. 7 Trapping and build-up of heat in the atmosphere (troposphere) near the earth's surface. Some
of the heat flowing back toward space from the earth's surface is absorbed by water vapor, carbon dioxide,
ozone, and several other gases in the atmosphere and then reradiated back toward the earth's surface. If the
atmospheric concentrations of these greenhouse gases rise, the average temperature of the lower atmosphere
will gradually increase. See enhanced greenhouse effect, climate change, global warming. '
Greenhouse gas (GHG). ' Any gas that absorbs infrared radiation in the atmosphere. Greenhouse gases include,
but are not limited to, water vapor, carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O),
hydrochlorofluorocarbons (HCFCs), ozone (Os), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and
sulfur hexafluoride (SF6). See carbon dioxide, methane, nitrous oxide, hydrochlorofluorocarbon, ozone,
hydrofluorocarbon, perfluorocarbon, sulfur hexafluoride. '
Halocarbons.
iodine.
Chemicals consisting of carbon, sometimes hydrogen, and either chlorine, fluorine, bromine or
Halons. ' Compounds, also known as bromofluorocarbons, that contain bromine, fluorine, and carbon. They are
generally used as fire extinguishing agents and cause ozone depletion. Bromine is many times more effective at
destroying stratospheric ozone than chlorine. See ozone depleting substance.
Heat. 7 Form of kinetic energy that flows from one body to another when there is a temperature difference between
the two bodies. Heat always flows spontaneously from a hot sample of matter to a colder sample of matter.
This is one way to state the second law of thermodynamics. See temperature. •
Heat content. 5 The amount of heat per unit mass released upon complete combustion.
Heating Degree Days: The number of degrees per day that the average daily temperature is below 65° Fahrenheit.
The daily average temperature is the mean of the maximum and minimum temperatures for a 24 hour period.
(See Degree Days) :
Higher heating value. 5 Quantity of heat liberated by the complete combustion of a unit volume or weight of a fuel
assuming that the produced water vapor is completely condensed and the heat is recovered; also .known as gross
calorific value. See lower heating value.
Histosol. 9 Wet organic soils, such as peats and mucks.
Hydrocarbons. ] Substances containing only hydrogen and carbon. Fossil fuels are made up of hydrocarbons.
Some hydrocarbon compounds are major air pollutants.
Hydrochlorofluorocarbons (HCFCs). 1 Compounds containing hydrogen, fluorine, chlorine, and carbon atoms.
Although ozone depleting substances, they are less potent at destroying stratospheric ozone than
chlorofluorocarbons (CFCs). They have been introduced as temporary replacements for CFCs and are also
greenhouse gases. See ozone depleting substance. ;
Hydroelectric power plant. 7 Structure in which the energy of fading or flowing water spins a turbine generator to
produce electricity.
Hydrofluorocarbons (HFCs). ' Compounds containing only hydrogen, fluorine, and carbon atoms. They were
introduced as alternatives to ozone depleting substances in serving many industrial, commercial, and personal
needs. HFCs are emitted as by-products of industrial processes and are also used in manufacturing. They do
not significantly deplete the stratospheric ozone layer, but they are powerful greenhouse gases with global
warming potentials ranging from 140 (HFC-1 52a) to 1 1 ,700 (HFC-23). '-
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Hydrologic cycle. The process of evaporation, vertical and horizontal transport of vapor, condensation,
precipitation, and the flow of water from continents to oceans. It is a major factor in determining climate
through its influence on surface vegetation, the clouds, snow and ice, and soil moisture. The hydrologic cycle is
responsible for 25 to 30 percent of the mid-latitudes' heat transport from the equatorial to polar regions.
Hydropower.7 Electrical energy produced by falling or flowing water. See hydroelectric power plant.
Hydrosphere. 7 All the earth's liquid water (oceans, smaller bodies of fresh water, and underground aquifers),
frozen water (polar ice caps, floating ice, and frozen upper layer of soil known as permafrost), and small
amounts of water vapor in the atmosphere.
Industrial End-Use Sector: Comprises manufacturing industries, which make up the largest part of the sector,
along with mining, construction, agriculture, fisheries, and forestry. Establishments in this sector range from
steel mills to small farms to companies assembling electronic components. Nonutility power producers are also
included in the industrial end-use sector.
Infrared radiation.' The heat energy that is emitted from all solids, liquids, and gases. In the context of the
greenhouse issue, the term refers to the heat energy emitted by the Earth's surface and its atmosphere.
Greenhouse gases strongly absorb this radiation in the Earth's atmosphere, and re-radiate some of it back
towards the surface, creating the greenhouse effect. ;
Inorganic compound. 7 Combination of two or more elements other than those used to form organic compounds.
See organic compound.
Inorganic fertilizer. 7 See synthetic fertilizer.
Intergovernmental Panel on Climate Change (IPCC).' \ The IPCC was established jointly by the United Nations
Environment Programme and the World Meteorological Organization in 1988. The purpose of the IPCC is to
assess information in the scientific and technical literature related to all significant components of the issue of
climate change. The IPCC draws upon hundreds of the world's expert scientists as authors and thousands as
expert reviewers. Leading experts on climate change and environmental, social, and economic sciences from
some 60 nations have helped the IPCC to prepare periodic assessments of the scientific underpinnings for
understanding global climate change and its consequences. With its capacity for reporting on climate change,
its consequences, and the viability of adaptation and; mitigation measures, the IPCC is also looked to as the
official advisory body to the world's governments on the state of the science of the climate change issue. For
example, the IPCC organized the development of internationally accepted methods for conducting national
greenhouse gas emission inventories. !
Irreversibilities.10 Changes that, once set in motion, cannot be reversed, at least on human time scales.
Jet fuel 8 Includes both naphtha-type and kerosene-type fuels meeting standards for use in aircraft turbine engines.
Although most jet fuel is used in aircraft, some is used for other purposes such as generating electricity.
Joule.' The energy required to push with a force of one Newton for one meter.
Kcrogcn. 7 Solid, waxy mixture of hydrocarbons found in oil shale, with a fine grained sedimentary rock. When
the rock is heated to high temperatures, the kerogen is vaporized. The vapor is condensed and then sent to a
refinery to produce gasoline, heating oil, and other products. See oil shale, shale oil.
Kerosene.2 A petroleum distillate that has a maximum distillation temperature of 401 degrees Fahrenheit at the 10
percent recovery point, a final boiling point of 572 degrees Fahrenheit, and a minimum flash point of 100
degrees Fahrenheit. Used hi space heaters, cookstoves, and water heaters, and suitable for use as an illuminant
when burned in wick lamps.
Kyoto Protocol. 10 This is an international agreement struck by 159 nations attending the Third Conference of
Parties (COP) to the United Nations Framework Convention on Climate Change (held in December of 1997 in
Kyoto Japan) to reduce worldwide emissions of greenhouse gases. If ratified and put into force, individual
countries have committed to reduce their greenhouse gas emissions by a specified amount. See Framework
Convention on Climate Change, Conference of Parties:
Landfill. 7 Land waste disposal site in which waste is generally spread in thin layers, compacted, and covered with
a fresh layer of soil each day.
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Lifetime (atmospheric).' The lifetime of a greenhouse gas refers to the approximate amount of time it would take
for the anthropogenic increment to an atmospheric pollutant concentration to return to its natural level
(assuming emissions cease) as a result of either being converted to another chemical compound or being taken
out of the atmosphere via a sink. This time depends on the pollutant's sources and sinks as well as its reactivity.
The lifetime of a pollutant is often considered in conjunction with the mixing of pollutants in the atmosphere; a
long lifetime will allow the pollutant to mix throughout the atmosphere. Average lifetimes can Vary from about
a week (e.g., sulfate aerosols) to more than a century (e.g., CFCs, carbon dioxide). See residence time.
Light-duty vehicles.8 Automobiles and light trucks combined.
Lignite. 2 A brownish-black coal of low rank with high inherent moisture and volatile matter content, used almost
exclusively for electric power generation. Also referred to as brown coal.
Liquefied natural gas (LNG). 7 Natural gas converted to liquid form by cooling to a very low temperature.
Liquefied petroleum gas (LPG). 2 Ethane, ethylene, propane, propylene, normal butane, butylene, and isobutane
produced at refineries or natural gas processing plants, including plants that fractionate new natural gas plant
liquids.
Litter. 9 Undecomposed plant residues on the soil surface. See decomposition. -
Longwave radiation. 9 The radiation emitted in the spectral wavelength greater than 4 micrometers corresponding
to the radiation emitted from the Earth and atmosphere. It is sometimes referred to as terrestrial radiation or
infrared radiation, although somewhat imprecisely. See infrared radiation.
Low Emission Vehicle (LEV).8 A vehicle meeting the low-emission vehicle standards.
Lower heating value.5 Quantity of heat liberated by the complete combustion of a unit volume or weight of a fuel
assuming that the produced water remains as a vapor and the heat of the vapor is not recovered; also known as
net calorific value. See higher heating value. ,
Lubricant. 2 A substance used to reduce friction between bearing surfaces or as a process | material, either
incorporated into other materials used as aids in manufacturing processes or as carriers of other materials.
Petroleum lubricants may be produced either from distillates or residues. Other substances may be added to
impart or improve useful properties. Does not include by-products of lubricating oil from solvent extraction or
tars derived from de-asphalting. Lubricants include all grades of lubricating oils from spindle oil to cylinder oil
and those used in greases. Lubricant categories are paraffinic and naphthenic.
Mamure. 7 Dung and urine of animals that can be used as a form of organic fertilizer.
Mass balance.9 The application of the principle of the conservation of matter. \
Manna Loa. 9 An intermittently active volcano 13,680 feet (4,170 meters) high in Hawaii.
Methane (CH4).' A hydrocarbon that is a greenhouse gas with a global warming potential most recently estimated
at 21. Methane is produced through anaerobic (without oxygen) decomposition of waste in landfills, animal
digestion, decomposition of animal wastes, production and distribution of natural gas and petroleum, coal
production, and incomplete fossil fuel combustion. The atmospheric concentration of methane as been shown
to be increasing at a rate of about 0.6 percent per year and the concentration of about 1.7 per million by volume
(ppmv) is more than twice its pre-industrial value. However, the rate of increase of methane in the atmosphere
may be stabilizing.
Methanol (CH3OH). 8 A colorless poisonous liquid with essentially no odor and little taste. It is the simplest
alcohol with a boiling point of 64.7 degrees Celsius. In transportation, methanol is used as a vehicle fuel by
itself (Ml 00), or blended with gasoline (M85).
Methanotrophic. 7 Having the biological capacity to oxidize methane to CO2 and water by metabolism under
aerobic conditions. See aerobic.
Methyl bromide (CH3Br). n An effective pesticide; used to fumigate soil and many agricultural products.
Because it contains bromine, it depletes stratospheric ozone when released to the atmosphere. See ozone
depleting substance. ',
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Metric ton.' Common international measurement for the quantity of greenhouse gas emissions. A metric ton is
equal to 1000 kilograms, 2204.6 pounds, or 1.1023 short tons.
Mineral.7 Any naturally occurring inorganic substance found in the earth's crust as a crystalline solid.
Model year. 8 Refers to the "sales" model year; for example, vehicles sold during the period from October 1 to the
next September 31 is considered one model year.
Molecule. 7 Chemical combination of two or more atoms of the same chemical element (such as O2) or different
chemical elements (such as H2O).
Montreal Protocol on Substances that Deplete the Ozone Layer. n The Montreal Protocol and its amendments
control the phaseout of ozone depleting substances production and use. Under the Protocol, several
international organizations report on the science of ozone depletion, implement projects to help move away
from ozone depleting substances, and provide a forum for policy discussions. In the United States, the Protocol
is implemented under the rubric of the Clean Air Act Amendments of 1990. See ozone depleting substance,
ozone layer.
Motor gasoline. 2 A complex mixture of relatively volatile hydrocarbons, with or without small quantities of
additives, obtained by blending appropriate refinery streams to form a fuel suitable for use in spark-ignition
engines. Motor gasoline includes both leaded and unleaded grades of finished gasoline, blending components,
and gasohol.
Municipal solid waste (MSW).2 Residential solid waste and some non-hazardous commercial, institutional, and
industrial wastes. This material is generally sent to municipal landfills for disposal. See landfill.
Naphtha.2 A generic term applied to a petroleum fraction ;with an approximate boiling range between 122 and 400
degrees Fahrenheit.
Natural gas. 7 Underground deposits of gases consisting of 50 to 90 percent methane (CH4) and small amounts of
heavier gaseous hydrocarbon compounds such as propane (CjHLt) and butane (C4H10).
Natural gas liquids (NGLs). 2 Those hydrocarbons in natural gas that are separated as liquids from the gas.
Includes natural gas plant liquids and lease condensate.
Nitrogen cycle. 7 Cyclic movement of nitrogen in different chemical forms from the environment, to organisms,
and then back to the environment.
Nitrogen fixation. 7 Conversion of atmospheric nitrogen gas into forms useful to plants and other organisms by
lightning, bacteria, and blue-green algae; it is part of the nitrogen cycle.
Nitrogen oxides (NO,).' Gases consisting of one molecule of nitrogen and varying numbers of oxygen molecules.
Nitrogen oxides are produced, for example, by the combustion of fossil fuels in vehicles and electric power
plants. In the atmosphere, nitrogen oxides can contribute to formation of photochemical ozone (smog), impair
visibility, and have health consequences; they are considered pollutants.
Nitrous oxide (N2O).' A powerful greenhouse gas with a global warming potential most recently evaluated at 310.
Major sources of nitrous oxide include soil cultivation practices, especially the use of commercial and organic
fertilizers, fossil fuel combustion, nitric acid production, and biomass burning.
Nonbiodegradable. 7 Substance that cannot be broken down in the environment by natural processes. See
biodegradable.
Nonlinearities.I0 Occur when changes in one variable cause a more than proportionate impact on another variable.
Non-methane volatile organic compounds (NMVOCs). 2 Organic compounds, other than methane, that
participate in atmospheric photochemical reactions.
Non-point source. 7 Large land area such as crop fields and urban areas that discharge pollutant into surface and
underground water over a large area. See point source.
Nonutility Power Producer: A corporation, person, agency, authority, or other legal entity of instrumentality that
owns electric generating capacity and is not an electric utility. Nonutility producers include qualifying
cogenerators, qualifying small power producers, and other nonutility generators (including independent power
Z-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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producers) without a designated, franchised, service area that do not file forms listed in the Code of Federal
Regulations, Title 18, Part 141.
Nuclear electric power.3 Electricity generated by an electric power plant whose turbines are (driven by steam
generated in a reactor by heat from the fissioning of nuclear fuel. !
Nuclear energy. 7 Energy released when atomic nuclei undergo a nuclear reaction such as the spontaneous
emission of radioactivity, nuclear fission, or nuclear fusion.
Oil shale. 7 Underground formation of a fine-grained sedimentary rock containing varying amounts of kerogen, a
solid, waxy mixture of hydrocarbon compounds. Heating the rock to high temperatures converts the kerogen to
a vapor, which can be condensed to form a slow flowing heavy oil called shale oil. See kerogen, shale oil.
Oil. See crude oil, petroleum.
Ore. 7 Mineral deposit containing a high enough concentration of at least one metallic element to permit the metal
to be extracted and sold at a profit.
Organic compound. 7 Molecule that contains atoms of the element carbon, usually combined with itself and with
atoms of one or more other element such as hydrogen, oxygen, nitrogen, sulfur, phosphorus, chlorine, or
fluorine. See inorganic compound.
Organic fertilizer. 7 Organic material such as manure or compost, applied to cropland as a source of plant
nutrients.
Oxidize.2 To chemically transform a substance by combining it with oxygen.
Oxygen cycle. 7 Cyclic movement of oxygen in different chemical forms from the environment, to organisms, and
then back to the environment.
Ozone. 6 A colorless gas with a pungent odor, having the molecular form of O3, found in two layers of the
atmosphere, the stratosphere and the troposphere. Ozone is a form of oxygen found naturally in the stratosphere
that provides a protective layer shielding the Earth from ultraviolet radiation's harmful health effects on humans
and the environment. In the troposphere, ozone is a chemical oxidant and major component of photochemical
smog. Ozone can seriously affect the human respiratory system. '
Ozone Depleting Substance (ODS). n A family of man-made compounds that includes, but are not limited to,
chlorofluorocarbons (CFCs), bromofluorocarbons (halonsj, methyl chloroform, carbon tetrachloride, methyl
bromide, and hydrochlorofluorocarbons (HCFCs). These compounds have been shown to deplete stratospheric
ozone, and therefore are typically referred to as ODSs.
Ozone layer. 7 Layer of gaseous ozone (O3) in the stratosphere that protects life on earth by filtering out harmful
ultraviolet radiation from the sun. See stratosphere, ultraviolet radiation.
Ozone precursors. 2 Chemical compounds, such as carbon monoxide, methane, non-methane hydrocarbons, and
nitrogen oxides, which in the presence of solar radiation react with other chemical compounds to form ozone,
mainly in the troposphere. See troposphere
Particulate matter (PM).7 Solid particles or liquid droplets suspended or carried in the air.
Particulates. See particulate matter.
Parts per billion (ppb). 7 Number of parts of a chemical found in one billion parts of a particular gas, liquid, or
solid mixture. See concentration. \
Parts per million (ppm). 7 Number of parts of a chemical found in one million parts of a particular gas, liquid, or
solid. See concentration. ;
Penttanes plus.2 A mixture of hydrocarbons, mostly pentanes and heavier fractions, extracted from natural gas.
Perlluorocarbons (PFCs). ' A group of human-made chemicals composed of carbon and fluorine only. These
chemicals (predominantly Cp4 and C2F6) were introduced as alternatives, along with hydrofluofocarbons, to the
ozone depleting substances. In addition, PFCs are emitted as by-products of industrial processes and are also
used in manufacturing. PFCs do not harm the stratospheric ozone layer, but they are powerful greenhouse
gases: CF4 has a global warming potential (GWP) of 6,500 and C2F6 has a GWP of 9,200. ;
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Petrochemical feedstock.2 Feedstock derived from petroleum, used principally for the manufacture of chemicals,
synthetic rubber, and a variety of plastics. The categories reported are naphtha (endpoint less than 401 degrees
Fahrenheit) and other oils (endpoint equal to or greater than 401 degrees Fahrenheit).
Petrochemicals. 7 Chemicals obtained by refining (i.e., distilling) crude oil. They are used as raw materials in the
manufacture of most industrial chemicals, fertilizers, pesticides, plastics, synthetic fibers, paints, medicines, and
many other products. See crude oil.
Petroleum coke.2 A residue that is the final product of the' condensation process in cracking.
Petroleum. 2 A generic term applied to oil and oil products in all forms, such as crude oil, lease condensate,
unfinished oils, petroleum products, natural gas plant liquids, and non-hydrocarbon compounds blended into
finished petroleum products. See crude oil.
Photosynthesis. 7 Complex process that takes place in living green plant cells. Radiant energy from the sun is used
to combine carbon dioxide (CO2) and water (H2O) to produce oxygen (O2) and simple nutrient molecules, such
as glucose (QHuOg).
Photovoltaic and solar thermal energy.2 Energy radiated by the sun as electromagnetic waves (electromagnetic
radiation) that is converted into electricity by means of solar (i.e., photovoltaic) cells or useable heat by
concentrating (i.e., focusing) collectors.
Point source. 7 A single identifiable source that discharges pollutants into the environment. Examples are
smokestack, sewer, ditch, or pipe. See non-point source.
Pollution.7 A change in the physical, chemical, or biological characteristics of the air, water, or soil that can affect
the health, survival, or activities of humans in an unwanted way. Some expand the term to include harmful
effects on all forms of life. :
Polyvinyl chloride (PVC). 2 A polymer of vinyl chloride. It is tasteless, odorless and insoluble in most organic
solvents. A member of the family vinyl resin, used in soft flexible films for food packaging and in molded rigid
products, such as pipes, fibers, upholstery, and bristles.
Population.7 Group of individual organisms of the same species living within a particular area.
Prescribed burning. 7 Deliberate setting and careful control of surface fires in forests to help prevent more
destructive fires and to kill off unwanted plants that compete with commercial species for plant nutrients; may
also be used on grasslands.
Primary oil recovery. 7 Pumping out the crude oil that flows by gravity into the bottom of an oil well. See
enhanced oil recovery, secondary oil recovery.
Quad.s Quad stands for quadrillion, which is, 1015.
Radiation. ' Energy emitted in the form of electromagnetic waves. Radiation has differing characteristics
depending upon the wavelength. Because the radiation from the Sun is relatively energetic, it has a short
wavelength (e.g., ultraviolet, visible, and near infrared) while energy re-radiated from the Earth's surface and
the atmosphere has a longer wavelength (e.g., infrared radiation) because the Earth is cooler than the Sun. See
ultraviolet radiation, infrared radiation, solar radiation, longwave radiation, terrestrial radiation.
Radiative forcing.' A change in the balance between incoming solar radiation and outgoing infrared (i.e., thermal)
radiation. Without any radiative forcing, solar radiation coming to the Earth would continue to be
approximately equal to the infrared radiation emitted from the Earth. The addition of greenhouse gases to the
atmosphere traps an increased fraction of the infrared radiation, reradiating it back toward the surface of the
Earth and thereby creates a warming influence.
Rail. 8 Includes "heavy" and "light" transit rail. Heavy transit rail is characterized by exclusive rights-of-way,
multi-car trains, high speed rapid acceleration, sophisticated signaling, and high platform loading. Also known
as subway, elevated railway, or metropolitan railway (metro). Light transit rail may be on exclusive or shared
rights of way, high or low platform, multi-car trains or single cars, automated or manually operated. In generic
usage, light rail includes streetcars, trolley cars, and tramways.
Rangcland. 7 Land, mostly grasslands, whose plants can provide food (i.e., forage) for grazing or browsing
animals. Seefeedlot.
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Recycling. Collecting and reprocessing a resource so it can be used again. An example is collecting aluminum
cans, melting them down, and using the aluminum to make new cans or other aluminum products.
Reforestation. Replanting of forests on lands that have recently been harvested.
Renewable energy.2 Energy obtained from sources that are essentially inexhaustible, unlike, for example, the fossil
fuels, of which there is a finite supply. Renewable sources of energy include wood, waste, geothermal, wind,
photovoltaic, and solar thermal energy. See hydropower, photovoltaic.
Residence time. Average time spent in a reservoir by an individual atom or molecule. Also, this term is used to
define the age of a molecule when it leaves the reservoir. With respect to greenhouse gases, residence time
usually refers to how long a particular molecule remains in the atmosphere. See lifetime.
Residential End-Use Sector: Consists of all private residences, whether occupied or vacant, owned or rented,
including single family homes, multifamily housing units, and mobile homes. Secondary home, such as
summer homes, are also included. Institutional housing, such as school dormitories, hospitals, and military
barracks, generally are not included in the residential end-use sector, but are instead included in the commercial
end-use sector.
Residual fuel oil. 2 The heavier oils that remain after the distillate fuel oils and lighter hydrocarbons are distilled
away in refinery operations and that conform to ASTM Specifications D396 and D975. Included are No. 5, a
residual fuel oil of medium viscosity; Navy Special, for use in steam-powered vessels in government service
and in shore power plants; and No. 6, which includes Bunker C fuel oil and is used for commercial and
industrial heating, electricity generation, and to power ships. Imports of residual fuel oil include imported crude
oil burned as fuel.
Secondary oil recovery. 7 Injection of water into an oil well after primary oil recovery to force out some of the
remaining thicker crude oil. See enhanced oil recovery, primary oil recovery. ,
Sector. Division, most commonly used to denote type of energy consumer (e.g., residential) or according to the
Intergovernmental Panel on Climate Change, the type of greenhouse gas emitter (e.g. industrial process). See
Intergovernmental Panel on Climate Change.
Septic tank. 7 Underground tank for treatment of wastewater from a home in rural and suburban areas. Bacteria in
the tank decompose organic wastes and the sludge settles to the bottom of the tank. The effluent flows out of
the tank into the ground through a field of drainpipes.
Sewage treatment (primary). 7 Mechanical treatment of sewage in which large solids are filtered out by screens
and suspended solids settle out as sludge in a sedimentation tank.
Shale oil. 7 Slow-flowing, dark brown, heavy oil obtained when kerogen in oil shale is vaporized at high
temperatures and then condensed. Shale oil can be refined to yield gasoline, heating oil, and other petroleum
products. See kerogen, oil shale.
Short ton.' Common measurement for a ton in the United States. A short ton is equal to 2,000 Ibs. or 0.907 metric
tons.
Sink.' A reservoir that uptakes a pollutant from another part of its cycle. Soil and trees tend to act as natural sinks
for carbon.
Sludge.7 Gooey solid mixture of bacteria and virus laden organic matter, toxic metals, synthetic organic chemicals,
and solid chemicals removed from wastewater at a sewage treatment plant.
Soil, 7 Complex mixture of inorganic minerals (i.e., mostly clay, silt, and sand), decaying organic matter, water, air,
and living organisms.
Soil carbon. A major component of the terrestrial biosphere pool in the carbon cycle. The amount of carbon in
the soil is a function of the historical vegetative cover and productivity, which in turn is dependent in part upon
climatic variables.
Solar energy. 7 Direct radiant energy from the sun. It also includes indirect forms of energy such as wind, falling
or flowing water (hydropower), ocean thermal gradients, and biomass, which are produced when direct solar
energy interact with the earth. See solar radiation.
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Solar radiation.' Energy from the Sun. Also referred to as short-wave radiation. Of importance to the climate
system, solar radiation includes ultra-violet radiation, visible radiation, and infrared radiation.
Source.4 Any process or activity that releases a greenhouse gas, an aerosol, or a precursor of a greenhouse gas into
the atmosphere.
Special naphtha.2 All finished products within the naphtha boiling range that are used as paint thinners, cleaners,
or solvents. Those products are refined to a specified flash point.
Still gas. ^ Any form or mixture of gases produced in refineries by distillation, cracking, reforming, and other
processes. Principal constituents are methane, ethane, ethylene, normal butane, butylene, propane, propylene,
etc. Used as a refinery fuel and as a petrochemical feedstock.
Stratosphere. 7 Second layer of the atmosphere, extending from about 19 to 48 kilometers (12 to 30 miles) above
the earth's surface. It contains small amounts of gaseoiis ozone (O3), which filters out about 99 percent of the
incoming harmful ultraviolet (UV) radiation. Most commercial airline flights operate at a cruising altitude in
the lower stratosphere. See ozone layer, ultraviolet radiation.
Stratospheric ozone. See ozone layer.
Strip mining.7 Cutting deep trenches to remove minerals such as coal and phosphate found near the earth's surface
in flat or rolling terrain. See surface mining.
Subbituminous coal.2 A dull, black coal of rank intermediate between lignite and bituminous coal.
Sulfur cycle. 7 Cyclic movement of sulfur in different chemical forms from the environment, to organisms, and
then back to the environment.
Sulfur dioxide (SO2).' A compound composed of one sulfur and two oxygen molecules. Sulfur dioxide emitted
into the atmosphere through natural and anthropogenic processes is changed in a complex series of chemical
reactions in the atmosphere to sulfate aerosols. These aerosols are believed to result in negative radiative
forcing (i.e., tending to cool the Earth's surface) and do result in acid deposition (e.g., acid rain). See aerosols,
radiative forcing, acid deposition, acid rain.
Sulfur hexafluoride (SF6). l A colorless gas soluble in alcohol and ether, slightly soluble in water. A very
powerful greenhouse gas used primarily in electrical transmission and distribution systems and as a dielectric in
electronics. The global warming potential of SF6 is 23,900. See Global Warming Potential.
Surface mining. 7 Removal of soil, sub-soil, and other strata and then extracting a mineral deposit found fairly
close to the earth's surface. See strip mining.
Synthetic fertilizer. 7 Commercially prepared mixtures of plant nutrients such as nitrates, phosphates, and
potassium applied to the soil to restore fertility and increase crop yields. See organic fertilizer.
Synthetic natural gas (SNG). 3 A manufactured product chemically similar in most respects to natural gas,
resulting from the conversion or reforming of petroleum hydrocarbons. It may easily be substituted for, or
interchanged with, pipeline quality natural gas.
Tailings.7 Rock and other waste materials removed as impurities when minerals are mined and mineral deposits are
processed. These materials are usually dumped on the ground or into ponds.
Tar sand. 7 Swamp-like deposit of a mixture of fine clay, sand, water, and variable amounts of tar-like heavy oil
known as bitumen. Bitumen can be extracted from tar sand by heating. It can then be purified and upgraded to
synthetic crude oil. See bitumen.
Temperature. 7 Measure of the average speed of motion of the atoms or molecules in a substance or combination
of substances at a given moment. See heat.
Terrestrial.7 Pertaining to land.
Terrestrial radiation. 9 The total infrared radiation emitted by the Earth and its atmosphere in the temperature
range of approximately 200 to 300 Kelvin. Terrestrial radiation provides a major part of the potential energy
changes necessary to drive the atmospheric wind system and is responsible for maintaining the surface air
temperature within limits of livability.
Z-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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Trace gas. Any one of the less common gases found in the Earth's atmosphere. Nitrogen, oxygen, and argon make
up more than 99 percent of the Earth's atmosphere. Other gases, such as carbon dioxide, water vapor, methane,
oxides of nitrogen, ozone, and ammonia, are considered trace gases. Although relatively unimportant in terms
of their absolute volume, they have significant effects on the Earth's weather and climate. !
Transportation End-Use Sector: Consists of private and public vehicles that move people and commodities.
Included are automobiles, trucks, buses, motorcycles, railroads and railways (including streetcars and subways),
aircraft, ships, barges, and natural gas pipelines.
Troposphere.1&7 The lowest layer of the atmosphere and contains about 95 percent of the mass of air in the Earth's
atmosphere. The troposphere extends from the Earth's surface up to about 10 to 15 kilometers. All weather
processes take place in the troposphere. Ozone that is formed in the troposphere plays a significant role in both
the greenhouse gas effect and urban smog. See ozone precursor, stratosphere, atmosphere.
Tropospheric ozone precursor. See ozone precursor.
Tropospheric ozone.' See ozone.
Ultraviolet radiation (UV). n A portion of the electromagnetic spectrum with wavelengths shorted than visible
light. The sun produces UV, which is commonly split into three bands of decreasing wavelength. Shorter
wavelength radiation has a greater potential to cause biological damage on living organisms. The longer
wavelength ultraviolet band, UVA, is not absorbed by ozone in the atmosphere. UVB is mostly absorbed by
ozone, although some reaches the Earth. The shortest wavelength band, UVC, is completely absorbed by ozone
and normal oxygen in the atmosphere.
Unfinished oils.3 All oils requiring further refinery processing, except those requiring only mechanical blending.
Includes naphtha and lighter oils, kerosene and light gas oils, heavy gas oils, and residuum.
United Nations Framework Convention on Climate Change (UNFCCC).' The international treaty unveiled at
the United Nations Conference on Environment and Development (UNCED) in June 1992. The UNFCCC
commits signatory countries to stabilize anthropogenic (i.e. human-induced) greenhouse gas emissions to
"levels that would prevent dangerous anthropogenic interference with the climate system". The UNFCCC also
requires that all signatory parties develop and update national inventories of anthropogenic emissions of all
greenhouse gases not otherwise controlled by the Montreal Protocol. Out of 155 countries that have ratified this
accord, the United States was the first industrialized nation to do so.
Vehicle miles traveled (VMT).8 One vehicle traveling the distance of one mile. Thus, total vehicle miles is the
total mileage traveled by all vehicles.
Volatile organic compounds (VOCs). 6 Organic compounds that evaporate readily into the atmosphere at normal
temperatures. VOCs contribute significantly to photochemical smog production and certain health problems.
See non-methane volatile organic compounds.
Wastewater. 2 Water that has been used and contains dissolved or suspended waste materials. See sewage
treatment. :
Water vapor. l The most abundant greenhouse gas; it is the water present in the atmosphere in gaseous form.
Water vapor is an important part of the natural greenhouse effect. While humans are not significantly
increasing its concentration, it contributes to the enhanced greenhouse effect because the warming influence of
greenhouse gases leads to a positive water vapor feedback. In addition to its role as a natural greenhouse gas,
water vapor plays an important role in regulating the temperature of the planet because clouds form when
excess water vapor in the atmosphere condenses to form ice and water droplets and precipitation.
Waxes. 2 Solid or semisolid materials derived from petroleum distillates or residues. Light-colored, more or less
translucent crystalline masses, slightly greasy to the touch, consisting of a mixture of solid hydrocarbons in
which the paraffin series predominates. Included are all marketable waxes, whether crude scale or fully refined.
Used primarily as industrial coating for surface protection.
Weather.' Weather is the specific condition of the atmosphere at a particular place and time. It is measured in
terms of such things as wind, temperature, humidity, atmospheric pressure, cloudiness, and precipitation. In
most places, weather can change from hour-to-hour, day-to-day, and season-to-season. Climate is the average
Z-17
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of weather over time and space. A simple way of remembering the difference is that climate is what you expect
(e.g. cold winters) and 'weather' is what you get (e.g. a blizzard). See climate.
Wetland.7 Land that stays flooded all or part of the year with fresh or salt water.
Wetlands.2 Areas regularly saturated by surface or groundwater and subsequently characterized by a prevalence of
vegetation adapted for life in saturated-soil conditions.
Wood energy.2 Wood and wood products used as fuel, including roundwood (i.e., cordwood), limbwood, wood
chips, bark, sawdust, forest residues, and charcoal.
References
1 U.S. Environmental Protection Agency, Global Warming website, .
February 26, 1999.
2 Energy Information Administration, Emissions of Greenhouse Gases in the United States 1997, DOE/EIA-
0573(97), U.S. Department of Energy, Washington, DC. October 1998. [See< http://www.eia.doe.gov>]
3 Energy Information Administration, Annual Energy Review 1997, DOE/EIA-0387(97), U.S. Department of
Energy, Washington, DC., July 1998.
4 United Nations Framework Convention on Climate Change. [See ]
5 Intergovernmental Panel on Climate Change, Climate Change 1995: The Science of Climate Change, Cambridge
University Press: New York, 1996
6 Cooper's Comprehensive Environmental Desk Reference, Arthur R. Cooper, Sr., Van Nostrand Reinhold: New
York, 1996.
7 Miller, G. Tyler, Jr., Living in the Environment, An Introduction to Environment Science, sixth edition, 1990.
8 Davis, Stacy, Transportation Energy Data Book, Oak Ridge National Laboratory, U.S. Department of Energy,
Edition 17,1997.
Z-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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Industrial: The industrial economic sector is the only economic sector to exhibit a decrease in emissions
between 1990 and 2000. The majority of emissions are comprised of COz from fossil fuel combustion,
although more than 25 specific industrial processes contribute to greenhouse gas emissions from this sec-
tor.
Transportation: This economic sector has been steadily increasing from 1990 through 2000 due to sever-
al factors, including population growth, urban sprawl, low fuel prices, decreased average fuel efficiency,
increased air travel and freight transportation. While transportation emissions are mostly from vehicles
on the roads, they also come from airplanes, boats, trains, and other equipment.
Electricity Generation at Power Plants: Electricity generation in"the United States is composed of tradi-
tional electric utilities, cogenerators, and nonutility power producers. This economic sector includes the'
generation, transmission, and distribution of electricity. Emissions result primarily in the form of CCh
from fossil fuel combustion. Electricity generation accounts for over one-third of all U.S. greenhouse gas
emissions, and is the largest of the economic sectors.
Commercial: Like most of the other economic sectors, commercial emissions are derived mainly from
COz emissions from the combustion of fossil fuels used to supply businesses with heat and electricity.
Other types of emissions that result from this economic sector come from the use of landfills, combus-
tion of waste, leaks from the use of refrigerants, and stationary combustion.
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vvEPA
United States i !
Enviromental Protection :
Agency
EPA 430-R-02-Q03 April 2002
Office of Atmospheric Programs (6204N)
Washington, DO 20460
Official Business
Penalty for Private Use
$300 i i
**r^fr
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