430R03004
III of U:S. Greenhouse Gas
|p; and Sinks: 1990-2001
i, )**'<**"
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Acknowledgments
The Environmental Protection Agency would like to acknowledge the many individual and organizational
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, EPA's Office of Atmospheric Programs would like to thank some key contributors and reviewers
whose work has significantly improved this year's report.
Work on fuel combustion and industrial process emissions was lead by Bill Irving, Leif Hockstad, and Lisa
Hanle. 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. Tom Wirth led the preparation of the
chapter on Land-Use Change and Forestry. Work on emissions of MFCs, PFCs, and SF6 was directed by Deborah
Schafer and Dave Godwin. Veronika Pesinova contributed work on emissions from mobile combustion.
Within the EPA, other Offices also contributed data, analysis and technical review for this report. 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.
The Energy Information Administration and the Department of Energy contributed invaluable data and analysis
on numerous energy-related topics. The U.S. Forest Service prepared the forest carbon inventory, and the Department
of Agriculture's Agricultural Research Service and the Natural Resource Ecology Laboratory at Colorado State
University contributed leading research on nitrous oxide and carbon fluxes from soils.
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.
We would also like to thank Marian Martin Van Pelt, Randall Freed, and their staff at ICF Consulting's Climate
and Atmospheric Policy Practice, including John Venezia, Kim Raby, Katrin Peterson, Barbara Braatz, Leonard
Crook, Sarah Percy, Diana Pape, Bill Cowart, Anne Choate, Noam Glick, Jeffrey King, Ravi Kantamaneni, Robert
Lanza, Deanna Lekas, Caren Mintz, Laxmi Palreddy, Jeremy Scharfenberg, David Duong, Matt Stanberry, Vanessa
Melendez, and Philip Groth 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 decision 3/CP.5 of the LJNFCCC Conference of the Parties, national inventories
for 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 site.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.
1 See Article 4(l)(a) of the United Nations Framework Convention on Climate Change .
2 See .
ii U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
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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 x
Boxes xi
Executive Summary ES-1
Recent Trends in U.S. Greenhouse Gas Emissions ES-2
Emissions by Economic Sector ES-7
Global Warming Potentials ES-10
Carbon Dioxide Emissions ES-10
Methane Emissions ES-18
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-1
Changes in Historical Data Changes-9
1. Introduction 1-1
Greenhouse Gases 1-2
Global Warming Potentials 1-6
Recent Trends in U.S. Greenhouse Gas Emissions 1-8
Emissions by Economic Sectors 1-15
Methodology and Data Sources 1-21
Uncertainty in and Limitations of Emission Estimates 1-22
Organization of Report 1-23
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) 2-24
Coal Mining 2-30
Natural Gas Systems 2-32
Petroleum Systems 2-34
Municipal Solid Waste Combustion 2-36
Natural Gas Flaring and Ambient Air Pollutant Emissions from Oil and Gas Activities 2-39
International Bunker Fuels 2-41
Wood Biomass and Ethanol Consumption 2-45
iii
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List of Tables,
Figures, and Boxes
Tables
Table ES-1: 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 (Tg CO2 Eq. and Percent) ES-5
Table ES-3: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO2 Eq.) ES-7
Table ES-4: U.S Greenhouse Gas Emissions by Economic Sector and Gas with Electricity-Related
Emissions Distributed (Tg CO2 Eq.) ES-8
Table ES-5: Recent Trends in Various U.S. Data (Index 1990 = 100) and Global Atmospheric CO2
Concentration ES-9
Table ES-6: Global Warming Potentials (100 Year Time Horizon) Used in this Report ES-10
Table ES-7: Comparison of 100 Year GWPs ES-11
Table ES-8: U.S. Sources of CO2 Emissions and Sinks (Tg CO2 Eq.) ES-13
Table ES-9: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.) ES-14
Table ES-10: U.S. Sources of CH4 Emissions (Tg CO2 Eq.) ES-18
Table ES-11: U.S. Sources of Nitrous Oxide Emissions (Tg CO2 Eq.) ES-21
Table ES-12: Emissions of HFCs, PFCs, and SF6 (Tg CO2 Eq.) ES-23
Table ES-13: Emissions of Ozone Depleting Substances (Gg) ES-24
Table ES-14: Emissions of NOx, CO, NMVOCs, and SO2 (Gg) ES-25
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 1-3
Table 1-2: Global Warming Potentials and Atmospheric Lifetimes (Years) Used in this Report 1-6
Table 1-3: Comparison of 100 Year GWPs 1-7
Table 1-4: Effects on U.S. Greenhouse Gas Emission Trends Using IPCC SAR and TAR GWP Values
(TgC02Eq.) 1.7
Table 1-5: Comparison of Emissions by Sector using IPCC SAR and TAR GWP Values (Tg CO2Eq.) 1-8
Table 1-6: Annual Change in CO2 Emissions from Fossil Fuel Combustion for Selected Fuels and
Sectors (Tg CO2 Eq. and Percent) 1-10
Table 1-7: Recent Trends in Various U.S. Data (Index 1990 = 100) 1-14
Table 1-8: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq.) 1-12
Table 1-9: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg) 1-13
Table 1-10: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector
(TgC02Eq.) 1-15
Table 1-11: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO2 Eq. and Percent
of Total in 2001) 1-16
Table 1-12: Electricity Generation-Related Greenhouse Gas Emissions (Tg CO2 Eq.) 1-18
Table 1-13: U.S Greenhouse Gas Emissions by "Economic Sector" and Gas with Electricity-Related
Emissions Distributed (Tg CO2 Eq.) and percent of total in 2001 1-19
Table 1-14: Transportation-Related Greenhouse Gas Emissions (Tg CO Eq.) 1-20
Table 1-15: IPCC Sector Descriptions 1-23
vi U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
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Table 1-16: List of Annexes 1-24
Table 2-1: Emissions from Energy (Tg CO2 Eq.) 2-2
Table 2-2: 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
Table 2-4: Fossil Fuel Carbon in Products (Tg CO2 Eq.) 2-7
Table 2-5: CO2 Emissions from International Bunker Fuels (Tg CO2 Eq.) 2-7
Table 2-6: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.) 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./QBtu) 2-14
Table 2-9: Carbon Intensity from all Energy Consumption by Sector (Tg CO2 Eq./QBtu) 2-15
Table 2-10: Change in CO2 Emissions from Direct Fossil Fuel Combustion Since 1990 (Tg CO2 Eq.) 2-16
Table 2-11: 2001 Non-Energy Fossil Fuel Consumption, Storage, and Emissions
(Tg CO2 Eq. unless otherwise noted) 2-19
Table 2-12: Storage and Emissions from Non-Energy Fossil Fuel Consumption (Tg CO2 Eq.) 2-20
Table 2-13: CH4 Emissions from Stationary Combustion (Tg CO2 Eq.) 2-22
Table 2-14: N2O Emissions from Stationary Combustion (Tg CO2 Eq.) 2-22
Table 2-15: CH4 Emissions from Stationary Combustion (Gg) 2-23
Table 2-16: N2O Emissions from Stationary Combustion (Gg) 2-23
Table 2-17: NOx, CO, and NMVOC Emissions from Stationary Combustion in 2001 (Gg) 2-24
Table 2-18: CH4 Emissions from Mobile Combustion (Tg CO2 Eq.) 2-26
Table 2-19: N2O Emissions from Mobile Combustion (Tg CO2 Eq.) 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 2001 (Gg) 2-28
Table 2-23: CH4 Emissions from Coal Mining (Tg CO2 Eq.) 2-31
Table 2-24: CH4 Emissions from Coal Mining (Gg) 2-31
Table 2-25: Coal Production (Thousand Metric Tons) 2-32
Table 2-26: CH4 Emissions from Natural Gas Systems (Tg CO2 Eq.) 2-33
Table-2-27: CH4 Emissions from Natural Gas Systems (Gg) 2-33
Table 2-28: CH4 Emissions from Petroleum Systems (Tg CO2 Eq.) 2-35
Table 2-29: CH4 Emissions from Petroleum Systems (Gg) 2-35
Table 2-30: CO2 and N2O Emissions from Municipal Solid Waste Combustion (Tg CO2 Eq.) 2-37
Table 2-31: CO2 and N2O Emissions from Municipal Solid Waste Combustion (Gg) 2-37
Table 2-32: NOx, CO, and NMVOC Emissions from Municipal Solid Waste Combustion (Gg) 2-37
Table 2-33: Municipal Solid Waste Generation (Metric Tons) and Percent Combusted 2-38
Table 2-34: U.S. Municipal Solid Waste Combusted, by Data Source (Metric Tons) 2-39
Table 2-35: CO2 Emissions from Natural Gas Flaring 2-40
Table 2-36: NOx, NMVOCs, and CO Emissions from Oil and Gas Activities (Gg) 2-40
Table 2-37: Total Natural Gas Reported Vented and Flared (Million Ft3) and Thermal Conversion
Factor (Btu/Ft3) 2-40
Table 2-38: Emissions from International Bunker Fuels (Tg CO2 Eq.) 2-43
Table 2-39: Emissions from International Bunker Fuels (Gg) 2-43
Table 2-40: Aviation Jet Fuel Consumption for International Transport (Million Gallons) 2-44
Table 2-41: Marine Fuel Consumption for International Transport (Million Gallons) 2-45
Table 2-42: CO2 Emissions from Wood Consumption by End-Use Sector (Tg CO2 Eq.) 2-46
Table 2-43: CO2 Emissions from Wood Consumption by End-Use Sector (Gg) 2-46
vii
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Table 2-44: CO2 Emissions from Ethanol Consumption 2-46
Table 2-45: Woody Biomass Consumption by Sector (Trillion Btu) 2-47
Table 2-46: Ethanol Consumption 2-47
Table 2-47: CH4 Emissions from Non-Combustion Fossil Sources (Gg) 2-48
Table 2-48: Formation of CO2 Through Atmospheric CH4 Oxidation (Tg CO2 Eq.) 2-48
Table 3-1: Emissions from Industrial Processes (Tg CO2 Eq.) 3-2
Table 3-2: Emissions from Industrial Processes (Gg) 3-3
Table 3-3: CO2 Emissions from Iron and Steel Production 3-4
Table 3-4: CO2 Emissions from Cement Production 3-5
Table 3-5: Cement Production (Gg) 3-6
Table 3-6: CO2 Emissions from Ammonia Manufacture 3-7
Table 3-7: CO2 Emissions from Urea Application 3-7
Table 3-8: Ammonia Production 3-8
Table 3-9: Urea Production 3-8
Table 3-10: Urea Net Imports 3-9
Table 3-11: Net CO2 Emissions from Lime Manufacture 3-10
Table 3-12: CO2 Emissions from Lime Manufacture (Gg) 3-10
Table 3-13: Lime Production and Lime Use for Sugar Refining and PCC (Thousand Metric Tons) 3-11
Table 3-14: Hydrated Lime Production (Thousand Metric Tons) 3-11
Table 3-15: CO2 Emissions from Limestone & Dolomite Use (Tg CO2 Eq.) 3-12
Table 3-16: CO2 Emissions from Limestone & Dolomite Use (Gg) 3-12
Table 3-17: Limestone and Dolomite Consumption (Thousand Metric Tons) 3-13
Table 3-18: Dolomitic Magnesium Metal Production Capacity (Metric Tons) 3-14
Table 3-19: CO2 Emissions from Soda Ash Manufacture and Consumption 3-15
Table 3-20: CO2 Emissions from Soda Ash Manufacture and Consumption (Gg) 3-15
Table 3-21: Soda Ash Manufacture and Consumption (Thousand Metric Tons) 3-16
Table 3-22: CO, Emissions from Titanium Dioxide 3-16
Table 3-23: Titanium Dioxide Production 3-17
Table 3-24: CO, Emissions from Ferroalloy Production 3-18
Table 3-25: Production of Ferroalloys (Metric Tons) 3-18
Table 3-26: CO2 Emissions from Carbon Dioxide Consumption 3-19
Table 3-27: Carbon Dioxide Consumption 3-20
Table 3-28: CH4 Emissions from Petrochemical Production 3-20
Table 3-29: Production of Selected Petrochemicals (Thousand Metric Tons) 3-21
Table 3-30: CH4 Emissions from Silicon Carbide Production 3-21
Table 3-31: Production of Silicon Carbide 3-21
Table 3-32: N2O Emissions from Nitric Acid Production 3-22
Table 3-33: Nitric Acid Production 3-22
Table 3-34: N2O Emissions from Adipic Acid Production 3-23
Table 3-35: Adipic Acid Production 3-24
Table 3-36: N2O Emissions from Nitrous Oxide Product Usage 3-25
Table 3-37: N2O Production (Thousand Metric Tons) 3-26
Table 3-38: Emissions of HFCs and PFCs from ODS Substitution (Tg CO2 Eq.) 3-27
Table 3-39: Emissions of HFCs and PFCs from ODS Substitution (Mg) 3-27
Table 3-40: CO2 Emissions from Aluminum Production 3-28
Table 3-41: PFC Emissions from Aluminum Production (Tg CO2 Eq.) 3-29
viii U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
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Table 3-42: PFC Emissions from Aluminum Production (Gg) 3-29
Table 3-43: Production of Primary Aluminum 3-30
Table 3-44: HFC-23 Emissions from HCFC-22 Production 3-31
Table 3-45: HCFC-22 Production 3-32
Table 3-46: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Tg CO2 Eq.) 3-32
Table 3-47: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Mg) 3-33
Table 3-48: SF^ Emissions from Electrical Transmission and Distribution 3-34
o
Table 3-49: SF6 Emissions from Magnesium Production and Processing 3-36
Table 3-50: SF6 Emission Factors (kg SF6 per metric ton of magnesium) 3-36
Table 3-51: 2001 Potential and Actual Emissions of HFCs, PFCs, and SF6 from Selected Sources
(TgC02Eq.) 3-37
Table 3-52: NOx, CO, and NMVOC Emissions from Industrial Processes (Gg) 3-38
Table 4-1: Emissions of NOx, CO, and NMVOC from Solvent Use (Gg) 4-2
Table 5-1: Emissions from Agriculture (Tg CO2 Eq.) 5-2
Table 5-2: Emissions from Agriculture (Gg) 5-2
Table 5-3: CH4 Emissions from Enteric Fermentation (Tg CO2 Eq.) 5-3
Table 5-4: CH4 Emissions from Enteric Fermentation (Gg) 5-3
Table 5-5: CH4 andN2O Emissions from Manure Management (Tg CO2Eq.) 5-7
Table 5-6: CH4 and N2O Emissions from Manure Management (Gg) 5-7
Table 5-7: CH4 Emissions from Rice Cultivation (Tg CO2Eq.) 5-11
Table 5-8: CH4 Emissions from Rice Cultivation (Gg) 5-12
Table 5-9: Rice Areas Harvested (Hectares) 5-13
Table 5-10: N2O Emissions from Agricultural Soil Management (Tg CO2 Eq.) 5-16
Table 5-11: N2O Emissions from Agricultural Soil Management (Gg) 5-16
Table 5-12: Direct N2O Emissions from Managed Soils (Tg CO2 Eq.) 5-16
Table 5-13: Direct N2O Emissions from Pasture, Range, and Paddock Livestock Manure (Tg CO2Eq.) 5-16
Table 5-14: Indirect N2O Emissions (Tg CO2 Eq.) 5-17
Table 5-15: Emissions from Field Burning of Agricultural Residues (Tg CO2 Eq.) 5-20
Table 5-16: Emissions from Field Burning of Agricultural Residues (Gg) 5-21
Table 5-17: Agricultural Crop Production (Thousand Metric Tons of Product) 5-22
Table 5-18: Percentage of Rice Area Burned by State 5-22
Table 5-19: Percentage of Rice Area Burned in California 5-23
Table 5-20: Key Assumptions for Estimating Emissions from Agricultural Residue Burning 5-23
Table 5-21: Greenhouse Gas Emission Ratios 5-24
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 Changes in Carbon Stocks in Forest and Harvested Wood Pools, and Total Net
Forest Carbon Flux (Tg CO2 Eq.) 6-5
Table 6-4: Net Changes in Carbon Stocks in Forest and Harvested Wood Pools, and Total Net
Forest Carbon Flux (Tg C) 6-5
Table 6-5: U.S. Forest Carbon Stock Estimates (Tg C) 6-5
Table 6-6: Net CO2 Flux From Urban Trees (Tg CO2 Eq.) 6-10
Table 6-7: Carbon Stocks (Metric Tons C), Annual Carbon Sequestration (Metric Tons C/yr), Tree Cover
(Percent), and Annual Carbon Sequestration per Area of Tree Cover (kg C/m2 cover-yr) for Ten
U.S. Cities 6-11
Table 6-8: Net C02 Flux From Agricultural Soils (Tg CO2 Eq.) 6-13
Table 6-9: Net Annual CO2 Flux from U.S. Agricultural Soils Based on Monte Carlo Simulation (Tg CO2 Eq.) ..6-16
IX
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Table 6-10: Quantities of Applied Minerals (Thousand Metric Tons) 6-17
Table 6-11: Net CO2 Flux from Landfilled Yard Trimmings (Tg CO2 Eq.) 6-19
Table 6-12: Storage Factor (kg C/kg dry yard trimmings), Moisture Content (kg water/kg wet yard
trimmings), Yard Trimmings Composition (percent), and Carbon Storage Factor (kg C/kg wet
yard trimmings) of Landfilled Yard Trimmings 6-20
Table 6-13: Collection and Destination of Yard Trimmings (Million Metric Tons, or Tg, wet weight) 6-20
Table 7-1: Emissions from Waste (Tg CO2 Eq.) 7-2
Table 7-2: Emissions from Waste (Gg) 7-2
Table 7-3: CH4 Emissions from Landfills (Tg CO2 Eq.) 7-3
Table 7-4: CH4 Emissions from Landfills (Gg) 7-3
Table 7-5: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Tg CO2 Eq.) 7-5
Table 7-6: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Gg) 7-5
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-1: U.S. GHG Emissions by Gas ES-2
Figure ES-2: Annual Percent Change in U.S. GHG Emissions ES-4
Figure ES-3: Absolute Change in U.S. Greenhouse Gas Emissions Since 1990 ES-4
Figure ES-4: 2001 Greenhouse Gas Emissions by Gas ES-4
Figure ES-5: Emissions Allocated to Economic Sectors ES-7
Figure ES-6: Emissions with Electricity Distributed to Economic Sectors ES-8
Figure ES-7: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product ES-9
Figure ES-8: 2001 U.S. Fossil Carbon Flows (Tg CO2 Eq.) ES-12
Figure ES-9: 2001 Sources of CO2 ES-12
Figure ES-10: 2001 U.S. Energy Consumption by Energy Source ES-13
Figure ES-11: U.S. Energy Consumption (Quadrillion Btu) ES-13
Figure ES-12: 2001 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type ES-15
Figure ES-13: 2001 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion ES-15
Figure ES-14: 2001 Sources of CH4 ES-18
Figure ES-15: 2001 Sources of N2O ES-20
Figure ES-16: 2001 Sources of HFCs, PFCs, and SF6 ES-23
Figure 1-1: U.S. GHG Emissions by Gas 1-9
Figure 1-2: Annual Percent Change in U.S. GHG Emissions 1-9
Figure 1-3: Absolute Change in U.S. GHG Emissions Since 1990 1-9
Figure 1-4: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product 1-10
Figure 1-5: U.S. GHG Emissions by Chapter/IPCC Sector 1-14
Figure 1-6: Emissions Allocated to Economic Sectors 1-15
Figure 1-7: Emissions with Electricity Distributed to Economic Sectors 1-18
Figure 2-1: 2001 Energy Chapter GHG Sources 2-1
Figure 2-2: 2000 U.S. Fossil Carbon Flows (Tg CO2 Eq.) 2-3
Figure 2-3: 2001 U.S. Energy Consumption by Energy Source 2-4
Figure 2-4: Annual Deviations from Normal Heating Degree Days for the United States (1949-2001) 2-5
x U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
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Figure 2-5: Annual Deviations from Normal Cooling Degree Days for the United States (1949-2001) 2-5
Figure 2-6: Aggregate Nuclear and Hydroelectric Power Plant Capacity Factors in the United States
(1973-2001) 2-6
Figure 2-7: U.S. Energy Consumption (Quadrillion Btu) 2-6
Figure 2-8: 2001 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type 2-7
Figure 2-9: 2001 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion 2-8
Figure 2-10: Motor Gasoline Retail Prices (Real) 2-9
Figure 2-11: Motor Vehicle Fuel Efficiency 2-9
Figure 2-12: 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: U.S. Energy Consumption and Energy-Related CO2 Emissions Per Capita and Per Dollar GDP.... 2-15
Figure 2-17: Change in CO2 Emissions from Fossil Fuel Combustion Since 1990 by End-Use Sector 2-15
Figure 2-18: Mobile Source CH4 and N2O Emissions 2-25
Figure 3-1: 2001 Industrial Processes Chapter GHG Sources 3-1
Figure 5-1: 2001 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 by Region, 1997 6-6
Figure 6-3. Forest Carbon Stocks, Per Hectare, by County, 1997 6-7
Figure 6-4. Net Annual CO2 Flux, per Hectare, From Mineral Soils Under Agricultural Management,
1990-1992 6-14
Figure 6-5. Net Annual CO2 Flux, per Hectare, From Mineral Soils Under Agricultural Management,
1993-2001 6-14
Figure 6-6. Net Annual CO2 Flux, per Hectare, From Organic Soils Under Agricultural Management,
1990-1992 6-15
Figure 6-7. Net Annual CO2 Flux, per Hectare, From Organic Soils Under Agricultural Management,
1993-2001 6-15
Figure 7-1: 2001 Waste Chapter GHG Sources 7-1
Boxes
Box ES-1: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data ES-9
Box ES-2: The IPCC Third Assessment Report and Global Warming Potentials ES-11
Box ES-3: Emissions of Ozone Depleting Substances ES-24
Box ES-4: Sources and Effects of Sulfur Dioxide ES-26
Box 1-1: The IPCC Third Assessment Report and Global Warming Potentials 1-8
Box 1-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data 1-14
Box 1-3: IPCC Good Practice Guidance 1-21
Box 2-1: Weather and Non-Fossil Energy Effects on CO2 from Fossil Fuel Combustion Trends 2-5
Box 2-2: Carbon Intensity of U.S. Energy Consumption 2-14
Box 2-3: Biogenic Emissions and Sinks of Carbon 2-37
Box 2-4: Formation of CO2 Through Atmospheric CH4 Oxidation 2-48
Box 3-1: Potential Emission Estimates of HFCs, PFCs, and SF^ 3-37
0
Box 5-1: DAYCENT Model Estimates of N2O Emissions from Agricultural Soils 5-19
Box 6-1: Century model estimates of soil carbon stock changes on cropland 6-18
Box 7-1: Biosenic Emissions and Sinks of Carbon 7-3
xi
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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 1992, the United States signed and ratified 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. Such a level should be achieved within a time-frame sufficient to allow ecosystems to adapt
naturally to climate change, to ensure that food production is not threatened and to enable economic development to
proceed in a sustainable manner."2
Parties to the Convention, by ratifying, committed "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 2001. To ensure that the U.S. emissions inventory is comparable to those of other UNFCCC Parties, the estimates
presented here were calculated using methodologies consistent with those recommended in the Revised 1996 IPCC
Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IE A 1997) and the IPCC Good Practice Guidance
and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2000). For most source categories, the IPCC
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
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(l)(a) of the United Nations Framework Convention on Climate Change (also identified in Article 12). See .
Executive Summary ES-1
-------
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.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 non-
methane 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, human activities have
changed their atmospheric concentrations. Since the pre-
industrial era (i.e., ending about 1750), concentrations of
these greenhouse gases have increased by 31, 150, and 16
percent, respectively (IPCC 2001).
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 entry
into force 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 2001, total U.S. greenhouse gas emissions were 6,936.2
teragrams of carbon dioxide equivalents (Tg CO2 Eq.)5 (13.0
percent above 1990 emissions). Emissions declined for the
second time since the base year 1990, decreasing by 1.6
percent (111.2 Tg CO2 Eq.) from 2000 to 2001, driven primarily
by decreases in CO2 emissions from fossil fuel combustion.
The following factors were primary contributors to this
decrease: 1) slow economic growth in 2001, leading to
decreased demand for electricity fuels, 2) a considerable
reduction in industrial output, leading to decreased demand
for electricity and fossil fuel, 3) warmer winter conditions
compared to 2000, and 4) increased output from nuclear
facilities. (See the 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 2001.
Figure ES-1
U.S. GHG Emissions by Gas
I HFCs, PFCs, & SF6
I Nitrous Oxide
* Methane
• Carbon Dioxide
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 section on Global Warming Potentials, Chapter 1.)
ES-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table ES-1: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg C02 Eq.)
Gas/Source
1990
1995 1996 1997 1998 1999 2000 2001
5,334.4
5,141.5
74.4
36.8
18.5
20.5
12.8
8.7
7.0
5.3
4.3
1.7
1.1
1.9
(1,064.2)
707.0
650.0
216.1
127.2
123.0
73.5
36.2
26.6
24.2
7.6
8.5
4.9
1.5
0.7
0.7
430.9
284.1
60.9
16.6
19.9
13.9
13.2
17.2
4.5
0.4
0.3
0.9
99.5
21.7
27.0
27.5
5.9
11.8
5.6
6,514.9
5,450.7
5,514.8
5,325.8
68.3
37.1
19.4
20.3
13.5
8.2
7.6
5.6
4.2
1.7
1.1
2.0
(1,061.0)
702.3
636.8
212.1
127.4
120.5
68.4
34.9
26.8
23.9
7,0
8.7
4.8
1.6
0.7
0.7
441.7
293.2
60.7
17.0
20.7
14.1
13.8
17.0
4.5
0.4
0.3
0.9
113.6
30.4
31.1
27.7
5.4
12.5
6.5
6,707.0
5,646.0
5,595.4
5,400.0
71.9
38.3
21.2
20.7
13.7
7.6
7.1
5.6
4.4
1.8
1.2
2.0
(840.6)
709.9
629.5
207.5
126.0
118.3
68.1
36.6
27.3
23.6
7.5
7.5
4.7
1.6
0.8
0.7
440.9
298.2
60.3
17.3
21.2
14.4
13.7
10.3
4.8
0.4
0.3
7.0
116.8
37.7
30.0
25.2
6.5
11.0
6.3
6,782.6
5,942.0
5,614.2
5,420.5
67.4
39.2
22.5
21.9
13.9
6.3
7.3
5.8
4.3
1.8
1.2
2.0
(830.5)
772.9
622.7
202.4
124.0
116.7
67.9
39.0
27.7
22.9
7.9
7.2
4.6
1.6
0.8
0.7
436.8
299.2
59.7
17.3
20.9
14.6
13.7
6.0
4.8
0.5
0.2
7.0
127.6
44.5
40.2
20.9
7.3
9.0
5.8
6,801.3
5,970.9
5,680.7
5,488.8
64.4
40.0
23.9
20.6
13.5
6.7
7.7
5.9
4.2
1.9
1.2
2.0
(841.1)
105.3
615.5
203.7
120.3
116.6
63.7
38.9
28.2
21.6
8.3
7.4
4.5
1.7
0.8
0.7
430.0
297.0
58.8
17.4
20.1
15.1
13.7
5.5
4.8
0.4
0.2
0.9
120.3
50.9
30.4
16.4
7.7
8.9
6.0
6,849.5
6,008.5
5,883.1
5,692.2
65.8
41.2
25.4
19.6
13.3
5.5
5.8
5.4
4.2
1.9
1.2
1.7
(834.6)
99.3
613.4
205.8
121.2
115.7
60.9
38.2
28.3
21.2
7.5
7.6
4.4
1.7
0.8
0.7
429.9
294.6
57.5
17.9
19.1
15.1
14.3
6.0
4.8
0.5
0.2
0.9
121.0
57.3
29.8
15.4
7.4
7.9
3.2
7,047.4
6,212.7
5,794.8
5,614.9
59.1
41.4
26.9
16.6
12.9
5.2
5.3
4.1
4.1
1.9
1.3
1.3
(838.1)
97.3
605.9
202.9
117.3
114.8
60.7
38.9
28.3
21.2
7.6
7.4
4.3
1.5
0.8
0.7
424.6
294.3
54.8
18.0
17.6
15.3
14.2
4.9
4.8
0.5
0.2
0.9
111.0
63.7
19.8
15.3
5.5
4.1
2.5
6,936.2
6,098.1
C02 5,003.7
Fossil Fuel Combustion 4,814.8
Iron and Steel Production 85.4
Cement Manufacture 33.3
Waste Combustion 14.1
Ammonia Manufacture & Urea Application 19.3
Lime Manufacture 11.2
Natural Gas Flaring 5.5
Limestone and Dolomite Use 5.5
Aluminum Production 6.3
Soda Ash Manufacture and Consumption 4.1
Titanium Dioxide Production 1.3
Carbon Dioxide Consumption 0.9
Ferroalloys 2.0
Land-Use Change and Forestry (Sink)3 (1,072.8)
International Bunker Fuels" 113.9
CH4 644.0
Landfills 212.1
Natural Gas Systems 122.0
Enteric Fermentation 117.9
Coal Mining 87.1
Manure Management 31.3
Wastewater Treatment 24.1
Petroleum Systems 27.5
Rice Cultivation 7.1
Stationary Sources 8.1
Mobile Sources 5.0
Petrochemical Production 1.2
field Burning of Agricultural Residues 0.7
Silicon Carbide Production +
International Bunker Fuels'1 0.2
N20 397.6
Agricultural Soil Management 267.5
Mobile Sources 50.6
Manure Management 16.2
Nitric Acid 17.8
Human Sewage 12.7
Stationary Combustion 12.5
Adiptc Acid 15.2
N20 Product Usage 4.3
Reid Burning of Agricultural Residues 0.4
Waste Combustion 0.3
International Bunker Fuels" 1.0
MFCs, PFCs, and SF6 94.4
Substitution of Ozone Depleting Substances 0.9
HCFC-22 Production 35.0
Electrical Transmission and Distribution 32.1
Semiconductor Manufacture 2.9
Aluminum Production 18.1
Magnesium Production and Processing 5.4
__ 6,139.6
Net Emissions (Sources and Sinks) 5,066.8
+ Does not exceed 0.05 Tg C02 Eq.
a For the most recent years, a portion of the sink estimate is based on historical and projected data; see Chapter 6, Table 6-1 for a complete
breakdown. 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.
Executive Summary ES-3
-------
Figure ES-2
Annual Percent Change in U.S. GHG Emissions
2.9%
2.9%
-1.6%
Figure ES-4
2001 Greenhouse Gas Emissions by Gas
1.6% MFCs, PFCs&
6.1%
Figure ES-3
Absolute Change in U.S. GHG
Emissions Since 1990
90S
797
Figure ES-4 illustrates the relative contribution of the
direct greenhouse gases to total U.S. emissions in 2001.
The primary greenhouse gas emitted by human activities in
the United States was CO2, representing approximately 84
percent of total greenhouse gas emissions. 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, natural
gas systems, and enteric fermentation associated with
domestic livestock. Agricultural soil management and mobile
source fossil fuel combustion were the major sources of
N2O emissions. 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 resulted as 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 80 percent of global warming potential (GWP)
weighted emissions in the 1990s. Emissions from this source
category grew by 17 percent (800.1 Tg CO2 Eq.) from 1990 to
2001 and were responsible for most of the increase in national
emissions during this period. The most recent annual
change in CO2 emissions from fossil fuel combustion was a
reduction of 77.3 Tg CO2 Eq. (1.4 percent), which is the first
decrease in emissions since a decrease from 1990 to 1991;
the source's average annual growth rate was 1.3 percent
from 1990 through 2001. 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 generally fluctuates in
response to changes in general economic conditions, energy
prices, weather, and the availability of non-fossil alternatives.
For example, in 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, there would likely
be proportionally greater fossil fuel consumption than a year
ES-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
with poor economic performance, high fuel prices, mild
temperatures, and increased output from nuclear and
hydroelectric plants.
In the longer-term energy consumption patterns respond
to 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 also depend on the type
of fuel or energy consumed and its carbon intensity.
Producing a unit of heat or electricity using natural gas
instead of coal, for example, can reduce the CO2 emissions
because of the lower carbon content of natural gas. Table
ES-2 shows annual changes in emissions during the last six
years for coal, petroleum, and natural gas in selected sectors.
Milder weather conditions in summer and winter of 1997
(compared to 1996) moderated the growth of CO2 emissions
from fossil fuel combustion. The shutdown of several
nuclear power plants, however, lead electric utilities to
increase their consumption of coal and other fuels to offset
the lost nuclear capacity.
In 1998, warm winter temperatures contributed to a
significant drop in residential and commercial natural gas
consumption. This drop in emissions from natural gas used
for heating was 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.6 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 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 offset
reduced hydropower output.
Table ES-2: Annual Change in C02 Emissions from Fossil Fuel Combustion for Selected Fuels and Sectors
(Tg C02 Eq. and Percent)
Sector
Fuel Type 1996101997 1997 to 1998 1998 to 1999 1999 to 2000
a Excludes emissions from International Bunker Fuels.
6 Includes fuels and sectors not shown in table.
' Normals are based on data from 1961 through 1990. Source: NOAA (2002)
2000 to 2001
Electricity Generation
Electricity Generation
Electricity Generation
Transportation3
Residential
Commercial
Industrial
Industrial
All Sectors"
Coal
Natural Gas
Petroleum
Petroleum
Natural Gas
Natural Gas
Coal
Natural Gas
All Fuels"
44.1
13.9
9.0
7.3
(14.0)
3.1
1.2
1.1
74.2
3%
7%
14%
0%
(3%)
2%
1%
0%
1%
30.6
29.1
29.7
33.0
(23.7)
(10.8)
(8.7)
(11.7)
20.5
2%
13%
40%
2%
(9%)
(6%)
(6%)
(2%)
0%
8.7
12.0
(7.6)
58.7
10.0
1.7
(6.1)
(17.6)
68.3
0%
5%
(7%)
4%
9%
1%
(4%)
(4%)
1%
89.4
20.6
(5.7)
49.8
13.9
9.1
2.3
12.5
202.8
5%
8%
(6%)
3%
3%
5%
2%
3%
4%
(50.1)
4.3
10.7
19.7
(9.6)
1.6
(7.7)
(33.5)
(77.9)
(3%)
2%
12%
1%
(1%)
1%
(6%)
(7%)
(1%)
Executive Summary ES-5
-------
In 2001, economic growth in the U.S. slowed
considerably for the second time since 1990, contributing to
a decrease in CO2 emissions from fossil fuel combustion,
also for the second time since 1990. A significant reduction
in industrial output contributed to weak economic growth,
primarily in manufacturing, and led to lower emissions from
the industrial sector. Several other factors also played a role
in this decrease in emissions. Warmer winter conditions
compared to 2000, along with higher natural gas prices,
reduced demand for heating fuels. Additionally, nuclear
facilities operated at their highest capacity on record,
offsetting electricity produced from fossil fuels. Since there
are no greenhouse gas emissions associated with electricity
production from nuclear plants, this substitution reduces
the overall carbon intensity of electricity generation.
Other significant trends in emissions from additional
source categories over the twelve-year period from 1990
through 2001 included the following:
• Carbon dioxide emissions from waste combustion
increased by 12.8 Tg CO2 Eq. (91 percent), as the volume
of plastics and other fossil carbon-containing materials
in municipal solid waste grew.
• Net CO2 flux from land use change and forestry
decreased by 234.7 Tg CO2 Eq. (22 percent), primarily
due to a decline in the rate of net carbon accumulation
in forest carbon stocks.
• Methane emissions from coal mining dropped by 26.4
Tg CO2 Eq. (30 percent) as a result of the mining of less
gassy coal from underground mines and the increased
use of methane collected from degasification systems.
• By 1998, all of the three major adipic acid producing
plants had voluntarily implemented N2O abatement
technology, and as a result, emissions fell by 10.3 Tg
CO2 Eq. (68 percent). The majority of this decline
occurred from 1996 to 1998, despite increased
production.
• Nitrous oxide emissions from agricultural soil
management increased by 26.8 Tg CO2 Eq. (10 percent)
as crop and forage production, manure production, and
fertilizer consumption rose.
• Aggregate HFC and PFC emissions resulting from the
substitution of ozone depleting substances (e.g., CFCs)
increased by 62.7 Tg CO2 Eq. This increase was
significantly offset, however, by reductions in PFC
emissions from aluminum production (14.0 Tg CO2 Eq.
or 77 percent), reductions in emissions of HFC-23 from
the production of HCFC-22 (15.2 Tg CO2 Eq. or 43
percent), and reductions of SF6 from electric power
transmission and distribution systems (16.8 Tg CO2 Eq.
or 52 percent). Reductions in PFC emissions from
aluminum production resulted from both industry
emission reduction efforts and lower domestic aluminum
production. HFC-23 emissions from the production of
HCFC-22 decreased because a reduction in the intensity
of emissions from that source offset an increase in
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.
Overall, from 1990 to 2001, total emissions of CO2 and
N2O increased by 791.1 (16 percent) and 27.0 Tg CO2 Eq. (7
percent), respectively, while CH4 emissions decreased by
38.1 Tg CO2 Eq. (6 percent). During the same period,
aggregate weighted emissions of HFCs, PFCs, and SF6 rose
by 16.6 Tg CO2 Eq. (18 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, trees in urban areas, agricultural soils, and landfilled
yard trimmings, which was estimated to be 12 percent of
total emissions in 2001.
ES-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Emissions by Economic Sector
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
consistency with UNFCCC reporting guidelines, it is also
useful to allocate emissions into more commonly used
sectoral categories. This section reports emissions by the
following economic sectors: Residential, Commercial,
Industry, Transportation, Electricity Generation, and
Agriculture, and U.S. Territories. Table ES-3 summarizes
emissions from each of these sectors. Figure ES-5 shows
the trend in emissions by sector from 1990 to 2001.
Using this categorization, emissions from electricity
generation accounted for the largest portion (33 percent) of
U.S. greenhouse gas emissions in 2001. 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 2001. 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 based to a service-based
economy), fuel switching has occurred, and efficiency
improvements have been made. The remaining 21 percent
of U.S. greenhouse gas emissions were contributed by the
Figure ES-5
Emissions Allocated to Economic Sectors
Year
Note: Does not include U.S. territories
residential, agriculture, and commercial economic sectors,
plus emissions from U.S. Territories. Residences accounted
for about 5 percent, and primarily consisted of 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 N2O emissions from agricultural soils instead of CO2 from
fossil fuel combustion. The commercial sector accounted
for about 7 percent of emissions, while U.S. territories
accounted for 1 percent.
Table ES-3: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg C02 Eq.)
Sector
1990
1995
1996
1997
1998
1999 2000 2001
Electricity Generation
Transportation
Industry
Agriculture
Residential
Commercial
U.S. Territories
Total
Sinks
Net Emissions (Sources
1,862 H
1,526 11
1,423 «
488 ma
335 •
472 m&
34 •
6,140 H
(1'073) 1
and Sinks) 5,067 H|
Note: Totals may not sum. Emissions include C02, CH4,
See Table 1-13 for more
detailed data.
I 1,990
I 1,651
I 1,445
1 526
1 371
1 488
I 44
I 6,515
I (1,064)
1 5,451
HFCs, PFCs,
2,064
1,694
1,485
526
402
495
40
6,707
(1,061)
5,646
and SF6.
2,130
1,707
1,485
538
385
494
43
6,783
(841)
5,942
2,217
1,736
1,433
539
353
474
48
6,801
(830)
5,971
2,227
1,798
1,381
540
372
481
50
6,850
(841)
6,008
2,332
1,849
1,401
526
390
498
52
7,047
(835)
6,213
2,298
1,867
1,316
526
379
497
54
6,936
(838)
6,098
Executive Summary ES-7
-------
Carbon dioxide was also emitted and sequestered by a
variety of activities related to forest management practices,
tree planting in urban areas, the management of agricultural
soils, and landfilling of yard trimmings.
Electricity is ultimately consumed in the economic
sectors described above. Table ES-4 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 electricity
generation were allocated to the residential, commercial,
industry, transportation, and agriculture economic sectors
according to retail sales of electricity.7 These source
categories include CO2 from fossil fuel combustion and the
use of limestone and dolomite for flue gas desulfurization,
CO2 and N2O from waste combustion, CH4 and N2O from
stationary sources, and SF6 from electrical transmission and
distribution systems.
When emissions from electricity are distributed among
these sectors, industry accounts for the largest share of
U.S. greenhouse gas emissions (30 percent) in 2001.
Emissions from the residential and commercial sectors also
increase substantially due to their relatively large share of
electricity consumption (e.g., lighting, appliances, etc.).
Transportation activities remain the second largest
Figure ES-6
Emissions with Electricity Distributed
to Economic Sectors
Industrial
Note: Does not include U.S. territories.
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-6 shows the trend in these emissions by sector
from 1990 to 2001.
Table ES-4: U.S Greenhouse Gas Emissions by Economic Sector and Gas with Electricity-Related Emissions
Distributed (Tg C02 Eq.)
Sector
Industry
Transportation
Residential
Commercial
Agriculture
US Territories
Total
Sinks
Net Emissions (Sources and Sinks)
1990
2,097
1,529
943
1,025
512
34
6,140
(1,073)
5,067
See Table 1-11 for more detailed data.
1995
1996
1997
1998
1999 2000 2001
2,164
1,654
1,020
1,081
553
44
6,515
(1,064)
5,451
2,224
1,697
1,081
1,110
555
40
6,707
(1,061)
5,646
2,245
1,710
1,074
1,151
560
43
6,783
(841)
5,942
2,209
1,740
1,076
1,164
564
48
6,801
(830)
5,971
2,165
1,801
1,095
1,178
560
50
6,850
(841)
6,008
2,201
1,852
1,155
1,241
547
52
7,047
(835)
6,213
2,074
1,870
1,139
1,253
546
54
6,936
(838)
6,098
7 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.
ES-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Box ES-1: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data
Total emissions can be compared to other economic and social indices to highlight changes over time. These comparisons include:
1) emissions per unit of aggregate energy consumption, because energy-related activities are the largest sources of emissions;
2) emissions per unit of fossil fuel consumption, because almost all energy-related emissions involve the combustion of fossil fuels;
3) emissions per unit of electricity consumption, because the electric power industry—utilities and nonutiltties combined—was the largest
source of U.S. greenhouse gas emissions in 2001; 4) emissions per unit of total gross domestic product as a measure of national
economic activity; or 5) emissions per capita.
Table ES-5 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 1.1 percent since 1990. This rate is slower than that for
total energy or fossil fuel consumption and much slower than 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 ES-7). Overall, global atmospheric C02 concentrations—a function of many complex anthropogenic and natural processes—are
increasing at 0.4 percent per year.
Table ES-5: Recent Trends in Various U.S. Data (Index 1990 = 100) and Global Atmospheric C02 Concentration
Variable
Growth
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 Rate'
Greenhouse Gas Emissions3
Energy Consumption11
Fossil Fuel Consumption"
Electricity Consumption11
GDP°
Population11
Atmospheric C02 Concentration6
99
100
100
102
100
101
100
101
102
102
102
103
103
101
103
104
104
106
105
104
101
105
106
106
109
110
105
101
106
108
107
112
112
107
102
109
112
111
115
116
108
102
110
112
112
117
122
109
103
111
113
113
121
127
111
104
112
115
114
124
132
112
104
115
118
118
128
137
113
104
113
115
115
127
137
114
105
1.1%
1.3%
1.3%
2.2%
2.9%
1.2%
0.4%
a GWP weighted values
b Energy content weighted values (EIA 2002a)
0 Gross Domestic Product in chained 1996 dollars (BEA 2002)
d (U.S. Census Bureau 2002)
e Mauna Loa Observatory, Hawaii (Keeling and Whorf 2002)
1 Average annual growth rate
Figure ES-7
U.S. Greenhouse Gas Emissions Per Capita and
Per Dollar of Gross Domestic Product
Real GDP
Population
Emissions
per capita
Emissions
per $GDP
Source: BEA (2002), U.S. Census Bureau (2002), and emission
estimates in this report
Executive Summary ES-9
-------
Global Warming Potentials
Gases in the atmosphere can contribute to the
greenhouse effect both directly and indirectly. Direct
effects occur when the gas itself absorbs radiation. Indirect
radiative forcing occurs when chemical transformations of
the substance 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).8 The IPCC developed the Global
Warming Potential (GWP) concept to compare the ability
of each greenhouse gas to trap heat in the atmosphere
relative to another gas.
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. The
reference gas used is CO2, and therefore GWP-weighted
emissions are measured in teragrams of CO2 equivalents
(Tg CO2 Eq.).9 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:
Tg
Table ES-6: Global Warming Potentials (100 Year Time
Horizon) Used in This Report
Tg CO2 Eq = (Gg of gas) x (GWP);
l,OOOGg
While any time period can be selected, this report uses
the 100 year G WPs recommended by the IPCC, and adopted
by the UNFCCC for reporting purposes (IPCC 1996). GWP
values are listed in Table ES-6.
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).
Gas
GWP
Carbon dioxide (C02)
Methane (CH4)*
Nitrous oxide (N20)
HFC-23
HFC-32
HFC-125
HFC-1343
HFC-143a
HFC-1523
HFC-227ea
HFC-236fa
HFC-4310mee
CF4
C2F6
64^10
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
Source: IPCC (1996)
* 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.
The global carbon cycle is made up of large carbon
flows and reservoirs. Billions of tons of carbon in the form
of CO2 are absorbed by oceans and living biomass (i.e.,
sinks) and are emitted to the atmosphere annually through
natural processes (i.e., sources). When in equilibrium,
carbon fluxes among these various reservoirs are roughly
balanced. Since the Industrial Revolution, this equilibrium
of atmospheric carbon has been disrupted. Atmospheric
concentrations of CO2 have risen about 31 percent (IPCC
2001), principally because of fossil fuel combustion, which
accounted for 97 percent of total U.S. CO2 emissions in
2001. 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).10 Changes in land
8 Albedo is a measure of the Earth's reflectivity; see the Glossary (Annex AB) for definition.
9 Carbon comprises 12/44ths of carbon dioxide by weight.
10 Global CO2 emissions from fossil fuel combustion were taken from Marland et al. (2002).
ES-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Box ES-2: The IPCC Third Assessment Report and Global Warming Potentials
In its Third Assessment Report (TAR), the IPCC updated the global warming potentials (GWPs) of several gases relative to the Second
Assessment Report (SAR), and new GWPs were 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 in the TAR 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 were
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 that were not presented in the Second Assessment Report. Table ES-7 presents
the new Global Warming Potentials, relative to those presented in the Second Assessment Report.
Table ES-7: Comparison of 100 Year GWPs
Gas SAR TAR
Change
Carbon dioxide (C02)
Methane (CH4)*
Nitrous oxide (N20)
HFC-23
HFC-32
HFC-125
HFC-1343
HFC-1433
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
CF4
C2F6
64^10
C6Fi4
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
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 2001,1996)
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 report use the GWPs from the Second
Assessment Report. The UNFCCC reporting guidelines for national inventories11 were updated in 2002, but continue to require the use of
GWPs from the SAR so that current estimates of aggregated greenhouse gas emissions for 1990 through 2001 are consistent with estimates
developed prior to the publication of the TAR. Therefore, to comply with international reporting standards underthe 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, and all estimates are provided throughout this report in both C02 equivalents and unweighted units. A comparison of
emission values using the SAR GWPs versus the TAR GWPs can be found in Chapter 1 and in more detail in Annex S.
use and forestry practices can also emit CO2 (e.g., through Figure ES-9 and Table ES-8 summarize U.S. sources and
conversion of forest land to agricultural or urban use) or sinks of CO2. The remainder of this section discusses CO2
can act as a sink for CO2 (e.g., through net additions to emission trends in greater detail.
forest biomass).
See .
Executive Summary ES-11
-------
Figure ES-8
2001 U.S. Fossil Carbon Flows (Tg C02 Eq.)
(Tg C02 Eq.]
2,030
Natural Gas Liquids,
Liquefied Refinery Gas,
& Other Liquid
IBS ^
Petroieum
1,669
Fossil Fuel
Stock Consumption
Non-Energy Changes
Use Imports 133 Territories
47 32
Fossil Fuel
Combustion
Residual
(Not Oxidized
Fraction)
50
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.
NED = Non-Energy Use
NG = Natural Gas
Figure ES-9
2001 Sources of CO
Fossil Fuel Combustion
Iron and Steel Production
Cement Manufacture
Waste Combustion
Ammonia Production and
Urea Application
Lime Manufacture
Limestone and Dolomite Use •
Natural Gas Flaring |
Aluminum Production H
Soda Ash Manufacture •
and Consumption •
Titanium Dioxide Production |
Ferroalloys |
Carbon Dioxide Consumption |
5,615
C02as a Portion
of all Emissions
5 10 15 20 25 30 35 40
TgCC^Eq
Energy
Energy-related activities, primarily fossil fuel
combustion, accounted for the vast majority of U.S. CO2
emissions for the period of 1990 through 2001. In 2001,
approximately 86 percent of the energy consumed in the
United States was produced through the combustion of
fossil fuels. The remaining 14 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.
ES-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table ES-8: U.S. Sources of C02 Emissions and Sinks (Tg C02 Eq.)
Source or Sink
Fossil Fuel Combustion
Electricity Generation
Transportation
Industrial
Residential
Commercial
U.S. Territories
Iron and Steel Production
Cement Manufacture
Waste Combustion
Ammonia Manufacture & Urea Application
Lime Manufacture
Natural Gas Flaring
Limestone and Dolomite Use
Aluminum Production
Soda Ash Manufacture and Consumption
Titanium Dioxide Production
Carbon Dioxide Consumption
Ferroalloys
Land-Use Change and Forestry (Sink)3 (1
International Bunker Foe/s*
Total
Net Emissions (Sources and Sinks)
1990
4,814.8
1,805.0
1,470.5
955.3
328.9
221.4
33.7
85.4
33.3
14.1
19.3
11.2
5.5
5.5
6.3
4.1
1.3
0.9
2.0
,072.8)
113.9
5,003.7
3,930.9
1995
5,141.5
1,931.8
1,577.8
1,002.6
358.5
226.9
44.0
74.4
36.8
18.5
20.5
12.8
8.7
7.0
5.3
4.3
1.7
1.1
1.9
(1,064.2)
101.0
5,334.4
4,270.3
1996
5,325.8
2,003.9
1,617.4
1,039.5
388.6
236.4
40.1
68.3
37.1
19.4
20.3
13.5
8.2
7.6
5.6
4.2
1.7
1.1
2.0
(1,061.0)
702.3
5,514.8
4,453.8
1997
5,400.0
2,070.8
1,626.9
1,050.8
371.7
237.1
42.8
71.9
38.3
21.2
20.7
13.7
7.6
7.1
5.6
4.4
1.8
1.2
2.0
(840.6)
109.9
5,595.4
4,754.7
1998
5,420.5
2,160.3
1,653.9
1,000.1
338.8
219.5
47.9
67.4
39.2
22.5
21.9
13.9
6.3
7.3
5.8
4.3
1.8
1.2
2.0
(830.5)
112.9
5,614.2
4,783.7
1999
5,488.8
2,173.5
1,713.0
973.2
357.3
221.7
50.2
64.4
40.0
23.9
20.6
13.5
6.7
7.7
5.9
4.2
1.9
1.2
2.0
(841.1)
705.3
5,680.7
4,839.6
2000
5,692.2
2,277.8
1,762.7
991.1
373.9
234.3
52.3
65.8
41.2
25.4
19.6
13.3
5.5
5.8
5.4
4.2
1.9
1.2
1.7
(834.6)
99.3
5,883.1
5,048.5
2001
5,614.9
2,242.8
1,780.9
937.7
363.3
235.9
54.4
59.1
41.4
26.9
16.6
12.9
5.2
5.3
4.1
4.1
1.9
1.3
1.3
(838.1)
97.3
5,794.8
4,956.7
a 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.
Figure ES-10
2001 U.S. Energy Consumption by Energy Source
5.8% Renewable
8.3% Nuclear
22.6% Coal
23.9%
Natural Gas
Figure ES-11
t,-,j V; Petroleum
Source: Annual Energy Review 2001, EIA (2002a), Table 1.3
U.S. Energy Consumption (Quadrillion Btu)
120
Total Energy
Note: Expressed as gross calorific values.
Source: Annual Energy Review 2001, EIA (2002a),
Table 1.3.
Executive Summary ES-13
-------
Fossil Fuel Combustion (5,614.9 Tg C02 Eq.)
As fossil fuels are combusted, the carbon stored in them
is emitted almost entirely 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 and natural gas have about
25 percent and 45 percent less carbon than coal, respectively.
From 1990 through 2001, 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 1.4 percent from 1990 to 2001.
The fundamental factors influencing this trend include (1) a
growing domestic economy over the last 11 years, and
(2) significant growth in emissions from transportation
activities and electricity generation. Between 1990 and 2001,
CO2 emissions from fossil fuel combustion increased from
4,814.8 Tg CO2 Eq. to 5,614.9 Tg CO2 Eq.—a 17 percent total
increase over the twelve-year period.
The four major end-use sectors contributing to CO2
emissions from fossil fuel combustion are 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 on the basis of each sector's share of
aggregate electricity consumption. This method of
distributing emissions assumes that each end-use sector
consumes electricity that is generated from 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.
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.
Table ES-9: C02 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg C02 Eq.)
End-Use Sector
1990
Industrial
Combustion
Electricity
Transportation
Combustion
Electricity
Residential
Combustion
Electricity
Commercial
Combustion
Electricity
U.S. Territories
Total
Electricity Generation
1,632.1
955.3
676.8
1,473.5
1,470.5
3.0
918.8
328.9
589.9
756.6
221.4
535.2
33.7
4,814.8
1,805.0
1995
1996
1997
1998
1999
2000
2001
1,710.3
1,002.6
707.7
1,580.9
1,577.8
3.0
996.4
358.5
637.8
810.0
226.9
583.1
44.0
5,141.5
1,931.8
1,767.4
1,039.5
727.9
1,620.4
1,617.4
3.0
1,056.6
388.6
668.1
841.2
236.4
604.8
40.1
5,325.8
2,003.9
1,796.8
1,050.8
746.0
1,630.0
1,626.9
3.1
1,048.0
371.7
676.4
882.5
237.1
645.4
42.8
5,400.0
2,070.8
1,764.6
1,000.1
764.5
1,657.0
1,653.9
3.1
1,051.6
338.8
712.8
899.4
219.5
679.9
47.9
5,420.5
2,160.3
1,744.8
973.2
771.7
1,716.2
1,713.0
3.2
1,069.4
357.3
712.1
908.2
221.7
686.5
50.2
5,488.8
2,173.5
1,779.5
991.1
788.4
1,766.1
1,762.7
3.4
1,127.3
373.9
753.5
966.9
234.3
732.6
52.3
5,692.2
2,277.8
1,684.5
937.7
746.8
1,784.4
1,780.9
3.6
1,111.1
363.3
747.8
980.5
235.9
744.6
54.4
5,614.9
2,242.8
Note: Totals may not sum due to independent rounding. Emissions from fossil fuel combustion by electricity generation are allocated based on
aggregate national electricity consumption by each end-use sector.
ES-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Figure ES-12
2001C02 Emissions from Fossil Fuel Combustion by
Sector and Fuel Type
Figure ES-13
Relative Contribution by
Fuel Type
2,000 '
Natural Gas
Petroleum
• Coal
Note: Electricity generation also includes emissions of less
than 1 Tg C02 Eq. from geothermal-based electricity generation
2001 End-Use Sector Emissions of C02 from
Fossil Fuel Combustion
I From Electricity
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 30 percent of CO2 from
fossil fuel combustion in 2001. 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 2001,12 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 for
personal vehicle use. The remaining emissions came from
other transportation activities, including the combustion of
diesel fuel in heavy-duty vehicles and jet fuel in aircraft.
Residential and Commercial End-Use Sectors. The
residential and commercial end-use sectors accounted for
20 and 17 percent, respectively, of CO2 emissions from fossil
fuel combustion in 2001. Both sectors relied heavily on
electricity for meeting energy demands, with 67 and 76
percent, respectively, of their emissions attributable to
electricity consumption for lighting, heating, cooling, and
operating appliances. The remaining emissions were due to
the consumption of natural gas and petroleum for heating
and cooking.
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 generators consumed 34 percent
of U.S. energy from fossil fuels and emitted 40 percent of the
CO2 from fossil fuel combustion in 2001. 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 93
percent of all coal consumed for energy in the United States
in 2001. Consequently, changes in electricity demand have
a significant impact on coal consumption and associated
CO2 emissions.
Waste Combustion (26.9 Tg C02 Eq.)
The burning of garbage and non-hazardous solids,
referred to as municipal solid waste (MSW), as well as the
burning of hazardous waste, is usually performed to recover
energy from the waste materials. Carbon dioxide emissions
arise from the organic (i.e., carbon) materials found in these
12 If emissions from international bunker fuels are included, the transportation end-use sector accounted for 33 percent of U.S. emissions
from fossil fuel combustion in 2001.
Executive Summary ES-15
-------
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. Several components of MSW, such as plastics,
synthetic rubber, synthetic fibers, and carbon black, are of
fossil fuel origin, and are included as sources of CO2 emissions.
Natural Gas Flaring (5.2 Tg C02 Eq.)
Flaring of natural gas from oil wells releases COr Natural
gas is flared to relieve rising pressure or to dispose of small
quantities of gas that are not commercially marketable. In
2001, flaring accounted for approximately 0.1 percent of
U.S. CO2 emissions.
Biomass Combustion (183.7 Tg C02 Eq.)
Biomass refers to organically-based carbon fuels (as
opposed to fossil-based). Biomass in the form of fuel wood
and wood waste was used primarily in the industrial sector,
while the transportation 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
CO2 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 in the estimates for Land-
Use Change and Forestry.
The industrial sector accounted for 69 percent of gross
CO2 emissions from biomass combustion, and the residential
sector accounted for 18 percent. Ethanol consumption by
the transportation sector accounted for 6 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, which often release
waste 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 and urea application. Carbon
dioxide emissions from these sources were approximately
148.0 Tg CO2 Eq. in 2001, accounting for about 3 percent of
total CO2 emissions.
Iron and Steel Production (59.1 Tg C02 Eq.)
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, which
contains 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 (41.4 Tg C02 Eq.)
Clinker is an intermediate product in the formation of
finished Portland and masonry cement. Heating calcium
carbonate (CaCO3) in a cement kiln forms lime and CO2. The
lime combines with other materials to produce clinker, and
the CO2 is released into the atmosphere.
Ammonia Manufacture and Urea Application (16.6 Tg C02 Eq.)
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 two fossil fuel-based
reactions produce carbon monoxide and hydrogen gas.
This carbon monoxide is transformed into CO2 in the
presence of a catalyst. The CO2 is generally released into
the atmosphere, but some of the CO2, together with
ammonia, is used as a raw material in the production of
urea [CO(NH2)2], which is a type of nitrogenous fertilizer.
The carbon in the urea that is produced and assumed to
be subsequently applied to agricultural land as a
nitrogenous fertilizer is ultimately released into the
environment as CO2.
Lime Manufacture (12.9Tg C02 Eq.)
Lime is used in steel making, construction, flue gas
desulfurization, 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.
ES-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Limestone and Dolomite Use (5.3 Tg C02 Eq.)
Limestone (CaCO3) and dolomite (CaMg(CO3)) are basic
raw materials used in a wide variety of industries, including
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.
Aluminum Production (4.1 Tg C02 Eq.)
Carbon dioxide is emitted 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
(4.1TgC02Eq.)
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 (1.9 Tg C02 Eq.)
Titanium dioxide (TiO2) is a metal oxide manufactured
from titanium ore, and is principally used as a pigment. It is
used in white paint and as a pigment in the manufacture of
white paper, foods, and other products. Two processes, the
chloride process and the sulfate process, are used for making
TiO2. Carbon dioxide is emitted from the chloride process,
which uses petroleum coke and chlorine as raw materials.
Ferroalloy Production (1.3 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 alter the
material properties of the steel.
Carbon Dioxide Consumption (1.3 Tg C02 Eq.)
Many segments of the economy consume CO2,
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 also alter the natural carbon fluxes between
biomass, soils, and the atmosphere. Forest management
practices, tree planting in urban areas, the management of
agricultural soils, and landfilling of yard trimmings have
resulted in a net uptake (sequestration) of carbon in the
United States, which offset about 14 percent of total U.S.
gross CO2 emissions in 2001. Forests (including vegetation,
soils, and harvested wood) accounted for approximately
91 percent of total 2001 sequestration, urban trees
accounted for 7 percent, agricultural soils (including mineral
and organic soils and the application of lime) accounted
for 2 percent, and landfilled yard trimmings accounted for
1 percent of the total sequestration in 2001. The net forest
sequestration is a result of net forest growth and increasing
forest area, as well as a net accumulation of carbon stocks
in harvested wood pools. The net sequestration in urban
forests is a result of net tree growth in these areas. In
agricultural soils, mineral soils account for a net carbon
sink that is approximately one and a third time larger than
the sum of emissions from organic soils and liming. The
mineral soil carbon sequestration is largely due to
conversion of cropland to permanent pastures and hay
production, a reduction in summer fallow areas in semi-
arid areas, an increase in the adoption of conservation
tillage practices, and an increase in the amounts of organic
fertilizers (i.e., manure and sewage sludge) applied to
agriculture lands. The landfilled yard trimmings net
sequestration is due to the long-term accumulation of yard
trimming carbon in landfills.
Executive Summary ES-17
-------
Methane Emissions
According to the IPCC, CH4 is more than 20 times as
effective as CO2 at trapping heat in the atmosphere. Over
the last two hundred and fifty years, the concentration of
CH4 in the atmosphere increased by 150 percent (IPCC 2001).
Experts believe that over half of this atmospheric increase
was 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 (202.9 TgC02Eq.)
Landfills are the largest anthropogenic source of CH4
emissions in the United States. In an environment where
the oxygen content is low or zero, anaerobic bacteria can
decompose organic materials, such as yard waste, household
waste, food waste, and paper, resulting in the generation of
CH4 and biogenic COr Site-specific factors, such as waste
composition, moisture, and landfill size, influence the level
of methane generation.
Methane emissions from U.S. landfills have decreased
by 4 percent since 1990. The generally declining emission
estimates are a result of two offsetting trends: (1) the amount
of municipal solid waste in landfills contributing to CH4
emissions has increased, thereby increasing the potential
Figure ES-14
2001 Sources of CH4
Landfills
Natural Gas Systems
Enteric Fermentation
Coal Mining
Manure Management ^^^
Wastewater Treatment ^f
Petroleum Systems ^|
Rice Cultivation |
Stationary Sources |
Mobile Sources |
Petrochemical Production |
Agricultural Residue Burning |
Silicon Carbide Production <0.05
CH4 as a Portion
of all Emissions
8.7%
50
100 150 200
Tg CO2 Eq.
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.
Natural Gas and Petroleum Systems
(138.6TgC02Eq.)
Methane is the major component of natural gas. Fugitive
emissions of CH4 occur throughout the production,
processing, transmission, and distribution of natural gas.
Because natural gas is often found in conjunction with
Table ES-10: U.S. Sources of Methane Emissions (Tg C02 Eq.)
Source
1990
Landfills
Natural Gas Systems
Enteric Fermentation
Coal Mining
Manure Management
Wastewater Treatment
Petroleum Systems
Rice Cultivation
Stationary Sources
Mobile Sources
Petrochemical Production
Field Burning of Agricultural Residues 0.7
Silicon Carbide Production +
International Bunker Fuels* 0.2
Total*
+ Does not exceed 0.05 Tg C02 Eq.
* Emissions from International Bunker Fuels are not included in totals.
Note: Totals may not sum due to independent rounding.
1995
1996
1997 1998
1999 2000 2001
216.1
127.2
123.0
73.5
36.2
26.6
24.2
7.6
8.5
4.9
1.5
0.7
0.1
650.0
212.1
127.4
120.5
68.4
34.9
26.8
23.9
7.0
8.7
4.8
1.6
0.7
0.1
636.8
207.5
126.0
118.3
68.1
36.6
27.3
23.6
7.5
7.5
4.7
1.6
0.8
0.1
629.5
202.4
124.0
116.7
67.9
39.0
27.7
22.9
7.9
7.2
4.6
1.6
0.8
0.1
622.7
203.7
120.3
116.6
63.7
38.9
28.2
21.6
8.3
7.4
4.5
1.7
0.8
0.1
615.5
205.8
121.2
115.7
60.9
38.2
28.3
21.2
7.5
7.6
4.4
1.7
0.8
0.1
613.4
202.9
117.3
114.8
60.7
38.9
28.3
21.2
7.6
7.4
4.3
1.5
0.8
0.1
605.9
ES-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
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 2001,
CH4 emissions from U.S. natural gas systems were accounted
for approximately 19percentof U.S. CH4emissions.
Petroleum is often found in the same geological
structures as natural gas, and the two are often retrieved
together. Crude oil is saturated with many lighter
hydrocarbons, including methane. When the oil is brought
to the surface and processed, many of the dissolved lighter
hydrocarbons (as well as water) are removed through a series
of high-pressure and low-pressure separators. The
remaining hydrocarbons in the oil are emitted at various
points along the system. Methane emissions from the
components of petroleum systems generally occur as a result
of system leaks, disruptions, and routine maintenance. In
2001, emissions from petroleum systems were just under 4
percent of U.S. CH4 emissions.
Coal Mining (60.7 TgC02Eq.)
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 type of coal and the
method and rate of mining.
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 2001, coal mining activities emitted 10 percent
of U.S. CH4 emissions. From 1990 to 200 Remissions 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.
Stationary and Mobile Combustion (11.7 Tg C02 Eq.)
In 2001, stationary and mobile combustion were
responsible for CH4 emissions of 7.4 and 4.3 Tg CO2 Eq.,
respectively. The majority of CH4 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.
Petrocbemical and Silicon Carbide Production
(1.5TgC02Eq.)
Small amounts of CH4 are released during the production
of five petrochemicals: carbon black, ethylene, ethylene
dichloride, styrene, and methanol. These production
processes resulted in emissions of 1.5 Tg CO2 Eq. in 2001.
Methane is also emitted from the production of silicon
carbide, a material used as an industrial abrasive. In 2001,
silicon carbide production resulted in emissions of less than
0.1TgCO2Eq.
Enteric Fermentation (114.8 Tg C02 Eq.)
During animal digestion, CH4 is produced through the
process of enteric fermentation, in which microbes residing
in animal digestive systems break down food. 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
2001, enteric fermentation was the source of about 19 percent
of U.S. CH4 emissions, and more than 70 percent of the CH4
emissions from agriculture. From 1990 to 2001, 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.
Manure Management (38.9 Tg C02 Eq.)
The decomposition of organic animal waste in an
anaerobic environment produces CH4. 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
Executive Summary ES-19
-------
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 2001 and 24 percent of the
CH4 emissions from agriculture. From 1990 to 2001, emissions
from this source increased by 24 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.
Rice Cultivation (7.6 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 CH4 to the atmosphere, primarily
through the rice plants. In 2001, rice cultivation was the
source of 1 percent of U.S. CH4 emissions, and about 5
percent of U.S. CH4 emissions from agriculture. Emission
estimates from this source have increased about 7 percent
since 1990 due to an increase in the area harvested.
Field Burning of Agricultural Residues (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 re-
sponsible for only 0.1 percent of U.S. CH4 emissions in 2001.
Wastewater Treatment (28.3 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.
Nitrous Oxide Emissions
Nitrous oxide (N2O) is produced naturally from
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 lower than CO2 emissions, N2O is approximately
300 times more powerful than CO2 at trapping heat in the
atmosphere. Since 1750, the atmospheric concentration of
N2O has risen by approximately 16 percent (IPCC 2001). The
main anthropogenic activities producing N2O in the United
States are agricultural soil management, fuel combustion in
motor vehicles, manure management, nitric acid production,
human sewage, and stationary fuel combustion (see Figure
ES-15andTableES-ll).
Figure ES-15
2001 Sources of N,0
294.3
Agricultural Soil Management
Mobile Sources
Manure Management
Nitric Acid
Human Sewage
Stationary Sources
Adipic Acid
N2O Product Usage
Agricultural Residue Burning
Waste Combustion
N2O as a Portion
of all Emissions
6.1%
0.4
0.2
10 20 30 40 50 60 70
Tg CO, Eq
ES-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table ES-11: U.S. Sources of Nitrous Oxide Emissions (Tg C02 Eq.)
Source
1990
1995
1996
1997 1998
1999
2000 2001
Agricultural Soil Management 267.5
Mobile Sources 50.6
Manure Management 16.2
Nitric Acid 17.8
Human Sewage 12.7
Stationary Combustion 12.5
Adipic Acid 15.2
N20 Product Usage 4.3
Field Burning of Agricultural Residues 0.4
Waste Combustion 0.3
International Bunker Fuels* 1.0
Total*
397.6
284.1
60.9
16.6
19.9
13.9
13.2
17.2
4.5
0.4
0.3
0.9
430.9
293.2
60.7
17.0
20.7
14.1
13.8
17.0
4.5
0.4
0.3
0.9
441.7
298.2
60.3
17.3
21.2
14.4
13.7
10.3
4.8
0.4
0.3
1.0
440.9
299.2
59.7
17.3
20.9
14.6
13.7
6.0
4.8
0.5
0.2
1.0
436.8
297.0
58.8
17.4
20.1
15.1
13.7
5.5
4.8
0.4
0.2
0.9
433.0
294.6
57.5
17.9
19.1
15.1
14.3
6.0
4.8
0.5
0.2
0.9
429.9
294.3
54.8
18.0
17.6
15.3
14.2
4.9
4.8
0.5
0.2
0.9
424.6
* Emissions from International Bunker Fuels are not included in totals.
Note: Totals may not sum due to independent rounding.
Agricultural Soil Management (294.3 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 processes.
These activities may add nitrogen to soils either directly or
indirectly. Direct additions occur through the application of
synthetic and organic fertilizers; production of nitrogen-fixing
crops and forages; 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 or deposited on soils as
fertilizer, livestock manure, and sewage sludge.
In 2001, agricultural soil management accounted for 69
percent of U.S. N2O emissions. From 1990 to 2001, emissions
from this source increased by 10 percent as fertilizer
consumption, manure production, and production of
nitrogen-fixing and other crops rose.
Stationary and Mobile Combustion (68.9 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 emitN2O, 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, some types of
catalytic converters installed to reduce motor vehicle
pollution can promote the formation of N2O.
In 2001, N2O emissions from mobile combustion were
13 percent of U.S. N2O emissions, while stationary
combustion accounted for 3 percent. From 1990 to 2001,
combined N2O emissions from stationary and mobile
combustion increased by 9 percent, primarily due to
increased rates of N2O generation in highway vehicles.
Adipic Acid Production (4.9 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 2001, U.S. adipic acid plants emitted 1 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 68 percent since 1990.
Nitric Acid Production (17.6 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 2001, N2O
emissions from nitric acid production accounted for 4 percent
of U.S. N2O emissions. From 1990 to 2001, emissions from
this source category decreased by 1 percent with the trend in
the time series closely tracking the changes in production.
Executive Summary ES-21
-------
N20 from Product Usage (4.8 Tg C02 Eq.)
Nitrous oxide is used in carrier gases with oxygen to
administer more potent inhalation anesthetics for general
anesthesia and as an anesthetic in various dental and
veterinary applications. As such, it is used to treat short-
term pain, for sedation in minor elective surgeries and as an
induction anesthetic. The second main use of N2O is as a
propellant in pressure and aerosol products, the largest
application being pressure-packaged whipped cream.
Manure Management (18.0 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 2001 accounted for 4 percent
of U.S. N2O emissions. From 1990 to 2001, emissions from
this source category increased by 11 percent, as poultry
and swine populations have increased.
Field Burning of Agricultural Residues (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.
Because field burning is not a common method of agricultural
residue disposal in the United States, emissions from this
source are minor.
Human Sewage (Domestic Wastewater) (15.3 Tg C02 Eq.)
Domestic human sewage is usually mixed with other
household wastewater, 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 or centralized wastewater treatment 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 may be generated during both nitrification and
denitrification of the nitrogen present, usually in the form of
urea, ammonia, and proteins. Emissions of N2O from treated
human sewage discharged into aquatic environments were
estimated to be 15.3 Tg CO2 Eq. in 2001.
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), with some
components, such as plastics, synthetic rubber, and
synthetic fibers, of fossil origin, which together accounted
for emissions of 0.2 Tg CO2 Eq. in 2001.
HFC, PFC, and SF6 Emissions
Hydrofluorocarbons (MFCs) and perfluorocarbons
(PFCs) are families 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. HFCs
and PFCs do not deplete the stratospheric ozone layer, and
are therefore acceptable alternatives under the Montreal
Protocol.
These compounds, however, along with sulfur hexa-
fluoride (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 111.0 Tg CO2 Eq. in 2001.
Substitution of Ozone Depleting Substances
(63.7TgC02Eq.)
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 57
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.
ES-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table ES-12: Emissions of HFCs, PFCs, and SF6 (Tg C02 Eq.)
Source
1990
Substitution of Ozone Depleting Substances
HCFC-22 Production
Electrical Transmission and Distribution
Semiconductor Manufacture
Aluminum Production
Magnesium Production and Processing
Total
Note: Totals may not sum due to independent rounding.
1995
1996
1997 1998
1999
2000 2001
21.7
27.0
27.5
5.9
11.8
5.6
99.5
30.4
31.1
27.7
5.4
12.5
6.5
113.6
37.7
30.0
25.2
6.5
11.0
6.3
116.8
44.5
40.2
20.9
7.3
9.0
5.8
127.6
50.9
30.4
16.4
7.7
8.9
6.0
120.3
57.3
29.8
15.4
7.4
7.9
3.2
121.0
63.7
19.8
15.3
5.5
4.1
2.5
111.0
In the short term, this trend is expected to continue, and
will likely accelerate in the next decade as
hydrochlorofluoro-carbons (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 (4.1 Tg C02 Eq.)
During the production of primary aluminum CF4 and
C2F6 are emitted as intermittent by-products of the
smelting process. These PFCs are formed when fluorine
from the cryolite bath combines with carbon from the
electrolyte anode. Emissions from aluminum production
have decreased by 77 percent between 1990 and 2001 due
to emission reduction efforts by the industry and falling
domestic aluminum production.
HCFC-22 Production (19.8Tg C02 Eq.)
HFC-23 is a by-product of the production of HCFC-22.
Emissions from this source have decreased by 43 percent
since 1990. The HFC-23 emission rate (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 (5.5 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 2001. This later reduction is due to the implementation
of PFC emission reduction methods, such as process
optimization.
Electrical Transmission and Distribution Systems
(15.3TgC02Eq.)
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 52 percent since
1990, primarily due to higher SF6 prices and industrial efforts
to reduce emissions.
Figure ES-16
2001 Sources of HFCs, PFCs, and SF6
Substitution of Ozone
Depleting Substances
HCFC-22 Production
Electrical Transmission
and Distribution
Semiconductor Manufacture
Aluminum Production
I
I
HFCs, PFCs, and SF6
as a Portion
of all Emissions
1.6%
.4.
Magnesium Production I
and Processing |
0 10 20 30 40 50 60 70
TgCO,Eq
Executive Summary ES-23
-------
Magnesium Production (2.5 Tg C02 Eq.)
Sulfur hexafluoride is also used as a protective cover
gas for the casting of molten magnesium. Emissions from
primary magnesium production and magnesium casting have
decreased by 53 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.
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 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). They are also potent greenhouse gases.
Recognizing the harmful effects of these compounds on the ozone layer, in 1987 many countries ratified 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 UNFCCC reporting guidelines do not include reporting instructions for estimating emissions of ODSs because they are tracked under
the Montreal Protocol. Nevertheless, estimates for several Class I and Class II ODSs are provided in Table ES-13 for informational purposes.
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
HCFC 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.
It 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
1990
Class I
CFC-11
CFC-12
CFC-113
CFC-114
CFC-115
Carbon Tetrachloride
Methyl Chloroform
Halon-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 0.05 Gg
1995 1996
1997
1998 1999
2000
2001
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
+
26.6
35.5
+
+
3.2
+
+
1.1
1.4
41.0
0.7
5.9
9.9
4.0
+
25.1
23.1
+
+
2.9
+
+
1.1
1.3
42.4
0.8
6.2
8.8
4.3
+
24.9
21.0
+
+
2.7
+
+
1.1
1.3
43.8
0.9
6.4
9.7
4.7
+
24.0
14.0
+
+
2.6
+
+
1.1
1.3
74.1
1.0
6.5
10.9
5.0
+
22.8
17.2
+
+
2.3
+
+
1.1
1.3
79.1
1.1
6.5
10.9
5.4
+
22.8
21.3
+
+
1.5
+
+
1.1
1.2
80.5
1.2
6.5
10.7
5.8
4-
ES-24 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
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 warming 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 include 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.
Table ES-14: Emissions of NOX, CO, NMVOCs, and S02 (Gg)
Gas/Activity
1990
1995
1996
1997 1998
1999
2000 2001
NO,
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Waste Combustion
Industrial Processes
Solvent Use
Field Burning of Agricultural Residues
Waste
CO
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Waste Combustion
Industrial Processes
Solvent Use
Field Burning of Agricultural Residues
Waste
NMVOCs
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Waste Combustion
Industrial Processes
Solvent Use
Field Burning of Agricultural Residues
Waste
S02
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Waste Combustion
Industrial Processes
Solvent Use
Field Burning of Agricultural Residues
Waste
23,037
9,884
12,134
139
82
769
1
28
0
130,575
4,999
119,482
302
978
4,124
4
685
1
20,937
912
10,933
555
222
2,426
5,217
NA
673
20,936
18,407
793
390
39
1,306
0
NA
0
f 22,509
f 9,822
# 11,784
ii 100
88
; 682
3
.: 29
; 1
•109,149
" 5,383
;., 97,755
316
1,073
' 3,958
5
656
2
19,520
;: 973
: 8,744
:: 582
237
: 2,643
5,609
NA
f 731
16,892
14,724
673
334
42
1,117
1
NA
1
22,360
9,540
11,714
126
135
808
3
32
3
104,063
3,935
93,409
321
2,628
3,016
1
747
5
17,184
1,018
8,306
433
304
1,997
4,969
NA
158
16,682
14,746
649
304
29
953
1
NA
1
22,289
9,578
11,768
130
140
634
3
34
3
101,132
3,927
90,284
333
2,668
3,153
1
761
5
16,994
1,016
7,928
442
313
2,038
5,100
NA
157
17,091
15,104
659
312
29
985
1
NA
1
21,961
9,419
11,592
130
145
635
3
35
3
98,976
3,927
87,940
332
2,826
3,163
1
781
5
16,403
1,016
7,742
440
326
2,047
4,671
NA
161
17,189
15,191
665
310
30
991
1
NA
1
21,341
8,716
11,582
113
142
748
3
34
3
95,464
4,941
84,574
152
2,833
2,145
46
760
14
16,245
1,312
7,658
376
326
1,890
4,533
NA
151
16,013
14,073
701
275
29
933
1
NA
1
20,917
8,226
11,395
115
149
992
3
35
3
93,965
4,163
83,680
152
2,914
2,214
45
784
14
15,418
1,088
7,230
348
332
1,845
4,422
NA
153
14,802
12,883
632
279
29
977
1
NA
1
20,141
7,826
11,254
117
149
755
3
35
3
100,653
4,169
90,268
153
2,916
2,327
44
762
14
15,148
1,087
6,800
357
333
1,829
4,584
NA
158
14,324
12,367
636
281
30
1,008
1
NA
1
Source: (EPA 2003) except for estimates from field burning of agricultural residues.
+ Does not exceed 0.5 Gg
NA (Not Available)
Note: Totals may not sum due to independent rounding.
Executive Summary ES-25
-------
Box ES-4: Sources and Effects of Sulfur Dioxide
Sulfur dioxide (S02) emitted into the atmosphere through natural and anthropogenic processes affects the Earth's radiative budget
through 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 (IPCC 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 69 percent in 2001. Coal
combustion contributes nearly all of those emissions (approximately 92 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 desulf urization equipment.
Ambient air pollutants are regulated under the Clean
Air Act in an effort to protect human health and the
environment. These gases also indirectly 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 COr Therefore, increased atmos-
pheric 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 2003).'3 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.
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, 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 highly
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
UNFCCC reporting guidelines follow the recommendation of
the Revised 1996 IPCC Guidelines for National Greeenhouse
Gas Inventories (IPCC/UNEP/OECD/IEA 1997) and require
that countries provide single point estimates for each gas
and emission or removal source category.
Currently, a qualitative discussion of uncertainty is presented
for all source and sink categories. Within the discussion of each
emission source, specific factors affecting the accuracy of the
estimates are discussed. A limited number of sources also contain
a quantitative uncertainty assessment. Beginning with the
Inventory submission in 2004, the United States will provide
quantitative estimates for all source and sink categories, in
accordance with the new UNFCCC reporting guidelines.
13 NOX and CO emission estimates from field burning of agricultural residues were estimated separately, and therefore not taken from EPA (2003).
ES-26 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Changes in This Year's
Inventory Report
Each year the U.S. Greenhouse Gas Inventory Program recalculates and revises the emission and sink estimates
for all years in the Inventory of U.S. Greenhouse Gas Emissions and Sinks, and attempts to improve both the
analyses themselves, through the use of better methods or data, and the overall usefulness of the report. A summary of this
year's revisions is presented in this chapter, including both changes in methodology and updates to historical data. The
magnitude of each change's impact on emissions 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., 1990-2000 report). These tables present the magnitude of
these changes in units of teragrams of carbon dioxide (CO2) equivalents (Tg CO2 Eq.).
For methodological changes, differences between the previous report and this report are explained. In general, when
methodological changes have been implemented, the entire time series (i.e., 1990 through 2000) has been recalculated to
reflect the change.
Changes in historical data are generally the result of changes in statistical data supplied by other agencies. References
for the data are provided for additional information.
Methodological Changes
C02 Emissions from Fossil Fuel Combustion
Storage factors for fossil fuels produced but not combusted (e.g., feedstocks) have been updated. The carbon storage
factor for miscellaneous products under other petroleum for U.S. territories was reduced to 10 percent. This revision is
based on the assumption that the carbon consumption for miscellaneous products is not used primarily for asphalt and
road oil, which had been previously assumed, but for other uses which store much less carbon. The combination of this
change, the historical changes described below, and the methodological changes in "Emissions and Storage from Non-
Energy Uses of Fossil Fuels" (which affect the emissions from this source), resulted in an average annual increase of 52.0
Tg CO2 Eq. (1.0 percent) in CO2 emissions for the period 1990 through 2000.
Changes-1
-------
Table Changes-1: Revisions to U.S. Greenhouse Gas Emissions (Tg C02 Eq.)
Gas/Source
1990
1995
1996 1997
1998 1999 2000
C°* 5'2
Fossil Fuel Combustion 34.9
Natural Gas Flaring NC
Cement Manufacture NC
Lime Manufacture NC
Limestone and Dolomite Use 0.3
Soda Ash Manufacture and Consumption +
Carbon Dioxide Consumption 0.1
Waste Combustion +
Titanium Dioxide Production NC
m
1 28.6 31.1 27.4
I 56.5 59.2 60.5
f. NC NC NC
t: NC NC NC
k NC NC NC
\ + 0.2 (1.3)
ff + + +
f 0.1 + (0.1)
$ (0.1) (0.2) (0.2)
r NC NC NC
Aluminum Production NC NC NC NC
Iron and Steel Production NC ff:pJ? NC NC (4.3)
Ferroalloys NC ZJjgi*
Ammonia Manufacture & Urea Application 0.8
International Bunker Fuels +
CH< (7'3)
Stationary Sources 0.2
Mobile Sources 0.1
NC NC NC
'~ 1.5 0.8 1.2
"4,1 T T
| (7.6) (6.9) (3.8)
§ 0.3 0.3 +
* 0.1 0.1 0.1
Coal Mining + NC NC NC
Natural Gas Systems 0.8
Petroleum Systems 1.1
Petrochemical Production NC
^ 1.6 0.8 3.3
r + (o.i) (0.4)
~- + + NC
Silicon Carbide Production NC NC NC NC
Enteric Fermentation (10.0) (10.2) (9.1) (8.4)
Manure Management 2.1 li*>1- j
Rice Cultivation NC
Field Burning of Agricultural Residues NC *i| "3
Landfills (1.3)
1.4 0.7 0.7
- NC NC NC
NC NC NC
f (0.5) 0.6 1.1
Wastewater Treatment (0.2) (0.2) (0.2) (0.2)
International Bunker Fuels +
~~ + + +
N20 10.3 ^tnf^ 11.2 11.3 11.1
WJer** **
Stationary Sources (0.3)
Mobile Sources (0.3) t-'*C
Adipic Acid 0.3 l/« v>
Nitric Acid +
^ (0.3) (0.3) (0.5)
^ 0.5 0.6 0.7
{ (0.7) (0.7) (1.2)
^ + ~T +
Manure Management 0.1 0.2 0.2 0.2
Agricultural Soil Management 0.5 fftv;
Field Burning of Agricultural Residues NC
Human Sewage 5.7
N20 Product Usage3 4.3
Waste Combustion NC
International Bunker Fuels +
HFCs, PFCs, and SF6 0.7
Substitution of Ozone Depleting Substances NC
Aluminum Production NC
HCFC-22 Production NC
Semiconductor Manufacture NC
Electrical Transmission and Distribution 0.9
Magnesium Production and Processing (0.1)
Net Change in Total Emissions11 8.9
Percent Change 0.1%
+ Absolute value does not exceed 0.05 Tg C02 Eq.
a New source category relative to previous inventory.
b Excludes emissions from land-use change and forestry.
NC: (No Change)
Note: Totals may not sum due to independent rounding.
0.6 0.6 0.7
NC NC NC
\ 6.3 6.3 6.5
£. 4.5 4.5 4.8
f NC NC NC
- + + +
1 1.0 1.8 (0.1)
fe (0.1) (0.2) (0.3)
£ NC NC NC
1 NC NC NC
1 NC NC NC
1 1.0 0.9 0.7
I °-1 1-1 (°-6)
1 33.1 37.2 34.5
1 0.5% 0.6% 0.5%
39.1
64.4
NC
NC
NC
(0.9)
+
(0.2)
2.2
NC
NC
NC
NC
1.8
(0.1)
(4.4)
0.2
0.1
NC
1.8
(0.5)
NC
NC
(8.2)
1.0
NC
NC
1.4
(0.2)
_j_
10.5
(0.6)
0.5
(1.7)
+
0.2
0.8
NC
6.5
4.8
NC
+
+
(0.3)
NC
NC
NC
0.7
(0.4)
45.2
0.7%
15.2
40.2
NC
NC
NC
(1.4)
+
(0.4)
2.1
NC
NC
NC
NC
1.7
(0.1)
(5.0)
+
0.1
NC
1.7
(0.7)
_i_
+
(7.9)
1.3
NC
NC
0.6
(0.2)
+
9.4
(0.9)
0.1
(2.2)
+
0.2
0.7
NC
6.7
4.8
NC
+
0.4
(0.4)
NC
NC
NC
0.9
(0.1)
20.1
0.3%
43.1
68.9
(0.5)
0.1
+
(3.4)
+
(0.1)
2.9
+
NC
+
NC
1.6
(1.0)
(1.2)
0.1
0.1
+
4.8
(0.6)
+
NC
(8-2)
0.8
+
+
2.3
(0.4)
_i_
4.6
(0.7)
(0.8)
(2.1)
(0.7)
0.4
(3.0)
+
6.7
4.8
+
+
(0.4)
(0.5)
+
NC
NC
1.0
(0.8)
46.1
0.7%
Changes-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table Changes-2: Revisions to Net C02 Sequestration from Land-Use Change and Forestry (Tg C02 Eq.)
Component 1990 1995 1996 1997 1998 1999 2000
Forests
Urban Trees
Agricultural Soils
Landfilled Yard Trimmings
Net Change in Total Flux
Percent Change
NC
NC
24.0
0.9
24.9
(2.3%)
NC
NC
45.3
0.6
45.8
(4.1%)
NC
NC
46.6
0.5
47.1
(4.2%)
NC
NC
46.5
0.4
46.9
(5.3%)
NC
NC
55.7
(0.3)
55.4
(6.3%)
NC
NC
55.8
(0.5)
55.3
(6.2%)
14.7
NC
53.7
(0.5)
67.9
(7.5%)
NC: (No Change)
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.
Carbon Stored in Products from Non-
Energy Uses of Fossil Fuels
The methods for estimating CO2 emissions of non-
energy uses (NEU) of fossil fuels were revised in several
ways this year. A full time series (1990-2001) of net imports/
exports of feedstock-related petrochemicals was
incorporated into the NEU analysis. The storage versus
emissions balance of NEU carbon was also updated to
include the carbon emitted from consumption of personal
cleansers (e.g., soaps, shampoo, and detergents) and the
carbon flows in refinery wastewaters. These changes, in
combination with historical data changes in "CO2 Emissions
from Fossil Fuel Combustion" and other modifications to
the NEU section, resulted in an average annual decrease in
stored carbon of 12.9 Tg CO2 Eq. (5.0 percent) for the period
1990 through 2000.
Stationary Combustion (excluding C02)
The activity data for estimating non-CO2 emissions from
stationary combustion previously included the consumption
of some fuels used for non-energy purposes. For the current
inventory, consumption for these purposes is now being
removed from the activity data. The combination of this
change and the historical data changes described below
resulted in an average annual increase of 0.2 Tg CO2 Eq. (2.8
percent) of CH4 emissions and an average annual decrease
of 0.4 Tg CO2 Eq. (3.0 percent) in N2O emissions for the
period 1990 through 2000.
Mobile Combustion (excluding C02)
The methodology for estimating non-CO2 emissions
from mobile combustion was altered significantly. The
changes consisted of revisions to the distribution of control
technologies for gasoline and diesel highway vehicles, the
estimation of emission factors for gasoline and diesel
highway vehicles, the estimation of vehicle miles traveled
for alternative fuel vehicles, and the development of emission
factors for alternative fuel vehicles.
Control technology assignments for light and heavy-
duty conventional fuel vehicles for model years 1972 (when
regulations began to take effect) through 1995 were estimated
in EPA (1998). Assignments for 1998 through 2001 were
determined using confidential engine family sales data
submitted to the EPA (EPA 2002b). Vehicle classes and
emission standard tiers to which each engine family was
certified were taken from annual certification test results
and data (EPA 2002a). This was used to determine the
fraction of sales of each class of vehicle that met Tier 0, Tier
1, and LEV standards. Assignments for 1996 and 1997 were
estimated based upon the fact that Tier 1 standards for light-
duty vehicles were fully phased in by 1996. The previous
methodology, which estimated control technology and
emissions for California separately from the other 49 states,
is no longer used.
Previous emission factors for heavy-duty gasoline
vehicles only included Tier 0, oxidation catalyst, non-catalyst
control and uncontrolled. In 1996, heavy-duty gasoline
Changes-3
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engines underwent a significant change with most going to
three-way catalysts and multi-point sequential fuel injection
systems, and new emission factors for these vehicles were
developed. Emission factors for methane (CH4) for Tier 1
and LEV heavy-duty gasoline vehicles were estimated using
emission factors from the California Air Resources Board
(CARB 2000). Nitrous oxide emissions were estimated from
the ratio of NOx emissions to N2O emissions for Tier 0 heavy-
duty gasoline trucks. ANOx to N2O ratio of 60 was used.
Vehicle Miles Traveled (VMT) for alternative fuel and
advanced technology vehicles were calculated from the
Energy Information Administration Data Tables (EIA 2002a).
The data obtained include vehicle fuel use and total number
of vehicles in use from 1992 through 2001. Fuel economy
for each vehicle type and calendar year was determined by
estimating the gasoline equivalent fuel economy for each
technology. Energy economy ratios (the ratio of the gasoline
equivalent fuel economy of a given technology to that of
conventional gasoline or diesel vehicles) were taken from
full fuel cycle studies done for the California Air Resources
Board (Unnasch and Browning 2000). These were used to
estimate fuel economy in miles per gasoline gallon equivalent
for each alternative fuel and vehicle type. Energy use per
fuel type was then divided among the various weight
categories and vehicle technologies that would use that
fuel. Total VMT per vehicle type for each calendar year was
then determined by dividing the energy usage by the fuel
economy. Average VMT was then calculated by dividing
total VMT per vehicle type by the number of vehicles.
Average VMT for each vehicle type was checked against
the Federal Highway Administration Highway Statistics
Series for each calendar year (FHWA 1996 through 2001).
Note that for alternative fuel vehicles capable of running on
both/either traditional and alternative fuels, the VMT given
reflects only those miles driven that were powered by the
alternative fuel.
Light-duty alternative fuel vehicle emission factors are
estimated in Argonne National Laboratory's GREET 1.5 —
Transportation Fuel Cycle Model (Wang 1999). In addition,
Lipman and Delucchi estimate emission factors for some
light and heavy-duty alternative fuel vehicles (Lipman and
Delucchi 2002). The approach taken here is to calculate CH4
emissions from actual test data and determine N2O emissions
from NOx emissions from the same tests. Since it is likely
that most alternative fuel vehicles use the same or similar
catalysts to their conventional counterpart, the amount of
N2O emissions will depend upon the amount of oxides of
nitrogen emissions that the engine produces. Based upon
gasoline data for Tier 1 cars, the tailpipe NOx to N2O ratio is
5.75. Lipman and Delucchi (2002) found NOx to N2O ratios
for light-duty alternative fuel vehicles with three-way
catalyst systems to vary from 3 to 5.5 for older technology.
• Methane emission factors for light-duty vehicles were
taken from the Auto/Oil Air Quality Improvement
Research Program dataset (CRC 1997). This dataset
provided CH4 emission factors for all light-duty vehicle
technologies except for propane (LPG). Light-duty
propane emission factors were determined from reports
on propane-vehicle emissions from the California Air
Resources Board (Brasil and McMahon 1999) and the
University of California Riverside (Norbeck et al 1998).
• Heavy-duty emission factors for alternative fuel
vehicles were determined from test data using the West
Virginia University mobile dynamometer (DOE 2002).
Emission factors were determined based on the ratio of
total hydrocarbon emissions to CH4 emissions found
for light-duty vehicles using the same fuel. Nitrous
oxide emissions for heavy-duty engines were calculated
from NOx emission results using a NOx to N2O ratio of
50, which is more typical for heavy-duty engines with
oxidation catalysts.
The combination of these changes and the historical
data revisions described below resulted in an average annual
increase of 0.1 Tg CO2 Eq. (1.8 percent) in CH4 emissions
and 0.1 Tg CO2 Eq. (0.2 percent) in N2O emissions for the
period 1990 through 2000.
Coal Mining
There was a single alteration to the methodology for
estimating the emissions from coal mining. The change
consisted of incorporating EIA's updated coal production
data for the year 2000. The combination of this change and
the historical data revisions described below resulted in an
average annual increase of 0.1 Tg CO2 Eq. (0.1 percent) in
CH4 emissions for the period 1990 through 2000.
Changes-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
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Natural Gas Systems
The methodology used to estimate the emissions from
natural gas systems was modified in two ways. First, data
from four additional states were added to the number of
north central non-associated wells. These states were left
out in previous analyses, because the number of wells in
these states was negligible. Second, the reduction in
emission factors due to technological improvement was
removed. In the past, emission factors were reduced at an
annual rate of 0.2 percent such that by year 2020, emission
factors would have declined by 5 percent from 1995. These
reductions were made to reflect the underlying technological
improvements through both innovation and normal
replacement of equipment. However, the analysis already
incorporates the emission reductions from some of these
technological improvements as reported by EPA's Natural
Gas STAR Partners. This is done by subtracting emission
reductions associated with each stage of the natural gas
system (production, processing, transmission and
distribution) from the corresponding total emissions
estimates for each operating stage. Thus, the emission
factors were held constant throughout the time series for
this year's inventory to eliminate the possibility of double
counting. See Annex G for more detailed information on the
methodology and data used to calculate CH4 emissions from
natural gas systems. The combination of these changes
and the historical data revisions described below resulted
in an average annual increase of 1.3 Tg CO2 Eq. (1.1 percent)
in CH4 emissions for the period 1990 through 2000.
Petroleum Systems
There were three alterations to the methodology for
estimating CH4 emissions from petroleum systems. First,
the emission factor for gas engines in the production sector
was adjusted. In the previous report, the emission factor for
gas engines, 0.08 scf CH/ HP-hr, was based on the 1999
EPA draft report, Estimates of Methane Emissions from the
U.S. Oil Industry (EPA 1999). The 1996 Radian Study,
Methane Emissions from the U.S. Petroleum Industry (Radian
1996) cites an emission factor of 0.24 scf CH4/ HP-hr, which
is a more accurate estimate for the emission factor of gas
engines. Therefore, the 1996 Radian Study is the basis for
the gas engine emission factor used in this year's inventory.
Second, in the previous report, the activity data in the CRF
table for the refining and crude transportation were based
on crude oil production. However, crude production
accounts only for the crude that is produced in the country,
not the crude that is imported. The total crude refined
includes both crude that is produced in the country and
crude that is imported. In this year's report, the activity data
for refining and crude transportation were based on refinery
crude feed data obtained from El A (2001). The amount of
refinery feed accounts for all crude produced and imported
that is refined. The activity data for crude oil transport were
unavailable. In this case, it was assumed that all the crude
that is transported goes to refineries. Therefore, the activity
data for refining sector was used also for the transportation
sector. Changing the bases from the crude production to
refinery feed more accurately estimates the activity data of
refining and crude transportation. Third, the estimated
emissions in last year's report did not account for any
emissions reductions reported by members of EPA's Natural
Gas STAR Program. In this year's report, these emission
reductions are taken into account by subtracting from tank
venting the amount of emission reductions that were reported
by the Natural Gas STAR Program partners from installing
vapor recovery units for the period 1990 through 2001 (EPA
1995- 2000). Incorporating the reported emission reductions
into the estimated CH4 emissions gives a more accurate
inventory estimate. See Annex H for additional detail. These
changes resulted in an average annual increase of 0.1 Tg
CO2 Eq. (0.2 percent) in CH4 emissions for the period 1990
through 2000.
Municipal Solid Waste Combustion
The incorporation of new 2000 data in the municipal
solid waste combustion section led to a change in
methodology for estimating the activity data for the years
1999 and 2001. Values for 1999 were interpolated between
1998 and 2000 reported data; 2001 values were extrapolated
from the 2000 data. The combination of this change and the
historical data changes described below resulted in an
average annual increase of 0.6 Tg CO2Eq. (2.6 percent) in
CO2 emissions for the period 1990 through 2000.
Ammonia Manufacture and Urea
Application
The methodology for estimating CO2 emissions from
ammonia production was adjusted to account for the use of
some of the CO2 produced from ammonia production as a
Changes-5
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raw material in the production of urea. For each ton of urea
produced, 8.8 of every 12 tons of CO2 are consumed and 6.8
of every 12 tons of ammonia is consumed. The CO2 emissions
reported for ammonia production are therefore reduced by a
factor of 0.73 multiplied by total annual domestic urea
production, and that amount of CO2 emissions is allocated
to urea fertilizer application. Both ammonia production and
urea application are included in the same section of the
Industrial Processes chapter; therefore total CO2 emissions
resulting from nitrogenous fertilizer production does not
change.
In addition to the allocation of some emissions to urea
application within this section, urea application data were
adjusted to account for imports and exports of urea. Since
imports of urea were greater than exports of urea during the
years 1990 through 2000, this resulted in a net increase of
emissions. The combination of this change and the historical
data change discussed below resulted in an average annual
increase of 1.2 Tg CO2 Eq. (6.5 percent) in CO2 emissions for
the period 1990 through 2000.
Nitrous Oxide (N20) Product Usage
The N2O Product Usage source has been added to this
year's report to account for emissions produced by the use
of nitrous oxide and products containing it. Nitrous oxide is
primarily used in carrier gases with oxygen to administer
more potent inhalation anesthetics for general anesthesia
and as an anesthetic in various dental and veterinary
applications. The second principal use of N2O is as a
propellant in pressure and aerosol products, the largest
application being pressure-packaged whipped cream.
Emissions from this source category added an annual
average of 4.5 Tg CO2 Eq. in N2O emissions over the period
1990 through 2000.
Electrical Transmission and Distribution
The primary change in the methodology for calculating
emissions from electrical transmission and distribution was
an increase in the assumed emission rate from equipment
manufacturers. Previously, the emission rate of U.S. electrical
equipment manufacturers was assumed to be 3 percent of
the SF6 charged into new equipment. In light of the final
CIGRE paper, this estimate has been increased to 10 percent.
This revision resulted in an average annual increase of 0.9
Tg CO2 Eq. (3.7 percent) in SF6 emissions for the period 1990
through 2000.
Magnesium Production and Processing
There was a single change to the methodology for
estimating the emissions from magnesium production. The
emission factor for die casting in 2000 was adjusted
downward to reflect the fact that participants in EPA's SF6
Emission Reduction Partnership for the Magnesium Industry,
which have relatively low emission rates, accounted for a
greater percentage of die casting (nearly 100 percent) than
previously believed (60 percent). The combination of this
change and the historical data revisions described below
resulted in an average annual decrease of less than 0.1 Tg
CO2 Eq. (1.9 percent) in SF6 emissions for the period 1990
through 2000.
Enteric Fermentation
The methodology for estimating CH4 emissions from
enteric fermentation now incorporates new diet information
for grazing beef cattle and cattle in feedlots. The changes in
diet information were based on comments received during
the expert review period of the Inventory of U.S. Greenhouse
Gas Emissions and Sinks: 1990-2000. To revise the values
for digestible energy (DE) and fraction of energy converted
to CH4 (Ym) for grazing beef cattle (beef cows, beef
replacements, heifer stackers, and steer stackers), the diet
descriptions developed for the enteric fermentation model
were combined with new diet characteristic information found
in the Nutrient Requirements of Beef Cattle (NRC 2000). New
DE values were estimated for both forage-only and
supplemented diets. For forage diets, two separate DE values
were used to account for the lower feed quality in the western
United States. Where DE values were not available, total
digestible nutrients as a percent of dry matter intake was
used as a proxy for DE and is considered essentially the
1 For example, in California the forage DE of 64.7 percent was used for 95 percent of the grazing cattle diet and a supplemental diet DE of
65.2 percent was used for five percent of the grazing cattle diet, for a total weighted DE of 64.9 percent.
Changes-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
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same as the DE value. Weighted averages were developed
for DE values for each region using both the supplemental
diet and the forage diet.1 For beef cows, the DE value was
adjusted downward by two percent (assumed value) to
reflect the reduced diet of the mature beef cow. For feedlot
animals, diet characteristics were revised because of abrupt
changes in emissions due to changes in DE and Ym, as a
result of the DE and Ym originally being used for sets of
years 1990 through 1992,1993 through 1995, and 1996
through 2000. It was also determined that the values used
previously for 1990 through 1992 were too low for the DE
and too high for the Ym. To correct both of these issues, the
values previously used for 1993 through 1995 were used for
1990, and this value was extrapolated linearly between the
1990 and the 1996 values. Values remain constant from 1996
onwards. See Annex L for more detailed information on the
development of the diet information from cattle. The
combination of these changes and the historical data
revisions described below resulted in an average annual
decrease of 9.3 Tg CO2 Eq. (7.3 percent) in CH4 emissions for
the period 1990 through 2000.
Manure Management
The primary change in the methodology for estimating
CH4 and N2O emissions from manure management was a
change in the source for volatile solids excretion rates for
cattle. This source was updated to be consistent with the
results of the Enteric Fermentation Energy model.
In previous years, the method for calculating volatile
solids production from dairy cows reflected 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 1996) 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 was used to estimate the volatile
solids excretion rate for dairy cows given the estimated
annual milk production data, published by USDA's National
Agricultural Statistics Service (USDA 2000). 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.
The volatile solids excretion rate for other animals were
developed from published sources reviewed for U.S.-specific
livestock waste characterization data. Data from the National
Engineering Handbook, Agricultural Waste Management Field
Handbook (USDA 1996) 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.
This year, the method for calculating volatile solids
production from beef and dairy cows, heifers, and steer is
based on the relationship between animal diet and energy
utilization, which is modeled in the enteric fermentation
portion of the inventory. Volatile solids content of manure
is equal to the fraction of the diet consumed by cattle that is
not digested and thus is excreted as fecal material. The
combination of this fecal material and urinary excretions
constitutes manure. The enteric fermentation model requires
the estimation of gross energy intake and its fractional
digestibility, digestible energy, in the process of estimating
enteric CH4 emissions (see Annex M for details on the enteric
energy model). These two inputs were used to calculate the
indigestible energy per animal unit as gross energy minus
digestive energy plus an additional 2 percent of gross energy
for urinary energy excretion per animal unit. This was then
converted to volatile solids production per animal unit using
the typical conversion of dietary gross energy to dry organic
matter of 20.1 MJ/kg (Garrett and Johnson 1983). The
combination of this change and the historical data changes
described below resulted in an average annual increase of
1.3 Tg CO2 Eq. (4.0 percent) in CH4 emissions and an average
annual increase of 0.2 Tg CO2 Eq. (1.2 percent) in N2O
emissions for the period 1990 through 2000.
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
methodologies used in the first, third, and fourth sections
have changed relative to the previous Inventory. The
changes to each section are described below.
• Forests. In this year's Inventory, revised estimates are
reported for the amounts of harvested wood products
and landfilled wood for 2000 to correct small errors in
the results reported last year.
Changes-7
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Agricultural Soils. The current inventory is based on
a modified version of the carbon accounting method
developed by the Intergovernmental Panel on Climate
Change (IPCC/UNEP/OECD/IEA 1997). The default
IPCC method is a deterministic approach that provides
general global parameters for estimating the impact of
land use and management on soil organic carbon
storage, and does not directly assess uncertainty in
the resulting estimates. Previous years' inventories
used the default method. For the current inventory, the
method was modified in four ways to improve the
method for application to U.S. soils and to assess
uncertainty. First, probability density functions were
developed for each management factor, instead of using
the single values provided in the IPCC documentation
(IPCC/UNEP/OECD/IEA 1997). Second, probability
density functions were constructed for the activity data
that were used in the previous inventory. Third, the
mineral soil equation was modified so that the reference
carbon stocks were based on soils under agricultural
management instead of native vegetation. This was
necessary due to the availability of data to construct
probability density functions for the reference carbon
stocks. Fourth, a Monte Carlo Analysis was used to
select values from the probability density functions for
repeated calculations of carbon stock change,
generating a 95 percent confidence interval for the
inventory. Overall, these changes should better reflect
the impact of land use and management on soil organic
carbon storage in U.S. agricultural lands. Four additional
changes were made in the methods from the previous
inventory to improve the estimates. First, the effect of
wetland restoration in the Northern Great Plains was
included, and represented an additional increase in
carbon storage for wetlands enrolled in the
Conservation Reserve Program and restored through
the Partners for Wildlife Program (U.S. Fish and Wildlife
Service). Second, changes in carbon stocks were not
estimated for lands converted from agricultural uses to
urban, miscellaneous non-cropland, and open water. In
the previous inventory, carbon stocks were computed
for these non-agricultural land uses using the factor
values that were intended to represent changes from
cultivated cropland to grasslands or forests.
Consequently, applying these factor values to represent
changes to non-agricultural land uses is highly
questionable (e.g., converting a corn field into a
subdivision or lake), and so those calculations were
not included in the current inventory. Third, the
previous inventory only accounted for manure applied
to a portion of U.S. grazing lands based upon
assumptions by Follett et al. (2001). The current
inventory accounts for all of the manure and sewage
sludge nitrogen that is available for application to
agricultural land, based on information derived for the
Agriculture Soil Management section of the Agriculture
chapter of this volume. A national average rate of
application was assumed, as was a national average
rate of soil organic carbon change for croplands and
grazing lands. This is a more complete and accurate
assessment of manure and sewage sludge impacts on
soil organic carbon storage than the previous inventory.
Lastly, carbon stock changes for 1993 through 1997 in
the previous inventory were based on land use and
management differences between 1982 and 1997. To
better reflect trends in carbon stock changes over the
1993 through 1997 time period, the current inventory is
based on the activity data coinciding with those years
(i.e., 1992 and 1997). However, the 1992 to 1997 carbon
stock calculations for some areas were based on the
1982 land uses if a change had occurred between 1982
and 1992, but remained unchanged between 1992 and
1997. This modification allowed for continued accrual
or loss of carbon that continues for 20 years following
a land use and management change according to the
IPCC carbon accounting approach (IPCC/UNEP/OECD/
IEA1997).
• Landfilled Yard Trimmings. The Carbon Storage
Factors (CSFs), which are used to estimate the amount
of yard trimmings carbon stored in landfills, were
adjusted to correct for a mass balance problem in the
experimental results that are the basis of these data
(Barlaz 1998). These adjustments, which are based on
the CH4 yields for each yard trimmings component from
Eleazer et al. (1997), resulted in a 5 percent decrease in
the weighted average CSF for yard trimmings.
The combination of these changes and the historical
data changes described below resulted in an average annual
decrease in carbon sequestration from land-use change and
Changes-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
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forestry of 24.7 Tg CO2 Eq. (2.3 percent) for the period 1990
through 1992 and 51.6 Tg CO2 Eq. (5.3 percent) for the period
1993 through 2000.
Landfills
The methodological change for estimating CH4
emissions from landfills was incorporating municipal solid
waste generation data from U.S. territories. The combination ,
of this change and the historical data changes described
below resulted in an average annual decrease of less than
0.05 Tg CO2 Eq. (less than 0.05 percent) in CH4 emissions for
the period 1990 through 2000.
Human Sewage (Domestic Wastewater)
Several changes were made to the methodology for
estimating N2O emissions from human sewage. Previously,
the estimate included only N2O emissions from wastewater
treatment plant effluent. This year, the methodology was
expanded to include direct emissions from wastewater
treatment plants. In addition, the emissions now also reflect
nitrogen from the use of garbage disposals, and from bath
and laundry water, which represents an increase of
approximately 75 percent. Another change was to subtract
out the nitrogen in sewage sludge that leaves the treatment %
plant to be disposed on agricultural land, landfilled, or
incinerated. In earlier estimates, this reduction was only
accounted for partially. These changes resulted in an
average annual increase of 6.3 Tg CO2 Eq. (80.9 percent) in
N2O emissions for the period 1990 through 2000.
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 2002b) for all years. The major
changes include: (1) reorganization of the electric power
generation sector; (2) revisions to electric power fuel
use statistics based on EIA's use of non-utility power
plant data in place of fuel supplier data; and (3) revisions
to historical data per extensive review and resolution of
anomalies by EIA. These revisions specifically impacted
natural gas and renewable energy estimates. The
combination of these changes, the methodological
change described above, and the methodological
changes in "Emissions and Storage from Non-Energy
Uses of Fossil Fuels" (which affect the emissions from
this source) resulted in an average annual increase of
52.0 Tg CO2 Eq. (1.0 percent) in CO2 emissions for 1990
through 2000.
In the Stationary Combustion (excluding CO2) section of
the Energy chapter, changes to emission estimates were
entirely due to revised data from EIA (2002b). 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. One specific revision affecting stationary
combustion is the inclusion of wood energy consumption
by electric utilities and non-utilities in the electric power
sector. EIA previously allocated this consumption under
the industrial sector. The combination of these changes
and the methodological change described above resulted
in an average annual increase of 0.2 Tg CO2 Eq. (2.8
percent) in CH4 emissions and an average annual decrease
of 0.4 Tg CO2 Eq. (3.0 percent) in N2O emissions for the
period 1990 through 2000.
In the Mobile Combustion (excluding CO2) section of
the energy chapter, the following historical data changes
were made:
Vehicle Miles Traveled (VMT) Adjustment for
Gasoline and Diesel Highway Vehicles: VMT for
alternative fuel vehicles were calculated separately
using EIA Data Tables (EIA 2002a). Since the VMT
estimates from Federal Highway Administration
include total VMT in the United States, it was
necessary to subtract VMT from alternative fuel
vehicles from this total.
Locomotive fuel consumption: The data source for
locomotive fuel consumption was changed to AAR
(2001), which reports annual diesel consumption
for Class I railroad locomotives, and Benson (2002),
which provided diesel consumption for Class II and
Class III railroad locomotives.
Changes-9
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The combination of these changes and the
methodological revisions described above resulted in an
average annual increase of 0.1 Tg CO2 Eq. (1.8 percent)
in CH4 emissions and 0.1 Tg CO2 Eq. (0.2 percent) in N2O
emissions for the period 1990 through 2000.
• In the Coal Mining section of the Energy Chapter, an
error was corrected in the spreadsheet for recovery
estimates for 1991 and 1992. For the year 2000, the
recovery information was updated based on improved
information from one underground mine. The
combination of these changes and the methodological
revision described above resulted in an average annual
increase of 0.1 Tg CO2 Eq. (0.1 percent) in CH4 emissions
for the period 1990 through 2000.
• In the Natural Gas Systems section of the Energy
chapter, the following changes were made:
- Methane emission estimates have been revised to
incorporate new activity driver data for natural gas
consumption in the transportation sector (EIA
2002e), the number of associated wells (API 2002),
and the number of non-associated wells (EIA 2002d).
Updated emission reduction data has become
available for the 1990 through 2001 time series from
the EPA Natural Gas STAR Program. Historical data
has been revised to incorporate the updated data.
The combination of these changes and the
methodological revisions described above resulted in an
average annual increase of 1.3 Tg CO2 Eq. (1.1 percent)
in CH4 emissions for the period 1990 through 2000.
• In the Municipal Solid Waste Combustion section of
the Energy chapter, scrap tire weight data were updated
to reflect information from the RMA/STMC website
Scrap Tires, Facts and Figures (2002). New data on
plastics, synthetic fibers, and synthetic rubber in 2000
from Municipal Solid Waste in the U.S.: 2000 Facts
and Figures were also incorporated into the municipal
solid waste analysis. The combination of these
changes and the methodological revision described
above resulted in an average annual increase of 0.6 Tg
CO2Eq. (2.6 percent) in CO2 emissions for the period
1990 through 2000.
• In the International Bunker Fuels section of the Energy
chapter, there was a change in historical military fuel
consumption reported by the DoD (DESC 2002). Based
on available Service data and expert judgment, a small
fraction of the total jet fuel was reallocated from the
aviation subtotal to a new land-based jet fuel category
for 1997 and subsequent years. This change resulted
in reduced military aviation fuel consumption reported
between 1997 and 2000. DoD is increasing the use of
JP8 (a type of jet fuel) in land-based vehicles and
equipment as the Department implements its policy of
using a single fuel (JP8) for all tactical equipment. Total
aviation emissions increased in the year 2000 due to
revised historical data on total jet fuel expenditures by
foreign air carriers in U.S. ports (BEA 2002). Military
marine fuel consumption data provided by the DoD was
revised downward for 2000, though this had little effect
on total emissions. These changes resulted in an
emissions decrease of 0.97 Tg CO2 Eq. (-1 percent) in a
combination of CO2, CH4, and N2O emissions for 2000.
• In the Iron and Steel Production section of the Industrial
Processes chapter, 1997 and 2000 coal consumption data
for U.S. coke plants were revised using updated
estimates from EIA (EIA 2002c). These changes resulted
in a decrease of 4.3 Tg CO2 Eq. (5.6 percent) in CO2
emissions for 1997 and an increase of less than 0.05 Tg
CO2 Eq. (0.1 percent) in CO2 emissions for 2000.
• In the Cement Manufacture section of the Industrial
Processes chapter, the clinker production data were
updated to reflect the information in the Mineral
Industry Surveys, Cement, December 2001 (USGS
2002a). The revisions resulted in an increase of 0.1 Tg
CO2 Eq. (0.3 percent) in CO2 emissions for 2000.
• In the Ammonia Manufacture and Urea Application
section of the Industrial Processes chapter, ammonia
production for 2000 was adjusted to reflect revised
production information from the U.S. Census Bureau
(U.S. Census Bureau 2002). The combination of this
change and the methodological changes discussed
above resulted in an average annual increase of 1.2 Tg
CO2 Eq. (6.5 percent) in CO2 emissions for the period
1990 through 2000.
Changes-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
• In the Lime Manufacture section of the Industrial •
Processes chapter, the activity data was altered to
incorporate revised production numbers (USGS 2002b)
for dolomitic quicklime and high-calcium hydrated lime.
The revision decreased the total lime production for
2000, leading to a decrease of less than 0.05 Tg CO2 Eq.
(less than 0.05 percent) in CO2 emissions for that year.
• In the Limestone and Dolomite Use section of the
Industrial Processes chapter, the limestone and dolomite
consumption data used to calculate CO2 emissions have
been revised for the entire 1990 to 2000 time period. •
The revision included a change in the source of
consumption data for flue gas desulphurization from an
EIA document to the Mineral Yearbook: Crushed Stone
Annual Report (Tepordei 2002). The comprehensive
activity data revision was responsible for improving
the accuracy of end-use consumption estimates for 1990 .
and 1992, years in which the USGS did not conduct a
detailed survey of limestone and dolomite consumption.
Additionally, the revision allowed for the more accurate
estimation of the consumption data points withheld by
the USGS to avoid disclosing proprietary company
information. These changes resulted in an average
annual increase in CO2 emissions of 0.3 Tg CO2 Eq. (5.4
percent) for the period 1990 through 1996 and an
average annual decrease in CO2 emissions of 1.8 Tg
CO2Eq. (19.9 percent) for the period 1997 through 2000.
• In the Titanium Dioxide Consumption section of the
Industrial Processes chapter, the activity data used to
calculate CO2 emissions have been revised to reflect an
updated 2000 figure (USGS 2001). This change resulted
in a decrease of less than 0.05 Tg CO2 Eq. (2.3 percent)
in CO2 emissions for 2000.
• In the Carbon Dioxide Consumption section of the
Industrial Processes chapter, the activity data used to .
calculate CO2 emissions was revised to incorporate the
most recent publication by the Freedonia Group, Inc.
(2002). The Freedonia Group, Inc. report included data
for 1992, 1996, and 2001. Remaining years were
extrapolated rather compiling data from previous
Freedonia Group, Inc. reports, to ensure data timeseries
consistency. This change resulted in an average annual
increase of 0.2 Tg CO2 Eq. (14 percent) in C02 emissions
from this source from 1990 through 2000.
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 (ACC 2002). The
production data was altered for ethylene for the years
1995,1996,1999,and2000. Methanol data was revised
for 1995 only and styrene data was revised for 1996
only. These changes resulted in an average annual
increase of less than 0.05 Tg CO2 Eq. (0.2 percent) in
CH4 emissions for the period 1995 through 2000.
In the Silicon Carbide section of the Industrial
Processes chapter, the activity data used to calculate
CH4 emissions have been revised to correct an error in
the 1999 calculation. This change resulted in a
decrease of less than 0.05 Tg CO2 Eq. (6.9 percent) in
CH4 emissions for 1999.
In the Nitric Acid Production section of the Industrial
Processes chapter, 2000 production data used last year
were revised using updated estimates from Chemical
and Engineering News (C&EN 2002). The change
resulted in an average annual decrease of 0.1 Tg CO2
Eq. (0.3 percent) in N2O emissions for the period 1990
through 2000.
In the Adipic Acid Production section of the Industrial
Processes chapter, the 2000 capacity data for the
smallest plant in the 1990-2000 report were based on
projections of an expansion in capacity. However, no
data exists to confirm the expansion. Consequently,
this year's inventory keeps the 2000 capacity data for
this plant equal to its 1998 capacity data. In addition,
facility-specific emissions data were used directly for
another plant. The change resulted in an annual average
decrease of 0.7 Tg CO2 Eq. (8.2 percent) inN2O emissions
for the period 1990 through 2000.
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 in the
fire-extinguishing sector. These changes resulted in
an average annual decrease of 0.3 Tg CO2 Eq. (0.7
percent) in HFC and PFC emissions for the period 1994
through 2000.
Changes-11
-------
• In the Aluminum Production section of the Industrial
Processes chapter, the estimates of PFC emissions for
2000 have been revised due to the receipt of additional
smelter-specific information on aluminum production
and anode effect frequency and duration. These data
were provided by the EPA in cooperation with
participants in the Voluntary Aluminum Industrial
Partnership program. The changes resulted in a
decrease of less than 0.05 Tg CO2 Eq. (0.3 percent) in
PFC emissions for 2000.
• In the Magnesium Production and Processing section
of the Industrial Processes chapter, the emissions
estimates for this report were revised to reflect new
activity data for magnesium produced and processed
(particularly the quantities die cast). The revision of the
estimates of the quantities of magnesium die cast was
the most important of these changes, setting the pattern
for the changes in the emission estimates. Both estimated
die-casting and estimated emissions increased for the
year 1996 and decreased for the years 1997 through 2000.
The combination of these changes and the
methodological revision described above resulted in an
average annual decrease of 0.1 Tg CO2 Eq. (1.9 percent)
in SF6 emissions for the period 1990 through 2000.
• In the Enteric Fermentation section of the Agriculture
chapter, the majority of the change in cattle emissions
is due to the diet assumption discussed above, but
the animal population data were also updated to
include revisions completed by the organizations that
produce these estimates. Specifically, the Food and
Agriculture Organization updated horse populations
from 1990 through 2000 (FAO 2002a). Additionally,
some cattle population data were revised to reflect
updated USDA estimates. The combination of these
changes and the methodological revisions described
above resulted in an average annual decrease of 9.3
Tg CO2 Eq. (7.3 percent) in CH4 emissions for the period
1990 through 2000.
• In the Manure Management section of the Agriculture
chapter, historical data for swine, turkey, sheep, and horse
populations were updated. The changes are detailed below:
The 2001 inventory includes corrections made to
the population data for swine. The 2000 inventory
contained errors in the swine population for the
following states and years: South Dakota, 1990;
Wisconsin, 1992; and Georgia and Kentucky; 1999.
These data were corrected. An additional error was
identified in the N2O emissions calculations, in
which the total managed swine population reflected
an incorrect sum of weight class populations.
These formulas were corrected. An error was also
identified in the previous inventory in which the
swine population data listed for Pennsylvania in
1991 and 1992 were incorrect. This was due to an
inaccuracy in the online USDA database from which
these data were collected. USDA verified the correct
data are published in the USDA publication Hogs
and Pigs-Final Estimates 1988-92 (USDA 1994).
The results of all of these corrections are a slight
change for the swine CH4 emission estimates (up
to a 4 percent increase) and a 19 percent increase in
the N2O emission estimates for all years of the swine
inventory estimates.
The 2000 inventory contained incorrect population
data for turkeys in 2000. These errors were due to
incorrect spreadsheet linking and were corrected.
The result is a slight change in poultry CH4 and
N2O emissions for that year of the inventory.
The 2000 inventory contained incorrectly
calculated sheep populations for sheep on-feed
and not-on-feed for all years of the inventory for
the "Other" state populations classification. This
calculation was corrected, resulting in an
estimated increase of 3 percent to 11 percent N2O
emissions. This calculation did not affect CH4
emissions estimates.
The Food and Agriculture Organization of the
United Nations has an online database that is used
for horse population estimates. These data, from
1990 through 2000, have been updated from the
data used in the previous Inventory. Therefore,
all N2O and CH4 emission estimates for horses
have changed slightly (up to 2 percent) 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.
Changes-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
The combination of these changes and the
methodological change described above resulted in an
average annual increase of 1.3 Tg CO2 Eq. (4.0 percent)
in CH4 emissions and 0.2 Tg CO2 Eq. (1.2 percent) in
N2O emissions for the period 1990 through 2000.
• In the Rice Cultivation section of the Agriculture
chapter, one change has been made to the historical
data. Acreage harvested in Missouri in the year 2000
has been revised based on the latest statistics from
the USDA (2002d). This change resulted in a less than
one percent change in total harvested rice area for
that year. As a result, there was a decrease of less
than 0.05 Tg CO2 Eq. (0.1 percent) in CH4 emissions
for 2000.
• In the Agricultural Soil Management section of the
Agriculture chapter, there were several changes to
historical data that are described below:
Crop production figures for 2000 were revised
using the most recent estimates provided by
USDA(2002d).
New manure data were incorporated based on the
following updated livestock population estimates:
Swine population numbers were corrected for
several years from 1990 through 1999.
Spreadsheet errors affecting the year 2000 turkey
and sheep population data were found and
corrected. The horse population data for 1990
through 2000 were revised with the updated data
from the FAO online database. (USDA2002a-c,e-
g; FAO 2002b).
Estimates of sewage sludge nitrogen applied to
land were revised for 1990 through 1994. The
percent of total sludge produced that gets land
applied was modified to exclude surface disposal.
Commercial and organic fertilizer consumption data
were updated for 2000 using the most recent
AAPFCO estimates (2002).
These revisions resulted in a decrease of 3.0 Tg CO2
Eq. (1.0 percent) in N2O emissions for 2000, and an
average annual increase of 0.3 Tg CO2 Eq. (0.1 percent)
in N2O emissions for the period 1990 through 2000.
• In the Field Burning of Agricultural Residues section of
the Agriculture chapter, the year 2000 crop production
data have been revised for all crops. The new data reflect
the most current statistics from the USDA (2002d). This
change resulted in a decrease of less than 0.05 Tg CO2 Eq.
(0.3 percent) in CH4 emissions and a decrease of less than
0.05 Tg CO2 Eq. (0.4 percent) inN2O emission for 2000.
In the Land-Use Change and Forestry chapter, the
following changes were made:
In the Agricultural Soils section, probability
density functions were constructed for
management factors based on a statistical
analysis of estimated changes in carbon stocks
from published studies addressing land use and
management impacts (Ogle et al. in review). The
probability density functions were used in place
of the management factors provided in the
documentation for the default IPCC carbon
accounting approach (IPCC/UNEP/OECD/
IEA 1997). Similarly, probability density
functions were constructed for reference carbon
stocks based on a statistical analysis of field
measurements recorded in the National Soil
Survey Characterization Database (NRCS 1997).
The probability density functions were used in
place of the reference carbon stocks that are
provided in the documentation for the default
IPCC carbon accounting approach (IPCC/UNEP/
OECD/IEA 1997).
In the Agricultural Soils section, the 1998 to 2001
estimates for the CRP enrollment were updated with
data provided by the Farm Services Agency
(Barbarika2002).
In the Landfilled Yard Trimmings section, the
landfilled yard trimmings data for 1998 through
2000 were updated to reflect revised estimates in
EPA(2002c).
The combination of these changes and the
methodological revisions described above resulted in
an average annual decrease in carbon sequestration
from land-use change and forestry of 24.7 Tg CO2 Eq.
(2.3 percent) for the period 1990 through 1992 and 51.6
Tg CO2 Eq. (5.3 percent) for the period 1993 through
2000.
Changes-13
-------
• In the Landfills section of the Waste chapter, this report
reflects an updated database of flare and landfill-gas-to-
energy (LFGTE) projects. The CH4 mitigated from LFGTE
projects increased slightly from 1990 through 1999 and
decreased slightly in 2000. The difference is primarily
attributed to the availability of additional LFGTE projects
included in this year's LFGTE database, as well as revised
estimates of megawatt capacity for electricity projects
and landfill gas flow for direct use projects. This year's
estimate of CH4 emissions avoided through flaring reflects
new data on flares that became operational prior to 1990.
In addition, new data in the LFGTE database led to
increased matches between the flare data and the LFGTE
data, resulting in the exclusion of additional flares from
the estimate of emission reductions through flaring (note:
emission reductions associated with landfills that have
both a flare and a LFGTE project are counted in the LFGTE
totals). The combination of these changes and the
methodological change described above resulted in an
average annual decrease of less than 0.05 Tg CO2 Eq.
(less than 0.05 percent) in CH4 emissions for the period
1990 through 2000.
• In the Wastewater Treatment section of the Waste
chapter, the U.S. population estimates were updated
for the 1991 through 2000 period with data from the
2000 Census. The revision resulted in an average annual
decrease of 0.2 Tg CO2 Eq. (0.8 percent) in CH4 emissions
for the period 1990 through 2000.
Changes-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
1. Introduction
This report presents estimates by the United States government of U.S. anthropogenic greenhouse gas emissions
and sinks for the years 1990 through 2001. 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 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. Such a level
should be achieved within a time-frame sufficient to allow ecosystems to adapt naturally to climate change, to ensure that
food prdocution is not threatened and to enable economic development to proceed in a sustainable manner."2-3
Parties to the Convention, by ratifying, committed "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.. ."4 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 World Meteorological Organization (WMO) and the United
Nations Environment Programme (UNEP) jointly established the Intergovernmental Panel on Climate Change (IPCC). 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). Underworking 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 IPCC accepted the Revised
1996 IPCC Guidelines at its Twelfth Session (Mexico City, 11-13 September 1996). This report presents information in
accordance with these guidelines. 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.
Overall, this inventory of anthropogenic greenhouse gas emissions (1) provides a basis for the ongoing development
of methodologies for estimating sources and sinks of greenhouse gases; (2) provides 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) is a prerequisite for accounting for reductions and evaluating possible
mitigation strategies.
1 See the section below entitled Global Warming Potentials for an explanation of GWP values.
2 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).
3 Article 2 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change.
See . (UNEP/WMO 2000)
4 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
-------
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 (CO2), 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 balance of energy transfers between the atmosphere,
space, land, and the oceans.5 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, 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 hydrochloro-
fluorocarbons (HCFCs) are halocarbons that contain
chlorine, while halocarbons that contain bromine are referred
to as bromofluorocarbons (i.e., halons). As stratospheric
ozone depleting substances, CFCs, HCFCs, and halons are
covered under the Montreal Protocol on Substances that
Deplete the Ozone Layer. The UNFCCC defers to this earlier
international treaty. Consequently, Parties are not required
to include these gases in national greenhouse gas
inventories.6 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 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 are extremely small particles or liquid
droplets that are often composed of sulfur compounds,
carbonaceous combustion products, crustal materials and
other human induced pollutants. They can affect the
absorptive characteristics of the atmosphere. Comparatively,
however, the level of scientific understanding of aerosols is
still very low. (IPCC 2001)
Carbon dioxide, CH4, and N2O 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.
5 For more on the science of climate change, see NRC (2001).
6 Emissions estimates of CFCs, HCFCs, halons and other ozone-depleting substances are included in this document for informational
purposes.
1 -2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
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
CO,
CH,
N70
SFfi!
Pre-industrial atmospheric concentration
Atmospheric concentration11
Rate of concentration change0
Atmospheric Lifetime
280
370.3
1.5"
50-200°
0.722
1.842
0.007"
12f
0.270
0.316
0.0008
114f
0
4.7
0.24
3,200
40
80
1.0
> 50,000
Source: Current atmospheric concentrations for C02, CH4, N20, and SF6 are from Biasing and Jones (2002). All other data is from IPCC (2001).
8 Concentrations in parts per trillion (ppt) and rate of concentration change in ppt/year.
b Concentration for C02 was measured in 2001. Concentrations for all other gases were measured in 2000.
c Rate is calculated over the period 1990 to 1999.
d Rate has fluctuated between 0.9 and 2.8 ppm per year for C02 and between 0 and 0.013 ppm per year for CH4 over the period 1990 to 1999.
e No single lifetime can be defined for C02 because of the different rates of uptake by different removal processes.
f This lifetime has been defined as an "adjustment time" that takes into account the indirect effect of the gas on its own residence time.
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 affect directly the average global
concentration of water vapor, but, the radiative forcing
produced by the increased concentrations of other
greenhouse gases may indirectly affect the hydrologic cycle.
While a warmer atmosphere has an increased water holding
capacity, increased concentrations of water vapor affects
the formation of clouds, which can both absorb and reflect
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 COr Atmospheric CO2 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-industrial times to 370.3
ppmv in 2001, a 32 percent increase (IPCC 2001 and Biasing
and Jones 2002).7<8 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 CO2.
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 wanning 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 CH4 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
7 The pre-industrial period is considered as the time preceding the year 1750 (IPCC 2001).
8 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).
Introduction 1-3
-------
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 through a
reaction with the hydroxyl radical (OH) and is ultimately
converted to CO2. Minor removal processes also include
reaction with chlorine in the marine boundary layer, a soil
sink, and stratospheric reactions. Increasing emissions of
CH4 reduce the concentration of OH, a feedback that may
increase the atmospheric lifetime of CH4 (IPCC 2001).
Nitrous Oxide (N2O). Anthropogenic sources of N2O
emissions include agricultural soils, especially production
of nitrogen-fixing crops and forages, the use of synthetic
and manure fertilizers, and manure deposition by livestock;
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 N2O has increased by 16
percent since 1750, from a pre industrial value of about 270
ppb to 316 ppb in 2000, 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,9 where it shields the Earth from harmful levels
of ultraviolet radiation, and at lower concentrations in the
troposphere,10 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 Act" 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
(SFJ. 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
hydrobro-mofluorocarbons (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 warming 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 512
countries beginning in 1996, and then followed by a complete
phase-out by the year 2030. While ozone depleting gases
9 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.
10 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.
11 [42 U.S.C § 7408, CAA § 108]
12 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.
1 -4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
covered under the Montreal Protocol and its Amendments are
not covered by the UNFCCC, they are reported in this inventory
under Annex T for informational purposes.
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 are primarily used as replacements
for ozone depleting substances but also emitted as a by-
product of the HCFC-22 manufacturing process. Currently,
they have a small aggregate radiative forcing impact, but it
is anticipated that their 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, but 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 CH4 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 in the atmosphere, it is eventually oxidized
to CO2. Carbon monoxide concentrations are both short-
lived in the atmosphere and spatially variable.
Nitrogen Oxides (NOJ. 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.13 Additionally,
NOx emissions from aircraft are also likely to decrease CH4
concentrations, thus having a negative radiative forcing
effect (IPCC 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 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 substances
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, sulfates, and volcanic aerosols, and
anthropogenically manufactured aerosols such as industrial
dust and carbonaceous14 aerosols (e.g., black carbon, organic
carbon) from transportation, coal combustion, cement
manufacturing, waste incineration, and biomass burning.
13 NOX emissions injected higher in the stratosphere, primarily from fuel combustion emissions from high altitude supersonic aircraft, can
lead to stratospheric ozone depletion.
14 Carbonaceous aerosols are aerosols that are comprised mainly of organic substances and forms of black carbon (or soot) (IPCC 2001).
Introduction 1-5
-------
Table 1-2: Global Warming Potentials and
Atmospheric Lifetimes (Years) Used in This Report
Gas
Atmospheric Lifetime GWPa
Carbon dioxide (C02)
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
CM^O
Vl4
SF6
50-200
12±3
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 GWP of CH4 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.
The net effect of aerosols on radiative forcing is believed
to be negative (i.e., net cooling effect on the climate), although
because they remain in the atmosphere for only days to weeks,
their concentrations respond rapidly to changes in emissions.15
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, elemental carbon, may have
a positive radiative forcing (Jacobson 2001). The primary
anthropogenic emission sources of elemental carbon include
diesel exhaust, coal combustion, and biomass burning.
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
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.)16
The relationship between gigagrams (Gg) of a gas and Tg
CO2Eq. can be expressed as follows:
Tg CO2 Eq = (Gg of gas) * (GWP):
Tg
l,OOOGg
where,
TgCO2Eq. =Teragrams of Carbon Dioxide Equivalents
Gg = Gigagrams (equivalent to a thousand metric tons)
GWP = Global Warming Potential
Tg = Teragrams
GWP values allow for a comparison of 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.
"...consistent with decision 2/CP.3, Annex I Parties
should report aggregate emissions and removals of
greenhouse gases, expressed in CO2 equivalent terms
at summary inventory level, using GWP values
provided by the IPCC in its Second Assessment
Report, ... based on the effects of greenhouse
gases over a 100-year time horizon. "17
15 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).
16 Carbon comprises 12/44ths of carbon dioxide by weight.
17 Framework Convention on Climate Change; ; 1 November 2002; Report of the Conference
of the Parties at its eighth session; held at New Delhi from 23 October to 1 November 2002; Addendum; Part One: Action taken by the
Conference of the Parties at its eighth session; Decision -/CP.8; Communications from Parties included in Annex I to the Convention:
Guidelines for the Preparation of National Communications by Parties Included in Annex I to the Convention, Part 1: UNFCCC reporting
guidelines on annual inventories; p. 6. Advance unedited version. FCCC (2002)
1 -6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
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 assessment
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 C02 radiative
forcing and an improved C02 response function (presented in WMO 1999). 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.
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
HFC-4310mee
CF4
C2F6
C^io
CeFu
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
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 (No Change)
* The GWP of CH4 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, this report uses GWPs from the Second Assessment Report. The UNFCCC
reporting guidelines for national inventories18 were updated in 2002 but continue to require the use of GWPs from the SAR so that current
estimates of aggregate greenhouse gas emissions for 1990 through 2001 are consistent and comparable with estimates 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 below and in even more detail in Annex S. Overall, these revisions to GWP values do not have a significant effect on U.S.
emission trends, as shown in Table 1 -4. All estimates provided throughout this report are also presented in unweighted units.
Table 1-4: Effects on U.S. Greenhouse Gas Emission Trends Using IPCC SAR and TAR GWP Values (Tg C02 Eq.)
Change from 1990 to 2001 Revisions to Annual Estimates
Gas SAR TAR 1990 2001
C02
CH4
N20
MFCs, PFCs, and SF6
Total
Percent Change
791.1
(38.12)
27.0
16.6
796.6
13.0%
791.1
(41.75)
25.8
10.0
785.1
12.7%
0
61.3
(18.0)
(2.6)
40.8
0.7%
0
57.7
(19.2)
(9.2)
29.3
0.4%
See .
Introduction 1-7
-------
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 (8.7 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 1-5: Comparison of Emissions by Sector using IPCC SAR and TAR GWP Values (Tg C02 Eq.)
Sector
1990
Energy
SAR GWP (Used In Inventory) 5,147.5
TAR GWP 5,168.4
Difference (%) 0.4%
Industrial Processes
SAR GWP (Used In Inventory) 302.2
TAR GWP 298.1
Difference (%) (1.4%)
Agriculture
SAR GWP (Used In Inventory) 441.0
TAR GWP 443.1
Difference (%) 0.5%
Land-Use Change and Forestry
SAR GWP (Used In Inventory) (1,072.8)
TAR GWP (1,072.8)
Difference (%) 0.0%
Waste
SAR GWP (Used In Inventory) 248.9
TAR GWP 270.8
Difference (%) 8.8%
Net Emissions (Sources and Sinks)
SAR GWP (Used In Inventory) 5,066.8
TAR GWP 5,107.6
Difference (%) 0.8%
NC (No change)
Note: Totals may not sum due to independent rounding.
1995
1996
1997
1998
1999
2000
2001
5,481.6
5,500.9
0.4%
308.3
302.3
(1.9%)
468.4
470.8
0.5%
(1,064.2)
(1,064.2)
0.0%
256.6
279.1
8.8%
5,450.7
5,488.9
0.7%
5,661.4
5,680.3
0.3%
318.8
310.0
(2.8%)
473.7
475.2
0.3%
(1,061.0)
(1,061.0)
0.0%
253.1
275.2
8.7%
5,646.0
5,679.6
0.6%
5,733.0
5,751.5
0.3%
321.4
312.8
(2.7%)
479.0
480.3
0.3%
(840.6)
(840.6)
0.0%
249.2
270.9
8.7%
5,942.0
5,974.9
0.6%
5,749.4
5,767.6
0.3%
325.9
317.5
(2.6%)
481.3
482.7
0.3%
(830.5)
(830.5)
0.0%
244.7
266.0
8.7%
5,970.9
6,003.3
0.5%
5,809.5
5,826.9
0.3%
313.7
304.5
(2.9%)
479.3
480.8
0.3%
(841.1)
(841.1)
0.0%
247.0
268.4
8.7%
6,008.5
6,039.6
0.5%
6,010.4
6,027.7
0.3%
312.6
30Z.9
(3.1%)
475.1
476.4
0.3%
(834.6)
(834.6)
0.0%
249.2
270.8
8.7%
6,212.7
6,243.2
0.5%
5,927.1
5,944.1
0.3%
287.6
277.3
(3.6%)
474.9
476.2
0.3%
(838.1)
(838.1)
0.0%
246.6
267.9
8.7%
6,098.1
6,127.4
0.5%
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
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 2001, total U.S. greenhouse gas emissions were 6,936.2
teragramsofCO2 equivalents (Tg CO2 Eq.)19 (13.0 percent
above 1990 emissions). Emissions declined for the second
time since 1990, decreasing by 1.6 percent (111.2 Tg CO2 Eq.)
from 2000 to 2001, primarily because of a decrease in CO2
emissions from fossil fuel combustion. The reduction in fossil
fuel combustion emissions is linked to the following factors:
1) slowing of economic growth in 2001, 2) a considerable
19 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.)
1 -8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Figure 1-1
Figure 1-2
U.S. GHG Emissions by Gas
I MFCs, PFCs, & SF6 • Methane
Nitrous Oxide • Carbon Dioxide
Annual Percent Change in U.S. GHG Emissions
2.9%
2.9%
reduction in industrial output, leading to decreased demand
for electricity and fuel, 3) warmer winter conditions compared
to 2000, and 4) an increased share of output from nuclear
facilities. (See the 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.
As the largest source of U.S. greenhouse gas emissions,
CO2 from fossil fuel combustion accounted for a nearly constant
80 percent of global warming potential (GWP) weighted emissions
in the 1990s. Emissions from this source category grew by 17
percent (800.1 TgCO2Eq.)from 1990 to 2001 and were responsible
for most of the increase in national emissions during this period.
The recent annual change in CO2 emissions from fossil fuel
combustion was a reduction of 77.3 Tg CO2 Eq. (1.4 percent),
which is the second decrease in emissions since the Inventory
base year 1990, the first being in 1991. The source's average
annual growth rate was 1.3 percent from 1990 through 2001.
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 generally fluctuates in response to changes in
general economic conditions, energy prices, weather, and the
availability of non-fossil alternatives. For example, in a year
Figure 1-3
Absolute Change in U.S. GHG Emissions Since 1990
908
797
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, there would likely be 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.
In the longer-term, energy consumption patterns respond
to 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).
Introduction 1-9
-------
Table 1-6: Annual Change in C02 Emissions from Fossil Fuel Combustion for Selected Fuels and Sectors (Tg C02 Eq.
and Percent)
Sector
Fuel Type 1996 to 1997 1997 to 1998 1998 to 1999 1999 to 2000 2000 to 2001
Electricity Generation
Electricity Generation
Electricity Generation
Transportation3
Residential
Commercial
Industrial
Industrial
All Sectors"
Coal
Natural Gas
Petroleum
Petroleum
Natural Gas
Natural Gas
Coal
Natural Gas
All Fuels"
44.1
13.9
9.0
7.3
(14.0)
3.1
1.2
1.1
74.2
3%
7%
14%
0%
(3%)
2%
1%
0%
1%
30.6
29.1
29.7
33.0
(23.7)
(10.8)
(8.7)
(11.7)
20.5
2%
13%
40%
2%
(9%)
(6%)
(6%)
(2%)
0%
8.7
12.0
(7.6)
58.7
10.0
1.7
(6.1)
(17.6)
68.3
0%
5%
(7%)
4%
9%
1%
(4%)
(4%)
1%
89.4
20.6
(5.7)
49.8
13.9
9.1
2.3
12.5
202.8
5%
8%
(6%)
3%
3%
5%
2%
3%
4%
(50.1)
4.3
10.7
19.7
(9.6)
1.6
(7.7)
(33.5)
(77.9)
(3%)
2%
12%
1%
(1%)
1%
(6%)
(7%)
(1%)
a Excludes emissions from International Bunker Fuels.
b Includes fuels and sectors not shown in table.
Energy-related CO2 emissions also depend on the type
of fuel or energy consumed and its carbon intensity.
Producing a unit of heat or electricity using natural gas
instead of coal, for example, can reduce the CO2 because of
the lower carbon content of natural gas. Table 1-6 shows
annual changes in emissions during the last six years for
coal, petroleum, and natural gas in selected sectors.
Milder weather conditions in summer and winter of 1997
(compared to 1996) moderated the growth of CO2 emissions from
fossil fuel combustion. The shut-down of several nuclear power
plants, however, led electric utilities to increase their consumption
of coal and other fuels to offset the lost nuclear capacity.
In 1998, warm winter temperatures contributed to 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.20 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 that
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 offset
reduced hydropower output.
In 2001, the U.S. economy slowed for the second time
since 1990, resulting in decreased emissions from CO2 emissions
from fossil fuel combustion also for the second time since 1990.
A significant reduction in industrial output accompanied this
slowdown, primarily in manufacturing, leading to lower
emissions from the industrial sector. Several other factors also
played a role in this decrease in emissions. Warmer winter
conditions compared to 2000, along with higher natural gas
prices, reduced demand for heating fuels. Additionally, nuclear
facilities operated at their highest capacity on record, replacing
electricity produced from fossil fuels. Since there are no
greenhouse gas emissions associated with electricity
production from nuclear plants, this substitution reduces the
carbon intensity of electricity generation.
Other significant trends in emissions from additional
source categories over the twelve year period from 1990
through 2001 included the following:
1 Normals are based on data from 1961 through 1990. Source: NOAA (2002)
1-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Net CO2 flux from land use change and forestry
decreased by 234.7 Tg CO2 Eq. (22 percent), primarily
due to a decline in the rate of net carbon accumulation
in forest carbon stocks.
Aggregate HFC and PFC emissions resulting from the
substitution of ozone depleting substances (e.g., CFCs)
increased by 62.7 Tg CO2 Eq. This increase was significantly
offset, however, by reductions in PFC emissions from
aluminum production (14.0 Tg CO2 Eq. or 77 percent),
reductions in emissions of HFC-23 from the production of
HCFC-22 (15.2 Tg CO2 Eq. or 43 percent), and reductions of
SF6 from electric power transmission and distribution
systems (16.8 Tg CO2 Eq. or 52 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 because a reduction in
the intensity of emissions from that source offset 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 26.4
Tg CO2 Eq. (30 percent) as a result of the mining of less
gassy coal from underground mines and the increased
use of CH4 collected from degasification systems.
Nitrous oxide emissions from agricultural soil
management increased by 26.8 Tg CO2 Eq. (10 percent)
as fertilizer consumption and cultivation of nitrogen-
fixing and other crops rose.
Carbon dioxide emissions from waste combustion
increased 12.8 Tg CO2 Eq. (91 percent), as the volume
of plastics and other fossil carbon-containing materials
in municipal solid waste grew.
By 1998, all of the three major adipic acid producing plants
had voluntarily implemented N2O abatement technology,
and as a result, emissions fell by 10.3 Tg CO2 Eq. (68 percent).
The majority of this decline occurred from 1996 collected
and combusted by landfill operators has increased.
Methane emissions from U.S. landfills decreased by 9.1 Tg
CO2 Eq. (4 percent), as the amount of landfill gas collected
and combusted by landfill operators has increased.
Figure 1-4
U.S. GHG Emissions by Chapter/IPCC Sector
7,000 -
6,000
5,000
S 4,000
CM
§ 3,000
O)
I- 2,000
1,000
0
(1,000)
(2,000)
Industrial Processes Waste
Agriculture
Energy
Land-Use Change and Forestry (sink)
Overall, from 1990 to 2001, total emissions of CO2 and
N2O increased by 791.1 (16 percent) and 27.0 Tg CO2 Eq. (7
percent), respectively, while CH4 emissions decreased by 3 8.1
Tg CO2 Eq. (6 percent). During the same period, aggregate
weighted emissions of HFCs, PFCs, and SF6 rose by 16.6 Tg
CO2 Eq. (18 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, trees in urban areas,
agricultural soils, and landfilled yard trimmings, which was
estimated to be 12 percent of total emissions in 2001.
As an alternative, emissions of all gases can be totaled for
each of the IPCC sectors. Over the twelve year period of 1990
to 2001, total emissions in the Energy and Agriculture sectors
climbed by 779.6 (15 percent) and 33.8 Tg CO2Eq. (8 percent),
respectively, while emissions from the Industrial Processes and
Waste sectors decreased 14.6 Tg CO2Eq. (5 percent) and 2.3 Tg
CO2 Eq. (1 percent), respectively. Over the same period,
estimates of net carbon sequestration in the Land-Use Change
and Forestry sector declined by 234.7 Tg CO2 Eq. (22 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 1-4.
Introduction 1-11
-------
Table 1-8: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg C02 Eq.)
Gas/Source
1990
1995
1996
1997 1998
1999
2000 2001
C02
Fossil Fuel Combustion
Iron and Steel Production
Cement Manufacture
Waste Combustion
5,003.7
4,814.81
85.41
33.31
14.1 1
Ammonia Manufacture & Urea Application 1 9.3 f
Lime Manufacture
Natural Gas Flaring
Limestone and Dolomite Use
Aluminum Production
Soda Ash Manufacture and Consumption
Titanium Dioxide Production
Carbon Dioxide Consumption
Ferroalloys
11-2 1
5.51
5.5!
6.31
4.11
1-31
0.91
2.01
Land-Use Change and Forestry (Sink)3 (1 ,072.8) J
International Bunker Fuels"
CH4
Landfills
Natural Gas Systems
Enteric Fermentation
Coal Mining
Manure Management
Wastewater Treatment
Petroleum Systems
Rice Cultivation
Stationary Sources
Mobile Sources
Petrochemical Production
Field Burning of Agricultural Residues
Silicon Carbide Production
International Bunker Fuels"
N20
Agricultural Soil Management
Mobile Sources
Manure Management
Nitric Acid
Human Sewage
Stationary Combustion
Adipic Acid
N20 Product Usage
Field Burning of Agricultural Residues
Waste Combustion
International Bunker Fuels"
HFCs, PFCs, and SF6
773.91
644.01
212.11
122.0!
117.91
87.1 1
31.31
24.11
27.5!
7.11
8.11
5.01
1.2!
0.71
+ 1
0.21
397.61
267.51
50.61
16.21
17,81
127I
12.51
15.21
4.3 1
°-4l
0.31
I0l
94.41
Substitution of Ozone Depleting Substances 0.9 f
HCFC-22 Production
Electrical Transmission and Distribution
Semiconductor Manufacture
Aluminum Production
Magnesium Production and Processing
Total
Net Emissions (Sources and Sinks)
35.0!
32.11
2.9!
18.1 1
5-4 1
6,139.61
5,066.8
1 5,334.4
1 5>141'5
I 74'4
1 36-8
1 18-5
1 20-5
I 12-8
1 87
I 7'°
I 5-3
1 4-3
1 1-7
I 1-1
I 1.9
1(1,064.2)
1 101-°
I 650.0
1 216'1
1 127'2
I 123-°
1 73-5
I 36'2
I 26.6
1 24.2
I 7'6
1 8'5
I 4-9
I 1-5
1 °-7
1 +
1 °-1
1 430>9
1 284'1
I 60.9
1 16-6
I 19-9
I 13'9
1 13'2
I 17'2
I 4'5
I °'4
I °'3
1 °-9
1 99'5
1 217
I 27.0
I 27'5
1 5'9
1 11'8
I 5'6
I 6,514.9
1 5,450.7
5,514.8
5,325.8
68.3
37.1
19.4
20.3
13.5
8.2
7.6
5.6
4.2
1.7
1.1
2.0
(1,061.0)
102.3
636.8
212.1
127.4
120.5
68.4
34.9
26.8
23.9
7.0
8.7
4.8
1.6
0.7
+
0.1
441.7
293.2
60.7
17.0
20.7
14.1
13.8
17.0
4.5
0.4
0.3
0.9
113.6
30.4
31.1
27.7
5.4
12.5
6.5
6,707.0
5,646.0
5,595.4
5,400.0
71.9
38.3
21.2
20.7
13.7
7.6
7.1
5.6
4.4
1.8
1.2
2.0
(840.6)
109.9
629.5
207.5
126.0
118.3
68.1
36.6
27,3
23.6
7.5
7.5
4.7
1.6
0.8
+
0.1
440.9
298.2
60.3
17.3
21.2
14.4
13.7
10.3
4.8
0.4
0.3
1.0
116.8
37.7
30.0
25.2
6.5
11.0
6.3
6,782.6
5,942.0
5,614.2
5,420.5
67.4
39.2
22.5
21.9
13.9
6.3
7.3
5.8
4.3
1.8
1.2
2.0
(830.5)
112.9
622.7
202.4
124.0
116.7
67.9
39.0
27.7
22.9
7.9
7.2
4.6
1.6
0.8
+
0.1
436.8
299.2
59.7
17.3
20.9
14.6
13.7
6.0
4.8
0.5
0.2
1.0
127.6
44.5
40.2
20.9
7.3
9.0
5.8
6,801.3
5,970.9
5,680.7
5,488.8
64.4
40.0
23.9
20.6
13.5
6.7
7.7
5.9
4.2
1.9
1.2
2.0
(841.1)
105.3
615.5
203.7
120.3
116.6
63.7
38.9
28.2
21.6
8.3
7.4
4.5
1.7
0.8
+
0.1
433.0
297.0
58.8
17.4
20.1
15.1
13.7
5.5
4.8
0.4
0.2
0.9
120.3
50.9
30.4
16.4
7.7
8.9
6.0
6,849.5
6,008.5
5,883.1
5,692.2
65.8
41.2
25.4
19.6
13.3
5.5
5.8
5.4
4.2
1.9
1.2
1.7
(834.6)
99.3
613.4
205.8
121.2
115.7
60.9
38.2
28.3
21.2
7.5
7.6
4.4
1.7
0.8
+
0.1
429.9
294.6
57.5
17.9
19.1
15.1
14.3
6.0
4.8
0.5
0.2
0.9
121.0
57.3
29.8
15.4
7.4
7.9
3.2
7,047.4
6,212.7
5,794.8
5,614.9
59.1
41.4
26.9
16.6
12.9
5.2
5.3
4.1
4.1
1.9
1.3
1.3
(838.1)
97.3
605.9
202.9
117.3
114.8
60.7
38.9
28.3
21.2
7.6
7.4
4.3
1.5
0.8
+
0.1
424.6
294.3
54.8
18.0
17.6
15.3
14.2
4.9
4.8
0.5
0.2
0.9
111.0
63.7
19.8
15.3
5.5
4.1
2.5
6,936.2
6,098.1
+ Does not exceed 0.05 Tg C02 Eq.
a 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.
1-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table 1-9: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg)
Gas/Source
CO,
Fossil Fuel Combustion
Iron and Steel Production
Cement Manufacture
Waste Combustion
Ammonia Manufacture
& Urea Application
Lime Manufacture
Natural Gas Flaring
Limestone and Dolomite Use
Aluminum Production
Soda Ash Manufacture
and Consumption
Titanium Dioxide Production
Carbon Dioxide Consumption
Ferroalloys
Land-Use Change &
Forestry (Sink)3
International Bunker Fue/s"
CH4
Landfills
Natural Gas Systems
Enteric Fermentation
Coal Mining
Manure Management
Wastewater Treatment
Petroleum Systems
Rice Cultivation
Stationary Sources
Mobile Sources
Petrochemical Production
1990
5,003,685
4,814,758
85,414
33,278
14,068
19,306
11,238
5,514
5,470
6,315
4,141
1,308
895
1,980
(1,072,807)
113,863
30,667
10,099
5,810
5,612
4,149
1,490
1,147
1,309
339
388
236
56
Field Burning of Agricultural Residues 33
Silicon Carbide Production
International Bunker Fuels"
N20
Agricultural Soil Management
Mobile Sources
Manure Management
Nitric Acid
Human Sewage
Stationary Combustion
Adipic Acid
N20 Product Usage
1
8
1,282
863
163
52
58
41
40
49
14
Field Burning of Agricultural Residues 1
Waste Combustion
International Bunker Fuels'1
MFCs, PFCs, and SF6
Substitution of Ozone
Depleting Substances
HCFC-22 Production0
1
3
M
M
3
Electrical Transmission &Distribution11 1
Semiconductor Manufacture
Aluminum Production
M
M
Magnesium Production & Processing" +
NO,
CO
NMVOCs
22,860
130,575
20,937
1995
5,334,446
5,141,548
74,357
36,847
18,472
20,453
12,804
8,729
7,042
5,265
4,304
1,670
1,088
1,866
(1,064,173)
101,037
30,954
10,290
6,059
5,855
3,502
1,723
1,267
1,153
363
406
232
72
31
1
6
1,389
916
197
53
64
45
43
56
14
1
1
3
M
M
2
1
M
M
+
22,434
109,149
19,520
1996
5,514,811
5,325,798
68,324
37,079
19,418
20,282
13,495
8,233
7,614
5,580
4,239
1,657
1,138
1,954
(1,061,016)
102,272
30,324
10,100
6,069
5,737
3,255
1,661
1,278
1,138
332
415
227
75
36
1
6
1,424
946
196
55
67
46
45
55
14
1
1
3
M
M
3
1
M
M
+
22,149
104,063
17,184
1997
5,595,361
5,400,034
71,864
38,323
21,173
20,650
13,685
7,565
7,055
5,621
4,354
1,836
1,162
2,038
(840,622)
103,858
29,977
9,880
6,001
5,635
3,244
1,741
1,301
1,123
356
358
223
77
36
1
7
1,421
962
195
56
68
46
44
33
15
1
1
3
M
M
3
1
M
M
+
22,284
101,132
16,994
1998
5,614,198
5,420,519
67,429
39,218
22,454
21,934
13,914
6,250
7,331
5,792
4,325
1,819
1,186
2,027
(830,477)
112,859
29,652
9,639
5,903
5,557
3,235
1,858
1,318
1,090
376
342
217
78
37
1
7
1,408
965
192
56
67
47
44
19
15
1
1
3
M
M
3
1
M
M
+
21,963
98,976
16,403
1999
5,680,677
5,488,804
64,376
39,991
23,903
20,615
13,466
6,679
7,671
5,895
4,217
1,853
1,210
1,996
(841,054)
105,262
29,311
9,701
5,728
5,551
3,033
1,852
1,341
1,029
395
351
214
80
36
1
6
1,396
958
190
56
65
49
44
18
15
1
1
3
M
M
3
1
M
M
+
21,199
95,464
16,245
2000
5,883,118
5,692,170
65,755
41,190
25,351
19,587
13,315
5,525
5,763
5,410
4,181
1,918
1,233
1,719
(834,637)
99,268
29,207
9,798
5,772
5,509
2,902
1,820
1,348
1,010
357
363
211
79
37
1
6
1,386
950
185
58
62
49
46
19
15
1
1
3
M
M
3
1
M
M
+
20,555
93,965
15,418
2001
5,794,804
5,614,853
59,074
41,357
26,907
16,588
12,859
5,179
5,281
4,114
4,147
1,857
1,257
1,329
(838,137)
97,346
28,851
9,663
5,588
5,468
2,893
1,850
1,350
1,011
364
353
204
71
36
+
5
1,369
949
177
58
57
49
46
16
15
1
1
3
M
M
2
1
M
M
+
20,048
100,653
15,148
+ Does not exceed 0.5 Gg.
M Mixture of multiple gases
3 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.
c HFC-23 emitted
d SF6 emitted
Note: Totals may not sum due to independent rounding.
Note: Parentheses indicate negative values (or sequestration).
Introduction 1-13
-------
Box 1 -2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data
Total emissions can be compared with other economic and social indices to highlight changes over time. These comparisons include:
1) emissions per unit of aggregate energy consumption, because energy-related activities are the largest sources of emissions; 2) emissions
per unit of fossil fuel consumption, because almost all energy-related emissions involve the combustion of fossil fuels; 3) emissions per unit
of electricity consumption, because the electric power industry—utilities and nonutilities combined—was the largest source of U.S.
greenhouse gas emissions in 2001; 4) emissions per unit of total gross domestic product as a measure of national economic activity; and
5) emissions per capita.
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 1.1 percent since 1990. This rate is slower than that for total energy or fossil
fuel and much slower than 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 1-5). 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
Growth
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 Rate*
GHG Emissions3
Energy Consumption"
Fossil Fuel Consumption"
Electricity Consumption"
GDP
Population"1
Atmospheric C02 Concentration6
99
100
100
102
100
101
100
101
102
102
102
103
103
101
103
104
104
106
105
104
101
105
106
106
109
110
105
101
106
108
107
112
112
107
102
109
112
111
115
116
108
102
110
112
112
117
122
109
103
111
113
113
121
127
111
104
112
115
114
124
132
112
104
115
118
118
128
137
113
104
113
115
115
127
137
114
105
1.1%
1.3%
1.3%
2.2%
2.9%
1.2%
0.4%
GWP weighted values
Energy content weighted values (EIA 2002a)
Gross Domestic Product in chained 1996 dollars (BEA 2002)
(U.S. Census Bureau 2002)
Mauna Loa Observatory, Hawaii (Keeling and Whorf 2002)
Average annual growth rate
Figure 1-5
U.S. Greenhouse Gas Emissions Per Capita and Per
Dollar of Gross Domestic Product
Real GDP
Population
Emissions
per capita
Emissions
per $GDP
Source: BEA (2002), U.S. Census Bureau (2002), and
emission estimates in this report
1-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table 1 -10: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg C02 Eq.)
Chapter/IPCC Sector 1990 H 1995 1996 1997 1998 1999 2000
Energy 5,147.5
Industrial Processes 302.2
Agriculture 441.0
Land-Use Change and Forestry (Sink)* (1072.8)
Waste 248.8
Total
Net Emissions (Sources and Sinks)
6,139.
5,066.8
* 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).
2001
5,481.6
308.2
468.4
(1064.2)
256.6
6,514.9
5,450.7
5,661.4
318.8
473.7
(1061.0)
253.1
6,707.0
5,646.0
5,733.0
321.4
479.0
(840.6)
249.2
6,782.6
5,942.0
5,749.4
325.9
481.3
(830.5)
244.7
6,801.3
5,970.9
5,809.5
313.7
479.3
(841.1)
247.0
6,849.5
6,008.5
6,010.4
312.6
475.1
(834.6)
249.2
7,047.4
6,212.7
5,927.1
287.6
474.9
(838.1)
246.6
6,936.2
6,098.1
Emissions by
Economic Sector
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 consistency with UNFCCC
reporting guidelines, it is also useful to allocate emissions
into more commonly used sectoral categories. This section
reports emissions by the following "economic sectors":
Residential, Commercial, Industry, Transportation, Electricity
Generation, and Agriculture, and U.S. Territories. Using this
categorization, emissions from electricity generation
accounted for the largest portion (33 percent) of U.S.
greenhouse gas emissions. 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 2001. 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
residential, agriculture, commercial economic sectors, and U.S.
territories contributed the remaining 21 percent of emissions.
Residences accounted for approximately 5 percent, and
primarily consisted of 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 non-
CO2 emissions. The commercial sector accounted for about 7
percent of emissions, while U.S. territories accounted for 1
percent of total emissions.
Carbon dioxide was also emitted and sequestered by a
variety of activities related to forest management practices,
tree planting in urban areas, the management of agricultural
soils, and landfilling of yard trimmings.
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 2001.
Figure 1-6
Emissions Allocated to Economic Sectors
Year
Note: Does not include U.S. Territories
Introduction 1-15
-------
Table 1-11: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg C02 Eq. and Percent of Total in 2001)
Sector/Source
1990
1995 1996 1997 1998 1999 2000 2001 Percent'
Electricity Generation
C02 from Fossil Fuel Combustion
Waste Combustion"
Transmission & Distribution1
Stationary Combustion"
Limestone and Dolomite Use
Transportation
C02 from Fossil Fuel Combustion
Mobile Combustion11
Substitution of ODSe
Industry
C02 from Fossil Fuel Combustion
Natural Gas Systems
Coal Mining
Iron and Steel Production
Cement Manufacture
Petroleum Systems
HCFC-22 Production'
Nitric Acid
Ammonia Manufacture
Lime Manufacture
Substitution of ODS"
Aluminum Production9
Stationary Combustion"
Semiconductor Manufacture6
Natural Gas Flaring
Adipic Acid
N20 Product Usage
Soda Ash Manufacture & ConsumptJor
Limestone and Dolomite Use
Magnesium Production & Processing0
Titanium Dioxide Production
Petrochemical Production
Ferroalloys
Carbon Dioxide Consumption
Silicon Carbide Production
Agriculture
Agricultural Soil Management
Enteric Fermentation
Manure Management"
C02 from Fossil Fuel Combustion
Rice Cultivation
Field Burning of Agricultural Residues"
Mobile Combustion"
Stationary Combustion"
Residential
C02 from Fossil Fuel Combustion
Substitution of ODSe
Stationary Combustion"
Continued on next page.
1,862.3
1,805.0
14.4
32.1
8.1
2.7
1,525.6
1,470.5
55.2
+
1,423.3
909.0
122.0
87.1
85.4
33.3
27.5
35.0
17.8
19.3
11.2
+
24.4
5.7
2.9
5.5
15.2
4.3
4.1
2.7
5.4
1.3
1.2
2.0
0.9
+
487.8
267.5
117.9
47.5
46.3
7.1
1.1
0.4
+
334.5
328.9
+
5.7
1,990.1
1,931.8
18.7
27.5
8.6
3.5
1,651,0
1,577.8
65.3
7.8
1,444.7
945.7
127,2
73.5
74.4
36.8
24.2
27.0
19.9
20.5
12.8
3.6
17.1
6.1
5.9
8.7
17.2
4.5
4.3
3.5
5.6
1.7
1.5
1.9
1.1
+
525.8
284.1
123.0
52.7
56.9
7.6
1.0
0.5
+
371.3
358.5
6.9
5.8
2,064 1
2,003.9
19.7
27.7
9.1
3.8
1,694.1
1,617.4
65.0
11.7
1,484.9
987.5
127.4
68.4
68.3
37.1
23.9
31.1
20.7
20.3
13.5
6.3
18.0
6.3
5.4
8.2
17.0
4.5
4.2
3.8
6.5
1.7
1.6
2.0
1.1
+
526.1
293.2
120.5
51.9
52.0
7.0
1.2
0.4
+
402.1
388.6
7.6
5.9
2,130.4
2,070.8
21.4
25.2
9.3
3.5
1,706.8
1,626.9
64.5
15.4
1,485.4
992.5
126.0
68.1
71.9
38.3
23.6
30.0
21.2
20.7
13.7
6.6
16.6
6.1
6.5
7.6
10.3
4.8
4.4
3.5
6.3
1.8
1.6
2.0
1.2
+
537.9
298.2
118.3
53.8
58.3
7.5
1.2
0.5
+
385.4
371.7
9.2
4.5
2,217.2
2,160.3
22.7
20.9
9.6
3.7
1,736.5
1,653.9
63.7
18.8
1,433.5
942.5
124.0
67.9
67.4
39.2
22.9
40.2
20.9
21.9
13.9
7.0
14.8
6.0
7.3
6.3
6.0
4.8
4.3
3.7
5.8
1.8
1.6
2.0
1.2
+
539.4
299.2
116.7
56.4
57.6
7.9
1.2
0.5
+
352.8
338.8
9.8
4.2
2,227.5
2,173.5
24.1
16.4
9.6
3.8
1,797.7
1,713.0
62.7
21.9
1,381.4
913.2
120.3
63.7
64.4
40.0
21.6
30.4
20.1
20.6
13.5
7.5
14.8
5.8
7.7
6.7
5.5
4.8
4.2
3.8
6.0
1.9
1.7
2.0
1.2
+
539.8
297.0
116.6
56.2
59.9
8.3
1.2
0.5
+
372.4
357.3
10.7
4.5
2,331.8
2,277.8
25.6
15.4
10.0
2.9
1,849.0
1,762.7
61.5
24.8
1,400.6
940.7
121.2
60.9
65.8
41.2
21.2
29.8
19.1
19.6
13.3
8.0
13.3
6.0
7.4
5.5
6.0
4.8
4.2
2.9
3.2
1.9
1.7
1.7
1.2
+
526.0
294.6
115.7
56.1
50.4
7.5
1.2
0.4
+
390.1
373.9
11.6
4.6
2,297.7
2,242.8
27.1
15.3
9.8
2.6
1,866.8
1,780.9
58.6
27.3
1,315.7
887.2
117.3
60.7
59.1
41.4
21.2
19.8
17.6
16.6
12.9
11.7
8.2
6.2
5.5
5.2
4.9
4.8
4.1
2.6
2.5
1.9
1.5
1.3
1.3
+
525.7
294.3
114.8
56.9
50.4
7.6
1.2
0.4
+
379.4
363.3
11.6
4.4
33.1%
32.3%
0.4%
0.2%
0.1%
+
26.9%
25.7%
0.8%
0.4%
19.0%
12.8%
1.7%
0.9%
0.9%
0.6%
0.3%
0.3%
0.3%
0.2%
0.2%
0.2%
0.1%
0.1%
0.1%
0.1%
0.1%
0.1%
0.1%
+
+
+
+
+
+
+
7.6%
4.2%
1.7%
0.8%
0.7%
0.1%
+
+
+
5.5%
5.2%
0.2%
0.1%
1-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table 1 -11: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg C02 Eq. and Percent of Total in 2001)
continued from page 1-16
Sector/Source
1990
1995 1996 1997 1998 1999 2000 2001 Percent3
Commercial
C02 from Fossil Fuel Combustion
Landfills
Wastewater Treatment
Human Sewage
Substitution of ODSe
Stationary Combustiond
U.S. Territories
C02 from Fossil Fuel Combustion
Total
Sinks
Forests
Urban Trees
Agricultural Soils
Landfilled Yard Trimmings
472.4
221,4
212.1
24.1
12.7
0.9
1-1
33.7
33.7
6,139.6
(1,072.8)
(982.7)
(58.7)
(13.3)
(18.2)
1 488-°
• 226'9
• 216-1
• 26'6
I 13'9
• 3-4
• 1-1
• 44-°
• 44'°
• 6'514'9
1(1,064.2)
I (979-°)
1 <58J)
I <14'9)
1 <11'6>
495.5
236.4
212.1
26.8
14.1
4.8
1.2
40.1
40.1
6,707.0
(1,061.0)
(979.0)
(58.7)
(13.6)
(9.7)
494.0
237.1
207.5
27.3
14.4
6.5
1.2
42.8
42.8
6,782.6
(840.6)
(759.0)
(58.7)
(13.9)
(9.0)
474.2
219.5
202.4
27.7
14.6
8.9
1.1
47.9
47.9
6,801.3
(830.5)
(751.7)
(58.7)
(11.5)
(8.7)
480.6
221.7
203.7
28.2
15.1
10.7
1.1
50.2
50.2
6,849.5
(841.1)
(762.7)
(58.7)
(11.9)
(7.8)
497.6
234.3
205.8
28.3
15.1
12.8
1.2
52.3
52.3
7,047.4
(834.6)
(755.3)
(58.7)
(13.8)
(6.9)
496.5
235.9
202.9
28.3
15.3
12.9
1.1
54.4
54.4
6,936.2
(838.1)
(759.0)
(58.7)
(15.2)
(5.3)
7.2%
3.4%
2.9%
0.4%
0.2%
0.2%
+
0.8%
0.8%
100.0%
(12.1%)
(10.9%)
(0.8%)
(0.2%)
(0.1%)
Net Emissions (Sources and Sinks) 5,066.8 |j
Note: Includes all emissions of C02, CH4, N20, HFCs,
Totals may not sum due to independent rounding.
ODS (Ozone Depleting Substances)
+ Does not exceed 0.05 Tg C02 Eq. or 0.05%.
- Not applicable.
a Percent of total emissions for year 2001.
" Includes both C02 and N20.
c SF6 emitted.
d Includes both CH4 and N20.
e May includes a mixture of HFCs, PFCs, and SF6.
1 HFC-23 emitted.
»Includes both C02 and PFCs.
I 5,450.7 5,646.0 5,942.0 5,970.9 6,008.5 6,212.7 6,098.1
PFCs, and SF6. Parentheses indicate negative values (or sequestration).
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). The
generation, transmission, and distribution of electricity,
which is the largest economic sector in the United States,
accounted for 33 percent of total U.S. greenhouse gas
emissions in 2001. Emissions increased by 23 percent since
1990, as electricity demand 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 1-12
provides a detailed summary of emissions from electricity
generation-related activities.
To distribute electricity emissions among economic 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 2002b and Duffield 2002). These three source
categories include CO2 from fossil fuel combustion, CH4 and
N2O from stationary sources, and SF6 from electrical
transmission and distribution.21
21 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 -12: Electricity Generation-Related Greenhouse Gas Emissions (Tg C02 Eq.)
Gas/Fuel Type or Source
C02
C02 from Fossil Fuel Combustion
Coal
Natural Gas
Petroleum
Geothermal
Waste Combustion
Limestone and Dolomite Use
CH4
Stationary Combustion*
N20
Stationary Combustion*
Waste Combustion
SF6
Electrical Transmission and Distribution
Total
1990
1,821.8
1,805.0
1,530.3
175.3
99.0
0.4
14.4
2.7
0.6
0.6
7.8
7.6
0.3
32.1
32.1
1,862.3
1995
1,953.8
1,931.8
1,643.4
228.3
59.7
0.4
18.7
3.5
0.6
0.6
8.3
8.0
0.3
27.5
27.5
1,990.1
1996
2,027.1
2,003.9
1,734.0
205.0
64.5
0.4
19.7
3.8
0.6
0.6
8.7
8.5
0.3
27.7
27.7
2,064.1
1997
2,095.5
2,070.8
1,778.1
218.9
73.5
0.4
21.4
3.5
0.6
0.6
9.0
8.7
0.3
25.2
25.2
2,130.4
1998
2,186.5
2,160.3
1,808.7
248.0
103.2
0.4
22.7
3.7
0.7
0.7
9.2
8.9
0.2
20.9
20.9
2,217.2
1999
2,201.2
2,173.5
1,817.5
260.1
95.6
0.4
24.1
3.8
0.7
0.7
9.2
8.9
0.2
16.4
16.4
2,227.5
2000
2,306.1
2,277.8
1,906.9
280.6
89.9
0.4
25.6
2.9
0.7
0.7
9.6
9.3
0.2
15.4
15.4
2,331.8
2001
2,272.3
2,242.8
1,856.8
284.9
100.7
0.4
27.1
2.6
0.7
0.7
9.4
9.1
0.2
15.3
15.3
2,297.7
Note: Totals may not sum due to independent rounding.
* Includes only stationary combustion emissions related to the generation of electricity.
When emissions from electricity are distributed among
these sectors, industry accounts for the largest share of
U.S. greenhouse gas emissions (30 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
Figure 1-7
Emissions with Electricity Distributed to Economic Sectors
Industrial
Note: Does not include U.S. Territories
agriculture, CO2 accounts for more than 75 percent of
greenhouse gas emissions, primarily from the combustion
of fossil fuels.
Table 1-13 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 2001.
Transportation
Transportation activities accounted for 27 percent of
U.S. greenhouse gas emissions in 2001. Table 1-14 provides
a detailed summary of greenhouse gas emissions from
transportation-related activities. Total emissions in Table
1-14 differ slightly from those shown in Table 1-13 primarily
because the table below includes all transportation activities,
including those that had been counted under the Agriculture
economic sector.
From 1990 to 2001, transportation emissions rose by
22 percent due, in part, to increased demand for travel and
the stagnation 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 30 percent from 1990 to 2001) and the gallons of
1-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table 1 -13: U.S Greenhouse Gas Emissions by "Economic Sector" and Gas with Electricity-Related Emissions
Distributed (Tg C02 Eq.) and Percent of Total in 2001
Sector/Gas
Industry
Direct Emissions
C02
CH4
N20
MFCs, PFCs, and SF6
Electricity-Related
C02
N204
SF8
Transportation
Direct Emissions
C02
CH4
N20
MFCs"
Electricity-Related
C02
N2d
SF
Residential
Direct Emissions
C02
CH4
N20
MFCs
Electricity-Related
C02
CH4
N20
SF
Commercial
Direct Emissions
C02
N2fj
HFCs
Electricity-Related
CH2
N2fj
SF.
Agriculture
Direct Emissions
C02
N2d
Electricity-Related
CH2
N204
S^s
U.S. Territories
C02
Total
1990
2,097.3
1,423.3
1,081.1
240.0
40.8
61.3
674.0
659.3
0.2
2.8
11.6
1,528.8
1,525.6
1,470.5
4.5
50.6
3.1
3.1
+
0.1
943.2
334.5
328.9
4.6
1.1
+
608.7
595.4
0.2
2.6
10.5
1,024.5
472.4
221.4
236.9
13.1
0.9
552.2
540.2
0.2
2.3
9.5
512.1
487.8
46.3
157.1
284.4
24.3
23.8
0.1
0.4
33.7
33.7
6,139.6
1995
2,164.0
1,444.7
1,116.6
229.0
45.3
53.9
719.3
706.2
0.2
3.0
9.9
1,654.1
1,651.0
1,577.8
4.4
60.9
7.8
3.1
3.0
+
+
1,019.5
371.3
358.5
4.7
1.2
6.9
648.3
636.4
0.2
2.7
9.0
1,080.7
488.0
226.9
243.5
14.3
3.4
592.7
581.8
0.2
2.5
8.2
552.6
525.8
56.9
167.6
301.4
26.8
26.3
+
0.1
0.4
44.0
44.0
6,514.9
1996
2,224.1
1,484.9
1,153.3
223.8
46.0
61.8
739.2
725.9
0.2
3.1
9.9
1,697.2
1,694.1
1,617.4
4.3
60.7
11.7
3.1
3.0
+
+
1,080.5
402.1
388.6
4.7
1.2
7.6
678.4
666.3
0.2
2.9
9.1
1,109.7
495.5
236.4
239.8
14.5
4.8
614.2
603.2
0.2
2.6
8.2
555.3
526.1
52.0
163.2
310.9
29.2
28.7
+
0.1
0.4
40.1
40.1
6,707.0
1997
2,244.7
1,485.4
1,163.1
221.8
40.0
60.5
759.3
746.9
0.2
3.2
9.0
1,710.0
1,706.8
1,626.9
4.2
60.3
15.4
3.1
3.1
+
+
1,073.8
385.4
371.7
3.6
1.0
9.2
688.4
677.2
0.2
2.9
8.2
1,150.9
494.0
237.1
235.7
14.8
6.5
656.9
646.2
0.2
2.8
7.8
560.4
537.9
58.3
163.3
316.3
22.5
22.2
+
0.1
0.3
42.8
42.8
6,782.6
1998
2,209.4
1,433.5
1,110.1
218.9
35.2
69.3
775.9
765.2
0.2
3.2
7.3
1,739.6
1,736.5
1,653.9
4.1
59.7
18.8
3.2
3.1
+
+
1,076.2
352.8
338.8
3.3
0.9
9.8
723.4
713.4
0.2
3.0
6.8
1,164.2
474.2
219.5
230.9
15.0
8.9
690.0
680.5
0.2
2.8
6.5
564.0
539.4
57.6
164.6
317.3
24.6
24.2
+
0.1
0.2
47.9
47.9
6,801.3
1999
2,165.0
1,381.4
1,077.4
209.6
33.9
60.6
783.6
774.3
0.2
3.2
5.8
1,800.9
1,797.7
1,713.0
4.0
58.8
21.9
3.2
3.2
+
+
1,095.5
372.4
357.3
3.5
0.9
10.7
723.1
714.5
0.2
3.0
5.3
1,177.7
480.6
221.7
232.7
15.4
10.7
697.1
688.9
0.2
2.9
5.1
560.3
539.8
59.9
164.7
315.2
20.5
20.3
+
0.1
0.2
50.2
50.2
6,849.5
2000
2,200.6
1,400.6
1,103.5
207.4
33.5
56.3
799.9
791.1
0.2
3.3
5.3
1,852.4
1,849.0
1,762.7
4.0
57.46
24.78
3.45
3.4
+
+
1,154.7
390.1
373.9
3.7
1.0
11.6
764.5
756.1
0.2
3.1
5.1
1,240.9
497.6
234.3
234.9
15.5
12.8
743.3
735.1
0.2
3.1
4.9
546.5
526.0
50.4
162.3
313.3
20.5
20.3
+
0.1
0.1
52.3
52.3
7,047.4
2001
2,074.0
1,315.7
1,037.6
203.2
31.1
43.7
758.4
750.0
0.2
3.1
5.1
1,870.5
1,866.8
1,780.9
3.9
54.75
27.35
3.62
3.6
+
+
1,138.7
379.4
363.3
3.5
0.9
11.6
759.3
750.9
0.2
3.1
5.1
1,252.6
496.5
235.9
232.1
15.6
12.9
756.1
747.8
0.2
3.1
5.0
546.0
525.7
50.4
162.2
313.1
20.3
20.0
+
0.1
0.1
54.4
54.4
6,936.2
Percent'
29.9%
19.0%
15.0%
2.9%
0.4%
0.6%
10.9%
10.8%
+
+
0.1%
27.0%
26.9%
25.7%
0.1%
0.8%
0.4%
0.1%
0.1%
+
•f
16.4%
5.5%
5.2%
0.1%
+
0.2%
10.9%
10.8%
+
+
0.1%
18.1%
7.2%
3.4%
3.3%
0.2%
0.2%
10.9%
10.8%
+
+
0.1%
7.9%
7.6%
0.7%
2.3%
4.5%
0.3%
0.3%
+
+
+
0.8%
0.3%
-
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 C02 Eq, or 0.05 percent.
a Percents for year 2001.
"Includes primarily HFC-134a.
Introduction 1-19
-------
Table 1-14: Transportation-Related Greenhouse Gas Emissions (Tg C02 Eq.)
Gas/Vehicle Type
HFCs
Mobile Air Conditioners8
Refrigerated Transport
Total
1990
C02
Passenger Cars
Light-Duty Trucks
Other Trucks
Buses
Alternative Fuel Vehicles
Aircraft3
Boats and Vessels
Locomotives
Other*
International Bunker Fuels'
CH4
Passenger Cars
Light-Duty Trucks
Other Trucks and Buses
Alternative Fuel Vehicles
Aircraft
Boats
Locomotives
Other"
International Bunker Fuels'
N20
Passenger Cars
Light-Duty Trucks
Other Trucks and Buses
Alternative Fuel Vehicles
Aircraft
Boats
Locomotives
Other*
International Bunker Fuels'
1,473.5
600.3
306.2
203.9
7.5
1.3
176.9
48.6
28.1
100.7
113.9
5.0
2.4
1.6
0.4
+
0.2
0.1
0.1
0.2
0.2
50.6
31.0
14.1
2.5
0.1
1.7
0.4
0.3
0.6
1.0
1,529.1
1995
1,580.9
587.2
392.9
237.0
7.9
1.2
171.4
51.7
30.8
100.7
101.0
4.9
2.0
1.9
0.4
+
0.1
0.1
0.1
0.2
0.1
60.9
33.4
21.1
3.2
0.1
1.7
0.5
0.3
0.6
0.9
7.8
6.7
1.2
1,654.5
1996
1,620.4
594.3
406.5
246.5
8.2
1.1
180.2
48.1
31.8
103.8
102.3
4.8
2.0
1.8
0.4
0.1
0.1
0.1
0.1
0.2
0.1
60.7
33.1
21.1
3.4
0.1
1.8
0.4
0.3
0.6
0.9
11.7
9.8
1.9
1,697.6
1997
1,630.0
592.8
419.1
257.6
8.3
1.1
179.0
33.6
31.6
107.0
109.9
4.7
2.0
1.7
0.4
0.1
0.2
0.1
0.1
0.2
0.1
60.3
32.6
21.1
3.6
0.1
1.7
0.3
0.3
0.6
1.0
15.4
12.9
2.5
1,710.4
1998
1,657.0
607.9
427.6
269.3
8.6
1.3
183.0
27.4
32.4
99.5
112.9
4.6
2.0
1.7
0.4
0.1
0.1
0.1
0.1
0.2
0.1
59.7
32.2
20.6
3.7
0.1
1.8
0.3
0.3
0.6
1.0
18.8
15.7
3.2
1,740.1
1999
1,716.2
618.6
446.1
284.2
9.6
1.1
186.8
38.6
34.1
97.1
105.3
4.5
1.9
1.6
0.4
0.1
0.2
0.1
0.1
0.2
0.7
58.8
31.2
20.4
3.8
0.2
1.8
0.4
0.3
0.6
0.9
21.9
18.2
3.8
1,801.4
2000
1,766.1
621.7
450.2
294.7
9.3
1.3
195.3
59.7
33.8
100.2
99.3
4.4
1.9
1.5
0.4
0.1
0.2
0.1
0.1
0.2
0.1
57.5
30.2
19.9
3.8
0.2
1.9
0.5
0.3
0.6
0.9
24.8
20.4
4.4
1,852.8
2001
1,784.4
632.7
460.0
298.3
8.6
1.2
183.9
58.3
34.3
107.2
97.3
4.3
1.8
1.5
0.4
0.1
0.1
0.1
0.1
0.2
0.1
54.8
28.7
18.9
3.8
0.2
1.8
0.3
0.3
0.7
0.9
27.3
22.5
4.9
1,870.8
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
a 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.
d "Other" CH4 and N20 emissions include motorcycles, construction equipment, agricultural machinery, industrial equipment, and snowmobiles.
e Includes primarily HFC-134a.
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 and road 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
1-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
for the remainder. The primary driver of transportation-
related emissions was CO2 from fossil fuel combustion, which
increased by 21 percent from 1990 to 2001. This rise in CO2
emissions, combined with increases of 27.3 Tg CO2 Eq. and
4.2 Tg CO2 Eq. in HFC and N2O emissions over the same
period, led to an increase in overall emissions from
transportation activities of 22 percent.
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 1996
IPCC Guidelines for National Greenhouse Gas Inventories
(IPCC/UNEP/OECD/IEA1997). To the extent possible, the
present report 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 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
Box 1-3: IPCC Good Practice Guidance
estimates for NOx, CO, and NMVOCs were taken directly,
except where noted, from EPA data published on the National
Emission Inventory (NEI) Air Pollutant Emission Trends web
site (EPA 2003), which provides the latest estimates of
regional and national emissions of local air pollutants.
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 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 (2003) 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.
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 (IPCC/UNEP/OECD/IEA 1997).
Carbon dioxide emissions from fuel combusted within U.S.
territories, however, are included in U.S. totals.
In response to a request by Parties to the United Nations Framework Convention on Climate Change (UNFCCC), the Intergovernmental
Panel on Climate Change (IPCC) prepared and published a report on inventory good practice. 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 and many other countries.22 It focuses on providing direction to countries to produce
emission estimates that are as accurate and transparent as possible, with the least possible uncertainty. In addition, Good Practice was
designed as a tool to complement the methodologies suggested in the Revised 1996 IPCC Guidelines for National Greenhouse Gas
Inventories (IPCC Guidelines).
In order to obtain these goals, Good Practice gives specific guidance in the following areas:
• Selection of the most appropriate estimation method, within the context of the IPCC Guidelines
• Implementation of quality control and quality assurance measures
• Proper assessment and documentation of data and information
• Quantification of uncertainties for each source category
By providing such direction, the IPCC hopes to help countries provide inventories that are transparent, documented, and comparable.
See
Introduction 1-21
-------
In order to aggregate emissions by economic sector,
source category emission estimates were generated according
to the methodologies outlined in the appropriate sections of
this report. 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 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) and fuel sales
data (EIA1991 through 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 accounted
for under the transportation end-use sector.
• Landfills, Wastewater Treatment and Human Sewage.
CH4 emissions from landfills and wastewater treatment,
as well as N2O emissions from human sewage, were
allocated to the commercial sector.
• Waste Combustion. CO2 and N2O emissions from waste
combustion were allocated completely to the electricity
generation sector since nearly all-waste combustion
occurs in waste-to-energy facilities.
• Limestone and Dolomite Use. CO2 emissions from
limestone and dolomite use are allocated to the electricity
generation (50 percent) and industrial (50 percent) sectors,
because 50 percent of the total emissions for this source
are used in flue gas desulfurization.
• 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 UNFCCC reporting guidelines 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
sources than those contained in that section of the Energy
chapter. 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 W). 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.
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 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 highly 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
UNFCCC reporting guidelines follow the recommendation
in the Revised 1996 IPCC Guidelines for National
Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA1997)
and 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.
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. This report uses the IPCC method-
1 -22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
ologies 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 X for a
discussion of the sources of greenhouse gas emissions
and sinks excluded from this report.
• 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 CH4
and N2O 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.
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.
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/
IE A 1997), this Inventory of U.S. Greenhouse Gas Emissions
and Sinks is segregated into six sector-specific chapters,
listed below in Table 1-15.
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 C02 from forest management, other land-use activities, and
land-use change.
Emissions from waste management activities.
Source: (IPCC/UNEP/OECD/IEA 1997)
Introduction 1-23
-------
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 in the emission estimates presented.
Special attention is given to CO2 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.
Table 1-16: List of Annexes
ANNEX A Methodology for Estimating Emissions of C02 from Fossil Fuel Combustion
ANNEX B Methodology for Estimating the Carbon Content of Fossil Fuels
ANNEX C Methodology for Estimating Carbon Stored in Products from Non-Energy Uses of Fossil Fuels
ANNEX D Methodology for Estimating Emissions of CH4, N20, and Ambient Air Pollutants from Stationary Combustion
ANNEX E Methodology for Estimating Emissions of CH4, N20, and Ambient Air Pollutants from Mobile Combustion and
Methodology for and Supplemental Information on Transportation-Related GHG Emissions
ANNEX F Methodology for Estimating CH4 Emissions from Coal Mining
ANNEX G Methodology for Estimating CH4 Emissions from Natural Gas Systems
ANNEX H Methodology for Estimating CH4 Emissions from Petroleum Systems
ANNEX I Methodology for Estimating C02 Emissions from Municipal Solid Waste Combustion
ANNEX J Methodology for Estimating Emissions from International Bunker Fuels used by the U.S. Military
ANNEX K Methodology for Estimating HFC and PFC Emissions from Substitution of Ozone Depleting Substances
ANNEX L Methodology for Estimating CH4 Emissions from Enteric Fermentation
ANNEX M Methodology for Estimating CH4 and N20 Emissions from Manure Management
ANNEX N Methodology for Estimating N20 Emissions from Agricultural Soil Management
ANNEX 0 Methodology for Estimating Net Changes in Forest Carbon Stocks
ANNEX P Methodology for Estimating Net Changes in Carbon Stocks in Mineral and Organic Soils
ANNEX Q Methodology for Estimating CH4 Emissions from Landfills
ANNEX R Key Source Analysis
ANNEX S Global Warming Potential Values
ANNEX T Ozone Depleting Substance Emissions
ANNEX U Sulfur Dioxide Emissions
ANNEX V Complete List of Source Categories
ANNEX W IPCC Reference Approach for Estimating C02 Emissions from Fossil Fuel Combustion
ANNEX X Sources of Greenhouse Gas Emissions Excluded
ANNEX Y Constants, Units, and Conversions
ANNEX I Abbreviations
ANNEX AA Chemical Formulas
ANNEX AB Glossary
1 -24 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
2. Energy
Energy-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 2001. This included 97,35, and 16 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 from fossil fuel combustion comprise the vast majority of energy-related emissions, with CO2 being the
primary gas emitted (see Figure 2-1). Globally, approximately 23,300 Tg 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).' Due to the relative importance of fossil fuel combustion-related CO2 emissions, they are considered separately, and
in more detail than other energy-related 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 Figure 2-1
as the production, transmission, storage, and distribution of
fossil fuels, also emit greenhouse gases. These emissions
consist primarily of fugitive CH4 from natural gas systems,
petroleum systems, and coal mining. Smaller quantities of
CO2, CO, NMVOCs, and NOx 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 during the consumption
of biomass 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 national totals under stationary and mobile combustion.
2001 Energy Chapter GHG Sources
Fossil Fuel Combustion
Natural Gas Systems
Mobile Sources
Coal Mining
Stationary Sources |
Waste Combustion |
Petroleum Systems |
Natural Gas Flaring |
15,615
Energy as a
Portion
of all Emissions
85.5%
20 40 60 80 100 120 140
Tg CQ, Eq.
' Global CO2 emissions from fossil fuel combustion were taken from Marland et al. (2002) .
Energy 2-1
-------
Table 2-1 summarizes emissions for the Energy chapter
in units of teragrams of CO2 equivalents (Tg CO2 Eq.), while
unweighted gas emissions in gigagrams (Gg) are provided
in Table 2-2. Overall, emissions due to energy-related
activities were 5,927.1 Tg CO2 Eq. in 2001, an increase of 15
percent since 1990.
Table 2-1: Emissions from Energy (Tg C02 Eq.)
Gas/Source
1990
1995
1996
1997
1998
1999
2000
2001
C02
Fossil Fuel Combustion
Waste Combustion
Natural Gas Flaring
Biomass-Wood*
International Bunker Fuels*
Biomass-Ethanol*
Carbon Stored in Products*
CH4
Natural Gas Systems
Coal Mining
Petroleum Systems
Stationary Combustion
Mobile Combustion
International Bunker Fuels*
N20
Mobile Combustion
Stationary Combustion
Waste Combustion
International Bunker Fuels*
Total
* These values are presented for
Note: Totals may not sum due to
4,834.3 ||1
4,814.8 •
14.1 •
5.5 •
175.0 •
113.9 if
4.4 •
214.5 •
249.7 •
122.0 •
87.1 flf
27.5 •
8.1 •
5.0 •
0.2 Iff
63.4 •
50.6 •
12.5 •
0.3 •
1-0 H
5,147.5 ll
informational purposes
independent rounding.
5,168.7
5,141.5
18.5
8.7
193.3
101.0
8.1
238.1
238.4
127.2
73.5
24.2
8.5
4.9
0.1
74.4
60.9
13.2
0.3
0.9
5,481.6
only and are
5,353.4
5,325.8
19.4
8.2
197.1
102.3
5.8
240.9
233.2
127.4
68.4
23.9
8.7
4.8
0.1
74.8
60.7
13.8
0.3
0.9
5,661.4
not included
5,428.8
5,400.0
21.2
7.6
176.6
109.9
7.4
249.7
229.9
126.0
68.1
23.6
7.5
4.7
0.1
74.3
60.3
13.7
0.3
1.0
5,733.0
or are already
5,449.2
5,420.5
22.5
6.3
173.8
112.9
8.1
258.5
226.6
124.0
67.9
22.9
7.2
4.6
0.1
73.6
59.7
13.7
0.2
1.0
5,749.4
accounted
5,519.4
5,488.8
23.9
6.7
176.6
105.3
8.5
271.9
217.4
120.3
63.7
21.6
7.4
4.5
0.1
72.7
58.8
13.7
0.2
0.9
5,809.5
for in totals.
5,723.0
5,692.2
25.4
5.5
180.3
99.3
9.7
263.6
215.4
121.2
60.9
21.2
7.6
4.4
0.1
72.0
57.5
14.3
0.2
0.9
6,010.4
5,646.9
5,614.9
26.9
5.2
173.4
97.3
10.2
252.8
211.0
117.3
60.7
21.2
7.4
4.3
0.1
69.2
54.8
14.2
0.2
0.9
5,927.1
Table 2-2: Emissions from Energy (Gg)
Gas/Source
1990
1995
1996
1997
1998
1999
2000
2001
C02
Fossil Fuel Combustion
Waste Combustion
Natural Gas Flaring
Biomass-Wood*
International Bunker Fuels*
Biomass-Ethanol*
4,834,340 j
4,814,758
14,068 1
5,514 I
174,991 j
113,863 I
4,380
Carbon Stored in Products* 214,454 1
CH4
Natural Gas Systems
Coal Mining
Petroleum Systems
Stationary Combustion
Mobile Combustion
International Bunker Fuels*
N20
Mobile Combustion
Stationary Combustion
Waste Combustion
International Bunker Fuels*
11,891
5,810 1
4,149 I
1,309
388
236
8
205 )
163 I
40 1
1
3 I
•
• 5,168,749
I 5,141,548
1 18>472
1 8<729
1 193-333
I 101'037
1 8'°"
I 238-061
1 11>352
I 6-059
I 3-502
I 1'153
I 406
I 232
1 6
I 240
1 197
1 43
1 1
1 3
5,353,449
5,325,798
19,418
8,233
197,104
102,272
5,809
240,891
11,105
6,069
3,255
1,138
415
227
6
241
196
45
1
3
5,428,772
5,400,034
21,173
7,565
176,589
109,858
7,356
249,693
10,949
6,001
3,244
1,123
358
223
7
240
195
44
1
3
5,449,223
5,420,519
22,454
6,250
173,822
112,859
8,128
258,475
10,788
5,903
3,235
1,090
342
217
7
237
192
44
1
3
5,519,386
5,488,804
23,903
6,679
176,589
105,262
8,451
271,894
10,354
5,728
3,033
1,029
351
214
6
234
190
44
1
3
5,723,047
5,692,170
25,351
5,525
180,321
99,268
9,667
263,646
10,258
5,772
2,902
1,010
363
211
6
232
185
46
1
3
5,646,940
5,614,853
26,907
5,179
173,426
97,346
10,226
252,772
10,049
5,588
2,893
1,011
353
204
5
223
177
46
1
3
* These values are presented for informational purposes only and are not included or are already accounted for in totals.
Note: Totals may not sum due to independent rounding.
2-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Figure 2-2
2001 U.S. Fossil Carbon Flows (Tg C02 Eq.)
(Tg C02 Eq.)
Natural Gas uauids.
Liquefied Refinery Gas,
& Other Liquids
185 ^
Petroleum
1,659
Fossil Fuel N0unsfuesr9y
Stock Consumption
Non-Energy Changes U.S.
Use Imports 133 Territories
47 32
Fossil Fuel
Combustion
Residual
(Not Oxidized
Fraction)
50
17
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
N6 = Natural Gas
Carbon Dioxide Emissions
from Fossil Fuel Combustion
Carbon dioxide emissions from fossil fuel combustion
have declined for the first time since 1991, decreasing by 1.4
percent from 2000 to 2001. The primary reason for this
reduction is due to slow growth of the U.S. economy and a
decline in manufacturing output, which reduced overall
demand for fuels. In 2001, CO2 emissions from fossil fuel
combustion were 5,614.9 Tg CO2 Eq., or 16.6 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, in 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,
there would likely be 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 aggregate societal
trends 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 also depend on the source of
energy and its carbon intensity. The amount of carbon in
fuels varies significantly by fuel type. For example, coal
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: C02 Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg C02 Eq.)
Fuel/Sector 1990 •
Coal 1,697.3 •
Residential 2.5 ||1|
Commercial 12.3
Industrial 151.6 |j|
Transportation NE
Electricity Generation 1,530.3
U.S. Territories 0.6 ^B
Natural Gas 1,012.5 f|j
Residential 238.8 |||
Commercial 142.6 H|
Industrial 419.9 |||
Transportation 35.9
Electricity Generation 175.3
U.S. Territories NO •
Petroleum 2,104.5 •
Residential 87.6 i||f
Commercial 66.6 |i|
Industrial 383.7 1||
Transportation 1,434.6 »|
Electricity Generation 99.0 j|l
U.S. Territories 33.1 •
Geothermal* 0.4 •
Total 4,814.8
NE (Not estimated)
NO (Not occurring)
1995
1,805.8
1.6
11.1
148.8
NE
1,643.4
0.9
1,172.6
263.0
164.3
478.8
38.2
228.3
NO
2,162.7
94.0
51.4
374.9
1,539.6
59.7
43.1
0.4
5,141.5
* Although not technically a fossil fuel, geothermal energy-related C02
Note: Totals may not sum due to independent rounding.
Figure 2-3
2001 U.S. Energy Consumption by Energy Source
15.8% Renewable
8.3% Nuclear
22.6% Coal
23.9%
Natural Gas
139.3%
Petroleum
Source: Annual Energy Review 2001, EIA (2002a), Table 1
3
1996 1997 1998 1999 2000 2001
1,893.4 1,939.1 1,957.3 1,961.1 2,051.5 1,993.8
1.6 1.5 1.2 1.3 1.1 1.1
11.5 12.1 8.7 9.7 8.6 8.6
145.3 146.4 137.8 131.7 134.0 126.3
NE NE NE NE NE N
1,734.0 1,778.1 1,808.7 1,817.5 1,906.9 1,856.8
0.9 0.9 0.9 0.9 0.9 0.9
1,193.9 1,200.3 1,177.2 1,183.8 1,240.3 1,202.1
284.2 270.2 246.5 256.5 270.3 260.8
171.3 174.3 163.5 165.2 174.3 175.8
494.6 495.8 484.1 466.4 478.9 445.5
38.9 41.1 35.1 35.6 35.5 33.9
205.0 218.9 248.0 260.1 280.6 284.9
NO NO NO NO 0.6 1.2
2,238.2 2,260.3 2,285.6 2,343.6 2,400.0 2,418.6
102.8 100.0 91.1 99.5 102.4 101.4
53.6 50.6 47.2 46.7 51.4 51.4
399.6 408.6 378.2 375.0 378.2 365.8
1,578.5 1,585.8 1,618.8 1,677.5 1,727.3 1,747.0
64.5 73.5 103.2 95.6 89.9 100.7
39.1 41.8 47.0 49.3 50.8 52.3
0.4 0.4 0.4 0.4 0.4 0.4
5,325.8 5,400.0 5,420.5 5,488.8 5,692.2 5,614.9
emissions are included for reporting purposes.
contains 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 Producing a unit of heat or electricity using natural
gas instead of coal can reduce the CO2 emissions associated
with energy consumption, and using nuclear or renewable
energy sources (e.g., wind) can essentially eliminate
emissions (see Box 2-2).
In the United States, 86 percent of the energy consumed
in 2001 was produced through the combustion of fossil fuels
such as coal, natural gas, and petroleum (see Figure 2-3 and
Figure 2-7). The remaining portion was supplied by nuclear
electric power (8 percent) and by a variety of renewable
energy sources (6 percent), primarily hydroelectric power
(EIA 2002a). Specifically, petroleum supplied the largest
share of domestic energy demands, accounting for an average
3 Based on national aggregate carbon content of all coal, natural gas, and petroleum fuels combusted in the United States.
2-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Box 2-1: Weather and Non-Fossil Energy Effects on C02 from Fossil Fuel Combustion Trends
After a fairly typical year in 2000, weather conditions became warmer in 2001. The warmer winter conditions led to decreased demand
for heating fuels, while a warmer summer increased electricity demand for air conditioning in the residential and commercial sectors. Heating
degree days in the United States in 2001 were 8 percent below normal (see Figure 2-4) while cooling degree days in 2001 were 7 percent
above normal (see Figure 2-5).4
Although no new U.S. nuclear power plants have been constructed in recent years, the utilization (i.e., capacity factors5) of existing
plants reached record levels in 2001, approaching 90 percent. This increase in utilization translated into an increase in electricity output by
nuclear plants of approximately 2 percent in 2001. This output by nuclear plants, however, was more than offset by reduced electricity
output by hydroelectric power plants, which declined by almost 23 percent. Electricity generated by nuclear plants in 2001 provided
approximately 3.5 times as much of the energy consumed in the United States as hydroelectric plants. Nuclear and hydroelectric power
plant capacity factors since 1973 are shown in Figure 2-6.
Figure 2-4
Annual Deviations from Normal Heating Degree Days for the United States (1949-2001)
"II
II
Normal
(4,576 Heating Degree Days)
Annual Deviations from Normal Cooling Degree Days for the United States (1949-2001)
Note: Climatological normal data are highlighted. Statistical confidence interval for "normal" climatology period of 1961 through 1990.
Source: NOAA (2002)
Figure 2-5
Annual Deviations from Normal Cooling Degree Days for the United States (1949-2001)
Normal
(1,193 Cooling Degree Days)
Annual Deviations from Normal Cooling Degree Days for the United States (1949-2001)
Note: Climatological normal data are highlighted. Statistical confidence interval for "normal" climatology period of 1961 through 1990.
Source: NOAA (2002)
4 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).
5 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 200 Ib).
Energy 2-5
-------
Box 2-1: Weather and Non-Fossil Energy Effects on
C02 from Fossil Fuel Combustion Trends (Continued)
Figure 2-6
Aggregate Nuclear and Hydroelectric Power Plant
Capacity Factors in the United States (1973-2001)
100
O) r- CO IO Is- O)
CO 00 0) O> O) O) O)
O) O> O O) CT> O) O)
Source: Annual Energy Review, EIA (2002a), Table 9.2
of 39 percent of total energy consumption from 1990 through
2001. Natural gas and coal followed in order of importance,
accounting for 24 and 23 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. Natural gas broadly
consumed in all end-use sectors except transportation (see
Figure 2-8) (EIA 2002a).
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 CH4, CO, and NMVOCs.6 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,
except for the soot and 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/
IE A 1997) recommends 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.
Figure 2-7
U.S. Energy Consumption (Quadrillion Btu)
^ 120
§ 100
io
CD
O
nsumpti
O>
O
Co
*>
O
rgy
S
Total Energy
Renewable
& Nuclear
Note: Expressed as gross calorific values.
Source: Annual Energy Review 2001, EIA (2002a), Table 1.3
6 See the sections entitled Stationary Combustion and Mobile Combustion in this chapter for information on non-CO2 gas emissions from
fossil fuel combustion.
2-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Figure 2-8
2001 C02 Emissions from Fossil Fuel Combustion by
Sector and Fuel Type
• Natural Gas v Petroleum
Relative Contribution
by Fuel Type
I Coal
Note: The electricity generation sector also includes emissions of
less than 0.01 Tg C02 Eq. from geothermal-based generation
According to the UNFCCC reporting guidelines, CO2
emissions from the consumption of fossil fuels for aviation
and marine international transport activities (i.e., international
bunker fuels) should 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.
End-Use Sector Consumption
An alternative method of presenting CO2 emissions is
to allocate emissions associated with electricity generation
to the sectors in which it is used. Four end-use sectors
were defined: industrial, transportation, residential, and
commercial.7 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 summari/e CO2 emissions from direct fossil fuel
combustion and pro-rated electricity generation emissions
from electricity consumption by end-use sector.
Table 2-4: Fossil Fuel Carbon in Products (Tg C02 Eq.)*
Sector 1990 1995
Industrial
Transportation
Territories
Total
214.5
1996
1997 1998
1999 2000 2001
235.9
1.2
1.0
238.1
238.3
1.1
1.5
240.9
247.0
1.2
1.6
249.7
255.7
1.2
1.5
258.5
268.9
1.2
1.8
271.9
260.6
1.2
1.8
263.6
249.7
1.1
1.9
252.8
* 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 Emissions from International Bunker Fuels (Tg C02 Eq.)4
Vehicle Mode
1990
1995
Aviation
Marine
Total
1996
1997 1998
1999 2000 2001
52.2
50.1
55.9
54.0
55.0
57.9
58.8
46.4
58.4
40.9
113.9
102.3
109.9 112.9
105.3 99.3
* See International Bunker Fuels section for additional detail.
Note: Totals may not sum due to independent rounding.
58.9
38.5
97.3
7 See Glossary (Annex AB) for more detailed definitions of the industrial, residential, commercial, and transportation end-use sector, as well
as electricity generation.
Energy 2-7
-------
Table 2-6: C02 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg C02 Eq.)
End-Use Sector 1990 1995 1996 1997 1998
Industrial
Combustion
Electricity
Transportation
Combustion
Electricity
Residential
Combustion
Electricity
Commercial
Combustion
Electricity
U.S. Territories
Total
Electricity Generation
1999 2000 2001
1,632.1
955.3
676.8
1,473.5
1,470.5
3.0
918.8
328.9
589.9
756.6
221.4
535.2
33.7
4,814.8
1,805.0
1,710.3
1,002.6
707.7
1,580.9
1,577.8
3.0
996.4
358.5
637.8
810.0
226.9
583.1
44.0
1,767.4
1,039.5
727.9
1,620.4
1,617.4
3.0
1,056.6
388.6
668.1
841.2
236.4
604.8
40.1
1,796.8
1,050.8
746.0
1,630.0
1,626.9
3.1
1,048.0
371.7
676.4
882.5
237.1
645.4
42.8
1,764.6
1,000.1
764.5
1,657.0
1,653.9
3.1
1,051.6
338.8
712.8
899.4
219.5
679.9
47.9
1,744.8
973.2
771.7
1,716.2
1,713.0
3.2
1,069.4
357.3
712.1
908.2
221.7
686.5
50.2
1,779.5
991.1
788.4
1,766.1
1,762.7
3.4
1,127.3
373.9
753.5
966.9
234.3
732.6
52.3
1,684.5
937.7
746.8
1,784.4
1,780.9
3.6
1,111.1
363.3
747.8
980.5
235.9
744.6
54.4
5,141.5 5,325.8 5,400.0 5,420.5 5,488.8 5,692.2 5,614.9
1,931.8 2,003.9 2.070.8 2.160.3 2,173.5 2,277.8 2,242.8
Note: Totals may not sum due to independent rounding. Emissions from fossil fuel combustion by electricity generation are allocated based on
aggregate national electricity consumption by each end-use sector.
Figure 2-9
2001 End-Use Sector Emissions of C02 from
Fossil Fuel Combustion
2 000 -i
i!soo-
1 ,600 -
1 ,400 -
1 ,200 -
1 ,000 -
800-
600-
400-
200-
0J
From Electricity
Consumption
I From Direct Fossil
Fuel Combustion
.jr
Transportation End-Use Sector
The transportation end-use sector accounted for the
largest share (approximately 32 percent) of CO2 emissions
from fossil fuel combustion.8 Almost all of the energy
consumed in the transportation sector was petroleum-
based, with nearly two-thirds being 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 21 percent from 1990 to
2001, to 1,784.4 Tg CO2 Eq. The growth in transportation
end-use sector emissions has been relatively steady,
including a 1.0 percent single year increase in 2001. 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). 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 rose
in 2000 to levels not seen since 1990, though they decreased
slightly in 2001 (see Figure 2-10). Despite unfavorable
economic conditions, demand for transportation fuel in 2001
increased from 2000 levels. Since 1990, travel activity in the
United States has grown more rapidly than population, with a
14 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
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 AB) for a more detailed definition of the transportation end-use sector.
2-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
1977 (FHWA1996 through 2002). 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-seven percent of the
emissions from this end-use sector in 2001 were the result of
the combustion of motor gasoline in passenger cars and
light-duty trucks. Diesel highway vehicles and jet aircraft
were also significant contributors, accounting for 16 and 13
percent of CO2 emissions from the transportation end-use
sector, respectively.10
Industrial End-Use Sector
The industrial end-use sector accounted for 30 percent of
CO2 emissions from fossil fuel combustion. On average, 56 percent
of these emissions resulted from the direct consumption of fossil
fuels for steam and process heat production. The remaining 44
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 (EIA1997).
Just six industries—Petroleum, Chemicals, Primary Metals, Pulp
and Paper, Food, and Stone, Clay, and Glass products—represent
83 percent of total manufacturing energy use.
In theory, emissions from the industrial end-use sector
should be highly correlated with economic growth and
industrial output, but 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.
Figure 2-10
Motor Gasoline Retail Prices (Real)
180 -
60 J
1972 1976 1980 1984 1988 1992 1996 2000
Source for gasoline prices: Annual Energy Review 2001, EIA
(2002a), Table 5.22
Source for motor vehicle fuel efficiency: FHWA (1996
through 2002)
Figure 2-11
Motor Vehicle Fuel Efficiency
10 J
1972 1976 1980 1984 1988 1992 1996 2000
Source: FHWA (1996 through 2002)
10 These percentages include emissions from bunker fuels.
11 See Glossary (AnnexAB) for a more detailed definition of the industrial end-use sector.
12 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 2-9
-------
Table 2-7: C02 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg C02 Eq.)
Fuel/Vehicle Type
1990
1995
1996
1997 1998 1999 2000 2001
1,023.0
582.4
381.3
37.1
1.0
1.7
9.2
8.0
2.4
311.9
4.9
11.6
199.9
6.9
30.2
12.3
25.0
11.9
9.1
219.9
121.4
24.1
5.3
17.9
51.1
2.7
2.7
71.0
30.2
40.8
38.2
0.1
0.1
38.0
1.0
0.5
0.5
1,041.4
589.6
394.3
36.1
0.9
1.7
8.5
7.9
2.4
328.9
4.7
12.2
210.4
7.3
31.2
15.0
26.3
13.4
8.3
229.8
124.9
23.1
5.8
23.9
52.2
2.6
2.6
66.4
24.6
41.8
38.9
+
0.1
38.7
0.9
0.4
0.5
1,050.6
588.2
406.0
34.7
0.7
1.7
8.4
8.4
2.5
342.4
4.6
13.1
222.9
7.6
30.9
14.6
26.0
13.6
9.1
232.1
129.4
21.0
6.1
19.7
55.9
2.7
2.7
55.5
10.6
44.9
41.1
+
0.2
40.9
0.8
0.4
0.4
1,072.5
603.5
414.2
34.6
0.7
1.7
8.1
7.7
2.0
355.6
4.4
13.4
234.7
7.9
31.7
13.1
24.4
14.4
11.5
235.6
131.4
21.5
7.7
19.9
55.0
2.4
2.4
52.6
6.2
46.4
35.1
+
0.2
34.9
1.0
0.4
0.6
1,098.7
614.2
431.7
33.7
0.7
1.8
9.3
5.9
1.5
373.5
4.4
14.4
250.5
9.0
33.4
15.6
23.5
14.4
8.2
242.9
137.3
20.6
9.2
17.0
58.8
2.7
2.7
51.9
13.7
38.2
35.6
+
0.3
35.3
0.8
0.3
0.5
1,105.7
617.5
435.7
33.4
0.6
1.8
9.6
5.6
1.6
385.1
4.1
14.6
261.3
8.7
33.1
15.5
25.7
15.9
6.2
251.2
141.0
21.0
9.5
21.4
58.4
2.5
2.5
69.2
34.6
34.6
35.5
+
0.4
35.0
0.8
0.3
0.5
1,129.3
628.8
445.2
32.4
0.5
1.6
9.5
6.9
4.4
394.1
3.9
14.8
265.9
8.1
33.5
16.8
28.3
17.6
5.2
240.4
131.6
22.8
9.3
17.8
58.9
2.4
2.4
65.2
32.0
33.2
33.9
+
0.4
33.5
0.8
0.3
0.5
Gasoline 955.3
Automobiles 594.0
Light Trucks 297.3
Other Trucks 39.8
Buses 1.6
Motorcycles 1.7
Boats (Recreational) 11.2
Agricultural Equipment 7.0
Construction Equipment 2.7
Distillate Fuel Oil (Diesel) 277.3
Automobiles 6.3
Light-Duty Trucks 8.9
Other Trucks 164.2
Buses 5.8
Locomotives 27.5
Ships & Boats 14.0
Agricultural Equipment 26.1
Construction Equipment 13.1
Ships (Bunkers) 11.4
Jet Fuel 220.4
Commercial Aircraft 118.2
Military Aircraft 34.8
General Aviation Aircraft 6.3
Other Aircraft3 14.6
Aircraft (Bunkers) 46.6
Aviation Gasoline 3.1
General Aviation Aircraft 3.1
Residual Fuel Oil 79.2
Locomotives +
Ships & Boats" 23.4
Ships (Bunkers)" 55.8
Natural Gas 35.9
Automobiles +
Light Trucks +
Buses +
Pipeline 35.9
LPG 1.3
Light Trucks 0.5
Other Trucks 0.8
Buses +
Electricity 3.0
Buses +
Locomotives & Transit Cars 0.6
Pipeline 2.4
Lubricants 11.7
Total (Including Bunkers)0 1,587.3
Total (Excluding Bunkers)" 1,473.5
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
a Including but not limited to fuel blended with heating oils and fuel used for chartered aircraft flights.
6 Fluctuations in emission estimates from the combustion of residual fuel oil are currently unexplained, but may be related to data collection
problems.
c Official 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.
3.0
3.0
3.1
3.1
3.2
3.4
3.6
0.6
2.4
11.2
1,681.9
1,580.9
0.6
2.4
10.9
1,722.7
1,620.4
0.7
2.4
11.5
1,739.9
1,630.0
0.6
2.5
12.0
1,769.9
1,657.0
0.7
2.5
12.1
1,821.5
1,716.2
0.7
2.7
12.0
1,865.4
1,766.1
0.8
2.8
12.1
1,881.8
1,784.4
2-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
From 2000 to 2001, total industrial production and
manufacturing output were reported to have decreased by
3.9 and 4.4 percent, respectively (FRB 2002). Output declined
in all six of the aforementioned industries that account for
the majority of energy use in manufacturing. The largest
declines were in the Primary Metals (-11.4 percent) and Pulp
and Paper industries (-5.1 percent) (see Figure 2-12).
Despite the growth in industrial output (42 percent) and the
overall U.S. economy (37 percent) from 1990 to 2001, emissions
from the industrial end-use sector increased only slightly (by 3
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. Carbon dioxide emissions
from fossil fuel combustion and electricity use within the industrial
end-use sectors were 1,684.5 Tg CO2 Eq. in 2001.
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
17 percent between 1990 and 2001, to 249.7 Tg CO2 Eq.13
Residential and Commercial End-Use Sectors
The residential and commercial end-use sectors accounted
for an average 20 and 17 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 67 and 76 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
Figure 2-12
Industrial Production Indexes (Index 1992=100)
140 -
120 -
100
80 J
Total Industrial
Index
— Total Index excluding
Computers, Communications
Equip., and Semiconductors
Chemicals & Products
Petroleum Products
Source: FRB (2002)
component of energy use in both these end-use sectors. In
2001, CO2 emissions from fossil fuel combustion and electricity
use within the residential and commercial end-use sectors were
1,111.1 Tg CO2 Eq. and 980.5 Tg CO2 Eq., respectively.
Since 1990, emissions from residences and commercial
buildings have increased steadily, unlike those from the
industrial sector, which experienced sizeable reductions
during the economic downturns of 1991 and 2001 (see Table
2-6). This difference exists because short-term fluctuations
in energy consumption in these sectors are correlated more
with 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).
A number of contrasting trends influenced emissions in
2001. Emissions from residential natural gas consumption actually
decreased by 4 percent, due, in part, to warmer winter weather.
13 See the Carbon Stored in Products in Non-Energy Uses of Fossil Fuels for a more detailed discussion. Also, see Waste Combustion in the
Waste chapter for a discussion of emissions from the incineration or combustion of fossil fuel-based products.
Energy 2-11
-------
Winter conditions in the United States were warmer than normal
in 2001 (heating degree days were 8 percent below normal), and
slightly warmer than conditions in 2000 (see Figure 2-13).
Electricity sales to the residential and commercial end-
use sectors in 2001 increased by 1 and 3 percent, respectively.
Hotter summer conditions in 2001 are partially responsible for
this trend, due to increased air-conditioning related electricity
consumption (see Figure 2-14). However, other factors such
as growth in personal income and population are also
important drivers of emissions from these sectors.
Although the residential and commercial sector usually
exhibit similar emission trends, total emissions from the
commercial end-use sector increased by 1.4 percent, while
emissions from the residential sector decreased by 1.4 percent
in 2001. This occurred despite an increase in electricity
consumption from both sectors. The reason for the opposing
trends in these two sectors is mainly due to 1) strong
commercial development in 2001 (EIA 2002d), and 2) the nature
of energy use in each sector. The reduction in emissions from
the residential sector results from a combination of lower
natural gas consumption and a modest increase in electricity
use. The residential sector consumes a much higher proportion
of natural gas for its energy needs, and due to higher natural
gas prices and a warmer winter, consumed a lesser amount of
natural gas. Consumption of electricity in the residential sector
is much more price-sensitive due to the individual choices by
Figure 2-13
consumers. For the first time since the early 1980's, the retail
price of residential electricity increased, causing consumers
to moderate their electricity usage to a relatively modest 1
percent growth. The commercial sector is much more reliant
on electricity to meet energy needs, and had to consume a
higher amount of electricity for air conditioning during the
hotter summer of 2001.
Electricity Generation
The process of generating electricity is the single
largest source of CO2 emissions in the United States (39
percent). Electricity was consumed primarily in the
residential, commercial, and industrial end-use sectors
for 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 40 percent in 2001.
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
Figure 2-14
Heating Degree Days 14 H
^ 120-
o"
¥ 110-
co
O lUU -
z,
SS 90;
•o <
80.
1
Normal
(4,576 Heating Degree Days)
i f
3i-cvico*j-incofvcoo>Oi-
gOOOO0)O0)G)OO
9O)d)0)G)O)0)O)OO
Note: Excludes Alaska and Hawaii
Source: Annual Energy Review, EIA (2002a), Table 1.7
§ 120 -
jF
1 <
o 100 -
z
"x" 90 -
O)OO)0>O)OOO
3) O) O) O) O) O) O) O) O) 0) O O
jdes Alaska and Hawaii
inual Energy Review, EIA (2002a), Table 1.8
14 Degree days are relative measurements of outdoor air temperature. Heating degree days are deviations of the mean daily temperature
below 65° F. Excludes Alaska and Hawaii. Normals are based on data from 1961 through 1990.
15 Degree days are relative measurements of outdoor air temperature. 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.
2-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Figure 2-15
Electricity Generation Retail Sales by End-Use Sector
1,400 -
1,200-
> 1,000-
2
O 800
OQ
600-
Residential
Industrial
Commercial
400
1972 1976 1980 1984 1988 1992 1996 2000
Note: The transportation end-use sector consumes minor quantities
of electricity.
Source: Annual Energy Review, EIA (2002a), Table 8.5
customers). However, the electric power industry in the
United States has been undergoing significant changes as
both Federal and State government agencies have modified
regulations to create a more competitive market for electricity
generation. These changes have led to the growth of
nonutility power producers, including the sale of generating
capacity by electric utilities to nonutilities. Due to this
restructuring, the distinction between utilities and non-utilities
has become much less meaningful. As a result, the Department
of Energy no longer categorizes electric power generation
into these ownership groups, and is instead using two new
functional categories: electricity-only and combined-heat-and-
power. Electricity-only plants are those that solely produce
electricity, whereas combined-heat-and-power plants produce
both electricity and heat.16
In 2001, CO2 emissions from electricity generation
decreased by 1.5 percent relative to the previous year,
coinciding with decreased electricity consumption and a
slowly growing U.S. economy. An additional factor
contributing to the decrease in emissions was the power
crisis in California. Emissions decreased despite a reduction
in the volume and share of generation of electricity from
renewable resources, including a 24 percent reduction in
output from hydroelectric dams, which was replaced by
additional fossil fuel consumption to produce electricity.
The overall carbon intensity from energy consumption for
electricity generation increased (see Table 2-9) as a result.
Coal is consumed primarily by the electric power
sector in the United States, which accounted for 90
percent of total coal consumption for energy purposes in
2001. Consequently, changes in electricity demand have
a significant impact on coal consumption and associated
U.S. CO2 emissions. Coal consumption for electricity
generation decreased by 2.6 percent in 2001, due to a
reduction in electricity demand and fuel-switching from
coal to natural gas and petroleum, which increased
consumption of both fuels.
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 (IPCC/UNEP/OECD/IEA1997). 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.
Total fossil fuel consumption for each year is estimated
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.). The United States
does not include territories in its national energy
statistics, so fuel consumption data for territories were
collected separately.17 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 they were actually consumed
during non-energy related industrial activity. 18
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
16 Refer to Appendix H in EIA's Annual Energy Review 2001 for a more detailed explanation of recent changes in the U.S. electric power
sector and the new classification system.
17 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.
18 See sections on Iron and Steel Production, Ammonia Manufacture, Titanium Dioxide Production, Ferroalloy Production, and Aluminum
Production in the Industrial Processes chapter.
Energy 2-13
-------
Box 2-2: Carbon Intensity of U.S. Energy Consumption
Fossil fuels are the dominant source of energy in the United States, and 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.19
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 from the combustion of fossil fuels is dependent upon the carbon content of the fuel and the fraction of that carbon that is oxidized.20
Fossil fuels vary in their average carbon content, ranging from about 53 Tg C02 Eq./QBtu for natural gas to upwards of 95 Tg C02 Eq./QBtu for
coal and petroleum coke.21 In general, the carbon content 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 EqYBtu). 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.22 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 has declined since 1990 to a comparable level in 2001, as commercial businesses shift
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 70 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.23 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
Table 2-8: Carbon Intensity from Direct Fossil Fuel Combustion by Sector (Tg C02 Eq./QBtu)
Sector 1990 1995 1996 1997 1998 1999
2000 2001
Residential3
Commercial8
Industrial3
Transportation3
Electricity 6enerationb
U.S. Territories0
56.4
57.6
63.3
70.4
85.7
73.0
56.4
57.5
63.2
70.4
86.6
72.6
56.5
57.3
63.5
70.3
86.4
72.5
56.4
57.0
62.9
70.3
85.7
72.7
56.5
57.0
62.7
70.4
85.5
73.0
56.4
57.0
62.9
70.5
85.4
72.5
56.5
57.0
62.7
70.5
85.1
72.1
All Sectors0
72.4
71.9
72.0
72.2 72.3
72.3 72.3
72.3
a 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.
19 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.
20 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.
21 One exajoule (EJ) is equal to 1018 joules or 0.9478 QBtu.
22 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.
23 In other words, the emissions from the generation of electricity are intentionally double counted by attributing them both to electricity
generation and the end-use sector in which electricity consumption occurred.
2-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table 2-9: Carbon Intensity from all Energy Consumption by Sector (Tg C02 EqVQBtu)
Sector 1990 BB 1995 1996 1997 1998
Transportation3 70.4
Other End-Use Sectors3'b 62.8
Electricity Generation0 58.8
All Sectors"
61.1
1999
2000 2001
70.1
61.6
57.1
60.1
70.1
61.7
57.5
60.1
70.0
63.1
58.8
60.8
70.0
63.5
59.1
61.0
70.0
63.2
58.3
60.7
70.1
63.5
59.3
61.1
70.1
63.4
59.7
61.4
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.
amount of biomass based fuels 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 C02.
By comparing the values in Table 2-8 and Table 2-9, a few observations can be made. The use of renewable and nuclear energy sources
has resulted in a significantly lower carbon intensity of the U.S. economy. Over the eleven-year period of 1990 through 2001, however, 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 greater energy-related C02 emissions per capita in the United States since 1990 (see Figure 2-16). 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) have declined since 1990.
Figure 2-17 and Table 2-10 present the detailed C02 emission trends underlying the carbon intensity differences and changes described in
Table 2-8. In Figure 2-17, changes over time 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.
Figure 2-16
U.S. Energy Consumption and Energy-Related CO
Emissions Per Capita and Per Dollar GDP
Energy Consumption/capita
§
CO2/capita
CO2/Energy
Consumption
CO2/$GDP
Energy Consumption/$GDP
Source: BEA (2002), U.S. Census (2002), and emission and energy
consumption estimates in this report.
Figure 2-17
Change in C02 Emissions from Fossil Fuel Combustion
Since 1990 by End-Use Sector
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.
Residential Commercial Industrial Transportation
Energy 2-15
-------
Table 2-10: Change in C02 Emissions from Direct Fossil Fuel Combustion Since 1990 (Tg C02 Eq.)
Sector/Fuel Type
1991
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
10.8
(0.3)
9.2
1.9
0.8
(1.0)
5.9
(4.1)
(11.8)
(0.5)
6.4
(17.7)
(33.4)
-
(3.2)
(30.2)
(0.3)
1.7
4.1
(6.1)
0.0
5.6
0.1
-
5.5
(28.4)
+ Does not exceed 0.05 Tg C02 Eq.
NE (Not Estimated)
Note: Totals may not sum due to Independent rounding.
1995
1996
1997 1998
1999 2000 2001
29.7
(0.9)
24.2
6.3
5.4
(1.2)
21.8
(15.1)
47.2
(2.8)
58.9
(8.8)
107.4
2.3
105.1
126.8
113.1
53.0
(39.3)
(0.0)
10.3
0.3
10.0
326.8
59.7
(0.9)
45.4
15.2
14.9
(0.7)
28.7
(13.0)
84.2
(6.4)
74.7
15.9
146.9
3.0
144.0
198.9
203.7
29.7
(34.5)
(0.0)
6.4
0.3
6.1
511.0
42.8
(1.0)
31.4
12.4
15.6
(0.1)
31.7
(16.0)
95.5
(5.2)
75.8
24.8
156.5
5.2
151.3
265.9
247.8
43.6
(25.5)
(0.0)
9.1
0.3
8.7
585.3
10.0
(1.2)
7.7
3.5
(2.0)
(3.6)
21.0
(19.4)
44.8
(13.9)
64.1
(5.5)
183.5
(0.8)
184.2
355.4
278.5
72.7
4.2
(0.0)
14.2
0.3
13.9
605.8
28.4
(1.2)
17.7
11.9
0.2
(2.6)
22.6
(19.9)
17.9
(19.9)
46.5
(8.7)
242.6
(0.3)
242.9
368.5
287.2
84.7
(3.4)
(0.0)
16.4
0.3
16.2
674.0
45.0
(1.3)
31.6
14.8
12.9
(3.7)
31.7
(15.1)
35.8
(17.6)
59.0
(5.6)
292.3
(0.4)
292.7
472.8
376.6
105.3
(9.1)
(0.0)
18.6
0.3
17.7
877.4
34.4
(1.3)
22.0
13.8
14.4
(3.7)
33.3
(15.1)
(17.7)
(25.3)
25.5
(17.9)
310.4
(2.0)
312.4
437.8
326.6
109.6
1.7
(0.0)
20.7
0.3
19.2
800.1
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 Annexes A and B.
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. Because U.S. aggregate energy
statistics include consumption of fossil fuels for non-
energy uses, 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 UNFCCC reporting
guidelines emissions from international transport
activities, or bunker fuels, should not be included in
national totals. U.S. energy consumption statistics
include these bunker fuels (e.g., distillate fuel oil,
residual fuel oil, and jet fuel) as part of consumption by
See Carbon Stored in Products from Non-Energy Uses of Fossil Fuels section in this chapter for a more detailed discussion.
2-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
the transportation end-use sector, however, so
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.
This report provides a more detailed accounting of
emissions from transportation because it was such a
large consumer of fossil fuels in the United States.27
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. The difference between
total U.S. jet fuel consumption (as reported by El A)
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 in Table 2-7, and includes
such fuel uses as blending with heating oils and fuel
used for chartered aircraft flights.
Data Sources
Fuel consumption data 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), primarily from the Annual
Energy Review and other EIA databases (EIA 2002a). 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 2002) supplied data on military jet fuel use. 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/IEA 1997). Bechtel
(1993) provided the fraction oxidation value for coal.
Fuel consumption data for the allocation of
transportation end-use sector emissions were taken from
AAR (2001), Benson (2002), BEA (1991 through 2002), DESC
(2002), DOE (1993 through 2002), EIA (2002a), EIA (2002b),
EIA (2002c), EIA (1991 through 2002), FAA (1995 through
2002), and FHWA (1996 through 2002), and USAF (1998).
For a more detailed description of the data sources used for
the analysis of the transportation end use sector see the
Mobile Combustion (excluding CO2) and International
Bunker Fuels sections of the Energy chapter, Annex E, and
Annex J.
Carbon intensity estimates were developed using
nuclear and renewable energy data from EIA (2002a) and
fossil fuel consumption data as discussed above and
presented in Annex A.
For consistency of reporting, the IPCC has
recommended that countries report energy data 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
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 primarily to provide electricity to the other sectors.
28 See IPCC Reference Approach for estimating CO2 emissions from fossil fuel combustion in Annex W for a comparison of U.S. estimates
using top-down and bottom-up approaches.
Energy 2-17
-------
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 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.
Nevertheless, there are uncertainties 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.
Although statistics of total fossil fuel and other energy
consumption are relatively accurate, the allocation of this
consumption to individual end-use sectors (i.e., residential,
commercial, industrial, and transportation) is less certain.
For example, for some fuels the sectoral allocations are based
on price rates (i.e., tariffs), but a 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 fuel can add complexity because the
carbon might not be emitted to the atmosphere (e.g., plastics,
asphalt, etc.) or might be emitted at a delayed rate. This report
makes assumptions about the proportions of fuels used in
these non-energy production processes that result in the
sequestration of carbon. 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 in that 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 improve the
allocation into 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).
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: 1990-2001
-------
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 in Table 2-11. These fuels are
used in the industrial and transportation end-use sectors and
are quite diverse, including natural gas, LPG, 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,
emissions may occur during the product's lifetime, such as
during solvent use. Overall, more than 64 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.
There is some overlap between fossil fuels consumed
for non-energy uses and the fossil-derived CO2 emissions
accounted for in the Industrial Processes chapter. To avoid
double-counting, the "raw" non-energy fuel consumption
data reported by EIA are adjusted to account for these
overlaps, as shown in Table 2-11. In 2001, fossil fuel
consumption for non-energy uses constituted 7 percent
(5,752.5 TBtu) of overall fossil fuel consumption,
approximately the same proportion as in 1990. There are
also net exports of petrochemicals that are not completely
accounted for in the EIA data, and these affect the total
carbon content of non-energy fuels; the effects of these
adjustments are also shown in the table. In 2001, the adjusted
Table 2-11:2001 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 (>401 deg. 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 Adjusted"
6,060.6
689.1
333.9
1,257.6
1,690.4
174.3
239.2
493.7
662.5
31.0
181.1
78.5
11.7
56.6
36.3
124.9
164.6
164.6
259.3
1.5
257.8
6,484.5
5,328.6
24.9
333.9
1,257.6
1,690.4
174.3
239.2
493.7
662.5
31.0
113.2
78.5
11.7
56.6
36.3
124.9
164.6
164.6
259.3
1.5
257.8
5,752.5
Carbon
Total
366.5
2.3
17.7
95.1
104.6
12.9
16.0 .
32.8
48.5
2.0
11.6
5.7
0.9
4.5
2.6
9.3
12.2
12.2
19.0
0.1
18.9
397.7
Content
Adjusted"
360.1
2.3
17.1
95.1
101.4
12.9
15.5
31.9
47.2
2.0
11.6
5.7
0.9
4.5
2.6
9.3
12.2
12.2
19.0
0.1
18.9
391.3
Storage
Factor
0.75
0.61
1.00
0.61
0.09
0.61
0.61
0.61
0.80
0.50
0.00
0.50
0.50
1.00
1.00
0.09
0.09
0.10
0.65
Carbon
Stored
249.7
1.8
10.4
95.1
61.7
1.2
9.5
19.4
28.7
1.6
5.8
-
0.4
2.2
2.6
9.3
1.1
1.1
1.9
+
1.9
252.8
Emissions
110.4
0.6
6.7
+
39.7
11.7
6.1
+
12.5
18.5
0.4
5.8
5.7
0.4
2.2
+
+
11.1
11.1
17.1
0.1
17.0
138.6
3 To avoid double-counting, coal coke, petroleum coke, and natural gas consumption are adjusted for industrial process consumption addressed
in the Industrial Process chapter.
b Natural gas, LPG, Pentanes Plus, Naphthas, and Other Oils are adjusted to account for exports of chemical Intermediates derived from these fuels.
- Not applicable.
Note: Totals may not sum due to independent rounding.
Energy 2-19
-------
Table 2-12: Storage and Emissions from Non-Energy Fossil Fuel Consumption (Tg C02 Eq.)
Variable
1990
Potential Emissions
Carbon Stored
Emissions
1995
1996
1997
1998
1999 2000 2001
362.9
238.1
124.8
372.4
240.9
131.6
385.5
249.7
135.8
402.3
258.5
143.8
427.9
271.9
156.0
410.8
263.6
147.2
391.3
252.8
138.6
carbon content of fuels consumed for non-energy uses was
approximately 391.3 Tg CO2 Eq., an increase of 20 percent
since 1990. About 252.8 Tg CO2 Eq. of this carbon was stored,
while the remaining 138.6 Tg CO2 Eq. was emitted. The
proportion of carbon emitted has remained about the same, at
about 34 to 36 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 2001.
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. Consumption
values 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, such
as petrochemical feedstocks, liquid petroleum gases (LPG),
pentanes plus, natural gas for non-fertilizer uses, asphalt
and road oil, and lubricants, 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 and during use. Annex C provides
more details of these calculations. 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 (2001 a).
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 EIA Manufacturer's
Energy Consumption Survey (MECS) (EIA 200 Ib), the
National Petrochemical & Refiners Association (NPRA2001),
the National Asphalt Pavement Association (Connolly 2000),
the Emissions Inventory Improvement Program (EIIP 1999),
the U.S. Census Bureau (1999), the American Plastics Council
(APC 2000), the International Institute of Synthetic Rubber
Products (HSRP 2000), the Fiber Economics Bureau (FEE 2000),
and the Chemical Manufacturer's Handbook (CMA1999). For
the other fuel types, storage factors were taken from Marland
and Rotty (1984). Specific data sources are listed in full detail
in Annex C.
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
30 These source categories include Iron and Steel Production, Ammonia Manufacture, Titanium Dioxide Production, Ferroalloy Production,
and Aluminum Production.
2-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
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 C. 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 CO2, which was addressed in the
previous section, gases from stationary combustion include
the greenhouse gases CH4 and N2O and the ambient air
pollutants NOx, CO, and NMVOCs.31 Emissions of these
gases from stationary combustion sources depend upon
fuel characteristics, size and vintage, along with combustion
technology, pollution control equipment, and ambient
environmental conditions. Emissions also vary with
operation and maintenance practices.
Nitrous oxide and NOx emissions from stationary
combustion are closely related to air-fiiel 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 9 percent overall from 8.1 Tg
CO2 Eq. (388 Gg) in 1990 to 7.4 Tg CO2 Eq. (353 Gg) in 2001.
This decrease in CH4 emissions was primarily due to lower
wood consumption in the residential sector. Conversely, N2O
emissions rose 13 percent since 1990 to 14.2 Tg CO2 Eq. (46
Gg) in 2001. 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 2001. Overall, however, stationary combustion
is a small source of CH4 and N2O in the United States.
In contrast, stationary combustion was a significant source
ofNOx emissions, but a smaller source of CO and NMVOCs. In
2001, emissions of NOx from stationary combustion represented
39 percent of national NOx emissions, while CO and NMVOC
emissions from stationary combustion contributed
approximately 4 and 7 percent, respectively, to the national
totals. From 1990 to 2001, emissions of NOx and CO from
stationary combustion decreased by 21 and 17 percent,
respectively, and emissions ofNMVOCs increased by 19 percent.
The decrease in NOx emissions from 1990 to 2001 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 apparent changes in residential
wood use, 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 2001 are given in Table 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 NOs, CO, and NMVOCs, the major categories
included in this section are those used in EPA (2003): coal,
fuel oil, natural gas, wood, other fuels (including LPG, 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.
31 Sulfur dioxide (SO2) emissions from stationary combustion are addressed in Annex U.
32 See Annex D for a complete time series of ambient air pollutant emission estimates for 1990 through 2001.
Energy 2-21
-------
Table 2-13: CH4 Emissions from Stationary Combustion (Tg C02 Eq.)
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
0.6
0.3 I
0.1 1
1 °6
• 0.4
• o.o
0.1 H| 0.1
0.1 JJj
2.2 I
0.3 1
.2 m
0.8 1
0.9 1
0.7 I
+ 1
0.2 I
0.3 1
• 5-1
• 2'5
1 °-3
.2
• 0.9
m 1-°
1 °-8
K +
• O-1
• °-3
0.2 H| 0.3
4.6 • 4.7
0.2 H| 0.1
0.3 jm 0.3
0.5 • 0.5
3.7 im 3.8
8.1 B 8.5
0.6
0.4
0.1
0.1
0.1
2.5
0.3
On
.2
1.0
1.1
0.8
+
0.2
0.3
0.3
4.7
0.1
0.3
0.6
3.8
8.7
0.6
0.4
0.1
0.1
0.1
2.5
0.3
0.2
1.0
1.0
0.9
+
0.1
0.3
0.3
3.6
0.1
0.3
0.5
2.6
7.5
0.7
0.4
0.1
0.1
0.1
2.4
0.3
0.2
0.9
1.0
0.8
+
0.1
0.3
0.3
3.3
0.1
0.3
0.5
2.4
7.2
0.7
0.4
0.1
0.1
0.1
2.4
0.3
0.1
0.9
1.0
0.8
+
0.1
0.3
0.3
3.5
0.1
0.3
0.5
2.6
7.4
0.7
0.4
0.1
0.1
0.1
2.4
0.3
0.1
0.9
1.0
0.9
+
0.2
0.3
0.3
3.7
0.1
0.3
0.5
2.7
7.6
0.7
0.4
0.1
0.1
0.1
2.4
0.4
0.1
0.9
1.0
0.8
+
0.2
0.4
0.3
3.5
0.1
0.3
0.5
2.6
7.4
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to Independent rounding.
Table 2-14: N20 Emissions from Stationary Combustion (Tg C02 Eq.)
Sector/Fuel Type
1990
1995
1996
1997 1998
1999
2000 2001
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
7.6
7.1
0.2
0.1
0.2
3.5
0.7
0.8
0.2
1.8
0.4
0.1
0.2
0.1
0.0
1.1
+
0.2
0.1
0.7
Total
12.5
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
8.0
7.6
0.1
0.1
0.2
3.7
0.7
0.7
0.3
2.1
0.3
0.1
0.1
0.1
0.1
1.2
0.3
0.2
0.7
13.2
8.5
8.0
0.2
0.1
0.2
3.8
0.7
0.7
0.3
2.1
0.4
0.1
0.1
0.1
0.1
1.2
0.3
0.2
0.7
13.8
8.7
8.2
0.2
0.1
0.2
3.7
0.7
0.7
0.3
2.0
0.4
0.1
0.1
0.1
0.1
1.0
0.3
0.2
0.5
13.7
8.9
8.4
0.2
0.1
0.2
3.6
0.6
0.7
0.3
2.0
0.3
0.0
0.1
0.1
0.1
0.9
0.2
0.1
0.5
13.7
8.9
8.4
0.2
0.2
0.2
3.5
0.6
0.6
0.3
2.0
0.3
0.0
0.1
0.1
0.1
0.9
0.3
0.2
0.5
13.7
9.3
8.8
0.2
0.2
0.2
3.6
0.6
0.7
0.3
2.0
0.3
0.0
0.1
0.1
0.1
1.0
0.3
0.2
0.5
14.3
9.1
8.6
0.2
0.2
0.2
3.8
0.9
0.7
0.3
2.0
0.3
0.0
0.1
0.1
0.1
0.9
0.3
0.2
0.5
14.2
2-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table 2-15: CH4 Emissions from Stationary Combustion (Gg)
Sector/Fuel Type
1990
1995
1996
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
27
16
4
3
4
107
16
8
39
43
36
1
9
14
12
218
8
13
23
175
388
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding
Table 2-16: N20 Emissions from Stationary Combustion (Gg)
Sector/Fuel Type
1990
1995
1996
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
24
23
1
+
+
11
2
2
1
6
1
+ I
1
+
+
4
+
1
+
2
Total
40
43
45
1997
1998
1999
2000 2001
28
18
2
4
4
118
16
7
45
50
38
1
7
16
14
223
5
14
25
179
406
29
18
2
4
4
120
15
8
46
51
40
1
7
16
15
226
5
15
27
179
415
30
19
3
4
4
118
16
8
46
48
41
1
7
17
16
169
5
15
26
124
358
32
19
4
5
4
115
15
7
45
48
38
1
7
16
14
157
4
13
23
116
342
32
19
4
5
4
113
14
7
43
48
39
1
7
16
16
168
4
15
24
124
351
33
20
3
5
4
115
14
7
45
49
41
1
7
17
16
175
4
15
26
130
363
33
20
4
5
4
116
20
7
42
48
38
1
7
17
13
166
4
15
25
122
353
1997 1998
1999 2000 2001
26
25
+
+
1
12
2
2
1
7
1
27
26
+
+
1
12
2
2
1
7
1
28
27
1
+
1
12
2
2
1
6
1
29
27
1
+
1
12
2
2
1
6
1
29
27
1
+
1
11
2
2
1
6
1
30
28
1
1
1
12
2
2
1
7
1
30
28
1
1
1
12
3
2
1
6
1
4
1
+
2
4
1
1
2
3
1
1
2
3
1
+
2
3
1
+
2
3
1
1
2
3
1
+
2
44
44
44
46
46
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding.
Energy 2-23
-------
Table 2-17: NOX, CO, and NMVOC Emissions from
Stationary Combustion in 2001 (Gg)
Sector/Fuel Type
NO.
CO
NMVOC
Electric Generation
Coal
Fuel Oil
Natural gas
Other Fuels'
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Residential
Coal"
Fuel Oil"
Natural Gas"
Wood
Other Fuels
Total
4,437
3,782
148
330
NA
37
140
2,393
496
147
875
NA
111
764
384
28
72
227
NA
57
611
NA
NA
NA
30
582
7,826
445
223
28
93
NA
33
68
1,071
118
43
345
NA
303
263
149
13
16
80
NA
40
2,503
NA
NA
NA
2,292
211
4,169
57
27
5
13
NA
2
11
152
10
8
52
NA
28
54
38
1
4
15
NA
19
839
NA
NA
NA
812
27
1,087
NA (Not Available)
a Includes LPG, waste oil, coke oven gas, and coke (EPA 2003).
b Coal, fuel oil, and natural gas emissions are included In
"Other Fuels" (EPA 2003).
Note: Totals may not sum due to independent rounding.
See Annex D for emissions in 1990 through 2001.
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/IEA 1997).
More detailed information on the methodology for
calculating emissions from stationary combustion, including
emission factors and activity data, is provided in Annex D.
Data Sources
Emissions estimates for NOx, CO, and NMVOCs in this
section were taken directly from EPA data published on the
National Emission Inventory (NET) Air Pollutant Emission Trends
web site (EPA 2003). Fuel consumption data for CH4 and N2O
estimates were provided by the U.S. Energy Information
Administration's Annual Energy Review (EIA 2002). 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 1996IPCC Guidelines for National
Greenhouse Gas Inventories (IPCC/UNEP/OECD/TEA1997).
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 CH4, N2O, and the ambient air pollutants NOx, CO, and
NMVOCs. While air conditioners and refrigerated units in
vehicles also emit hydrofluorocarbons (HFCs), these are covered
in Chapter 3, Industrial Processes, under the section entitled
Substitution of Ozone Depleting Substances. 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 the presence of post-combustion
emission controls. Carbon monoxide emissions are highest when
air-fuel mixtures have less oxygen than required for complete
2-24 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
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), fuel type (e.g., motor
gasoline, diesel fuel, jet fuel), and vehicle type (e.g.,
passenger cars, light-duty trucks). 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 2001 are given in Table 2-22.33
Mobile combustion was responsible for a small portion
(0.7 percent) of national CH4 emissions but was the second
largest source of N2O (13 percent) in the United States. From
1990 to 2001, CH4 emissions declined by 13 percent, to 4.3 Tg
CO2 Eq. (204 Gg). During the same time period, N2O emissions
rose by 8 percent to 54.8 Tg CO2 Eq. (177 Gg) (see Figure 2-18).
The reason for this conflicting trend was that the control
technologies employed on highway vehicles in the United States
reduced CO, NOx, NMVOC, and CH4 emissions, but resulted in
higher average N2O emission rates. However, 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,NOx,andNMVOC emissions in the UnitedStates. In 2001,
mobile combustion contributed 90 percent of CO emissions, 56
percent of NO emissions, and 45 percent of NMVOC emissions.
Figure 2-18
Mobile Source CH, and N,0 Emissions
Since 1990, emissions of NMVOCs from mobile combustion
decreased by 38 percent, CO emissions decreased 24 percent, and
emissions of NOx decreased by 7 percent.
Methodology
Estimates of 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 for gasoline and diesel highway
vehicles were based on VMT and emission factors by vehicle
type, fuel type, model year, and control technology. Emissions
from alternative fuel vehicles (AFVs)34 were based on VMT
by vehicle and fuel type. Fuel consumption data were
employed as a measure of activity for non-highway vehicles
and then fuel-specific emission factors were applied.35 A
complete discussion of the methodology used to estimate
emissions from mobile combustion is provided in Annex E.
EPA (2003) provided emissions estimates of NOx, CO,
and NMVOCs for eight categories of highway vehicles,36
aircraft, and seven categories of off-highway vehicles.37
33 See Annex E for a complete time series of emission estimates for 1990 through 2001.
34 Alternative fuel and advanced technology vehicles are those that can operate using a motor fuel other than gasoline or diesel. This includes
electric or other bifuel or dual fuel vehicles that may be partially powered by gasoline or diesel.
35 The consumption of international bunker fuels is not included in these activity data, but are estimated separately under the International
Bunker Fuels source category.
36 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.
37 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.
Energy 2-25
-------
Data Sources
Emission factors used in the calculations of CH4 and N2O
emissions are presented in Annex E. The Revised 1996IPCC
Guidelines (IPCC/UNEP/OECD/ffiA 1997) provided most of the
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
Table 2-18: CH4 Emissions from Mobile Combustion (Tg C02 Eq.)
Fuel Type/Vehicle Type3
1990
1995
1996
1997 1998 1999 2000 2001
Gasoline Highway 4.3
Passenger Cars 2.4
Light-Duty Trucks 1.6
Heavy-Duty Vehicles 0.2
Motorcycles 0.1
Diesel Highway 0.2
Passenger Cars +
Light-Duty Trucks +
Heavy-Duty Vehicles 0.2
Alternative Fuel Highway +
Non-Highway 0.4
Ships and Boats 0.1
Locomotives 0.1
Farm Equipment 0.1
Construction Equipment +
Aircraft 0.2
Other* +
4.1
2.0
1.8
0.1
0.1
0.3
+
+
0.5
0.1
0.1
0.1
+
4.0
2.0
1.8
0.1
0.1
0.3
0.3
0.1
0.5
0.1
0.1
0.1
0.1
3.9
2.0
1.7
0.1
0.1
0.3
0.3
0.1
0.4
0.1
0.1
0.1
0.2
3.8
2.0
1.6
0.1
0.1
0.3
0.3
0.1
0.4
0.1
0.1
0.1
0.1
3.7
1.9
1.6
0.1
0.1
0.3
0.3
0.1
0.5
0.1
0.1
0.1
0.2
3.6
1.9
1.5
0.1
0.1
0.3
0.3
0.1
0.5
0.1
0.1
0.1
0.2
3.4
1.8
1.5
0.1
0.3
0.3
0.1
0.5
0.1
0.1
0.1
0.1
Total
4.9
4.8
4.7
4.6
4.5
4.4
4.3
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
a See Annex E for definitions of highway vehicle types.
b "Other" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty diesel
powered utility equipment.
Table 2-19: N20 Emissions from Mobile Combustion (Tg C02 Eq.)
Fuel Type/Vehicle Type
1990
1995
1996
1997 1998 1999 2000 2001
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Alternative Fuel Highway
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
45-6 H
30.9 ij»
13.9
0.7
+
2.0
0.1
0.2
1.8
0/1 H
2.9 »
0.4
0.3 IM
0-3 111
0.1
i-7 9R
0.1 III
50.6 111
1 55.2
1 33.4
1 20.9
; 1-0
I +
I 2.6
i 0.1
! 0.2
I 2.3
[ 0.1
! 3.0
I 0.5
i 0.3
i 0.3
s 0.1
i 1.7
| 0.1
I 60.9
54.9
33.0
20.8
1.0
+
2.6
0.1
0.2
2.4
0.1
3.1
0.4
0.3
0.3
0.1
1.8
0.1
60.7
54.4
32.5
20.9
1.1
+
2.8
0.1
0.2
2.5
0.1
2.9
0.3
0.3
0.3
0.2
1.7
0.1
60.3
53.7
32.2
20.4
1.1
+
2.9
0.1
0.2
2.6
0.1
2.9
0.3
0.3
0.3
0.2
1.8
0.1
59.7
52.5
31.2
20.2
1.1
+
3.0
+
0.3
2.7
0.2
3.1
0.4
0.3
0.3
0.1
1.8
0.1
58.8
51.0
30.2
19.6
1.1
+
3.0
+
0.3
2.7
0.2
3.3
0.5
0.3
0.3
0.2
1.9
0.1
57.5
48.4
28.6
18.6
1.1
+
3.1
+
0.3
2.8
0.2
3.1
0.3
0.3
0.3
0.2
1.8
0.2
54.8
+ 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.
2-26 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
temperature, vehicle speeds, national vehicle registration
distributions, gasoline volatility, and other variables in order to
produce these factors (EPA 1997). Emission factors for CH4 for
Tier 1 and LEV38 heavy-duty gasoline vehicles were determined
using emission factors from the California Air Resources Board
mobile source emissions factor model for 2002 (CARB 2000).
Table 2-20: CH4 Emissions from Mobile Combustion (Gg)
Fuel Type/Vehicle Type
1990
1995
1996
1997 1998
1999 2000 2001
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Alternative Fuel Highway
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
203
116
75
9
4
11
+
+
10
1
21
3
3
6
1
7
1
236
195
97
88
7
4
13
189
95
85
6
4
13
185
93
82
6
3
14
180
93
78
5
3
14
174
91
76
5
3
14
169
89
73
5
3
14
163
87
69
4
2
14
13
2
22
4
3
6
1
7
1
13
3
22
4
3
6
1
7
1
13
3
21
3
3
6
1
7
1
13
4
20
2
3
5
1
7
1
13
5
21
4
3
5
1
7
1
13
5
23
5
3
5
1
7
1
13
6
22
3
3
6
1
7
1
232
227
223
217
214
211
204
+ 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.
Table 2-21: N20 Emissions from Mobile Combustion (Gg)
Fuel Type/Vehicle Type
1990
1995
1996
1997 1998 1999 2000 2001
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Alternative Fuel Highway
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
147
100
45
2
178
108
67
1
7
+
1
1
+
5
+
177
106
67
3
1
8
10
1
1
1
176
105
67
3
173
104
66
4
9
1
8
9
1
1
1
169
101
65
4
10
1
9
10
1
1
1
164
97
63
4
10
1
9
1
11
2
1
1
1
6
156
92
60
3
10
1
9
1
10
1
1
1
1
6
1
Total
163
197
196
195
192
190
185
177
+ 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.
See Annex E for definitions of control technology levels.
Energy 2-27
-------
Table 2-22: NOX, CO, and NMVOC Emissions from
Mobile Combustion in 2001 (Gg)
Fuel Type/Vehicle Type
NO,
CO NMVOCs
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
3,942
2,150
1,363
414
12
3,542
6
6
3,530
3,770
971
907
480
690
73
650
11,254
66,857
37,250
26,611
2,842
181
1,025
7
6
1,011
22,387
1,952
90
621
1,041
233
18,449
90,268
4,217
2,355
1,638
203
38
204
3
4
198
2,379
730
35
72
125
19
1,397
6,800
NE = Not Estimated.
a Aircraft estimates include only emissions related to landing and take-
off (LTD) cycles, and therefore do not include cruise attitude 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 construc-
tion, airport service.
Note: Totals may not sum due to independent rounding. See Annex E
for emissions from 1990 through 2001.
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 IPCC 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
NVFEL. The U.S. default values in the Revised 1996IPCC
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 most gasoline
vehicles other than passenger cars (i.e., light-duty gasoline
trucks, 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 2002), EPA/DOE (2001), and Census (2000). 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. Emission factors for N2O
for Tier 1 and LEV heavy-duty gasoline vehicles were
estimated from the ratio of NOx emissions to N2O emissions
for Tier 0 heavy-duty gasoline trucks.39
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 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.
Emission factors for AFVs were developed after
consulting a number of sources, including Argonne National
Laboratory's GREET 1.5 - Transportation Fuel Cycle Model
(Wang 1999), Lipman and Delucchi (2002), the Auto/Oil Air
Quality Improvement Research Program (1997), the California
Air Resources Board (Brasil and McMahon 1999), and the
University of California Riverside (Norbeck, et al., 1998).
The primary approach taken was to calculate CH4 emissions
from actual test data and determine N2O emissions from NOx
emissions from the same tests. A complete discussion of the
data source and methodology used to determine emission
factors from AFVs is provided in Annex E.
Activity data were gathered from several U.S.
government sources including BEA (1991 through 2001),
Census (2000), DESC (2001), DOC (1991 through2001), DOT
(1991 through 2001), EIA (2002a), EIA (2002b), EIA (2002c),
EIA(2002d), EIA(1991 through 2002), EPA/DOE (2001), FAA
(1995 through 2002), and FHWA (1996 through 2002). Control
technology and standards data for highway vehicles were
See Annex E for definitions of control technology levels.
2-28 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
obtained from the EPA's Office of Transportation and Air
Quality (EPA2002a, 2002b, 2000, 1998, and 1997). These
technologies and standards are defined in Annex E, and
were compiled from EPA (1993), EPA (1994a), EPA (1994b),
EPA (1998), EPA (1999), and IPCC/UNEP/OECD/IEA (1997).
Annual VMT data for 1990 through 2001 were obtained from
the Federal Highway Administration's (FHWA) Highway
Performance Monitoring System database as reported in
Highway Statistics (FHWA 1996 through 2002).
Emissions estimates forNOx, CO, NMVOCs were taken
directly from EPA data published on the National Emission
Inventory (NEI) Air Pollutant Emission Trends web site
(EPA2003).
Uncertainty
Mobile combustion emissions from each vehicle mile
traveled can vary significantly due to assumptions
concerning fuel type and composition, technology type,
operating speeds and conditions, 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, NOx, 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 in the United States, overall hydrocarbon
emissions from mobile combustion—a component of which
is CH4—are regulated.
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 the 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 NMVOCs.
All these gases, however, 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.
Energy 2-29
-------
Lastly, in EPA (2001), U.S. aircraft emission estimates
for CO, NOx, and NMVOCs are based upon 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 CH4
as part of the normal mining operations. The amount of CH4
liberated depends on the amount that remains in the coal
("in situ") and surrounding strata when mining occurs. The
in-situ CH4 content depends upon the amount of CH4 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 CH4
and retain more of the gas afterwards. Accordingly, deep
underground coal seams generally have higher CH4 contents
than shallow coal seams or surface deposits.
Three types of coal mining related activities release CH4
to the atmosphere: underground mining, surface mining,
and post-mining (i.e., coal-handling) activities. Underground
coal mines contribute the largest share of CH4 emissions.
All underground coal mines employ ventilation systems to
ensure that CH4 levels remain within safe concentrations.
These systems can exhaust significant amounts of CH4 to
the atmosphere in low concentrations. Additionally, twenty-
one U.S. coal mines 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 CH4 before, during, or after
mining. In 2001, ten coal mines collected CH4 from
degasification systems and sold this gas to a pipeline, thus
reducing emissions to the atmosphere. Surface coal mines
also release CH4 as the overburden is removed and the coal
is exposed, but the level of emissions is much lower than
from underground mines. Finally, some of the CH4 retained
in the coal after mining is released during processing, storage,
and transport of the coal.
Total CH4 emissions in 2001 were estimated to be 60.7
Tg CO2 Eq. (2,893 Gg), declining 30 percent since 1990 (see
Table 2-23 and Table 2-24). Of this amount, underground
mines accounted for 63 percent, surface mines accounted
for 16 percent, and post-mining emissions accounted for 21
percent. With the exception of 1994 and 1995, total CH4
emissions declined in each successive year during this
period. In 1993, CH4 generated from underground mining
dropped, primarily due to labor strikes at many large
underground mines. In 1995, there was an increase in CH4
emissions from underground mining due to significantly
increased emissions at the highest-emitting coal mine in the
country. The decline in CH4 emissions from underground
mines in 2001 is the result of the mining of less gassy coal,
and an increase in CH4 recovered and used. Surface mine
emissions and post-mining emissions remained relatively
constant from 1990 to 2001.
Methodology
The methodology for estimating CH4 emissions from
coal mining consists of two parts. The first part involves
estimating CH4 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 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 emission factors.
Underground mines. Total CH4 emitted from
underground mines was estimated as the sum of CH4 liberated
from ventilation systems and CH4 liberated by means of
degasification systems, minus CH4 recovered and used. The
Mine Safety and Heath Administration (MSHA) samples
CH4 emissions from ventilation systems for all mines with
detectable40 CH4 concentrations. These mine-by-mine
measurements are used to estimate CH4 emissions from
ventilation systems.
40 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.
2-30 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table 2-23: CH4 Emissions from Coal Mining (Tg C02 Eq.)
Activity
1990
1995
1996
1997
1998
1999
2000 2001
Underground Mining
Liberated
Recovered & Used
Surface Mining
Post- Mining (Underground)
Post-Mining (Surface)
Total
Note: Totals may not sum due to
62.1
67.6
(5.6)
10.2
13.1
1.7 v-';;^
87.1
independent rounding.
51.2
63.3
(12.0)
8.9
11.9
1.5
73.5
45.3
59.8
(14.5)
9.2
12.4
1.5
68.4
44.3
55.7
(11.4)
9.5
12.8
1.5
68.1
44.4
58.6
(14.2)
9.4
12.6
1.5
67.9
41.6
54.4
(12.7)
8.9
11.7
1.4
63.7
39.4
54.0
(14.7)
8.8
11.3
1.4
60.9
38.1
54.2
(16.0)
9.5
11.6
1.5
60.7
Table 2-24: CH4 Emissions from Coal Mining (Gg)
Activity
Underground Mining
Liberated
Recovered & Used
Surface Mining
Post- Mining (Underground)
Post-Mining (Surface)
Total
1990 ^j
2,956 '; ""
3,220 Y'7"
(265) v&.'
488 :"/,,
626 if'
79 '';>
4,149 vV
1995
2,439
3,012
(574)
425
569
69
3,502
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
1,877
2,573
(698)
420
538
68
2,902
2001
1816
2580
(764)
453
550
74
2,893
Note: Totals may not sum due to independent rounding.
Some of the higher-emitting underground mines also
use degasification systems (e.g., wells or boreholes) that
remove CH4 before, during, or after mining. This CH4 can
then be collected for use or vented to the atmosphere.
Various approaches were employed to estimate the quantity
of CH4 collected by each of the twenty-one mines using
these systems, depending on available data. For example,
some mines report to EPA the amount of CH4 liberated from
their degasification systems. For mines that sell recovered
CH4 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 CH4 recovered by degasification
systems and then used (i.e., not vented) was estimated. This
calculation was complicated by the fact that most CH4 is not
recovered and used during the same year in which the
particular coal seam is mined. In 2001, ten active coal mines
sold recovered CH4 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 CH4 emissions were estimated by
multiplying basin-specific coal production by basin-specific
emission factors. Surface mining emission factors were
developed by assuming that surface mines emit two times
as much CH4 as the average in situ CH4 content of the coal.
This accounts for CH4 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 CH4
content of coals mined in the basin.
Data Sources
The Mine Safety and Health Administration provided
mine-specific information on CH4 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
Energy 2-31
-------
Table 2-25: Coal Production (Thousand Metric Tons)
Year
Underground Surface
Total
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
384,250
368,635
368,627
318,478
362,065
359,477
371,816
381,620
378,964
355,433
338,173
345,303
546,818
532,656
534,290
539,214
575,529
577,638
593,315
607,163
634,864
642,877
635,592
677,735
931,068
901,291
902,917
857,692
937,594
937,115
965,131
988,783
1,013,828
998,310
973,765
1,023,039
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) (EIA
2002). Data on in situ CH4 content and emissions factors are
taken from EPA (1990).
Uncertainty
The emission estimates from underground ventilation
systems were based on 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 10
percent overestimation of annual CH4 emissions (Mutmansky
and Wang 2000). Estimates of CH4 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. A level of uncertainty currently 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 emission factors from
field measurements. 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 CH4 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. 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 117.3 Tg CO2 Eq. (5,588
Gg) of CH4 in 2001, a slight decrease over emissions in 1990
(see Table 2-26 and Table-2-27). Improvements in management
practices and technology, along with the replacement of older
equipment, have helped to stabilize emissions (EPA 2001).
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
engines 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 CH4
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
26 percent of CH4 emissions from natural gas systems
between 1990 and 2001.
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
2-32 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
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 CH4 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 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 33 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 1,117,351 miles of distribution mains in 2001, an increase
from just over 837,000 miles in 1990 (OPS 2002a). Distribution
system emissions, which account for approximately 28
percent of emissions from natural gas systems, result mainly
from fugitive emissions from gate stations and non-plastic
piping (cast iron, steel).41 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 2001 were slightly higher
than 1990 levels.
Methodology
The basis for estimates of CH4 emissions from the U.S.
natural gas industry is a detailed study by the Gas Research
Institute and EPA (EPA/GRI 1996). 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, EPA developed a 1992 base-year emission
Table 2-26: CH4 Emissions from Natural Gas Systems (Tg C02 Eq.)
Stage
Field Production
Processing
Transmission and Storage
Distribution
1990
30.4
14.7
46.7
30.2
Total
122.0
1995
Note: Totals may not sum due to independent rounding.
Table 2-27: CH4 Emissions from Natural Gas Systems (Gg)
Stage
1990
Field Production 1,445
Processing 702
Transmission and Storage 2,223
Distribution 1,440
Total
5,810
1995
Note: Totals may not sum due to independent rounding.
1996
1997
1998
1999
1996
1997
1998
1999
41 The percentages of total emissions from each stage may not add to 100 because of independent rounding.
2000
2000
2001
33.2
14.9
46.1
33.0
127.2
32.3
14.9
46.7
33.6
127.4
33.1
14.9
45.8
32.2
126.0
33.7
14.4
44.9
31.0
124.0
30.7
14.2
43.7
31.7
120.3
31.3
14.3
43.1
32.6
121.2
30.8
14.5
39.3
32.7
117.3
2001
1,583
709
2,196
1,572
1,537
709
2,223
1,600
1,577
710
2,183
1,532
1,605
684
2,140
1,475
1,463
675
2,082
1,508
1,488
680
2,053
1,551
1,467
692
1,870
1,559
6,059 6,069 6,001 5,903 5,728 5,772 5,588
Energy 2-33
-------
estimate using the emission and activity factors. For other
years, 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.
See Annex G for more detailed information on the
methodology and data used to calculate CH4 emissions from
natural gas systems.
Data Sources
Activity factor data were taken from the following
sources: American Gas Association (AGA 1991-1998);
American Petroleum Institute (API 2002); Minerals and
Management Service (DOI1998-2002); Natural Gas Annual
(EIA1993,1996,1997,1998a,2002d,2002f, 1998g); Natural
Gas Monthly (EIA 2002 b, 2001,2002c, 2001,2002e); Office
of Pipeline Safety (OPS 2002 a,b); Oil and Gas Journal (OGJ
1999 through 2002). The Gas Systems Analysis model was
used to aid in collecting data for non-associated and
associated wells (GSAM 1997). All emissions factors were
taken from EPA/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, scaling
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, CH4 is released to
the atmosphere as fugitive emissions, vented emissions,
emissions from operational upsets, and emissions from fuel
combustion. Total CH4 emissions from petroleum systems in
2001 were21.2TgCO Eq.(l,011 Gg). Since 1990,emissions
declined due to a decline in domestic oil production and industry
efforts to make reductions. (See Table 2-28 and Table 2-29.)
The various sources of emissions are detailed below.
Production Field Operations. Production field
operations account for approximately 97 percent of total
CH4 emissions from petroleum systems. Vented CH4 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
CH4 entrained in crude oil under high pressure volatilizes
once the crude oil is dumped into storage tanks at
atmospheric pressure. The next largest 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
CH4 emissions from the oil industry. Venting from tanks and
marine vessel loading operations accounts for the majority
of CH4 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 CH4 emissions from the oil
industry because most of the CH4 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,
while fugitive and combustion emissions account for approximately
6 percent each. Refinery system blowdowns 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 CH4 in
process heater stack emissions and from unburned CH4 in engine
exhausts and flares.
Methodology
The methodology for estimating CH4 emissions from
petroleum systems is based on a comprehensive study of CH4
emissions from U.S. petroleum systems, Estimates of Methane
Emissions from the U.S. Oil Industry (Draft Report) (EPA 1999)
and Methane Emissions from the U.S. Petroleum Industry (Radian
1996a-d). These studies combined emission estimates from 70
2-34 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
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 H explains the emission
estimates for these 70 activities in greater detail. The estimates of
CH4 emissions from petroleum systems do not include emissions
downstream from oil refineries because these emissions are very
small compared to CH4 emissions upstream from oil refineries.
The methodology for estimating CH4 emissions from the
70 oil industry activities employs emission factors initially
developed in EPA (1999) and activity factors that are based on
EPA (1999) and Radian (1996a-d). Emissions are estimated for
each activity by multiplying emission factors (e.g., emission
rate per equipment item or per activity) by their corresponding
activity factor (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 2001.
Activity factors for 1990 through 2001 were collected from
a wide variety of statistical resources. For some years, complete
activity factor data were not available. In such cases, one of
three approaches was employed. Where appropriate, the
activity factor was calculated from related statistics using ratios
developed for Radian (1996a-d). For example, Radian (1996a-d)
found that the number of heater treaters (a source of CH4
emissions) is related to both number of producing wells and
annual production. To estimate the activity factor for heater
treaters, reported statistics for wells and production are used,
along with the ratios developed for Radian (1996a-d). In other
cases, the activity factor is held constant from 1990 through
2001 based on EPA (1999). Lastly, the previous year's data
were used when data for the current year were unavailable.
See Annex H for additional detail.
Data Sources
Nearly all emission factors were taken from Radian (1996e).
The remaining emission factors were taken from the following
sources: the American Petroleum Institute (API 1996), EPA default
values, MMS reports (MMS 1995 and 1999), the Exploration and
Table 2-28: CH4 Emissions from Petroleum Systems (Tg C02 Eq.)
Activity
Production Field Operations
Tank venting
Pneumatic device venting
Wellhead fugitives
Combustion & process upsets
Misc. venting & fugitives
Crude Oil Transportation
Refining
Total
1990
26.8
11.7
11.0
0.6
2.2
1.4
0.1
0.5
27.5
1995
1996
1997
1998
1999
2000
2001
23.6
9.2
10.4
0.5
2.1
1.3
0.1
0.5
24.2
23.2
8.9
10.4
0.5
2.1
1.3
0.1
0.5
23.9
22.9
8.6
10.4
0.5
2.1
1.3
0.1
0.6
23.6
22.2
8.2
10.2
0.5
2.0
1.3
0.1
0.6
22.9
20.9
7.3
9.9
0.5
1.9
1.3
0.1
0.6
21.6
20.5
7.2
9.7
0.5
1.9
1.3
0.1
0.6
21.2
20.6
7.3
9.7
0.5
1.9
1.3
0.1
0.6
21.2
Note: Totals may not sum due to independent rounding.
Table 2-29: CH4 Emissions from Petroleum Systems (Gg)
1995
Activity
Production Field Operations
Tank venting
Pneumatic device venting
Wellhead fugitives
Combustion & process upsets
Misc. venting & fugitives
Crude Oil Transportation
Refining
Total
1990
1,278
558
525
26
103
65
7
25
1,309
1996
1997
1998
1999
2000
2001
1,122
439
497
25
98
63
6
25
1,153
1,107
425
496
25
98
63
6
26
1,138
1,090
409
495
25
98
63
6
27
1,123
1,058
390
485
25
96
62
6
27
1,090
996
349
470
24
92
61
6
27
1,029
977
343
460
22
91
60
5
28
1,010
979
345
460
22
91
60
5
27
1,011
Note: Totals may not sum due to independent rounding.
Energy 2-35
-------
Production (E&P) Tank model (API and GRI), reports by the
Canadian Association of Petroleum Producers (CAPP 1992 and
1993), and the consensus of industry peer review panels.
Among the more important references used to obtain
activity factors are the Energy Information Administration
annual and monthly reports (EIA 1995-2001), the API Basic
Petroleum Data Book (API 2000), 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 1990 through 2001). Annex H provides
a complete list of references.
Uncertainty
The detailed, bottom-up analysis used to evaluate U.S.
petroleum systems reduces the uncertainty related to the CH4
emission estimates in comparison with a top-down approach.
However, a number of uncertainties remain. Emission factors
and activity factors are based on a combination of
measurements, equipment design data, engineering calculations
and studies, surveys of selected facilities and statistical
reporting. Statistical uncertainties arise from natural variation
in measurements, equipment types, operational variability and
survey and statistical methodologies. Published activity factors
are not available every year for all 70 activities analyzed for
petroleum systems; therefore, some are estimated. Because of
the dominance of six of major sources, which account for 90
percent of the total emissions, a process is underway to examine
and develop uncertainty estimates for them and for total
emissions from the petroleum systems.
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.
Approximately 26 million metric tons of MSW were
combusted in the United States in 2001. Carbon dioxide
emissions from combustion of MSW rose 91 percent since
1990, to an estimated 26.9 Tg CO2 Eq. (26,907 Gg) in 2001, as
the volume of plastics and other fossil carbon-containing
materials in MSW increased (see Table 2-30 and Table 2-31).
Waste combustion is also a source of N2O emissions (De
Soete 1993). Nitrous oxide emissions from MS W combustion
were estimated to be 0.2 Tg CO2 Eq. (1 Gg) in 2001, and have
not changed significantly since 1990.
Ambient air pollutants were emitted during waste
incineration and open burning and are shown in Table 2 32.
These emissions are a relatively small portion of the overall
ambient air pollutant emissions, remaining below 5 percent
for each gas over the entire time series.
Municipal Solid Waste Combustion Methodology
Combustion is used to manage about 7 to 17 percent of the
municipal solid wastes (MSW) generated in the United States,
depending on the source of the estimate and the scope of
materials included in the definition of solid waste (EPA 2000c,
Goldstein and Matdes 2001). Almost all combustion of MS W 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
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, and synthetic fibers
were categorized into four product types, each having a
discrete carbon content. Scrap tires contain several types of
2-36 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
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
anthropogenic greenhouse gas sources. But the focus of the United Nations Framework Convention on Climate Change is on 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 153 Tg C02 Eq. and 12 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 2-30: C02 and N20 Emissions from Municipal Solid Waste Combustion (Tg C02 Eq.)
Gas/Waste Product
1990
C02
Plastics
Synthetic Rubber in Tires
Carbon Black in Tires
Synthetic Rubber in MSW
Synthetic Fibers
Total
1995
1996
1997 1998
1999 2000 2001
14.4
18.5
11.1
1.5
2.3
1.7
1.9
0.3
18.7
19.4
11.5
1.6
2.6
1.7
2.0
0.3
19.7
21.2
12.5
1.9
2.9
1.8
2.1
0.3
21.4
22.5
12.9
2.1
3.3
1.8
2.2
0.2
22.7
23.9
13.6
2.4
3.7
1.9
2.3
0.2
24.1
25.4
14.2
2.6
4.1
2.0
2.4
0.2
25.6
26.9
15.0
2.9
4.5
2.1
2.5
0.2
27.1
Table 2-31: C02 and N20 Emissions from Municipal Solid Waste Combustion (Gg)
Gas/Waste Product
C02
Plastics
Synthetic Rubber in Tires
Carbon Black in Tires
Synthetic Rubber in MSW
Synthetic Fibers
1990
14,068
10,320
246
383
1 ,584
1,535
1
1995
1996
1997
1998
1999
2000 2001
19,418
11,459
1,642
2,561
1,737
2,018
1
21,173
12,484
1,852
2,889
1,807
2,141
1
22,454
12,929
2,130
3,321
1,841
2,233
1
23,903
13,580
2,377
3,707
1,910
2,329
1
25,351
14,232
2,624
4,092
1,979
2,424
1
26,907
14,975
2,871
4,478
2,055
2,527
1
Table 2-32: NO,, CO, and NMVOC Emissions from Municipal Solid Waste Combustion (Gg)
Gas/Source
1990
1995
1996
1997
1998
1999
2000 2001
NO,
Waste Incineration
Open Burning
CO
Waste Incineration
Open Burning
NMVOCs
Waste Incineration
Open Burning
135
46
89
2,628
66
2,562
304
23
281
140
48
92
2,668
68
2,600
313
23
290
145
49
96
2,826
69
2,757
326
23
303
142
48
94
2,833
69
2,764
326
20
306
149
50
99
2,914
70
2,844
332
20
312
149
50
99
2,916
72
2,844
333
21
312
Note: Totals may not sum due to independent rounding.
Energy 2-37
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Table 2-33: Municipal Solid Waste Generation (Metric
Tons) and Percent Combusted
Year
Waste Generation
Combusted (%)
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
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
371,316,526
371,316,526
11.5
10.0
11.0
10.0
10.0
10.0
10.0
9.0
7.5
7.0
7.0
7.0
EPA (2003) provided emission estimates for NOx, CO, and NMVOCs
from waste Incineration and open burning.
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 N2O. 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 I.
Ambient air pollutant emission estimates for NOx, CO,
and NMVOCs were determined using industry published
production data and applying average emission factors.
Data Sources
For each of the methods used to calculate CO2 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 26 million metric tons of
MSW were combusted in the United States in 2001
(Goldstein and Madtes 2001). Waste combustion and percent
incinerated for 2001 was assumed to be the same as for 2000.
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 (EPA2000c, 2002a). 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 Scrap Tires, Facts and Figures (STMC
2000,2001,2002).
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 (FEE 2000). Personal
communications with the APC (Eldredge-Roebuck 2000) and
the FEE (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 2002).
The assumption that 98 percent of organic carbon is
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 (EPA2002b).
The N2O emission estimates are based on different data
sources. The N2O emissions are a function of total waste
combusted, as reported in the December 2001 issue of
BioCycle (Goldstein and Matdes 2001). Table 2-33 provides
MSW generation and percentage combustion data for the
total waste stream. The emission factor of N2O emissions per
quantity of MS W combusted was taken from Olivier (1993).
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,
2002a) estimates of materials generated, discarded, and
combusted carry considerable uncertainty associated
with the material flows methodology used to generate
2-38 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
them. Similarly, the BioCycle (Glenn 1999, Goldstein and
Matdes 2000, Goldstein and Matdes 2001) 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 (EPA 2000c, 2002a) and BioCycle (Glenn
1999, Goldstein and Matdes 2000, Goldstein and Matdes
2001)—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.
Missing Data on MSW Composition. Disposal rates
have been interpolated when there is an incomplete
interval within a time series. Where data are not available
for more recent years (2000,2001), they are extrapolated
from the most recent years for which estimates are
available. In addition, the ratio of landfilling to combustion
was assumed to be constant for the entire period (1990 to
2001) based on the 1998 ratio (EPA 2000c, 2002a).
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/Biogenic 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.
Table 2-34: U.S. Municipal Solid Waste Combusted by
Data Source (Metric Tons)
Year EPA BioCycle
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
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
NA
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
24,312,318
25,992,157
25,992,1 57a
NA (Not Available)
a Used 2000 data as proxy, as 2001 data was not yet available.
• 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
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 COr In addition, oil and gas activities also release small
amounts of NOx, CO, and 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
Energy 2-39
-------
Table 2-35: C02 Emissions from Natural Gas Flaring
Year
Tg C02 Eg.
1990
1995
1996
1997
1998
1999
2000
2001
5.5
8.7
8.2
7.6
6.3
6.7
5,5
5.2
5,514
8.729
8,233
7,565
6,250
6,679
5,525
5,179
Table 2-36: NOX, NMVOCs, and CO Emissions from
Oil and Gas Activities (Gg)
Year
NO,
CO
NMVOCs
1990
139
302
555
1995
1996
1997
1998
1999
2000
2001
100
126
130
130
113
115
117
316
321
333
332
152
152
153
582
433
442
440
376
348
357
Table 2-37: Total Natural Gas Reported Vented and Flared
(Million Ft3) and Thermal Conversion Factor (Btu/Ft3)
Thermal
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
Vented and
Flared (original)
150,415
169,909
167,519
226,743
228,336
283,739
272,117
256,351
103,019
110,285
91,232
85,678
Vented and
Flared (revised)*
91,130
92,207
83,363
108,238
109,493
144,265
135,709
124,918
103,019
110,285
91,232
85,678
Conversion
Factor
1,106
1,108
1,110
1,106
1,105
1,106
1,109
1,107
1,109
1,107
1,107
1,105
* Wyoming venting and flaring estimates were revised. See text for
further explanation.
total reported U.S. venting and flaring, approximately 20
percent may be vented, with the remaining 80 percent flared,
but it is now believed that flaring accounts for an even greater
proportion. Methane emissions from venting are accounted
for under Petroleum Systems. For 2001 CO2 emissions from
flaring were estimated to be approximately 5.2Tg CO2 Eq. (5,119
Gg), a decrease of 6 percent since 1990 (see Table 2-35).
Ambient air pollutant emissions from oil and gas
production, transportation, and storage, constituted a
relatively small portion of the total emissions of these gases
from the 1990 to 2001 (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 NOx, 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 2003). 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 (2003). One facility in Wyoming had
been incorrectly reporting CO2 vented as CH4. EIA corrected
these data in the Natural Gas Annual 2000 (EIA 2001) 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 (2003) and are included in Table 2-37.
Emission estimates for NOx, CO, and NMVOCs from
petroleum refining, petroleum product storage and transfer,
and petroleum marketing operations were taken directly from
EPA data published on the National Emission Inventory (NEI)
Air Pollutant Emission Trends web site (EPA 2003). 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 through 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.
2-40 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
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.42 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 (IPCC/UNEP/OECD/IEA1997).43
Greenhouse gases emitted from the combustion of
international bunker fuels, like other fossil fuels, include
CO2, CH4, N2O, CO, NOx, NMVOCs, paniculate matter, and
sulfur dioxide (SO2).44 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.45
Emissions of CO2 from aircraft are essentially a function
of fuel use. Methane, N2O, CO, NOx, and NMVOC
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. In 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.46 At the cruising altitudes of subsonic aircraft,
however, NOx 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.47 The vast majority
of aircraft NOx emissions occur at these lower cruising
altitudes of commercial subsonic aircraft (NASA 1996).48
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 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
42 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).
43 Note that the definition of international bunker fuels used by the UNFCCC differs from that used by the International Civil Aviation Organization.
44 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 United States, 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.
45 Naphtha-type jet fuel was used in the past by the military in turbojet and turboprop aircraft engines.
46 Currently there are only around a dozen civilian supersonic aircraft in service around the world that fly at these altitudes, however.
47 However, at this lower altitude, ozone does little to shield the earth from ultraviolet radiation.
48 Cruise altitudes for civilian subsonic aircraft generally range from 8.2 to 12.5 km (27,000 to 41,000 feet).
Energy 2-41
-------
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 2001 from
the combustion of international bunker fuels from both aviation
and marine activities were 98.3 Tg CO2 Eq., or 14 percent below
emissions in 1990 (see Table 2-38). Although emissions from
international flights departing from the United States have
increased significantly (26 percent), emissions from international
shipping voyages departing the United States have decreased
by 43 percent since 1990. Increased military activity during the
Persian Gulf War resulted in an increased level of military marine
emissions in 1990 and 1991 and again in 1998 with further U.S.
military activity in Iraq; civilian marine emissions during this
period exhibited a similar trend.49 The majority of these
emissions were in the form of CO2; however, small amounts of
CH4 and N2O were also emitted. Emissions of NOx by 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 2-39).
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.50
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 J 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, Annex B, and Annex J. Heat content and density
conversions were taken from EIA (2002) and USAF (1998).
Emission factors used in the calculations of CH4, N2O, CO,
NOx, and NMVOC emissions were obtained from the
Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA
1997). 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 for 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 forN20,1.9 for CO, 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
2002). 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 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. U.S. general aviation aircraft jet
fuel consumption data were obtained from the Federal Aviation
Administration (FAA 1995 through 2002). 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 2002). Approximate average
fuel prices paid by air carriers for aircraft on international
49 See Uncertainty section for a discussion of data quality issues.
50 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).
2-42 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
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Table 2-38: Emissions from International Bunker Fuels (Tg C02 Eq.)
Gas/Mode
1990
C02
Aviation
Marine
CH4
Aviation
Marine
N20
Aviation
Marine
Total
1995
1996
1997 1998
1999 2000 2001
101.0
51.1
49.9
0.1
102.3
52.2
50.1
0.1
109.9
55.9
54.0
0.1
112.9
55.0
57.9
0.1
105.3
58.8
46.4
0.1
99.3
58.4
40.9
0.1
97.3
58.9
38.5
0.1
0.1
0.9
0.5
0.4
0.1
0.9
0.5
0.4
0.1
1.0
0.5
0.4
0.1
1.0
0.5
0.4
0.1
0.9
0.6
0.4
0.1
0.9
0.6
0.3
0.1
0.9
0.6
0.3
115.0
102.1
103.3
111.0 114.0
106.3 100.3 98.3
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to Independent rounding. Includes aircraft cruise altitude emissions.
Table 2-39: Emissions from International Bunker Fuels (Gg)
Gas/Mode
1990
1999 2000 2001
C02
Aviation
Marine
CH4
Aviation
Marine
N20
Aviation
Marine
CO
Aviation
Marine
NO,
Aviation
Marine
NMVOC
Aviation
Marine
Note: Totals may not sum due to independent rounding. Includes aircraft cruise altitude emissions.
flights was taken from DOT (1991 through 2002) 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 2002). 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 2-40. See Annex
J 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 2002). Activity data on distillate diesel consumption
by military vessels departing from U.S. ports were provided
Energy 2-43
-------
Table 2-40: Aviation Jet Fuel Consumption for International Transport (Million Gallons)
Nationality
1990
U.S. Carriers
Foreign Carriers
U.S. Military
1,982
2,062
862
Total
4,905
1995
Note: Totals may not sum due to independent rounding.
1996
1997 1998
1999 2000 2001
2,256
2,549
581
5,385
2,329
2,629
540
5,497
2,482
2,918
493
5,893
2,363
2,935
496
5,793
2,638
3,085
479
6,203
2,740
2,949
469
6,158
2,662
3,034
510
6,206
by DESC (2002). 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 2-41.
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
fuel consumption activity data for international transport
activities separate from domestic transport activities.51 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 2002)
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 2002) 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
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.52
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. Total aircraft and ship fuel use estimates were
developed from DoD records, which document fuel sold to
the Navy and Air Force from the Defense Logistics Agency.
These data may slightly over or under estimate actual total
fuel use in aircraft and ships because each Service may have
procured fuel from, and/or may have sold to, traded with,
and/or given fuel to other ships, aircraft, governments, or
other entities. There are uncertainties in aircraft operations
and training activity data. Estimates for the quantity of fuel
actually used in Navy and Air Force flying activities reported
as bunker fuel emissions had to be 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, which 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 uncertainty
51 See uncertainty discussions under CO2 from Fossil Fuel Combustion and Mobile Combustion.
52 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.
2-44 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
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Table 2-41: Marine Fuel Consumption for International Transport (Million Gallons)
Fuel Type 1990 1995 1996 1997 1998
Residual Fuel Ol!
Distillate Diesel Fuel & Other
U.S. Military Naval Fuels
Total
4,781
617
522
5,920
1999 2000 2001
I 3-495
I 573
1 334
I 4>*02
3,583
456
367
4,406
3,843
421
484
4,748
3,974
627
518
5,119
3,272
308
511
4,091
2,967
290
329
3,586
2,846
204
318
3,368
Note: Totals may not sum due to independent rounding.
associated with jet fuel use for 1997 through 2001. Small
fuel quantities are used in ground vehicles or equipment
rather than in aircraft.
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 using the original set from 1995. 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.
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 (IPCC/UNEP/OECD/IEA 1997). The IPCC also
recommends that cruise altitude emissions be estimated
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 COr53
There is also concern as to the reliability of the existing
DOC (1991 through 2002) 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 COr
However, in the long run the CO2 emitted from biomass
consumption does not increase atmospheric CO2
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 2001, CO2 emissions due to burning of woody biomass
within the industrial and residential/commercial sectors and
by electricity generation were about 173.4 Tg CO2 Eq. (174,991
Gg) (see Table 2-42 and Table 2-43). As the largest consumer
of woody biomass, the industrial sector in 2001 was
responsible for 73 percent of the CO2 emissions from this
source. The residential sector was the second largest emitter,
making up 19 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
53 It should be noted that in the EPA (2003), 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 IPCC-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 (2003) is also likely to include
emissions from ocean-going vessels departing from U.S. ports on international voyages.
Energy 2-45
-------
Table 2-42: C02 Emissions from Wood Consumption by End-Use Sector (Tg C02 Eq.)
End-Use Sector
1990
Industrial
Residential
Commercial
Electricity Generation
115.6
46.4
3.1
9.9
Total
175.0
1995 1996
1997
1998
1999
2000
Note: Totals may not sum due to independent rounding.
Table 2-43: C02 Emissions from Wood Consumption by End-Use Sector (Gg)
End-Use Sector
Industrial
Residential
Commercial
Electricity Generation
Total
1990
115,589
46,424
3,086
9,893
174,991
2001
132.0
47.6
3.7
10.0
193.3
134.5
47.5
4.0
11.0
197.1
128.3
33.1
4.2
11.0
176.6
128.1
30.9
3.8
10.9
173.8
128.3
33.1
4.2
11.0
176.6
130.7
34.6
4.2
10.7
180.3
126.3
32.5
3.4
11.2
173.4
1995
132,006
47,622
3,684
10,021
193,333
1996
134,517
47,542
4,029
11,015
197,104
1997
128,311
33,070
4,179
11,029
176,589
1998
128,120
30,933
3,846
10,923
173,822
1999
128,311
33,070
4,179
11,029
176,589
2000
130,715
34,626
4,247
10,733
180,321
2001
126,280
32,522
3,424
11,200
173,426
Note: Totals may not sum due to independent rounding.
Table 2-44: C02 Emissions from Ethanol Consumption
Year Tg C02 Eq. Gg
1990
4,380
1995
1996
1997
1998
1999
2000
2001
8.1
5.8
7.4
8.1
8.5
9.7
10.2
8,099
5,809
7,356
8,128
8,451
9,667
10,226
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 COr
In 2001, the United States consumed an estimated 147
trillion Btus of ethanol. Emissions of CO2 in 2001 due to ethanol
fuel burning were estimated to be approximately 10.2 Tg CO2
Eq. (10,226 Gg)(see Table 2-44).
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 (EIA 1997). 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 carbon released
from combustion was estimated using 90 percent for the fraction
2-46 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
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 2-45). Estimates of wood biomass
consumption for fuel combustion do not include 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 (IPCC/UNEP/OECD/IEA1997).
Emissions from ethanol were estimated using
consumption data from EIA (2002) (see Table 2-46). The
carbon coefficient used was provided by OTA (1991).
Uncertainty
The fraction oxidized (i.e., combustion efficiency) factor used
is believed to underestimate 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.
hi 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.
Table 2-45: Woody Biomass Consumption by Sector
(Trillion Btu)
Electric
Year Industrial Residential Commercial Generation
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
1,447
1,410
1,461
1,484
1,580
1,652
1,683
1,606
1,603
1,606
1,636
1,580
581
613
645
548
537
596
595
414
387
414
433
407
39
41
44
46
46
46
50
52
48
52
53
43
124
126
140
150
152
125
138
138
137
138
134
140
Table 2-46: Ethanol Consumption
Year
Trillion Btu
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
63
73
83
97
109
117
84
106
117
122
139
147
Energy 2-47
-------
Box 2-4: Formation of C02 Through Atmospheric CH4 Oxidation
Methane emitted to the atmosphere will eventually oxidize into C02, which remains in the atmosphere for up to 200 years. The global warming potential
(GWP) of CH4, however, does not account for the radiative forcing effects of the C02 formation that results from this CH4 oxidation. The IPCC Guidelines
for Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA1997) do not explicitly recommend a procedure for accounting for oxidized CH4, but some of the
resulting C02 is, in practice, included in the inventory estimates because of the intentional "double-counting" structure for estimating COZ emissions from
the combustion of fossil fuels. According to the IPCC Guidelines, countries should estimate emissions of CH4, CO, and NMVOCs from fossil fuel
combustion, but also assume that these compounds eventually oxidize to C02 in the atmosphere. This is accomplished by using C02 emission factors
that do not factor out carbon in the fuel that is released as in the form of CH4, CO, and NMVOC molecules. Therefore, the carbon in fossil fuel is intentionally
double counted, as an atom in a CH4 molecule and as an atom in a C02 molecule.54 While this approach does account for the full radiative forcing effect
of fossil fuel-related greenhouse gas emissions, the timing is not accurate because it may take up to 12 years for the CH4 to oxidize and form C02.
There is no similar IPCC approach to account for the oxidation of CH4 emitted from sources other than fossil fuel combustion (e.g., landfills, livestock,
and coal mining). Methane from biological systems contains carbon that is part of a rapidly cycling biological system, and therefore any carbon created
from oxidized CH4 from these sources is matched with carbon removed from the atmosphere by biological systems - likely during the same or subsequent
year. Thus, there are no additional radiative forcing effects from the oxidation of CH4 from biological systems. For example, the carbon content of CH4 from
enteric fermentation is derived from plant matter, which itself was created through the conversion of atmospheric C02 to organic compounds.
The remaining anthropogenic sources of CH4 (e.g., fugitive emissions from coal mining and natural gas systems, industrial process
emissions) do increase the long-term C02 burden in the atmosphere, and this effect is not captured in the inventory. The following tables provide
estimates for the equivalent C02 production that results from the atmospheric oxidation of CH4 from these remaining sources. The estimates for CH4
emissions are gathered from the respective sections of this report, and are presented in Table 2-47. The C02 estimates are summarized in Table 2-48.
The estimates of C02 formation are calculated by applying a factor of 44/16, which is the ratio of molecular weight of C02 to the
molecular weight of CH4. For the purposes of the calculation, it is assumed that CH4 is oxidized to C02 in the same year that it is emitted. As
discussed above, this is a simplification, because the average atmospheric lifetime of CH4 is approximately 12 years.
Carbon dioxide formation can also result from the oxidation of CO and NMVOCs. However, the resulting increase of C02 in the
atmosphere is 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 and NMVOC counted as C02 emissions in the mass balance.55
Table 2-47: CH4 Emissions from Non-Combustion Fossil Sources (Gg)
Source
Coal Mining
Natural Gas Systems
Petroleum Systems
Petrochemical Production
Silicon Carbide Production
Total
1990
4,149
5,810
1,309
56
1
11,325
1995
1996
1997
1998
1999
2000
2001
3,502
6,059
1,153
72
1
10,786
3,255
6,069
1,138
75
1
10,538
3,244
6,001
1,123
77
1
10,446
3,235
5,903
1,090
78
1
10,308
3,033
5,728
1,029
80
1
9,869
2,902
5,772
1,010
79
1
9,764
2,893
5,588
1,011
71
+
9,563
Note: These emissions are accounted for under their respective source categories. Totals may not sum due to independent rounding.
Table 2-48: Formation of C02 Through Atmospheric CH4 Oxidation (Tg C02 Eq.)
Source
1990
1995
1996
1997
1998
1999
2000
2001
Coal Mining 11.4
Natural Gas Systems 16.0
Petroleum Systems 3.6
Petrochemical Production 0.2
Carbide Production +
9.6
16.7
3.2
0.2
9.0
16.7
3.1
0.2
8.9
16.5
3.1
0.2
8.9
16.2
3.0
0.2
8.3
15.8
2.8
0.2
8.0
15.9
2.8
0.2
8.0
15.4
2.8
0.2
Total
31.1
29.7
29.0
28.7
28.3
27.1
26.9
26.3
Note: Totals may not sum due to independent rounding.
+ Does not exceed 0.05 Tg C02 Eq.
54 It is assumed that 100 percent of the CH4 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).
55 See Annex C for a more detailed discussion on accounting for indirect emissions from CO and NMVOCs.
2-48 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
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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 and urea application, 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, petrochemical production, silicon carbide production, nitric acid production, adipic
acid production, and N2O from product usage (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 HFCs for the substitution of ozone depleting substances 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
Figure 3-1 manufacture, electric power transmission and distribution,
and magnesium metal production and processing. Sulfur
hexafluoride is the most potent greenhouse gas the IPCC
has evaluated.
In 2001, industrial processes generated emissions of
287.6 Tg CO2 Eq., or 4.1 percent of total U.S. greenhouse
gas emissions. Carbon dioxide emissions from all industrial
processeswere 147.9TgCO2Eq.(147,864Gg)in2001. This
amount accounted for only 2.6 percent of national CO2
emissions. Methane emissions from petrochemical and
silicon carbide production resulted in emissions of
approximately 1.5TgCO2Eq. (71 Gg) in 2001, which was 0.2
percent of U.S. CH4 emissions. Nitrous oxide emissions
from adipic acid and nitric acid production and N2O from
product usage were 27.3 Tg CO Eq. (88 Gg) in 2001, or 6.4
2001 Industrial Processes Chapter GHG Sources
Iron and Steel Production
Cement Manufacture
HCFC-22 Production
Nitric Acid
Ammonia Production and Urea Application
Electrical Transmission and Distribution
Lime Manufacture
Aluminum Production
Semiconductor Manufacture
Limestone and Dolomite Use
Adipic Acid
N2O Product Usage
Soda Ash Manufacture and Consumption
Magnesium Production and Processing
Titanium Dioxide Production
Petrochemical Production
Carbon Dioxide Consumption
Ferroalloys
Silicon Carbide Production
g^H^^HB
^^^H|
^^^H
^^H
I^^H
I^H
ff§
f
• Industrial
^^ Processes
H as a Portion of all
H Emissions
• 4.1%
• .
: .-'.f.
i
i
<0.05
0 10 20 30 40 50 60 70
TgC02Eq.
Industrial Processes 3-1
-------
Table 3-1: Emissions from Industrial Processes (Tg C02 Eq.)
Gas/Source
1990
1995 1996 1997
1998
1999
2000 2001
C02
Iron and Steel Production
Cement Manufacture
Ammonia Manufacture & Urea Application
Lime Manufacture
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Aluminum Production
Titanium Dioxide Production
Ferroalloy Production
Carbon Dioxide Consumption
CH4
Petrochemical Production
Silicon Carbide Production
N20
Nitric Acid Production
Adipic Acid Production
N20 Product Usage
HFCs, PFCs, and SF6
Substitution of Ozone Depleting Substances
HCFC-22 Production
Electrical Transmission and Distribution
Aluminum Production
Semiconductor Manufacture
Magnesium Production and Processing
Total
a
169.3 1
85.4 1
33.3 I
19.3 I
11.2 1
5.5 I
4.1 1
6-3 1
1.3 I
2.0 1
0.9 1
1.2 1
1.2 I
+ 1
37.3 I
17-8 1
15.2 1
4.3 1
94.4 1
0.9 1
35.0 •
32.1 I
18.1 1
2.9 I
5.4 1
302.2 1
• 165-7
• 74-4
1 36-8
• 20-5
1 12-8
• 7.0
« 4-3
• 5.3
• 1.7
• 1-9
1 1.1
• 1.5
• 1.5
• +
• 41-6
1 19.9
• 17.2
I 4'5
• 99-5
• 217
• 27-°
I 27-5
• 11-8
• 5'9
• 5.6
161.4
68.3
37.1
20.3
13.5
7.6
4.2
5.6
1.7
2.0
1.1
1.6
1.6
+
42.2
20.7
17.0
4.5
113.6
30.4
31.1
27.7
12.5
5.4
6.5
318.8
166.6
71.9
38.3
20.7
13.7
7.1
4.4
5.6
1.8
2.0
1.2
1.6
1.6
+
36.3
21.2
10.3
4.8
116.8
37.7
30.0
25.2
11.0
6.5
6.3
321.4
165.0
67.4
39.2
21.9
13.9
7.3
4.3
5.8
1.8
2.0
1.2
1.7
1.6
+
31.7
20.9
6.0
4.8
127.6
44.5
40.2
20.9
9.0
7.3
5.8
325.9
161.3
64.4
40.0
20.6
13.5
7.7
4.2
5.9
1.9
2.0
1.2
1.7
1.7
+
30.4
20.1
5.5
4.8
120.3
50.9
30.4
16.4
8.9
7.7
6.0
313.7
160.1
65.8
41.2
19.6
13.3
5.8
4.2
5.4
1.9
1.7
1.2
1.7
1.7
+
29.9
19.1
6.0
4.8
121.0
57.3
29.8
15.4
7.9
7.4
3.2
312.6
147.9
59.1
41.4
16.6
12.9
5.3
4.1
4.1
1.9
1.3
1.3
1.5
1.5
+
27.3
17.6
4.9
4.8
111.0
63.7
19.8
15.3
4.1
5.5
2.5
287.6
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to Independent rounding.
percent of total U.S. N2O emissions. In 2001, combined emissions
of HFCs, PFCs and SF6 totaled 111.0 Tg CO2 Eq. Overall,
emissions from industrial processes decreased by 5 percent
from 1990 to 2001, which was the result of decreases in emissions
from several industrial processes—such as iron and steel,
electrical transmission and distribution, HCFC-22 production,
and aluminum production—which was partially offset by
increases in emissions in other industrial processes, the largest
being substitutes for ozone depleting substances.
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—is believed to be an industrial source of N2O
emissions. However, emissions for this 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.'
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 CO2 equivalents
(Tg CO2 Eq.), while unweighted gas emissions in gigagrams
(Gg) are provided in Table 3-2.
See Annex X for a discussion of emission sources excluded.
3-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-2: Emissions from Industrial Processes (Gg)
Gas/Source
1990
1995 1996 1997 1998 1999 2000 2001
C02 169,346
Iron and Steel Production 85,414
Cement Manufacture 33,278
Ammonia Manufacture & Urea Application 19,306
Lime Manufacture 11,238
Limestone and Dolomite Use 5,470
Soda Ash Manufacture and Consumption 4,141
Aluminum Production 6,315
Titanium Dioxide Production 1,308
Ferroalloy Production 1,980
Carbon Dioxide Consumption 895
CH4 57
Petrochemical Production 56
Silicon Carbide Production 1
N20 120
Nitric Acid Production 58
Adipic Acid Production 49
N20 Product Usage 14
MFCs, PFCs, and SF6 M
Substitution of Ozone Depleting Substances M
HCFC-22 Production3 3
Electrical Transmission and Distribution" 1
Aluminum Production M
Semiconductor Manufacture M
Magnesium Production and Processing11 +
+ Does not exceed 0.5 Gg
M (Mixture of gases)
a HFC-23 emitted
b SF6 emitted
Note: Totals may not sum due to independent rounding.
165,697
74,357
36,847
20,453
12,804
7,042
4,304
5,265
1,670
1,866
1,088
73
72
1
134
64
56
14
M
M
2
1
M
M
161,362
68,324
37,079
20,282
13,495
7,615
4,239
5,580
1,657
1,954
1,138
76
75
1
136
67
55
14
M
M
3
1
M
M
166,589
71,864
38,323
20,650
13,685
7,055
4,354
5,621
1,836
2,038
1,162
78
77
1
117
68
33
15
M
M
3
1
M
M
164,975 161,291
67,429
39,218
21,934
13,914
7,331
4,325
5,792
1,819
2,027
1,186
79
78
1
102
67
19
15
M
M
3
1
M
M
64,376
39,991
20,615
13,466
7,671
4,217
5,895
1,853
1,996
1,210
80
80
1
98
65
18
15
M
M
3
1
M
M
160,072
65,755
41,190
19,587
13,315
5,763
4,181
5,410
1,918
1,719
1,233
80
79
1
96
62
19
15
M
M
3
1
M
M
147,864
59,074
41,357
16,588
12,859
5,281
4,147
4,114
1,857
1,329
1,257
71
71
0
88
57
16
15
M
M
2
1
M
M
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 2001
were 59.1 Tg CO2 Eq. (59,074 Gg). Emissions have fluctuated
significantly from 1990 to 2001 due to changes in domestic
economic conditions and changes in product imports and
exports (see Table 3-3). For the past several years, pig iron
production has experienced a downward trend. Despite
recovering somewhat in 2000, domestic production fell again
in 2001. Pig iron production in 2001 was 12 percent lower
than in 2000 and 18 percent below 1995 levels. A slowdown
in the domestic and worldwide economy and the availability
of low-priced imports limit growth in domestic production
(USGS2001a).
Industrial Processes 3-3
-------
Table 3-3: CO? Emissions from Iron and Steel Production
Year
Tg C02 Eg.
Gg
1990
85.4
85,414
1995
1996
1997
1998
1999
2000
2001
74.4
68.3
71.9
67.4
64.4
65.8
59.1
74,357
68,324
71,864
67,429
64,376
65,755
59,074
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 steelEAF). 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
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.
Data Sources
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 January-
March 2002 (EIA 2002); U.S. Coal Domestic and
International Issues (EIA 2001); Mineral Yearbook: Iron
WS'fe
-------
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 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.
Table 3-4: C02 Emissions from Cement Production*
Year Tg C02 Eq. Gg
1990
33.3
33,278
1995
1996
1997
1998
1999
2000
2001
36.8
37.1
38.3
39.2
40.0
41.2
41.4
36,847
37,079
38,323
39,218
39,991
41,190
41,357
* Totals exclude C02 emissions from making masonry cement from
clinker, which are accounted for under Lime Manufacture.
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 2001, U.S. clinker production—including Puerto
Rico—totaled 79,979 thousand metric tons, and U.S. masonry
cement production was estimated to be 4,450 thousand metric
tons (USGS 2002). The resulting emissions of CO2 from
clinker production were estimated to be 41.4 Tg CO2 Eq.
(41,357 Gg) (see Table 3-4). Emissions from masonry
production from clinker raw material were estimated to be
0.1 Tg CO2 Eq. (100 Gg) in 2001, 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 2001, emissions increased by 24 percent. In
2001, output by cement plants increased by less than 1
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
-------
percent over 2000, to 79,979 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, in 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:
EFr... =0.646 CaO
Clinker
|"44.01g/moleCO
L56.08g/moleCaO
0.507 tons CO2/ton clinker
Table 3-5: Cement Production (Gg)
Year
Clinker
Masonry
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 0.05/(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 in 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.
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,
2000,2001,2002). The data were compiled by USGS through
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
64,355
62,918
63,415
66,957
69,786
71,257
71,706
74,112
75,842
77,337
79,656
79,979
3,209
2,856
3,093
2,975
3,283
3,603
3,469
3,634
3,989
4,375
4,332
4,450
questionnaires sent to domestic clinker and cement
manufacturing plants.
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 kiln. The lime
content of clinker varies from 64 to 66 percent. CKD loss
can range from 1.5 to 8 percent depending upon plant
3-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
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 and Urea
Application
Emissions of 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 C02 emissions.
There are five principal process steps in synthetic ammonia
production from natural gas feedstock. The primary reforming
step converts CH4 to CO2, carbon monoxide (CO), and H2 in the
presence of a catalyst. Only 30 to 40 percent of the CH4
feedstock to the primary reformer is converted to CO and CO2.
The secondary reforming step converts the remaining CH4
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 CH4, including primary and secondary reforming
and the shift conversion processes, is approximately as
follows:
(catalyst)
0.88CH4+1.26Air+1.24H2O->0.88CO2 + N2 + 3H2
N, + 3 H. ->2 NH,
CO(NH2)2 + H2O
Not all of the CO2 produced in the production of
ammonia is emitted directly to the atmosphere. Both ammonia
and carbon dioxide are used as raw materials in the production
of urea [CO(NH2)2], which is another type of nitrogenous
fertilizer that contains carbon as well as nitrogen. The
chemical reaction that produces urea is:
2 NH3 + CO2 -> NH2COONH4
The carbon in the urea that is produced and assumed
to be subsequently applied to agricultural land as a
nitrogenous fertilizer is ultimately released into the
environment as CO2; therefore, the CO2 produced by
ammonia production and subsequently used in the
production of urea does not change overall CO2 emissions.
However, the CO2 emissions are allocated to the ammonia
and urea production processes in accordance to the
amount of ammonia and urea produced.
Net emissions of CO2 from ammonia production in 2001
were 9.1 Tg CO2 Eq. (9,104 Gg). Carbon dioxide emissions
from this source are summarized in Table 3-6. Emissions of
CO2 from urea application in 2001 totaled 7.5 Tg CO2 Eq.
(7,485 Gg). Carbon dioxide emissions from this source are
summarized in Table 3-7.
Table 3-6: CO, Emissions from Ammonia Manufacture
Year
Tg C02 Eq.
Gg
1990
MM
1995
1996
1997
1998
1999
2000
2001
12.6
•i
13.5
13.8
14.0
14.2
12.9
12.1
9.1
12,553
13,546
13,825
14,028
14,215
12,948
12,100
9,104
Table 3-7: C02 Emissions from Urea Application
Year
Tg C02 Eq.
Gg
1990
1995
1996
1997
1998
1999
2000
2001
6.9
6.5
6.6
7.7
7.7
7.5
7.5
6,753
6,907
6,457
6,622
7,719
7,667
7,488
7,485
Industrial Processes 3-7
-------
Table 3-8: Ammonia Production
Year
Thousand Metric Tons
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
15,425
15,576
16,261
15,599
16,211
15,788
16,260
16,231
16,761
15,728
14,342
11,374
Table 3-9: Urea Production
Year
Thousand Metric Tons
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
8,124
7,373
8,142
7,557
7,584
7,363
7,755
7,430
8,042
8,080
6,969
6,199
Methodology
The calculation methodology for non-combustion CO2
emissions from production of nitrogenous fertilizers is based
on a CO2 emission factor published by the European Fertilizer
Manufacturers Association (EFMA). The CO2 emission
factor (1.2 tons CO2/ton NH3) is applied to the total annual
domestic ammonia production. Emissions of CO2 from
ammonia production are then adjusted to account for the
use of some of the CO2 produced from ammonia production
as a raw material in the production of urea. For each ton of
urea produced, 8.8 of every 12 tons of CO2 are consumed
and 6.8 of every 12 tons of ammonia are consumed. The CO2
emissions reported for ammonia production are therefore
reduced by a factor of 0.73 multiplied by total annual domestic
urea production, and that amount of CO2 emissions is
allocated to urea fertilizer application. Total CO2 emissions
resulting from nitrogenous fertilizer production does not
change as a result of this calculation, but some of the CO,
emissions are attributed to ammonia production and some
of the CO2 emissions are attributed to urea application.
The calculation of the total non-combustion CO2 emissions
from nitrogenous fertilizers accounts for CO2 emissions from
the application of imported and domestically produced urea.
For each ton of imported urea applied, 0.73 tons of CO2 are
emitted to the atmosphere. The amount of imported urea applied
is calculated based on the net of urea imports and exports.
All ammonia production and subsequent urea
production was assumed to be from the same process—
conventional catalytic reforming of natural gas feedstock.
Further, ammonia and urea are assumed to be manufactured
in the same manufacturing complex, as both the raw materials
needed for urea production are produced by the ammonia
production process.
Data Sources
The emission factor of 1.2 ton CO2/ton NH3 was taken
from the European Fertilizer Manufacturers Association Best
Available Techniques publication, Production of Ammonia
(EFMA 1995). The EFMA reported an emission factor range
of 1.15 to 1.30 ton CO2/ton NH3, with 1.2 ton CO2/ton NH3 as
a typical value. The EFMA reference also indicates that
more than 99 percent of the CH4 feedstock to the catalytic
reforming process is ultimately converted to CO2. Ammonia
and urea production data (see Table 3-8 and Table 3-9,
respectively) were obtained from the Census Bureau of the
U.S. Department of Commerce (U.S. Census Bureau 1991,
1992,1993,1994,1998,1999,2000,200 la, 200 lb,2002a,2002b,
2002c) as reported in Current Industrial Reports Fertilizer
Materials and Related Products annual and quarterly
reports. Import and export data were obtained from the U.S.
Census Bureau Current Industrial Reports Fertilizer
Materials and Related Products annual reports (U.S. Census
Bureau) for 1997 through 2001, The Fertilizer Institute (TFI
2002) for 1993 through 1996, and the United States
International Trade Commission Interactive Tariff and Trade
DataWeb (U.S. ITC 2002) for 1990 through 1992.
3-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
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
NH3, 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 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, as CO2 emissions from fuel use and non-
energy use are calculated separately.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.
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 CO2/ton NH3,
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
Table 3-10: Urea Net Imports
Year
Thousand Metric Tons
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
1,086
648
656
2,305
2,249
2,055
1,051
1,600
2,483
2,374
3,241
4,008
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 and subsequent urea
production was assumed to be from the same process—
conventional catalytic reforming of natural gas feedstock.
However, actual emissions may differ because processes
other than catalytic steam reformation and feedstocks other
than natural gas may have been used for ammonia
production. Urea is also used for other purposes than as a
nitrogenous fertilizer. It was assumed that 100 percent of
the urea production and net imports are used as fertilizer or
in otherwise emissive uses. It is also assumed that ammonia
and urea are produced at collocated plants from the same
natural gas raw material.
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)
systems at coal-fired electric power plants, construction,
3 It appears, for example, that the IPCC emission factor for ammonia production of 1.5 ton CO2 per ton 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 tons CO2 per ton
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 ton per ton (with a typical value of 1.2 ton
per ton) and an emission factor for fuel CO2 of 0.5 tons per ton. This corresponds to a total CO2 emission factor for the ammonia production
process, including both feedstock CO2 and process heat CO2, of 1.7 ton per ton 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 ton CO2 per ton ammonia reported by the EFMA.
Industrial Processes 3-9
-------
Table 3-11: Net CO, Emissions from Lime Manufacture
Year
Tg C02 Eg.
1990
11.2
1995
1996
1997
1998
1999
2000
2001
12.8
13.5
13.7
13.9
13.5
13.3
12.9
Table 3-12: C02 Emissions from Lime Manufacture (Gg)
Year Potential Recovered* Net Emissions
1990
11,730
(493)
11,238
1995
1996
1997
1998
1999
2000
2001
13,701
14,347
14,649
14,975
14,655
14,548
14,016
(896)
(852)
(964)
(1,061)
(1,188)
(1,233)
(1,156)
12,804
13,495
13,685
13,914
13,466
13,315
12,859
* For sugar refining and precipitated calcium carbonate production
Note: Totals may not sum due to independent rounding.
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 CO during use (see Uncertainty, below).
Lime production in the United States—including Puerto
Rico—was reported to be 18,957 thousand metric tons in 2001
(USGS 2002). This resulted in estimated CO2 emissions of
12.9 Tg CO2 Eq. (12,859 Gg) (see Table 3-11 and Table 3-12).
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, 35
percent; environmental uses, 27 percent; chemical and
industrial uses, 24 percent; and construction uses, 13 percent.
Construction end-uses account for the largest segment of
the hydrated lime market, however, hydrated lime constitutes
less than 10 percent of the total lime market (USGS 2002).
Lime production in 2001 declined 3 percent from 2000,
the third consecutive drop in annual production. Overall,
from 1990 to 2001, lime production increased by 20 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 15 percent in 2001 (USGS 1992,2002).
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 g/moleCO2) - (56.08 g/mole CaO)] x
(0.95 CaO/lime) = 0.75 g CO/g lime
For dolomitic lime:
[(88.02 g/mole C02) - (96.39 g/mole CaO)] x
(0.95 CaO/lime) = 0.87 g CO2/g lime
Precipitated calcium carbonate is a specialty filler used in premium-quality coated and uncoated papers.
3-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Production is adjusted to remove the mass of chemically
combined water found in hydrated lime, 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 18,957 thousand
metric tons in 2001 (USGS 2002), resulting in potential CO2
emissions of 14.0 Tg CO2. Some of the CO2 generated during
the production process, however, was recovered for use in
sugar refining and precipitated calcium carbonate (PCC)
production. Combined lime manufacture by these producers
was 1,939 thousand metric tons in 2001, generating 1.4 Tg
COr It was assumed that approximately 80 percent of the CO2
involved in sugar refining and PCC was recovered, resulting
in actual CO2 emissions of 12.9 Tg CO2.
Data Sources
The activity data for lime manufacture and lime
consumption by sugar refining and PCC production for 1990
through 2001 (see Table 3-13)were obtained from USGS (1992,
1994,1995,1996,1997,1998,1999,2000,2001,2002). TheCaO
and CaOMgO 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 sugar refining and PCC, it was
assumed that 100 percent of lime manufacture and
consumption was high-calcium, based on communication with
the National Lime Association (Males 2003).
Uncertainty
Uncertainties in the emission estimate can be attrib-
uted 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.
Table 3-13: Lime Production and Lime Use for Sugar
Refining and PCC (Thousand Metric Tons)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
High-Calcium
Production*
12,947
12,840
13,307
13,741
14,274
15,193
15,856
16,120
16,750
16,110
15,850
15,730
Dolomite
Production"'5
2,895
2,838
2,925
3,024
3,116
3,305
3,434
3,552
3,423
3,598
3,621
3,227
Use
826
964
1,023
1,279
1,374
1,503
1,429
1,616
1,779
1,992
2,067
1,939
a Includes hydrated limes.
b Includes dead-burned dolomite.
Table 3-14: Hydrated Lime Production
(Thousand Metric Tons)
Year
High-Calcium Hydrate Dolomitic Hydrate
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
1,781
1,841
1,892
1,908
1,942
2,027
1,858
1,820
1,950
2,010
1,550
2,030
319
329
348
342
348
363
332
352
383
298
421
447
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 PCC reacts with CO2; whereas most
of the lime used in steel making 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.
5 Representatives of the National Lime Association estimate that CO2 reabsorption that occurs from the use of lime may offset as much as
a quarter of the CO2 emissions from calcination (Males 2003).
Industrial Processes 3-11
-------
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 mostly 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
quicklime 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.
Table 3-15: C02 Emissions from Limestone & Dolomite Use (Tg C02 Eq.)
Activity
1990
Flux Stone
Glass Making
F6D
Magnesium Production
Other Miscellaneous Uses
Total
1995
1996
1997 1998
1999 2000 2001
5.5
3.7
0.5
1.7
+
1.1
7.0
4.1
0.4
2.0
0.1
1.1
7.6
4.8
0.3
1.5
0.1
0.4
7.1
5.0
0.1
1.3
0.1
0.9
7.3
5.5
+
1.3
0.1
0.8
7.7
2.5
0.4
1.8
0.1
1.0
5.8
2.1
0.1
2.6
0.1
0.5
5.3
+ Does not exceed 0.05 Tg C02 Eq.
Notes: Totals may not sum due to independent rounding. Other miscellaneous uses include chemical stone, mine dusting or acid water treatment,
acid neutralization, and sugar refining.
Table 3-16: C02 Emissions from Limestone & Dolomite Use (Gg)
Activity
1990
1995
1996
1997 1998 1999 2000 2001
Flux Stone
Limestone
Dolomite
Glass Making
Limestone
Dolomite
FGD
Magnesium Production
Other Miscellaneous Uses
Total
2,954
2,554
401
214
189
25
1,433
64
804
5,470
3,709
3,098
610
494
413
81
1,674
41
1,125
7,042
4,052
3,375
677
389
299
90
2,017
73
1,084
7,614
4,803
4,063
741
327
327
+
1,462
73
389
7,055
4,992
4,496
497
123
68
54
1,287
73
856
7,331
5,538
4,499
1,039
+
+
+
1,308
73
752
7,671
2,506
1,885
621
383
383
+
1,847
73
953
5,763
2,062
1,640
422
113
113
+
2,551
53
501
5,281
+ Does not exceed 0.5 Gg.
Notes: Totals may not sum due to independent rounding. Other miscellaneous uses include chemical stone, mine dusting or acid water treatment,
acid neutralization, and sugar refining.
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.
7 Limestone and dolomite are collectively referred to as limestone by the industry, and intermediate varieties are seldom distinguished.
3-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-17: Limestone and Dolomite Consumption (Thousand Metric Tons)
Activity
Flux Stone
Limestone
Dolomite
Glass Making
Limestone
Dolomite
FGD
Other Miscellaneous Uses
1990
1995
1996
1997 1998 1999 2000 2001
8,303
7,042
1,261
1,105
939
166
3,805
2,557
9,069
7,671
1,399
865
679
186
4,583
2,445
10,764
9,234
1,530
743
743
0
3,324
873
11,244
10,218
1,026
268
155
112
2,924
1,935
12,372
10,225
2,147
0
0
0
2,974
1,709
5,567
4,285
1,282
871
871
0
4,199
2,167
4,599
3,728
871
258
258
0
5,799
1,138
NA (Not Available)
Note: "Other miscellaneous uses" includes chemical stone, mine dusting or acid water treatment, acid neutralization, and sugar refining.
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, or as a raw material
in glass manufacturing and magnesium production.
In 2001, approximately 10,923 thousand metric tons of
limestone and 871 thousand metric tons of dolomite were
consumed for these applications. Overall, usage of limestone
and dolomite resulted in aggregate CO2 emissions of 5.3 Tg
CO2 Eq. (5,281 Gg) (see Table 3-15 and Table 3-16). Emissions
in 2001 decreased 8 percent from the previous year and have
decreased 2 percent since 1990.
Methodology
Carbon dioxide emissions were calculated by
multiplying the quantity of limestone or dolomite consumed
by the average carbon content, approximately 12.0 percent
for limestone and 13.2 percent for dolomite (based on
stoichiometry). This assumes that all carbon is oxidized and
released. This methodology was used for flux stone, glass
manufacturing, FGD systems, chemical stone, mine dusting
or acid water treatment, acid neutralization, and sugar refining
and then converting to CO2 using a molecular weight ratio.
Two magnesium production methods were in use in the
United States during 2001. One plant produced magnesium
metal from the dolomitic process, while the only other plant
in the United States produced magnesium from magnesium
chloride (electrolytic reduction). During the dolomitic
process, CO2 emissions during the thermic reduction of
dolomite (CaMg (CO3)2) to magnesium metal vapor was
estimated based on magnesium production capacity and the
magnesium to carbon molar ratio. Capacity fluctuations are
due to variable furnace availability. Operation at maximum
operational capacity is assumed, which results in an
overestimation of emissions. The assumption of emissions
based on the magnesium to carbon molar ratio
underestimates emissions from less than ideal (chemically)
production. According to the reaction stoichiometry, two
carbon molecules are emitted per magnesium molecule.
Data Sources
Consumption data for 1990 through 2001 of limestone
and dolomite used for flux stone, glass manufacturing, FGD
systems, chemical stone, mine dusting or acid water treatment,
acid neutralization, and sugar refining (see Table 3-17) were
obtained from personal communication with Valentine
Tepordei of the USGS regarding data in the Minerals
Yearbook: Crushed Stone Annual Report (Tepordei 2002 and
USGS 1993,1995a, 1995b, 1996a, 1997a, 1998a, 1999a,2000a,
2001 a). The production capacity data for 1990 through 2001
of dolomitic magnesium metal (see Table 3-18) also came from
the USGS (1995c, 1996b, 1997b, 1998b, 1999b,2000b,2001b).
During 1990 and 1992, the USGS did not conduct a detailed
survey of limestone and dolomite consumption by end-use.
Consumption figures for 1990 were estimated by applying the
1991 percentages of total limestone and dolomite use
constituted by the individual limestone and dolomite uses to
the 1990 total use figure. Similarly, the 1992 consumption
figures were approximated by applying an average of the 1991
and 1993 percentages of total limestone and dolomite use
constituted by the individual limestone and dolomite uses to
the 1992 total figure.
Industrial Processes 3-13
-------
Table 3-18: Dolomitic Magnesium Metal Production
Capacity (Metric Tons)
Year
Production Capacity
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
35,000
35,000
14,909
12,964
21,111
22,222
40,000
40,000
40,000
40,000
40,000
29,167
Additionally, each year the USGS withholds certain
limestone and dolomite end-uses due to confidentiality
agreements regarding company proprietary data. On average
between 1990 and 2001 the USGS withheld estimates for two
limestone and dolomite end-uses. For the purposes of this
analysis, emissive end-uses that contained withheld data
were estimated using one of the following techniques: (1)
the value for all the withheld data points for limestone or
dolomite use was distributed evenly to all withheld end-
uses; (2) the average percent of total limestone or dolomite
for the withheld end-use in the preceding and succeeding
years; or (3) the average fraction of total limestone or
dolomite for the end-use over the entire time period.
Finally, 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 for emissive end uses. 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.8
Uncertainty
Uncertainties in this estimate are due, in part, to variations
in the chemical composition of limestone, hi 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. Additionally, there is significant
inherent uncertainty associated with estimating withheld
data points for specific end uses of limestone and dolomite.
Lastly, the uncertainty of the estimates for limestone used
in glass making is especially high. Large fluctuations in
reported consumption exist, reflecting year-to-year changes
in the number of survey responders. 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 a small percent of consumption,
its contribution to the overall emissions estimate is low.
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 three States produce natural soda ash: Wyoming,
California, and Colorado. Of these three States, only Wyoming
has net emissions of CO2. This difference is a result of the
production processes employed in each state.9 During the
8 This approach was recommended by USOS.
9 In California, soda ash is manufactured using sodium carbonate-bearing brines instead of trona ore. To extract the sodium carbonate, the
complex brines are 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
-------
production process used in Wyoming, natural sources of
sodium carbonate are heated and transformed into a crude
soda ash that requires further refining. Carbon dioxide 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 2001, CO2 emissions from the manufacture of soda
ash from trona were approximately 1.5 Tg CO2 Eq. (1,500
Gg). Soda ash consumption in the United States generated
2.6 Tg CO2 Eq. (2,648 Gg) in 2001. Total emissions from this
source in 2001 were 4.1 Tg CO2 Eq. (4,147 Gg) (see Table 3-19
and Table 3-20). Emissions have fluctuated since 1990.
These fluctuations were strongly related to the behavior of
the export market and the U.S. economy. Emissions in 2001
decreased by 1 percent from the previous year, and have
increased overall by less than 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 2001
was glass making, 50 percent; chemical production, 27
percent; soap and detergent manufacturing, 11 percent;
distributors, 6 percent; flue gas desulfurization and pulp
and paper production, 2 percent each; and water treatment
and miscellaneous, 1 percent each (USGS 2002).
The domestic market for soda ash continued to decrease
in 2001, but was partially offset by an increase in exports.
This increase followed the closure of a synthetic soda ash
plant in Japan. Although the United States continues to be
the major supplier of world soda ash, China's soda ash
manufacturing capacity is rapidly increasing. This will likely
cause greater competition in Asian markets in the future.
The world market for soda ash is expected to grow 1.5 to 2
percent annually.
A new major soda ash plant that uses a new feedstock—
nahcolite, a natural sodium bicarbonate found in deposits
in Colorado's Piceance Creek Basin—came online in 2001.
The new facility will have an annual capacity of 900,000
tons of soda ash and began operation in October 2001 (USGS
2001). Part of this production 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.
Table 3-19: C02 Emissions from Soda Ash
Manufacture and Consumption
Year
1990
1995
1996
1997
1998
1999
2000
2001
Tg C02 Eq.
4.1
4.3
4.2
4.4
4.3
4.2
4.2
4.1
Table 3-20: C02 Emissions from Soda Ash
Manufacture and Consumption (Gg)
Year
1990
1995
1996
1997
1998
1999
2000
2001
Manufacture
1,431
1,607
1,587
1,665
1,607
1,548
1,529
1,500
Consumption
2,710
2,698
2,652
2,689
2,718
2,668
2,652
2,648
Total
4,141
4,304
4,239
4,354
4,325
4,217
4,181
4,147
Note: Totals may not sum due to independent rounding.
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 • 2H2O) -> 3Na2CO3 + 5H2O + CO2
[trona] [s°cla ash]
Based on this formula, approximately 10.27 metric tons
of trona are required to generate one metric ton of CO2.
Thus, the 15.4 million metric tons of trona mined in 2001 for
soda ash production (USGS 2002) resulted in CO2 emissions
of approximately 1.5 Tg CO2 Eq. (1,500 Gg).
Once manufactured, most soda ash is consumed in 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
Industrial Processes 3-15
-------
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 3-21) were taken from USGS (1994,
1995,1996, 1997, 1998,1999,2000,2001,2002). 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.
Table 3-21: Soda Ash Manufacture and Consumption
(Thousand Metric Tons)
Year
Manufacture*
Consumption
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
14,700
14,700
14,900
14,500
14,600
16,500
16,300
17,100
16,500
15,900
15,700
15,400
6,530
6,280
6,320
6,280
6,260
6,500
6,390
6,480
6,550
6,430
6,390
6,380
* Soda ash manufactured from trona ore only.
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
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.
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 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 2001, approximately 95 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:
2TJC1 +2O -
4 I *. L
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.
The majority of U.S. TiO2 was produced in the United States
through the chloride process, and a special grade of
petroleum coke is manufactured specifically for this purpose.
Emissions of CO2 from titanium dioxide production in 2001
were 1.9 Tg CO2 Eq. (1,857 Gg), an increase of 42 percent
from 1990 due to increasing production within the industry
(see Table 3-22).
Table 3-22: CO, Emissions from Titanium Dioxide
Year
Tg C02 Eq.
Gg
1990
1.3
1,308
1995
1996
1997
1998
1999
2000
2001
1.7
1.7
1.8
1.8
1.9
1.9
1.9
1,670
1,657
1,836
1,819
1,853
1,918
1,857
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 95
percent of the total production in 2001 was produced using
the chloride process. An emission factor of 0.4 metric tons
3-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
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 2000 (see Table 3-23) were obtained from the U.S.
Geological Survey's (USGS) Minerals Yearbook: Titanium
Annual Report (USGS 1991,1992,1993,1994,1995,1996,1997,
1998,1999,2000,2001). Data for 2001 were obtained from U.S.
Census Bureau (2002) Current Industrial Reports: Titanium
Dioxide, November 2002. Data for the percentage of the
total titanium dioxide production capacity that is chloride
process for 1994 through 2000 were also taken from the USGS
Minerals Yearbook. Percentage chloride process data were
not available for 1990 through 1993, and data from the 1994
USGS Minerals Yearbook were used for these years. Because
a sulfate-process plant closed in September 2001, the chloride
process percentage for 2001 was estimated based on a
discussion with Joseph Gambogi, USGS Commodity Specialist
(2002). The composition data for petroleum coke were
obtained from Onder and Bagdoyan (1993).
Table 3-23: Titanium Dioxide Production
Year
Metric Tons
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
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
1,400,000
1,330,000
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.
Ferroalloy Production
Carbon dioxide is emitted from the production of several
ferroalloys. Ferroalloys are composites of iron and other
elements such as 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 in the United
States. Subsequently, government information disclosure
rules prevent the publication of production data for these
Industrial Processes 3-17
-------
Table 3-24: C02 Emissions from Ferroalloy Production
Year
Tg C02 Eg.
Gg
1990
2.0
1,980
1995
1996
1997
1998
1999
2000
2001
1.9
2.0
2.0
2.0
2.0
1.7
1.3
1,866
1,954
2,038
2,027
1,996
1,719
1,329
Table 3-25: Production of Ferroalloys (Metric Tons)
Ferrosilicon Ferrosilicon Misc. Alloys
Year 25%-55% 56%-95% Silicon Metal (32%-65%)
1990 321,385 109,566 145,744
72,442
1995
1996
1997
1998
1999
2000
2001
184,000
182,000
175,000
162,000
252,000
229,000
167,000
128,000
132,000
147,000
147,000
145,000
100,000
89,000
163,000
175,000
187,000
195,000
195,000
184,000
137,000
99,500
110,000
106,000
99,800
NA
NA
NA
NA (Not Available)
production facilities. Similar to emissions from the
production of iron and steel, CO2 is 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 to COr A
representative reaction equation for the production of
50 percent ferrosilicon is given below:
Fe2O3 + 2SiO2
>2FeSi + 7CO
Emissions of CO2 from ferroalloy production in 2001
were 1.3 Tg CO2 Eq. (1,329 Gg) (see Table 3-24), a 23 percent
reduction from the previous year.
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 1996IPCC Guidelines (IPCC/UNEP/OECD/IEA
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 50 percent silicon ferrosilicon
(2.35 tons CO2/ton of alloy produced) was applied. Additionally,
for ferrosilicon alloys containing 56 to 95 percent silicon, an
emission factor for 75 percent silicon ferrosilicon (3.9 tons CO2
per ton alloy produced) was applied. The emission factor for
silicon metal was assumed to be 4.3 tons CO2/ton 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 the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/
IEA 1997). Ferroalloy production data for 1990 through 2001
(see Table 3-25) were obtained from the U.S. Geological
Survey's (USGS) Minerals Yearbook: Silicon Annual
Report(\JSGS 1991,1992,1993,1994,1995,1996,1997,1998,
1999, 2000, 2001, 2002). Until 1999, the USGS reported
production of ferrosilicon containing 25 to 55 percent silicon
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 3-25).
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.10 Emissions from ferroalloys produced
with coking coal or graphite inputs would be counted in
Emissions and sinks of biogenic carbon are accounted for in the Land-Use Change and Forestry chapter.
3-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
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.
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." 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 already 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.
Table 3-26: C02 Emissions from Carbon
Dioxide Consumption
Year
Tg C02 Eg.
Gg
1990
0.9
895
1995
1996
1997
1998
1999
2000
2001
1.1
1.1
1.2
1.2
1.2
1.2
1.3
1,088
1,138
1,162
1,186
1,210
1,233
1,257
In 2001, CO2 emissions from this source not accounted
for elsewhere were 1.3 Tg CO2 Eq. (1,257 Gg) (see Table
3-26). This amount represents an increase of 2 percent from
the previous year and an increase of 40 percent from
emissions in 1990.
Methodology
Carbon dioxide emission estimates were based on CO2
consumption, and assume that the end-use applications,
except enhanced oil recovery, eventually release 100 percent
of the CO2 into the atmosphere. Carbon dioxide consumption
for uses other than enhanced oil recovery was about 6,287
thousand metric tons in 2001. 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 from this
source are equal to 20 percent of CO2 consumption. The
remaining 80 percent was assumed to 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 3-27) were
obtained from Industrial Gases to 2006, a report published by
the Freedonia Group, Inc. (2002). The Freedonia Group, Inc.
" 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.
Industrial Processes 3-19
-------
Table 3-27: Carbon Dioxide Consumption
Year
Thousand Metric Tons
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
4,476
4,652
4,683
4,935
5,186
5,438
5,690
5,809
5,929
6,048
6,167
6,287
report contains actual data for 2001,1996, and 1992. Data for
1990 through 1991,1993 through 1995,and 1997 through 2000
were obtained by extrapolating the trend created by the 2001,
1996, and 1992 values. The percent of CO2 produced from
natural wells was obtained from Freedonia Group, Inc. (1991).
Uncertainty
Uncertainty exists in the assumed allocation of CO2
produced from fossil fuel by-products (80 percent) and CO2
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. Further research is required
to determine the quantity, if any, that may be recovered.
Petrochemical Production
Methane is released, in small amounts, 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 generated 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.
Aggregate emissions of CH4 from petrochemical
production in 2001 were 1.5 Tg CO2 Eq. (71 Gg) (see Table
3-28), a decrease of 11 percent from the previous year.
Table 3-28: CH4 Emissions from Petrochemical Production
Year Tg C02 Eq. Gg
1990
1.2
56
1995
1996
1997
1998
1999
2000
2001
1.5
1.6
1.6
1.6
1.7
1.7
1.5
72
75
77
78
80
79
71
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,12 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 CH4 emissions, there
were not sufficient data to estimate their emissions.
12 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 (C2H2C12) instead of ethylene dichloride (C2H4C12).
3-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-29: 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
1995
1996
1997 1998
1999 2000 2001
1,524
21,215
7,829
5,166
4,992
1,560
22,217
9,303
5,402
5,280
1,588
23,088
10,324
5,171
5,743
1,610
23,474
11,080
5,183
5,860
1,642
25,118
10,308
5,410
5,303
1,674
24,971
9,866
5,420
5,221
1,583
22,521
9,294
4,277
5,053
Data Sources
Emission factors were taken from the Revised 1996
IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). Annual
production data for 1990 (see Table 3-29) were obtained from
the Chemical Manufacturer's Association Statistical
Handbook (CMA 1999). Production data for 1991 through
2001 were obtained from the American Chemistry Council's
Guide to the Business of Chemistry (2002).
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 CH4 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 reacted with carbon in
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, these emissions are already accounted for under
CO2 from Fossil Fuel Combustion in the Energy chapter.
Emissions of CH4 from silicon carbide production in 2001
(see Table 3-30) were 0.5 GgCH4(0.01 TgC02Eq.).
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 (IPCC/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 2001 (see Table 3-31) were obtained
from the Minerals Yearbook: Volume I-Metals and Minerals,
Manufactured'Abrasives (USGS 1991,1992,1993,1994,1995,
1996,1997,1998,1999,2000,2001,2002).
Table 3-30: CH4 Emissions from
Table 3-31: Production of Silicon Carbide
Year
Metric Tons
Silicon Carbide Production
Year Tg C02 Eq. Gg
1990 + 1
1995 + 1
1996 + 1
1997 + 1
1998 + 1
1999 + 1
2000 + +
+ Does not exceed 0.05 Tg C02 Eq. or 0.5 Gg
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
105,000
78,900
84,300
74^900
84,700
75,400
73,600
68,200
69,800
65,000
45,000
40,000
Industrial Processes 3-21
-------
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.
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.
Approximately 20 percent of 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
atl7.6TgCO2Eq.(56.8Gg)in2001 (seeTable3-32). Emissions
from nitric acid production have decreased 1.4 percent since
1990, with the trend in the time series closely tracking the
changes in production.
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 N2O / metric ton HNO3 for
plants using non-selective catalytic reduction (NSCR)
systems and 9.5 kg N2O / metric ton HNO3 for plants not
equipped with NSCR (Choe et al. 1993). In the process of
destroying NOx, NSCR systems destroy 80 to 90 percent of
the N2O, which is accounted for in the emission factor of 2
kg N2O / metric ton HNO3. An estimated 20 percent of HNO3
plants in the United States are equipped with NSCR (Choe
et al. 1993). Hence, the emission factor is equal to (9.5 x 0.80)
+ (2 x 0.20) = 8 kg N2O per metric ton HNO3.
Data Sources
Nitric acid production data for 1990 (see Table 3-33)
was obtained from Chemical and Engineering News, "Facts
and Figures" (C&EN 2001). Nitric acid production data for
1991 through 2001 (see Table 3-33) were obtained from
Chemical and Engineering News, "Facts and Figures"
(C&EN 2002). The emission factor range was taken from
Choe, etal.( 1993).
Table 3-33: Nitric Acid Production
Year
Thousand Metric Tons
2
Year
1990
1995
1996
1997
1998
1999
2000
2001
r Eiiiiaaiuna nuin muib ni>
Tg C02 Eq.
17.8
19.9
20.7
21.2
20.9
20.1
19.1
17.6
iu riuuubiiun
Gg
57.6
•MBBiililiiimfil
64.2
66.8
68.5
67.4
64.9
61.5
56.8
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
7,196
7,191
7,381
7,488
7,905
8,020
8,351
8,557
8,423
8,115
7,692
7,097
3-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
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.
Table 3-34: N20 Emissions from Adipic Acid Production
Year Tg C02 Eg. Gg
Adipic Acid Production
Adipic acid production is an anthropogenic source of
nitrous oxide (N2O) emissions. Worldwide, few adipic acid
plants exist. The United States is the major producer with three
companies in four locations accounting for approximately one-
third 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.
Food grade adipic acid is also used to provide some foods with
a "tangy" flavor (Thiemems and Trogler 1991). Approximately
90 percent of all adipic acid produced in the United States is
used in the production of nylon 6,6 (CMR 2001).
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 (Thiemens and Trogler
1991). Process emissions from the production of adipic acid
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
1990
15.2
49.0
1995
1996
1997
1998
1999
2000
2001
17.2
17.0
10.3
6.0
5.5
6.0
4.9
55.5
55.0
33.3
19.3
17.7
19.5
15.9
technologies in place and as of 1998, the three major adipic
acid production facilities had control systems in place.13
Only one small plant, representing approximately two percent
of production, does not control forN2O (Reimer 1999).
Nitrous oxide emissions from this source were estimated
to be 4.9 Tg CO2 Eq. (15.9 Gg) in 2001 (see Table 3-34).
National adipic acid production has increased by
approximately 14 percent over the period of 1990 through
2001, to approximately 0.8 million metric tons. At the same
time, emissions have been significantly reduced due to the
widespread installation of pollution control measures.
Methodology
For two production plants, 1990 to 2001 emission estimates
were obtained directly from the plant engineer and account for
reductions due to control systems in place at these plants during
the time series. 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 ofN2O 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 mt ofN2O per metric ton of product. Emissions
are estimated using the following equation:
N2O emissions = [production of adipic acid (mt of
adipic acid)] x [0.3 mtN2O / mt adipic acid] * [1 - (N2O
destruction factor x abatement system utility factor) ]
13During 1997, the N2O emission controls installed by the third plant operated for approximately a quarter of the year.
Industrial Processes 3-23
-------
Table 3-35: Adipic Acid Production
Year
Thousand Metric Tons
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
735
708
723
769
821
830
839
871
862
907
925
835
The "N2O destruction factor" represents the percentage
of N2O emissions that are destroyed by the installed
abatement technology. The "abatement system utility factor"
represents the percentage of time that the abatement
equipment operates during the annual production period.
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 (see Table 3-35)
for 1990 through 2001 were obtained from the American
Chemical Council (ACC 2002). Plant capacity data for 1990
through 1994 were obtained from Chemical and
Engineering News, "Facts and Figures" and "Production
of Top 50 Chemicals" (C&EN 1992,1993,1994,1995). Plant
capacity data for 1995 and 1996 were kept the same as 1994
data. The 1997 plant capacity data were taken from
Chemical Market Reporter "Chemical Profile: Adipic Acid"
(CMR 1998). The 1998 plant capacity data for all four plants
and 1999 plant capacity data for three of the plants were
obtained from Chemical Week, Product focus: adipic acid/
adiponitrile (CW 1999). Plant capacity data for 2000 and
2001 for three of the plants were updated using Chemical
Market Reporter, "Chemical Profile: Adipic Acid" (CMR
2001). Plant capacity data for 1999,2000, and 2001 forthe
one remaining plant was kept the same as 1998. The
emission factor was taken from Thiemens and Trogler
(1991). 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
(Childs2002).
Uncertainty
In order to calculate emissions for the two plants where
emissions were not provided by the plant engineer,
production data on a plant-specific basis was needed.
However, these production data are considered confidential
and were not available from the plants. As a result, plant-
specific production figures for the two plants were calculated
by allocating national adipic acid production using existing
plant capacities. This allocation creates a degree of
uncertainty in the adipic acid production data as all plants
are assumed to operate at equivalent utilization levels as
represented by their capacities.
The emission factor was based on experiments
(Thiemens and Trogler 1991) that attempt to replicate the
industrial process and, thereby, measure the reaction
stoichiometry forN2O 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.
Nitrous Oxide Product Usage
Nitrous oxide is a clear, colorless, oxidizing liquefied
gas, with a slightly sweet odor. Nitrous oxide is produced
by thermally decomposing ammonium nitrate (NH4NO3), a
chemical commonly used in fertilizers and explosives. The
decomposition creates steam (H2O) and N2O by a low
pressure, low-temperature (500°F) reaction. Once the steam
is condensed out, the N2O is purified, compressed, dried,
and liquefied for storage and distribution. Two
manufacturers of N2O exist in the United States (CGA 2002).
Nitrous oxide is primarily used in carrier gases with
oxygen to administer more potent inhalation anesthetics for
general anesthesia and as an anesthetic in various dental
and veterinary applications. As such, it is used to treat
short-term pain, for sedation in minor elective surgeries and
as an induction anesthetic. The second main use of N2O is
as a propellant in pressure and aerosol products, the largest
application being pressure-packaged whipped cream. Small
quantities of N2O are also used in the following applications:
3-24 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
• Oxidizing agent and etchant used in semiconductor
manufacturing;
• Oxidizing agent used, with acetylene, in atomic
absorption spectrometry;
• Production of sodium azide, which is used to inflate
airbags;
• Fuel oxidant in auto racing; and
• Oxidizing agent in blowtorches used by jewelers and
others (Heydorn 1997).
Production of N2O in 2001 was approximately 17.0
thousand metric tons. Nitrous oxide emissions were 4.8 Tg
CO2 Eq. (15.5 Gg) in 2001 (see Table 3-36). Production of
N2O has stabilized over the past decade because medical
markets have found other substitutes for anesthetics, and
more medical procedures are being performed on an
outpatient basis using local anesthetics. The use of N2O as
a propellant for whipped cream has also stabilized due to
the increased popularity of cream products packaged in
reusable plastic tubs.
Methodology
Emissions from N2O product usage were calculated by
first multiplying the total amount ofN2O produced in the United
States by the share of the total quantity of N2O that is used
by each sector. This value was then multiplied by the
associated emissions rate for each sector. After the emissions
were calculated for each sector, they were added together to
obtain a total estimate of N2O product usage emissions.
Emissions were determined using the following equation:
Nitrous Oxide Product Usage Emissions = £. [Total U.S.
Production of Nitrous Oxide] x [Share of Total Quantity
of N2O Usage by Sector] x [Emissions Rate for Sector]
where,
i = each sector
The share of total quantity of N2O usage by sector
represents the share of national N2O produced that is used
by the given sector. For example, in 2001, the medicine/
dentistry industry used an estimated 87 percent of total N2O
produced, followed by food processing propellants at 6
percent. All other categories combined used the remaining 7
percent of the N2O produced (Tupman 2002). This sector
breakdown has changed only slightly over the past decade.
For instance, the small share of N20 usage in the production
Table 3-36: N20 Emissions from Nitrous Oxide Product Usage
Year Tg C02 Eq. GgN20
1990
1995
1996
1997
1998
1999
2000
2001
4.3
4.5
4.5
4.8
4.8
4.8
4.8
4.8
13.9
14.4
14.4
15.5
15.5
15.5
15.5
15.5
of sodium azide has declined significantly during the decade
of the 1990's. Due to the lack of information on the specific
time period of the phase-out in this market sector, it was
assumed that most of the N2O usage for sodium azide
production ceased after 1996, with the majority of its small
share of the market assigned to the larger medical/dentistry
consumption sector. Once the N2O is allocated across these
sectors, a usage emissions rate is then applied for each sector
to estimate the amount of N2O emitted.
Only the medical/dentistry and food propellant sectors
are estimated to release emissions into the atmosphere, and
therefore these sectors are the only usage sectors with
emission rates. For the medicine/dentistry sector, due to
the poor solubility of N2O in blood and other tissues,
approximately 97.5 percent of the N2O is not metabolized
during anesthesia and quickly leaves the body in exhaled
breath. Therefore, an emissions factor of 97.5 percent is
used for this sector (Tupman 2002). For N2O used as a
propellant in pressurized and aerosol food products, none
of the N2O is reacted during the process and all of the N2O is
emitted to the atmosphere resulting in an emissions factor
of 100 percent for this sector (Heydorn 1997). For the
remaining sectors all of the N2O is consumed/reacted during
the process, and therefore the emissions rate is considered
to be zero percent (Tupman 2002).
Data Sources
The 1990 through 1992 and 1996 N2O production data
were obtained from SRI Consulting's Nitrous Oxide, North
America report (Heydorn 1997). These data were provided
as a range. For example, in 1996, Heydorn (1997) estimates
N2O production to range between 13.6 and 18.1 thousand
metric tons. An industry expert was able to provide a
narrower range for 1996 that falls within the production
Industrial Processes 3-25
-------
bounds described by Heydorn (1997). These data are
considered more industry specific and current (Tupman 2002).
The midpoint of the narrower production range (15.9 to 18.1
thousand metric tons) was used to estimate N2O emissions
for years 1993 through 2001.
The 1996 share of the total quantity of N2O used by
each sector was obtained from SRI Consulting's Nitrous
Oxide, North America report (Heydorn 1997). The 1990
through 1995 share of total quantity of N2O used by each
sector was kept the same as the 1996 number provided by
SRI Consulting. The 1997 through 2001 share of total
quantity of N2O usage by sector was obtained from
communication with a N2O industry expert (Tupman 2002).
The emissions rate for the food processing propellant
industry was obtained from SRI Consulting's Nitrous Oxide,
North America report (Heydorn 1997), and confirmed by a
N2O industry expert (Tupman 2002). The emissions rate for
all other sectors was obtained from communication with a
N2O industry expert (Tupman 2002). The emissions rate for
the medicine/dentistry sector was substantiated by the
Encyclopedia of Chemical Technology (Othmer 1990).
Uncertainty
Since plant specific N2O production data is confidential,
emissions are based on national production statistics, which
were provided as a range. Based on the N2O production
ranges described by Heydorn (1997) and Tupman (2002),
uncertainty associated with the production estimate used to
develop industry emissions for 1993 through 2001 are within
Table 3-37: N20 Production (Thousand Metric Tons)
Year
Thousand Metric Tons
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
16.3
15.9
15.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
-20 percent and +7 percent. For 1990 through 1992, the
uncertainty in the production data is ± 3 percent. Information
regarding the industry specific use of N2O is also confidential.
Thus, the predicted share of the total quantity of N2O used
by each sector is somewhat uncertain because it is based on
industry expert opinion. In particular, the exact timeframe for
the market decline in N2O use during sodium azide production
is unknown. The emissions rate for the medicine/dentistry
industry is an estimate also based on industry opinion and
does not have a published source that confirms the percent
of emissions released into the environment.
Substitution of Ozone
Depleting Substances
14 [42 U.S.C § 7671, CAA § 601]
'5 R-404A contains HFC-125, HFC-143a, and HFC-134a.
Hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
are used as alternatives to several classes of ozone-depleting
substances (ODSs) that are being phased out under the terms
of the Montreal Protocol and the Clean Air Act Amendments
of 1990.H Ozone depleting substances—chlorofluorocarbons
(CFCs), halons, carbon tetrachloride, methyl chloroform, and
hydrochlorofluorocarbons (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 3-38 and Table 3-39.
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.15 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 63.7 Tg CO2 Eq. in 2001. This increase was in large
3-26 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-38: Emissions of HFCs and PFCs from ODS Substitution (Tg C02 Eq.)
Gas
1990
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-1433
HFC-236fa
CF4
Others*
Total
1995
1996
1997
1998 1999 2000 2001
0.9
0.1
+
1.3
15.9
0.4
+
4.0
21.7
0.1
+
1.9
21.1
0.8
+
6.6
30.4
0.2
+
2.5
26.2
1.3
0.1
7.5
37.7
0.2
+
3.1
30.0
1.9
0.8
8.5
44.5
0.3
+
3.6
33.9
2.6
1.3
9.1
50.9
0.4
0.1
4.4
37.6
3.4
1.9
9.6
57.3
0.5
0.2
5.2
41.0
4.3
2.3
10.1
63.7
+ Does not exceed 0.05 Tg C02 Eq.
* Others include HFC-152a, HFC-227ea, HFC-4310mee, and PFC/PFPEs, the latter being a proxy for a diverse collection of PFCs and
perfluorapolyethers (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.
Table 3-39: Emissions of HFCs and PFCs from ODS Substitution (Mg)
Gas
1990
HFC-23
HFC-32
HFC-125
HFC-1343
HFC-143a
HFC-236fa
CF4
Others*
+
+
+
564
+
+
+
M
1995
1996
1997 1998
1999 2000 2001
5
+
478
12,232
111
+
+
M
9
3
675
16,211
209
+
+
M
14
7
889
20,166
334
15
+
M
19
11
1,116
23,089
488
120
+
M
26
17
1,289
26,095
676
213
1
M
32
94
1,559
28,906
903
296
1
M
39
240
1,869
31,552
1,142
370
1
M
M (Mixture of Gases)
+ Does not exceed 0.5 Mg
* Others include HFC-152a, HFC-227ea, HFC-4310mee and PFC/PFPEs, the latter being a proxy for a diverse collection of PFCs and
perfluorapolyethers (PFPEs) employed for solvent applications.
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
time. Emissions for each end-use were estimated by applying
annual leak rates and release profiles, which account for the
lag in 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 K.
Industrial Processes 3-27
-------
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.
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 2001, the United States was the third largest producer of
primary aluminum, with 11 percent of the world total (USGS
2002). 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 CO2 and two perfluorocarbons
(PFCs): perfluoromethane (CF4) andperfluoroethane (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
Table 3-40: CO, Emissions from Aluminum Production
Year
Tg C02 Eg.
1990
6.3
6,315
1995
1996
1997
1998
1999
2000
2001
5.3
5.6
5.6
5.8
5.9
5.4
4.1
5,265
5,580
5,621
5,792
5,895
5,410
4,114
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 4.1 Tg CO2 Eq. (4,114 Gg) in 2001 (see
Table 3-40). 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—where it would
otherwise be counted—to avoid double-counting.
In addition to CO2 emissions, the aluminum production
industry is also the second largest source (after
semiconductor manufacturing) 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, the magnitude of emissions for a given level
of production depends on the frequency and duration of these
anode effects. As the anode effects become longer and more
frequent, there is a corresponding rise in emission levels.
Primary aluminum production-related emissions of PFCs
are estimated to have declined 77 percent since 1990. Since
1990, emissions of CF4 and C2F6 have declined 77 and 76
percent, respectively, to 3.6 Tg CO2 Eq. of CF4 (0.6 Gg CF4)
and 0.6 Tg CO2 Eq. of C2F6 (0.1 Gg C2F6) in 2001, as shown in
Table 3-41 and Table 3-42. 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.
U.S. primary aluminum production for 2001—totaling
2,637 thousand metric tons—decreased by 24 percent from
2000. 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 35 percent (USGS 2002).
3-28 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 3-41: PFC Emissions from Aluminum Production
(TgC02Eq.)
Year
CF4
Total
1990
15.8
2.3
18.1
1995
1996
1997
1998
1999
2000
2001
10.5
11.1
9.8
8.1
8.0
7.1
3.6
1.3
1.4
1.2
0.9
0.9
0.8
0.6
11.8
12.5
11.0
9.0
8.9
7.9
4.1
Note: Totals may not sum due to independent rounding.
Table 3-42: PFC Emissions from Aluminum Production (Gg)
Year CFj C2F6
1990
2.4
0.2
1995
1996
1997
1998
1999
2000
2001
1.6
1.7
1.5
1.2
1.2
1.1
0.6
0.1
0.1
0.1
0.1
0.1
0.1
0.1
Methodology
Carbon dioxide is generated during alumina reduction
to aluminum metal following the reaction below:
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 1PCC 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/IEA 1997). 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, production was assumed to be 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 * Anode Effect
Minutes/Cell-Day
where,
S = Slope coefficient
Anode Effect Minutes/Cell-Day = Anode Effect
Frequency x Anode Effect Duration
For 8 out of the 23 U.S. smelters (4 out of the 18 smelters
operating in 2001), smelter-specific slope coefficients based
on field measurements were used. For the remaining smelters,
technology-specific slope coefficients from Good Practice
Guidance and Uncertainty Management in National
Greenhouse Gas Inventories (IPCC 2000) were used. The
slope coefficients were combined with smelter anode effect
data, collected by aluminum companies and reported to the
VAIP, to estimate emission factors overtime. Where smelter-
specific anode effect data were not available (2 out of 23
smelters), industry averages were used. Emissions factors
were multiplied by annual production to estimate annual
emissions at the smelter level. Smelter-specific production
data was available for 20 of the 23 smelters (15 of the 18
smelters operating in 2001); production at the remaining
smelters was estimated based on national aluminum
production and capacity data (USGS). 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 1990 through 1999
and 2001 (see Table 3-43) were obtained from USGS, Mineral
Industry Surveys: Aluminum Annual Report (USGS 1995,1998,
2000,2002). The USGS requested data from the 11 domestic
producers, all of whom responded. Primary aluminum
production data for 2000 were obtained by using information
from VAIP program submittals and from USGS, Mineral
Industry Surveys: Aluminum Annual Report (USGS 2001).
Comparing a subset of smelter specific production data from
EPA's VAIP program and the USGS Mineral Industry Surveys:
Industrial Processes 3-29
-------
Table 3-43: Production of Primary Aluminum
Year
Thousand Metric Tons
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
4,048
4,121
4,042
3,695
3,299
3,375
3,577
3,603
3,713
3,779
3,468
2,637
A Iwninum Annual Report (USGS 2001), it was observed that
in 2000 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 for 2000. The CO2 emission factors
were taken from the Revised 1996IPCC Guidelines (IPCC/
UNEP/OECD/IEA 1997). Emission estimates of PFCs 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 (IAI2000).
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.
Using IPCC Good Practice Guidance Tier 1 methodology,
the overall uncertainty associated with the 2001 CF4 and
C2F6 emissions estimates is ± 16 and ± 18 percent,
respectively, using a 95 percent confidence interval. For the
2000 PFC emission estimates, the uncertainty of the CF4
estimate is estimated to be ± 11 percent and the uncertainty
of the C2F6 estimate is estimated to be ± 13 percent. For the
1991 estimates, the corresponding uncertainties are ± 8
percent and ± 11 percent. For each smelter, uncertainty
associated with the quantity of aluminum produced, the
frequency and duration of anode effects, and the slope factor
was estimated. Error propagation analysis was then applied
to estimate the overall uncertainty of the emissions estimate
for each smelter and for the U.S. aluminum industry as a
whole. The uncertainty of aluminum production estimates
ranged between 1 percent and 25 percent, depending on
whether a smelter's production was reported or estimated.
The uncertainty of the frequency and duration of anode
effects ranged between 2 percent and 78 percent, depending
on whether these parameters were reported or were estimated
using industry-wide averages. Given the limited uncertainty
data on site-specific slope coefficients (i.e., those developed
using IPCC Tier 3b methodology), it was assumed that the
overall uncertainty associated with the slope coefficients
would be similar to that given by the IPCC guidance for
technology-specific slope coefficients. Consequently, the
uncertainty assigned to the slope coefficients ranged
between 7 percent and 35 percent, depending upon the gas
and the smelter technology type. In general, where precise
quantitative information was not available on the uncertainty
of a parameter, a conservative (upper-bound) value was used.
Occasionally, 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 CO2 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 SF6 in
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).
3-30 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
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.
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.16 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 SbClxF , (where x + y = 5), which reacts with
chlorinated 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 (CHC1F2), 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 2001 were estimated to be 19.8
Tg CO2 Eq. (1.7 Gg). This quantity represents a 33 percent
decrease from emissions in 2000, and a 43 percent decrease
from emissions in 1990 (see Table 3-44). Although HCFC-
Table 3-44: HFC-23 Emissions from HCFC-22 Production
Year
1990
1995
1996
1997
1998
1999
2000
2001
Tg C02 Eq.
35.0
27.0
31.1
30.0
40.2
30.4
29.8
19.8
Gg
3.0
2.3
2.7
2.6
3.4
2.6
2.6
1.7
22 production has increased by 10 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 48 percent over the same period, lowering
emissions. Four HCFC-22 production plants operated in
the United States in 2001, two of which used thermal
oxidation to significantly lower (and in at least one case,
virtually eliminate) their HFC-23 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
is based upon measurements at individual HCFC-22
production plants. Plants using thermal oxidation to abate
their HFC-23 emissions monitor the performance of their
oxidizers to verify that the HFC-23 is almost completely
destroyed. The other plants periodically measure HFC-23
concentrations in the output stream using gas
chromotography. This information is combined with
information on quantities of critical feed components (e.g.,
HF) and/or products (HCFC-22) to estimate HFC-23
emissions using a material balance approach. HFC-23
concentrations are determined at the point the gas leaves
the chemical reactor; therefore, estimates also include
fugitive emissions.
16 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]
Industrial Processes 3-31
-------
Table 3-45: HCFC-22 Production
Year
Gg
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
138.9
142.7
149.6
132.4
146.8
154.7
166.1
164.5
182.8
165.5
186.9
152.4
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 3-45.
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 (C3Fg) and perfluorocyclobutane
(c-C4F8) 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, SF6 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,
Table 3-46: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Tg C02 Eq.)
Year
1990
CF4
C2F6
^3^8
HFC-23
SF6
NF3*
Total
1995
1996
1997 1998
1999 2000 2001
1.5
3.2
0.2
0.2
0.8
0.1
5.9
1.4
2.9
0.2
0.2
0.8
0.1
5.4
1.7
3.5
0.2
0.2
1.0
0.2
6.5
1.8
3.9
0.2
0.2
1.0
0.2
7.3
1.9
4.2
0.3
0.3
1.1
0.2
7.7
1.9
4.0
0.2
0.2
1.1
0.2
7.4
1.4
3.0
0.2
0.2
0.7
0.2
5.5
Note: Totals may not sum due to independent rounding.
*NF3 emissions are presented for informational purposes, using a GWP of 8,000, and are not included in totals.
3-32 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
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 2001, total weighted emissions of all fluorinated
greenhouse gases by the U.S. semiconductor industry were
estimated to be 5.5 Tg CO2 Eq. Combined emissions of all
fluorinated greenhouse gases are presented in Table 3-46
and Table 3-47. The rapid growth of this industry and the
increasing complexity of semiconductor products that use
more PFCs in the production process have led to an increase
in emissions of 93 percent since 1990. However, the growth
rate in emissions began to slow in 1997, and emissions
declined by 28 percent between 1999 and 2001. This decline
is due both to a drop in production (with silicon consumption
declining by 21 percent between 2000 and 2001) and 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 2001, 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-
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
and 2001, 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 years 2000 and 2001. The 2000 and 2001 U.S. emissions
estimates were adjusted accordingly.
Chemical-specific emission estimates were based on
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 2001 participant reports.
This assumption is supported by chemical sales information
from previous years and chemical-specific emission factors.
Table 3-47: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Mg)
Year
1990
1995
1996
1997
1998
1999 2000 2001
CF4
C2F6
CaFg
HFC-23
SF6
NF3
111 ijji
167 III
14 III
8 •
17 •
9 jji
m 22g
m 345
m 28
1 17
1 35
1 19
211
318
26
16
32
17
254
383
31
19
39
21
282
424
35
21
43
23
300
452
37
22
46
24
286
431
35
21
44
23
217
326
26
16
31
23
Industrial Processes 3-33
-------
Participants estimate their emissions using a range of
methods. For 2001, 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 (IPCC 2000). The partners with
relatively high emissions typically use the more accurate IPCC
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 Fabs on Disk) database (1996 to 2002).
Estimates of silicon consumed by line-width from 1990
through 1994 were derived from information from VLSI
Research (2001), and the number of layers per line-width
was obtained from International SEMATECH's
International Technology Roadmap: 2000 Update.
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
Sulfur hexafluoride's largest use, 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 15.3 Tg CO2 Eq.
(0.6 Gg) in 2001. This quantity represents a 51 percent decrease
below the estimate for 1990 (see Table 3-48). 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 SF6 emissions.
Table 3-48: SF6 Emissions from Electrical Transmission
and Distribution
Year
Tg C02 Eq.
Gg
1990
32.1
1.3
1995
1996
1997
1998
1999
2000
2001
27.5
27.7
25.2
20.9
16.4
15.4
15.3
1.1
1.2
1.1
0.9
0.7
0.6
0.6
Methodology
The 2001 estimate of SF6 emissions from electrical
equipment, 15.3 Tg CO2 Eq., is comprised of (1) estimated
emissions of approximately 14.6 Tg CO2 Eq. from U.S. electric
power systems, and (2) estimated emissions of approximately
0.7 Tg CO2 Eq. from U.S. electrical equipment manufacturers
(original equipment manufacturers, or OEMs). The 2001
estimate of emissions from electric power systems is based on
the reported 2001 emissions (5.5 Tg CO2) of participating utilities
in EPA's SF6 Emissions Reduction Partnership 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 utilities' emissions are strongly correlated
3-34 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
with their transmission miles. The 2001 emissions estimate for
OEMs of 0.7 Tg CO2 is derived by assuming that manufacturing
emissions equal 10 percent of the quantity of SF6 charged into
new equipment. The quantity of SF6 charged into new
equipment is estimated based on statistics compiled by the
National Electrical Manufacturers Association. (In the absence
of statistics for 2001, the quantity of SF6 used to fill new
equipment in 2001 was assumed to be the same as in 2000.) The
10 percent emission rate is the average of the "ideal" and
"realistic" manufacturing emission rates (4 percent and 17
percent, respectively) identified in a paper prepared under the
auspices of the International Council on Large Electric Systems
(CIGRE) in February 2002 (P. O'Connell, et al. Study Committee
23). Emissions for 1999 and 2000 were estimated similarly.
Because most participating utilities reported emissions
only for 1999 through 2001, 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 1990 through
1998 emissions, aggregate world sales of SF6 (RAND 2000)
for each year from 1990 through 1999 were divided by the
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 electric power systems in 1999, which
was estimated to be 15.8 Tg 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
SF, emissions and SF, sales. Emissions from OEM were
6 6
estimated for 1990-1998 using OEM statistics for this period.
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 total U.S.
emissions from the emissions reported by participants in EPA's
SF6 Emissions Reduction Partnership for Electric Power
Systems, and in extrapolating 1990 through 1998 emissions
from 1999 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 through 2001. In addition, emission rates for utilities
that were not participants, which accounted for approximately
65 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 SF6 as a cover gas to prevent the violent oxidation of
molten magnesium in the presence of air. A dilute gaseous
mixture of SF6 with dry air and/or CO2 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 SF6 used is emitted into the 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 2.5 Tg CO2 Eq. (0.1 Gg)
of SF6 in 2001 (see Table 3-49). This represents a significant
decline from previous years. The decline is attributable to
declines in production, casting, and estimated emission factors.
One of the two primary U.S. producers closed in October 2001.
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
Emission estimates for the magnesium industry incorporate
information provided by industry participants in EPA's SF6
Emission Reduction Partnership for the Magnesium Industry.
These participating companies represent 100 percent of U.S.
primary production and over 80 percent of the casting sector.
Industrial Processes 3-35
-------
Table 3-49: SF6 Emissions from Magnesium Production
and Processing
Year
Tg C02 Eg.
1990
5.4
0.2
1995
1996
1997
1998
1999
2000
2001
5.6
6.5
6.3
5.8
6.0
3.2
2.5
0.2
0.3
0.3
0.2
0.3
0.1
0.1
The 1999 through 2001 emissions from primary production,
some secondary production, and a large fraction of die casting
were reported by participants. The 1999 through 2001 emissions
from the remaining secondary production and casting were
estimated by multiplying industry emission factors (kg SF6per
metric ton of Mg produced or processed) by the amount of
metal produced or consumed in the five major processes (other
than primary production) that require SF6 melt protection; 1)
secondary production, 2) die casting, 3) gravity casting, 4)
wrought products and, 5) anodes. The emission factors are
provided in Table 3-50. Because there were less than three
primary producers in the United States in 2001, the emission
factor for primary production is withheld to protect production
information. However, the emission factor has not risen above
the 1995 value of 1.1 kg per metric ton.
The 1999 through 2001 emission factors for die casting,
which is believed to account for about half of non-primary U.S.
SF6 emissions, were derived from information from industry
participants. The average 2001 emission factor for die casting
was estimated to be 0.74 kg SF6 per metric ton of magnesium
cast. However, to estimate total U.S. emissions from die-casting,
it was assumed that die casters who did not provide information
were similar to participants who cast small parts, with an average
emission factor of 5.2 kg SF6 per metric ton of magnesium. The
emission factors for the other industry sectors were based on
discussions with industry representatives.
To estimate 1990 to 1998 emissions, industry emission
factors were multiplied by the corresponding metal production
and consumption statistics from USGS. The primary production
emission factors were 1.1 kg per metric ton in both 1994 and
1995, and the die casting factor was 4.1 kg per metric ton. It was
assumed that these emission factors had remained constant
Table 3-50: SF6 Emission Factors (kg SF6 per metric ton
of magnesium)
Year Secondary Die Casting Gravity Wrought Anodes
1999 1
2000 1
2001 1
2.14
0.71
0.74
2 1
2 1
2 1
1
1
1
throughout the early 1990s. However, it was assumed that
after 1996 the emission factors for primary production and die
casting declined linearly to the level estimated based on Partner
reports. This assumption is consistent with the trend in sales
to the magnesium sector that is reported in the RAND survey
of major SF6 manufacturers, which shows a decline of 70 percent
between 1996 and 1999 (RAND 2000). The emission factors for
the other processes, about which less is known, were assumed
to remain constant.
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. U.S.magnesiummetalproduction(primaryandsecondary)
and consumption (casting) data from 1990 to 2001 are available
from the USGS.17 Emission factors from 1990 to 1998 were based
on a number of sources. Emission factors for primary production
were available from U.S. primary producers for 1994 and 1995,
and an emission factor for die casting was available for the mid-
1990s from an international survey (Gjestland & Magers 1996).
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 cause some
gas degradation. EPA is currently pursuing a measurement
campaign in cooperation with magnesium producers and
processors to ascertain the extent of such 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
cover gas 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.
See .
3-36 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Box 3-1: Potential Emission Estimates of HFCs, 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 consumption 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.
Table 3-51 presents potential emission estimates for HFCs and PFCs from the substitution of ozone depleting substances, HFCs,
PFCs, and SF6 from semiconductor manufacture, and SF6 from magnesium production and processing, and electrical transmission and
distribution.18 Potential emissions associated with the substitution for ozone depleting substances were calculated through a combina-
tion of the EPA's Vintaging Model and information provided by U.S. chemical manufacturers. Estimates of HFCs, PFCs, and SF6
consumed by semiconductor manufacture were developed by dividing chemical-by-chemical emissions by the appropriate chemical-
specific emission factors from the IPCC Good Practice Guidance (Tier 2c). Estimates of CF4 consumption were adjusted to account for
the conversion of other chemicals into CF4 during the semiconductor manufacturing process, again using the default factors from the
IPCC Good Practice Guidance. U.S. utility purchases of SF6 for electrical equipment from 1999 through 2001 were estimated based on
reports by participants in EPA's SF6 Emission Reduction Program for Electric Power Systems. U.S. utility purchases of SF6 for electrical
equipment from 1990 through 1998 were backcasted based on world sales of SF6 to utilities. Purchases of SF6 by utilities were added to
SF6 purchases by electrical equipment manufacturers to obtain total SF6 purchases by the electrical equipment sector.
Table 3-51: 2001 Potential and Actual Emissions of HFCs, PFCs, and
SF6 from Selected Sources (Tg C02 Eq.)
Source Potential Actual
Substitution of Ozone Depleting Substances 224.7 63.7
Aluminum Production - 4.1
HCFC-22 Production - 19.8
Semiconductor Manufacture 8.1 5.5
Magnesium Production and Processing 2.5 2.5
Electrical Transmission and Distribution 24.1 15.3
- Not applicable.
See Annex X for a discussion of sources of SF6 emissions excluded from the actual emissions estimates in this report.
Industrial Processes 3-37
-------
Table 3-52: NOX, CO, and NMVOC Emissions from Industrial Processes (Gg)
Gas/Source
1990
1995
607
144
89
5
362
7
3,958
1,109
2,159
22
566
102
2,643
599
113
1,499
409
23
1996
596
113
75
14
393
1
3,016
954
1,451
64
509
39
1,997
352
66
1,174
395
10
1997
629
115
81
15
417
1
3,153
971
1,551
64
528
38
2,038
352
71
1,205
397
13
1998
637
117
81
15
424
1
3,163
981
1,544
65
535
38
2,047
357
71
1,204
402
13
1999
605
102
79
9
415
1
2,145
326
1,118
145
517
39
1,890
265
60
1,104
449
12
2000
631
104
82
9
435
1
2,214
335
1,155
151
536
37
1,845
269
62
1,039
465
11
2001
662
106
87
10
458
1
2,327
346
1,230
158
556
37
1,829
277
65
1,043
434
10
NOX 591
Chemical & Allied Product
Manufacturing 152
Metals Processing 88
Storage and Transport 3
Other Industrial Processes 343
Miscellaneous* 5
CO 4,124
Chemical & Allied Product
Manufacturing 1,074
Metals Processing 2,395
Storage and Transport 69
Other Industrial Processes 487
Miscellaneous* 101
NMVOCs 2,426
Chemical & Allied Product
Manufacturing 575
Metals Processing 111
Storage and Transport 1,356
Other Industrial Processes 364
Miscellaneous* 20_
* Miscellaneous includes the following categories: catastrophic/accidental release, other combustion, health services, cooling towers, and fugitive
dust. It does not include agricultural fires or slash/prescribed burning, which are accounted for under the Reid Burning of Agricultural Residues source.
Note: Totals may not sum due to independent rounding.
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 2001 are reported in
Table 3-52.
Methodology and Data Sources
The emission estimates for this source were taken
directly from the EPA (2003). 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.
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.
3-38 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
lir 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—41 percent in 2001—while "non-industrial"2
uses accounted for about 38 percent and degreasing applications for 7 percent. Overall, solvent use accounted for
approximately 28 percent of total U.S. emissions of NMVOCs in 2001, and has decreased 13 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, non-industrial uses (i.e., uses of paint
thinner, etc.), and solvent utilization NEC. 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 2001 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-specific emission factors to the amount 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 (MFCs) 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
1990
1995
1996
1997 1998 1999 2000 2001
3
1
2
3
1
2
3
1
2
3
1
2
3
+
3
3
+
3
3
+
3
NOX 1
Degreasing +
Graphic Arts +
Dry Cleaning +
Surface Coating 1
Other Industrial Processes3 +
Non-Industrial Processes" +
Other NA
CO 4
Degreasing +
Graphic Arts +
Dry Cleaning +
Surface Coating +
Other Industrial Processes3 4
Non-Industrial Processes'1 +
Other NA
NMVOCs 5,217
Degreasing 675
Graphic Arts 249
Dry Cleaning 195
Surface Coating 2,289
Other Industrial Processes3 85
Non-Industrial Processes" 1,724
Other +_
3 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.
46
45
44
1
1
3
NA
5,609
716
307
209
2,432
87
1,858
+
+
1
+
+
4,969
546
261
140
2,155
96
1,768
3
+
1
+
+
5,100
566
266
148
2,228
100
1,790
3
+
1
+
+
4,671
337
272
151
1,989
101
1,818
3
+
46
+
+
4,533
360
222
265
1,851
94
1,701
40
+
45
+
+
4,422
318
224
268
1,782
99
1,690
41
+
44
+
+
4,584
334
230
274
1,878
104
1,721
43
Data Sources
The emission estimates for this source were taken
directly from EPA data published on the National Emission
Inventory (NEI) Air Pollutant Emission Trends web site (EPA
2003). 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
EPA's Compilation of Air Pollutant Emission Factors, AP-
42 (EPA 1997). 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.
Uncertainty
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: 1990-2001
-------
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
Figure 5-1
2001 Agriculture Chapter GHG Sources
Agricultural Soil
Management
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Residue
Burning
Agriculture as
a Portion of all
Emissions
6.8%
1.2
management, rice cultivation, agricultural soil
management, and field burning of agricultural residues
(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. Carbon dioxide emissions from on-farm
energy use are accounted in the Energy chapter.
In 2001, agricultural activities were responsible for
emissions of 474.9 Tg CO2 Eq., or 6.8 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 19 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 CH4. Rice cultivation and
agricultural crop residue burning were minor sources of CH4. Agricultural soil management activities such as fertilizer
application and other cropping practices were the largest source of U.S. N2O emissions, accounting for 69 percent. Manure
management and field burning of agricultural residues were also small sources of N2O emissions.
Table 5-1 and Table 5-2 present emission estimates for the Agriculture chapter. Between 1990 and 2001, CH4 emissions
from agricultural activities increased by 3.3 percent while N2O emissions increased by 10.1 percent. In addition to CH4
and N2O, field burning of agricultural residues was also a minor source of the ambient air pollutants carbon monoxide
(CO) and nitrogen oxides (NO ).
o o o o o
i/> o m o
Tg CQ, Eq
Agriculture 5-1
-------
Table 5-1: Emissions from Agriculture (Tg C02 Eq.)
Gas/Source
1990
CH4
Enteric Fermentation
Manure Management
Rice Cultivation
Field Burning of Agricultural Residues
N20
Agricultural Soil Management
Manure Management
Field Burning of Agricultural Residues
_
441.0
1995 1996 1997 1998 1999 2000 2001
Note: Totals may not sum due to independent rounding.
167.4
123.0
36.2
7.6
0.7
301.0
284.1
16.6
0.4
468.4
163.1
120.5
34.9
7.0
0.7
310.6
293.2
17.0
0.4
473.7
163.1
118.3
36.6
7.5
0.8
315.9
298.2
17.3
0.4
479.0
164.4
116.7
39.0
7.9
0.8
316.9
299.2
17.3
0.5
481.3
164.5
116.6
38.9
8.3
0.8
314.8
297.0
17.4
0.4
479.3
162.2
115.7
38.2
7.5
0.8
312.9
294.6
17.9
0.5
475.1
162.1
114.8
38.9
7.6
0.8
312.8
294.3
18.0
0.5
474.9
Table 5-2: Emissions from Agriculture (Gg)
Gas/Source
1990
CH4
Enteric Fermentation
Manure Management
Rice Cultivation
Field Burning of Agricultural Residues
N20
Agricultural Soil Management
Manure Management
Field Burning of Agricultural Residues
Note: Totals may not sum due to independent rounding.
1995 1996 1997 1998 1999 2000 2001
7,972
5,855
1,723
363
31
971
916
53
1
7,765
5,737
1,661
332
36
1,002
946
55
1
7,768
5,635
1,741
356
36
1,019
962
56
1
7,829
5,557
1,858
376
37
1,022
965
56
1
7,834
5,551
1,852
395
36
1,015
958
56
1
7,723
5,509
1,820
357
37
1,009
950
58
1
7,718
5,468
1,850
364
36
1,009
949
58
1
Enteric Fermentation
Methane 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 CH4 as a by-product,
which can be exhaled or eructated by the animal. The amount
of CH4 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 CH4 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
CH4 emissions among all animal types.
Non-ruminant domesticated animals (e.g., swine, horses,
and mules) also produce CH4 emissions through enteric
fermentation, although this microbial fermentation occurs
in the large intestine. These non-ruminants emit significantly
less CH4 on a per-animal basis than ruminants because the
capacity of the large intestine to produce CH4 is lower.
In addition to the type of digestive system, an animal's
feed quality and feed intake also affects CH4 emissions.
In general, a lower feed quality and a higher feed intake
leads to higher CH4 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.
Methane emission estimates from enteric fermentation
are provided in Table 5-3 and Table 5-4. Total livestock
CH4 emissions in 2001 were 114.8 Tg CO2 Eq. (5,468 Gg),
decreasing slightly since 2000 due to minor decreases in
animal populations. Beef cattle remain the largest
contributor of CH4 emissions from enteric fermentation,
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
Beef Cattle
Dairy Cattle
Horses
Sheep
Swine
Goats
Total
1990
83.2
28.9
1.9
1.9
1.7
0.3
117.9
1995
1996
1997 1998
1999
2000
Note: Totals may not sum due to independent rounding.
Table 5-4: CH4 Emissions from Enteric Fermentation (Gg)
Livestock type
Beef Cattle
Dairy Cattle
Horses
Sheep
Swine
Goats
Total
1990
3,961
1,375
91
91
81
13
5,612
1995
1996
1997
1998
1999
2000
2001
89.7
27.7
1.9
1.5
1.9
0.2
123.0
88.8
26.3
1.9
1.4
1.8
0.2
120.5
86.6
26.4
2.0
1.3
1.8
0.2
118.3
85.0
26.3
2.0
1.3
2.0
0.2
116.7
84.7
26.6
2.0
1.2
1.9
0.2
116.6
83.5
27.0
2.0
1.2
1.9
0.2
115.7
82.7
26.9
2.0
1.2
1.9
0.2
114.8
2001
4,272
1,320
92
72
88
11
5,855
4,227
1,254
93
68
84
10
5,737
4,124
1,255
93
64
88
10
5,635
4,046
1,251
94
63
93
10
5,557
4,035
1,266
93
58
90
10
5,551
3,976
1,284
94
56
88
10
5,509
3,936
1,282
95
56
88
10
5,468
Note: Totals may not sum due to independent rounding.
accounting for 72 percent in 2001. Emissions from dairy
cattle in 2001 accounted for 23 percent, and the remaining 5
percent was from horses, sheep, swine, and goats.
From 1990 to 2001, emissions from enteric fermentation
have decreased by 3 percent. Generally, emissions have been
decreasing since 1995, mainly due to decreasing populations
of both beef and dairy cattle and improved feed quality for
feedlot cattle. During this timeframe, populations of sheep
and goats have also decreased, while horse populations
increased and the populations of swine fluctuated.
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 CH4 emissions
from livestock in the United States. Cattle production
systems in the United States are better characterized in
comparison with other livestock production systems. A more
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 CH4 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 Stockers
• 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 L. These variables include
performance factors such as pregnancy and lactation as well
as average weights and weight gain.
Diet characteristics were estimated by region for U.S.
dairy, beef, and feedlot cattle. These estimates were used to
calculate Digestible Energy (DE) values and CH4 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 Y values were based on contact
m
with state agricultural extension specialists, a review of
published forage quality studies, expert opinion, and
modeling of animal physiology. See Annex L for more
details on the method used to characterize cattle diets in the
United States.
In order to estimate CH4 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
differences in CH4 emissions from these animal types. Cattle
diet characteristics were used to develop regional emission
factors for each sub-category. Tier 2 equations from IPCC
(2000) were used to produce CH4 emission factors for the
following cattle types: dairy cows, beef cows, dairy
replacements, beef replacements, steer stockers, heifer
stockers, steer feedlot animals, and heifer feedlot animals.
To estimate emissions from cattle, population data were
multiplied by the emission factor for each cattle type. More
details are provided in Annex L.
Emission estimates for other animal types were based
on average emission factors representative of entire
populations of each animal type. Methane emissions from
these animals accounted for a minor portion of total CH4
emissions from livestock in the United States from 1990
through 2001. Also, the variability in 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 L for more detailed information on the
methodology and data used to calculate CH4 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,b, 1999a,c,d,f, 2000a,c,d,f,
2001a,c,d,f, 2002a,c,d,f). Diet characteristics were used to
develop DE and Ym values for cattle populations. Diet
characteristics for dairy cattle were from Donovan (1999),
while beef cattle were derived from NRC (2000). DE and
Ym for dairy cows 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. For grazing beef cattle, DE values were
based on diet information in NRC (2000) and Ym values
were based on Johnson (2002). Weight data were estimated
from Feedstuff's (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, 1998, 1999b,e,2000b,e,2001b,e,2002b,e). Horse
data were obtained from the Food and Agriculture
Organization (FAO) statistical database (FAO 2002).
Methane emissions from sheep, goats, swine, and horses
were estimated by using emission factors utilized in Crutzen
et al. (1986, cited in IPCC/UNEP/OECD/IEA 1997). 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 determining an emission factor for all
5-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
possible cattle sub-groupings and diet characterizations in the
United States is not possible, the 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, the values
supporting the development of emission factors for the animal
types studied are more appropriate for the situation in the
United States than the IPCC recommended values.
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, the
model characterizes the changes in U.S. cattle population and
captures potential differences related to the emission factors
used for different animal types.
The values for Ym and DE reflect the diet charac-
terizations that are assumed for each cattle group, within
each region of the country. While these values try to reflect
the general diet characteristics within each region, there is
uncertainty associated with local variations in feed and in
the way cattle feed intake is managed.
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 CH4 and 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/
slurry 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. Ambient temperature, moisture,
and manure storage or residency time affect the amount of
CH4 produced because they influence the growth of the
bacteria responsible for CH4 formation. For example, CH4
production generally increases with rising temperature and
residency time. Also, 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 CH4 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. 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.
However, some higher energy feeds also are more digestible
than lower quality forages, which can result in less overall
waste excreted from the animal. Ultimately, a combination
of diet characteristics and the growth rate of the animals
will affect the total manure produced.
A very small portion of the total nitrogen excreted is
expected to convert to N2O in the waste management system.
The production of N2O from livestock manure depends on
the composition of the manure and urine, the type of bacteria
Agriculture 5-5
-------
involved in the process, and the amount of oxygen and liquid
in the manure system. For 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 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 N2O 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 CH4 emissions in 2001 were 38.9
Tg CO2 Eq. (1,850 Gg), 24 percent higher than in 1990.
The majority of this increase was from swine and dairy cow
manure, which increased 31 and 32 percent respectively,
and is attributed to shifts by the swine and dairy industries
towards larger facilities. Larger swine and dairy farms tend
to use liquid systems to manage (flush or scrape) 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 CH4 conversion factor (MCF) values calculated
from the 1992 and 1997 farm-size distribution reported in
the Census of Agriculture (USDA 1999e). From 2000 to
2001, there was a 1.8 percent increase in CH4 emissions,
due to minor shifts in the 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. A description of the emission
estimation methodology is provided in Annex M.
Total N2O emissions from manure management systems
in 2001 were estimated to be 18.0 Tg CO2 Eq. (58.0 Gg).
The 11 percent increase in N2O emissions from 1990 to 2001
can be partially attributed to a shift in the poultry industry
away from the use of liquid manure management systems,
in favor of litter-based systems and high rise houses. In
addition, there was an overall increase in the population of
poultry and swine from 1990 to 2001, although swine
populations declined slightly in 1993, 1995, 1996, 1999,
and 2000 from previous years and poultry populations
decreased in 1995 and 2001 from previous years. Nitrous
oxide emissions showed a 0.6 percent increase from 2000
to 2001, due to minor shifts in animal population.
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 a steady level of 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
The methodologies presented in Good Practice
Guidance and Uncertainty Management in National
Greenhouse Gas Inventories (IPCC 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 CH4 producing potential is realized
for each type of manure management system (by state
and manure management system);
5-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 5-5: CH4 and N20 Emissions from Manure Management (Tg C02 Eq.)
Gas/Animal Type
1990
1995
1996
1997
1998
1999
CH4
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
NZ0
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
Total
31.3
11.4
3.4
13.1
0.1
+
2.7
0.6
16.2
4.3
4.9
0.4
+
+
6.3
0.2
47.5
2.6
0.6
16.6
4.1
5.3
0.4
2.6
0.6
17.0
4.0
5.1
0.4
2.7
0.6
17.3
4.0
5.4
0.4
2.7
0.6
17.3
3.9
5.5
0.5
2.6
0.6
17.4
4.0
5.5
0.4
+ 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
1990
CH4
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
N20
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
1,490
545
161
623
3
1
128
29
52
14
16
1
+
+
21
1
1995
1996
1997
1998
1999
+ Does not exceed 0.5 Gg.
Note: Totals may not sum due to independent rounding.
2000
2.6
0.6
17.9
4.0
5.9
0.4
2000
2001
36.2
13.4
3.5
16.0
0.1
34.9
12.8
3.5
15.3
+
36.6
13.4
3.4
16.4
+
39.0
13.9
3.3
18.4
+
38.9
14.7
3.3
17.6
+
38.2
14.6
3.3
17.1
+
38.9
15.1
3.3
17.1
+
2.7
0.6
18.0
3.9
6.1
0.4
6.5
0.2
52.8
7.2
0.2
51.9
7.2
0.2
53.9
7.2
0.2
56.3
7.2
0.2
56.3
7.4
0.2
56.1
7.3
0.2
56.9
2001
1,723
640
164
763
2
1
124
29
53
13
17
1
1,661
611
164
729
2
1
125
29
55
13
17
1
1,741
639
161
781
2
1
127
29
56
13
17
1
1,858
661
158
876
2
1
130
30
56
13
18
1
1,852
700
158
838
2
1
124
29
56
13
18
1
1,820
693
157
813
2
1
125
30
58
13
19
1
1,850
719
155
815
2
1
128
30
58
13
20
1
21
1
23
1
23
1
23
1
23
1
24
1
24
1
• Portion of manure managed in each manure
management system (by state and animal type); and
• 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 (ERG
2000a, EPA 2001a, 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
default IPCC factors (IPCC 2000). MCFs for liquid/slurry,
Agriculture 5-7
-------
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 M 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 using the volatile
solids (VS) production for all livestock. For poultry and
swine animal groups, for example, 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 most cattle groups, regional animal-specific VS
production rates that are related to the diet of the animal for
each year of the inventory were used (Peterson et al., 2002).
The resulting VS for each animal group was then multiplied
by the maximum CH4 producing capacity of the waste (Bo),
and the state-specific CH4 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.
See Annex M for more detailed information on the
methodology and data used to calculate CH4 and N2O
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, 2002a-f). Horse population data were obtained
from the FAOSTAT database (FAO 2002). 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 2001 a, 2001 b). 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; EPA 200 la, 200 Ib). 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 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,
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
-------
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 (NOAA 2001, 2002), 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 2001 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 CH4 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.
Nitrogen excretion rate data from the USDA Agricultural
Waste Management Field Handbook (USDA 1996a) were
used for all livestock except sheep, goats, and horses. Data
from the American Society of Agricultural Engineers (AS AE
1999) were used for these animal types. Volatile solids
excretion rate data from the USDA Agricultural Waste
Management Field Handbook (USDA 1996a) were used for
swine, poultry, bulls, and calves not on feed. In addition,
volatile solids production rates from Peterson et al., 2002 were
used for dairy and beef cows, heifers, and steer for each year
of the inventory. Nitrous oxide emission factors and MCFs
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 CH4 generating characteristics of each
type of manure management system. Because of significant
shifts in 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 CH4 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 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.
Agriculture 5-9
-------
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 CH4
at different rates, and would in all likelihood produce N2O
at different rates, although a single N2O emission factor 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
beef and dairy cows, heifers, and steer, further research is
needed to confirm and track diet changes over time. 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
CH4 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.
An uncertainty analysis was conducted on the manure
management inventory considering the issues described
above and based on published data from scientific and
statistical literature, the IPCC, and experts in the industry.
The results of the uncertainty analysis showed that the
manure management CH4 inventory has a 95 percent
confidence interval of-18 percent to 20 percent around the
inventory value, and the manure management N2O inventory
has a 95 percent confidence interval of-16 percent to 24
percent around the inventory value.
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, CH4 is produced through anaerobic
decomposition of soil organic matter by methanogenic
bacteria. As much as 60 to 90 percent of the CH4 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 CH4 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 CH4 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 shallow flooding
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 CH4 to oxidize
but also inhibits further CH4 production in soils. All rice in
5-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 5-7: CH4 Emissions from Rice Cultivation (Tg C02 Eq.)
State
1990
Primary
Arkansas
California
Florida
Louisiana
Mississippi
Missouri
Texas
Ratoon
Arkansas
Florida
Louisiana
Texas
Total
5.1
2.1
0.7
+
1.0
0.4
0.1
0.6
2.1
0.0
+
1.1
0.9
7.1
+ Less than 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
1995
1996
1997
1998
1999
2000
2001
5.6
2.4
0.8
1.0
0.5
0.2
0.6
2.1
0.0
0.1
1.1
0.8
7.6
5.0
2.1
0.9
1.0
0.4
0.2
0.5
1.9
0.0
0.1
1.1
0.8
7.0
5.6
2.5
0.9
1.0
0.4
0.2
0.5
1.9
0.0
0.1
1.2
0.7
7.5
5.8
2.7
0.8
1.1
0.5
0.3
0.5
2.1
+
0.1
1.2
0.8
7.9
6.3
2.9
0.9
1.1
0.6
0.3
0.5
2.0
+
0.1
1.2
0.7
8.3
5.5
2.5
1.0
0.9
0.4
0.3
0.4
2.0
0.0
0.1
1.3
0.7
7.5
5.9
2.9
0.8
1.0
0.5
0.4
0.4
1.7
0.0
+
1.1
0.6
7.6
the United States is grown under continuously flooded
conditions; none is grown under deepwater 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 CH 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 2001, CH4 emissions
from rice cultivation were 7.6 Tg CO2 Eq. (364 Gg).
Although annual emissions fluctuated unevenly between the
years 1990 and 2001, ranging from an annual decrease of
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 5-8: CH4 Emissions from Rice Cultivation (Gg)
State
1990
Primary
Arkansas
California
Florida
Louisiana
Mississippi
Missouri
Texas
Ratoon
Arkansas
Florida
Louisiana
Texas
Total
241
102
34
1
46
21
7
30
98
0
2
52
45
339
+ Less than 0.5 Gg
Note: Totals may not sum due to independent rounding.
1995
1996
1997
1998
1999
2000
2001
265
114
40
2
48
25
10
27
98
0
4
54
40
363
240
99
43
2
45
18
8
25
92
0
4
51
38
332
265
118
44
2
50
20
10
22
91
0
3
55
33
356
278
126
39
2
53
23
12
24
98
+
3
59
36
376
300
138
43
2
52
28
16
22
95
+
4
58
33
395
260
120
47
2
41
19
14
18
97
0
3
61
34
357
283
138
40
1
46
22
18
18
81
0
2
52
27
364
11 percent to an annual increase of 17 percent, there was an
overall increase of 7 percent over the eleven-year period
due to an overall increase in harvested area.3
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,
200Ib). 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 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, 200Ib).
Methodology
The Revised 1996 IPCC Guidelines (IPCC/UNEP/
OECD/IEA 1997) recommends utilizing 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 with
the use of United States-specific emission factors derived
from rice field measurements. Seasonal emissions have
been found to be much higher for ratooned crops than for
primary crops, so emissions from ratooned and primary
areas are estimated separately using emission factors that
are representative of the particular growing season. This
is consistent with IPCC Good Practice Guidance and
Uncertainty Management in National Greenhouse Gas
Inventories (IPCC 2000).
1 The 11 percent decrease occurred between 1992 and 1993; the 17 percent increase happened between 1993 and 1994.
5-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 5-9: Rice Areas Harvested (Hectares)
State/Crop
1990
Arkansas
Primary
Ratoon*
California
Florida
Primary
Ratoon
Louisiana
Primary
Ratoon
Mississippi
Missouri
Texas
Primary
Ratoon
Total
485,633
NO
159,854
4,978
2,489
220,558
66,168
101,174
32,376
142,857
57,143
1,273,229
1995
1996
1997
1998
1999
2000
2001
542,291
NO
188,183
9,713
4,856
230,676
69,203
116,552
45,326
128,693
51,477
1,386,969
473,493
NO
202,347
8,903
4,452
215,702
64,711
84,176
38,446
120,599
48,240
1,261,068
562,525
NO
208,822
7,689
3,845
235,937
70,781
96,317
47,349
104,816
41,926
1,380,008
600,971
202
185,350
8,094
4,047
250,911
75,273
108,458
57,871
114,529
45,811
1,451,518
657,628
202
204,371
7,229
4,673
249,292
74,788
130,716
74,464
104,816
41,926
1,550,106
570,619
NO
221,773
7,801
3,193
194,253
77,701
88,223
68,393
86,605
43,302
1,361,864
656,010
NO
190,611
4,562
2,752
220,963
66,289
102,388
83,772
87,414
34,966
1,449,726
* Arkansas ratooning occurred only in 1998 and 1999.
NO (Not Occurring)
Note: Totals may not sum due to independent rounding.
Data Sources
The harvested rice areas for the primary and ratoon crops
in each state are presented in Table 5-9. Primary crop areas
for 1990 through 2001 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 2000
Summary (USDA 2001), and Crop Production 2001 Summary
(USDA 2002). Harvested rice areas in Florida, which are not
reported by USDA, were obtained from Tom Schueneman
(1999b, 1999c, 2000,2001 a), a Florida agricultural extension
agent, and Dr. Chris Deren (2002) of the Everglades Research
and Education Centre at the University of Florida. 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), around 41 percent of the primary area in 2000
(Schueneman 200la), and about 70 percent of the primary
area in 2001 (Deren 2002). 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, before returning to 30 percent in 2001
(Linscombe 1999a, 2001 a, 2002 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
and in 2001, but increased to 50 percent in 2000 due to an
early primary crop (Klosterboer 1999, 2000, 200la, 2002).
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
Agriculture 5-13
-------
experimental results4 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. 199la
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.
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, used
here, primary emissions ranged from 22 to 479 kg CH4/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 2001 were estimated to range
from 1.7 to 17 Tg CO2 Eq. (80 to 800 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 68 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, CH4 flux
measurements have not been undertaken in all of these states
or under all representative conditions, so this activity is not
included in the emission estimates presented here.
Agricultural Soil Management
Nitrous oxide is produced naturally in soils through the
microbial processes of nitrification and denitrification.5 A
number of agricultural activities add nitrogen to soils, thereby
increasing the amount of nitrogen available for nitrification and
denitrification, and ultimately the amount ofN2O 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 and 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).6 Indirect additions of
nitrogen to soils occur through two mechanisms:
1) volatilization and subsequent atmospheric deposition of
applied nitrogen;7 and 2) surface runoff and leaching of applied
nitrogen into groundwater and surface water. Other agricultural
soil management, 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.
4 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/IEA 1997).
5 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).
6 Cultivation of histosols does not, per se, "add" nitrogen to soils. Instead, the process of cultivation enhances mineralization of nitrogen-rich organic
matter that is present in histosols, thereby enhancing N2O emissions from histosols.
7 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 particulate ammonium (NH4), nitric acid (HNO3), and oxides
of nitrogen.
5-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Agricultural soil management is the largest source of
N2O in the United States.8 Estimated emissions from this
source in 2001 were 294.3 Tg CO2 Eq. (949 Gg N2O) (see
Table 5-10 and Table 5-11). Although annual agricultural
soil management emissions fluctuated between 1990 and
2001, there was a general increase in emissions over the
twelve-year period (see Annex N 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 and forage 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 twelve-year
period, total emissions of N2O from agricultural soil
management increased by approximately 10 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
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). 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 fertilizers, sewage
sludge and total livestock manure nitrogen.
Annex N 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.
Figure 5-2
Direct and Indirect N20 Emissions
from Agricultural Soils
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 section
of a managed soil; histosol cultivation is represented here.
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 forages, 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:
8 Note that the emission estimates for this source category include applications of nitrogen to all soils (e.g., forest soils, urban areas, golf courses,
etc.), but the term "Agricultural Soil Management" is kept for consistency with the reporting structure of the Revised 1996 IPCC Guidelines (IPCC/
UNEP/OECD/IEA 1997).
Agriculture 5-15
-------
Table 5-10: N20 Emissions from Agricultural Soil Management (Tg C02 Eq.)
Activity 1990 ^| 1995 1996 1997 1998 1999 2000
Direct 193.7
Managed Soils 153.3
Pasture, Range, & Paddock Livestock 40.4
Indirect 73.8
Total
267.5
Note: Totals may not sum due to independent rounding.
Table 5-11: N20 Emissions from Agricultural Soil Management (Gg)
Activity 1990 11 1995 1996 1997 1998 1999 2000
Direct 625
Managed Soils 495
Pasture, Range, & Paddock Livestock 130
Indirect 238
Total
863
Note: Totals may not sum due to independent rounding.
Table 5-12: Direct N20 Emissions from Managed Soils (Tg C02 Eq.)
Activity
1990
Commercial Fertilizers*
Livestock Manure
Sewage Sludge
N Fixation
Crop Residue
Histosol Cultivation
Total
55.4
13.0
0.4
58.5
23.2
2.8
153.3
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
2.2
40.4
2001
205.1
161.5
43.6
79.0
284.1
212.6
169.1
43.5
80.6
293.2
217.8
175.6
42.2
80.3
298.2
219.0
177.6
41.3
80.2
299.2
216.8
175.9
40.9
80.2
297.0
215.9
175.6
40.3
78.7
294.6
216.6
176.7
39.9
77.7
294.3
2001
662
521
141
255
916
685
545
140
260
946
703
567
136
259
962
706
573
133
259
965
700
568
132
259
958
696
566
130
254
950
699
570
129
251
949
1995 1996 1997 1998 1999 2000 2001
59.2
13.6
0.6
61.8
23.4
2.8
161.5
61.2
13.7
0.6
63.9
26.8
2.8
169.1
61.3
14.0
0.7
68.2
28.7
2.9
175.6
61.4
14.2
0.7
69.2
29.3
2.9
177.6
61.6
14.2
0.7
68.2
28.3
2.9
175.9
59.8
14.4
0.7
68.8
29.0
2.9
175.6
58.6
14.5
0.7
70.6
29.3
2.9
176.6
Note: Totals may not sum due to independent rounding.
* Excludes sewage sludge and livestock manure used as commercial fertilizers.
Table 5-13: Direct N20 Emissions from Pasture, Range, and Paddock Livestock Manure (Tg C02 Eq.)
1995 1996 1997 1998 1999 2000 2001
38.9
1.5
0.3
0.3
0.2
0.1
2.3
43.6
39.0
1.4
0.3
0.3
0.2
0.1
2.3
43.5
37.8
1.3
0.2
0.3
0.2
0.1
2.3
42.2
37.0
1.3
0.2
0.3
0.2
0.1
2.3
41.3
36.7
1.2
0.2
0.3
0.2
0.1
2.3
40.9
36.0
1.2
0.2
0.3
0.2
0.1
2.3
40.3
35.7
1.2
0.2
0.3
0.2
0.1
2.3
39.9
Note: Totals may not sum due to independent rounding.
5-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 5-14: Indirect N20 Emissions from Agricultural Soil Management (Tg C02 Eq.)
Activity
Volatilization & Atm. Deposition
Commercial Fertilizers*
Livestock Manure
Sewage Sludge
Surface Leaching & Runoff
Commercial Fertilizers*
Livestock Manure
Sewage Sludge
Total
1990
11.7
4.9
6.7
0.1
62.1
36.9
24.9
0.3
73.8
1995 1996 1997 1998 1999 2000 2001
12.5
5.3
7.1
0.1
66.5
39.5
26.5
0.5
79.0
12.7
5.4
7.1
0.1
67.9
40.8
26.6
0.5
80.6
12.6
5.4
7.1
0.1
67.7
40.9
26.3
0.5
80.3
12.6
5.5
7.0
0.1
67.6
40.9
26.1
0.5
80.2
12.6
5.5
7.0
0.1
67.6
41.1
26.0
0.5
80.2
12.4
5.3
6.9
0.1
66.3
39.9
25.9
0.5
78.7
12.3
5.2
6.9
0.1
65.4
39.1
25.8
0.5
77.7
Note: Totals may not sum due to independent rounding.
* Excludes sewage sludge and livestock manure used as commercial fertilizers.
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 and forages 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.9
Total annual emissions from nitrogen applications, and
annual emissions from histosol cultivation, were then summed
to estimate total direct emissions from managed soils.
9 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
-------
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 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 N2O 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,10 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 (TVA 1991, 1992a, 1993, 1994; AAPFCO 1995,
1996, 1997, 1998, 1999, 2000b, 2002). 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; 2002b-g), the FAOSTAT
database (FAO 2002), 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 ASAE
(1999) and USDA (1996); and information about the fraction
of poultry litter used as a feed supplement from Carpenter
(1992). Data collected by the EPA were used to derive
annual estimates of land application 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, 200la,
2002a), 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, Gerrish 2000, Hoveland 2000, Evers
2000, and Pederson 2000). Mass ratios of aboveground
10 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
-------
residue to crop product, dry matter fractions, and nitrogen
contents for nitrogen-fixing crops were obtained from
Strehler and Stiitzle (1987), Barnard and Kristoferson
(1985), Karkosh (2000), Ketzis (1999), and IPCC/UNEP/
OECD/IEA (1997). 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, 2002a). Production statistics for rice in
Florida are not recorded by USDA, so these were derived
from Smith (1999), Schueneman (1999, 2001), and Deren
(2002). Aboveground residue to crop mass ratios, residue
dry matter fractions, and residue nitrogen contents were
obtained from Strehler and Stutzle (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, u 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/IEA
1997), 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
Box 5-1: DAYCENT Model Estimates of N20 Emissions
from Agricultural Soils
U.S. EPA is currently working in collaboration with the Agri-
cultural Research Service and the Natural Resource Ecology Lab
at Colorado State University to test the feasibility of using the
DAYCENT ecosystem process model to estimate N20 emissions
from agricultural soil management. In countries like the United
States that cover large land areas and have a diversity of climate,
soils, land use and management systems, the use of an ecosys-
tem process model such as DAYCENT can have great advan-
tages over the single emission factor approach as specified in
the IPCC Guidelines for estimating N20 emissions. Potential ad-
vantages 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 N20 emissions. One of the greatest chal-
lenges involved in this effort will be obtaining the activity data
(e.g., synthetic fertilizer and manure nitrogen inputs) at the ap-
propriate spatial scale for use in the DAYCENT model. The goal
of the modeling effort is to develop county-level estimates of N20
emissions from agricultural soils that can be summed to produce
a national-level estimate. Emission estimates from this modeling
effort are intended for use in the 1990-2002 inventory.
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 (see Box 5-1).
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
" Note that the emission factor used for cultivated histosols in the sub-tropics is the average of the tropical and temperate default IPCC emission factors.
Agriculture 5-19
-------
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.
Field Burning of Agricultural Residues
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
in the field. Alternatively, they can be collected and used
as fuel, animal bedding material, or supplemental animal
feed. Field burning of crop residues is not considered a
net source of 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 CH4, N2O, CO, and
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 in 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.12 Annual emissions from this source over
the period 1990 through 2001 averaged approximately 0.7
Tg C02 Eq. (35 Gg) of CH4, 0.4 Tg CO2 Eq. (1 Gg) of
N2O, 728 Gg of CO, and 32 Gg of NOx (see Table 5-15
and Table 5-16).
Gas/Crop Type
1990
CH4
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
N20
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
Total
0.7
0.1
0.1
+
0.3
+
0.1
+
0.4
+
+
+
0.1
+
0.2
+
1.1
jricultural Residues (Tg C02 Eq.)
1995 1996 1997
0.7
0.1
0.1
0.3
0.2
0.4
0.1
0.2
1.0
0.7
0.1
0.1
0.3
0.2
0.4
0.1
0.2
1.2
0.8
0.1
0.1
0.3
0.2
0.4
0.1
0.3
1.2
1998
0.8
0.1
0.1
0.3
0.2
0.5
0.1
0.3
1.2
1999
0.8
0.1
0.1
0.3
0.2
0.4
0.1
0.3
1.2
2000
0.8
0.1
0.1
0.4
0.2
0.5
0.1
0.3
1.2
2001
0.8
0.1
0.1
0.3
0.2
0.5
0.1
0.3
1.2
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
12 The fraction of rice straw burned each year is significantly higher than that for other crops (see "Data Sources" discussion below).
5-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
Table 5-16: Emissions from Field Burning of Agricultural Residues (Gg)*
Gas/Crop Type
1990
CH4
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
N20
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
CO
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
NOX
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
33
7
4
1
13
1
7
+
1
+
+
+
+
+
1
+
685
137
81
18
282
16
148
2
28
4
3
+
7
1
14
+
* Full molecular weight basis.
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding.
1995
1996
1997
1998 1999
2000
2001
31
5
4
1
13
1
8
1
36
5
4
1
16
1
9
1
36
6
3
1
16
1
10
1
37
6
3
1
17
1
10
1
36
5
3
1
16
+
10
1
37
5
3
1
17
1
10
1
36
5
3
1
16
+
11
1
656
109
80
20
263
13
167
2
29
3
3
6
16
747
114
85
19
328
15
183
2
32
3
3
8
17
761
124
66
21
328
13
207
2
34
3
2
8
20
781
128
58
22
347
13
211
2
35
3
2
8
20
760
115
69
23
336
10
204
2
34
3
2
8
19
784
112
69
24
353
12
212
2
35
3
2
8
20
762
98
69
23
338
9
222
3
35
3
2
8
21
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:13
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)14
Nitrogen Released = (Annual Crop Production)
(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)
13 Note: As is explained under Data Sources, the fraction of rice residues burned varies among states, so these equations were applied at the state level
for rice. These equations were applied at the national level for all other crop types.
14 Burning Efficiency is defined as the fraction of dry biomass exposed to burning that actually burns. Combustion Efficiency 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.
Agriculture 5-21
-------
Table 5-17: Agricultural Crop Production (Thousand Metric Tons of Product)
Crop
1990
Wheat
Rice
Sugarcane
Corn*
Barley
Soybeans
Peanuts
74,292
7,105
25,525
201,534
9,192
52,416
1,635
1995
1996 1997 1998 1999 2000 2001
59,404
7,935
27,922
187,970
7,824
59,174
1,570
61,980
7,828
26,729
234,518
8,544
64,780
1,661
67,534
8,339
28,766
233,864
7,835
73,176
1,605
69,327
8,570
30,896
247,882
7,667
74,598
1,798
62,569
9,381
32,023
239,549
6,103
72,223
1,737
60,758
8,697
32,762
251,854
6,939
75,055
1,481
53,278
9,686
31,571
241,485
5,434
78,668
1,923
*Corn for grain (i.e., excludes corn for silage).
Table 5-18: Percentage of Rice Area Burned by State
State
Arkansas
California
Florida"
Louisiana
Mississippi
Missouri
Texas
Percent Burned
1990-1998
10
variable8
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
Percent Burned
2001
10
23
0
4
40
5
0
a Values provided in Table 5-19.
b Burning of crop residues is illegal in Florida.
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 (ILENR 1993, 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 2000 Summary (USDA 2001), and Crop
Production 2001 Summary (USDA 2002). Rice production
data for Florida, which are not collected by USDA, were
estimated by applying average primary and ratoon crop
yields for Florida (Smith 1999) to Florida acreages
(Schueneman 1999b, 2001; Deren 2002). 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
Energy 1995, Noller 1996, Wisconsin Department of Natural
Resources 1993, and Cibrowski 1996). Estimates of the
percentage of rice residue burned were derived from state-
level estimates of the percentage of rice area burned each
year, which were multiplied by state-level, annual rice
production statistics. The annual percentages of rice area
burned in each state were obtained from the agricultural
5-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
-------
extension agents in each of the seven rice-producing states
and reports of the California Air Resources Board (CARB)
(Bollich 2000; Deren 2002; Guethle 1999,2000,2001,2002;
Fife 1999; California Air Resources Board 1999, 2001;
Klosterboer 1999a, 1999b, 2000,2001,2002; Lindberg 2002;
Linscombe 1999a, 1999b, 2001, 2002; Mutters 2002, Najita
2000,2001; Schueneman 1999a, 1999b, 2001; Slaton 1999a,
1999b, 2000; Street 1999a, 1999b, 2000,2001,2002; Wilson
2001,2002) (see Table 5-18 and Table 5-19). The estimates
provided for Arkansas and Florida remained constant over
the entire 1990 through 2001 period, while the estimates for
all other states varied over the time series. For California, it
was assumed that the annual percents of rice area burned in
the 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). These
percents declined between 1990 and 2001 because of a
legislated reduction in rice straw burning (Lindberg 2002)
(see Table 5-19).
Table 5-19: Percentage of Rice Area Burned in
California
Year
California
1990
75
1995
1996
1997
1998
1999
2000
2001
59
63
34
33
27
27
23
personal communications with Jen Ketzis (1999), who
accessed Cornell University's Department of Animal
Science's computer model, Cornell Net Carbohydrate and
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
Table 5-20: Key Assumptions for Estimating Emissions from Agricultural Residue Burning4
Crop
Residue/Crop Ratio Fraction of Residue Burned Dry Matter Fraction Carbon Fraction Nitrogen Fraction
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
1.3
1.4
0.8
1.0
1.2
2.1
1.0
0.03
variable
0.03
0.03
0.03
0.03
0.03
0.93
0.91
0.62
0.91
0.93
0.87
0.86
0.4428
0.3806
0.4235
0.4478
0.4485
0.4500
0.4500
0.0062
0.0072
0.0040
0.0058
0.0077
0.0230
0.0106
* The burning efficiency and combustion efficiency for all craps were assumed to be 0.93 and 0.88, respectively.
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
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).
Agriculture 5-23
-------
Table 5-21: Greenhouse Gas Emission Ratios
Gas Emission Ratio
CH4a
C0a
N20b
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).
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. A residue/
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.
5-24 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2000
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6. Land-Use Change and Forestry
This 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 used to estimate all
three components of changes in agricultural soil carbon stocks are consistent with the Revised 1996 IPCC Guidelines.
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 flux from urban trees is based on neither annual data nor periodic survey data, but
instead on data collected over the period 1990 through 1999. This flux has been applied to the entire time series.
1 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.)
Sink Category 1990 1995 1996 1997
Forests
Urban Trees
Agricultural Soils
Landfilled Yard Trimmings
Total
(982.7)
(58.7)
(13.3)
(18.2)
(1,072.8)
1998 1999 2000 2001
(979.0)
(58.7)
(14.9)
(11.6)
(979.0)
(58.7)
(13.6)
(9.7)
(759.0)
(58.7)
(13.9)
(9.0)
(751.7)
(58.7)
(11.5)
(8.7)
-------
for energy use, combustion results in an immediate release
of carbon. Conversely, if timber is harvested and subse-
quently 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 be stored
permanently in the landfill.
This section of the Land-Use Change and Forestry
chapter quantifies the 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.
Forest carbon storage pools, and the flows between them
via emissions, sequestration, and transfers, are shown in
Figure 6-1. In this figure, 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 the boxes are not identical
to the storage pools identified in this chapter. The storage
pools identified in this chapter have been altered in this
graphic to better illustrate the processes that result in
transfers of carbon from one pool to another, and that result
in emissions to the atmosphere.
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 current net carbon flux
from forest land are management activities and the ongoing
Figure 6-1
Forest Sector Carbon Pools and Flows
Legend
fj Carbon Pool
—>• Carbon transfer or flux
Combustion
Source: Adapted from Heath and Birdsey (1997)
Land-Use Change and Forestry 6-3
-------
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 will cause 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 uptake (i.e., net sequestration) of carbon during the period
from 1990 through 2001. 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 in 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.
Changes in carbon stocks in U.S. forests and harvested
wood were estimated to account for an average annual net
sequestration of 887 Tg CO2 Eq. (242 Tg C) over the period
1990 through 2001 (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 23 percent between 1990 and 2001. This was
due to a greater increase in forest area between 1987 and
1997 than between 1997 and 2001. Most of the decline in
annual sequestration occurred in the forest soil carbon pool.
This result is due to the method used to account for changes
in soil carbon after the conversion of land from forest to
non-forest. Specifically, soil carbon stocks for each forest
type are assumed to depend on land use and soil type and
not to vary over time within forests. Therefore, as lands are
converted from non-forest to forest, there is a substantial
immediate increase in soil carbon stocks.
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 forest carbon stocks, excluding
harvested wood stocks, by the regions that were used in the
forest carbon analysis. Figure 6-3 shows 1997 forest carbon
stocks per hectare, by county, excluding harvested wood stocks,
for all counties in the conterminous United States that have at
least 5 percent of the county area in forest.
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 2001), 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 O.
6-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table 6-3: Net Changes in Carbon Stocks in Forest and Harvested Wood Pools, and Total Net Forest Carbon Flux (Tg C02 Eq.)
Carbon Pool
1990
1995
1996
1997 1998
1999 2000 2001
Forest
Trees
Understory
Forest Floor
Down Dead Wood
Forest Soils
Harvested Wood
Wood Products
Landfilled Wood
Total Net Flux
(773.7)
(469.3)
(11.0)
(25.7)
(55.0)
(212.7)
(209.0)
(47.7)
(161.3)
(982.7)
(773.7)
(469.3)
(11.0)
(25.7)
(55.0)
(212.7)
(205.3)
(55.0)
(150.3)
(773.7)
(469.3)
(11.0)
(25.7)
(55.0)
(212.7)
(205.3)
(55.0)
(150.3)
(979.0)
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 net flux) is an estimate of the actual net flux between the total forest carbon pool and
the atmosphere. 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 Changes in Carbon Stocks in Forest and Harvested Wood Pools, and Total Net Forest Carbon Flux (Tg C)
Carbon Pool
1990
1997 1998 1999 2000 2001
Forest
Trees
Understory
Forest Floor
Down Dead Wood
Forest Soils
Harvested Wood
Wood Products
Landfilled Wood
Total Net Flux
(211)
(128)
(3)
(7)
(15)
(58)
(57)
(13)
(44)
(268)
(211)
(128)
(3)
(7)
(15)
(58)
(56)
(15)
(41)
(211)
(128)
(3)
(7)
(15)
(58)
(56)
(15)
(41)
Note: 1 Tg C = 1 Tg carbon = 1 million metric tons carbon. This table has been included to facilitate comparison with previous U.S. Inventories.
Parentheses indicate net carbon "sequestration" (i.e., accumulation into the carbon pool minus emissions or harvest from the carbon pool). The sum
of the net stock changes in this table (i.e., total net flux) is an estimate of the actual net flux between the total forest carbon pool and the atmosphere.
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 6-5: U.S. Forest Carbon Stock Estimates (Tg C)
Methodology
Carbon Pool
1987 1997 2002
Forest
Trees
Understory
Forest Floor
Down Dead Wood
Forest Soils
Harvested Wood
Wood Products
Landfilled Wood
Total Forest Carbon Stocks
47,595
15,168
448
4,240
2,058
25,681
1,920
1,185
735
49,515
49,695
16,449
473
4,306
2,205
26,262
2,478
1,319
1,159
52,173
50,440
''i'ifipit
' '"'"498
:
-------
Figure 6-2
Forest Carbon Stocks by Region, 1997
NORTHEAST
Region
This graphic shows total forest carbon stocks in 1997, by region.
Harvested wood carbon stocks are not included.
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.4 The
use of direct measurements from forest surveys to estimate
the forest pools, and the use of data on wood products and
landfilled wood to estimate the harvested wood pool is likely
to result in more accurate flux estimates than the alternative
IPCC methodologies. Due to differences in data sources,
different methods were used to calculate the carbon flux in
forests and in harvested wood products. Therefore these
methods are described separately below.
Forest Carbon Stock Change
The overall approach was to sample the forest carbon
at one time, sample the forest carbon again several years
later, and then subtract the two estimates to calculate the net
change in carbon stocks. Three periodic inventories
(sampling times) were used: 1987, 1997, and 2002.5 For
each periodic inventory, each carbon pool was estimated
using coefficients from the FORCARB model, as described
below. The carbon pools included live and dead standing
trees, understory vegetation, forest floor, and soil. These
estimates were summed to calculate total carbon stocks at
each time period. Data sources and methods for estimating
each carbon pool are described briefly below and more fully
in Annex O.
The starting point for estimating forest carbon stock
change was to obtain data on the area and growing stock
volume for forest lands. For 1987 and 1997, such data were
available from periodic inventories conducted by the USDA
Forest Service Forest Inventory and Analysis program (Smith
et al. 2001, Prayer and Furnival 1999). In the past, the Forest
Inventory and Analysis program did not conduct detailed
surveys of all forest land, but instead focused on timber
producing land, which is called timberland. In addition, some
reserved forest land and some other forest land were surveyed.6
With the introduction of the new annualized inventory design
(Gillespie 1999), all forest lands will feature the same type of
detailed information. In order to include all forest lands,
estimates were made for timberlands and then were
extrapolated for non-timberland forests.
4 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).
5 As explained in the paragraphs below, the 1987 and 1997 "inventories" referred to here are actual forest inventories (i.e., datasets based on field
surveys), while the 2002 "inventory" is a projection derived from the historical field data and a linked system of forest sector models. A national
(field-based) forest inventory has not been completed for 2002.
6 Forest land in the United States includes all land that is at least 10 percent stocked with trees of any size. Timberland is the most 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 than 20 cubic feet per
acre per year.
6-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Figure 6-3
Forest Carbon Stocks, per Hectare, by County, 1997
metric ton C/ha
105-152
153-199
200-246
247-293
294-340
This figure shows total, per hectare, forest carbon stocks in 1997, by county. Only counties in the conterminous United States that have at least
5 percent of the county area in forest are shown. Harvested wood carbon stocks are not included.
The Forest Inventory and Analysis program has
conducted consistent forest surveys based on extensive
statistically based sampling 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 to 14 years,
depending on the state), all states within a region would
be surveyed, and then states would be resurveyed. The
Forest Inventory and Analysis program 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. Currently, some of these pools must
be estimated based on other measured characteristics.
Characteristics that were measured in the 1987 and 1997
surveys include individual tree diameter and species, and
forest type and age of the plot. For more information about
forest inventory data and carbon stock change, see Birdsey
and Heath (2001).
Historically, the main purpose of the Forest Inventory
and Analysis program has been to estimate areas, volume of
growing stock, and timber products output and utilization
factors. Growing stock is 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.
Land-Use Change and Forestry 6-7
-------
For the 2002 periodic inventory, data were not available
from the Forest Inventory and Analysis program. Therefore,
areas, volumes, growth, land-use changes, and other forest
characteristics were projected with a system of models
representing the U.S. forest sector (see Haynes 2002, also
see Annex O).
Based on the measured or projected periodic survey data,
estimates were made of the total biomass and carbon in trees
on timberlands and other forest lands. For timberlands, total
biomass and carbon in standing trees were calculated from
the growing stock volume. Calculations were made using
biomass conversion factors for each forest type and region
presented in Smith et al. (in press). For non-timberlands,
biomass and carbon in standing trees were estimated based
on average carbon estimates derived from similar 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 of non-timberland forests 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.
Understory carbon was estimated from inventory data
using equations presented in Birdsey (1992). Forest floor
carbon was estimated from inventory data using the
equations presented in Smith and Heath (2002). Down dead
wood was estimated using a procedure similar to that used
for estimating carbon in understory vegetation, as described
in Annex O. Data on the carbon content of soils were
obtained from the national STATSGO spatial database.
These data were combined with spatial data from the Forest
Inventory and Analysis program on the location of U.S. forest
lands to estimate soil carbon in all forest lands.
Once carbon pools were estimated as described above
for each periodic inventory (1987,1997, and 2002), the pools
were summed together to create total forest carbon stock
estimates. Average annual carbon stock changes were then
calculated by subtracting carbon stocks at the end of a time
period from those at the beginning of the time period, and
then dividing by the number of years in the time period.
Harvested Wood Products Carbon Stock Change
Estimates of carbon stock changes in wood products and
wood discarded in landfills were based on the methods
described in Skog and Nicholson (1998). These methods utilize
two harvested wood carbon storage pools: wood products in
use, and wood discarded in landfills. Annual historical estimates
and projections of detailed product production were used to
divide consumed roundwood into product, wood mill residue,
and pulp mill residue. Rates of decay for wood products and
for wood in landfills were estimated and applied to the
respective pools. The results were aggregated to produce
national estimates. To account for imports and exports, the
production approach was used, meaning that carbon in exported
wood was included using the same disposal rates as in the United
States, while carbon in imported wood was not included. Over
the period 1990 through 2001, carbon in exported wood
accounted for an average of 22 Tg CO2 Eq. storage per year,
with little variation from year to year. For comparison, imports
(which were not included in the harvested wood net flux
estimates) increased from 26 Tg CO2 Eq. per year in 1990 to
47 Tg CO2 Eq. per year in 2001.
Data Sources
The estimates of forest carbon stocks used in this
Inventory 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 Forest Inventory and Analysis program.
Compilations of these data for 1987 and 1997 are given in
Waddell et al. (1989) and Smith et al. (2001), 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 used to
derive estimates of carbon stocks as described above in the
methodology section and in Annex O. Estimates of soil
carbon are based on data from the STATSGO database
(USDA 1991). Carbon stocks in wood products in use and
wood products stored in landfills are based on historical
data from the USDA Forest Service (USDA 1964, Ulrich
6-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
1989, Howard 2001), and historical data as implemented in
the framework underlying the NAPAP (Ince 1994) and
TAMM/ATLAS (Haynes 2002, Mills 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).
Uncertainty
This section discusses uncertainties in the carbon
sequestration estimates, given the methods and data used.
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, many of the
data currently used were collected over more than one year
in a state, and data associated with a particular year may
actually have been collected over several previous years.
Thus, there is uncertainty in the year associated with the
forest inventory data. In addition, the forest survey data
that are currently available generally exclude timber stocks
on most forest land in Alaska, Hawaii, and U.S. territories.
However, net carbon fluxes from these stocks are believed
to be minor. The assumptions that were used to calculate
carbon stocks in reserved forests and other forests in the
conterminous 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. Estimates from sampling at different times
on permanent plots are correlated, and such correlation
reduces the uncertainty in estimates of carbon flux. 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
decreased more than three-fold when the correlation
coefficient increased from 0.5 to 0.95.
Additional sources of uncertainty come from the models
used to estimate carbon storage in specific ecosystem
components, such as forest floor, understory vegetation, and
soil. Extrapolation of the results of site-specific ecosystem
studies to all forest lands introduces uncertainty because such
studies may not adequately represent regional or national
averages. Uncertainty also arises due to (1) modeling errors,
for example relying on coefficients or relationships that are
not well known, and (2) errors in converting estimates from
one reporting unit to another (Birdsey and Heath 1995). An
important source of uncertainty is that the impacts of forest
management activities, including harvest, on soil carbon are
not well understood. For example, while Johnson and Curtis
(2001) found little or no net change in soil carbon following
harvest on average across a number of studies, many of the
individual studies did exhibit differences. Heath and Smith
(2000b) noted that the experimental design in a number of
soil studies was such that the usefulness of the studies may be
limited in determining harvesting effects on soil carbon. Soil
carbon impact estimates need to be very precise because even
small 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. As more
information becomes available, the effects of changes in land
use will be better accounted for in estimates of soil carbon.
Recent studies have begun to quantify the 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. Because of these additional factors, uncertainty
is expected to be greater in estimates for all forest lands.
Land-Use Change and Forestry 6-9
-------
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 is estimated
that urban areas (cities, towns, and villages), which cover
3.5 percent of the continental United States, contain about
3.8 billion trees. With an average tree canopy cover of 27.1
percent, urban areas account for approximately 3 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 2001, as it is based on data collected
during the 1990s. Annual estimates of CO2 flux have not
been developed (Table 6-6).
Table 6-6: Net C02 Flux From Urban Trees (Tg C02 Eq.)
Year Tg C02 Eq.
1990
1995
1996
1997
1998
1999
2000
2001
(58.7)
(58.7)
(58.7)
(58.7)
(58.7)
(58.7)
(58.7)
(58.7)
Note: Parentheses indicate net sequestration.
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
1996IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).7
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
1989 through 1999, 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
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
aboveground biomass 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.
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 seven of the ten cities by subtracting the annual gross
emission estimates from the annual gross sequestration
estimates.8 See Table 6-7.
7 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.
8 Three cities did not have net estimates.
6-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table 6-7: Carbon Stocks (Metric Tons C), Annual Carbon Sequestration (Metric Tons C/yr), Tree Cover (Percent),
and Annual Carbon Sequestration per Area of Tree Cover (kg C/m2 cover-yr) for Ten U.S. Cities
City
New York, NY
Atlanta, GA
Sacramento, CA
Chicago, IL
Baltimore, MD
Philadelphia, PA
Boston, MA
Syracuse, NY
Oakland, CA
Jersey City, NJ
Carbon Stocks
1,225,200
1,220,200
1,107,300
854,800
528,700
481,000
289,800
148,300
145,800
19,300
Gross Annual
Sequestration
38,400
42,100
20,200
40,100
14,800
14,600
9,500
4,700
NA
800
Net Annual
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
Gross Annual
Sequestration
per Area of
Tree Cover
0.23
0.34
0.66
0.61
0.28
0.27
0.30
0.30
NA
0.18
Net Annual
Sequestration
per Area of
Tree Cover
0.12
0.26
NA
NA
0.20
0.20
0.22
0.22
NA
0.13
NA = not analyzed
National annual net carbon sequestration by urban trees
was estimated from the city estimates of 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 density greater than 1,000 people per square
mile or population total greater than 2,500. Therefore, urban
encompasses most cities, towns, and villages (i.e., it includes
both urban and suburban areas). The gross and net carbon
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. 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 annual gross sequestration was
multiplied by the average of the ratios of net to gross
sequestration for those cities that had both estimates. The
average of these ratios is 0.70.
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.
2002), 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 percent crown dieback (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 were based on expert
judgment of the authors. Decomposition rates were based on
literature estimates (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).
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. 2002), as well as with the tree cover area
estimates for urban areas, as these are based on interpretation
Land-Use Change and Forestry 6-11
-------
of Advanced Very High Resolution Radiometer 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).
Changes in Agricultural
Soil Carbon Stocks
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/ffiA 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 (usually less than 20 percent by weight), 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., 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
time. 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 CO2.
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 2001 period. Carbon sequestration in
6-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table 6-8: Net C02 Flux From Agricultural Soils (Tg C02 Eq.)
Soil Type/Management Activity
Mineral Soils
Organic Soils
Liming of Soils
Total
1990
(57.1)
34.3
9.5
(13.3)
1995
(58.6)
34.8
8.9
1996
(57.3)
34.8
8.9
(14.9) (13.6)
1997 1998 1999 2000 2001
(57.4)
34.8
8.7
'»$"
9.6
9.1
MS
8.8
9.1
(13.9)
'It**'
Note: Parentheses indicate net sequestration. Shaded areas indicate values based on a combination of historical data and projections.
are based on historical data only.
I other values
mineral soils in 2001 was estimated at approximately 59 Tg
CO2 Eq. (16 Tg C), while emissions from organic soils were
estimated at 35 Tg CO2 Eq. (9 Tg C) and emissions from
liming were estimated at 9 Tg CO2 Eq. (2.5 Tg C). Together,
the three activities accounted for net sequestration of
approximately 15 Tg CO2 Eq. (4 Tg C) in 2001. Total annual
net CO2 flux was negative (i.e., net sequestration) each year
over the 1990 to 2001 period. Between 1990 and 2001,
total net carbon sequestration in agricultural soils increased
by close to 14 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 shift in annual
net sequestration from 1990 to 1995 is the result of
calculating average annual mineral and organic soil fluxes
from periodic, rather than annual, activity data.9
The spatial variability in annual, per hectare CO2 flux
for mineral and organic soils is displayed in Figure 6-4 through
Figure 6-7. The greatest mineral soil sequestration rates are
in the south and east central United States and in a small area
of the Pacific Northwest, while the greatest organic soil
emission rates are along the southeast coast, in the northeast
central United States, and along the central west coast.
The flux estimates presented here are restricted to CO2
fluxes associated with the use and management of
agricultural soils. Agricultural soils are 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. These emissions are
accounted for in the Agriculture chapter.' ° 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
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 net CO2 flux from
use and management of mineral and organic soils and from
liming follow the Revised 1996 IPCC Guidelines (IPCC/
UNEP/OECD/IEA 1997, Ogle et al. 2002, Ogle et al. in
review), except where noted below. (Additional details on
the methodology and data used to estimate flux from mineral
and organic soils are described in Annex P). Mineral soil
organic carbon stocks were estimated for 1982, 1992, and
1997 for the conterminous United States and Hawaii using
U.S. data on climate, soil types, land use and land
management activity data, reference carbon stocks (for
agricultural soils rather than native soils) and field studies
9 Mineral and organic soil results for the entire time series are presented in Annex P.
10 Nitrous 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.
Land-Use Change and Forestry 6-13
-------
Figure 6-4
Net Annual C02 Flux, per Hectare, From Mineral Soils Under Agriculture Management, 1990-1992
Note: Positives represent emissions,^
and negatives represent sequestration.
Map does not include soil organic carbon
change resulting from manure and
sewage sludge additions.
metric ton CO2/ha
I l<-3
|~~| -.3 to -.2
| -.1 to 0
| 0 to .1
I > .1
This map shows the spatial variability in net annual carbon dioxide flux from mineral soils for the year 1990 through 1992.
The color assigned to each polygon represents the average annual flux per hectare for the area of managed mineral soils in that polygon.
Figure 6-5
Net Annual C02 Flux, per Hectare, From Mineral Soils Under Agriculture Management, 1993-2001
Note: Positives represent emissions,'
and negatives represent sequestration.
Map does not include soil organic carbon
change resulting from manure and sewage
sludge additions or enrollment in CRP after 1997.
This map shows the spatial variability in net annual carbon dioxide flux from mineral soils for the year 1993 through 2001.
The color assigned to each polygon represents the average annual flux per hectare for the area of managed mineral soils in that polygon.
6-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Figure 6-6
Net Annual C02 Flux, per Hectare, From Organic Soils Under Agriculture Management, 1990-1992
Note: Positives represent emissions.
metric ton CO2/ha
m > 40
1^ 30 to 40
•^•1 2° to 30
10 to 20
| | OtolO
| | no organic soils
This map shows the spatial variability in net annual carbon dioxide flux from organic soils for the year 1990 through 1992.
The color assigned to each polygon represents the average annual flux per hectare for the area of managed organic soils in that polygon.
Figure 6-7
Net Annual C02 Flux, per Hectare, From Organic Soils Under Agriculture Management, 1993-2001
Note: Positives represent emissions.
metric ton CO2/ha
^| >40
IB 3°to 40
•0 20 to 30
10 to 20
| |0 to 10
| | no organic soils
This map shows the spatial variability in net annual carbon dioxide flux from organic soils for the year 1993 through 2001.
Land-Use Change and Forestry 6-15
-------
Table 6-9: Net Annual C02 Flux from U.S. Agricultural
Soils Based on Monte Carlo Simulation (Tg C02 Eq.)
Soil Type
1990-1992
1993-2001
Mineral Soils
Estimate*
Uncertainties
Organic Soils
Estimate
Uncertainties
Total
Estimate
Uncertainties
(35.8)
(13.9) to (58.7)
34.3
23.1 to 48.4
(1.5)
24.2 to (27.2)
(35.4)
(20.9) to (50.3)
34.8
23.5 to 49.1
(0.7)
19.5 to (19.5)
Note: Parentheses indicate net sequestration. The uncertainties are
based on the Monte Carlo analysis. The range is a 95 percent
confidence interval, based on the simulated values at the 2.5 and 97.5
percentiles in the final distribution of 50,000 estimates.
* Does not include the change in carbon storage resulting from the
annual application of manure and sewage sludge, or the change in
Conservation Reserve Program enrollment after 1997.
addressing management effects on soil organic carbon
storage. National-scale data on land-use and management
changes over time were obtained from the 1997 National
Resources Inventory (NRCS 2000). The 1997 National
Resources Inventory provides land use/management data and
soils information for more than 400,000 locations in U.S.
agricultural lands. Two other sources were used to
supplement the land-use information from the 1997National
Resources Inventory. The Conservation Technology
Information Center (CTIC 1998) provided data on tillage
activity, with adjustments for long-term adoption of no-till
agriculture (Towery 2001), and Euliss and Gleason (2002)
provided activity data on wetland restoration of Conservation
Reserve Program Lands. Major Land Resource Areas
(MLRAs, NRCS 1981) were used as the base spatial unit
for mapping climate regions in the United States. Each Major
Land Resource Area represents a geographic unit with
relatively similar soils, climate, water resources, and land
uses (NRCS 1981).11 Major Land Resource Areas were
classified into climate zones according to the IPCC
categories using the Parameter-Evaluation Regressions on
Independent Slopes Model (PRISM) climate-mapping
program of Daly et al. (1994). Reference carbon stocks
were estimated using the National Soil Survey
Characterization Database (NRCS 1997), and the reference
condition for the stock estimates was cultivated cropland,
rather than native vegetation as used in the Revised 1996
IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).
Changing the reference condition was necessary because soil
measurements under agricultural management are much
more common and easily identified in the National Soil
Survey Characterization Database (NRCS 1997).
Management factors were derived from published literature
to determine the impact of management practices on soil
organic carbon storage, including changes in tillage,
cropping rotations and intensification, as well as land-use
change between cultivated and uncultivated conditions (Ogle
et al. in review). Euliss and Gleason (2002) provided the
data for computing the change in soil organic carbon storage
resulting from restoration of Conservation Reserve Program
Lands (Olness et al. in press, Euliss et al. in prep).
Combining information from these data sources, carbon
stocks were estimated 50,000 times for 1982, 1992, and
1997, using a Monte Carlo simulation approach and the
probability density functions for U.S.-specific management
factors, reference carbon stocks, and land-use activity data
(Ogle et al. in review, Ogle et al. 2002). The annual carbon
flux for 1990 through 1992 was estimated by calculating
the annual change in stocks between 1982 and 1992; annual
carbon flux for 1993 through 2001 was estimated by
calculating the annual change in stocks between 1992 and
1997 (see Table 6-9).
Annual carbon emission estimates from organic soils
used for agriculture between 1990-2001 were derived using
Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA
1997), except that U.S.-specific carbon loss rates were used
in the calculations rather than default IPCC rates (Ogle et
al. 2002). Similar to mineral soils, the final estimates include
a measure of uncertainty as determined from the Monte Carlo
simulation. Data from published literature were used to
derive probability density functions for carbon loss rates
(Ogle et al. in review), which were used to compute
emissions based on the 1992 and 1997 land areas in each
climate/land-use category defined in the Revised 1996 IPCC
Guidelines (IPCC/UNEP/OECD/IEA 1997). The area
estimates were derived from the same climate, soil, and land-
use/management databases that were used for mineral soil
calculations (Daly et al. 1994, USDA 2000). The annual
flux estimated for 1992 was applied to 1990 through 1992,
and the annual flux estimated for 1997 was applied to 1993
through 2001 (see Table 6-9).
11 The polygons displayed in Figure 6-4 through Figure 6-7 are the Major Land Resource Areas.
6-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table 6-10: Quantities of Applied Minerals (Thousand Metric Tons)
Mineral 1990 1991 1992 1993 1994 1995 1996
1997 1998 1999 2000 2001
Limestone 19,012 20,312 17,984 15,609 16,686 17,297 17,479 16,539 14,882 16,894 15,863 16,473
Dolomite 2,360 2,618 2,232 1,740 2,264 2,769 2,499 2,989 6,389 3,420 3,812 3,959
Annual carbon flux estimates for mineral soils between
1990 and 2001 were adjusted to account for additional
carbon sequestration from manure and sewage sludge
applications, as well as gains or losses in carbon
sequestration due to changes in Conservation Reserve
Program enrollment after 1997. The amount of land
receiving manure and sewage sludge was estimated from
nitrogen application data from the Agricultural Soil
Management section of the Agriculture chapter of this
volume, and an assumed application rate derived from
Kellogg et al. (2000). The total land area was subdivided
between cropland and grazing land based on supplemental
information collected by the USDA (ERS 2000, NASS
2002). Carbon storage rate was estimated at 0.10 metric
tons C per hectare per year for cropland and 0.33 metric
tons C per hectare per year for grazing land. To estimate
the carbon impacts of changes in Conservation Reserve
Program enrollment after 1997, the changes in Conservation
Reserve Program acreage relative to 1997 were derived
based on Barbarika (2002), and the mineral soil changes
were multiplied by 0.5 metric tons C per hectare per year.
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 6-10) by CO2 emission
factors (0.120 metric ton C/metric ton limestone, 0.130
metric ton C/metric ton dolomite).12 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, 2002; USGS 2002). 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).
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 in that same
year. In addition, data were not available for 1990, 1992,
and 2001 on the fractions of total crushed stone production
that were limestone and dolomite, and on the 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 and 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 2001 data,
the 2000 fractions were applied to a 2001 estimate of total
crushed stone presented in the USGS Mineral Industry
Surveys: Crushed Stone and Sand and Gravel in the First
Quarter of 2002 (USGS 2002).
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 Yearbook began rounding (to the nearest
thousand) quantities for total crushed stone produced or
12 The default emission factor for dolomite provided in the Workbook volume of the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 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
-------
Box 6-1: 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 (e.g., crop residues, manure) and carbon emissions from organic matter decomposition, which are
governed by climate and soil 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 largely from the same sources as in the IPCC-based method (i.e., 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 Conser-
vation Technology Information Center (CTIC). In addition, the Century analysis used detailed information on crop rotation-specific fertili-
zation and tillage implements obtained from USDA's Economic Research Service. The main difference between the methods is that the
climate, soil and management data serve as 'driving variables' in the Century simulation, whereas in the IPCC approach these data are
more highly aggregated and are used for classification purposes. 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 mineral soils (excluding organic
soils) are currently acting as a carbon sink. The Century model estimates are that U.S. cropland soils sequester approximately 77 Tg C02
Eq. per year (21 Tg C/year) (average rates for 1992 through 1997). Organic soils (which contribute large C losses) were not simulated by
Century.
As with the IPCC method, increases in mineral soil C stocks in the Century analysis are associated with reduced tillage, Conservation
Reserve Program lands, reduced bare fallow and some increase in hay area. However, the Century analysis also includes the effect of a
long-term trend in increasing residue inputs due to higher productivity on cropland in general, which contributes to the increase in soil
carbon stocks. However, further work is needed to refine model input data and to estimate uncertainty for the dynamic model approach.
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.
used. It then reported revised (rounded) quantities for each includes some points designated as non-agricultural land-uses
of the years from 1990 to 1993. In order to minimize the if this designation changed during the period from 1992 to 1997.
inconsistencies in the activity data, these revised production The non-agricultural land uses are urban, water, and
numbers have been used in all of the subsequent calculations. miscellaneous non-cropland (e.g., roads and barren areas). The
impact on carbon storage resulting from converting cropland
UnCGftdinty to non-agricultural uses is not well understood, and therefore,
Although the mineral and organic soil estimates have been those points were not included in the calculations. Third, this
improved from previous years using a Monte Carlo approach inventory may underestimate losses of carbon from organic
with the incorporation of U.S.-specific reference carbon stocks soils because the 7997 National Resources Inventory was not
and management factor values, some limitations do remain in designed as a soil survey and organic soils frequently occur as
the analysis. First, minimal data exist on where and how much relatively small inclusions within major soil types. Lastly, this
manure and sewage sludge has been applied to U.S. agricultural methodology does not take into account changes in carbon
lands. Consequently, uncertainties have not been estimated stocks due to pre-1982 land use and land-use change.
for the change in soil organic carbon storage resulting from A revised inventory approach to better quantify
these applications. Second, due to the IPCC requirement that uncertainty and to better represent between-year variability
inventories include all land areas that are potentially subject to ;n annual fluxes is being developed and is currently under
land-use change, the 1997 National Resources Inventory datoset
6-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
review. This new annual activity-based inventory, using a
dynamic simulation model, would use climate, soil, and land-
use/land-management databases to estimate annual variation
in fluxes and include the effects of long-term trends in
agricultural productivity on soil carbon stocks (see Box 6-1).
Uncertainties in the estimates of emissions from liming
result from both the methodology and the activity data. The
IPCC method assumes that all the inorganic carbon in the
applied minerals evolves to CO2, and that this degradation
occurs in the same year that the minerals are applied.
However, recent research has shown that liming can either
be a carbon source or a sink, depending upon weathering
reactions, which are pH dependent (Hamilton et al. 2002).
Moreover, it can take several years for agriculturally applied
limestone and dolomite to degrade completely. However,
application rates are fairly constant over the entire time
series, so this latter assumption may not contribute
significantly to overall uncertainty.
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 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.
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,
Table 6-11: Net C02 Flux from Landfilled Yard
Trimmings (Tg C02 Eq.)
Year
Tg CO; Eq.
1990
(18.2)
1995
1996
1997
1998
1999
2000
2001
(11.6)
(9.7)
(9.0)
(8.7)
(7.8)
(6.9)
Note: Parentheses indicate net storage. Shaded area indicates values
based on projections.
programs banning or discouraging disposal have led to an
increase in backyard composting and the use of mulching
mowers, and a consequent 21 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 26
percent in 2001. The decrease in the yard trimmings landfill
disposal rate has resulted in a decrease in the rate of landfill
carbon storage from approximately 18 Tg CO2 Eq. in 1990
to 5 Tg CO2 Eq. in 2001 (Table 6-11).
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 CH4 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 (see Table
6-12). For purposes of this analysis, these were converted
to wet weight basis using assumed moisture contents of
Land-Use Change and Forestry 6-19
-------
Table 6-12: Storage Factor (kg C/kg dry yard
trimmings), Moisture Content (kg water/kg wet yard
trimmings), Yard Trimmings Composition (percent),
and Carbon Storage Factor (kg C/kg wet yard
trimmings) of Landfilled Yard Trimmings
Grass
Leaves
Branches
Storage Factor3
Moisture Content
Yard Trimmings
Composition
Converted Storage
Factor"
0.30
0.60
50%
0.12
0.46
0.20
25%
0.37
0.43
0.40
25%
0.26
"From Barlaz (1998), adjusted using CH4 yields in Eleazer et al.
(1997).
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 for yard trimmings is obtained by
weighting the component storage factors by the yard trimmings
composition percents.
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 0.22 (weight of carbon stored indefinitely per unit
weight of wet yard trimmings).
Data Sources
The yard trimmings discards data were taken from two
reports: Characterization of Municipal Solid Waste in the
United States: 1998 Update (Franklin Associates 1999) and
Municipal Solid Waste in the United States: 2000 Facts and
Figures (EPA 2002), which provide estimates for 1990
through 2000 (see Table 6-13). Yard trimmings discards for
2001 were projected using a linear regression of the 1990
through 2000 data. These reports do not subdivide discards
of individual materials into volumes landfilled and combusted,
although they 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 77 percent and 23 percent in 2001) for the waste stream as
a whole.13 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 Eleazer et al. (1977), and assumed moisture contents and
component fractions for yard trimmings.
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 2001 disposal
from estimates for the period from 1990 through 2000. In
addition, the methodology does not include an accounting of
changes in carbon stocks in yards.
Table 6-13: Collection and Destination of Yard Trimmings (Million Metric Tons, or Tg, wet weight)
Destination 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001
Municipal
Composting Facilities
Discarded
Landfill
Incineration
Total
3.8
27.9
22.8
5.2
31.8
4.4
27.4
22.2
5.2
31.8
4.9
26.9
21.7
5.2
31.8
6.3
23.9
19.2
4.7
30.2
7.3
21.3
17.1
4.2
28.6
8.2
18.8
14.5
4.3
26.9
9.4
15.9
12.1
3.8
25.3
10.4
14.7
11.3
3.4
25.2
11.4
13.8
10.8
2.9
25.2
12.9
12.3
9.8
2.5
25.2
14.3
10.9
8.6
2.3
25.2
1
Note: Shaded area indicates values based on projections.
13 These percents represent the percent of total municipal solid waste (MSW) discards after recovery for recycling or composting.
6-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
7. Waste
W
;aste management and treatment activities are sources of greenhouse gas emissions (see Figure 7-1). Landfills
vere the largest source of anthropogenic methane (CH4) emissions, accounting for 33 percent of the U.S. total.1
Smaller amounts of CH4 are emitted from wastewater systems by bacteria used in various treatment processes. Wastewater
treatment systems are also a potentially significant source of nitrous oxide (N2O) emissions; however, methodologies are not
currently 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 Fjgure ^.•\
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 Landfills
chapter is presented in Table 7-1 and Table 7-2.
Overall, in 2001, waste activities generated
2001 Waste Chapter GHG Sources
Wastewater
Treatment
Human
Sewage
•
I
Waste as a
Portion of all
Emissions
3.6%
50
100
Tg COz Eq
150
200
emissions of 246.6 Tg CO2 Eq., or 3.6 percent of total
U.S. greenhouse gas emissions.
Landfills
Landfills are the largest anthropogenic source of
CH4 emissions in the United States. In 2001, landfill
CH4 emissions were approximately 202.9 Tg CO2 Eq.
(9,663 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 CH4.
After being placed in a landfill, biogenic waste (such as paper, food scraps, and yard trimmings) is initially digested by
aerobic bacteria. After the oxygen has been depleted, the remaining waste is available for consumption by anaerobic
bacteria, which can 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-producing anaerobic bacteria convert these fermentation products into
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.
Waste 7-1
-------
Table 7-1: Emissions from Waste (Tg C02 Eq.)
Gas/Source
1990
CH4 236.2
Landfills 212.1
Wastewater Treatment 24.1
N20 12.7
Human Sewage 12.7
Total
248.9
Note: Totals may not sum due to Independent rounding.
Table 7-2: Emissions from Waste (Gg)
Gas/Source 1990
1995
242.7
216.1
26.6
13.9
13.9
256.6
1996
238.9
212.1
26.8
14.1
14.1
253.1
1997
234.8
207.5
27.3
14.4
14.4
249.2
1998
230.1
202.4
27.7
14.6
14.6
244.7
1999
231.9
203.7
28.2
15.1
15.1
247.0
2000
234.1
205.8
28.3
15.1
15.1
249.2
2001
231.3
202.9
28.3
15.3
15.3
246.6
1995
1996
1997 1998 1999 2000 2001
CH4 11,245
Landfills 10,099
Wastewater Treatment 1,147
N20 41
Human Sewage 41
11,557
10,290
1,267
45
45
11,378
10,100
1,278
46
46
11,182
9,880
1,301
46
46
10,957
9,639
1,318
47
47
11,042
9,701
1,341
49
49
11,146
9,798
1,348
49
49
11,013
9,663
1,350
49
49
Note: Totals may not sum due to independent rounding.
stabilized organic materials and biogas consisting of
approximately 50 percent carbon dioxide (CO2) and 50
percent CH4, by volume.2 Significant CH4 production
typically begins one or two years after waste disposal in a
landfill and may last from 10 to 60 years.
From 1990 to 2001, net CH4 emissions from landfills
decreased by approximately 4 percent (see Table 7-3 and
Table 7-4), with small increases occurring in some interim
years. This slightly downward trend in overall emissions is
the result of increases in the amount of landfill gas collected
and combusted by landfill operators, which has more than
offset the additional CH4 emissions resulting from increases
in the amount of MS W landfilled.
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 CH4 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 6,280 Tg in 2001,
an increase of 28 percent (see Annex Q'). During this
period, the estimated CH4 recovered and flared from
landfills increased as well. In 1990, for example,
approximately 1,190 Gg of CH4 were recovered and
combusted (i.e., used for energy or flared) from landfills.
In 2001, the estimated quantity of CH4 recovered and
combusted increased to 5,263 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 CH4 that is recovered and either flared or used for energy
purposes is expected to increase, 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 2002),
and an EPA program that encourages voluntary CH4 recovery
and use at landfills not affected by the regulation.
Methodology
Methane emissions from landfills were estimated to
equal the CH4 produced from municipal landfills, minus the
CH4 recovered and combusted, plus the CH4 produced by
industrial landfills, minus the CH4 oxidized before being
released into the atmosphere.
2 The percentage of CO2 in biogas released from a landfill may be smaller because some CO2 dissolves in landfill water (Bingemer and Crutzen 1987).
Additionally, less than 1 percent of landfill gas is composed of non-methane volatile organic compounds (NMVOCs).
7-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
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 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
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 153 Tg C02 Eq. and 5 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.
Table 7-3: CH4 Emissions from Landfills (Tg C02 Eq.)
Activity
1990
MSW Landfills
Industrial Landfills
Recovered
Gas-to-Energy
Flared
Oxidized1
243.6
17.1
(15.4)
(9.6)
(23.6)
Total
212.1
1995
Note: Totals may not sum due to independent rounding.
11ncludes oxidation at both municipal and industrial landfills.
Table 7-4: CH4 Emissions from Landfills (Gg)
Activity
MSW Landfills
Industrial Landfills
Recovered
Gas-to-Energy
Flared
Oxidized1
Total
1990
11,559
812
(732)
(458)
(1,122)
10,099
1995
13,238
927
(1,064)
(1,668)
(1,143)
Note: Totals may not sum due to independent rounding.
11ncludes oxidation at municipal and industrial landfills.
1996
1997 1998 1999 2000 2001
278.0
19.5
(22.3)
(35.0)
(24.0)
216.1
283.9
19.9
(25.6)
(42.5)
(24.2)
212.1
289.8
20.3
(30.5)
(49.1)
(24.2)
207.5
295.0
20.6
(36.8)
(53.9)
(24.1)
202.4
302.1
21.1
(42.0)
(54.8)
(23.7)
203.7
307.8
21.5
(45.9)
(54.8)
(23.2)
205.8
314.0
22.0
(50.3)
(60.2)
(22.6)
202.9
1996
1997
1998 1999 2000 2001
13,520
946
(1,220)
(2,024)
(1,154)
13,802
966
14,047
983
(1,452) (1,752)
(2,338) (2,568)
(1,155) (1,149)
14,385
1,007
(2,002)
(2,611)
(1,128)
14,659
1,026
14,954
1,047
(2,187) (2,396)
(2,611) (2,867)
(1,104) (1,077)
10,290 10,100 9,880 9,639 9,701 9,798 9,663
Waste 7-3
-------
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 1986. 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 CH4 generation was estimated using its year
of opening, its waste acceptance rate, year of closure, and
design capacity. Data on national municipal waste landfilled
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 Q.
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 compiled
by EPA's Landfill Methane Outreach Program (LMOP). Based
on the information provided by vendors, the CH4 combusted by
642 flares in operation from 1990 to 2001 was estimated. This
quantity likely underestimates flaring, because EPA does not have
information on all flares in operation. Additionally, the LFGTE
database provided data on landfill gas flow and energy generation
for 334 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 seven percent of the total CH4 emissions from municipal
landfills (EPA 1993). The amount of CH4 oxidized by the
landfill cover at both municipal and industrial landfills was
assumed to be ten percent of the CH4 generated that is not
recovered (Liptay et al. 1998). To calculate net CH4 emissions,
both CH4 recovered and CH4 oxidized were subtracted from
CH4 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 generation and disposal data
for 1991 through 2001 were obtained from BioCycle (2001).
Because BioCycle does not account for waste generated in
U.S. territories, waste generation for the territories was
estimated using population data obtained from the U.S. Census
Bureau (2000) and per capita MSW generation from EPA's
Municipal Solid Waste Disposal in the United States report
(2002a). Documentation on the landfill CH4 emissions
methodology employed is available in EPA's Anthropogenic
Methane Emissions in the United States, Estimates for 1990:
Report to Congress (EPA 1993). Information on flares was
obtained from vendors (ICF 2002), and information on landfill
gas-to-energy projects was obtained from the EPA's Landfill
Methane Outreach Program database (EPA 2002a).
Uncertainty
Several types of uncertainty are associated with the
estimates of CH4 emissions from landfills. The primary
uncertainty concerns the characterization of landfills.
Information is not available for waste in place for every
landfill - a fundamental factor that affects CH4 production.
The heterogeneity of waste disposed in landfills is uncertain
as well. The approach used here assumes that the landfill
set is representative of waste composition and reflects this
heterogeneity. Also, the approach used to estimate the
contribution of industrial non-hazardous wastes to total CH4
generation employs introduces uncertainty. Aside from
uncertainty in estimating CH4 generation potential,
uncertainty exists in the estimates of oxidation efficiency.
Overall, uncertainty in the landfill CH4 emission rate is
estimated to be roughly ±30 percent.
The N2O emissions from application of sewage sludge
on landfills are not explicitly modeled as part of greenhouse
gas emissions from landfills. Nitrous oxide emissions from
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: 1990-2001
-------
sewage sludge applied to landfills would be relatively small
because the microbial environment in landfills is not very
conducive to the nitrification and denitrification processes
that result in N2O emissions. The total nitrogen (N) in sewage
sludge increased from 178 to 234 Gg total N between 1990
and 2001. The quantity of sewage sludge applied to landfills
decreased from 28 to 11 percent from 1990 to 2001.
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 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.
The organic content, expressed in terms of either
biochemical oxygen demand (BOD) or chemical oxygen
demand (COD), determines the CH4 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 CH4 than wastewater with lower BOD or COD.
In 2001, CH4 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 following industries: pulp and paper;
meat and poultry processing; and vegetables, fruits and juices
processing.4 In 2001, CH4 emissions from industrial
wastewater treatment were 14.5TgCO2Eq. (690Gg). Table
7-5 and Table 7-6 provide emission estimates from domestic
and industrial wastewater treatment.
Table 7-5: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Tg C02 Eq.)
Activity
Domestic
Industrial*
Total
1990 \
12.1
12.0 ^;,
24.1 v , '.
1995
12.9
13.7
26.6
1996
13.0
13.8
26.8
1997
13.2
14.2
27.3
1998
13.4
14.3
27.7
1999
13.5
14.6
28.2
2000
13.7
14.6
28.3
2001
13.9
14.5
28.3
* Industrial activity includes the following industries: pulp and paper; meat and poultry; and vegetables, fruits and juices processing.
Note: Totals may not sum due to independent rounding.
Table 7-6: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Gg)
Activity 1990 U 1995 1996 1997 1998 1999 2000
* Industrial activity includes the following industries: pulp and paper; meat and poultry; and vegetables, fruits and juices processing.
Note: Totals may not sum due to independent rounding.
1 Industrial wastewater emissions from petroleum systems are included in the petroleum systems section in the Energy chapter.
2001
Domestic
Industrial*
Total
576 " ,
571
1,147 >:':
613
653
1,267
620
658
1,278
627
674
1,301
637
681
1,318
644
697
1,341
651
697
1,348
660
690
1,350
Waste 7-5
-------
Methodology
Domestic wastewater CH4 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
wastewater BOD produced. It was assumed that 0.065
kilograms of wastewater BOD55 was produced per day per
capita and that 16.25 percent of wastewater BOD5 was
anaerobically digested. This proportion of BOD was then
multiplied by an emission factor of 0.6 kg CH4/kg BOD5.
A top-down approach was used to develop estimates of
CH4 emissions from industrial wastewater according to the
methodology described in the IPCC Good Practice
Guidance (IPCC 2000). Industry categories were identified
that are likely to have significant CH4 emissions from their
wastewater treatment. 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 (mVton 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 (World Bank
1999, Nemerow 1991). The most important step is
lagooning for storage, settling, and biological treatment
(secondary treatment). In developing estimates for this
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).
The meat and poultry processing industry makes
extensive use of anaerobic lagoons, 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 2001 used in the
domestic wastewater emissions estimates, were based on
data from the U.S. Census Bureau (2001). Per-capita
production of BOD5 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 CH/kg COD (IPCC 2000).
Table 7-7 provides U.S. population and wastewater
BOD data.
' The 5-day biochemical oxygen demand (BOD) measurement (Metcalf and Eddy 1991).
7-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
Table 7-7: U.S. Population (Millions) and Wastewater
BOD Produced (Gg)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
Population
249
252
255
257
261
265
268
271
275
278
281
285
BOD5
5,905
5,983
6,054
6,102
6,196
6,291
6,363
6,434
6,529
6,600
6,681
6,766
Table 7-8: U.S. Pulp and Paper, Meat and Poultry,
and Vegetables, Fruits and Juices Production
(Million Metric Tons)
For pulp and paper, a time series of CH4 emissions for
post-1990 years was developed based on production figures
reported in the Lockwood-Post Directory (Lockwood-Post
Directory 1992 - 2002). 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
of 2 to 7) g/liter. These parameters are currently undergoing
review, based on a recent comprehensive survey conducted
by EPA's Office of Water (EPA, 2002).
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 mVton 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.
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
Pulp and paper
128.9
129.2
134.5
134.1
139.3
140.9
140.3
145.6
144.0
145.1
142.8
134.3
Meat and
Poultry
28.2
29.0
30.0
31.0
32.0
33.6
34.2
34.6
35.7
37.0
37.4
38.6
Vegetables
Fruits and Juices
29.7
30.8
32.9
33.6
36.7
36.2
35.9
37.1
35.9
36.8
38.3
34.3
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.
Large uncertainties are associated with the industrial
wastewater emission estimates. Wastewater outflows and
organics loading 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).
Waste 7-7
-------
Human Sewage (Domestic Wastewater)
Domestic human sewage is usually mixed with other
household wastewater, 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 treatment (WWT) system, or a
centralized WWT system. Decentralized WWT systems are
septic systems and package plants. Centralized WWT
systems may include a variety of processes, ranging from
lagooning to advanced tertiary treatment technology for
removing nutrients. Often, centralized WWT systems also
treat certain flows of industrial, commercial, and institutional
wastewater. 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
Earth's surface.
Nitrous oxide may be generated during both nitrification
and denitriflcation of the nitrogen present, usually in the
form of urea, ammonia, and proteins. These are converted
to nitrate via nitrification, an aerobic process converting
ammonia-nitrogen into nitrate (NO3"). Denitrification occurs
under anoxic conditions (without free oxygen), and involves
the biological conversion of nitrate into dinitrogen gas (N2).
Nitrous oxide can be an intermediate product of both
processes, but is more often associated with denitriflcation.
The U.S. quantifies two distinct sources for N2O
emissions from domestic wastewater: emissions from
wastewater treatment (WWT) processes, and emissions from
effluent that has been discharged into aquatic environments.
The 2001 emissions of N2O from WWT processes and from
effluent were estimated to be 0.3 Tg CO2 Eq. (0.9 Gg) and
Table 7-9: N20 Emissions from Human Sewage
Year
Tg C02 Eq.
Gg
1990
12.7
41
|V
1995
1996
1997
1998
1999
2000
2001
13.9
14.1
14.4
14.6
15.1
15.1
15.3
45
46
46
47
49
49
49
15.0 Tg CO2 Eq. (48.5 Gg), respectively. Total N2O
emissions from domestic wastewater were estimated to be
15.3 Tg C02 Eq. (49.3 Gg). (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 three modifications (see
below). The IPCC method assumes that nitrogen disposal—
and thus N2O emissions associated with land disposal,
subsurface disposal, as well as domestic WWT—are
negligible and that all nitrogen is discharged directly into
aquatic environments.
• In the United States, some nitrogen is removed with the
sewage sludge, which is land applied, incinerated or
landfilled. The nitrogen disposal into aquatic environments
is thus reduced to account for the sewage sludge application.
• Emissions from wastewater treatment plants (WWTPs)
are not accounted for in the current IPCC methodology.
A new overall emission factor of 4 g N2O/person.year
is used to estimate N2O emissions from U.S. municipal
WWTPs. This emission factor is based on a factor of
3.2 g N2O/person-year (Czepiel, 1995) multiplied by
1.25 to adjust for co-discharged industrial nitrogen. The
nitrogen quantity associated with these emissions is
calculated by multiplying the N2O emitted by ^2xl4)/44.
• The IPCC method uses annual, per capita protein
consumption (kg/year). This number is likely to
underestimate the amount of protein entering the sewer or
septic system. Food (waste) that is not consumed is often
washed down the drain, as a result of the use of garbage
disposals. Also, bath and laundry water can be expected
to contribute to nitrogen loadings. Furthermore, industrial
wastewater co-discharged with domestic wastewater is not
accounted for in the existing methodology. A factor of
1.75 is applied to protein consumption to account for the
extra nitrogen from these sources.
With the modifications described above, N2O emissions
from domestic wastewater were estimated using the IPCC
default methodology (IPCC/UNEP/OECD/IEA 1997). This
methodology is illustrated below:
7-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
N2O(s) = (US
pOP
Frac
F1CI
PR
US
'-^
0.75 x EF,) + {[(Protein x 1.75
) - N - N 1 x EF x 44/ }
' ^WWT sludge-1 2 ' 2$>
where,
N2O(s) = N2O emissions from domestic wastewater
("human sewage")
USpop = U.S. population
0.75 = Fraction of population using WWTPs
(as opposed to septic systems)
EF, = Emission factor (4 g N2O/person.year)
Protein = Annual, per capita protein consumption
1.75 = Fraction of non-consumption protein in
domestic wastewater
= Fraction of nitrogen in protein
= Quantity of wastewater nitrogen removed by
WWT processes [(USPOP x 0.75 x EF,) x 28/4J
= Quantity of sewage sludge N not entering
aquatic environments
= Emission factor (kg N2O-N/kg sewage-N
produced)
= The molecular weight ratio of N2O to N2
Frac
'NPR
N
WWT
N
sludge
EF
44
/ \
' -&>
Data Sources
U.S. population data were taken from the U.S. Census
Bureau (2001). The fraction of the US population using
WWTPs is from the NEEDS Survey (1996). The emission
factor (EF,) used to estimate emissions from WWT is based
on Czepiel, et al. (1995). 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 2001,
the value of per capita protein consumption for the previous
year was used. The fraction of non-consumption protein
in domestic wastewater is based on expert judgment and
on Metcalf & Eddy (1991) and Mullick (1987). An
emission factor to estimate emissions from effluent (EF2)
has not been specifically estimated for the United States,
so the default IPCC value (0.01 kg N2O-N/kg sewage-N
Table 7-10: U.S. Population (Millions) and Average
Protein Intake (kg/Person/Year)
Year
Population
Protein
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
250
253
257
260
263
266
269
273
276
279
282
285
39.2
39.8
40.0
40.2
41.2
40.6
40.7
41.0
41.1
41.9
41.6
41.6
produced) was applied. 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 (FracNpR) are
believed to be fairly accurate. Large uncertainty exists,
however, in the emission factor for effluent (EF2). 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. Also, the emission
factor for emissions from WWT (EF,) is uncertain. When
more plants incorporate nitrification/denitrification in the
future, this emission factor is likely to increase. However,
emissions from WWT are less significant than emissions
from effluent-surface water. Taken together, these
uncertainties present significant difficulties in estimating
N2O emissions from domestic wastewater.
Waste 7-9
-------
Table 7-11: Emissions of NOX, CO, and NMVOC from Waste (Gg)
Gas/Source
1990
NOX
Landfills
Wastewater Treatment
Miscellaneous3
CO
Landfills
Wastewater Treatment
Miscellaneous3
NMVOCs
Landfills
Wastewater Treatment
Miscellaneous3
+
+
+
+
1
1
+
+
673
58
57
558
1995
1996
1997 1998 1999 2000 2001
1
1
1
2
2
+
1
731
68
61
602
3
2
1
5
5
+
+
158
32
61
65
3
2
1
5
5
+
+
157
32
62
64
3
2
1
5
5
+
+
161
33
63
65
3
3
+
14
13
1
+
151
29
64
58
3
3
+
14
13
1
+
153
29
65
59
3
3
+
14
13
1
+
158
30
68
60
a Miscellaneous Includes TSDFs (Treatment, Storage, and Disposal Facilities under the Resource Conservation and Recovery Act [42 U.S.C. § 6924,
SWDA § 3004]) and other waste categories.
Note: Totals may not sum due to independent rounding.
+ Does not exceed 0.5 Gg
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 NOx, CO, and NMVOCs from waste sources for the years
1990 through 2001 are provided in Table 7-11.
Methodology and Data Sources
These emission estimates were taken directly from EPA
data published on the National Emission Inventory (NEI)
Air Pollutant Emission Trends web site (EPA 2003). 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.
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
data bases.
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: 1990-2001
-------
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UEP (1999) Voluntary Survey Results - Estimated
Percentage Participation/Activity, Caged Layer
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John Thome, Capitolink. June 2000.
USDA (2002a) Cattle, U.S. Department of Agriculture,
National Agriculture Statistics Service, Washington, DC.
February 1. (Data also available from ).
USDA (2002b) Cattle on Feed Cattle, U.S. Department of
Agriculture, National Agriculture Statistics Service,
Washington, DC. January 18. (Data also available from
).
USDA (2002c) Hogs and Pig, U.S. Department of
Agriculture, National Agriculture Statistics Service,
Washington, DC. March 28. (Data also available from
).
USDA (2002d) Chicken and Eggs Annual Summary, U.S.
Department of Agriculture, National Agriculture Statistics
Service, Washington, DC. January 29, revised March 22.
(Data also available from ).
USDA (2002e) Poultry Production and Value Annual
Summary, U.S. Department of Agriculture, National
Agriculture Statistics Service, Washington, DC. April 29,
revised May 3. (Data also available from ).
USDA (2002f) Sheep and Goats, U.S. Department of
Agriculture, National Agriculture Statistics Service,
Washington, DC. February 1. (Data also available from
).
USDA (2001 a) Cattle, U.S. Department of Agriculture,
National Agriculture Statistics Service, Washington, DC.
January 26. (Data also available from ).
USDA (200Ib) Cattle on Feed Cattle, U.S. Department of
Agriculture, National Agriculture Statistics Service,
Washington, DC. January 19. (Data also available from
).
USDA (200Ic) Hogs and Pig, U.S. Department of
Agriculture, National Agriculture Statistics Service,
Washington, DC. March 30. (Data also available from
).
USDA (200 Id) Chicken and Eggs - 1999 Summary
Cattle, U.S. Department of Agriculture, National
Agriculture Statistics Service, Washington, DC. January.
USDA (2001 e) Poultry Production and Value - 1999
Summary, U.S. Department of Agriculture, National
Agriculture Statistics Service, Washington, DC. April.
USDA (200If) Sheep and Goats, U.S. Department of
Agriculture, National Agriculture Statistics Service,
Washington, DC. January. (Data also available from
).
USDA (200Ig) Published Estimates Database, U.S.
Department of Agriculture, National Agricultural
Statistics Service, Washington, DC. Downloaded from
. September 26.
USDA (2000a) Cattle, U.S. Department of Agriculture,
National Agriculture Statistics Service, Washington, DC.
January 28. (Data also available from ).
8-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001
-------
USDA (2000b) Cattle on Feed Cattle, U.S. Department of
Agriculture, National Agriculture Statistics Service,
Washington, DC. April 14. (Data also available from
).
USDA (2000c) Hogs and Pig, U.S. Department of
Agriculture, National Agriculture Statistics Service,
Washington, DC. March 24. (Data also available from
).
USDA (2000d) Chicken and Eggs -1999 Summary
Cattle, U.S. Department of Agriculture, National
Agriculture Statistics Service, Washington, DC. January.
USDA (2000e) Poultry Production and Value - 1999
Summary, U.S. Department of Agriculture, National
Agriculture Statistics Service, Washington, DC. April.
USDA (2000f) Sheep and Goats, U.S. Department of
Agriculture, National Agriculture Statistics Service,
Washington, DC. January. (Data also available from
).
USDA (2000g) Chicken and Eggs - Final Estimates
1988-1993, U.S. Department of Agriculture, National
Agriculture Statistics Service, Washington, DC.
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sets/livestock/95908/sb908.txt. May 3.
USDA (2000h) Re-aggregated data from the National
Animal Health Monitoring System's (NAHMS) Dairy '96
study provided by Stephen L. Ott of the U.S. Department
of Agriculture, Animal and Plant Health Inspection
Service. June 19.
USDA (2000i) Layers '99 - Part II: References of 1999
Table Egg Layer Management in the U.S., U.S.
Department of Agriculture, Animal and Plant Health
Inspection Service (APHIS), National Animal Health
Monitoring System (NAHMS). January.
USDA (1999a) Cattle - Final Estimates 1994-98, U.S.
Department of Agriculture, National Agriculture Statistics
Service, Washington, DC. January. (Data also available
from ).
USDA (1999b) Poultry Production and Value - Final
Estimates 1994-97, U.S. Department of Agriculture, National
Agriculture Statistics Service, Washington, DC. March.
USDA (1999c) Sheep and Goats - Final Estimates 1994-
1998, U.S. Department of Agriculture, National
Agriculture Statistics Service, Washington, DC. January.
USDA (1999d) , Table 25.
Miscellaneous Livestock and Animal Specialties
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Agriculture, National Agriculture Statistics Service,
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USDA (1999e) 1992 and 1997 Census of Agriculture
(CD-ROM), U.S. Department of Agriculture, National
Agriculture Statistics Service, Washington, DC.
USDA (1998a) Hogs and Pigs - Final Estimates 1993-97,
U.S. Department of Agriculture, National Agriculture
Statistics Service, Washington, DC. December. (Data also
available from ).
USDA (1998b) Chicken and Eggs - Final Estimates 1994-
97, U.S. Department of Agriculture, National Agriculture
Statistics Service, Washington, DC. December.
USDA (1998c) Nutrients Available from Livestock
Manure Relative to Crop Growth Requirements, Resource
Assessment and Strategic Planning Working Paper 98-1,
U.S. Department of Agriculture, Natural Resources
Conservation Service. February.
USDA (1998d) Re-aggregated data from the National
Animal Health Monitoring System's (NAHMS) Swine '95
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Agriculture, Centers for Epidemiology and Animal Health.
USDA (1996a) Agricultural Waste Management Field
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from ).
USDA (1995b) Poultry Production and Value - Final
Estimates 1989-1993, U.S. Department of Agriculture,
National Agriculture Statistics Service, Washington, DC.
January.
USDA (1994a) Hogs and Pigs - Final Estimates 1988-92,
U.S. Department of Agriculture, National Agriculture
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available from ).
USDA (1994b) Sheep and Goats - Final Estimates 1989-
1993, U.S. Department of Agriculture, National Agriculture
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Ann Tracy of ERG and Peter Wright, Cornell University,
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Rice Cultivation
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Palm Beach County Agricultural Extension Agent,
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Caren Mintz of ICF Consulting and Tom Schueneman, Palm
Beach County Agricultural Extension Agent, Florida, 9 October.
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Payton Deeks of ICF Consulting and Tom Schueneman, Palm
Beach County Agricultural Extension Agent, Florida, 16 May.
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Catherine Leining of ICF Consulting and Tom
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Payton Deeks of ICF Consulting and Tom Schueneman, Palm
Beach County Agricultural Extension Agent, Florida, 10 August.
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John Venezia of ICF Consulting and Tom Schueneman,
Palm Beach County Agricultural Extension Agent,
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Barbara Braatz of ICF Incorporated and Tom Schueneman,
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Agronomist - Rice, University of Arkansas Division of
Agriculture Cooperative Extension Service, 23 August.
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Mintz of ICF Consulting and Nathan Slaton, Extension
Agronomist - Rice, University of Arkansas Division of
Agriculture Cooperative Extension Service, 3 October.
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Deeks of ICF Consulting and Nathan Slaton, Extension
Agronomist - Rice, University of Arkansas Division of
Agriculture Cooperative Extension Service, 20 May.
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Electricity Generation: Electricity generation
in the United States is composed of
traditional electric utilities, cogenerators,
and non-utility power producers. This
economic sector includes the generation,
transmission, and distribution of electricity.
Emissions result primarily in the form of
CO2 from fossil fuel combustion. Electricity generation accounts
for approximately one-third of all U.S. greenhouse gas emis-
sions, making it the largest emitter among the economic sectors.
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 CH4 emissions from
livestock due to enteric fermentation and
manure management, and then CO2 from fossil fuel combustion.
Smaller quantities of CH4 and N2O emissions are derived from
rice cultivation, agricultural residue burning, and mobile and
stationary combustion.
Residential: Residential sector greenhouse
gas emissions are dominated by CO2 from
fossil fuel combustion, used mainly to
heat and supply electricity to homes.
Methane and N2O also occur from
stationary combustion for home heating
and electricity, while HFC emissions arise
from refrigeration and air-conditioning equipment as well as
medical and consumer product aerosols.
Transportation: Emissions from this
economic sector have been steadily
increasing from 1990 through 2001 due
to several factors, including an increased
demand for travel. While transportation
emissions are primarily from highway
vehicles, they are also generated from
airplanes, boats, trains, and other equipment.
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v>EPA
United States
Enviromental Protection
Agency
EPA 430-R-03-004 April 2003
Office of Atmospheric Programs (6204N)
Washington, DC 20460
Official Business
Penalty for Private Use
$300
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