EPA 430-R-05-003
INVENTORY OF U.S. GREENHOUSE GAS EMISSIONS AND SINKS:
1990-2003
APRIL 15, 2005
U.S. Environmental Protection Agency
1200 Pennsylvania Ave., N.W.
Washington, DC 20460
U.S.A.
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[Inside Front Cover]
HOW TO OBTAIN COPIES
You can electronically download this document on the U.S. EPA's homepage at
. To request free copies of this report, call the
National Service Center for Environmental Publications (NSCEP) at (800) 490-9198, or visit the web site above and
click on "order online" after selecting an edition.
All data tables of this document are available for the full time series 1990 through 2003, inclusive, at the internet
site mentioned above.
FOR FURTHER INFORMATION
Contact Mr. Leif Hockstad, Environmental Protection Agency, (202) 343-9432, hockstad.leif@epa.gov.
Or Ms. Lisa Hanle, Environmental Protection Agency, (202) 343-9434, hanle.lisa@epa.gov.
For more information regarding climate change and greenhouse gas emissions, see the EPA web site at
.
Released for printing: April 15,2005
[INSERT DISCUSSION OF COVER DESIGN]
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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 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 HFCs, PFCs, and SF6 was directed by Deborah Schafer and Dave
Godwin. John Davies directed the work on 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 Energy
Policy and Programs Practice, including John Venezia, Leonard Crook, Diana Pape, Meg Walsh, Michael Grant,
Beth Moore, Ravi Kantamaneni, Robert Lanza, Chris Steuer, Lauren Flynn, Kamala Jayaraman, Dan Lieberman,
Jeremy Scharfenberg, Matt Stanberry, Rebecca LePrell, Philip Groth, Sarah Percy, Daniel Karney, Brian Gillis,
Zachary Schaffer, Vineet Aggarwal, Lauren Pederson, and Toby Mandel for synthesizing this report and preparing
many of the individual analyses. Eastern Research Group, Raven Ridge Resources, and Arcadis also provided
significant analytical support.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page i
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Preface
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 UNFCCC 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(1 )(a) of the United Nations Framework Convention on Climate Change .
2 See .
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page
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Table of Contents
ACKNOWLEDGMENTS I
TABLE OF CONTENTS III
LIST OF TABLES, FIGURES, AND BOXES VI
Tables vi
Figures vi
Boxes xiv
EXECUTIVE SUMMARY ES-1
ES.l. Background Information ES-1
ES.2. Recent Trends in U.S. Greenhouse Gas Emissions and Sinks ES-3
ES.3. Overview of Sector Emissions and Trends ES-9
ES.4. Other Information ES-12
1. INTRODUCTION 1
1.1. Background Information 2
1.2. Institutional Arrangements 10
1.3. Inventory Process 10
1.4. Methodology and Data Sources 12
1.5. Key Sources 13
1.6. Quality Assurance and Quality Control 16
1.7. Uncertainty Analysis of Emission Estimates 17
1.8. Completeness 18
1.9. Organization of Report 18
2. TRENDS IN GREENHOUSE GAS EMISSIONS 21
2.1. Recent Trends in U.S. Greenhouse Gas Emissions 21
2.2. Emissions by Economic Sector 42
2.3. Ambient Air Pollutant Emissions 48
3. ENERGY 51
3.1. Carbon Dioxide Emissions from Fossil Fuel Combustion (IPCC Source Category 1 A) 52
3.2. Carbon Emitted from Non-Energy Uses of Fossil Fuels (IPCC Source Category 1A) 69
3.3. Stationary Combustion (excluding CO2) (IPCC Source Category 1A) 75
3.4. Mobile Combustion (excluding CO2) (IPCC Source Category 1A) 81
3.5. Coal Mining (IPCC Source Category IBla) 92
3.6. Abandoned Underground Coal Mines (IPCC Source Category IBla) 95
3.7. Petroleum Systems (IPCC Source Category lB2a) 99
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page iii
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3.8. Natural Gas Systems (IPCC Source Category lB2b) 102
3.9. Municipal Solid Waste Combustion (IPCC Source Category 1 A5) 106
3.10. Natural Gas Flaring and Ambient Air Pollutant Emissions from Oil and Gas Activities (IPCC Source
Category 1B2) 111
3.11. International Bunker Fuels (IPCC Source Category 1 : Memo Items) 113
3.12. Wood Biomass and Ethanol Consumption (IPCC Source Category 1A) 118
4. INDUSTRIAL PROCESSES 123
4. 1 . Iron and Steel Production (IPCC Source Category 2C 1 ) 125
4.2. Cement Manufacture (IPCC Source Category 2A1) 129
4.3. Ammonia Manufacture and Urea Application (IPCC Source Category 2B1) 132
4.4. Lime Manufacture (IPCC Source Category 2A2) 136
4.5. Limestone and Dolomite Use (IPCC Source Category 2A3) 140
4.6. Soda Ash Manufacture and Consumption (IPCC Source Category 2A4) 143
4.7. Titanium Dioxide Production (IPCC Source Category 2B5) 146
4.8. Phosphoric Acid Production (IPCC Source Category 2A7) 148
4.9. Ferroalloy Production (IPCC Source Category 2C2) 151
4. 1 0. Carbon Dioxide Consumption (IPCC Source Category 2B5) 1 53
4.11. Petrochemical Production (IPCC Source Category 2B5) 1 57
4. 1 2. Silicon Carbide Production (IPCC Source Category 2B4) 1 60
4.13. Nitric Acid Production (IPCC Source Category 2B2) 161
4. 14. Adipic Acid Production (IPCC Source Category 2B3) 163
4.15. Substitution of Ozone Depleting Substances (IPCC Source Category 2F) 1 66
4. 16. HCFC-22 Production (IPCC Source Category 2E1) 168
4. 17. Electrical Transmission and Distribution (IPCC Source Category 2F7) 170
4.18. Aluminum Production (IPCC Source Category 2C3) 174
4.19. Semiconductor Manufacture (IPCC Source Category 2F6) 179
4.20. Magnesium Production and Processing (IPCC Source Category 2C4) 182
4.21. Industrial Sources of Ambient Air Pollutants 1 86
5. SOLVENT AND OTHER PRODUCT USE 189
5,1, Nitrous Oxide Product Usage (IPCC Source Category 3D) 1 89
5.2. Ambient Air Pollutants from Solvent Use 1 92
6. AGRICULTURE 195
6. 1 . Enteric Fermentation (IPCC Source Category 4A) 196
6,2, Manure Management (IPCC Source Category 4B) 200
6.3. Rice Cultivation (IPCC Source Category 4C) 207
6.4. Agricultural Soil Management (IPCC Source Category 4D) 212
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page iv
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6.5. Field Burning of Agricultural Residues (IPCC Source Category 4F) 222
7. LAND-USE CHANGE AND FORESTRY 229
7.1. Forest Land Remaining Forest Land 231
7.2. Land Converted to Forest Land (Source Category 5A2) 241
7.3. Croplands Remaining Croplands 241
7.4. Lands Converted to Croplands (Source Category 5B2) 249
7.5. Settlements Remaining Settlements 250
7.6. Lands Converted to Settlements (Source Category 5E2) 259
8. WASTE 261
8.1. L andfills (IPCC Source C ategory 6A1) 261
8.2. Wastewater Treatment (IPCC Source Category 6B) 265
8.3. Human Sewage (Domestic Wastewater) (IPCC Source Category 6B) 269
8.4. Waste Sources of Ambient Air Pollutants 272
9. OTHER 275
10. RECALCULATIONS AND IMPROVEMENTS 277
REFERENCES 281
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page v
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List of Tables, Figures, and Boxes
Tables
Table ES-1: Global Warming Potentials (100 Year Time Horizon) Used in this Report 3
Table ES-2: Recent Trends in U. S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq.) 4
Table ES-3: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.) 7
Table ES-4: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg CO2 Eq.) 9
Table ES-5: Net CO2 Flux from Land-Use Change and Forestry (Tg CO2 Eq.) 11
Table ES-6: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO2 Eq.) 12
Table ES-7: U.S Greenhouse Gas Emissions by Economic Sector and Gas with Electricity-Related Emissions
Distributed (Tg CO2 Eq.) 13
Table ES-8: Recent Trends in Various U.S. Data (Index 1990 = 100) and Global Atmospheric CO2 Concentration
14
Table ES-9: Emissions of NOX, CO, NMVOCs, and SO2 (Gg) 14
Table 1-1: Global atmospheric concentration (ppm unless otherwise specified), rate of concentration change
(ppb/year) and atmospheric lifetime (years) of selected greenhouse gases 3
Table 1-2: Global Warming Potentials and Atmospheric Lifetimes (Years) Used in this Report 7
Table 1 -3: Comparison of 100 Year GWPs 8
Table 1-4: Effects on U.S. Greenhouse Gas Emission Trends Using IPCC SAR and TAR GWP Values (Tg CO,
Eq.) 9
Table 1-5: Comparison of Emissions by Sector using IPCC SAR and TAR GWP Values (Tg CO2Eq.) 9
Table 1-6: Key Source Categories for the United States (1990-2003) Based on Tier 1 Approach 15
Table 1-7: IPCC Sector Descriptions 18
Table 1-8: List of Annexes 19
Table 2-1: Annual Change in CO2 Emissions from Fossil Fuel Combustion for Selected Fuels and Sectors (Tg CO2
Eq. and Percent) 22
Table 2-2: Recent Trends in Various U.S. Data (Index 1990 = 100) and Global Atmospheric CO2 Concentration 24
Table 2-3: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq.) 24
Table 2-4: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg) 26
Table 2-5: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg CO2 Eq.) 28
Table 2-6: Emissions from Energy (Tg CO2 Eq.) 28
Table 2-7: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.) 29
Table 2-8: Emissions from Industrial Processes (Tg CO2 Eq.) 33
Table 2-9: N2O Emissions from Solvent and Other Product Use (Tg CO2 Eq.) 37
Table 2-10: Emissions from Agriculture (Tg CO2 Eq.) 38
Table 2-11: Net CO2 Flux from Land-Use Change and Forestry (Tg CO2 Eq.) 39
Table 2-12: N2O Emissions from Land-Use Change and Forestry (Tg CO2 Eq.) 40
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page vi
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Table 2-13: Emissions from Waste (Tg CO, Eq.) 41
Table 2-14: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO2 Eq. and Percent of Total in
2003) " 42
Table 2-15: Electricity Generation-Related Greenhouse Gas Emissions (Tg CO, Eq.) 44
Table 2-16: U. S Greenhouse Gas Emissions by "Economic Sector" and Gas with Electricity-Related Emissions
Distributed (Tg CO, Eq,) and Percent of Total in 2003 45
Table 2-17: Transportation-Related Greenhouse Gas Emissions (Tg CO, Eq.) 47
Table 2-18: Emissions of NOX, CO, NMVOCs, and SO, (Gg) 49
Table 3-1: Emissions from Energy (Tg CO, Eq.) 51
Table 3-2: Emissions from Energy (Gg) 52
Table 3-3: CO, Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg CO, Eq.) 53
Table 3-4: Annual Change in CO, Emissions from Fossil Fuel Combustion for Selected Fuels and Sectors (Tg CO,
Eq. and Percent) 54
Table 3-5: CO, Emissions from International Bunker Fuels (Tg CO, Eq.)* 56
Table 3-6: CO, Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO, Eq.) 56
Table 3-7: CO2 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg CO2 Eq.) 57
Table 3-8: Carbon Intensity from Direct Fossil Fuel Combustion by Sector (Tg CO2 Eq./QBtu) 62
Table 3-9: Carbon Intensity from all Energy Consumption by Sector (Tg CO, Eq./QBtu) 62
Table 3-10: Tier 2 Quantitative Uncertainty Estimates for CO, Emissions from Energy-related Fossil Fuel
Combustion by Fuel Type and Sector (Tg CO, Eq. and Percent) 67
Table 3-11: CO, Emissions from Non-Energy Use Fossil Fuel Consumption (Tg CO, Eq.) 69
Table 3-12: Adjusted Consumption of Fossil Fuels for Non-Energy Uses (TBtu) 71
Table 3-13: 2003 Adjusted Non-Energy Use Fossil Fuel Consumption, Storage, and Emissions 71
Table 3-14: Tier 2 Quantitative Uncertainty Estimates for CO, Emissions from Non-Energy Uses of Fossil Fuels
(Tg CO, Eq. and Percent) 73
Table 3-15: Tier 2 Quantitative Uncertainty Estimates for Storage Factors of Non-Energy Uses of Fossil Fuels
(Percent) 73
Table 3-16: CH4 Emissions from Stationary Combustion (Tg CO, Eq.) 75
Table 3-17: N,O Emissions from Stationary Combustion (Tg CO, Eq.) 76
Table 3-18: CH4 Emissions from Stationary Combustion (Gg) 77
Table 3-19: N,O Emissions from Stationary Combustion (Gg) 77
Table 3-20: NOX, CO, and NMVOC Emissions from Stationary Combustion in 2003 (Gg) 78
Table 3-21: Tier 2 Quantitative Uncertainty Estimates for CH4 and N,O Emissions from Energy-Related Stationary
Combustion, Including Biomass (Tg CO, Eq. and Percent) 80
Table 3-22: CH4 Emissions from Mobile Combustion (Tg CO, Eq.) 82
Table 3-23: N,O Emissions from Mobile Combustion (Tg CO, Eq.) 82
Table 3-24: CH4 Emissions from Mobile Combustion (Gg) 83
Table 3-25: N,O Emissions from Mobile Combustion (Gg) 83
Table 3-26: NOX Emissions from Mobile Combustion (Gg) 84
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page vii
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Table 3-27: CO Emissions from Mobile Combustion (Gg) 84
Table 3-28: NMVOC Emissions from Mobile Combustion (Gg) 85
Table 3-29: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Mobile Sources (Tg CO2
Eq. and Percent) 90
Table 3-30: CH4 Emissions from Coal Mining (Tg CO2 Eq.) 93
Table 3-31: CH4 Emissions from Coal Mining (Gg) 93
Table 3-32: Coal Production (Thousand Metric Tons) 94
Table 3-33: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Coal Mining (Tg CO2 Eq. and
Percent) 94
Table 3-34: CH4 Emissions from Abandoned Coal Mines (Tg CO2Eq.) 96
Table 3-35: CH4 Emissions from Abandoned Coal Mines (Gg) 96
Table 3-36: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Abandoned Underground Coal
Mines (Tg CO2 Eq. and Percent) 98
Table 3-37: CH4 Emissions from Petroleum Systems (Tg CO2 Eq.) 100
Table 3-38: CH4 Emissions from Petroleum Systems (Gg) 100
Table 3-39: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Petroleum Systems (Tg CO2 Eq. and
Percent) 101
Table 3-40: CH4 Emissions from Natural Gas Systems (Tg CO2Eq)* 103
Table 3-41: CH4 Emissions from Natural Gas Systems (Gg)* 103
Table 3-42: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Natural Gas Systems (Tg CO2 Eq.
and Percent) 104
Table 3-43: CO2 and N2O Emissions from Municipal Solid Waste Combustion (Tg CO2 Eq.) 107
Table 3-44: CO2 and N2O Emissions from Municipal Solid Waste Combustion (Gg) 107
Table 3-45: NOX, CO, and NMVOC Emissions from Municipal Solid Waste Combustion (Gg) 107
Table 3-46: Municipal Solid Waste Generation (Metric Tons) and Percent Combusted 108
Table 3-47: Tier 2 Quantitative Uncertainty Estimates for CO2 and N2O from Municipal Solid Waste Combustion
(Tg CO2 Eq. and Percent) 109
Table 3-48: U. S. Municipal Solid Waste Combusted, as Reported by EPA and BioCycle (Metric Tons) 110
Table 3-49: CO2 Emissions from On-Shore and Off-Shore Natural Gas Flaring (Tg CO2 Eq.) 111
Table 3-50: CO2 Emissions from On-Shore and Off-Shore Natural Gas Flaring (Gg) 111
Table 3-51: NOX, NMVOCs, and CO Emissions from Oil and Gas Activities (Gg) 111
Table 3-52: Total Natural Gas Reported Vented and Flared (Million Ft3) and Thermal Conversion Factor (Btu/Ft3)
112
Table 3-53: Volume Flared Offshore (MMcf) and Fraction Vented and Flared (Percent) 112
Table 3-54: Emissions from International Bunker Fuels (Tg CO2 Eq.) 114
Table 3-55: Emissions from International Bunker Fuels (Gg) 115
Table 3-56: Aviation Jet Fuel Consumption for International Transport (Million Gallons) 116
Table 3-57: Manne Fuel Consumption for International Transport (Million Gallons) 116
Table 3-58: CO2 Emissions from Wood Consumption by End-Use Sector (Tg CO2 Eq.) 118
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page viii
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Table 3-59: CO2 Emissions from Wood Consumption by End-Use Sector (Gg) 118
Table 3-60: CO2 Emissions from Ethanol Consumption 119
Table 3-61: Woody Biomass Consumption by Sector (Trillion Btu) 119
Table 3-62: Ethanol Consumption 119
Table 3-63: CH4 Emissions from Non-Combustion Fossil Sources (Gg) 121
Table 3-64: Formation of CO2 through Atmospheric CH4 Oxidation (Tg CO2 Eq.) 121
Table 4-1: Emissions from Industrial Processes (Tg CO2 Eq.) 123
Table 4-2: Emissions from Industrial Processes (Gg) 124
Table 4-3: CO2 and CH4 Emissions from Iron and Steel Production (Tg CO2 Eq.) 126
Table 4-4: CO2 and CH4 Emissions from Iron and Steel Production (Gg) 126
Table 4-5: CH4 Emission Factors for Coal Coke, Sinter, and Pig Iron Production (g/kg) 127
Table 4-6: Production and Consumption Data for the Calculation of CO2 and CH4 Emissions from Iron and Steel
Production (Thousand Metric Tons) 127
Table 4-7: Tier 2 Quantitative Uncertainty Estimates for CO2 and CH4 Emissions from Iron and Steel Production
(Tg. CO2 Eq. and Percent) 128
Table 4-8: CO2 Emissions from Cement Production (Tg CO2 Eq. and Gg)* 129
Table 4-9: Cement Production (Gg) 131
Table 4-10: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Cement Manufacture (Tg CO2 Eq.
and Percent) 131
Table 4-11: CO2 Emissions from Ammonia Manufacture and Urea Application (Tg CO2 Eq.) 132
Table 4-12: CO2 Emissions from Ammonia Manufacture and Urea Application (Gg) 133
Table 4-13: Ammonia Production (Gg) 133
Table 4-14: Urea Production (Gg) 134
Table 4-15: Urea Net Imports (Gg) 134
Table 4-16: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Ammonia Manufacture and Urea
Application (Tg CO2 Eq. and Percent) 136
Table 4-17: Net CO2 Emissions from Lime Manufacture (Tg CO2 Eq.) 137
Table 4-18: CO2 Emissions from Lime Manufacture (Gg) 137
Table 4-19: Lime Production and Lime Use for Sugar Refining and PCC (Gg) 138
Table 4-20: Hydrated Lime Production (Gg) 138
Table 4-21: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Lime Manufacture (Tg CO2 Eq. and
Percent) 140
Table 4-22: CO2 Emissions from Limestone & Dolomite Use (Tg CO2 Eq.) 140
Table 4-23: CO2 Emissions from Limestone & Dolomite Use (Gg) 140
Table 4-24: Limestone and Dolomite Consumption (Thousand Metric Tons) 142
Table 4-25: Dolomitic Magnesium Metal Production Capacity (Metric Tons) 142
Table 4-26: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Limestone and Dolomite Use (Tg
CO2 Eq. and Percent) 143
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ix
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Table 4-27: CO2 Emissions from Soda Ash Manufacture and Consumption (Tg CO2Eq.) 144
Table 4-28: CO2 Emissions from Soda Ash Manufacture and Consumption (Gg) 144
Table 4-29: Soda Ash Manufacture and Consumption (Gg) 145
Table 4-30: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Soda Ash Manufacture and
Consumption (Tg CO2 Eq. and Percent) 145
Table 4-31: CO2 Emissions from Titanium Dioxide (Tg CO2 Eq. and Gg) 146
Table 4-32: Titanium Dioxide Production (Gg) 147
Table 4-33: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Titanium Dioxide Production (Tg
CO2 Eq. and Percent) 147
Table 4-34: CO2 Emissions from Phosphoric Acid Production (Tg CO2 Eq. and Gg) 148
Table 4-35: Phosphate Rock Domestic Production, Exports, and Imports (Gg) 149
Table 4-36: Chemical Composition of Phosphate Rock (percent by weight) 150
Table 4-37: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Phosphoric Acid Production (Tg
CO2 Eq. and Percent) 151
Table 4-38: CO2 Emissions from Ferroalloy Production (Tg CO2 Eq. and Gg) 151
Table 4-39: Production of Ferroalloys (Metric Tons) 152
Table 4-40: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Ferroalloy Production (Tg CO2 Eq.
and Percent) 153
Table 4-41: CO2 Emissions from Carbon Dioxide Consumption (Tg CO2 Eq. and Gg) 154
Table 4-42: Carbon Dioxide Consumption (Metric Tons) 155
Table 4-43: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Carbon Dioxide Consumption (Tg
CO2 Eq. and Percent) 156
Table 4-44: CO2 and CH4 Emissions from Petrochemical Production (Tg CO2 Eq.) 157
Table 4-45: CO2 and CH4 Emissions from Petrochemical Production (Gg) 157
Table 4-46: Production of Selected Petrochemicals (Thousand Metric Tons) 158
Table 4-47: Carbon Black Feedstock (Primary Feedstock) and Natural Gas Feedstock (Secondary Feedstock)
Consumption (Thousand Metric Tons) 159
Table 4-48: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Petrochemical Production and CO2
Emissions from Carbon Black Production (Tg CO2 Eq. and Percent) 159
Table 4-49: CH4 Emissions from Silicon Carbide Production (Tg CO2 Eq. and Gg) 160
Table 4-50: Production of Silicon Carbide (Metric Tons) 160
Table 4-51: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Silicon Carbide Production (Tg CO2
Eq. and Percent) 161
Table 4-52: N2O Emissions from Nitric Acid Production (Tg CO2 Eq. and Gg) 162
Table 4-53: Nitric Acid Production (Gg) 162
Table 4-54: Tier 1 Quantitative Uncertainty Estimates for N2O Emissions from Nitric Acid Production (Tg CO2 Eq.
and Percent) 163
Table 4-55: N2O Emissions from Adipic Acid Production (Tg CO2 Eq. and Gg) 164
Table 4-56: Adipic Acid Production (Gg) 165
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page x
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Table 4-57: Tier 1 Quantitative Uncertainty Estimates for N2O Emissions from Adipic Acid Production (Tg CO2
Eq. and Percent) 165
Table 4-58: Emissions of HFCs and PFCs from ODS Substitution (Tg CO2 Eq.) 166
Table 4-59: Emissions of HFCs and PFCs from ODS Substitution (Mg) 166
Table 4-60: Tier 2 Quantitative Uncertainty Estimates for HFC and PFC Emissions from ODS Substitution (Tg
CO2 Eq, and Percent) 168
Table 4-61: HFC-23 Emissions from HCFC-22 Production (Tg CO2 Eq. and Gg) 169
Table 4-62: HCFC-22 Production (Gg) 169
Table 4-63: Tier 1 Quantitative Uncertainty Estimates for HFC-23 Emissions from HCFC-22 Production (Tg CO2
Eq. and Percent) 170
Table 4-64: SF6 Emissions from Electric Power Systems and Original Equipment Manufactures (Tg CO2 Eq.) 170
Table 4-65: SF6 Emissions from Electnc Power Systems and Original Equipment Manufacturers (Gg) 171
Table 4-66: Simulated Variables for Tier 2 Uncertainty Analysis 173
Table 4-67: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Electrical Transmission and
Distribution (Tg CO2 Eq. and Percent) 174
Table 4-68: CO2 Emissions from Aluminum Production (Tg CO2 Eq. and Gg) 175
Table 4-69: PFC Emissions from Aluminum Production (Tg CO2 Eq.) 175
Table 4-70: PFC Emissions from Aluminum Production (Gg) 175
Table 4-71: Production of Primary Aluminum (Gg) 177
Table 4-72: Tier 2 Quantitative Uncertainty Estimates for PFC Emissions from Aluminum Production (Tg CO2 Eq.
and Percent) 178
Table 4-73: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Tg CO2 Eq.) 179
Table 4-74: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Mg) 179
Table 4-75: Tier 2 Quantitative Uncertainty Estimates for HFC, PFC, and SF6 Emissions from Semiconductor
Manufacture (Tg CO2 Eq. and Percent) 182
Table 4-76: SF6 Emissions from Magnesium Production and Processing (Tg CO2 Eq. and Gg) 182
Table 4-77: SF6 Emission Factors (kg SF6 per metric ton of magnesium) 183
Table 4-78: Simulated Variables for Tier 2 Uncertainty Analysis 184
Table 4-79: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Magnesium Production and
Processing (Tg CO2 Eq. and Percent) 184
Table 4-80: 2003 Potential and Actual Emissions of HFCs, PFCs, and SF6 from Selected Sources (Tg CO2 Eq.) 186
Table 4-81: NOX, CO, and NMVOC Emissions from Industrial Processes (Gg) 186
Table 5-1: N2O Emissions from Solvent and Other Product Use (Tg CO2 Eq. and Gg) 189
Table 5-2: Ambient Air Pollutant Emissions from Solvent and Other Product Use (Gg) 189
Table 5-3: N2O Emissions from Nitrous Oxide Product Usage (Tg CO2 Eq. and Gg) 189
Table 5-4: N2O Production (Gg) 191
Table 5-5: Tier 1 Quantitative Uncertainty Estimates for N2O Emissions from Nitrous Oxide Product Usage (Tg
CO2 Eq. and Percent) 191
Table 5-6: Emissions of NOX, CO, and NMVOC from Solvent Use (Gg) 192
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page xi
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Table 6-1: Emissions from Agriculture (Tg CO2 Eq.) 195
Table 6-2: Emissions from Agriculture (Gg) 195
Table 6-3: CH4 Emissions from Enteric Fermentation (Tg CO2 Eq.) 196
Table 6-4: CH4 Emissions from Enteric Fermentation (Gg) 197
Table 6-5: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Enteric Fermentation (Tg CO2 Eq.
and Percent) 199
Table 6-6: CH4 and N2O Emissions from Manure Management (Tg CO2Eq.) 201
Table 6-7: CH4 and N2O Emissions from Manure Management (Gg) 201
Table 6-8: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Manure Management (Tg
CO2 Eq. and Percent) 204
Table 6-9: CH4 Emissions from Rice Cultivation (Tg CO2Eq.) 208
Table 6-10: CH4 Emissions from Rice Cultivation (Gg CH4) 209
Table 6-11: Rice Areas Harvested (Hectares) 210
Table 6-12: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Rice Cultivation (Tg CO2 Eq. and
Percent) 212
Table 6-13: N2O Emissions from Agricultural Soils (Tg CO2 Eq.) 213
Table 6-14: N2O Emissions from Agricultural Soils (Gg) 213
Table 6-15: Direct N2O Emissions from Agricultural Soils (Tg CO2 Eq.) 213
Table 6-16: Direct N2O Emissions from PRP Livestock Manure (Tg CO2 Eq.) 214
Table 6-17: Indirect N2O Emissions from all Land Use Types* (Tg CO2 Eq.) 214
Table 6-18: Tier 1 Quantitative Uncertainty Estimates of N2O Emissions from Agricultural Soil Management in
2003 (Tg CO2 Eq. and Percent) 219
Table 6-19. Comparison of Direct Soil N2O Emission Estimates for IPCC versus Current Methodologies (Tg CO2
Eq.). 221
Table 6-20. Comparison of Indirect Soil N2O Emission Estimates for IPCC versus Current Methodologies (Tg CO2
Eq.) 221
Table 6-21. Comparison of Total Soil N^O Emission Estimates for IPCC versus Current Methodologies (Tg CCS
Eq.) " 221
Table 6-22: Emissions from Field Burning of Agricultural Residues (Tg CO2 Eq.) 222
Table 6-23: Emissions from Field Burning of Agricultural Residues (Gg)* 223
Table 6-24: Agricultural Crop Production (Gg of Product) 225
Table 6-25: Percentage of Rice Area Burned by State 225
Table 6-26: Percentage of Rice Area Burned in California 225
Table 6-27: Key Assumptions for Estimating Emissions from Field Burning of Agricultural Residues 226
Table 6-28: Greenhouse Gas Emission Ratios 226
Table 6-29: Tier 1 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Field Burning of
Agricultural Residues (Tg CO2 Eq. and Percent) 227
Table 7-1: Net CO2 Flux from Land-Use Change and Forestry (Tg CO2 Eq.) 230
Table 7-2: Net CO2 Flux from Land-Use Change and Forestry (Tg C) 230
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page xii
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Table 7-3: Net N2O Emissions from Land-Use Change and Forestry (Tg CO2 Eq.) 231
Table 7-4: Net N2O Emissions from Land-Use Change and Forestry (Gg) 231
Table 7-5. Net Annual Changes in Carbon Stocks (Tg CO2 Eq. yr"1) in Forest and Harvested Wood Pools 233
Table 7-6. Net Annual Changes in Carbon Stocks (Tg C yr"1) in Forest and Harvested Wood Pools 233
Table 7-7. Carbon Stocks (Tg C) in Forest and Harvested Wood Pools 234
Table 7-8: Tier 2 Quantitative Uncertainty Estimates for CO2 Net Flux from Forest Land Remaining Forest Land:
Changes in Forest Carbon Stocks (Tg CO2 Eq. and Percent) 237
Table 7-9. N2O Fluxes from Soils in Forests Remaining Forests (Tg CO2 Eq. and Gg) 239
Table 7-10: Tier 1 Quantitative Uncertainty Estimates of N2O Fluxes from Forest Soils (Tg CO2 Eq. and Percent)
240
Table 7-11: Net CO2 Flux from Agricultural Soils (Tg CO2 Eq.) 242
Table 7-13: Quantities of Applied Minerals (Thousand Metric Tons) 245
Table 7-14: Tier 2 Quantitative Uncertainty Estimates for CO2 Flux from Mineral and Organic Agricultural Soil
Carbon Stocks (Tg CO2 Eq. and Percent) 246
Table 7-15: Tier 1 Quantitative Uncertainty Estimates for CO2 Emissions from Liming of Agricultural Soils (Tg
CO2 Eq. and Percent) 247
Table 7-16: Net Changes in Yard Trimming and Food Scrap Stocks (Tg CO2 Eq.) 250
Table 7-17: Net Changes in Yard Trimming and Food Scrap Stocks (Tg C) 250
Table 7-18: Moisture Content (%), Carbon Storage Factor, Initial Carbon Content (%), Proportion of Initial Carbon
Sequestered (%), and Half-Life (years) for Landfilled Yard Trimmings and Food Scraps 252
Table 7-19: Carbon Stocks in Yard Trimmings and Food Scraps (Tg C) 252
Table 7-20: Tier 2 Quantitative Uncertainty Estimates for CO2 Flux from Yard Trimmings and Food Scraps (Tg
CO2 Eq. and Percent) 253
Table 7-21: Net C Flux from Urban Trees (Tg CO2Eq. and Tg C) 255
Table 7-22: 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 256
Table 7-23: Tier 1 Quantitative Uncertainty Estimates for Net C Flux from Changes in Carbon Stocks in Urban
Trees (Tg CO2 Eq. and Percent) 257
Table 7-24: N2O Fluxes from Soils in Settlements Remaining Settlements (Tg CO2 Eq.) 258
Table 7-25: Tier 1 Quantitative Uncertainty Estimates of N2O Emissions from Soils in Settlements Remaining
Settlements (Tg CO2 Eq. and Percent) 259
Table 8-1: Emissions from Waste (Tg CO2 Eq.) 261
Table 8-2: Emissions from Waste (Gg) 261
Table 8-3: CH4 Emissions from Landfills (Tg CO2 Eq.) 262
Table 8-4: CH4 Emissions from Landfills (Gg) 262
Table 8-5: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Landfills (Tg CO2 Eq. and Percent)
264
Table 8-6: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Tg CO2 Eq.) 266
Table 8-7: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Gg) 266
Table 8-8: U.S. Population (Millions) and Wastewater BOD5 Produced (Gg) 266
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page xiii
-------
Table 8-9: U.S. Pulp and Paper, Meat and Poultry, and Vegetables, Fruits and Juices Production (Tg) 267
Table 8-10: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Wastewater Treatment (Tg CO2 Eq.
and Percent) 268
Table 8-11: N2O Emissions from Human Sewage (Tg CO2 Eq. and Gg) 269
Table 8-12: U.S. Population (Millions) and Average Protein Intake [kg/(person.year)J 271
Table 8-13: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from Human Sewage (Tg CO2 Eq. and
Percent) 272
Table 8-14: Emissions of NOX, CO, and NMVOC from Waste (Gg) 272
Table 10-1: Revisions to U.S. Greenhouse Gas Emissions (Tg CO2 Eq.) 278
Table 10-2: Revisions to Net Flux of CO2 to the Atmosphere from Land-Use Change and Forestry (Tg CO2 Eq.)
279
Figures
Figure ES-1: U.S. Greenhouse Gas Emissions by Gas 3
Figure ES-2: Annual Percent Change in U.S. Greenhouse Gas Emissions 3
Figure ES-3: Cumulative Change in U.S. Greenhouse Gas Emissions Relative to 1990 3
Figure ES-4: 2003 Greenhouse Gas Emissions by Gas 5
Figure ES-5: 2003 Sources of CO2 6
Figure ES-6: 2003 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type 6
Figure ES-7: 2003 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion 6
Figure ES-8: 2003 U.S. Sources of CH4 8
Figure ES-9: 2003 U.S. Sources of N2O 8
Figure ES-10: 2003 U.S. Sources of HFCs, PFCs, and SF6 9
Figure ES-11: U.S. Greenhouse Gas Emissions by Chapter/IPCC Sector 9
Figure ES-12: 2003 U.S. Energy Consumption by Energy Source 10
Figure ES-13: Emissions Allocated to Economic Sectors 12
Figure ES-14: Emissions with Electricity Distributed to Economic Sectors 13
Figure ES-15: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product 14
Figure ES-16: 2003 Key Sources - Tier 1 Level Assessment 15
Figure 2-1: U.S. Greenhouse Gas Emissions by Gas 21
Figure 2-2: Annual Percent Change in U.S. Greenhouse Gas Emissions 21
Figure 2-3: Cumulative Change in U.S. Greenhouse Gas Emissions Relative to 1990 21
Figure 2-4: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product 24
Figure 2-5: U.S. Greenhouse Gas Emissions by Chapter/IPCC Sector 28
Figure 2-6: 2003 Energy Sector Greenhouse Gas Sources 28
Figure 2-7: 2003 U.S. Fossil Carbon Flows (Tg CO2 Eq.) 28
Figure 2-8: 2003 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type 30
Figure 2-9: 2003 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion 30
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page xiv
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Figure 2-10: 2003 Industrial Processes Chapter Greenhouse Gas Sources 33
Figure 2-11: 2003 Agriculture Chapter Greenhouse Gas Sources 37
Figure 2-12: 2003 Waste Sector Greenhouse Gas Sources 40
Figure 2-13: Emissions Allocated to Economic Sectors 42
Figure 2-14: Emissions with Electricity Distributed to Economic Sectors 45
Figure 3-1: 2003 Energy Sector Greenhouse Gas Sources 51
Figure 3-2: 2003 U.S. Fossil Carbon Flows (Tg CO2 Eq.) 51
Figure 3-3: 2003 U.S. Energy Consumption by Energy Source 54
Figure 3-4: U.S. Energy Consumption (Quadrillion Btu) 54
Figure 3-5: 2003 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type 54
Figure 3-6: Annual Deviations from Normal Heating Degree Days for the United States (1949-2003) 55
Figure 3-7: Annual Deviations from Normal Cooling Degree Days for the United States (1949-2003) 55
Figure 3-8: Aggregate Nuclear and Hydroelectric Power Plant Capacity Factors in the United States (1973-2003)55
Figure 3-9: 2003 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion 57
Figure 3-10: Motor Gasoline Retail Prices (Real) 57
Figure 3-11: Motor Vehicle Fuel Efficiency 57
Figure 3-12: Industrial Production Indexes (Index 1997=100) 59
Figure 3-13: Heating Degree Days 60
Figure 3-14: Cooling Degree Days 60
Figure 3-15: Electricity Generation Retail Sales by End-Use Sector 60
Figure 3-16: U.S. Energy Consumption and Energy-Related CO2 Emissions Per Capita and Per Dollar GDP 63
Figure 3-17: Mobile Source CH4 and N2O Emissions 82
Figure 4-1: 2003 Industrial Processes Chapter Greenhouse Gas Sources 123
Figure 6-1: 2003 Agriculture Chapter Greenhouse Gas Emission Sources 195
Figure 6-2: Direct N2O Emissions Pathways from Cropland and Grassland Soils, and Indirect N2O Emissions
Pathways from All Sources. 213
Figure 7-1: Forest Sector Carbon Pools and Flows. 232
Figure 7-2: Estimates of Net Annual Changes in Carbon Stocks for Major Carbon Pools (Tg C yr"1) 234
Figure 7-3: Average Carbon Density in the Forest Tree Pool in the Conterminous U.S. During 2004. 234
Figure 7-4: Net Annual CO2 Flux, per Hectare, From Mineral Soils Under Agricultural Management, 1990-1992
243
Figure 7-5: Net Annual CO2 Flux, per Hectare, From Mineral Soils Under Agricultural Management, 1993-2003
243
Figure 7-6: Net Annual CO2 Flux, per Hectare, From Organic Soils Under Agricultural Management, 1990-1992
243
Figure 7-7: Net Annual CO2 Flux, per Hectare, From Organic Soils Under Agricultural Management, 1993-2003
243
Figure 8-1: 2003 Waste Chapter Greenhouse Gas Sources 261
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page xv
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Boxes
Box ES-1: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data 13
Box 1-1: The IPCC Third Assessment Report and Global Warming Potentials 8
Box 1-2: IPCC Good Practice Guidance 12
Box 2-1: Recent Trends in Various U. S. Greenhouse Gas Emissions-Related Data 23
Box 2-2: Methodology for Aggregating Emissions by Economic Sector 48
Box 2-3: Sources and Effects of Sulfur Dioxide 50
Box 3-1: Weather and Non-Fossil Energy Effects on CO2 from Fossil Fuel Combustion Trends 55
Box 3-2: Carbon Intensity of U.S. Energy Consumption 61
Box 3-3: Biogenic Emissions and Sinks of Carbon 106
Box 3-4: Formation of CO2 through Atmospheric CH4 Oxidation 120
Box 4-1: Potential Emission Estimates of HFCs, PFCs, and SF6 185
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page xvi
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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 Parties 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.
In 1992, the United States signed and ratified the UNFCCC. As stated in Article 2 of the UNFCCC, "The ultimate
objective of this Convention... 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, "shall 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 these commitments.
This chapter summarizes the latest information on U.S. anthropogenic greenhouse gas emission trends from 1990
through 2003. 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
1996IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997), the IPCC Good
Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2000), and the
IPCC Good Practice Guidance for Land Use, Land Use Change and Forestry (IPCC 2003). The structure of this
report is consistent with the UNFCCC guidelines for inventory reporting.4 For most source categories, the IPCC
methodologies were expanded, resulting in a more comprehensive and detailed estimate of emissions.
ES. 1. Background Information
Naturally occurring greenhouse gases include water vapor, carbon dioxide (CO2), methane (CH4), nitrous oxide
(NiO), and ozone (O3). Several classes of halogenated substances that contain fluorine, chlorine, or bromine are
also greenhouse gases, but they are, for the most part, solely a product of industrial activities. Chlorofluorocarbons
(CFCs) and hydrochlorofluorocarbons (HCFCs) are halocarbons that contain chlorine, while halocarbons that
contain bromine are referred to as bromofluorocarbons (i.e., halons). 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 their national greenhouse gas emission inventories.5 Some other fluorine-containing halogenated
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 .
J Article 4(l)(a) of the United Nations Framework Convention on Climate Change (also identified in Article 12). Subsequent
decisions by the Conference of the Parties elaborated the role of Annex I Parties in preparing national inventories. See
.
4 See .
5 Emissions estimates of CFCs, HCFCs, halons and other ozone-depleting substances are included in this document for
informational purposes.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ES-1
-------
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 emission 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).
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).6 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 equivalent (Tg CO2Eq.).7 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 CO2 Eq = (Gg of gas)x (GWP)
The UNFCCC reporting guidelines for national inventories were updated in 2002, 8 but continue to require the use
of GWPs from the IPCC Second Assessment Report (SAR). This requirement ensures that current estimates of
aggregate greenhouse gas emissions for 1990 to 2003 are consistent with estimates developed prior to the
publication of the IPCC Third Assessment Report (TAR). Therefore, to comply with international reporting
standards under the UNFCCC, official emission estimates are reported by the United States using SAR GWP
values. All estimates are provided throughout the report in both CO2 equivalents and unweighted units. A
6 Albedo is a measure of the Earth's reflectivity; see the Glossary (Annex 6.8) for definition.
7 Carbon comprises 12/44*8 of carbon dioxide by weight.
8 See .
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ES-2
-------
comparison of emission values using the SAR GWPs versus the TAR GWPs can be found in Chapter 1 and in more
detail in Annex 6.1. The GWP values used in this report are listed below in Table ES-1.
Table ES-1: Global Warming Potentials (100 Year Time Horizon) Used in this Report
~Gas GWP
C02 1
CH4* 21
N2O 310
HFC-23 11,700
HFC-32 650
HFC-125 2,800
HFC-134a 1,300
HFC-143a 3,800
HFC-152a 140
HFC-227ea 2,900
HFC-236fa 6,300
HFC-4310mee 1,300
CF4 6,500
C2F6 9,200
C4F10 7,000
C6F14 7,400
SF6 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 CO2 is not included.
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, or have
only indirect effects on radiative forcing (IPCC 1996).
ES.2. Recent Trends in U.S. Greenhouse Gas Emissions and Sinks
In 2003, total U.S. greenhouse gas emissions were 6,900.2 Tg CO2 Eq. Overall, total U.S. emissions have risen by
13 percent from 1990 to 2003, while the U.S. gross domestic product has increased by 46 percent over the same
period (BEA 2004). Emissions rose slightly from 2002 to 2003, increasing by 0.6 percent (42.2 Tg CO2 Eq.). The
following factors were primary contributors to this increase: 1) moderate economic growth in 2003, leading to
increased demand for electricity and fossil fuels, 2) increased natural gas prices, causing some electric power
producers to switch to burning coal, and 3) a colder winter, which caused an increase in the use of heating fuels,
primarily in the residential end-use sector.
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-2 provides a detailed summary of U.S. greenhouse gas emissions and sinks
for 1990 through 2003.
Figure ES-1: U.S. Greenhouse Gas Emissions by Gas
Figure ES-2: Annual Percent Change in U.S. Greenhouse Gas Emissions
Figure ES-3: Cumulative Change in U.S. Greenhouse Gas Emissions Relative to 1990
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ES-3
-------
Table ES-2: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq.)
Gas/Source
CO2
Fossil Fuel Combustion
Non-Energy Use of Fuels
Iron and Steel Production
Cement Manufacture
Waste Combustion
Ammonia Production and Urea
Application
Lime Manufacture
Natural Gas Flaring
Limestone and Dolomite Use
Aluminum Production
Soda Ash Manufacture and
Consumption
Petrochemical Production
Titanium Dioxide Production
Phosphoric Acid Production
Ferroalloys
Carbon Dioxide Consumption
Land-Use Change and Forestry
(Sinks)"
International Bunker Fuelsb
Biomass Combustion^
CH4
Landfills
Natural Gas Systems
Enteric Fermentation
Coal Mining
Manure Management
Wastewater Treatment
Petroleum Systems
Rice Cultivation
Stationary Sources
Abandoned Coal Mines
Mobile Sources
Petrochemical Production
Iron and Steel Production
Agricultural Residue Burning
Silicon Carbide Production
International Bunker Fuelsb
N2O
Agricultural Soil Management
Mobile Sources
Manure Management
Human Sewage
Nitric Acid
Stationary Sources
Settlements Remaining
Settlements
Adipic Acid
N2O Product Usage
Waste Combustion
Agricultural Residue Burning
1990 .v! 1997
5,009.6 ;:, 5,580.0
4,711 7
1080
854
33 3
109
193
11 2
58
55
63
4 1
22
1 3
1 5
20
09
(1,042.0)
113.5
216.7
605.3
1722
1283
1179
81 9
31 2
248
200
7 1
78
6 1
48
1 2
1 3
07
+
0.2
382.0
2530
437
163
130
178
123
55
152
43
04
';•- 5,263.2
;•:', 120.3
;'; 71.9
}; 38.3
'••: 17.8
T'
» I
:„: 20.7
<;, 13.7
r 7.9
'•'. 7.2
» /
;.' 5.6
\ '
r 4.4
;:; 2.9
;.' 1.8
'?;. 1.5
2.0
;•; 0.8
T'
,'"','. (930.0)
109.9
i':; 233.2
r 579.5
,v 147.4
133.6
;':; 118.3
r; 62.6
,v 36.4
'[" 31.7
'»", 18.8
r 7.5
7.4
i'; s. i
\'l 4.0
"•: 1.6
•v 1.3
;i!; 0.8
» i -\-
'•: o.i
\ '
396.3
;i!; 252.0
'>">, 55.2
T, 17.3
'.'. 14-7
;v 21.2
M 13.5
'C
'!• 6.1
r; 10.3
''•' 4.8
>' 0.4
0,4 ','-.? 0,4
1998
5,607.2
5,278.7
135.4
67.4
39.2
17.1
21.9
13.9
6.6
7.4
5.8
4.3
3.0
1.8
1.6
2.0
0.9
(881.0)
114.6
217.2
569.1
138.5
131.8
116.7
62.8
38.8
32.6
18.5
7.9
6.9
7.2
3.9
1.7
1.2
0.8
+
0.2
407.8
267.7
55.3
17.4
15.0
20.9
13.4
6.1
6.0
4.8
0.3
0,5
1999
5,678.0
5,345.9
141.6
64.4
40.0
17.6
20.6
13.5
6.9
8.1
5.9
4.2
3.1
1.9
1.5
2.0
0.8
(826.1)
105.3
222.3
557.3
134.0
127.4
116.8
58.9
38.8
33.6
17.8
8.3
7.1
7.3
3.6
1.7
1.2
0.8
+
0.1
382.1
243.4
54.6
17.4
15.4
20.1
13.5
6.2
5.5
4.8
0.3
0,4
2000
5,858.2
5,545.1
124.7
65.7
41.2
18.0
19.6
13.3
5.8
6.0
5.7
4.2
3.0
1.9
1.4
1.7
1.0
(822.4)
101.4
226.8
554.2
130.7
132.1
115.6
56.2
38.1
34.3
17.6
7.5
7.3
7.7
3.4
1.7
1.2
0.8
+
0.1
401.9
263.9
53.2
17.8
15.6
19.6
14.0
6.0
6.0
4.8
0.4
0,5
2001
5,744.8
5,448.0
120.1
58.9
41.4
18.8
16.7
12.8
6.1
5.7
4.1
4.1
2.8
1.9
1.3
1.3
0.8
(826.9)
97.9
200.5
546.8
126.2
131.8
114.5
55.6
38.9
34.7
17.4
7.6
6.7
6.9
3.1
1.4
1.1
0.8
+
0.1
385.8
257.1
49.0
18.0
15.6
15.9
13.5
5.8
4.9
4.8
0.4
0,5
2002
5,796.8
5,501.4
118.8
55.1
42.9
18.8
18.6
12.3
6.2
5.9
4.2
4.1
2.9
2.0
1.3
1.2
1.0
(826.5)
89.5
207.2
542.5
126.8
130.6
114.6
52.4
39.3
35.8
17.1
6.8
6.4
6.4
2.9
1.5
1.0
0.7
+
0.1
380.5
252.6
45.6
17.9
15.7
17.2
13.5
6.0
5.9
4.8
0.5
0,4
2003
5,841.5
5,551.6
118.0
53.8
43.0
18.8
15.6
13.0
6.0
4.7
4.2
4.1
2.8
2.0
1.4
1.4
1.3
(828.0)
84.2
216.8
545.0
131.2
125.9
115.0
53.8
39.1
36.8
17.1
6.9
6.7
6.4
2.7
1.5
1.0
0.8
+
0.1
376.7
253.5
42.1
17.5
15.9
15.8
13.8
6.0
6.0
4.8
0.5
0,4
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page ES-4
-------
Forest Land Remaining Forest
Land
International Bunker Fuelsb
HFCs, PFCs, and SF6
Substitution of Ozone Depleting
Substances
Electrical Transmission and
Distribution
HCFC-22 Production
Semiconductor Manufacture
Aluminum Production
Magnesium Production and
Processing
Total
Net Emissions (Sources and
Sinks)
0
1
91
0
29
35
2
18
5
6,088
5,046
\\
.ol
.2\
4\
2\
ol
9;
3 '
4:,
.it
.it
{'f- f
0
''»' 1
>:\, 121
f-
'Jr 46
{'f- f
{'• 21
';• 30
>\ 6
•:;'! 1 1
i'f .
{x 6
# 6,677
;'': 5,747
:,:i
^
.0
.7
.5
.7
.0
.3
.0
^
.5
.5
0.4
1.0
135.7
56.6
17.1
40.1
7.1
9.1
5.8
6,719.7
5,838.8
0.5
0.9
134.8
65.8
16.4
30.4
7.2
9.0
6.0
6,752.2
5,926.1
0
0
138
75
15
29
6
9
^
6,953
6,130
.4
.9
.9
.0
.6
.8
.3
.0
.2
.2
.8
0.4
0.9
129.5
83.3
15.4
19.8
4.5
4.0
2.6
6,806.9
5,980.1
0.4
0.8
138.3
91.5
14.7
19.8
4.4
5.2
2.6
6,858.1
6,031.6
0.4
0.8
137.0
99.5
14.1
12.3
4.3
3.8
3.0
6,900.2
6,072.2
+ Does not exceed 0.05 Tg CO2 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 and Biomass combustion are not included in totals.
Note: Totals may not sum due to independent rounding.
Figure ES-4 illustrates the relative contribution of the direct greenhouse gases to total U.S. emissions in 2003. The
primary greenhouse gas emitted by human activities in the United States was CO2, representing approximately 85
percent of total greenhouse gas emissions. The largest source of CO2, and of overall greenhouse gas emissions, was
fossil fuel combustion. Methane emissions, which have steadily declined since 1990, 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 PFC emissions resulted from semiconductor
manufacturing and as a by-product of primary aluminum production.
Figure ES-4: 2003 Greenhouse Gas Emissions by Gas
Overall, from 1990 to 2003, total emissions of CO2 increased by 832.0 Tg CO2 Eq. (17 percent), while CH4 and
N2O emissions decreased by 60.4 Tg CO2 Eq. (10 percent) and 5.2 Tg CO2 Eq. (1 percent), respectively. During the
same period, aggregate weighted emissions of HFCs, PFCs, and SF6 rose by 45.8 Tg CO2 Eq. (50 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 and food scraps,
which, in aggregate, offset 12 percent of total emissions in 2003. The following sections describe each gas'
contribution to total U.S. greenhouse gas emissions in more detail.
Carbon Dioxide Emissions
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, atmospheric concentrations of CO2 have risen about 31 percent (IPCC
2001), principally due to the combustion of fossil fuels. Within the United States, fuel combustion accounted for 95
percent of CO2 emissions in 2003. Globally, approximately 24,240 Tg of CO2 were added to the atmosphere
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page ES-5
-------
through the combustion of fossil fuels in 2000, of which the United States accounted for about 23 percent.9
Changes in land use and forestry practices can also emit CO2 (e.g., through conversion of forest land to agricultural
or urban use) or can act as a sink for CO2 (e.g., through net additions to forest biomass).
Figure ES-5: 2003 Sources of CO2
As the largest source of U.S. greenhouse gas emissions, CO2 from fossil fuel combustion has accounted for a nearly
constant 80 percent of GWP weighted emissions since 1990. Emissions of CO2 from fossil fuel combustion
increased at an average annual rate of 1.3 percent from 1990 to 2003. The fundamental factors influencing this
trend include (1) a generally growing domestic economy over the last 13 years, and (2) significant growth in
emissions from transportation activities and electricity generation. Between 1990 and 2003, CO2 emissions from
fossil fuel combustion increased from 4,711.7 Tg CO2 Eq. to 5,551.6 Tg CO2 Eq.—an 18 percent total increase over
the thirteen-year period. Historically, changes in emissions from fossil fuel combustion have been the dominant
factor affecting U.S. emission trends.
From 2002 to 2003, these emissions increased by 50.2 Tg CO2 Eq. (1 percent). A number of factors played a major
role in the magnitude of this increase. The U.S. economy experienced moderate growth from 2002, causing an
increase in the demand for fuels. The price of natural gas escalated dramatically, causing some electric power
producers to switch to coal, which remained at relatively stable prices. Colder winter conditions brought on more
demand for heating fuels, primarily in the residential sector. Though a cooler summer partially offset demand for
electricity as the use of air-conditioners decreased, electricity consumption continued to increase in 2003. The
primary drivers behind this trend were the growing economy and the increase in U.S. housing stock. Use of nuclear
and renewable fuels remained relatively stable. Nuclear capacity decreased slightly, for the first time since 1997.
Use of renewable fuels rose slightly due to increases in the use of hydroelectric power and biofuels.
Figure ES-6: 2003 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
Figure ES-7: 2003 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion
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.
Figure ES-6, Figure ES-7, and Table ES-3 summarize CO2 emissions from fossil fuel combustion by end-use sector.
9 Global CO2 emissions from fossil fuel combustion were taken from Marland et al. (2003)
.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ES-6
-------
Table ES-3: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.)
End-Use Sector
Transportation
Combustion
Electricity
Industrial
Combustion
Electricity
Residential
Combustion
Electricity
Commercial
Combustion
Electricity
U.S. Territories
Total
Electricity Generation
1990
1,449.8 -I;
1,446
3
1,553
882
671
924
339
585
755
224
530
28
4,711
1,790
.8 ,!'•'"
.0 ';f
.9 './,
8 >,''•"
i ',:?.
.8 '-it
.6 ',«'
.3 ,;-.'
.1 V.
.2 ''"'
.9 '
•o £
.7i-::T
.3lj,:
1997
1,606.4
1,603.3
3.1
1,703.0
963.8
739.2
1,040.7
370.6
670.2
876.7
237.2
639.5
36.4
5,263.2
2,051.9
1998
1,636.5
1,633.4
3.1
1,668.5
911.6
757.0
1,044.4
338.6
705.8
892.9
219.7
673.2
36.3
5,278.7
2,139.0
1999
1,693.9
1,690.8
3.2
1,651.2
888.1
763.1
1,063.5
359.3
704.2
901.2
222.3
678.9
36.2
5,345.9
2,149.3
2000
1,741
1,737
3
1,684
905
779
1,124
379
745
959
235
724
35
5,545
2,252
.0
.7
.4
.4
.0
.4
.2
.1
.0
.5
.2
.3
.9
.1
.1
2001
1,723
1,719
3
1,587
878
709
1,116
367
749
972
226
745
48
5,448
2,207
.1
.7
.4
.4
.2
o
. J
.2
.0
.2
.7
.7
.9
.6
.0
.8
2002
1,755.4
1,752.3
3.2
1,579.0
876.6
702.4
1,145.0
371.4
773.6
973.9
230.0
743.9
48.1
5,501.4
2,223.0
2003
1,770.4
1,767.2
3.2
1,572.9
858.6
714.3
1,168.9
385.1
783.8
983.1
234.0
749.2
56.2
5,551.6
2,250.5
Note: Totals may not sum due to independent rounding. Combustion-related emissions from electricity generation are allocated
based on aggregate national electricity consumption by each end-use sector.
Transportation End-Use Sector. Transportation activities (excluding international bunker fuels) accounted for 32
percent of CO2 emissions from fossil fuel combustion in 2003.10 Virtually all of the energy consumed in this end-
use sector came from petroleum products. Over 60 percent 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.
Industrial End-Use Sector. Industrial CO2 emissions, resulting both directly from the combustion of fossil fuels and
indirectly from the generation of electricity that is consumed by industry, accounted for 28 percent of CO2 from
fossil fuel combustion in 2003. 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.
Residential and Commercial End-Use Sectors. The residential and commercial end-use sectors accounted for 21
and 18 percent, respectively, of CO2 emissions from fossil fuel combustion in 2003. 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 35 percent of
U.S. energy from fossil fuels and emitted 41 percent of the CO2 from fossil fuel combustion in 2003. 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 2003. Consequently, changes
in electricity demand have a significant impact on coal consumption and associated CO2 emissions.
Other significant CO2 trends included the following:
10 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 2003.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ES-7
-------
• Carbon dioxide emissions from iron and steel production decreased to 53.8 Tg CO2 Eq. in 2003, and have
declined by 31.7 Tg CO2 Eq. (37 percent) from 1990 through 2003, due to reduced domestic production of pig
iron, sinter, and coal coke.
• Carbon dioxide emissions from waste combustion (18.8 Tg CO2 Eq. in 2003) increased by 7.9 Tg CO2 Eq. (72
percent) from 1990 through 2003, as the volume of plastics and other fossil carbon-containing materials in
municipal solid waste grew.
• Net CO2 sequestration from land-use change and forestry decreased by 214.0 Tg CO2 Eq. (21 percent) from
1990 through 2003. This decline was primarily attributable to forest soils, a result of the slowed rate of forest
area increases after 1997.
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, wastewater treatment, stationary
and mobile combustion, and certain industrial processes (see Figure ES-8).
Figure ES-8: 2003 U.S. Sources of CH4
Some significant trends in U.S. emissions of CH4 included the following:
• Landfills are the largest anthropogenic source of CH4 emissions in the United States. In 2003, landfill CH4
emissions were 131.2 Tg CO2 Eq. (approximately 24 percent of total CH4 emissions), which represents a
decline of 41.1 Tg CO2 Eq., or 24 percent, since 1990.
• Methane emissions from coal mining declined by 28.1 Tg CO2 Eq. (34 percent) from 1990 to 2003, as a result
of the mining of less gassy coal from underground mines and the increased use of methane collected from
degasification systems.
Nitrous Oxide Emissions
Nitrous oxide is produced by biological processes that occur in soil and water and by a variety of anthropogenic
activities in the agricultural, energy-related, industrial, and waste management fields. 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-9).
Figure ES-9: 2003 U.S. Sources of N2O
Some significant trends in U.S. emissions of N2O included the following:
• Agricultural soil management activities such as fertilizer application and other cropping practices were the
largest source of U.S. N2O emissions, accounting for 67 percent (253.5 Tg CO2 Eq.).
• In 2003, N2O emissions from mobile combustion were 42.1 Tg CO2 Eq. (approximately 11 percent of U.S. N2O
emissions). From 1990 to 2003, N2O emissions from mobile combustion decreased by 4 percent.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ES-8
-------
HFC, RFC, and SF6 Emissions
HFCs and PFCs are families of synthetic chemicals that are being used as alternatives to the 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 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 HCFC-22 production, electrical transmission and distribution
systems, semiconductor manufacturing, aluminum production, and magnesium production and processing (see
Figure ES-10).
Figure ES-10: 2003 U.S. Sources of HFCs, PFCs, and SF6
Some significant trends in U.S. HFC, PFC and SF6 emissions included the following:
• Emissions resulting from the substitution of ozone depleting substances (e.g., CFCs) have been increasing from
small amounts in 1990 to 99.5 Tg CO2 Eq. in 2003. Emissions from substitutes for ozone depleting substances
are both the largest and the fastest growing source of HFC, PFC and SF6 emissions.
• The increase in ODS emissions is offset substantially by decreases in emission of HFCs, PFCs, and SF6 from
other sources. Emissions from aluminum production decreased by 79 percent (14.5 Tg CO2 Eq.) from 1990 to
2003, due to both industry emission reduction efforts and lower domestic aluminum production. Emissions
from the production of HCFC-22 decreased by 65 percent (22.6 Tg CO2 Eq.), due to a steady decline in the
emission rate of HFC-23 (i.e., the amount of HFC-23 emitted per kilogram of HCFC-22 manufactured) and the
use of thermal oxidation at some plants to reduce HFC-23 emissions. Emissions from electric power
transmission and distribution systems decreased by 52 percent (15.1 Tg CO2 Eq.) from 1990 to 2003, primarily
because of higher purchase prices for SF6 and efforts by industry to reduce emissions.
ES.3. Overview of Sector Emissions and Trends
In accordance with the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories
(IPCC/UNEP/OECD/IEA 1997), and the 2003 UNFCCC Guidelines on Reporting and Review (UNFCCC 2003),
this Inventory of U.S. Greenhouse Gas Emissions and Sinks is segregated into six sector-specific chapters. Figure
ES-11 and Table ES-4 aggregate emissions and sinks by these chapters.
Figure ES-11: U.S. Greenhouse Gas Emissions by Chapter/IPCC Sector
Table ES-4: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg CO2 Eg.)
Chapter/IPCC Sector
Energy
Industrial Processes
Solvent and Other Product Use
Agriculture
Land-Use Change and Forestry (Emissions)
Waste
Total
Land-Use Change and Forestry (Sinks)
Net Emissions (Sources and Sinks)
1990 '
5,141 7; '.
2999; '
4 3 : •.
426 5 : '
56;,'
210 1,;::
6,088.1 ,
(10420);-;,
5,046.1.,
1997
5,712.8
327.1
4.8
432.8
6.4
193.7
6,677.5
(930.0)
5,747.5
1998
5,737.7
334.9
4.8
449.8
6.5
186.0
6,719.7
(881.0)
5,838.8
1999
5
,802
329
4
425
.6
.2
.8
.9
6.6
6
183
,752
(826.
5
,926
.1
.2
1)
.1
2000
5,985.3
332.1
4.8
444.1
6.3
180.6
6,953.2
(822.4)
6,130.8
2001
5,877.3
304.7
4.8
437.5
6.2
176.5
6,806.9
(826.9)
5,980.1
5
6
2002
,920.7
315.4
4.8
432.4
6.4
178.3
,858.1
(826.5)
6
,031.6
2003
5,963.4
308.6
4.8
433.3
6.4
183.8
6,900.2
(828.0)
6,072.2
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ES-9
-------
* 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).
Energy
The Energy chapter contains emissions of all greenhouse gases resulting from stationary and mobile energy
activities including fuel combustion and fugitive fuel emissions. Energy-related activities, primarily fossil fuel
combustion, accounted for the vast majority of U.S. CO2 emissions for the period of 1990 through 2003. In 2003,
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-12). Energy related activities are also responsible for CH4 and N2O
emissions (39 percent and 15 percent of total U.S. emissions, respectively). Overall, emission sources in the Energy
chapter account for a combined 87 percent of total U.S. greenhouse gas emissions in 2003.
Figure ES-12: 2003 U.S. Energy Consumption by Energy Source
Industrial Processes
The Industrial Processes chapter contains by-product or fugitive emissions of greenhouse gases from industrial
processes not directly related to energy activities such as fossil fuel combustion. For example, industrial processes
can chemically transform raw materials, which often release waste gases such as CO2 CH4 and N2O. The processes
include iron and steel production, cement manufacture, ammonia manufacture and urea application, lime
manufacture, limestone and dolomite use (e.g., flux stone, flue gas desulfurization, and glass manufacturing), soda
ash manufacture and use, titanium dioxide production, phosphoric acid production, ferroalloy production, CO2
consumption, aluminum production, petrochemical production, silicon carbide production, nitric acid production,
and adipic acid production. Additionally, emissions from industrial processes release HFCs, PFCs and SF6. Overall,
emission sources in the Industrial Process chapter account for 4.5 percent of U.S. greenhouse gas emissions in 2003.
Solvent and Other Product Use
The Solvent and Other Product Use chapter contains emissions Greenhouse gas emissions are produced as a by-
product of various solvent and other product uses. In the United States, emissions from N2O Product Usage, the
only source of greenhouse gas emissions from this sector, accounted for less than 0.1 percent of total U.S.
anthropogenic greenhouse gas emissions on a carbon equivalent basis in 2003.
Agriculture
The Agricultural chapter contains anthropogenic emissions from agricultural activities (except fuel combustion,
which is addressed in the Energy chapter). Agricultural activities contribute directly to emissions of greenhouse
gases through a variety of processes, including the following source categories: enteric fermentation in domestic
livestock, livestock manure management, rice cultivation, agricultural soil management, and field burning of
agricultural residues. Methane and N2O were the primary greenhouse gases emitted by agricultural activities.
Methane emissions from enteric fermentation and manure management represented about 21 percent and 7 percent
of total CH4 emissions from anthropogenic activities, respectively in 2003. Agricultural soil management activities
such as fertilizer application and other cropping practices were the largest source of U.S. N2O emissions in 2003,
accounting for 67 percent. In 2003, emission sources accounted for in the Agricultural chapters were responsible
for 6.3 percent of total U.S. greenhouse gas emissions.
Land-Use Change and Forestry
The Land-Use Change and Forestry chapter contains emissions and removals of CO2 from forest management, other
land-use activities, and land-use change. Forest management practices, tree planting in urban areas, the
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ES-10
-------
management of agricultural soils, and the landfilling of yard trimmings and food scraps have resulted in a net uptake
(sequestration) of carbon in the United States. Forests (including vegetation, soils, and harvested wood) accounted
for approximately 91 percent of total 2003 sequestration, urban trees accounted for 7 percent, agricultural soils
(including mineral and organic soils and the application of lime) accounted for 1 percent, and landfilled yard
trimmings and food scraps accounted for 1 percent of the total sequestration in 2003. 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 times 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 and food scraps net
sequestration is due to the long-term accumulation of yard trimming carbon and food scraps in landfills.
Land use, land-use change, and forestry activities in 2003 resulted in a net carbon sequestration of 828.0 Tg CO2
Eq. (Table ES-5). This represents an offset of approximately 14 percent of total U.S. CO2 emissions, or 12 percent
of total gross greenhouse gas emissions in 2003. Total land use, land-use change, and forestry net carbon
sequestration declined by approximately 21 percent between 1990 and 2003. This decline was primarily due to a
decline in the rate of net carbon accumulation in forest carbon stocks. Annual carbon accumulation in landfilled
yard trimmings and food scraps also slowed over this period, as did annual carbon accumulation in agricultural
soils. As described above, the constant rate of carbon accumulation in urban trees is a reflection of limited
underlying data (i.e., this rate represents an average for 1990 through 1999).
Land use, land-use change, and forestry activities in 2003 also resulted in emissions of N2O (6.4 Tg CO2 Eq.). Total
N2O emissions from the application of fertilizers to forests and settlements increased by approximately 14 percent
between 1990 and 2003.
Table ES-5: Net CO2 Flux from Land-Use Change and Forestry (Tg CO2 Eq.)
Sink Category
Forest Land Remaining Forest Land
Changes in Forest Carbon Stocks
Cropland Remaining Cropland
Changes in Agricultural Soil Carbon
Stocks
Settlements Remaining Settlements
Urban Trees
Landfilled Yard Trimmings and Food
Scraps
Total
1990
(949.3)
(949.3)
(8.1)
(8.1)
(84.7)
(58.7)
(26.0)
(1,042.0)
1 1997 1998 1999 2000 2001 2002 2003
! (851.0) (805.5) (751.7) (747.9) (750.9) (751.5) (752.7)
H (851.0) (805.5) (751.7) (747.9) (750.9) (751.5) (752.7)
! (7.4) (4.3) (4.3) (5.7) (7.1) (6.2) (6.6)
! (7.4) (4.3) (4.3) (5.7) (7.1) (6.2) (6.6)
I (71.6) (71.2) (70.0) (68.9) (68.9) (68.8) (68.7)
H (58.7) (58.7) (58.7) (58.7) (58.7) (58.7) (58.7)
| (12.9) (12.5) (11.4) (10.2) (10.3) (10.2) (10.1)
! (930.0) (881.0) (826.1) (822.4) (826.9) (826.5) (828.0)
Waste
The Waste chapter contains emissions from waste management activities (except waste incineration, which is
addressed in the Energy chapter). Landfills were the largest source of anthropogenic CH4 emissions, accounting for
24 percent of total U. S. CH4 emissions.11 Wastewater treatment systems are a potentially significant source of 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
11 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ES-11
-------
simplified methodology. Overall, in 2003, emission sources accounted for in the Waste chapter generated 2.7
percent of total U.S. greenhouse gas emissions.
ES.4. Other Information
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 charactenzation 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-6 summarizes emissions from each of these sectors, and Figure ES-13 shows the trend in
emissions by sector from 1990 to 2003.
Figure ES-13: Emissions Allocated to Economic Sectors
Table ES-6: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO2 Eq.)
Economic Sector
Electric Power Industry
Transportation
Industry
Agriculture
Commercial
Residential
U.S. Territories
Total
Land-Use Change and Forestry
Sinks
Net Emissions (Sources and
Sinks)
1990 :
1,841.8;;;:-
1,506.8;;;:-
1,446.1 ;;;;•
473.3 ;;;: •
435.4 ;;;:;
350.9;-
33.8 ^;:
6,088.1
..;•;.•••
(1,042.0) .;;t
•S
5,046.1 ;:
1997
2,104.6
1,693.0
1,509.1
492.0
445.2
391.0
42.7
6,677.5
(930.0)
5,747.5
1998
2,186.8
1,728.7
1,470.6
508.4
424.2
358.4
42.7
6,719.7
(881.0)
5,838.8
1999
2,197.3
1,790.0
1,427.9
486.9
426.8
379.5
43.9
6,752.2
(826.1)
5,926.1
2000
2,299.0
1,839.6
1,431.8
495.3
440.7
399.7
47.0
6,953.2
(822.4)
6,130.8
2001
2,254.9
1,819.8
1,371.0
488.6
431.4
387.1
54.1
6,806.9
(826.9)
5,980.1
2002
2,269.7
1,851.6
1,365.7
485.6
440.2
391.6
53.6
6,858.1
(826.5)
6,031.6
2003
2,296.2
1,864.4
1,331.4
486.4
453.5
406.1
62.3
6,900.2
(828.0)
6,072.2
Note: Totals may not sum. Emissions include CO2, CH4, HFCs, PFCs, and SF6.
See Table 2-14 for more detailed data.
Using this categorization, emissions from electricity generation accounted for the largest portion (33 percent) of
U.S. greenhouse gas emissions in 2003. 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 2003.
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 residential, agriculture, and commercial economic sectors,
plus emissions from U.S. Territories. Residences accounted for about 6 percent, and primarily consisted of CO2
emissions from fossil fuel combustion. Activities related to agriculture accounted for roughly 7 percent of U.S.
emissions; 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.
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 landfilhng of yard trimmings.
Electricity is ultimately consumed in the economic sectors described above. Table ES-7 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
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ES-12
-------
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.12 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 2003. 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 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-14 shows the trend in these emissions by sector from 1990 to 2003.
Table ES-7: U.S Greenhouse Gas Emissions by Economic Sector and Gas with Electricity-Related Emissions
Distributed (Tg CO2 Eq.)
Economic Sector
Industry
Transportation
Commercial
Residential
Agriculture
U.S. Territories
Total
Land-Use Change and Forestry Sinks
Net Emissions (Sources and Sinks)
1990
2,075.7:-:
1,509.9;:;
981.6;:;
953.0;:;
534.1 ;\:
33.8 :.' /:
6,088.1 ,
(1,042.0) ^;
5,046.1 :
1997 1998 1999 2000 2001 2002 2003
2,247.3 2,223.2 2,190.1 2,207.7 2,074.0 2,062.9 2,040.1
1,696.1 1,731.8 1,793.2 1,843.0 1,823.2 1,854.8 1,867.6
1,083.8 1,093.5 1,104.9 1,161.8 1,170.6 1,178.5 1,196.8
1,060.3 1,060.0 1,082.9 1,141.4 1,129.6 1,159.5 1,183.7
547.4 568.6 537.3 552.3 555.5 548.8 549.8
42.7 42.7 43.9 47.0 54.1 53.6 62.3
6,677.5 6,719.7 6,752.2 6,953.2 6,806.9 6,858.1 6,900.2
(930.0) (881.0) (826.1) (822.4) (826.9) (826.5) (828.0)
5,747.5 5,838.8 5,926.1 6,130.8 5,980.1 6,031.6 6,072.2
See Table 2-16 for more detailed data.
Figure ES-14: Emissions with Electricity Distributed to Economic Sectors
[BEGIN BOX]
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 nonutilities combined—was the largest source of U.S. greenhouse gas
emissions in 2003; 4) emissions per unit of total gross domestic product as a measure of national economic activity;
or 5) emissions per capita.
Table ES-8 provides data on various statistics related to U.S. greenhouse gas emissions normalized to 1990 as a
baseline year. Greenhouse gas emissions in the United States have grown at an average annual rate of 1.0 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. Total U.S. greenhouse gas emissions have also
grown more slowly than national population since 1990 (see Figure ES-15). Overall, global atmospheric CO2
12 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ES-13
-------
concentrations—a function of many complex anthropogenic and natural processes—are increasing at 0.5 percent
per year.
Table ES-8: Recent Trends in Various U.S. Data (Index 1990 = 100) and Global Atmospheric CO2 Concentration
Growth
Variable 1991 1997 1998 1999 2000 2001 2002 2003 Ratef
Greenhouse Gas Emissions3
Energy Consumptionb
Fossil Fuel Consumption11
Electricity Consumption11
GDPC
Population*
99 ;;•
100 |i
99 I
102 I
100 |
101 |
:e no
:? 112
:e 112
:? 117
:e 122
!:•: 109
110
113
113
121
127
110
111
114
114
124
133
112
114
117
117
128
138
113
112
114
115
125
139
114
113
116
116
129
142
115
113
116
116
130
146
116
1.0%
1.2%
1.2%
2.1%
3.0%
1.1%
Atmospheric CO2 K
Concentration6 100 ji^ 103 104 104 104 105 105 106 0.5%
a GWP weighted values
b Energy content weighted values (EIA 2004)
0 Gross Domestic Product in chained 2000 dollars (BEA 2004)
d (U.S. Census Bureau 2004)
e Mauna Loa Observatory, Hawaii (Keeling and Whorf 2004)
f Average annual growth rate
Figure ES-15: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product
[END BOX]
Ambient Air Pollutant Emissions
In the United States, CO, NOX, NMVOCs, SO2 are referred to as "ambient air pollutants," and are regulated under
the Clean Air Act in an effort to protect human health and the environment. 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. Additionally, some of these pollutants may react with other chemical compounds in the
atmosphere to form compounds that are greenhouse gases. Since 1970, the United States has published estimates of
annual emissions of ambient air pollutants (EPA 2004).13 Table ES-9 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.
Table ES-9: Emissions of NOX, CO, NMVOCs, and SO2 (Gg)
Gas/Activity
NOX
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Waste Combustion
1990 *
22,860:5
9,884 : 5
12,134;::::
139:.-:.:
82 ::W:
1997
: 22
: 9
,284
,578
. ; 11,768
130
140
1998
21,964
9,419
11,592
130
145
1999
20,530
8,344
11,300
109
143
2000
20
8
11
,288
,002
,395
111
114
2001
19
7
10
,414
,667
,823
113
114
2002
18,850
7,523
10,389
135
134
2003
18,573
7,222
10,418
124
121
lj NOX and CO emission estimates from field burning of agricultural residues were estimated separately, and therefore not taken
from EPA (2004).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ES-14
-------
Industrial Processes
Solvent Use
Agricultural Burning
Waste
CO
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Waste Combustion
Industrial Processes
Solvent Use
Agricultural Burning
Waste
NMVOCs
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Waste Combustion
Industrial Processes
Solvent Use
Agricultural Burning
Waste
SO2
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Waste Combustion
Industrial Processes
Solvent Use
Agricultural Burning
Waste
591 if
28 ; f
130,580 f
4,999;!
119,482;!
302;!
978i!
4, 124 if
4;!
689 if
1 if
20,937if
912;!
10,933;!
555;!
222;!
2,426;!
5,217 if
NAif
673 if
20,936 if
18,407 if
793 i f
3 90 if
39 if
1,306 if
oif
NAif:
o ff
i:f 629
:.':: 3
if 34
if 3
f 101,138
if 3,927
if 90,284
if 333
if 2,668
if 3,153
5; i
;; 767
f 5
f 16,994
if 1,016
if 7,928
if 442
if 313
if 2,038
ll 5,100
:i; NA
f; 157
f 17,091
if 15,104
if 659
if 312
if 29
f; 985
f; 1
* NA
637
35
3
98,984
3,927
87,940
2
3
332
,826
,163
1
789
5
16,403
1,016
7
2
4
17
15
,742
440
326
,047
,671
NA
161
,189
,191
665
310
30
991
1
NA
1
595
3
34
3
94,361
5,024
83,484
145
2,725
2,156
46
767
13
15,869
1,045
7,586
414
302
1,813
4,569
NA
140
15,917
13,915
704
283
30
984
1
NA
1
626
3
35
2
92,895
4,340
83,680
146
1,670
2,217
46
790
8
15,228
1,077
7,230
389
257
1,773
4,384
NA
119
14,829
12,848
632
286
29
1,031
1
NA
1
89
4
79
1
2
15
1
6
1
4
14
12
1
656
3
35
2
,329
,377
,972
147
,672
,339
45
770
8
,048
,080
,872
400
258
,769
,547
NA
122
,452
,461
624
289
30
,047
1
NA
1
630
5
33
2
87,451
4,020
78,574
1
2
14
6
1
4
116
,672
,308
46
707
8
,222
926
,560
340
281
,725
,256
NA
133
13,928
11,946
1
631
315
24
,009
2
NA
1
648
4
33
2
85,077
4,454
75,526
125
1,674
2,431
65
794
8
13,939
1,007
6,351
345
263
1,711
4,138
NA
125
14,463
12,477
634
293
28
1,029
2
NA
1
Source: (EPA 2004) 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.
Figure ES-16: 2003 Key Sources - Tier 1 Level Assessment
Quality Assurance and Quality Control (QA/QC)
The United States seeks to continually improve the quality, transparency and credibility of the Inventory of U.S.
Greenhouse Gas Emissions and Sinks. To assist in these efforts, the United States implemented a systematic
approach to QA/QC. While QA/QC has always been an integral part of the U.S. national system for Inventory
development, the procedures followed for the current Inventory have been formalized in accordance with the
QA/QC plan and the UNFCCC reporting guidelines.
Uncertainty Analysis 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 have low uncertainties. For some other categories of emissions, however, a lack of data or an
incomplete understanding of how emissions are generated increases the uncertainty associated with the estimates
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page ES-15
-------
presented. Acquiring a better understanding of the uncertainty associated with Inventory estimates is an important
step in helping to prioritize future work and improve the overall quality of the Inventory. Recognizing the benefit
of conducting an uncertainty analysis, the UNFCCC reporting guidelines follow the recommendations of the IPCC
Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (hereafter referred
to as the IPCC Good Practice Guidance) and require that countries provide single point estimates of uncertainty for
many source and sink categories.
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 uncertainty surrounding the estimates are
discussed. Most sources also contain a quantitative uncertainty assessment, in accordance with UNFCCC reporting
guidelines.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page ES-16
-------
I MFCs, PFCs, & SF e
Nitrous Oxide
Methane
I Carbon Dioxide
M21 6,251 6,343^6,621
6,678 6,720 6;752 6'953 6,807 6,858
6,900
8,000 -
7,000 -
6,000 -
CT 5,000 -
LU
O 4,000 -
<_>
P 3,000 -
2,000 -
1,000 -
0 -
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Figure ES-1: U.S. GHG Emissions by Gas
4% -
3% -
2% -
1% -
0%
-1% -
-2% -
-3% -
3.3%
3.0%
2.1%
1.4%
0.8% Oi6o/0
-0.8%
-2.1%
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Figure ES-2: Annual Percent Change in U.S. Greenhouse Gas Emissions
865
770
812
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Figure ES-3: Cumulative Change in U.S. Greenhouse Gas Emissions Relative to 1990
-------
MFCs, PFCs & SF6 2.0%
N20
CH4
CO,
84.7%
Figure ES-4: 2003 Greenhouse Gas Emissions by Gas
Fossil Fuel Combustion
Iron and Steel Production
Cement Manufacture
Waste Combustion
Ammonia Production and Urea Application
Lime Manufacture
Natural Gas Flaring
Limestone and Dolomite Use
Aluminum Production
Soda Ash Manufacture and Consumption
Titanium Dioxide Production
Phosphoric Acid Production
Ferroalloys
Carbon Dioxide Consumption
15,551.6
CO2 as a Portion
of all Emissions
10
20 30 40
Tg C02 Eq
50
60
Figure ES-5: 2003 Sources of CO2
-------
2,000 -
a- I'500 -
UJ
O
£ 1,000 -
500 -
0 -
Relative Contribution by
Fuel Type
0)
•a
0)
E
o
3
•a
o
4J
i Natural Gas
: Petroleum
I Coal
Figure ES-6: 2003 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
Note: Electricity generation also includes emissions of less than 1 Tg CO2 Eq. from geothermal-based
electricity generation.
2000
1800
1600
1400
1200
1000
800
600
400
200
0
t' From Electricity
Consumption
• From Direct Fossil
Fuel Combustion
&
Figure ES-7: 2003 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion
-------
Landfills
Natural Gas Systems
Enteric Fermentation
Coal Mining
Manure Management
Wastewater Treatment
Petroleum Systems ^^^
Rice Cultivation |
Stationary Sources |
Abandoned Coal Mines |
Mobile Sources |
Petrochemical Production |
Iron and Steel Production |
Agricultural Residue Burning |
Silicon Carbide Production <0.05
CH4 as a Portion
of all Emissions
7.9%
0
20
40
60 80
TgC02Eq.
100
120
140
Figure ES-8: 2003 Sources of CH4
Agricultural Soil Management
Mobile Sources
Manure Management
Human Sewage
Nitric Acid
Stationary Sources |
AdipicAcid |
N2O Product Usage |
Agricultural Residue Burning |
Waste Combustion |
253.5
N2O as a Portion
of all Emissions
5.5%
0 10 20 30 40 50 60 70
Tg CO2 Eq
Figure ES-9: 2003 Sources of N2O
-------
Substitution of Ozone
Depleting Substances
Electrical Transmission
and Distribution
HCFC-22 Production
Semiconductor
Manufacture
Aluminum Production
Magnesium Production
and Processing
1
1
1
as a Portion
of all Emissions
2.0%
o
0 10 20 30 40 50 60 70 80 90 100
Tg CO2 Eq
Figure ES-10: 2003 Sources of MFCs, PFCs, and SF6
Industrial Processes
Waste
7,000 -
6,000
5,000 -
CT 4,000 -
L1J '
8 3,000 -
H 2,000 -
1,000 -
0
(1,000) -
(2,000) -
Agriculture
Energy
LandHJse .Change an3j.Forestr.y .(s:ijik|; ,
Figure ES-11: U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector
-------
j^^^
6.1% Renewable
8.0% Nuclear
22.5%
Natural Gas
22.8% Coal
;;-',,. 39.1%
•'";'•' '-','. Petroleum
Figure ES-12: 2003 U.S. Energy Consumption by Energy Source
-------
2,500 -,
2,000 -
Electricity Generation
O"
LU
CM
O
O
D)
1,000 -
500 -
Transportation
Industry
Agriculture
Commercial
Residential
0
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Year
Figure ES-13: Emissions Allocated to Economic Sectors
Note: Does not include U.S. territories.
2,500
2,000
£1,500
CM
O
O
F 1,000
500
o
en
en
Industrial
Transportation
•Commercial
Residential
Agriculture
fMCNCNCN
Figure ES-14: Emissions with Electricity Distributed to Economic Sectors
Note: Does not include U.S. territories.
-------
150 -,
140 -
S- 130 -
7 120 -
V 1°° "
£ 90 -
80 -
70 -
Real GDP
Population
Emissions per capita
*- -.
Emissions per $GDP
Figure ES-15: U.S. Greenhouse Gas Emissions Per Capita
and Per Dollar of Gross Domestic Product
-------
CO2 - Stationary Combustion - Coal
CO2 - Mobile Combustion: Road & Other
CO2 - Stationary Combustion - Gas
CO2 - Stationary Combustion - Oil
CO2 - Mobile Combustion: Aviation |
Direct N2O Emissions from Agricultural Soils I
CH4 - Solid Waste Disposal Sites |
CH4 - Fugitive Emissions from Natural Gas Operations I
CO2 - Non-Energy Use of Fuels |
CH4 - Enteric Fermentation in Domestic Livestock |
Various - Substitutes for Ozone Depleting Substances I
Indirect N2O Emissions from Nitrogen Used in Agriculture I
CO2 - Mobile Combustion: Marine J
CH4 - Fugitive Emissions from Coal Mining and Handling I
CO2 - Iron and Steel Production J
CO2 - Cement Production |
N20 - Mobile Combustion: Road & Other |
200 400 600 800 1000 1200 1400 1600 1800 2000
Tg CO2Eq.
Figure ES-16: 2003 Key Sources - Tier 1 Level Assessment
Note: For a complete discussion of the key source analysis see Annex 1.
-------
-------
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 2003. A summary of these estimates is provided in Table 2-3 and Table 2-4 by gas
and source category in the Trends in Greenhouse Gas Emissions chapter. 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). As stated in Article 2 of the UNFCCC, 'The ultimate 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."2'3
Parties to the Convention, by ratifying, "shall 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 these commitments 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).
Under Working Group 1 of the IPCC, nearly 140 scientists and national experts from more than thirty countries
collaborated in the creation of the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories
(IPCC/UNEP/OECD/IEA 1997) to ensure that the emission inventories submitted to the UNFCCC are consistent
and comparable between nations. The 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 IPCC Good Practice Guidance and Uncertainty Management in
National Greenhouse Gas Inventories, which further expanded upon the methodologies in the Revised 1996 IPCC
Guidelines. The IPCC has also accepted the Good Practice Guidance for Land Use, Land-Use Change and
Forestry at its Twenty-First Session (Vienna, November 3-7, 2003), as an elaboration of the Revised 1996
Guidelines.
Overall, this inventory of anthropogenic greenhouse gas emissions 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. The structure of this report is consistent with the current UNFCCC
Guidelines on Reporting and Review (UNFCCC 2003).
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).
J 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(l)(a) of the United Nations Framework Convention on Climate Change (also identified in Article 12). Subsequent
decisions by the Conference of the Parties elaborated the role of Annex I Parties in preparing national inventories. See
.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 1
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1.1. Background Information
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 ofradiatively
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, chlonne, or bromine are also greenhouse
gases, but they are, for the most part, solely a product of industrial activities. Chlorofluorocarbons (CFCs) and
hydrochlorofluorocarbons (HCFCs) are halocarbons that contain chlorine, while halocarbons that contain bromine
are referred to as bromofluorocarbons (i.e., halons). 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) 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.
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.
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Atmospheric concentrations of these gases, along with their rates of growth and atmospheric lifetimes, are presented
in Table 1-1.
Table 1-1: Global atmospheric concentration (ppm unless otherwise specified), rate of concentration change
(ppb/year) and atmospheric lifetime (years) of selected greenhouse gases
Atmospheric Variable
Pre-industrial atmospheric
concentration
Atmospheric concentration1*
Rate of concentration changed
Atmospheric Lifetime
C02
280
372.3
1.5e
50-200f
CH4
0.722
1.729-1.843°
0.0076
12g
N2O
0.270
0.317-0.318C
0.0008
114g
SF6a
0
4.7-4.8
0.24
3,200
CF4a
40
80
1.0
>50,000
Source: Current atmospheric concentrations for CO2, CH4, N2O, and SF6 are from Biasing and Jones (2003). All other data is
from IPCC (2001).
a Concentrations in parts per trillion (ppt) and rate of concentration change in ppt/year.
b Concentration for SF6 was measured in 2001; concentration for CF4 was measured in 2000. Concentrations for all other gases
were measured in 2002.
0 The low and high endpoints of the range represent concentrations from Tasmania, a mid-latitude Southern-Hemisphere site, and
Ireland, a mid-latitude Northern-Hemisphere site, respectively.
d Rate is calculated over the period 1990 to 1999.
e Rate has fluctuated between 0.9 and 2.8 ppm per year for CO2 and between 0 and 0.013 ppm per year for CH4 over the period
1990 to 1999.
f No single lifetime can be defined for CO2 because of the different rates of uptake by different removal processes.
g 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 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. In nature, carbon is cycled between various atmospheric, oceanic, land biotic, marine biotic, and
mineral reservoirs. The largest fluxes occur between the atmosphere and terrestrial biota, and between the
atmosphere and surface water of the oceans. In the atmosphere, carbon predominantly exists in its oxidized form as
CO2. Atmospheric 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 372.3 ppmv in 2001, a 33 percent
increase (IPCC 2001 and Biasing and Jones 2004).7'8 The IPCC definitively states that "the present atmospheric
CO2 increase is caused by anthropogenic emissions of CO2" (IPCC 2001). The predominant source of
anthropogenic CO2 emissions is the combustion of fossil fuels. Forest clearing, other biomass burning, and some
non-energy production processes (e.g., cement production) also emit notable quantities of CO2.
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).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 3
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In its second assessment, the IPCC also stated that "[t]he increased amount of carbon dioxide [in the atmosphere] is
leading to climate change and will produce, on average, a global warming of the Earth's surface because of its
enhanced greenhouse effect—although the magnitude and significance of the effects are not fully resolved" (IPCC
1996).
Methane. 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
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. 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 17
percent since 1750, from a pre-industrial value of about 270 ppb to 314 ppb in 1998, a concentration that has not
been exceeded during the last thousand years. Nitrous oxide is primarily removed from the atmosphere by the
photolytic action of sunlight in the stratosphere (IPCC 2001).
Ozone. 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 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 NOX in the presence of
sunlight. Ozone, CO, SO2, nitrogen dioxide (NO2) and particulate matter are included in the category referred to as
"ambient air pollutants" in the United States under the Clean Air Act11 and its subsequent amendments. The
tropospheric concentrations of ozone and these other pollutants are short-lived and, therefore, spatially variable.
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]
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Halocarbons, Perfluorocarbons, and Sulfur Hexafluoride. Halocarbons are, for the most part, man-made chemicals
that have both direct and indirect radiative forcing effects. Halocarbons that contain chlorine (CFCs, HCFCs,
methyl chloroform, and carbon tetrachloride) and bromine (halons, methyl bromide, and hydrobromofluorocarbons
(HBFCs)) result in stratospheric ozone depletion and are therefore controlled under the Montreal Protocol on
Substances that Deplete the Ozone Layer. Although CFCs and HCFCs include potent global warming gases, their
net radiative forcing effect on the atmosphere is reduced because they cause stratospheric ozone depletion, which
itself is 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 covered under the Montreal Protocol and its Amendments are not
covered by the UNFCCC; they are reported in this inventory under Annex 6.2 for informational purposes.
HFCs, PFCs, and 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 (fPCC 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 (fPCC 2001).
Carbon Monoxide. 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 vanable.
Nitrogen Oxides. 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
12 Article 5 of the Montreal Protocol covets 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 often
additional years in the phase-out of ozone depleting substances.
1J NOX emissions injected higher in the stratosphere, primarily from fuel combustion emissions from high altitude supersonic
aircraft, can lead to stratospheric ozone depletion.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 5
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and biomass burning. Aerosols affect radiative forcing differently than greenhouse gases, and their radiative effects
occur through direct and indirect mechanisms: directly by scattering and absorbing solar 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 is 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, biogemc
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.
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, black carbon, may have a positive radiative forcing (Jacobson 2001). The primary anthropogenic emission
sources of black carbon include diesel exhaust and open biomass burning.
Global Warming Potentials
A GWP is 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 absorbs radiation. Indirect radiative forcing occurs when chemical
transformations involving the original gas produces a gas or gases that are greenhouse gases, or when a gas
influences other radiatively important processes such as the atmospheric lifetimes of other gases. The reference gas
used is CO2, and therefore GWP weighted emissions are measured in teragrams of CO2 equivalent (Tg CO2Eq.)16
The relationship between gigagrams (Gg) of a gas and Tg CO2Eq. can be expressed as follows:
Tg C02 Eq = (Ggof gas)x (GWP)
1,
where,
Carbonaceous aerosols are aerosols that are comprised mainly of organic substances and forms of black carbon (or soot)
(IPCC 2001).
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 12/44*8 of carbon dioxide by weight.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 6
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Tg CO2Eq. = Teragrams of Carbon Dioxide Equivalent
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.
Greenhouse gas emissions and removals should be presented on a gas-by-gas basis in units of mass... In
addition, consistent with decision 2/CP.3, 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
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.
Table 1-2: Global Warming Potentials and Atmospheric Lifetimes (Years) Used in this Report
Gas
C02
CH4b
N20
HFC-23
HFC-32
HFC- 125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
CF4
C2F6
C4Fio
C6F14
SF6
Atmospheric Lifetime
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
GWPa
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 CO2 is not included.
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. 7. (UNFCCC 2003)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 7
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[Begin Box]
Box 1-1: The IPCC Third Assessment Report and Global Warming Potentials
In 2001, the IPCC published its Third Assessment Report (TAR), which provided an updated and more
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 CO2 radiative forcing and an improved
CO2 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 CO2 is about 12 percent lower than that in the SAR, the GWPs of the other gases relative to CO2
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
CO2
CH4*
N2O
HFC-23
HFC-32
HFC- 125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
CF4
C2F6
C4Fio
C6F14
SF6
SAR
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
TAR
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
Change
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)
Note: Parentheses indicate negative values.
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 CO2 is not included.
To comply with international reporting standards under the UNFCCC, official emission estimates are reported by
the United States using SAR GWP values. 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 2003 are consistent and comparable with estimates developed prior to
the publication of the TAR. For informational purposes, emission estimates that use the updated GWPs are
presented below and in even more detail in Annex 6.1. 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.
18 See
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Table 1-4: Effects on U.S. Greenhouse Gas Emission Trends Using IPCC SAR and TAR GWP Values (Tg CO2
Eg.)
Gas
C02
CH4
N2O
HFCs, PFCs, and SF6
Total
Percent Change
Change from
SAR
832.0
(60.4)
(5.2)
45.8
812.1
13.3%
1990 to 2003
TAR
832.0
(66.1)
(5.0)
45.5
806.3
13.2%
Revisions to Annual Estimates
1990 2003
0 0
57.7 51.9
(17.3) (17.0)
(2.7) (2.9)
37.7 31.9
0.6% 0.5%
Note: Parentheses indicate negative values. Totals may not sum due to independent rounding.
Table 1-5 below shows a comparison of total emission 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 (8.3 percent in 2003), due the predominance of CH4 emissions in this sector. Emissions from all
other sectors were comprised of mainly CO2 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 CO2Eq.)
Sector 1990 e, 1997 1998 1999 2000 2001
2002
2003
Energy
SAR GWP (Used In Inventory)
TAR GWP
Difference (%)
Industrial Processes
SAR GWP (Used In Inventory)
TAR GWP
Difference (%)
Solvent and Other Product Use
SAR GWP (Used In Inventory)
TAR GWP
Difference (%)
Agriculture
SAR GWP (Used In Inventory)
TAR GWP
Difference (%)
Land-Use Change and Forestry
SAR GWP (Used In Inventory)
TAR GWP
Difference (%)
Waste
SAR GWP (Used In Inventory)
TAR GWP
Difference (%)
Net Emissions (Sources and
Sinks)
SAR GWP (Used In Inventory)
TAR GWP
Difference (%)
1
5,141 7J
5, 162 9J'
0.4% >.
>
299 9 ]'
296 0 >•
(1. 3%) I
j
43j-
4 1 1
(4.5%) i
I'
426 5 j
429 2 i
0.6% t
[
(1,036.5) \
(1,036.7) t
+ 1
\
210 1 1
228 3 1
8.7% '
5,046.1
5,083.8
0.7% ,
V,
f. 5,712.8
,i" 5,732.0
;!- 0.3%
327.1
':" 323.3
"l, (1-1%)
.«
;:- 4.8
'•;, 4.6
-*' (4.5%)
*"
v, 432.8
436.1
;" 0.8%
'I n,
'", (923.6)
;°" (923.9)
" i
"N ~r
•*!'•
/i 193.7
\ 210.1
'.;' 8.5%
» /
'*}
'',''' 5,747.5
;•: 5,782.2
"• 0.6%
5,737.3
5,756.6
0.3%
334.9
332.0
(0.9%)
4.8
4.6
(4.5%)
449.8
452.6
0.6%
(874.5)
(874.8)
+
186.0
201.6
8.4%
5,838.8
5,872.6
0.6%
5,802.6
5,820.7
0.3%
329.2
325.7
(1.1%)
4.8
4.6
(4.5%)
425.9
429.7
0.9%
(819.5)
(819.8)
+
183.1
198.4
8.3%
5,926.1
5,959.2
0.6%
5,985.3
6,003.7
0.3%
332.1
328.4
(1.1%)
4.8
4.6
(4.5%)
444.1
446.8
0.6%
(816.1)
(816.4)
+
180.6
195.6
8.3%
6,130.8
6,162.6
0.5%
5,877.3
5,895.6
0.3%
304.7
301.2
(1.1%)
4.8
4.6
(4.5%)
437.5
440.4
0.7%
(820.7)
(821.0)
+
176.5
191.1
8.3%
5,980.1
6,012.0
0.5%
5,920.7
5,938.6
0.3%
315.4
311.8
(1.1%)
4.8
4.6
(4.5%)
432.4
435.6
0.7%
(820.1)
(820.4)
+
178.3
193.1
8.3%
6,031.6
6,063.2
0.5%
5,963.4
5,981.1
0.3%
308.6
304.9
(1.2%)
4.8
4.6
(4.5%)
433.3
436.4
0.7%
(821.6)
(821.9)
+
183.8
199.1
8.3%
6,072.2
6,104.1
0.5%
NC (No change)
+ Less than 0.05%.
Note: Parentheses indicate negative values. Totals may not sum due to independent rounding.
[End Box]
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 9
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1.2. Institutional Arrangements
The U.S. Environmental Protection Agency (EPA), in cooperation with other U.S. government agencies, prepares
the Inventory of U.S. Greenhouse Gas Emissions and Sinks. A wide range of agencies and individuals are involved
in supplying data to, reviewing, or preparing portions of the U.S. Inventory—including federal and state
government authorities, research and academic institutions, industry associations, and private consultants.
Within EPA, the Office of Atmospheric Programs (OAP) is the lead office responsible for the emission calculations
provided in the Inventory, as well as the completion of the National Inventory Report and the Common Reporting
Format tables. The Office of Transportation and Air Quality (OTAQ) is also involved in calculating emissions for
the Inventory. While the U.S. Department of State officially submits the annual Inventory to the UNFCCC, EPA's
OAP serves as the focal point for technical questions and comments on the U.S. Inventory. The staff of OAP and
OTAQ coordinates the annual methodological choice, activity data collection, and emission calculations at the
individual source category level. Within OAP, an Inventory coordinator compiles the entire Inventory into the
proper reporting format for submission to the UNFCCC, and is responsible for the collection and consistency of
cross-cutting issues in the Inventory.
Several other government agencies contribute to the collection and analysis of the underlying activity data used in
the Inventory calculations. Formal relationships exist between EPA and other U.S. agencies that provide official
data for use in the Inventory. The U.S. Department of Energy's Energy Information Administration provides
national fuel consumption data and the U.S. Department of Defense provides military fuel consumption and bunker
fuels. Informal relationships also exist with other U.S. agencies to provide activity data for use in EPA's emission
calculations. These include: the U.S. Department of Agriculture, 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, and the Federal Aviation Administration. Academic and
research centers also provide activity data and calculations to EPA, as well as individual companies participating in
voluntary outreach efforts with EPA. Finally, the U.S. Department of State officially submits the Inventory to the
UNFCCC each April.
1.3. Inventory Process
EPA has a decentralized approach to preparing the annual U.S. Inventory, which consists of a National Inventory
Report (NIR) and Common Reporting Format (CRF) tables. The Inventory coordinator at EPA is responsible for
compiling all emission estimates, and ensuring consistency and quality throughout the NIR and CRF tables.
Emission calculations for individual sources are the responsibility of individual source leads, who are most familiar
with each source category and the unique characteristics of its emissions profile. The individual source leads
determine the most appropriate methodology and collect the best activity data to use in the emission calculations,
based upon their expertise in the source category, as well as coordinating with researchers and contractors familiar
with the sources. A multi-stage process for collecting information from the individual source leads and producing
the Inventory is undertaken annually to compile all information and data.
Methodology Development, Data Collection, and Emissions and Sink Estimation
Source leads at EPA collect input data and, as necessary, evaluate or develop the estimation methodology for the
individual source categories. For most source categories, the methodology for the previous year is applied to the
new "current" year of the Inventory, and Inventory analysts collect any new data or update data that have changed
from the previous year. If estimates for a new source category are being developed for the first time, or if the
methodology is changing for an existing source category (e.g., the United States is implementing a higher Tiered
approach for that source category), then the source category lead will develop a new methodology, gather the most
appropriate activity data and emission factors (or in some cases direct emission measurements) for the entire time
series, and conduct a special source-specific peer review process involving relevant experts from industry,
government, and universities.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 10
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Once the methodology is in place and the data are collected, the individual source leads calculate emissions and sink
estimates. The source leads then update or create the relevant text and accompanying annexes for the Inventory.
Source leads are also responsible for completing the relevant sectoral background tables of the Common Reporting
Format, conducting quality assurance and quality control (QA/QC) checks, and uncertainty analyses.
Summary Spreadsheet Compilation and Data Storage
The Inventory coordinator at EPA collects the source categories' descriptive text and Annexes, and also aggregates
the emission estimates into a summary spreadsheet that links the individual source category spreadsheets together.
This summary sheet contains all of the essential data in one central location, in formats commonly used in the
Inventory document. In addition to the data from each source category, national trend and related data is also
gathered in the summary sheet for use in the Executive Summary, Introduction, and Recent Trends sections of the
Inventory report. Electronic copies of each year's summary spreadsheet, which contains all the emission and sink
estimates for the United States, are kept on a central server at EPA under the jurisdiction of the Inventory
coordinator.
National Inventory Report Preparation
The NIR is compiled from the sections developed by each individual source lead. In addition, the Inventory
coordinator prepares a brief overview of each chapter that summarizes the emissions from all sources discussed in
the chapters. The Inventory coordinator then carries out a key source analysis for the Inventory, consistent with the
IPCC Good Practice Guidance, IPCC Good Practice Guidance for Land Use, Land Use Change and Forestry, and
in accordance with the reporting requirements of the UNFCCC. Also at this time, the Introduction, Executive
Summary, and Recent Trends sections are drafted, to reflect the trends for the most recent year of the current
Inventory. The analysis of trends necessitates gathering supplemental data, including weather and temperature
conditions, economic activity and gross domestic product, population, atmospheric conditions, and the annual
consumption of electricity, energy, and fossil fuels. Changes in these data are used to explain the trends observed in
greenhouse gas emissions in the United States. Furthermore, specific factors that affect individual sectors are
researched and discussed. Many of the factors that affect emissions are included in the Inventory document as
separate analyses or side discussions in boxes within the text. Text boxes are also created to examine the data
aggregated in different ways than in the remainder of the document, such as a focus on transportation activities or
emissions from electricity generation. The document is prepared to match the specification of the UNFCCC
reporting guidelines for National Inventory Reports.
Common Reporting Format Table Compilation
The CRF tables are compiled from individual tables completed by each individual source lead, which contain source
emissions and activity data. The Inventory coordinator integrates the source data into the complete CRF tables for
the United States, assuring consistency across all sectoral tables. The summary reports for emissions, methods, and
emission factors used, the overview tables for completeness and quality of estimates, the recalculation tables, the
notation key completion tables, and the emission trends tables are then completed by the Inventory coordinator.
Internal automated quality checks on the CRF tables, as well as reviews by the source leads, are completed for the
entire time series of CRF tables before submission.
QA/QC and Uncertainty
QA/QC and uncertainty analyses are supervised by the QA/QC coordinator, who has general oversight over the
implementation of the QA/QC plan and the overall uncertainty analysis for the Inventory (see sections on QA/QC
and Uncertainty, below). The QA/QC coordinator works closely with the source leads to ensure a consistent
QA/QC plan and uncertainty analysis is implemented across all inventory sources. The inventory QA/QC plan,
detailed in a following section, is consistent with the quality assurance procedures outlined by EPA.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 11
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Expert and Public Review Periods
During the Expert Review period, a first draft of the document is sent to a select list of technical experts outside of
EPA. The purpose of the Expert Review is to encourage feedback on the methodological and data sources used in
the current Inventory, especially for sources which have experienced any changes since the previous Inventory.
Once comments are received and addressed, a second draft of the document is released for public review by
publishing a notice in the U.S. Federal Register and posting the document on the EPA Web site. The Public Review
period allows for a 30 day comment period and is open to the entire U.S. public.
Final Submittal to UNFCCC and Document Printing
After the final revisions to incorporate any comments from the Expert Review and Public Review periods, EPA
prepares the final National Inventory Report and the accompanying Common Reporting Format Tables. The U.S.
Department of State sends the official submission of the U.S. Inventory to the UNFCCC. The document is then
formatted for printing, posted online, printed by the U.S. Government Printing Office, and made available for the
general public.
1.4. Methodology and Data Sources
Emissions of greenhouse gases from various source and sink categories have been estimated using methodologies
that are consistent with the Revised 1996IPCC Guidelines for National Greenhouse Gas Inventories
(IPCC/UNEP/OECD/IEA 1997). 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.
The IPCC methodologies provided in the Revised 1996 IPCC Guidelines represent baseline methodologies for a
variety of source categories, and many of these methodologies continue to be improved and refined as new research
and data become available. This report uses the IPCC methodologies when applicable, and supplements them with
other available methodologies and data where possible. Choices made regarding the methodologies and data
sources used are provided in conjunction with the discussion of each source category in the main body of the report.
Complete documentation is provided in the annexes on the detailed methodologies and data sources utilized in the
calculation of each source category.
[Begin Text Box]
Box 1-2: IPCC Good Practice Guidance
In response to a request by Parties in 1998 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 (IPCC Good Practice Guidance), was developed with extensive participation of experts from the
United States and many other countries.19 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, the IPCC
Good Practice Guidance was designed as a tool to complement the methodologies suggested in the Revised 1996
IPCC Guidelines for National Greenhouse Gas Inventories (IPCC Guidelines).
See
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 12
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In order to obtain these goals, IPCC Good Practice Guidance 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 most source categories
By providing such direction, the IPCC hopes to help countries provide inventories that are transparent, documented,
and comparable.
In addition, the IPCC accepted the Land Use, Land-Use Change, and Forestry (LULUCF) Good Practice Guidance
report in 2003, and the United States has implemented the new guidance in this Inventory submission.
[End Box]
The UNFCCC reporting guidelines require countries to complete a "top-down" reference approach for estimating
CO2 emissions from fossil fuel combustion in addition to their "bottom-up" sectoral methodology. This estimation
method uses alternative methodologies and different data sources than those contained in that section of the Energy
chapter. The reference approach 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 4).
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.
1.5. Key Sources
The IPCC's Good Practice Guidance (IPCC 2000) defines a key source category as a "[source category] that is
prioritized within the national inventory system because its estimate has a significant influence on a country's total
inventory of direct greenhouse gases in terms of the absolute level of emissions, the trend in emissions, or both."20
By definition, key source categories include those sources that have the greatest contribution to the absolute level of
national emissions. In addition, when an entire time series of emission estimates is prepared, a thorough
investigation of key source categories must also account for the influence of trends of individual source categories.
Therefore, a trend assessment is conducted to identify source categories for which significant uncertainty in the
estimate would have considerable effects on overall emission trends. This analysis culls out source categories that
diverge from the overall trend in national emissions. Finally, a qualitative evaluation of key source categories is
performed to capture any categories that were not identified in either of the quantitative analyses.
A Tier 1 approach, as defined in the IPCC's Good Practice Guidance (IPCC 2000), was implemented to identify the
key source categories for the United States. Using this approach, a number of key source categories were identified
based on an assessment of their absolute emission level and/or trend in emissions.
Due to the relative quantity of CO2 emissions from fossil fuel combustion—particularly from mobile combustion in
road vehicles and stationary combustion of coal, gas, and oil—these sources contributed most to this year's level
assessment. Additionally, the following sources were identified as key sources based on the level assessments for
each year (listed in descending order of their 2003 emissions):
20 See chapter 7 "Methodological Choice and Recalculation" in IPCC (2000).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 13
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• CO2 emissions from mobile combustion in the aviation sector;
• Direct N2O from agricultural soils;
• CH4 from solid waste disposal sites;
• Fugitive emissions from natural gas operations;
• CO2 from non-energy use of fuel;
• CH4 from enteric fermentation in domestic livestock;
• Indirect N2O emissions from nitrogen used in agriculture;
• Fugitive emissions from coal mining;
• CO2 emissions from iron and steel production;
• CO2 emissions from cement production; and
• N2O emissions from mobile combustion in road vehicles.
The remaining key sources identified under the level assessment varied by year. The following five source
categories were determined to be key using the level assessment for only part of the complete time series (listed in
descending order of their 2003 emissions):
• HFC and PFC emissions from substitutes for ozone depleting substances (1996-2003);
• CO2 emissions from mobile combustion in the marine sector (1990-1997, 1999-2003);
• CH4 emissions from manure management (1990-2000);
• CH4 emissions from wastewater handling (1995 and 1997); and
• HFC-23 emissions from HCFC-22 manufacture (1990-1996, 1998).
Although other sources have fluctuated by greater percentages since 1990, by virtue of their size, CO2 emissions
from mobile combustion from road vehicles and stationary combustion of coal are the greatest contributors to the
overall trend for 2003. The third largest contributor to the overall trend in 2003 is emissions from substitutes for
ozone depleting substances (ODSs). These emissions have grown quickly with the phase out of ODSs under the
Montreal Protocol.
Two additional source categories with trends of note are fugitive emissions from coal mining and PFC emissions
from aluminum manufacturing, which decreased from 1990 through 2003 by approximately 34 and 79 percent,
respectively. Reductions in emissions from coal mining are primarily due to EPA's voluntary coalbed methane
capture program and the mining of less gassy coal than in previous years. PFC emissions have decreased primarily
as a result of emission reduction activities by the aluminum industry.
The remaining source categories that were identified as key sources based solely on a trend assessment are listed
below (listed in descending order of their 2003 emissions).
• CO2 emissions from waste incineration;
• Fugitive emissions from oil operations;
• CO2 emissions from ammonia production and urea application;
• SF6 emissions from electrical equipment; and
• N2O emissions from adipic acid production.
In addition to conducting Tier 1 level and trend assessments, a qualitative assessment of the source categories, as
described in the IPCC's Good Practice Guidance (IPCC 2000), was conducted to capture any key sources that were
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 14
-------
not identified by either quantitative method. One additional key source was identified using this qualitative
assessment. A brief discussion of the reasoning for the qualitative designation is provided below.
• International bunker fuels are fuels consumed for aviation or marine international transport activities, and
emissions from these fuels are reported separately from totals in accordance with IPCC guidelines. If these
emissions were included in the totals, bunker fuels would qualify as a key source according to the Tier 1
approach. The amount of uncertainty associated with estimation of emissions from international bunker fuels
also supports the qualification of this source category as key.
Table 1 -6 presents the key source categories for the United States based on the Tier 1 approach using emissions data
in this report, and ranked according to their sector and global warming potential-weighted emissions in 2003. The
table also indicates the criteria used in identifying these source categories (i.e., level, trend, and/or qualitative
assessments). Please see Annex 1 for additional information regarding the key source categories in the United
States and the methodologies used to identify them.
Table 1-6: Key Source Categories for the United States (1990-2003) Based on Tier 1 Approach
IPCC Source Categories
Energy
CO2 Emissions from Stationary Combustion - Coal
Mobile Combustion: Road & Other
CO2 Emissions from Stationary Combustion - Gas
CO2 Emissions from Stationary Combustion - Oil
Mobile Combustion: Aviation
Fugitive Emissions from Natural Gas Operations
CO2 Emissions from Non-Energy Use of Fuels
International Bunker Fuelsb
Mobile Combustion: Marine
Fugitive Emissions from Coal Mining and Handling
Mobile Combustion: Road & Other
Fugitive Emissions from Oil Operations
Industrial Processes
Emissions from Substitutes for Ozone Depleting Substances
CO2 Emissions from Iron and Steel Production
CO2 Emissions from Cement Production
CO2 Emissions from Ammonia Production and Urea
Application
SF6 Emissions from Electrical Equipment
HFC-23 Emissions from HCFC-22 Manufacture
N2O Emissions from Adipic Acid Production
PFC Emissions from Aluminum Production
Agriculture
Direct N2O Emissions from Agricultural Soils
CH4 Emissions from Enteric Fermentation in Domestic
Livestock
Indirect N2O Emissions from Nitrogen Used in Agriculture
CH4 Emissions from Manure Management
Waste
CH4 Emissions from Solid Waste Disposal Sites
CH4 Emissions from Wastewater Handling
Gas Level
CO2 S
CO2 S
CO2 /
CO2 S
C02 ^
CH4 S
C02 ^
Several
CO2 S
CH4 /
N2O S
CH4
Several S
C02 ^
CO2 S
C02
SF6
HFCs ^
N2O
PFCs
N2O S
CH4 ^
N2O S
CH4 ^
CH4 ^
CH4 ^
2003 Emissions
Trend Quala (Tg CO2 Eq.)
S 2,013.8
S 1,538.5
/ 1,134.9
S 635.3
^ 171.3
S 125.9
118.0
^ 85,1
57.5
/ 53.8
S 39.9
^ 17.1
^ 99.5
^ 53.8
^ 43.0
^ 15.6
' 14.1
^ 12.3
/ 6.0
^ 3.8
155.3
^ 115.0
^ 98.2
39.1
^ 131,2
S 36.8
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 15
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CO2 Emissions from Waste Incineration CO2 £ 18.8
Subtotal of Key Source Emissions 6,833.5
Total Emissions 6,900.2
Percent of Total 99.0%
a Qualitative criteria.
bEmissions from these sources not included in totals.
Note: Sinks (e.g., LUCF, Landfill Carbon Storage) are not included in this analysis. The Tier 1 approach for identifying key
source categories does not directly include an assessment of uncertainty in emission estimates.
1.6. Quality Assurance and Quality Control
As part of efforts to achieve its stated goals for inventory quality, transparency, and credibility, the United States
has developed a quality assurance and quality control plan designed to check, document and improve the quality of
its inventory over time. QA/QC activities on the Inventory are undertaken within the framework of the U.S.
QA/QC plan, Quality Assurance/Quality Control and Uncertainty Management Plan for the U.S. Greenhouse Gas
Inventory: Procedures Manual for QA/QC and Uncertainty Analysis.
In particular, key attributes of the QA/QC plan include:
• The plan includes specific detailed procedures (or protocols) and templates (or forms) that serve to standardize
the process of documenting and archiving information, as well as to guide the implementation of QA/QC and
the analysis of the uncertainty of the inventory estimates.
• The plan includes expert review as well as QC—for both the inventory estimates and the Inventory (which is
the primary vehicle for disseminating the results of the inventory development process). In addition, the plan
provides for public review of the Inventory.
• The QC process includes both Tier 1 (general) and Tier 2 (source-specific) quality controls and checks, as
recommended by IPCC Good Practice Guidance.
• Investigations of secondary data quality and source-specific quality checks (Tier 2 QC) are considered in
parallel and coordination with the uncertainty assessment; the development of protocols and templates provides
for more structured communication and integration with the suppliers of secondary information.
• The plan contains record-keeping provisions to track what procedures have been followed, and the results of
the QA/QC and uncertainty analysis, and contains feedback mechanisms for corrective action based on the
results of the investigations, thereby providing for continual data quality improvement and guided research
efforts.
• The plan is designed so that QA/QC procedures are implemented throughout the whole inventory development
process—from initial data collection, through preparation of the emission estimates, to publication of the
Inventory.
• The plan includes a schedule for multi-year implementation.
• The plan promotes and involves coordination and interaction within the EPA, across Federal agencies and
departments, state government programs, and research institutions and consulting firms involved in supplying
data or preparing estimates for the inventory. The QA/QC plan itself is intended to be revised and reflect new
information that becomes available as the program develops, methods are improved, or additional supporting
documents become necessary. For example, the availability of new information or additional detail on
techniques or procedures for checking the quality of data inputs or emission calculations could necessitate
revising the procedures in the Procedures Manual or preparing a background paper expanding on procedures to
be used.
The quality checking and control activities described in the U.S. QA/QC plan occur throughout the inventory
process; QA/QC is not separate from, but is an integral part of, preparing the inventory. Quality control—in the
form of both good practices (such as documentation procedures) and checks on whether good practices and
procedures are being followed—is applied at every stage of inventory development and document preparation. In
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 16
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addition, quality assurance occurs at two stages—an expert review and a public review. While both phases can
significantly contribute to inventory quality, the public review phase is also essential for promoting the openness of
the inventory development process and the transparency of the inventory data and methods.
QA/QC procedures guide the process of ensuring inventory quality by describing data and methodology checks,
developing processes governing peer review and public comments, and developing guidance on conducting an
analysis of the uncertainty surrounding the emission estimates. The QA/QC procedures also include feedback loops
and provide for corrective actions that are designed to improve the inventory estimates over time.
In addition, based on the national QA/QC plan for the Inventory, source-specific QA/QC plans have been developed
for a limited number of sources. These plans follow the procedures outlined in the national QA/QC plan, tailoring
the procedures to the specific text and spreadsheets of the individual sources. For the current Inventory, source-
specific plans have been developed and implemented for the majority of sources within the Energy and Industrial
Process sectors.
Throughout this Inventory, a minimum of a Tier 1 QA/QC analysis has been undertaken. Where QA/QC activities
for a particular source go beyond the minimum Tier 1 level, further explanation is provided within the respective
source category text.
1.7. Uncertainty Analysis of Emission Estimates
Uncertainty estimates are an essential element of a complete and transparent emissions inventory. Uncertainty
information is not intended to dispute the validity of the inventory estimates, but to help prioritize efforts to improve
the accuracy of future inventories and guide future decisions on methodological choice. While the U.S. Inventory
calculates its emission estimates with the highest possible accuracy, uncertainties are associated to a varying degree
with the development of emission estimates for any inventory. Some of the current estimates, such as those for CO2
emissions from energy-related activities and cement processing, are considered to have minimal uncertainty
associated with them. For some other categories of emissions, however, a lack of data or an incomplete
understanding of how emissions are generated increases the uncertainty surrounding 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/IEA 1997) and require that
countnes provide single point estimates of uncertainty for each gas and emission or removal source category.
Within the discussion of each emission source, specific factors affecting the uncertainty associated with the
estimates are discussed.
Additional research in the following areas could help reduce uncertainty in the U.S. Inventory:
• Incorporating excluded emission sources. Quantitative estimates for 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 5 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.
The IPCC provides good practice guidance on two approaches—Tier 1 and Tier 2—to estimating uncertainty for
individual source categories. The Tier 1 method is a spreadsheet-based analysis that estimates uncertainties by
using the error propagation equation. The spreadsheet employs uncertainty ranges for activity data and emission
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 17
-------
factors consistent with the sectoral good practice guidance. The Tier 2 uncertainty estimation methodology employs
the Monte Carlo Stochastic Simulation technique. The principle of Monte Carlo analysis is to select random values
of emission factor and activity data from within their individual probability density functions, and to calculate the
corresponding emission values. Tier 2 uncertainty analysis was applied wherever data and resources permitted.
Consistent with the Good Practice Guidance, over a multi-year timeframe, the United States expects to continue to
improve the uncertainty estimates presented in this report and add quantitative estimates of uncertainty where none
currently exist. See Annex 7, Uncertainty, of this report for further details on the U.S. process for estimating
uncertainties associated with emission estimates and for a more detailed discussion of the limitations of the current
analysis and plans for improvement.
While there are two types of estimation uncertainty, parameter uncertainty and model uncertainty, the Tier 1 and
Tier 2 approaches were applied only to estimate parameter uncertainty of emission estimates. Parameter uncertainty
refers to the uncertainty associated with quantifying the parameters used as inputs (e.g., activity data and emission
factors) to the emission estimation models. Model uncertainty refers to the uncertainty associated with developing
mathematical equations or models to characterize the emission and/or removal processes. Model uncertainties can
be evaluated by comparing the model results with the results of other models that are developed to characterize the
same emission generation process and through sensitivity analysis. Model uncertainties for some sources are
identified, but not evaluated.
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.
1.8. Completeness
This report, along with its accompanying CRF tables, serves as a thorough assessment of the anthropogenic sources
and sinks of greenhouse gas emissions for the United States for the time series 1990 through 2003. Although this
report is intended to be comprehensive, certain sources have been identified yet excluded from the estimates
presented for various reasons. Generally speaking, sources not accounted for in this Inventory are excluded due to
data limitations or a lack of thorough understanding of the emission process. The United States is continually
working to improve upon the understanding of such sources and seeking to find the data required to estimate related
emissions. As such improvements are made, new emission sources are quantified and included in the Inventory.
For a complete list of sources excluded, see Annex 5.
1.9. Organization of Report
In accordance with the Revised 1996IPCC Guidelines for National Greenhouse Gas Inventories
(IPCC/UNEP/OECD/IEA 1997), and the 2003 UNFCCC Guidelines on Reporting and Review (UNFCCC 2003),
this Inventory of U.S. Greenhouse Gas Emissions and Sinks is segregated into six sector-specific chapters, listed
below in Table 1-7. In addition, chapters on Trends in Greenhouse Gas Emissions and Other information to be
considered as part of the U.S. Inventory submission are included.
Table 1-7: IPCC Sector Descriptions
Chapter/IPCC Sector Activities Included
Energy Emissions of all greenhouse gases resulting from stationary and mobile
energy activities including fuel combustion and fugitive fuel emissions.
Industrial Processes By-product or fugitive emissions of greenhouse gases from industrial
processes not directly related to energy activities such as fossil fuel
combustion.
Solvent and Other Product Use Emissions, of primarily NMVOCs, resulting from the use of solvents
and N2O from product usage.
Agriculture Anthropogenic emissions from agricultural activities except fuel
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 18
-------
combustion, which is addressed under Energy.
Land-Use Change and Forestry Emissions and removals of CO2 from forest management, other land-
use activities, and land-use change.
Waste Emissions from waste management activities.
Source: (IPCC/UNEP/OECD/IEA 1997)
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 and identification of
data references, primarily for activity data and emission factors.
Uncertainty: A discussion and quantification of the uncertainty in emission estimates and a discussion of time-
series consistency.
QA/QC and Verification: A discussion on steps taken to QA/QC and verify the emission estimates, where beyond
the overall U.S. QA/QC plan, and any key findings.
Recalculations: A discussion of any data or methodological changes necessitating a recalculation of previous
years' emission estimates, and the impact of the recalculation on the emission estimates, if applicable.
Planned Improvements: A discussion on any source-specific planned improvements, if applicable.
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, is described individually. Additional information for certain source categories and other topics is
also provided in several Annexes listed in Table 1-8.
Table 1-8: List of Annexes
ANNEX 1 Key Source Analysis
ANNEX 2 Methodology and Data for Estimating CO2 Emissions from Fossil Fuel Combustion
2.1. Methodology for Estimating Emissions of CO2 from Fossil Fuel Combustion
2.2. Methodology for Estimating the Carbon Content of Fossil Fuels
2.3. Methodology for Estimating Carbon Stored in Products from Non-Energy Uses of Fossil Fuels
ANNEX 3 Methodological Descriptions for Additional Source or Sink Categories
3.1. Methodology for Estimating Emissions of CH4, N2O, and Ambient Air Pollutants from Stationary Combustion
3.2. Methodology for Estimating Emissions of CH4, N2O, and Ambient Air Pollutants from Mobile Combustion and
Methodology for and Supplemental Information on Transportation-Related Greenhouse Gas Emissions
3.3. Methodology for Estimating CH4 Emissions from Coal Mining
3.4. Methodology for Estimating CH4 Emissions from Natural Gas Systems
3.5. Methodology for Estimating CH4 Emissions from Petroleum Systems
3.6. Methodology for Estimating CO2 and N2O Emissions from Municipal Solid Waste Combustion
3.7. Methodology for Estimating Emissions from International Bunker Fuels used by the U.S. Military
3.8. Methodology for Estimating HFC and PFC Emissions from Substitution of Ozone Depleting Substances
3.9. Methodology for Estimating CH4 Emissions from Enteric Fermentation
3.10. Methodology for Estimating CH4 and N2O Emissions from Manure Management
3.11. Methodology for Estimating N2O Emissions from Agricultural Soil Management
3.12. Methodology for Estimating Net Carbon Stock Changes in Forest Carbon Stocks
3.13. Methodology for Estimating Net Changes in Carbon Stocks in Mineral and Organic Soils
3.14. Methodology for Estimating CH4 Emissions from Landfills
ANNEX 4 IPCC Reference Approach for Estimating CO2 Emissions from Fossil Fuel Combustion
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 19
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ANNEX 5 Assessment of the Sources and Sinks of Greenhouse Gas Emissions Excluded
ANNEX 6 Additional Information
6.1. Global Warming Potential Values
6.2. Ozone Depleting Substance Emissions
6.3. Sulfur Dioxide Emissions
6.4. Complete List of Source Categories
6.5. Constants, Units, and Conversions
6.6. Abbreviations
6.7. Chemical Formulas
6.8. Glossary
ANNEX 7 Uncertainty
7.1. Overview
7.2. Methodology and Results
7.3. Uncertainty Estimation as a Process
7.4. Planned Improvements
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 20
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2. Trends in Greenhouse Gas Emissions
2.1. Recent Trends in U.S. Greenhouse Gas Emissions
In 2003, total U.S. greenhouse gas emissions were 6,900.2 teragrams of carbon dioxide equivalent (Tg CO2 Eq.)1
(13.3 percent above 1990 emissions). Emissions rose slightly from 2002 to 2003, increasing by 0.6 percent (42.2
Tg CO2 Eq.). The following factors were primary contributors to this increase: 1) moderate economic growth in
2003, leading to increased demand for electricity and fossil fuels, 2) increased natural gas prices, causing some
electric power producers to switch to burning coal, and 3) a colder winter, which caused an increase in the use of
heating fuels, primarily in the residential sector. (See the following section for an analysis of emission trends by
general economic sectors.) Figure 2-1 through Figure 2-3 illustrate the overall trends in total U.S. emissions by gas,
annual changes, and absolute changes since 1990.
Figure 2-1: U.S. Greenhouse Gas Emissions by Gas
Figure 2-2: Annual Percent Change in U.S. Greenhouse Gas Emissions
Figure 2-3: Cumulative Change in U.S. Greenhouse Gas Emissions Relative to 1990
As the largest source of U.S. greenhouse gas emissions, carbon dioxide (CO2) from fossil fuel combustion has
accounted for a nearly constant 80 percent of global warming potential (GWP) weighted emissions since 1990.
Emissions from this source category grew by 17.8 percent (839.8 Tg CO2Eq.) from 1990 to 2003 and were
responsible for most of the increase in national emissions during this period. From 2002 to 2003, these emissions
increased by 50.2 Tg CO2 Eq. (0.9 percent), the same rate as the source's average annual growth rate of 1.3 percent
from 1990 through 2003. 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 pnces, 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).
1 Estimates are presented in units of teragrams of carbon dioxide equivalent (Tg CO2 Eq.), which weight each gas by its Global
Warming Potential, or GWP, value. (See section on Global Warming Potentials, Chapter 1.)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 21
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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 2-1 shows annual changes in emissions during the last six years for
coal, petroleum, and natural gas in selected sectors.
Table 2-1: Annual Change in CO2 Emissions from Fossil Fuel Combustion for Selected Fuels and Sectors (Tg CO2
Eq, and Percent)
Sector
Electricity Generation
Electricity Generation
Electricity Generation
Transportation3
Residential
Commercial
Industrial
Industrial
All Sectors'1
Fuel Type
Coal
Natural Gas
Petroleum
Petroleum
Natural Gas
Natural Gas
Coal
Natural Gas
All Fuelsb
1999 to 2000
87.6
20.8
-5.6
47.0
13.9
7.1
1.1
8.2
199.2
5%
8%
-6%
3%
5%
4%
1%
2%
4%
2000 to
-62
8
9
-16
-10
-7
-4
-38
-97
.6
.4
.8
.4
.7
.9
.4
.5
.1
2001
-3%
3%
11%
-1%
-4%
-5%
-3%
-8%
-2%
2001 to 2002
22
16
-23
29
6
4
-7
9
53
.2
.5
.5
.4
.2
.2
.9
.5
.5
1%
6%
-23%
2%
2%
3%
-6%
2%
1%
2002 to
36.6
-28.0
18.9
16.6
11.5
2.0
0.8
-27.6
50.2
2003
2%
-9%
24%
1%
4%
1%
1%
-6%
1%
a Excludes emissions from International Bunker Fuels.
b Includes fuels and sectors not shown in table.
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.2 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. Additionally,
electricity generation became more carbon intensive as coal and natural gas consumption offset reduced hydropower
output.
In 2001, economic growth in the United States 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 a very high capacity, 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.
Emissions from fuel combustion resumed a modest growth in 2002, slightly less than the average annual growth rate
since 1990. There were a number of reasons behind this increase. The U.S. economy experienced moderate
growth, recovering from weak conditions in 2001. Prices for fuels remained at or below 2001 levels; the cost of
natural gas, motor gasoline, and electricity were all lower-triggering an increase in demand for fuel. In addition, the
United States experienced one of the hottest summers on record, causing a significant increase in electricity use in
2 Normals are based on data from 1971 through 2000. Source: EIA (2004b)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 22
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the residential sector as the use of air-conditioners increased. Partially offsetting this increased consumption of
fossil fuels, however, were increases in the use of nuclear and renewable fuels. Nuclear facilities operated at the
highest capacity on record in 2002. Furthermore, there was a considerable increase in the use of hydroelectric
power in 2002 after a very low output the previous year.
Emissions from fuel combustion continued growing in 2003, at about the average annual growth rate since 1990. A
number of factors played a major role in the magnitude of this increase. The U.S. economy experienced moderate
growth from 2002, causing an increase in the demand for fuels. The price of natural gas escalated dramatically,
causing some electric power producers to switch to coal, which remained at relatively stable prices. Colder winter
conditions brought on more demand for heating fuels, primarily in the residential sector. Though a cooler summer
partially offset demand for electricity as the use of air-conditioners decreased, electricity consumption continued to
increase in 2003. The primary drivers behind this trend were the growing economy and the increase in U.S. housing
stock. Use of nuclear and renewable fuels remained relatively stable. Nuclear capacity decreased slightly, and for
the first time since 1997. Use of renewable fuels rose slightly due to increases in the use of hydroelectric power and
biofuels.
Other significant trends in emissions from additional source categories over the fourteen-year period from 1990
through 2003 included the following:
• Carbon dioxide emissions from waste combustion increased by 7.9 Tg CO2 Eq. (72 percent), as the volume of
plastics and other fossil carbon-containing materials in municipal solid waste grew.
• Net CO2 sequestration from land use change and forestry decreased by 214.0 Tg CO2 Eq. (21 percent),
primarily due to a decline in the rate of net carbon accumulation in forest carbon stocks. This decline largely
resulted from a decrease in the estimated rate of forest soil sequestration caused by a slowing rate of increase in
forest area after 1997.
• Methane (CH4) emissions from coal mining declined by 28.1 Tg CO2 Eq. (34 percent) from 1990 to 2003, as a
result of the mining of less gassy coal from underground mines and the increased use of methane collected from
degasification systems.
• The increase in ODS emissions is offset substantially by decreases in emission of HFCs, PFCs, and SF6 from
other sources. Emissions from aluminum production decreased by 79 percent (14.5 Tg CO2 Eq.) from 1990 to
2003, due to both industry emission reduction efforts and lower domestic aluminum production. Emissions
from the production of HCFC-22 decreased by 65 percent (22.6 Tg CO2 Eq.) from 1990 to 2003, due to a
steady decline in the emission rate of HFC-23 (i.e., the amount of HFC-23 emitted per kilogram of HCFC-22
manufactured) and the use of thermal oxidation at some plants to reduce HFC-23 emissions. Emissions from
electric power transmission and distribution systems decreased by 52 percent (15.1 Tg CO2 Eq.) from 1990 to
2003, primarily because of higher purchase prices for SF6 and efforts by industry to reduce emissions.
Overall, from 1990 to 2003, total emissions of CO2 increased by 832.0 Tg CO2 Eq. (17 percent), while CH4 and
N2O emissions decreased by 60.4 Tg CO2 Eq. (10 percent) and 5.2 Tg CO2 Eq. (just over 1 percent), respectively.
During the same period, aggregate weighted emissions of HFCs, PFCs, and SF6 rose by 45.8 Tg CO2 Eq. (50
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 2003.
[BEGIN BOX]
Box 2-1: 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
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 23
-------
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 2003; 4) emissions per unit of total gross domestic product as a measure of national economic activity;
or 5) emissions per capita.
Table 2-2 provides data on various statistics related to U.S. greenhouse gas emissions normalized to 1990 as a
baseline year. Greenhouse gas emissions in the United States have grown at an average annual rate of 1.0 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. Total U.S. greenhouse gas emissions have also
grown more slowly than national population since 1990 (see Figure 2-4). Overall, global atmospheric CO2
concentrations—a function of many complex anthropogenic and natural processes—are increasing at 0.5 percent
per year.
Table 2-2: Recent Trends in Various U.S. Data (Index 1990 = 100) and Global Atmospheric CO2 Concentration
SfJ Growth
Variable 1991 ||j 1997 1998 1999 2000 2001 2002 2003 Ratef
Greenhouse Gas Emissions3
Energy Consumption15
Fossil Fuel Consumption15
Electricity Consumption15
GDPC
Population"1
Atmospheric CO2 Concentration6
99ifeV
100 if
99|;1*
102 it
looll-
101 [M
100 is
110
112
112
117
122
109
103
110
113
113
121
127
110
104
111
114
114
124
133
112
104
114
117
117
128
138
113
104
112
114
115
125
139
114
105
113
116
116
129
142
115
105
113
116
116
130
146
116
106
1.0%
1.2%
1.2%
2.1%
3.0%
1.1%
0.5%
a GWP weighted values
b Energy content weighted values (EIA 2004a)
0 Gross Domestic Product in chained 2000 dollars (BEA 2004)
d (U.S. Census Bureau 2004)
e Mauna Loa Observatory, Hawaii (Keeling and Whorf 2004)
f Average annual growth rate
Figure 2-4: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product
Source: BEA (2004), U.S. Census Bureau (2004), and emission estimates in this report.
[END BOX]
As an alternative, emissions of all gases can be totaled for each of the IPCC sectors. Over the thirteen year period
of 1990 to 2003, total emissions in the Energy, Industnal Processes, Agriculture, and Solvent and Other Product
Use sectors climbed by 821.6Tg CO2 Eq. (16 percent), 8.7 Tg CO2Eq. (3 percent), 6.8 Tg CO2Eq. (2 percent), and
0.5 Tg CO2 Eq. (11 percent), respectively, while emissions from the Waste sector decreased 26.3 Tg CO2Eq. (13
percent). Over the same period, estimates of net carbon sequestration in the Land-Use Change and Forestry sector
declined by 214.8 Tg CO2Eq. (21 percent).
Table 2-3 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 2-4. Alternatively, emissions
and sinks are aggregated by chapter in Table 2-5 and Figure 2-5.
Table 2-3: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq.)
Gas/Source
C02
Fossil Fuel Combustion
Non-Energy Use of Fuels
Iron and Steel Production
Cement Manufacture
1990
5,009.6
4,711 7
1080
854
33 3
1997
',; 5,580.0
, 5,263.2
";.-, 120.3
,v 71.9
f/" 38.3
1998
5,607.2
5,278.7
135.4
67.4
39.2
1999
5,678.0
5,345.9
141.6
64.4
40.0
2000
5,858.2
5,545.1
124.7
65.7
41.2
2001
5,744.8
5,448.0
120.1
58.9
41.4
2002
5,796.8
5,501.4
118.8
55.1
42.9
2003
5,841.5
5,551.6
118.0
53.8
43.0
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 24
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Waste Combustion
Ammonia Production and Urea
Application
Lime Manufacture
Natural Gas Flaring
Limestone and Dolomite Use
Aluminum Production
Soda Ash Manufacture and
Consumption
Petrochemical Production
Titanium Dioxide Production
Phosphoric Acid Production
Ferroalloys
Carbon Dioxide Consumption
Land-Use Change and Forestry
(Sinks)"
International Bunker Fuelsb
Biomass Combustionb
CH4
Landfills
Natural Gas Systems
Enteric Fermentation
Coal Mining
Manure Management
Wastewater Treatment
Petroleum Systems
Rice Cultivation
Stationary Sources
Abandoned Coal Mines
Mobile Sources
Petrochemical Production
Iron and Steel Production
Agricultural Residue Burning
Silicon Carbide Production
International Bunker Fuelsb
N2O
Agricultural Soil Management
Mobile Sources
Manure Management
Human Sewage
Nitric Acid
Stationary Sources
Settlements Remaining
Settlements
Adipic Acid
N2O Product Usage
Waste Combustion
Agricultural Residue Burning
Forest Land Remaining Forest
Land
International Bunker Fuelsb
HFCs, PFCs, and SF6
Substitution of Ozone Depleting
Substances
109 ?; 17.8
\ '
193
11 2
58
5 5
63
4 1
22
1 3
1 5
20
09
(1,042.0)
113.5
216.7
605.3
1722
1283
117,9
81 9
31 2
248
200
7 1
78
6 1
48
1 2
1 3
07
+
0.2
382.0
2530
437
163
130
178
123
55
152
43
04
04
0 1
1.0
91.2
'••- 20.7
;•:', 13.7
:,'' 7.9
':': 7.2
r 5.6
T'
» i
:„•' 4.4
<;, 2.9
;•'• 1.8
;*; 1-5
:„-' 2.0
,'"';. 0.8
.;•;
;*; (930.0)
;.' 109.9
,'"?, 233.2
r 579.5
;':; 147.4
r-' 133.6
,'"'; ii8,3
62.6
i':; 36.4
r; 31.7
,v 18.8
7.5
;:; 7.4
r; 8. 1
,v 4.0
\- 1.6
'»", 1.3
r;' 0.8
+
^ o.i
'•>, 396.3
"C 252.0
\ '
55.2
;'"•' 17.3
';'>, 14.7
T, 21.2
{•; 13.5
'; ,
'•">, 6.1
';-, 10.3
4.8
;v 0.4
M 0.4
M
0.3
r, i.o
';' 121.7
'"';,'
04 '^ 46.5
17.1
21.9
13.9
6.6
7.4
5.8
4.3
3.0
1.8
1.6
2.0
0.9
(881.0)
114.6
217.2
569.1
138.5
131.8
116,7
62.8
38.8
32.6
18.5
7.9
6.9
7.2
3.9
1.7
1.2
0.8
+
0.2
407.8
267.7
55.3
17.4
15.0
20.9
13.4
6.1
6.0
4.8
0.3
0.5
0.4
1.0
135.7
56.6
17.6
20.6
13.5
6.9
8.1
5.9
4.2
3.1
1.9
1.5
2.0
0.8
(826.1)
105.3
222.3
557.3
134.0
127.4
116,8
58.9
38.8
33.6
17.8
8.3
7.1
7.3
3.6
1.7
1.2
0.8
+
0.1
382.1
243.4
54.6
17.4
15.4
20.1
13.5
6.2
5.5
4.8
0.3
0.4
0.5
0.9
134.8
65.8
18.0
19.6
13.3
5.8
6.0
5.7
4.2
3.0
1.9
1.4
1.7
1.0
(822.4)
101.4
226.8
554.2
130.7
132.1
115,6
56.2
38.1
34.3
17.6
7.5
7.3
7.7
3.4
1.7
1.2
0.8
+
0.1
401.9
263.9
53.2
17.8
15.6
19.6
14.0
6.0
6.0
4.8
0.4
0.5
0.4
0.9
138.9
75.0
18.8
16.7
12.8
6.1
5.7
4.1
4.1
2.8
1.9
1.3
1.3
0.8
(826.9)
97.9
200.5
546.8
126.2
131.8
114,5
55.6
38.9
34.7
17.4
7.6
6.7
6.9
3.1
1.4
1.1
0.8
+
0.1
385.8
257.1
49.0
18.0
15.6
15.9
13.5
5.8
4.9
4.8
0.4
0.5
0.4
0.9
129.5
83.3
18.8
18.6
12.3
6.2
5.9
4.2
4.1
2.9
2.0
1.3
1.2
1.0
(826.5)
89.5
207.2
542.5
126.8
130.6
114,6
52.4
39.3
35.8
17.1
6.8
6.4
6.4
2.9
1.5
1.0
0.7
+
0.1
380.5
252.6
45.6
17.9
15.7
17.2
13.5
6.0
5.9
4.8
0.5
0.4
0.4
0.8
138.3
91.5
18.8
15.6
13.0
6.0
4.7
4.2
4.1
2.8
2.0
1.4
1.4
1.3
(828.0)
84.2
216.8
545.0
131.2
125.9
115,0
53.8
39.1
36.8
17.1
6.9
6.7
6.4
2.7
1.5
1.0
0.8
+
0.1
376.7
253.5
42.1
17.5
15.9
15.8
13.8
6.0
6.0
4.8
0.5
0.4
0.4
0.8
137.0
99.5
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 25
-------
Electrical Transmission and
Distribution
HCFC-22 Production
Semiconductor Manufacture
Aluminum Production
Magnesium Production and
Processing
Total
Net Emissions (Sources and
Sinks)
29
35
2
18
5
6,088
5,046
.2
.0
.9
^5
.4
.l£
.it
f;
"',"
A! 21
;/? 30
;•'« 6
-;{';• 1 1
'/•?
> 6
# 6,677
•:''•• 5,747
*/,
.7
.0
.3
.0
.3
.5
.5
17.1
40.1
7.1
9.1
5.8
6,719.7
5,838.8
16.4
30.4
7.2
9.0
6.0
6,752.2
5,926.1
15
29
6
9
3
6,953
6,130
.6
.8
.3
.0
.2
.2
.8
15.4
19.8
4.5
4.0
2.6
6,806.9
5,980.1
14.7
19.8
4.4
5.2
2.6
6,858.1
6,031.6
14.1
12.3
4.3
3.8
3.0
6,900.2
6,072.2
+ Does not exceed 0.05 Tg CO2 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 and Biomass Combustion are not included in totals.
Note: Totals may not sum due to independent rounding.
Table 2-4: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg)
Gas/Source
CO2
Fossil Fuel Combustion
Non-Energy Use of
Fuels
Iron and Steel
Production
Cement Manufacture
Waste Combustion
Ammonia Production
and Urea Application
Lime Manufacture
Natural Gas Flaring
Limestone and Dolomite
Use
Aluminum Production
Soda Ash Manufacture
and Consumption
Petrochemical
Production
Titanium Dioxide
Production
Phosphoric Acid
Production
Ferroalloys
Carbon Dioxide
Consumption
Land-Use Change and
Forestry (Sinks)"
International Bunker
Fuelsb
Biomass Combustion
CH4
Landfills
Natural Gas Systems
Enteric Fermentation
Coal Mining
Manure Management
1990
5,009,552 S
4,71 1,741 1
107,965 ;
85,413;
33,278;
10,919;
19,306;
11,238;
5,805 ;
5,533 ;
6,315 =
4,141 =
2,2211
uos;
1,529;
1,980;
860 ;
(1,042,050)1
113,5031
216,7021
28,826 I
8,202 •
6,112-
5,612-
3,900 •
1,485;
1997
^ 5,579,984
:,'. 5,263,164
•v; 120,301
!V,
H-. 71,863
K 38,323
17,761
'\\'
:y. 20,650
;:'!j 13,685
;;/ 7,874
:\',- 7,242
;::? 5,621
;-lf; 4,354
;:-} 2,919
;-lf; 1,836
::-} 1,544
:^r 2,038
iV,- 808
:^r (930,011)
iV- 109,858
::,;? 233,243
X': 27,595
'•'{ 7,017
"f 6,363
:-''; 5,634
'•'•<•'. 2,983
i',/, 1J33
1998
5,607,159
5,278,721
135,352
67,428
39,218
17,094
21,934
13,914
6,566
7,449
5,792
4,325
3,015
1,819
1,593
2,027
912
(880,995)
114,557
217,201
27,100
6,595
6,276
5,557
2,989
1,850
1999
5,677,970
5,345,904
141,583
64,376
39,991
17,632
20,615
13,466
6,943
8,057
5,895
4,217
3,054
1,853
1,539
1,996
849
(826,106)
105,294
222,340
26,537
6,382
6,066
5,561
2,805
1,846
2000
5,858,201
5,545,083
124,714
65,693
41,190
17,979
19,616
13,315
5,769
5,959
5,723
4,181
3,004
1,918
1,382
1,719
957
(822,409)
101,404
226, 765
26,389
6,223
6,289
5,505
2,677
1,813
2001
5,744,782
5,447,969
120,104
58,887
41,357
18,781
16,719
12,823
6,094
5,733
4,114
4,147
2,787
1,857
1,264
1,329
818
(826,879)
97,865
200,477
26,039
6,010
6,277
5,454
2,647
1,853
2002
5,796,757
5,501,427
118,811
55,082
42,898
18,781
18,571
12,304
6,233
5,885
4,220
4,139
2,857
1,997
1,338
1,237
978
(826,483)
89,489
207,249
25,832
6,039
6,221
5,458
2,497
1,873
2003
5,841,504
5,551,580
118,001
53,763
43,030
18,781
15,560
12,983
5,970
4,720
4,219
4,082
2,777
2,013
1,382
1,374
1,267
(828,046)
84,193
216,813
25,950
6,246
5,998
5,475
2,561
1,864
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 26
-------
Wastewater Treatment
Petroleum Systems
Rice Cultivation
Stationary Sources
Abandoned Coal Mines
Mobile Sources
Petrochemical
Production
Iron and Steel
Production
Field Burning of
Agricultural Residues
Silicon Carbide
Production
International Bunker
Fuelsb
N20
Agricultural Soil
Management
Mobile Sources
Manure Management
Human Sewage
Nitric Acid
Stationary Sources
Settlements Remaining
Settlements
Adipic Acid
N2O Product Usage
Waste Combustion
Field Burning of
Agricultural Residues
Forest Land Remaining
Forest Land
International Bunker
Fuelsb
HFCs, PFCs, and SF6
Substitution of Ozone
Depleting Substances
Electrical Transmission
and Distribution11
HCFC-22 Production"
Semiconductor
Manufacture
Aluminum Production
Magnesium Production
and Processing11
SO2
NOX
CO
NMVOCs
1,183
951
339
373
288
228
56
63
33
1
8
1,232
816
141
52
42
58
40
18
49
14
1
1
+
3
M
M
1
3
M
M
+
20,936
22,860
130,580
20,937
;:'u 1,509
>; 895
::'•', 356
;& 351
;:'£; 385
>; 193
'.•ji 78
' \ :
>,' 60
'.'ji 37
' \ :
>;' 1
:'ji 7
'.•'*, 1,278
• "'! «'
:v; 813
'•'$ ns
:? 56
>,' 47
•;./; 68
•:a; 44
' \ :
>,' 20
::.M 33
::a; is
' I:
;:':«'
;:./; i
;:a;
;••'"' i
•;':«'
•:.M s
;S; M
:'•'" M
;!./«
;:a; i
;:.-; 3
'r'!'.f
, •'" ^ N't
,.*-'«, ^/[
::V +
::i; 17,091
::V 22,284
:;;;> 101,138
: : 16,994
1,550
879
376
328
341
185
80
57
38
1
7
1,315
864
179
56
48
67
43
20
19
15
1
1
1
3
M
M
1
3
M
M
+
17,189
21,964
98,984
16,403
1,602
848
395
338
349
172
81
56
37
1
6
1,233
785
176
56
50
65
43
20
18
15
1
1
2
3
M
M
1
3
M
M
+
15,917
20,530
94,361
15,869
1,635
836
357
349
369
161
80
57
38
1
6
1,297
851
171
57
50
63
45
19
19
15
1
1
1
3
M
M
1
3
M
M
+
14,829
20,288
92,895
15,228
1,651
831
364
318
331
147
68
51
37
+
5
1,245
829
158
58
50
51
43
19
16
15
1
1
1
3
M
M
1
2
M
M
+
14,452
19,414
89,329
15,048
1,705
815
325
305
303
138
72
48
34
+
4
1,228
815
147
58
51
56
44
19
19
15
1
1
1
3
M
M
1
2
M
M
+
13,928
18,850
87,451
14,222
1,751
815
328
319
306
128
72
49
38
+
4
1,215
818
136
57
51
51
45
19
19
15
1
1
1
2
M
M
1
1
M
M
+
14,463
18,573
85,077
13,939
+ Does not exceed 0,5 Gg,
M Mixture of multiple gases
a Sinks are not included in CO2
Emissions from International
0 HFC-23 emitted
emissions total, and are based partially on projected activity data.
Bunker Fuels and Biomass Combustion are not included in totals.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 27
-------
d SF6 emitted
Note: Totals may not sum due to independent rounding.
Note: Parentheses indicate negative values (or sequestration).
Figure 2-5: U.S. Greenhouse Gas Emissions by Chapter/IPCC Sector
Table 2-5: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg CO2 Eq.)
Chapter/IPCC Sector 1990
Energy 5,141.7
Industrial Processes 299.9
Solvent and Other Product Use 4. 3
Agriculture 426.5
Land-Use Change and Forestry (Emissions) 5.6
Waste 210.1
Total 6,088.1
Land-Use Change and Forestry (Sinks) (1042.0)
Net Emissions (Sources and Sinks) 5,046.1
* Sinks are only included in net emissions total, and are based
Note: Totals may not sum due to independent rounding.
Note: Parentheses indicate negative values (or sequestration).
$ 1997
>' 5,712.8
i? 327.1
T 4'8
':-; 432.8
% 6.4
.;;' 193.7
•I]' 6,677.5
|; (930.0)
'X 5,747.5
partially on
1998
5,737.7
334.9
4.8
449.8
6.5
186.0
6,719.7
(881.0)
5,838.8
1999
5
6
,802
329
4
425
6
183
,752
(826.
5
,926
.6
.2
.8
.9
.6
.1
.2
1)
.1
5
2000
,985.3
332.1
4.8
444.1
6.3
180.6
6,953.2
(822.4)
6
,130.8
2001
5,877.3
304.7
4.8
437.5
6.2
176.5
6,806.9
(826.9)
5,980.1
2002
5,920
315
4
432
6
178
6,858
(826.
6,031
.7
.4
.8
.4
.4
.3
.1
5)
.6
2003
5,963.4
308.6
4.8
433.3
6.4
183.8
6,900.2
(828.0)
6,072.2
projected activity data.
Energy
Energy-related activities, primarily fossil fuel combustion, accounted for the vast majority of U.S. CO2 emissions
for the period of 1990 through 2003. In 2003, 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 2-6 and Figure 2-7). A
discussion of specific trends related to CO2 as well as other greenhouse gas emissions from energy consumption is
presented below. Energy related activities are also responsible for CH4 and N2O emissions (39 percent and 15
percent of total U.S. emissions, respectively). Table 2-6 presents greenhouse gas emissions from the Energy sector,
by source and gas.
Figure 2-6: 2003 Energy Sector Greenhouse Gas Sources
Figure 2-7: 2003 U.S. Fossil Carbon Flows (Tg CO2 Eq.)
Table 2-6: Emissions from Energy (Tg CO2 Eq.)
Gas/Source
C02
Fossil Fuel Combustion
Non-Energy Use of Fuels
Waste Combustion
Natural Gas Flaring
Biomass- Wood*
International Bunker Fuels*
Biomass-Ethanol *
CH4
Natural Gas Systems
Coal Mining
Petroleum Systems
1990 X 1997
4,836.4
4,711.7
108.0
10.9
5.8
272.5
113.5
4.2
248.9
128.3
81.9
£•'•>• 5,409.1
£•?'*; 5,263.2
;X'- 120.3
-V 17.8
$V.' 7.9
^"•'v 226.3
?/•";' 109.9
H^' 7-°
>'-? 234.6
D'>' 133.6
>: •;:, 62.6
20.0 ;';•''•,,; 18.8
1998
5,437.7
5,278.7
135.4
17.1
6.6
209.5
114.6
7.7
230.9
131.8
62.8
18.5
1999
5,512.1
5,345.9
141.6
17.6
6.9
214.3
105.3
8.0
222.1
127.4
58.9
17.8
2000
5,693.5
5,545.1
124.7
18.0
5.8
217.6
101.4
9.2
224.3
132.1
56.2
17.6
2001
5,592.9
5,448.0
120.1
18.8
6.1
190.8
97.9
9.7
221.6
131.8
55.6
17.4
2002
5,645.3
5,501.4
118.8
18.8
6.2
195.8
89.5
11.5
215.8
130.6
52.4
17.1
2003
5,694.3
5,551.6
118.0
18.8
6.0
201.0
84.2
15.8
212.7
125.9
53.8
17.1
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 28
-------
Stationary Sources
Abandoned Coal Mines
Mobile Sources
International Bunker Fuels*
N2O
Mobile Sources
Stationary Sources
Waste Combustion
International Bunker Fuels*
Total
7
6
4
.8
1
8
0.2
56
43
12
0
1
5,141
.4
7
.3
.4
.0
(";"•" 7.
>*"" 8.
',-'•'"', 4.
.>; v
''$'?': 0.
:*E';' 69.
;:'>'; 55.
:•>? i3.
•\'^i o-
r;:^ •?.
.7p;f:t, 5,712.
4
1
0
7
1
2
5
4
0
8
6.
7.
3.
a
69.
55.
13.
0.
1.
9
2
9
2
1
3
4
3
0
5,737.7
7.1
7.3
3.6
0.1
68.4
54.6
13.5
0.3
0.9
5,802.6
7.3
7.7
3.4
0.1
67.5
53.2
14.0
0.4
0.9
5,985.3
6.7
6.9
3.1
0.1
62.8
49.0
13.5
0.4
0.9
5,877.3
6.4
6.4
2.9
0.1
59.6
45.6
13.5
0.5
as
5,920.7
6.7
6.4
2.7
0.1
56.4
42.1
13.8
0.5
as
5,963.4
* These values are presented for informational purposes only and are not included in totals or are already accounted for in other
source categories.
Note: Totals may not sum due to independent rounding.
Fossil Fuel Combustion (5,551.6 Tg CO2 Eq.)
As fossil fuels are combusted, the carbon stored in them is emitted almost entirely as CO2. 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 2003, petroleum supplied the largest share of U.S. energy demands,
accounting for an average of 39 percent of total energy consumption with natural gas and coal accounting for 24
and 23 percent of total energy consumption, respectively. Petroleum was consumed primarily in the transportation
end-use sector, 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 1.3 percent from 1990 to 2003.
The fundamental factors influencing this trend include (1) a generally growing domestic economy over the last 13
years, and (2) significant growth in emissions from transportation activities and electricity generation. Between
1990 and 2003, CO2 emissions from fossil fuel combustion increased from 4,711.7 Tg CO2 Eq. to 5,551.6 Tg CO2
Eq.—an 18 percent total increase over the thirteen-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 2-7, Figure 2-8, and Figure 2-9 summarize CO2 emissions from fossil fuel
combustion by end-use sector.
Table 2-7: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.)
End-Use Sector
Transportation
Combustion
Electricity
Industrial
Combustion
Electricity
Residential
1990
1,449.8
1,4468
30
1,553.9
8828
671 1
924.8
V 1997
! 1,606.4
•> 1,603.3
>" 3-1
!'.<' 1,703.0
;f 963.8
". 739.2
• 1,040.7
1998
1,636.5
1,633.4
3.1
1,668.5
911.6
757.0
1,044.4
1999
1,693.9
1,690.8
3.2
1,651.2
888.1
763.1
1,063.5
2000
1,741.0
1,737.7
3.4
1,684.4
905.0
779.4
1,124.2
1
1
1
1
2001
,723.1
,719.7
3.4
,587.4
878.2
709.3
,116.2
1
1
1
1
2002
,755.4
,752.3
3.2
,579.0
876.6
702.4
,145.0
1
1
1
1
2003
,770.4
,767.2
3.2
,572.9
858.6
714.3
,168.9
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 29
-------
Combustion
Electricity
Commercial
Combustion
Electricity
U.S. Territories
Total
Electricity Generation
339
585
755
224
530
28
4,711
1,790
6 ,4!
3 •>•'
.1 .V
2 ,',
9 •'*
•0 ,X
.7 ' •
.3 la;
370.6
670.2
876.7
237.2
639.5
36.4
5,263.2
2,051.9
338
705
892
219
673
36
5,278
2,139
.6
.8
.9
.7
.2
.3
.7
.0
359.3
704.2
901.2
222.3
678.9
36.2
5,345.9
2,149.3
379
745
959
235
724
35
5,545
2,252
.1
.0
.5
.2
o
. j
.9
.1
.1
367.0
749.2
972.7
226.7
745.9
48.6
5,448.0
2,207.8
371.4
773.6
973.9
230.0
743.9
48.1
5,501.4
2,223.0
385.1
783.8
983.1
234.0
749.2
56.2
5,551.6
2,250.5
Note: Totals may not sum due to independent rounding. Combustion-related emissions from electricity generation are allocated
based on aggregate national electricity consumption by each end-use sector.
Figure 2-8: 2003 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
Figure 2-9: 2003 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion
Transportation End-Use Sector. Transportation activities (excluding international bunker fuels) accounted for 32
percent of CO2 emissions from fossil fuel combustion in 2003.3 Virtually all of the energy consumed in this end-
use sector came from petroleum products. Over 60 percent 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.
Industrial End-Use Sector. Industrial CO2 emissions, resulting both directly from the combustion of fossil fuels and
indirectly from the generation of electricity that is consumed by industry, accounted for 28 percent of CO2 from
fossil fuel combustion in 2003. 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.
Residential and Commercial End-Use Sectors. The residential and commercial end-use sectors accounted for 21
and 18 percent, respectively, of CO2 emissions from fossil fuel combustion in 2003. 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 35 percent of
U.S. energy from fossil fuels and emitted 41 percent of the CO2 from fossil fuel combustion in 2003. 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 2003. Consequently, changes
in electricity demand have a significant impact on coal consumption and associated CO2 emissions.
J 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 2003.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 30
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Non-Energy Use of Fossil Fuels (118.0 Tg CO2 Eq.)
In addition to being combusted for energy, fossil fuels are also consumed for non-energy uses (NEUs). Fuels are
used in the industrial and transportation end-use sectors for a variety of NEUs, including application as solvents,
lubricants, and waxes, or as raw materials in the manufacture of plastics, rubber, and synthetic fibers. 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 dunng the product's lifetime, such as during solvent use. Where appropriate data and methodologies are
available, NEUs of fossil fuels used for industrial processes are reported in the Industrial Processes sector.
Emissions in 2003 for non-energy uses of fossil fuels were 118.0 Tg CO2 Eq., which constituted 2 percent of overall
fossil fuel CO2 emissions and 2 percent of total national CO2 emissions, approximately the same proportion as in
1990.
Waste Combustion (19.2 Tg CO2 Eq.)
Combustion is used to manage about 7 to 17 percent of the municipal solid wastes generated in the United States.
The burning of garbage and non-hazardous solids, referred to as municipal solid waste, as well as the burning of
hazardous waste, is usually performed to recover energy from the waste materials. Carbon dioxide and N2O
emissions arise from the organic materials found in these wastes. Within municipal solid waste, many products
contain carbon of biogenic origin (e.g., paper, yard trimmings), and the CO2 emissions from their combustion are
accounted for under the Land Use Change and Forestry chapter. Several components of municipal solid waste, such
as plastics, synthetic rubber, synthetic fibers, and carbon black, are of fossil fuel origin, and are included as sources
of CO2 and N2O emissions. In 2003, CO2 emissions from waste combustion amounted to 18.8 Tg CO2 Eq., while
N2O emissions amounted to 0.5 Tg CO2 Eq.
Natural Gas Flaring (6.0 Tg CO2 Eq.)
The flaring of natural gas from oil wells results in the release of CO2 emissions. Natural gas is flared from both on-
shore and off-shore oil wells to relieve rising pressure or to dispose of small quantities of gas that are not
commercially marketable. In 2003, flaring accounted for approximately 0.1 percent of U.S. CO2 emissions.
Natural Gas Systems (125.9 Tg CO2 Eq.)
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
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
2003, CH4 emissions from U.S. natural gas systems accounted for approximately 23 percent of U.S. CH4 emissions.
Coal Mining (53.8 Tg CO2 Eq.)
Produced millions of years ago during the formation of coal, CH4 trapped within coal seams and surrounding rock
strata is released when the coal is mined. The quantity of CH4 released to the atmosphere during coal mining
operations depends primarily upon the 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. Dunng 2003, coal mining activities emitted 10 percent of U.S. CH4 emissions. From 1990 to 2003,
emissions from this source decreased by 34 percent due to increased use of the CH4 collected by mine degasification
systems and a general shift toward surface mining.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 31
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Petroleum Systems (17.1 Tg CO2 Eq.)
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 2003, emissions from petroleum systems were just over 3 percent of U.S.
CH4 emissions.
Mobile Combustion (44.8 Tg CO2 Eq.)
Mobile combustion results in N2O and CH4 emissions. Nitrous oxide is a product of the reaction that occurs
between nitrogen and oxygen during fuel combustion. 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 2003,
N2O emissions from mobile combustion were 42.1 Tg CO2 Eq. (11 percent of U.S. N2O emissions). From 1990 to
2003, N2O emissions from mobile combustion decreased by about 4 percent.
In 2003, CH4 emissions were estimated to be 2.7 Tg CO2 Eq. The combustion of gasoline in highway vehicles was
responsible for the majority of the CH4 emitted from mobile combustion.
Stationary Combustion (20.5 Tg CO2 Eq.)
Stationary combustion results in N2O and CH4 emissions. In 2003, N2O emissions from stationary combustion
accounted for 13.8 Tg CO2 Eq. (4 percent of U.S. N2O emissions). From 1990 to 2003, N2O emissions from
stationary combustion increased by 13 percent, due to increased fuel consumption. In 2003, CH4 emissions were
6.7 Tg CO2 Eq. (1 percent of U.S. CH4 emissions). The majority of CH4 emissions from stationary combustion
resulted from the burning of wood in the residential end-use sector.
Abandoned Coal Mines (6.4 Tg CO2 Eq.)
Coal mining activities result in the emission of CH4 into the atmosphere. However, the closure of a coal mine does
not correspond with an immediate cessation in the release of emissions. Following an initial decline, abandoned
mines can liberate CH4 at a near-steady rate over an extended period of time, or, if flooded, produce gas for only a
few years. In 2003, the emissions from abandoned coal mines constituted 1 percent of U. S. CH4 emissions.
CO2from Biomass Combustion (216.8 Tg CO2 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 the Land-Use Change and Forestry sector. 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.
The consumption of wood biomass in the industrial, residential, electric power, and commercial end-use sectors
accounted for 66, 17, 8, and 2 percent of gross CO2 emissions from biomass combustion, respectively. Ethanol
consumption in the transportation end-use sector accounted for the remaining 7 percent.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 32
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International Bunker Fuels (85.1 Tg CO2 Eq.)
Greenhouse gases emitted from the combustion of fuels used for international transport activities, termed
international bunker fuels under the UNFCCC, include CO2, CH4, and N2O. Emissions from these activities 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. These decisions are reflected in the Revised 1996IPCC Guidelines, in which countries are
requested to report emissions from ships or aircraft that depart from their ports with fuel purchased within national
boundanes and are engaged in international transport separately from national totals (IPCC/UNEP/OECD/IEA
1997).
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. Emissions of CO2, CH4, and N2O from international bunker fuel combustion were 84.2, 0.1,
and 0.8 Tg CO2 Eq. in 2003, respectively.
Industrial Processes
Emissions are produced as a by-product of many non-energy-related industrial process activities. For example,
industrial processes can chemically transform raw materials, which often release waste gases such as CO2 CH4 and
N2O. The processes include iron and steel production, cement manufacture, ammonia manufacture and urea
application, lime manufacture, limestone and dolomite use (e.g., flux stone, flue gas desulfurization, and glass
manufacturing), soda ash manufacture and use, titanium dioxide production, phosphoric acid production, ferroalloy
production, CO2 consumption, aluminum production, petrochemical production, silicon carbide production, nitric
acid production, and adipic acid production (see Figure 2-10). Additionally, emissions from industrial processes
release HFCs, PFCs and SF6. Table 2-8 presents greenhouse gas emissions from Industrial Processes by source
category.
Figure 2-10: 2003 Industrial Processes Chapter Greenhouse Gas Sources
Table 2-8: Emissions from Industrial Processes (Tg CO2 Eq.)
Gas/Source
C02
Iron and Steel Production
Cement Manufacture
Ammonia Manufacture & Urea Application
Lime Manufacture
Limestone and Dolomite Use
Aluminum Production
Soda Ash Manufacture and Consumption
Petrochemical Production
Titanium Dioxide Production
Phosphoric Acid Production
Ferroalloy Production
Carbon Dioxide Consumption
CH4
Petrochemical Production
Iron and Steel Production
Silicon Carbide Production
N20
Nitric Acid Production
1990
173.1
854
33 3
19.3
11.2
55
63
4 1
2.2
1.3
1 5
20
0.9
2.5
1 2
1.3
+
33.0
178
1997
. ' <>/ ' 170.9
•"! : '" 7i,9
:« <;. : 38.3
'''.' 20.7
', V ' 13.7
{'l- 7-2
-''",' 5-6
, i- 4.4
2.9
• .; '" 1.8
*';,,, L5
•';'"'',' 2-°
'\ "", ', 0.8
', 2.9
";:i;- 1.6
•''•"'' 1.3
+
• -,., 31-5
21.2
1998
169.4
67.4
39.2
21.9
13.9
7.4
5.8
4.3
3.0
1.8
1.6
2.0
0.9
2.9
1.7
1.2
+
26.9
20.9
1999
165.9
64.4
40.0
20.6
13.5
8.1
5.9
4.2
3.1
1.9
1.5
2.0
0.8
2.9
1.7
1.2
+
25.6
20.1
2000
164.7
65.7
41.2
19.6
13.3
6.0
5.7
4.2
3.0
1.9
1.4
1.7
1.0
2.9
1.7
1.2
+
25.6
19.6
2001
151.8
58.9
41.4
16.7
12.8
5.7
4.1
4.1
2.8
1.9
1.3
1.3
0.8
2.5
1.4
1.1
+
20.8
15.9
2002
151.5
55.1
42.9
18.6
12.3
5.9
4.2
4.1
2.9
2.0
1.3
1.2
1.0
2.5
1.5
1.0
+
23.1
17.2
2003
147.2
53.8
43.0
15.6
13.0
4.7
4.2
4.1
2.8
2.0
1.4
1.4
1.3
2.5
1.5
1.0
+
21.8
15.8
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 33
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Adipic Acid Production
HFCs, PFCs, and SF6
Substitution of Ozone Depleting
Substances
Electrical Transmission and Distribution
HCFC-22 Production
Aluminum Production
Semiconductor Manufacture
Magnesium Production and Processing
Total
15 2 \ ,.t 10
91.2
04
292
350
183
29
54
299.9
121
46
,' '•"- 21
V''-'; 30
''""." 11
";>,, 6
..*.'' 6
',"-'». 327
o
.J
.7
.5
.7
.0
.0
o
.3
.3
.1
6
135
56
17
40
9
7
5
334
.0
.7
.6
.1
.1
.1
.1
.8
.9
5.5
134.8
65.8
16.4
30.4
9.0
7.2
6.0
329.2
6
138
75
15
29
9
6
3
332
.0
.9
.0
.6
.8
.0
o
.3
.2
.1
4.9
129.5
83.3
15.4
19.8
4.0
4.5
2.6
304.7
5.9
138.3
91.5
14.7
19.8
5.2
4.4
2.6
315.4
6.0
137.0
99.5
14.1
12.3
3.8
4.3
3.0
308.6
+ Does not exceed 0.05 Tg CO2 Eq.
Note: Totals may not sum due to independent rounding.
Iron and Steel Production (54.8 Tg CO2 Eq.)
Pig iron is the product of combining iron oxide (i.e., iron ore) and sinter with metallurgical coke in a blast furnace.
The pig iron production process, as well as the thermal processes used to create sinter and metallurgical coke,
resulted in emissions of CO2 and CH4. In 2003, iron and steel production resulted in 1.0 Tg CO2 Eq. of CH4
emissions, with the majority of the emissions coming from the pig iron production process. The majority of CO2
emissions from iron and steel processes come from the production of coke for use in pig iron creation, with smaller
amounts evolving from the removal of carbon from pig iron used to produce steel. CO2 emissions from iron and
steel amounted to 53.8 Tg CO2 Eq. in 2003. From 1990 to 2003, emissions from this source decreased by 37
percent.
Cement Manufacture (43.0 Tg CO2 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. From 1990 to 2003, emissions from this source increased by
29 percent.
Ammonia Manufacture and Urea Application (15.6 Tg CO2 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 (13.0 Tg CO2 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.
Limestone and Dolomite Use (4.7 Tg CO2 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 34
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Aluminum Production (8.0 Tg CO2 Eq.)
Aluminum production results in emissions of CO2, CF4 and C2F6. 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. In 2003, CO2 emissions from aluminum production amounted to 4.2 Tg CO2 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. PFC emissions from aluminum production have decreased by 79 percent between 1990 and 2003 due to
emission reduction efforts by the industry and falling domestic aluminum production. In 2003, CF4 and C2F6
emissions from aluminum production amounted to 3.8 Tg CO2 Eq.
Soda Ash Manufacture and Consumption (4.1 Tg CO2 Eq.)
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.
Petrochemical Production (4.3 Tg CO2 Eq.)
The production process for carbon black results in the release CO2 emissions to the atmosphere. Carbon black is a
black powder generated by the incomplete combustion of an aromatic petroleum or coal-based feedstock
production. The majority of carbon black produced in the United States is consumed by the tire industry, which
adds it to rubber to increase strength and abrasion resistance. Small amounts of CH4 are also released during the
production of five petrochemicals: carbon black, ethylene, ethylene dichloride, styrene, and methanol. These
production processes resulted in emissions of 2.8 Tg CO2 Eq. of CO2 and 1.5 Tg CO2 Eq. of CH4 in 2003.
Titanium Dioxide Production (2.0 Tg CO2 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.
Phosphoric Acid Production (1.4 Tg CO2 Eq.)
Phosphoric acid is a basic raw material in the production of phosphate-based fertilizers. The phosphate rock
consumed in the United States originates from both domestic mines, located primarily in Florida, North Carolina,
Idaho, and Utah, and foreign mining operations in Morocco. The primary use of this material is as a basic
component of a senes of chemical reactions that lead to the production of phosphonc acid, as well as the by-
products CO2 and phosphogypsum.
Ferroalloy Production (1.4 Tg CO2 Eq.)
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.
Carbon Dioxide Consumption (1.3 Tg CO2 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-
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 35
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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. The majority of the CO2 used in these applications is eventually released to the
atmosphere.
Silicon Carbide Production (0.01 Tg CO2 Eq.)
Small amounts of CH4 are released during the production of silicon carbide, a material used as an industrial
abrasive. Silicon carbide (SiC) is made through a reaction of quartz (SiO2) and carbon (in the form of petroleum
coke). Methane is produced during this reaction from volatile compounds in the petroleum coke. Methane
emissions from silicon carbide production have declined significantly due a 67 percent decrease in silicon carbide
production since 1990. In 2003, only two companies produced silicon carbide in the United States (one company
produced abrasive-grade silicon carbide and the other produced a small quantity for heat-resistant products).
Nitric Acid Production (15.8 Tg CO2 Eq.)
Nitric acid production is an 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 2003, N2O emissions from nitric acid production accounted
for 4 percent of U.S. N2O emissions. From 1990 to 2003, emissions from this source category decreased byl 1
percent with the trend in the time series closely tracking the changes in production.
Adipic Acid Production (6.0 Tg CO2 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 2003, U.S. adipic acid plants emitted 2 percent of U.S. N2O emissions. Even though adipic acid production has
increased in recent years, 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 60 percent since 1990.
Substitution of Ozone Depleting Substances (99.5 Tg CO2 Eq.)
The use and subsequent emissions of HFCs and PFCs as substitutes for ODSs have increased from small amounts in
1990 to account for 73 percent of aggregate HFC, PFC, and SF6 emissions. This increase was in large part the
result of efforts to phase-out CFCs and other ODSs in the United States, especially the introduction of HFC-134a as
a CFC substitute in refrigeration and air-conditioning applications. In the short term, this trend is expected to
continue, and will likely accelerate over the coming 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.
HCFC-22 Production (12.3 Tg CO2 Eq.)
HFC-23 is a by-product of the production of HCFC-22. Emissions from this source have decreased by 65 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.
Electrical Transmission and Distribution Systems (14.1 Tg CO2 Eq.)
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. The gas
can also be released during equipment manufacturing, installation, servicing, and disposal. Estimated emissions
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 36
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from this source decreased by 52 percent since 1990, primarily due to higher SF6 prices and industrial efforts to
reduce emissions.
Semiconductor Manufacture (4.3 Tg CO2 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 49 percent since 1990 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 2003. This later reduction is
due to the implementation of PFC emission reduction methods, such as process optimization.
Magnesium Production (3.0 Tg CO2 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 45 percent since 1990. This decrease has
primarily taken place since 1999, due to a decline in the quantity of magnesium die cast and the closure of a U.S.
primary magnesium production facility.
Solvent and Other Product Use
Greenhouse gas emissions are produced as a by-product of various solvent and other product uses. In the United
States, emissions from N2O Product Usage, the only source of greenhouse gas emissions from this sector, accounted
for 4.8 Tg CO2 Eq. of N2O, or less than 0.1 percent of total U.S. anthropogenic greenhouse gas emissions on a
carbon equivalent basis in 2003 (see Table 2-9).
Table 2-9: N2O Emissions from Solvent and Other Product Use (Tg CO2 Eq.)
Gas/Source
N2O
Nitrous Oxide Product Usage
Total
1990 ;5'^;
4.3 ,;: '
43 '"*/,,
4.3 %&
1997
4.8
4.8
4.8
1998
4.8
4.8
4.8
1999
4.8
4.8
4.8
2000
4.8
4.8
4.8
2001
4.8
4.8
4.8
2002
4.8
4.8
4.8
2003
4.8
4.8
4.8
N2O Product Usage (4.8 Tg CO2 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. In
2003, N2O emissions from product usage constituted approximately 1 percent of U.S. N2O emissions. From 1990 to
2003, emissions from this source category increased by 11 percent.
Agriculture
Agricultural activities contribute directly to emissions of greenhouse gases through a variety of processes, including
the following source categories: enteric fermentation in domestic livestock, livestock manure management, rice
cultivation, agricultural soil management, and field burning of agricultural residues.
In 2003, agricultural activities were responsible for emissions of 433.3 Tg CO2 Eq., or 6 percent of total U.S.
greenhouse gas emissions. Methane and N2O were the primary greenhouse gases emitted by agncultural activities.
Methane emissions from enteric fermentation and manure management represented about 21 percent and 7 percent
of total CH4 emissions from anthropogenic activities, respectively in 2003. Agricultural soil management activities
such as fertilizer application and other cropping practices were the largest source of U.S. N2O emissions in 2003,
accounting for 67 percent. Table 2-10 presents emission estimates for the Agriculture sector.
Figure 2-11: 2003 Agriculture Chapter Greenhouse Gas Sources
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 37
-------
Table 2-10: Emissions from Agriculture (Tg CO2 Eq.)
Gas/Source
CH4
Enteric Fermentation
Manure Management
Rice Cultivation
Field Burning of Agricultural
Residues
N2O
Agricultural Soil Management
Manure Management
Field Burning of Agricultural
Residues
Total
1990 -',-;•"
156.9 j,:<
1179 ->V,i
312 ;-X
7 1 jf'<
•-v'.'v.
0 7 ;
-------
Field Burning of Agricultural Residues (1.2 Tg CO2 Eq.)
Burning crop residue releases N2O and CH4. Because field burning is not a common debris clearing method used in
the United States, it was responsible for only 0.1 percent of U.S. CH4 (0.8 Tg CO2 Eq.) and N2O (0.4 Tg CO2 Eq.)
emissions in 2003.
Agricultural Soil Management (253.5 Tg CO2 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 2003, agricultural soil management accounted for 67 percent of U.S. N2O emissions. From 1990 to 2003,
emissions from this source increased slightly as fertilizer consumption, manure production, and production of
nitrogen-fixing and other crops rose. Year-to-year fluctuations are largely a reflection of annual variations in
climate, synthetic fertilizer consumption, and crop production.
Land-Use Change and Forestry
When humans alter the terrestrial biosphere through land use, changes in land use, and land management practices,
they also alter the background carbon fluxes between biomass, soils, and the atmosphere. Forest management
practices, tree planting in urban areas, the management of agricultural soils, and the landfilling of yard trimmings
and food scraps have resulted in a net uptake (sequestration) of carbon in the United States, which offset about 12
percent of total U.S. gross CO2 emissions in 2003. Forests (including vegetation, soils, and harvested wood)
accounted for approximately 91 percent of total 2003 sequestration, urban trees accounted for 7 percent, agricultural
soils (including mineral and organic soils and the application of lime) accounted for 1 percent, and landfilled yard
trimmings and food scraps accounted for 1 percent of the total sequestration in 2003. 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 times 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 and food scraps net
sequestration is due to the long-term accumulation of yard trimming carbon and food scraps in landfills.
Land use, land-use change, and forestry activities in 2003 resulted in a net carbon sequestration of 828.0 Tg CO2
Eq. (Table ES-5). This represents an offset of approximately 14 percent of total U.S. CO2 emissions. Total land
use, land-use change, and forestry net carbon sequestration declined by approximately 21 percent between 1990 and
2003. This decline was primarily due to a decline in the rate of net carbon accumulation in forest carbon stocks.
Annual carbon accumulation in landfilled yard trimmings and food scraps also slowed over this period, as did
annual carbon accumulation in agricultural soils. As described above, the constant rate of carbon accumulation in
urban trees is a reflection of limited underlying data (i.e., this rate represents an average for 1990 through 1999).
Table 2-11: Net CO2 Flux from Land-Use Change and Forestry (Tg CO2 Eq.)
Sink Category
Forest Land Remaining Forest Land
Changes in Forest Carbon Stocks
Cropland Remaining Cropland
Changes in Agricultural Soil Carbon
1990
(949.3)
(949.3)
(8.1)
(8.1)
'", , 1997
,«1 (851.0)
",-,., (851.0)
(7.4)
;;,- (7.4)
1998
(805.5)
(805.5)
(4.3)
(4.3)
1999
(751.7)
(751.7)
(4.3)
(4.3)
2000
(747.9)
(747.9)
(5.7)
(5.7)
2001
(750.9)
(750.9)
(7.1)
(7.1)
2002
(751.5)
(751.5)
(6.2)
(6.2)
2003
(752.7)
(752.7)
(6.6)
(6.6)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 39
-------
Stocks
Settlements
Remaining Settlements
Urban Trees
Landfill ed
Scraps
Total
Yard
Trimmings
and Food
(84.7)
(58.7)
(26.0)
(1,042.0)
' :,. (7i.6)
' , (58.7)
M, ,Jf i
lr \ (12.9)
(930.0)
(71.2)
(58.7)
(12.5)
(881.0)
(70.0)
(58.7)
(11.4)
(826.1)
(68.9)
(58.7)
(10.2)
(822.4)
(68.9)
(58.7)
(10.3)
(826.9)
(68.8)
(58.7)
(10.2)
(826.5)
(68.7)
(58.7)
(10.1)
(828.0)
Note: Parentheses indicate net sequestration. Totals may not sum due to independent rounding.
Land use, land-use change, and forestry activities in 2003 also resulted in emissions of N2O (6.4 Tg CO2 Eq., Table
2-12). Total N2O emissions from the application of fertilizers to forests and settlements increased by approximately
14 percent between 1990 and 2003.
Table 2-12: N2O Emissions from Land-Use Change and Forestry (Tg CO2 Eq.)
Sink Category
Forest Land Remaining Forest Land
N2O Fluxes from Soils
Settlements Remaining Settlements
N2O Fluxes from Soils
Total
1990
0.1
0.1
5.5
5.5
5.6
1997
',! 0.3
0.3
6.1
6.1
. = 6.4
1998
0.4
0.4
6.1
6.1
6.5
1999
0.5
0.5
6.2
6.2
6.6
2000
0.4
0.4
6.0
6.0
6.3
2001
0.4
0.4
5.8
5.8
6.2
2002
0.4
0.4
6.0
6.0
6.4
2003
0.4
0.4
6.0
6.0
6.4
Note: Totals may not sum due to independent rounding.
Forest Land Remaining Forest Land (0.4 Tg CO2 Eq.)
As with other agricultural applications, forests may be fertilized to stimulate growth rates. This relative magnitude
of the impact of this practice is limited, however, because forests are generally only fertilized twice during their life
cycles, and applications account for no more than one percent of total U.S. fertilizer applications annually. In terms
of trends, however, N2O emissions from forest soils for 2003 were almost 7 times higher than in 1990, primarily the
result of an increase in fertilized area of pine plantations in the southeastern U.S. This source accounts for
approximately 0.1 percent of total U.S. N2O emissions.
Settlements Remaining Settlements (6.0 Tg CO2 Eq.)
Of the fertilizers applied to soils in the U.S., approximately 10 percent are applied to lawns, golf courses, and other
landscaping within settled areas. In 2003, N2O emissions from settlement soils constituted approximately 1.6
percent of total U.S N2O emissions. There has been an overall increase in emissions of 9 percent since 1990, a
result of a general increase in the applications of synthetic fertilizers.
Waste
Waste management and treatment activities are sources of greenhouse gas emissions (see Figure 2-12). Landfills
were the largest source of anthropogenic methane (CH4) emissions, accounting for 24 percent of total U.S. CH4
emissions.4 Wastewater treatment systems are 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 monoxide (CO), and non-methane volatile organic compounds
(NMVOCs) are also emitted by waste activities. A summary of greenhouse gas and ambient air pollutant emissions
from the Waste sector is presented in Table 2-13.
Figure 2-12: 2003 Waste Sector Greenhouse Gas Sources
4 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 40
-------
Overall, in 2003, waste activities generated emissions of 183.8 Tg CO2 Eq., or 3 percent of total U.S. greenhouse
gas emissions.
Table 2-13: Emissions from Waste (Tg CO2 Eq.)
Gas/Source
CH4
Landfills
Wastewater Treatment
N2O
Human Sewage
Total
1990 ,,^-f
197
172
24
13
13
210
1 ', ~1V
.2 ''"*"-;
.8 ,/.,*,
.0 '':, '-,,
,o '-y:''
.i.&&
1997
179
147
31
14
14
193
.0
.4
.7
.7
.7
.7
1998
171
138
32
15
15
186
.0
.5
.6
.0
.0
.0
1999
167.7
134.0
33.6
15.4
15.4
183.1
2000
165.0
130.7
34.3
15.6
15.6
180.6
2001
160.9
126.2
34.7
15.6
15.6
176.5
2002
162.6
126.8
35.8
15.7
15.7
178.3
2003
167.9
131.2
36.8
15.9
15.9
183.8
Note: Totals may not sum due to independent rounding.
Landfills (131.2 Tg CO2 Eq.)
Landfills are the largest anthropogenic source of CH4 emissions in the United States, accounting for approximately
24 percent of total CH4 emissions in 2003. 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 CO2. Site-specific factors, such as waste composition, moisture, and landfill
size, influence the level of methane generation.
From 1990 to 2003, net CH4 emissions from landfills decreased by approximately 24 percent, with small increases
occurring in some interim years. This 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 an increase in the amount of municipal solid waste landfilled.
Wastewater Treatment (36.8 Tg CO2 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. In 2003, wastewater treatment was the source of approximately 7 percent of U.S. CH4
emissions.
Human Sewage (Domestic Wastewater) (15.9 Tg CO2 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 demtrification of the nitrogen present, usually in the
form of urea, ammonia, and proteins. Emissions of N2O from treated human sewage discharged into aquatic
environments accounted for 4 percent of U.S. N2O emissions in 2003. From 1990 to 2003, emissions from this
source category increased by 22 percent.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 41
-------
2.2. 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, as well as
U.S. Territories. Using this categorization, emissions from electricity generation accounted for the largest portion
(33 percent) of U.S. greenhouse gas emissions in 2003. 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 2003. 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 residential, agriculture, commercial
economic sectors, and U.S. territories, contributed the remaining 20 percent of emissions. The residential economic
sector accounted for approximately 6 percent, and primarily consisted of CO2 emissions from fossil fuel
combustion. Activities related to agriculture accounted for roughly 7 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 2-14 presents a detailed breakdown of emissions from each of these economic sectors by source category, as
they are defined in this report. Figure 2-13 shows the trend in emissions by sector from 1990 to 2003.
Figure 2-13: Emissions Allocated to Economic Sectors
Table 2-14: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO2 Eq. and Percent of Total in
2003)
Sector/Source
Electricity Generation
CO2 from Fossil Fuel
Combustion
Stationary Combustiond
Electrical Transmission and
Distribution0
Waste Combustion1"
Limestone and Dolomite
Use
Transportation
CO2 from Fossil Fuel
Combustion
Mobile Combustion4
Substitution of ODSe
Non-Energy Use of Fuels
Industry
CO2 from Fossil Fuel
Combustion
Non-Energy Use of Fuels
Stationary Combustion
1990
1,841
1,790
8
29
11
2
1,506
1,446
48
11
1,446
836
90
5
.8 :
,3i::
.1 :
,2i::
.3!;!
.si-;
.8; ;
.8 ;;
.1 -
+ :•;
.9i;;
.1 :;;
.si:-
A\':
.3 :YV
1997
2,104
2,051
9
21
18
3
1,693
1,603
58
19
11
1,509
: 905
102
5
.6
.9
.3
.7
.1
.6
.0
.3
.7
.4
.6
.1
.4
.6
.9
1998
2,186.8
2,139.0
9.5
17.1
17.4
3.7
1,728.7
1,633.4
58.7
24.4
12.1
1,470.6
853.9
117.0
5.5
1999
2,197.3
2,149.3
9.5
16.4
18.0
4.0
1,790.0
1,690.8
57.7
29.3
12.3
1,427.9
828.0
121.8
5.5
2000
2,299.0
2,252.1
10.0
15.6
18.3
3.0
1,839.6
1,737.7
56.1
33.8
12.1
1,431.8
854.6
101.7
5.6
2001
2,254.9
2,207.8
9.7
15.4
19.2
2.9
1,819.8
1,719.7
51.6
37.4
11.1
1,371.0
827.9
103.7
5.2
2002
2,269.7
2,223.0
9.8
14.7
19.2
2.9
1,851.6
1,752.3
48.1
40.4
10.9
1,365.7
824.3
102.6
5.3
2003 Percent3
2,296.2
2,250.5
10.0
14.1
19.2
2.4
1,864.4
1,767.2
44.3
42.7
10.2
1,331.4
806.3
101.9
5.3
33.3%
32.6%
0.1%
0.2%
0.3%
+
27.0%
25.6%
0.6%
0.6%
0.1%
19.3%
11.7%
1.5%
0.1%
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 42
-------
Coal Mining
Abandoned Coal Mines
Natural Gas Systems
Petroleum Systems
Natural Gas Flaring
Titanium Dioxide
Production
Aluminum Production'1
Iron and Steel Productionf
Ferroalloys
Ammonia Manufacture
Cement Manufacture
Lime Manufacture
Limestone and Dolomite
Use
Soda Ash Manufacture and
Consumption
Carbon Dioxide
Consumption
Petrochemical Production
Silicon Carbide Production
Phosphoric Acid Production
Adipic Acid
Nitric Acid
N2O Product Usage
HCFC-22 Production8
Semiconductor
Manufacture6
Magnesium Production and
Processing0
Substitution of ODSe
Agriculture
CO2 from Fossil Fuel
Combustion
Stationary Combustion*
Mobile Combustion*
Enteric Fermentation
Manure Management*
Rice Cultivation
Agricultural Residue
Burning*
Agricultural Soil
Management
Forest Soil Fertilization
Commercial
CO2 from Fossil Fuel
Combustion
Stationary Combustion*
Substitution of ODS*
Landfills
Human Sewage
Waste water Treatment
Residential
CO2 from Fossil Fuel
Combustion
81.9;:;
6.1 ::;
128.3 ;::
20.0 ::;
5O • .v
.0 ; '..
i.3i:;
24.7 ::;
86.7 ::;
2.0:-;
19.3: :
33.3 :
11.2;;;
2.8 ;;
4.1 ;;;
0.9;;;
3.4;;;
+ ;:-
1,5-
15.2-
17.8-
4.3 -
35.0::^
2.9 :;
5.4 :::
o.i ::!
473.3 ; :;
46.3;:;
0.4 ::;
117.9;:;
47.4 ::;
7.1 ;
1.1 :
253.0 :::
0.1 i;;
435.4 ;
224.2 ;;
1.1 ;;;
172.2;;;
13.0;;;
24.8:;;
350.9
339.6 :;y
62.6
8.1
133.6
18.8
7.9
1.8
16.6
73.1
2.0
20.7
38.3
13.7
3.6
4.4
0.8
4.6
+
1,5
10.3
21.2
4.8
30.0
6.3
6.3
4.1
492.0
58.4
0.5
118.3
53.7
7.5
1.2
252.0
0.3
445.2
237.2
1.1
13.1
147.4
14.7
31.7
391.0
370.6
62.8
7.2
131.8
18.5
6.6
1.8
14.8
68.6
2.0
21.9
39.2
13.9
3.7
4.3
0.9
4.7
+
1,6
6.0
20.9
4.8
40.1
7.1
5.8
5.1
508.4
57.6
0.5
116.7
56.2
7.9
1.2
267.7
0.4
424.2
219.7
1.1
17.4
138.5
15.0
32.6
358.4
338.6
58.9
7.3
127.4
17.8
6.9
1.9
14.9
65.5
2.0
20.6
40.0
13.5
4.0
4.2
0.8
4.8
+
1,5
5.5
20.1
4.8
30.4
7.2
6.0
6.4
486.9
60.0
0.5
116.8
56.2
8.3
1.2
243.4
0.5
426.8
222.3
1.1
20.3
134.0
15.4
33.6
379.5
359.3
56.2
7.7
132.1
17.6
5.8
1.9
14.7
66.9
1.7
19.6
41.2
13.3
3.0
4.2
1.0
4.7
+
1,4
6.0
19.6
4.8
29.8
6.3
3.2
7.4
495.3
50.4
0.4
115.6
55.9
7.5
1.2
263.9
0.4
440.7
235.2
1.2
23.8
130.7
15.6
34.3
399.7
379.1
55.6
6.9
131.8
17.4
6.1
1.9
8.1
60.0
1.3
16.7
41.4
12.8
2.9
4.1
0.8
4.2
+
1,3
4.9
15.9
4.8
19.8
4.5
2.6
8.4
488.6
50.3
0.4
114.5
56.9
7.6
1.2
257.1
0.4
431.4
226.7
1.0
27.1
126.2
15.6
34.7
387.1
367.0
52.4
6.4
130.6
17.1
6.2
2.0
9.5
56.1
1.2
18.6
42.9
12.3
2.9
4.1
1.0
4.4
+
1,3
5.9
17.2
4.8
19.8
4.4
2.6
9.7
485.6
52.3
0.5
114.6
57.3
6.8
1.1
252.6
0.4
440.2
230.0
1.1
30.8
126.8
15.7
35.8
391.6
371.4
53.8
6.4
125.9
17.1
6.0
2.0
8.0
54.8
1.4
15.6
43.0
13.0
2.4
4.1
1.3
4.3
+
1,4
6.0
15.8
4.8
12.3
4.3
3.0
11.2
486.4
52.2
0.5
115.0
56.7
6.9
1.2
253.5
0.4
453.5
234.0
1.1
34.7
131.2
15.9
36.8
406.1
385.1
0.8%
0.1%
1.8%
0.2%
0.1%
0.1%
0.8%
+
0.2%
0.6%
0.2%
+
0.1%
0.1%
+
0.1%
0.2%
0.1%
0.2%
0.1%
+
0.2%
7.0%
0.8%
1.7%
0.8%
0.1%
*
3.7%
7.0%
3.4%
0.5%
1.9%
0.2%
0.5%
5.9%
5.6%
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 43
-------
Stationary Combustion0
Substitution of ODSe
Settlement Soil Fertilization
U.S. Territories
CO2 from Fossil Fuel
Combustion
Total
Sinks
Forests
Urban Trees
Agricultural Soils
Landfilled Yard Trimmings
5.5 f:
03 I
5.5 |:
33.8 |
33.8 ;;;
6,088.1
(1,042.0)
(949.3);:-:
(58.7) !>
(8.i);:
(26.0):,,
6
(
(
4.4
9.9
6.1
42.7
42.7
,677.5
930.0)
851.0)
(58.7)
(7.4)
(12.9)
4.0
9.6
6.1
42.7
42.7
6,719.7
(881.0)
(805.5)
(58.7)
(4.3)
(12.5)
4.3
9.8
6.2
43.9
43.9
6,752.2
(826.1)
(751.7)
(58.7)
(4.3)
(11.4)
4.5
10.1
6.0
47.0
47.0
6,953.2
(822.4)
(747.9)
(58.7)
(5.7)
(10.2)
4.0
10.3
5.8
54.1
54.1
6,806.9
(826.9)
(750.9)
(58.7)
(7.1)
(10.3)
3.6
10.6
6.0
53.6
53.6
6,858.1
(826.5)
(751.5)
(58.7)
(6.2)
(10.2)
3.9
11.0
6.0
62.3
62.3
6,900.2
(828.0)
(752.7)
(58.7)
(6.6)
(10.1)
0
0
0
0.
0
100.
-12.
-10
-0
-0
-0
1%
2%
1%
9%
9%
0%
0%
9%
9%
1%
1%
Net Emissions (Sources and
Sinks) 5,046.1 5,747.5 5,838.8 5,926.1 6,130.8 5,980.1 6,031.6 6,072.2
Note: Includes all emissions of CO2, CHt, N2O, HFCs, PFCs, and SF6. Parentheses indicate negative values (or sequestration).
Totals may not sum due to independent rounding.
ODS (Ozone Depleting Substances)
+ Does not exceed 0.05 Tg CO2 Eq. or 0.05%.
- Not applicable.
a Percent of total emissions for year 2003.
b Includes both CO2 and N2O.
0 SF6 emitted.
d Includes both CH4 and N2O.
e May include a mixture of HFCs, PFCs, and SF6.
Includes both CH4 and CO2.
g HFC-23 emitted.
h Includes both CO2 and PFCs.
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 2003. Emissions increased by 25 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 2-15 provides a detailed summary of emissions
from electricity generation-related activities.
Table 2-15: Electricity Generation-Related Greenhouse Gas Emissions (Tg CO2 Eq.)
Gas/Fuel Type or Source
CO2
CO2 from Fossil Fuel Combustion
Coal
Natural Gas
Petroleum
Geothermal
Waste Combustion
Limestone and Dolomite Use
CH4
Stationary Combustion*
N2O
Stationary Combustion*
1990
1,804.0 ^
1,790.3 ^
1,513.0.1
176.0.1
101.0.1
0.4\l
10.9 ii
2.8 \l
0.6 J
0.6 ;:f
8.0
7.6 ;«•
1997
2,073.3
2,051.9
1,758.4
218.9
74.3
0.4
17.8
3.6
0.6
:::• 0.6
9.0
v' 8.6
1998
2,159.9
2,139.0
1,786.4
248.0
104.3
0.4
17.1
3.7
0.7
0.7
9.2
8.9
1999
2,171.0
2,149.3
1,792.4
259.9
96.7
0.4
17.6
4.0
0.7
0.7
9.2
8.9
2000
2,273.1
2,252.1
1,880.0
280.7
91.0
0.4
18.0
3.0
0.7
0.7
9.6
9.3
2001
2,229.4
2,207.8
1,817.4
289.1
100.9
0.4
18.8
2.9
0.7
0.7
9.4
9.0
2002
2,244.8
2,223.0
1,839.7
305.6
77.4
0.4
18.8
2.9
0.7
0.7
9.5
9.1
2003
2,271.7
2,250.5
1,876.3
277.6
96.3
0.3
18.8
2.4
0.7
0.7
9.8
9.3
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 44
-------
Waste Combustion
SF6
Electrical Transmission and
Distribution
Total
0
29
29
1,841
.4 S
.2 :?
Z
.2 "':
.8
0
21
21
2,104
.4
.7
.7
.6
0.3
17.1
17.1
2,186.8
0
16
16
2,197
o
. J
.4
.4
.3
0.4
15.6
15.6
2,299.0
0.4
15.4
15.4
2,254.9
0.5
14.7
14.7
2,269.7
0.5
14.1
14.1
2,296.2
Note: Totals may not sum due to independent rounding.
* Includes only stationary combustion emissions related to the generation of electricity.
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 2004a and Duffield 2004). These three
source categories include CO2 from fossil fuel combustion, CH4 and N2O from stationary sources, and SF6 from
electrical transmission and distribution systems.5
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 agriculture, CO2 accounts for more than 75 percent of
greenhouse gas emissions, primarily from the combustion of fossil fuels.
Table 2-16 presents a detailed breakdown of emissions from each of these economic sectors, with emissions from
electricity generation distributed to them. Figure 2-14 shows the trend in these emissions by sector from 1990 to
2003.
Figure 2-14: Emissions with Electricity Distributed to Economic Sectors
Table 2-16: U. S Greenhouse Gas Emissions by '
Distributed (Tg CO2 Eq.) and Percent of Total in
Sector/Gas
Industry
Direct Emissions
CO,
CH4
N2O
HFCs, PFCs, and SF6
Electricity -Related
CO2
CH4
N,0
SF6
Transportation
Direct Emissions
C02
CH4
N2O
HFCsb
1990 1997
2,075.7 |:
1,446.1 1
1,103
240
40
61
629
616
0
2
10
.0 1;
.9 1
.5 !•
.7 !•
.6 |
7 f-
2 '?•
1 '?•
.0 |
1,509.9
1,506
1,458
4
43
o :;•;
7 ^
4 ^'
;; 2,247.3
1,509.1
:: 1,183.2
:: 228.4
:: 39.8
:: 57.7
738.2
:: 727.2
:: 0.2
:: 3.2
:: 7.6
1,696.1
1,693.0
:: 1,614.9
:;: 3.5
.7 B: 55.2
+ ':!;••• 19.4
'Economic Sector'
2003
1998
2,223.2
1,470.6
1,143
225
34
67
752
743
0
3
5
1,731
1,728
1,645
3
55
24
.2
o
. J
.9
.2
.5
o
. J
.2
.2
.9
.8
.7
.6
.4
o
. J
.4
1999
2,190.1
1,427.9
1,118.6
216.5
33.6
59.1
762.2
753.1
0.2
3.2
5.7
1,793.2
1,790.0
1,703.0
3.1
54.6
29.3
and Gas
2000
2,207.7
1,431.8
1,123.7
218.7
33.7
55.6
775.9
767.2
0.2
3.3
5.3
1,843.0
1,839.6
1,749.8
2.9
53.2
33.8
with Electricity -Related Emissions
2001
2,074.0
1,371.0
1,086.7
216.4
28.7
39.3
702.9
695.0
0.2
2.9
4.8
1,823.2
1,819.8
1,730.8
2.6
49.0
37.4
2002
2,062.9
1,365.7
1,081.7
211.2
31.1
41.8
697.2
689.5
0.2
2.9
4.5
1,854.8
1,851.6
1,763.2
2.4
45.6
40.4
2003
2,040.1
1,331.4
1,059.0
207.9
29.8
34.6
708.7
701.2
0.2
3.0
4.4
1,867.6
1,864.4
1,777.4
2.2
42.1
42.7
Percent"
29.6%
19.3%
15.3%
3.0%
0.4%
0.5%
10.3%
10.2%
+
+
0.1%
27.1%
27.0%
25.8%
+
0.6%
0.6%
5 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 45
-------
Electricity -Related
CO2
CH4
N20
SF6
Commercial
Direct Emissions
CO2
CH4
N2O
HFCs
Electricity -Related
C02
CH4
N,O
SF6
Residential
Direct Emissions
CO2
CH4
N20
HFCs
Electricity -Related
CO2
CH4
N20
SF6
Agriculture
Direct Emissions
CO2
CH4
N2O
Electricity -Related
CO2
CH4
N,0
SF6
U.S. Territories
CO2
Total
3
3
981
435
224
197
13
546
535
0
2
8
953
350
339
4
6
0
602
589
0
2
9
534
473
46
157
270
60
59
0
1
33
33
•1:;:
•0 K
+ ::^
+ 1 >•
+ i::
•6;:!
•4;:!
.2;::
.8;::
.4:::
+ k
.2:::
.o:::
.2:::
.4:::
,7:::
.0 :
.9 :
.6- 'I
.4^
.6: 'I
.3;;:
.1-
,7:;;
.2!;;
.6:;;
.6-
.ii:;
.3-
.31:5
.0^
,oi:;
.8 ;
,6\-:
+ : >
.3 ;::
•0;:;
.8
.8:.'-;
6,088.1
3.1
3.0
+
+
+
1,083.8
445.2
237.2
179.8
15.0
13.1
638.7
629.2
0.2
2.7
6.6
1,060.3
391.0
370.6
3.5
7.1
9.9
669.3
659,3
0.2
2.9
6.9
547.4
492.0
58.4
163.1
270.5
55.4
54.6
+
0.2
0.6
I 42.7
42.7
:;. 6,677.5
3.1
3.0
+
+
+
1,093.5
424.2
219.7
171.8
15.3
17.4
669.3
661.0
0.2
2.8
5.2
1,060.0
358.4
338.6
3.1
7.0
9.6
701.6
693,0
0.2
3.0
5.5
568.6
508.4
57.6
164.4
286.3
60.2
59.5
+
0.3
0.5
42.7
42.7
6,719.7
3
3
1,104
426
222
168
15
20
678
670
0
2
5
1,082
379
359
3
7
9
703
695
0
2
5
537
486
60
164
262
50
49
0
0
43
43
6,752
.1
.1
+
+
+
.9
.8
o
.3
.5
.8
.3
.1
.0
.2
.8
.1
.9
.5
o
.J
A
.1
.8
.4
,0
.2
.9
.2
.3
.9
.0
.8
.1
.4
.8
+
.2
.4
.9
.9
.2
3.3
3.3
+
+
+
1,161.8
440.7
235.2
165.8
15.9
23.8
721.1
713.0
0.2
3.0
4.9
1,141.4
399.7
379.1
3.5
6.9
10.1
741.7
733,3
0.2
3.1
5.0
552.3
495.3
50.4
162.1
282.8
57.0
56.3
+
0.2
0.4
47.0
47.0
6,953.2
3.4
3.3
+
+
+
1,170.6
431.4
226.7
161.6
16.0
27.1
739.2
730.9
0.2
3.1
5.1
1,129.6
387.1
367.0
3.1
6.7
10.3
742.5
734,1
0.2
3.1
5.1
555.5
488.6
50.3
162.0
276.3
66.9
66.2
+
0.3
0.5
54.1
54.1
6,806.9
3.1
3.1
+
+
+
1,178.5
440.2
230.0
163.4
16.0
30.8
738.3
730.2
0.2
3.1
4.8
1,159.5
391.6
371.4
2.8
6.8
10.6
767.9
759,4
0.2
3.2
5.0
548.8
485.6
52.3
161.6
271.7
63.2
62.5
+
0.3
0.4
53.6
53.6
6,858.1
3.2
3.2
+
+
+
1,196.8
453.5
234.0
168.7
16.2
34.7
743.3
735.3
0.2
3.2
4.6
1,183.7
406.1
385.1
3.1
6.9
11.0
777.6
769,3
0.2
3.3
4.8
549.8
486.4
52.2
162.0
272.2
63.4
62.7
+
0.3
0.4
62.3
62.3
6,900.2
+
+
+
+
+
17.3%
6.6%
3.4%
2.4%
0.2%
0.5%
10.8%
10.7%
+
+
0.1%
17.2%
5.9%
5.6%
+
0.1%
0.2%
11.3%
11.2%
+
+
0.1%
8.0%
7.0%
0.8%
2.3%
3.9%
0.9%
0.9%
+
+
+
0.9%
0.9%
100.0%
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 CO2 Eq. or 0.05%.
a Percents for year 2003.
b Includes primarily HFC-134a.
Transportation
Transportation activities accounted for 27 percent of U.S. greenhouse gas emissions in 2003. Table 2-17 provides a
detailed summary of greenhouse gas emissions from transportation-related activities. Total emissions in Table 2-17
differ slightly from those shown in Table 2-16 primarily because the table below excludes a few minor non-
transportation mobile sources, such as construction and industrial equipment.
From 1990 to 2003, transportation emissions rose by 24 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
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 46
-------
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 35 percent from 1990 to 2003) and the gallons
of gasoline consumed each year in the United States have increased steadily since the 1980s, according to the
FHWA and Energy Information Administration, respectively. These increases in motor vehicle usage are the result
of a confluence of factors including population growth, economic growth, urban sprawl, low fuel prices, and
increasing popularity of sport utility vehicles and other light-duty trucks that tend to have lower fuel efficiency. A
similar set of social and economic trends has led to a significant increase in air travel and freight transportation by
both air 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 for the remainder. The primary driver of
transportation-related emissions was CO2 from fossil fuel combustion, which increased by 22 percent from 1990 to
2003. This rise in CO2 emissions, combined with an increase of 42.7 Tg CO2 Eq. in HFC emissions over the same
period, led to an increase in overall emissions from transportation activities of 24 percent.
Table 2-17: Transportation-Related Greenhouse Gas Emissions (Tg CO2 Eq.)
Gas/Vehicle Type
C02
Passenger Cars
Light-Duty Trucks
Other Trucks
Buses
Aircraft3
Ships and Boats
Locomotives
Otherb
International Bunker Fuels0
CH4
Passenger Cars
Light-Duty Trucks
Other Trucks and Buses
Aircraft
Ships and Boats
Locomotives
Motorcycles
International Bunker Fuels0
N2O
Passenger Cars
Light-Duty Trucks
Other Trucks and Buses
Aircraft
Ships and Boats
Locomotives
Motorcycles
International Bunker Fuels0
HFCs
Mobile Air Conditioners4
Refrigerated Transport
Total
1990 :;
1,461.7 ;
612.5 :;;
312.2 :;;
217.0 :;;
7.8::;
177.2 i:;
49.2 \:l
36.3 !;!
49.4 !;!
93.6-1
4.6 i
2.6;;!
1.4;;!
0.3;;!
0.2;:!
o.i ;:!
o.i::!
+ ;:^
0.2::!
42.9 !
25.5::;
14.1 ::?
0.9::?
1.7::?
0.4 i:^
0.3 \'l
+ :';
1.0\\ ,
+ ; :; ;
+ ; ' :|V
+ :'"• ' '
1,509.3 TV
1997
1,618.0
595.5
421.6
279.9
9.1
179.0
38.7
40.0
54.2
106.1
3.8
1.9
1.3
0.3
0.2
0.1
0.1
+
0.1
54.2
26.7
23.7
1.4
1.7
0.3
0.3
+
1.0
19.4
13.8
5.5
1,695.4
1998
1,648.7
613.8
432.1
290.4
9.3
181.3
32.4
40.5
48.7
103.3
3.7
1.8
1.3
0.3
0.1
0.1
0.1
+
0.2
54.4
26.7
23.7
1.6
1.8
0.3
0.3
+
1.0
24.4
17.4
7.0
1,731.1
1999
1,706.2
622.4
449.2
304.3
10.4
186.7
42.3
41.7
49.3
102.7
3.4
1.7
1.1
0.3
0.2
0.1
0.1
+
0.1
53.7
25.9
23.6
1.7
1.8
0.3
0.3
+
0.9
29.3
20.8
8.5
1,792.5
2000
1,753.1
623.4
452.1
320.4
10.2
193.2
63.1
41.8
48.9
102.2
3.2
1.5
1.0
0.2
0.2
0.1
0.1
+
0.1
52.2
24.7
23.0
1.7
1.9
0.5
0.3
+
0.9
33.8
24.0
9.8
1,842.2
2001
1,734.2
625.7
456.2
327.5
9.6
183.4
42.7
42.8
46.1
98.5
2.9
1.4
0.9
0.2
0.1
0.1
0.1
+
0.1
47.9
23.1
20.6
1.7
1.8
0.3
0.3
+
0.9
37.4
26.7
10.8
1,822.4
2002
1,766.4
639.5
468.1
327.5
9.1
174.9
57.2
41.0
49.0
89.5
2.7
1.2
0.9
0.2
0.1
0.1
0.1
+
0.1
44.5
21.6
18.6
1.8
1.7
0.5
0.3
+
0.8
40.4
28.8
11.5
1,853.9
2003
1,780.7
633.7
478.8
341.2
8.9
171.3
57.5
42.8
46.6
84.2
2.4
1.1
0.8
0.2
0.1
0.1
0.1
+
0.1
40.9
19.9
16.8
1.8
1.7
0.5
0.3
+
0.8
42.7
30.3
12.3
1,866.7
+ Does not exceed 0.05 Tg CO2 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" CO2 emissions include motorcycles, pipelines, and lubricants.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 47
-------
0 Emissions from International Bunker Fuels include emissions from both civilian and military activities, but are not included in
totals.
d Includes primarily HFC-134a.
[BEGIN TEXT BOX]
Box 2-2: Methodology for Aggregating Emissions by Economic Sector
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 were then 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 2004) and fuel sales data (EIA 1991 through 2004). 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.
• Settlement Soil Fertilization, Forest Soil Fertilization. Emissions from settlement soil fertilization were
allocated to the residential economic sector; forest soil fertilization was allocated to the agriculture economic
sector.
[END TEXT BOX]
2.3. 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," and are regulated under the Clean
Air Act in an effort to protect human health and the environment. These pollutants do not have a direct global
warming effect, but indirectly affect terrestrial radiation absorption by influencing the formation and destruction of
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 48
-------
tropospheric and stratospheric ozone, or, in the case of SO2, by affecting the absorptive characteristics of the
atmosphere. Additionally, some of these pollutants may react with other chemical compounds in the atmosphere to
form compounds that are greenhouse gases. 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. Sulfur-containing compounds emitted into the atmosphere tend t exert a negative radiative forcing (i.e.,
cooling) and therefore are discussed separately.
One important indirect climate change effect of NMVOCs and NOX is their role as precursors for tropospheric
ozone formation. They can also alter the atmospheric lifetimes of other greenhouse gases. Another example of
ambient air pollutant formation into greenhouse gases is carbon monoxide's interaction with the hydroxyl
radical—the major atmospheric sink for methane emissions—to form CO2. Therefore, increased atmospheric
concentrations of CO limit the number of hydroxyl molecules (OH) available to destroy methane.
Since 1970, the United States has published estimates of annual emissions of ambient air pollutants (EPA 2004).6
Table 2-18 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.
Table 2-18: Emissions of NOX, CO, NMVOCs, and SO2 (Gg)
Gas/Activity
NOX
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
1990
22,860 x
9,884:5
12,134 ix
139:5
82:5
591 :5
1 |x
28 ! x
oil
130,580 x
4,999 ix
11 9,482 if
302 if
978 if
4, 124 if
4:5
689 i 5
1 if
20,937:5
912 •'{:.
10,933 x:::
555 ^
1997
22,284
: 9,578
: 11,768
: 130
: 140
: 629
: 3
: 34
o
J
101,138
• 3,927
90,284
333
2,668
: 3,153
; 1
; 767
; 5
16,994
5; 1,016
-------
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
222 : x
2,426 ; x
5,217;!
NA;!
673 ; x
20,936 x
18,407;!
793 ; x
390;x
39 ;x
1,306;|
0:5
NA:;V
o ;v, •
:;J 313
i;J 2,038
:i1 5,100
i;} NA
D 157
J 17,091
:;S 15,104
:;; 659
:;; 312
Ij 29
;U 985
•U 1
I NA
X i
326
2,047
4,671
NA
161
17,189
15,191
665
310
30
991
1
NA
1
302
1,813
4,569
NA
140
15,917
13,915
704
283
30
984
1
NA
1
257
1,773
4,384
NA
119
14,829
12,848
632
286
29
1,031
1
NA
1
258
1,769
4,547
NA
122
14,452
12,461
624
289
30
1,047
1
NA
1
281
1,725
4,256
NA
133
13,928
11,946
631
315
24
1,009
2
NA
1
263
1,711
4,138
NA
125
14,463
12,477
634
293
28
1,029
2
NA
1
Source: (EPA 2004) 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.
[BEGIN BOX]
Box 2-3: Sources and Effects of Sulfur Dioxide
Sulfur dioxide (SO2) 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 SO2 is short-lived and unevenly distributed in the atmosphere, its radiative
forcing impacts are highly uncertain.
Sulfur dioxide is also a major contnbutor to the formation of regional haze, which can cause significant increases in
acute and chronic respiratory diseases. Once SO2 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 SO2
emissions in the Clean Air Act.
Electricity generation is the largest anthropogenic source of SO2 emissions in the United States, accounting for 69
percent in 2003. 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 desulfurization equipment.
[END BOX]
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 50
-------
8,000 -,
7,000 -
6,000 -
CT 5,000 -
LU
O 4,000 -
H 3,000 -
2,000 -
1,000 -
0 -
• MFCs, PFCs, & SF 6
Nitrous Oxide
J Methane
• Carbon Dioxide
6'0886,038 6,121 6,251 £343
6,900
6,407 6,6216'678 6'720 6,752 6,807
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Figure 2-1: U.S. Greenhouse Gas Emissions by Gas
4% -
3% -
2% -
1% -
0%
-1% -
-2% -
-3% -
3.3%
3.0%
2.1%
1.4%
0.8% Q.6%
-0.8%
-2.1%
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Figure 2-2: Annual Percent Change in U.S. Greenhouse Gas Emissions
865
770
812
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Figure 2-3: Cumulative Change in U.S. Greenhouse Gas Emissions Relative to 1990
-------
150 -
140 -
I 13° "
7 120 -
§ 110 -
'x' 10° -
I 90 "
80 -
70 -
Real GDP
Population
Emissions per
capita
Emissions per
$GDP
Figure 2-4: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product
Industrial Processes
Waste
3 3,000 -
,CT
H 2,000 -
1,000 -
0
(1,000) -
(2,000) -
Energy
dTUse .Change,a,nd, .ISrestfy .(sinlc
Figure 2-5: U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector
-------
Fossil Fuel Combustion
Natural Gas Systems
Mobile Sources
Coal Mining
Stationary Sources
Waste Combustion
Petroleum Systems
Natural Gas Flaring
5,551.6
Energy as a Portion
of all Emissions
20 40 60 80 100 120 140
TgC02Eq.
Figure 2-6: 2003 Energy Sector Greenhouse Gas Sources
-------
Figure 2-7
2003 U.S. (Tg Eq.)
Note: Totals may not sum due to independent rounding.
The "Balancing Item" above accounts for statistical imbalances and unknowns in the reportei
data sets combined here.
NEU = Non-Energy Use
NG = Natural Gas
-------
2,000 -
a- I'500 -
UJ
O
£ 1,000 -
500 -
0 -
Relative Contribution by
Fuel Type
0)
•a
0)
E
o
3
•a
o
4J
i Natural Gas
: Petroleum
I Coal
Figure 2-8: 2003 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
Note: Electricity generation also includes emissions of less than 1 Tg CO2 Eq. from geothermal-based
electricity generation.
2000
1800
1600
1400
1200
1000
800
600
400
200
0
t' From Electricity
Consumption
• From Direct Fossil
Fuel Combustion
&
Figure 2-9: 2003 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion
-------
Substitution of Ozone Depleting Substances
Iron and Steel Production
Cement Manufacture
Nitric Acid
Ammonia Production and Urea Application
Electrical Transmission and Distribution
Lime Manufacture
HCFC-22 Production
Aluminum Production
Adipic Acid
Limestone and Dolomite Use
Semiconductor Manufacture
Petrochemical Production
Soda Ash Manufacture and Consumption
Magnesium Production and Processing
Titanium Dioxide Production |
Phosphoric Acid Production |
Ferroalloys |
Carbon Dioxide Consumption |
Silicon Carbide Production <0.05
Industrial
Processes
as a Portion of all
Emissions
4.5%
0 10 20 30
40 50 60
Tg C02Eq.
70 80 90 100
Figure 2-10: 2003 Industrial Processes Chapter Greenhouse Gas Sources
-------
Agricultural Soil
Management
Enteric Fermentation
Manure
Management
Rice Cultivation
Agricultural Residue
Burning
I
1.2
50
Agriculture as a
Portion of all
Emissions
6.3%
100 150
Tg C02 Eq
200
250
Figure 2-11: 2003 Agriculture Chapter GHG Sources
Landfills
Wastewater Treatment
Human Sewage
Waste as a Portion of all
Emissions
2.7%
20
40
60 80
Tg C02 Eq
100
120
140
Figure 2-12: 2003 Waste Chapter Greenhouse Gas Sources
-------
cr
LU
(M
O
o
0)
2,500 -,
2,000 -
1 ,500 -
1 ,000 -
500 -
i
n -
Electricity Generation
^ "
^~~- — - I ransportation
;_^^_^^_^
- Industry
^^^- Agriculture
____ .................. — , — -_ Commercial
. , . • • • • — — — , — * • • •
Residential
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Year
Figure 2-13: Emissions Allocated to Economic Sectors
2,500 -,
2,000 -
S 1 >500 -
O
O
1 ,000 -
500 -
o
O)
O)
T- OM
O) O)
O) O)
CO
O)
O)
in to t~~
O) O) O)
O) O) O)
00
O)
O)
O)
O)
O)
O T-
o o
o o
OM OM
Figure 2-14: Emissions with Electricity Distributed to Economic Sectors
OM
O
O
OM
Industrial
Transportation
-Commercial
Residential
Agriculture
CO
o
o
c\i
-------
3. Energy
Energy-related activities were the primary sources of U.S. anthropogenic greenhouse gas emissions, accounting for
86 percent of total emissions on a carbon equivalent basis in 2003. This included 97, 39, and 15 percent of the
nation's carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) emissions, respectively. Energy-related
CO2 emissions alone constituted 83 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 3-1). Globally, approximately 24,240 Tg CO2 were added to the atmosphere
through the combustion of fossil fuels in 2000, of which the United States accounted for about 23 percent.1 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 (see Figure 3-2). 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.
Figure 3-1: 2003 Energy Sector Greenhouse Gas Sources
Figure 3-2: 2003 U.S. Fossil Carbon Flows (Tg CO2 Eq.)
Energy-related activities other than fuel combustion, such as the production, transmission, storage, and distribution
of fossil fuels, also emit greenhouse gases. These emissions consist primarily of 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 within the Land-Use Change and Forestry sector. Emissions of other greenhouse
gases from the combustion of biomass and biomass-based fuels are included in national totals under stationary and
mobile combustion.
Table 3-1 summarizes emissions from the Energy sector in units of teragrams of CO2 equivalents (Tg CO2 Eq.),
while unweighted gas emissions in gigagrams (Gg) are provided in Table 3-2. Overall, emissions due to energy-
related activities were 5,963.4 Tg CO2 Eq. in 2003, an increase of 16 percent since 1990.
Table 3-1: Emissions from Energy (Tg CO2 Eq.)
Gas/Source
C02
Fossil Fuel Combustion
Non-Energy Use of Fuels
Waste Combustion
1990 |;>^
4,836.4 'i ;•-"'
4,711,7 ;»-:
108.0 ::!f-
10.9 ^
1997 1998 1999 2000 2001 2002 2003
5,409.1 5,437.7 5,512.1 5,693.5 5,592.9 5,645.3 5,694.3
5,263,2 5,278,7 5,345,9 5,545,1 5,448,0 5,501,4 5,551,6
120.3 135.4 141.6 124.7 120.1 118.8 118.0
17.8 17.1 17.6 18.0 18.8 18.8 18.8
1 Global CO2 emissions from fossil fuel combustion were taken from Marland et al. (2003)
.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 51
-------
Natural Gas Flaring
Biomass- Wood*
International Bunker Fuels*
Biomass-Ethanol *
CH4
Natural Gas Systems
Coal Mining
Petroleum Systems
Stationary Sources
Mobile Sources
Abandoned Coal Mines
International Bunker Fuels*
N20
Mobile Sources
Stationary Sources
Waste Combustion
International Bunker Fuels*
Total
5.
272.
8 'j-tf
5 '-Vi
113.5 ,$'-,
4.
248.
128.
81.
20.
7.
4.
6.
0.
56.
43.
12.
0.
;.
5,141.
2 :; M
9 v/i;
3 -'A'':,
9 X,V
o '>fi
8 ."^.,
8 >;/
1 ''fi
2 '*''•> ''
4 '}«>'
7 '^i-
3 '*$:;
4 ,';'i"'
0 :«v";;
'^ 'Hv1
7.9
226.3
109.9
7.0
234.6
133.6
62.6
18.8
7.4
4.0
8.1
0.1
69. 1
55.2
13.5
0.4
1.0
5,712.8
6.
209.
6
5
114.6
7.
230.
131.
62.
18.
6.
3.
7.
a
69.
55.
13.
0.
;.
5,737.
7
9
8
8
5
9
9
2
2
1
3
4
3
0
1
6.
274.
105.
8.
222.
127.
58.
17.
7.
3.
7.
a
68.
54.
13.
0.
a
5,802.
9
3
3
0
1
4
9
8
1
6
o
J
;
4
6
5
o
3
P
6
5.8
217.6
101.4
9.2
224.3
132.1
56.2
17.6
7.3
3.4
7.7
0.1
67.5
53.2
14.0
0.4
0.9
5,985.3
6.1
190.8
97.9
9.7
221.6
131.8
55.6
17.4
6.7
3.1
6.9
0.1
62.8
49.0
13.5
0.4
0.9
5,877.3
6.2
195.8
89.5
11.5
215.8
130.6
52.4
17.1
6.4
2.9
6.4
0.1
59.6
45.6
13.5
0.5
0.8
5,920.7
6.0
201.0
84.2
15.8
212.7
125.9
53.8
17.1
6.7
2.7
6.4
0.1
56.4
42.1
13.8
0.5
0.8
5,963.4
* 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.
Table 3-2: Emissions from Energy (Gg)
Gas/Source
CO2
Fossil Fuel Combustion
Non-Energy Use of Fuels
Waste Combustion
Natural Gas Flaring
Biomass- Wood*
International Bunker Fuels*
Biomass-Ethanol *
CH4
N
Natural Gas Systems
Coal Mining
Petroleum Systems
Stationary Sources
Mobile Sources
Abandoned Coal Mines
International Bunker Fuels*
20
Mobile Combustion
Stationary Combustion
Waste Combustion
International Bunker Fuels*
1990],.; 1997
4,836,430 ;
4,711,741 \
107,9649 j
10,919 j
5,805 j
212,547 j
113,503 j
4,155 !:
11,852 J
6,112 \
3,900 \
951 J
373 \
228 ;
288 \
8 j
182 :
141 ;
5,409
5,263
,100
.164
120,300.6
17
7
226
,761
,874
265
109,858
6
11
6
2
40 ;!;
i •';
3 :,'.
978
,170
,363
,983
895
351
193
385
7
223
178
44
1
3
1998
5,437,734
5,278,721
135,352.1
17,094
6,566
209,490
114,557
7,711
10,997
6,276
2,989
879
328
185
341
7
223
179
43
1
3
1999
5,512,062
5,345,904
141,582.9
17,632
6,943
214,323
105,294
8,017
10,577
6,066
2,805
848
338
172
349
6
221
176
43
1
3
2000
5,693
5,545
,544
083
124,713.8
17
5
277
,979
,769
577
101,404
9
10
6
2
188
,680
,289
,677
836
349
161
369
6
218
171
45
1
3
2001
5,592,947
5 447 969
120,104.1
18,781
6,094
190, 776
97,865
9,701
10,551
6,277
2,647
831
318
147
331
5
203
158
43
1
3
2002
5,645,251
5,501,427
118,810.6
18,781
6,233
195, 776
89,489
11,473
10,279
6,221
2,497
815
305
138
303
4
192
147
44
1
3
2003
5,694,332
5,551,580
118,001.4
18,781
5,970
201,042
84,193
15, 771
10,126
5,998
2,561
815
319
128
306
4
182
136
45
1
2
* 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.
3.1. Carbon Dioxide Emissions from Fossil Fuel Combustion (IPCC Source
Category 1A)
Carbon dioxide emissions from fossil fuel combustion in 2003 increased 0.9 percent from the previous year. This
increase is primarily a result of increased demand for fuels due to a growing economy, fuel-switching from natural
gas to coal in the electric power sector, and increased use of heating fuels in the residential sector caused by a colder
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 52
-------
winter. In 2003, CO2 emissions from fossil fuel combustion were 5,551.6 Tg CO2 Eq., or 18 percent above
emissions in 1990 (see Table 3-3).2
Table 3-3: CO2 Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg CO2 Eq.)
Fuel/Sector
1990 |c:;^.
1997
1998
1999
2000
2001
2002
2003
Coal
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Natural Gas
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Petroleum
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Geothermal*
Total
1,680.9
24
121
1526
NE
1,5130
06
1,009.5
238.8
142.6
4163
35.9
1760
NO
2,020.9
983
695
3139
1,4109
101 0
274
0.4
4,711.7 ,
':,;'-"; 1,920.2
IV?' " 1.5
; -i-, ,
,,,,,,> 122
':,;'-t 147.2
;v£" NE
•'::'.! 1,758.4
X'C 1.0
1V£" 1,193.7
::;:Vt 270.2
X-C 174.3
'"''£" 489.1
•::'!, 4i.i
;-','•],' 218.9
:VJ NO
'v^; 2,148.9
X*«V 98.9
r"V *, 50.7
'x':J; 327.4
;-''/,;; 1,562.2
f'fri 74.3
V*;> 35.5
'} °& 0.4
;f> 5,263.2
1,936.5
1.2
8.7
139.2
NE
1,786.4
1.0
1,169.9
246.5
163.5
476.7
35.1
248.0
NO
2,172.0
90.9
47.5
295.6
1,598.3
104.3
35.4
0.4
5,278.7
1,938.2
1.3
9.7
133.8
NE
1,792.4
0.9
1,173.6
256.5
165.2
456.4
35.6
259.9
NO
2,233.7
101.5
47.3
297.8
1,655.2
96.7
35.2
0.4
5,345.9
2,025.6
1.1
8.6
135.0
NE
1,880.0
0.9
1,224.1
270.3
172.4
464.6
35.5
280.7
0.7
2,295.0
107.7
54.2
305.5
1,702.2
91.0
34.3
0.4
5,545.1
1,959.2
1.1
9.2
130.6
NE
1,817.4
0.9
1,174.4
259.7
164.5
426.0
33.9
289.1
1.2
2,314.0
106.2
53.1
321.6
1,685.8
100.9
46.5
0.4
5,448.0
1,973.1
1.0
8.6
122.7
NE
1,839.7
1.2
1,214.0
265.9
168.7
435.5
37.1
305.6
1.2
2,314.0
104.5
52.7
318.4
1,715.2
77.4
45.7
0.4
5,501.4
2,013.8
1.1
9.3
123.4
NE
1,876.3
3.6
1,170.3
277.3
170.7
407.9
35.4
277.6
1.4
2,367.1
106.7
53.9
327.3
1,731.8
96.3
51.2
0.3
5,551.6
NE (Not estimated)
NO (Not occurring)
+ Does not exceed 0.05 Tg
* Although not technically
Note: Totals may not sum
CO2 Eq.
a fossil fuel, geothermal energy-related CO2 emissions are included for reporting purposes.
due to independent rounding.
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 contains the highest amount of carbon per unit of useful
2 An additional discussion of fossil fuel emission trends is presented in the Trends in U.S. Greenhouse Gas Emissions Chapter.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 53
-------
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 3-2). Table 3-4 shows annual changes in emissions during the last six years for coal,
petroleum, and natural gas in selected sectors.
Table 3-4: Annual Change in CO2 Emissions from Fossil Fuel Combustion for Selected Fuels and Sectors (Tg CO2
Eq, and Percent)
Sector
Electricity Generation
Electricity Generation
Electricity Generation
Transportation3
Residential
Commercial
Industrial
Industrial
All Sectors'1
Fuel Type
Coal
Natural Gas
Petroleum
Petroleum
Natural Gas
Natural Gas
Coal
Natural Gas
All Fuelsb
1999 to 2000
87.6
20.8
-5.6
47.0
13.9
7.1
1.1
8.2
199.2
5%
8%
-6%
3%
5%
4%
1%
2%
4%
2000 to
-62
8
9
-16
-10
-7
-4
-38
-97
.6
.4
.8
.4
.7
.9
.4
.5
.1
2001
-3%
3%
11%
-1%
-4%
-5%
-3%
-8%
-2%
2001 to 2002
22
16
-23
29
6
4
-7
9
53
.2
.5
.5
.4
.2
.2
.9
.5
.5
1%
6%
-23%
2%
2%
3%
-6%
2%
1%
2002 to
36.6
-28.0
18.9
16.6
11.5
2.0
0.8
-27.6
50.2
2003
2%
-9%
24%
1%
4%
1%
1%
-6%
1%
a Excludes emissions from International Bunker Fuels.
b Includes fuels and sectors not shown in table.
In the United States, 86 percent of the energy consumed in 2003 was produced through the combustion of fossil
fuels such as coal, natural gas, and petroleum (see Figure 3-3 and Figure 3-4). The remaining portion was supplied
by nuclear electric power (8 percent) and by a variety of renewable energy sources (6 percent), primarily
hydroelectric power and biofuels (EIA 2004a). Specifically, petroleum supplied the largest share of domestic
energy demands, accounting for an average of 39 percent of total energy consumption from 1990 through 2003.
Natural gas and coal followed in order of importance, accounting for 24 and 23 percent of total consumption,
respectively. Petroleum was consumed primarily in the transportation end-use sector, the vast majority of coal was
used in electricity generation, and natural gas was broadly consumed in all end-use sectors except transportation
(see Figure 3-5) (EIA 2004a).
Figure 3-3: 2003 U.S. Energy Consumption by Energy Source
Figure 3-4: U.S. Energy Consumption (Quadrillion Btu)
Figure 3-5: 2003 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
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.4 These other carbon containing non-CO2 gases are emitted as a by-
product of incomplete fuel combustion, but are, for the most part, eventually oxidized to CO2 in the atmosphere.
Therefore, 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.
J Based on national aggregate carbon content of all coal, natural gas, and petroleum fuels combusted in the United States.
4 See the sections entitled Stationary Combustion and Mobile Combustion in this chapter for information on non-CO2 gas
emissions from fossil fuel combustion.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 54
-------
[BEGIN BOX]
Box 3-1: Weather and Non-Fossil Energy Effects on CO2 from Fossil Fuel Combustion Trends
In 2003, weather conditions became cooler in both the winter and summer. Heating degree days in the United
States were 2 percent below normal (see Figure 3-6), while cooling degree days in 2003 were 5 percent above
normal (see Figure 3-7) (EIA 2004f).5 Winter conditions were colder in 2003 than in 2002, which, coupled with a
1.2 percent increase in the U.S. housing stock (EIA 2004f), led to an increase in demand for heating fuels, despite
escalating fuel prices for heating fuels. Though the summer of 2003 was cooler than the near record heat of 2002,
demand for electricity increased most likely due to the growing economy and increase in housing stock.
Figure 3-6: Annual Deviations from Normal Heating Degree Days for the United States (1949-2003)
Figure 3-7: Annual Deviations from Normal Cooling Degree Days for the United States (1949-2003)
Although no new U.S. nuclear power plants have been constructed in recent years, the utilization (i.e., capacity
factors6) of existing plants remained high, at 88 percent in 2003. This utilization level actually represents a 2
percent decrease in electricity output by nuclear plants, down from a record high of 90 percent in 2002. Electricity
output by hydroelectric power plants increased in 2003 by approximately 4 percent. Nevertheless, electricity
generated by nuclear plants in 2003 provided almost 3 times as much of the energy consumed in the United States
as hydroelectric plants (EIA 2004a). Aggregate nuclear and hydroelectric power plant capacity factors since 1973
are shown in Figure 3-8.
Figure 3-8: Aggregate Nuclear and Hydroelectric Power Plant Capacity Factors in the United States (1973-2003)
[END BOX]
For the purpose of international reporting, the IPCC (IPCC/UNEP/OECD/IEA 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), consumption of fuels for non-energy
purposes is estimated and subtracted from total fuel consumption estimates. Emissions from non-energy uses of
fuels are estimated in the Carbon Emitted and Stored in Products from Non-Energy Uses of Fossil Fuels section in
this chapter.
5 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. Heating degree
days have a considerably greater affect on energy demand and related emissions than do cooling degree days. Excludes Alaska
and Hawaii. Normals are based on data from 1971 through 2000. The variation in these normals during this time period was
±10 percent and ±14 percent for heating and cooling degree days, respectively (99 percent confidence interval).
6 The capacity factor is defined as the ratio of the electrical energy produced by a generating unit for a given period of time to
the electrical energy that could have been produced at continuous full-power operation during the same period (EIA 2004a).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 55
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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 international bunker fuel emissions for the United States are
provided in Table 3-5.
Table 3-5: CO2 Emissions from International Bunker Fuels (Tg CO2 Eg.)*
Vehicle Mode
Aviation
Marine
Total
1990
46
67
113
1 ' "u" .*",*'
2. > - ,J
.3 At/
.5 V-.A;,,
1997
55.9
54.0
109.9
1998
56.
57.
114.
7
9
6
1999
58.9
46.4
105.3
2000
60
40
101
.5
.9
.4
2001
59.4
38.5
97.9
2002
61.8
27.7
89.5
2003
59.6
24.6
84.2
* See International Bunker Fuels section for additional detail.
Note: Totals may not sum due to independent rounding.
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 egually 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 egual 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 3-6 and Figure 3-9 summarize CO2 emissions from direct fossil fuel combustion and pro-
rated electricity generation emissions from electricity consumption by end-use sector.
Table 3-6: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eg.)
End-Use Sector
Transportation
Combustion
Electricity
Industrial
Combustion
Electricity
Residential
Combustion
Electricity
Commercial
Combustion
Electricity
U.S. Territories
Total
Electricity Generation
1990 &<&:',. 1997
1,449.8 f" '",,-:; 1,606.4
1,446.81
3.01
1,553.9 1
882.8 1
671.11
924.8 1
339.61
585.3 1
755.1 1
224.2 1
530.91
;• ;-;.•" 1,603.3
',;;.',;;• 3.1
?,';'••', 1,703.0
i'.'V, < 963.8
'•;»;:, 739.2
;", ';•/'.' 1,040.7
i" ,'",';"' 370.6
V '*;";- 670.2
•i's'J'i 876.7
«;'^V" 237.2
/! :!': 639.5
28.0 .%...'. 'C,; 36.4
4,711.7 , -;>?"•- 5,263.2
1,790.3 :"•;, 2,051.9
1998
1,636.5
1,633.4
3.1
1,668.5
911.6
757.0
1,044.4
338.6
705.8
892.9
219.7
673.2
36.3
5,278.7
2,139.0
1999
1,693.9
1,690.8
3.2
1,651.2
888.1
763.1
1,063.5
359.3
704.2
901.2
222.3
678.9
36.2
5,345.9
2,149.3
2000
1,741.0
1,737.7
3.4
1,684.4
905.0
779.4
1,124.2
379.1
745.0
959.5
235.2
724.3
35.9
5,545.1
2,252.1
2001
1,723.1
1,719.7
3.4
1,587.4
878.2
709.3
1,116.2
367.0
749.2
972.7
226.7
745.9
48.6
5,448.0
2,207.8
2002
1,755
1,752
^
.4
.3
.2
1,579.0
876
702
1,145
371
773
973
230
743
48
5,501
2,223
.6
.4
.0
.4
.6
.9
.0
.9
.1
.4
.0
1
1
1
1
5
2
2003
,770
,767
3
,572
858
714
,168
385
783
983
234
749
56
,551
,250
.4
.2
.2
.9
.6
.3
.9
.1
.8
.1
.0
.2
.2
.6
.5
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.
7 See Glossary (Annex 6.8) for more detailed definitions of the industrial, residential, commercial, and transportation end-use
sector, as well as electricity generation.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 56
-------
Figure 3-9: 2003 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion
Transportation End-Use Sector
Using this allocation method, 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 22 percent from 1990 to 2003,
to 1,770.4 Tg CO2 Eq. The growth in transportation end-use sector emissions has been relatively steady, excluding
a 4 percent single year increase in 1999 and slight decreases in 1991 and 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.
In 2003, CO2 emissions from the transportation sector increased by approximately 1 percent. A 12 percent increase
in the price of motor gasoline in 2003 tempered the effects of the growing economy10 on demand for vehicle fuel
(see Figure 3-10).
Since 1990, travel activity in the United States has grown more rapidly than population, with a 16 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 1976 (FHWA 1996 through 2004). 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 3-11).
Figure 3-10: Motor Gasoline Retail Prices (Real)
Figure 3-11: Motor Vehicle Fuel Efficiency
Table 3-7 provides a detailed breakdown of CO2 emissions by fuel category and vehicle type for the transportation
end-use sector. Fifty-nine percent of the emissions from this end-use sector in 2003 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 18 and 12 percent of CO2 emissions from the transportation end-use
sector, respectively.11 For information on transportation-related CO2 emissions from agriculture and construction
equipment, other off-road equipment, and recreational vehicles, please refer to Table 3-36 in Annex 3.2.
Table 3-7: CO2 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg CO2 Eq.)
Fuel/Vehicle Type 1990g^,l: 1997 1998 1999 2000 2001 2002 2003
Gasoline 955.2 ;!*' 1,042.5 1,072.9 1,099.9 1,105.9 1,111.2 1,138.7 1,143.7
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 6.8) for a more detailed definition of the transportation end-use sector.
10 Gross domestic product increased 3.1 percent between 2002 and 2003 (BEA 2004).
11 These percentages include emissions from bunker fuels.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 57
-------
Automobiles
Light-Duty Trucks
Other Trucks
Buses
Motorcycles
Boats (Recreational)
Distillate Fuel Oil (Diesel)
Automobiles
Light-Duty Trucks
Other Trucks
Buses
Locomotives
Ships & Boats
Ships (Bunkers)
Jet Fuel
Commercial Aircraft
Military Aircraft
General Aviation Aircraft
Other Aircraft15
Aircraft (Bunkers)
Aviation Gasoline
General Aviation Aircraft
Residual Fuel Oil
Ships & Boats"
Ships (Bunkers)0
Natural Gas
Automobiles
Light Trucks
Buses
Pipeline
LPG
Light Trucks
Other Trucks
Buses
Electricity
Rail
Total (Including Bunkers)d
Total (Excluding Bunkers)d
605
301
37
0
1
9
265
7
10
178
7
33
16
11
220
117
34
6
15
46
3
3
79
23
55
35
35
1
0
0
3
3
1,563
i •;;*;'' 589
0
7
3
*y
4
.1
4
7
4
5
o
-5
3
4
^4
2
8
3
9
2
t J
,1
.3
^
.8
.9
+
+
+
o
^4
5
O
+
.•,,', 406
.'',; 33
'f1 0
1
.''• 11
"f1 338
• .'. 5
•'•I 15
I",'' 246
.',.;', 8
.''- 37
,£ * ')
16
-' ,->' 9
vS 232
\ 128
->' 21
•'•:, 6
,£ ' 1
20
•>' 55
•;•:,, 2
2
55
-;,, 10
44
i
-'-.;' 41
j '•'")
-'-;• o
!!•',/ 40
'' i.'-v-' °
":' !<,']' °
l'-> ' o
'• , V.
.0 ;^; 3
o .-,;;• 3
.3 : 1,716
1,449.8 '•',') '", 1,606
.8
.1
.3
.4
.7
.2
.4
.6
.1
.2
.6
.0
.9
.1
.1
.5
.0
.1
.6
.9
.7
,7
.5
.6
.9
.1
+
+
.2
.9
.8
.4
.4
+
.1
.1
.2
.4
608.6
416.3
34.6
0.4
1.8
11.2
348.4
5.2
15.4
255.2
8.7
37.4
15.0
11.5
235.6
126.3
21.5
7.7
23.4
56.7
2.4
2,4
52.6
6.2
46.4
35.1
+
+
0.2
34.9
1.0
0.4
0.6
+
3.1
3.1
1,751.1
1,636.5
618.4
432.6
35.7
0.4
1.8
11.1
362.2
4.0
16.3
268.1
9.7
38.5
17.4
8.2
242.9
136.4
20.6
9.2
17.8
58.9
2.7
2,7
51.9
13.7
38.2
35.6
+
+
0.3
35.3
0.8
0.3
0.5
+
3.2
3.2
1,799.2
1,693.9
620.1
435.3
37.3
0.4
1.8
11.2
374.0
3.4
16.6
282.7
9.4
38.4
17.3
6.2
251.2
140.6
21.0
9.2
19.9
60.5
2.5
2,5
69.2
34.6
34.6
35.5
+
+
0.4
35.0
0.7
0.3
0.4
+
3.4
3.4
1,842.5
1,741.0
622.3
438.7
37.1
0.4
1.6
11.2
383.2
3.5
17.2
289.9
8.8
39.4
19.1
5.2
240.4
132.8
22.8
9.0
16.4
59.4
2.4
2,4
45.7
12.4
33.2
33.9
+
+
0.5
33.4
0.8
0.3
0.5
+
3.4
3.4
1,821.0
1,723.1
636.1
450.9
38.7
0.3
1.6
11.1
378.1
3.4
16.9
288.3
8.2
37.9
18.4
5.1
234.4
121.7
20.4
9.3
21.2
61.8
2.3
2,3
50.4
27.7
22.6
37.1
+
+
0.6
36.4
0.9
0.3
0.5
+
3.2
3.2
1,844.9
1,755.4
630.2
460.9
39.6
0.3
1.6
11.0
392.6
3.4
17.6
301.1
8.0
39.6
17.0
6.0
228.6
122.8
20.5
9.4
16.3
59.6
2.2
2,2
48.1
29.5
18.6
35.4
+
+
0.6
34.8
0.8
0.3
0.5
+
3.2
3.2
1,854.6
1,770.4
Note: Totals may not sum due to independent rounding.
a Emissions are no longer allocated to gasoline and diesel consumption from agriculture and construction, and electricity
consumption from pipelines. This based on recognition that EIA statistics account for these activities in the industrial sector.
b This category represents all other jet fuel consumption, and may include some small commercial aircraft and jet fuel used for
heating oil.
0 Fluctuations in emission estimates from the combustion of residual fuel oil are currently unexplained, but may be related to data
collection problems.
d 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.
+ Less than 0.05 Tg CO2 Eq.
Industrial End-Use Sector
The mdustnal end-use sector accounted for 28 percent of CO2 emissions from fossil fuel combustion. On average,
55 percent of these emissions resulted from the direct consumption of fossil fuels for steam and process heat
production. The remaining 45 percent was associated with their consumption of electricity for uses such as motors,
electric furnaces, ovens, and lighting.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 58
-------
The industrial end-use sector includes activities such as manufacturing, construction, mining, and agriculture.12
The largest of these activities in terms of energy consumption is manufacturing, which was estimated in 1998 to
have accounted for about 84 percent of industrial energy consumption (EIA 2001 a). Just six industries—Petroleum,
Chemicals, Primary Metals, 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 is also affected by weather
conditions.13 In addition, structural changes within the U.S. economy that lead to shifts in industrial output away
from energy intensive manufacturing products to less energy intensive products (e.g., from steel to computer
equipment) also have a significant affect on industrial emissions.
From 2002 to 2003, total industrial production and manufacturing output increased slightly, by 0.2 and 0.1 percent,
respectively (FRB 2004). Also from 2002 to 2003, output increased for the Petroleum Refinery, Nonmetallic
Mineral Product, and Chemical industries, but declined for the Primary Metal, Food, and Paper industries (see
Figure 3-12).
Figure 3-12: Industrial Production Indexes (Index 1997=100)
Despite the growth in industrial output (44 percent) and the overall U.S. economy (46 percent) from 1990 to 2003,
emissions from the industrial end-use sector increased only slightly (by 1 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. In 2003, carbon dioxide emissions from fossil
fuel combustion and electricity use within the industrial end-use sectors were 1,572.9 Tg CO2 Eq., or 0.4 percent
below 2002 emissions.
Residential and Commercial End-Use Sectors
The residential and commercial end-use sectors accounted for an average 21 and 18 percent, respectively, of CO2
emissions from fossil fuel combustion. Both end-use sectors were heavily reliant on electricity for meeting energy
needs, with electricity consumption for lighting, heating, air conditioning, and operating appliances contributing to
about 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 component of energy use in both of these end-use
sectors. In 2003, CO2 emissions from fossil fuel combustion and electricity use within the residential and
commercial end-use sectors were 1,168.9 Tg CO2 Eq. and 983.1 Tg CO2 Eq., respectively.
Emissions from the residential and commercial sectors have generally been increasing since 1990, and are often
correlated with short-term fluctuations in energy consumption caused by weather conditions, rather than prevailing
economic conditions (see Table 3-6). 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).
12 See Glossary (Annex 6.8) for a more detailed definition of the industrial end-use sector.
13 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 59
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Emissions from natural gas consumption represent over 70 percent of the direct (not including electricity) fossil fuel
emissions from the residential and commercial sectors. In 2003, these emissions increased by 4 and 1 percent,
respectively, in each of these sectors. Colder winter conditions in the United States (see Figure 3-13) and an
increasing U.S. housing stock led to higher demand for natural gas, despite drastic increases in natural gas prices
(66 percent).
Figure 3-13: Heating Degree Days14
Electricity sales to the residential and commercial end-use sectors in 2003 increased by 1 and 0.4 percent,
respectively. This trend can largely be attnbuted to the growing economy (3.1 percent) and increase in U.S.
housing stock (1.2 percent), which led to increased demand for electricity. Increased consumption due to these
factors was somewhat offset by decreases in air conditioning-related electricity consumption expected with the
cooler summer (see Figure 3-14), and increases in electricity prices (1 and 2 percent higher to the residential and
commercial sectors, respectively). Electricity-related emissions in both sectors rose with increasing consumption
and the higher carbon intensity of electricity generation. Total emissions from the residential sector increased by
2.1 percent in 2003, with emission from the commercial sector 0.9 percent higher than in 2002.
Figure 3-14: Cooling Degree Days15
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 3-15). Electricity generation also
accounted for the largest share of CO2 emissions from fossil fuel combustion, approximately 41 percent in 2003.
Figure 3-15: Electricity Generation Retail Sales by End-Use Sector
The electric power industry includes all power producers, consisting of both regulated utilities and nonutilities (e.g.
independent power producers, qualifying cogenerators, and other small power producers). While utilities primarily
generate power for the U.S. electric grid for sale to retail customers, nonutilities produce electricity for their own
use, to sell to large consumers, or to sell on the wholesale electricity market (e.g., to utilities for distribution and
resale to customers). However, the electric power industry in the United States has undergone 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. As a result, the Department of Energy no longer categorizes
electnc power generation into these ownership groups, and instead uses three functional categories: the electric
power sector, the commercial sector, and the industrial sector. The electric power sector consists of electric utilities
and independent power producers whose primary business is the production of electricity, while the other sectors
consist of those producers that indicate their primary business is other than the production of electricity.
In 2003, the amount of electricity generated decreased very slightly, by 0.3 percent. Although total U.S. electricity
use actually increased by 1 percent, net generation declined due to increased net imports and reduced losses of
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 1971 through 2000.
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 1971 through 2000.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 60
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electricity.16 However, CO2 emissions increased by 1.2 percent, as escalating natural gas prices caused power
producers to switch from natural gas to coal, a more carbon-intensive fuel. Coal consumption for electricity
generation increased by 2.0 percent in 2003, while natural gas consumption decreased by 9.2 percent. As a result of
this shift, carbon intensity from energy consumption for electricity generation increased in 2003 (see Table 3-9).
Coal is consumed primarily by the electric power sector in the United States, which accounted for 93 percent of
total coal consumption for energy purposes in 2003. Electricity generation by nuclear and renewable resources
remained relatively stable, increasing 1 percent in 2003.
[BEGIN BOX]
Box 3-2: Carbon Intensity of U.S. Energy Consumption
Fossil fuels are the dominant source of energy in the United States, and CO2 is emitted as a product from their
combustion. Useful energy, however, can be generated from many other sources that do not emit CO2 in the energy
conversion process. In the United States, useful energy is also produced from renewable (i.e., hydropower,
biofuels, geothermal, solar, and wind) and nuclear sources.17
Energy-related CO2 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.18 Fossil fuels vary in their
average carbon content, ranging from about 53 Tg CO2 Eq./QBtu for natural gas to upwards of 95 Tg CO2 Eq./QBtu
for coal and petroleum coke.19 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 CO2 Eq./Btu). Energy generated from nuclear and many renewable sources do
not result in direct emissions of CO2. Biofuels such as wood and ethanol are also considered to be carbon neutral;
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.20 The
overall carbon intensity of the U.S. economy is thus dependent upon the quantity and combination of fuels and other
energy sources employed to meet demand.
Table 3-8 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
16 EIA statistics track net generation, imports, exports, and compare these with the end use of electricity. The difference
between these values is classified as "T&D losses and Unaccounted for". T&D losses refer to electricity lost during the
transmission and distribution of electricity from the source to the end user. There also exists a small amount of electricity not
accounted for due to data collection time frame differences and nonsampling error.
17 Small quantities of CO2, however, are released from some geologic formations tapped for geothermal energy. These
emissions are included with fossil fuel combustion emissions from the electricity generation. Carbon dioxide emissions may also
be generated from upstream activities (e.g., manufacture of the equipment) associated with fossil fuel and renewable energy
activities, but are not accounted for here.
Generally, more than 97 percent of the carbon in fossil fuel is oxidized to CO2 with most carbon combustion technologies
used in the United States.
19 One exajoule (EJ) is equal to 1018 joules or 0.9478 QBtu.
20 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 61
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natural gas for heating. The carbon intensity of the commercial sector has predominantly declined since 1990 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 CO2 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.
Table 3-8: Carbon Intensity from Direct Fossil Fuel Combustion by Sector (Tg CO2 Eq./QBtu)
Sector
Residential3
Commercial3
Industrial3
Transportation3
Electricity Generation15
U.S. Territories0
All Sectors0
1990 .yy7l' 1997
570
593
66 1
703
858
733
',.fei;' 56.5
57.4
,"*" 65.8
'•'if, 70.1
* .'•?!• 85-9
"''' i TOO
' ,
-------
By comparing the values in Table 3-8 and Table 3-9, 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
thirteen-year period of 1990 through 2003, 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.
The carbon intensity of total energy consumption in the United States has remained fairly constant. Per capita
energy consumption has fluctuated, but has generally demonstrated a constant overall trend since 1990 (see Figure
3-16). Due to a general shift from a manufacturing-based economy to a service-based economy, as well as overall
increases in efficiency, energy consumption and energy-related CO2 emissions per dollar of gross domestic product
(GDP) have both declined since 1990.
Figure 3-16: U.S. Energy Consumption and Energy-Related CO2 Emissions Per Capita and Per Dollar GDP
Carbon intensity estimates were developed using nuclear and renewable energy data from EIA (2004a) and fossil
fuel consumption data as discussed above and presented in Annex 2.1.
[END BOX]
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/IEA 1997). A detailed description of the U.S. methodology
is presented in Annex 2.1, and is characterized by the following steps:
1. Determine total 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.). Fuel
consumption data for the United States were obtained directly from the Energy Information Administration
(EIA) of the U.S. Department of Energy (DOE), primarily from the Monthly Energy Review and unpublished
supplemental tables on petroleum product detail (EIA 2004b). The United States does not include territories in
its national energy statistics, so fuel consumption data for territories were collected separately from Grillot
(2004).22
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.23
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
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 56 Tg CO2 Eq. in 2003.
2j See IPCC Reference Approach for estimating CO2 emissions from fossil fuel combustion in Annex 4 for a comparison of U.S.
estimates using top-down and bottom-up approaches.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 63
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adjusted to correspond to international standard, which are to report energy statistics in terms of net calorific
values (NCV) (i.e., lower heating values).24
2. Subtract uses accounted for in the Industrial Processes chapter. Portions of the fuel consumption data for five
fuel categories—coking coal, petroleum coke, natural gas, residual fuel oil, and other oil—were reallocated to
the industrial processes chapter, as they were consumed during non-energy related industrial activity. To make
these adjustments, additional data were collected from Gambogi (2004), EFMA (1995), U.S. Census Bureau
(1991 through 1994), U.S. Census Bureau (1998 through 2003), U.S. Census Bureau (2003), U.S. Census
Bureau (2004a), EIA (2000 through 2004), EIA (200 Ib), USGS (2003 through 2004), USGS (1998 through
2002), USGS (1995), USGS (1995 through 2004), USGS (1991 through 1994), USGS (1991 through 2003),
U.S. International Trade Commission (2004a), U.S. International Trade Commission (2004b), and Onder and
Bagdoyan(1993).25
3. Adjust for biofuels, conversion of fossil fuels, and exports ofCO2. Fossil fuel consumption estimates are
adjusted downward to exclude 1) fuels with biogenic origins, 2) fuels created from other fossil fuels, and 3)
exports of CO2. Fuels with biogenic origins are assumed to result in no net CO2 emissions, and must be
subtracted from fuel consumption estimates. These fuels include ethanol added to motor gasoline and biomass
gas used as natural gas. Synthetic natural gas is created from industrial coal, and is currently included in EIA
statistics for both coal and natural gas. Therefore, synthetic natural gas is subtracted from energy consumption
statistics.26 Since October 2000, the Dakota Gasification Plant has been exporting CO2 to Canada by pipeline.
Since this CO2 is not emitted to the atmosphere in the United States, energy used to produce this CO2 is
subtracted from energy consumption statistics. To make these adjustments, additional data for ethanol and
biogas were collected from EIA (2004b) and data for synthetic natural gas were collected from EIA (2004e),
and data for CO2 exports were collected from the Dakota Gasification Company (2003), Fitzpatrick (2002), and
Enckson (2003).
4. Adjust for fuels consumed for non-energy uses. U.S. aggregate energy statistics include consumption of fossil
fuels for non-energy purposes. Depending on the end-use, this can result in storage of some or all of the carbon
contained in the fuel for a period of time. As the emission pathways of carbon used for non-energy purposes are
vastly different than fuel combustion, these emissions are estimated separately in the Carbon Emitted and
Stored in Products from Non-Energy Uses of Fossil Fuels section in this chapter. Therefore, the amount of fuels
used for non-energy purposes was subtracted from total fuel consumption. Data on non-fuel consumption was
provided by EIA (2004b).
5. Subtract consumption of 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 the transportation end-use sector, however, so emissions from international transport activities
were calculated separately following 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).27 The Office of the Under Secretary of Defense (Installations and Environment) and the
Defense Energy Support Center (Defense Logistics Agency) of the U.S. Department of Defense (DoD) (DESC
2004) supplied data on military j et fuel use. Commercial j et fuel use was obtained from BE A (1991 through
24 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.
25 See sections on Iron and Steel Production, Ammonia Manufacture, Petrochemical Production, Titanium Dioxide Production,
Ferroalloy Production, and Aluminum Production in the Industrial Processes chapter.
26 These adjustments are explained in greater detail in Annex 2.1.
27 See International Bunker Fuels section in this chapter for a more detailed discussion.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 64
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2004) and DOT (1991 through 2004); residual and distillate fuel use for civilian marine bunkers was obtained
from DOC (1991 through 2004). Consumption of these fuels was subtracted from the corresponding fuels in
the transportation end-use sector. Estimates of international bunker fuel emissions are discussed further in the
section entitled International Bunker Fuels.
6. Determine the total carbon content of fuels consumed. Total carbon was estimated by multiplying the amount
of fuel consumed by the amount of carbon in each fuel. This total carbon estimate defines the maximum
amount of carbon that could potentially be released to the atmosphere if all of the carbon in each fuel was
converted to CO2. The carbon content coefficients used by the United States were obtained from EIA's
Emissions of Greenhouse Gases in the United States 2003 (EIA 2004c) and EIA's Monthly Energy Review and
unpublished supplemental tables on petroleum product detail EIA (EIA 2004b). They are presented in Annexes
2.1 and 2.2.
7. 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 2.1).
Unoxidized or partially oxidized organic (i.e., carbon containing) combustion products were assumed to have
eventually oxidized to CO2 in the atmosphere.28 IPCC provided fraction oxidized values for petroleum and
natural gas (IPCC/UNEP/OECD/IEA 1997). Bechtel (1993) provided the fraction oxidation value for coal.
8. Allocate transportation emissions by vehicle type. This report provides a more detailed accounting of
emissions from transportation because it is such a large consumer of fossil fuels in the United States.29 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. For jet fuel, CO2 emissions were
calculated directly based on reported consumption of fuel. For highway vehicles, annual estimates of combined
motor gasoline and diesel fuel consumption by vehicle category were obtained from FHWA (1996 through
2004); for each vehicle category, the percent gasoline, diesel, and other (e.g., CNG, LPG) fuel consumption are
estimated using data from DOE (1993 through 2004). For non-highway vehicles, activity data were obtained
from AAR (2004), BEA (1991 through 2004), Benson (2002 through 2004), DOE (1993 through 2004), DESC
(2004), DOC (1991 through 2004), DOT (1991 through 2004), EIA (2002a), EIA (2002b), EIA (2004a), EIA
(2004b), EIA (2003 through 2004), EIA (1991 through 2004), EPA (2004c), and FAA (2004). Heat contents
and densities were obtained from EIA (2004a) and USAF (1998).30 The difference between total U.S. jet fuel
consumption (as reported by EIA) and civilian air carrier consumption for both domestic and international
flights (as reported by DOT and BEA) plus military jet fuel consumption is reported as "other" under the jet
fuel category in Table 3-7, and includes such fuel uses as blending with heating oils and fuel used for chartered
aircraft flights.
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.
See Indirect CO2 from CH4 Oxidation section in this chapter for a more detailed discussion.
29 Electricity generation is not considered a final end-use sector, because energy is consumed primarily to provide electricity to
the other sectors.
J° 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 3.2, and Annex 3.7.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 65
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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. For the United States, however, the
impact of these uncertainties on overall CO2 emission estimates is believed to be relatively small. See, for example,
Marland and Pippin (1990).
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.
To calculate the total CO2 emission estimate from energy-related fossil fuel combustion, the amount of fuels used in
these non-energy production processes were subtracted from the total fossil fuel consumption for 2003. The amount
of CO2 emissions resulting from non-energy related fossil fuel use has been calculated separately and reported in the
Carbon Emitted from Non-Energy Uses of Fossil Fuels section of this report. 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. Detailed discussions on the uncertainties
associated with Carbon emitted from Non-Energy Uses of Fossil Fuels can be found within that section of this
chapter.
Various sources of uncertainty surround the estimation of emissions from international bunker fuels, which are
subtracted from the U. S. totals (see the detailed discussions on these uncertainties 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.
Uncertainties in the emission estimates presented above also result from 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 that do not mimic changes in other variables such as shipping ton miles.
The uncertainty analysis was performed by primary fuel type for each end-use sector, using the IPCC-recommended
Tier 2 uncertainty estimation methodology, Monte Carlo Simulation technique, with @RISK software. For this
uncertainty estimation, the inventory estimation model for CO2 from fossil fuel combustion was integrated with the
relevant inventory variables from the inventory estimation model for International Bunker Fuels, to realistically
characterize the interaction (or endogenous correlation) between the variables of these two models. About 150
input variables were modeled for CO2 from energy-related Fossil Fuel Combustion (including about 10 for non-
energy fuel consumption and about 20 for International Bunker Fuels).
In developing the uncertainty estimation model, uniform distributions were assumed for all activity-related input
variables and emission factors, based on the SAIC/EIA (2001) report. ^ Triangular distributions were assigned for
jl SAIC/EIA (2001) characterizes the underlying probability density function for the input variables as a combination of uniform
and normal distributions (the former to represent the bias component and the latter to represent the random component).
However, for purposes of the current uncertainty analysis, it was determined that uniform distribution was more appropriate to
characterize the probability density function underlying each of these variables.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 66
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the oxidization factors (or combustion efficiencies). The uncertainty ranges were assigned to the input variables
based on the data reported in SAIC/EIA (2001) and on conversations with various agency-personnel.-^
The uncertainty ranges for the activity-related input variables were typically asymmetric around their inventory
estimates; the uncertainty ranges for the emissions factors were symmetric. Bias (or systematic uncertainties)
associated with these variables accounted for much of the uncertainties associated with these variables (SAIC/EIA
2001). For purposes of this uncertainty analysis, each input variable was simulated 10,000 times through Monte
Carlo Sampling.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-10. Fossil fuel combustion
CO2 emissions in 2003 were estimated to be between 5,474.3 and 5,863.3 Tg CO2 Eq. at a 95 percent confidence
level (or in 19 out of 20 Monte Carlo Simulations). This indicates a range of 1 percent below to 6 percent above the
2003 emission estimate of 5,551.6 Tg CO2 Eq.
Table 3-10: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Energy-related Fossil Fuel
Combustion by Fuel Type and Sector (Tg CO2 Eq. and Percent)
Fuel/Sector
Coalb
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Natural Gasb
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Petroleum1"
Residential
Commercial
Industrial
Transportation
Electric Utilities
U.S. Territories
2003 Emission
Estimate
(Tg C02 Eq.)
2,013.8
1.1
9.3
123.4
NE
1,876.3
3.6
1,170.3
277.3
170.7
407.9
35.4
277.6
1.4
2,367.1
106.7
53.9
327.3
1,731.8
96.3
51.2
Uncertainty Range Relative to Emission
(Tg C02 Eq.)
Lower Bound
1,962.0
1.1
8.9
120.0
NE
1815.7
3.2
1,161.0
270.5
166.5
396.6
34.5
270.5
1.2
2,256.9
101.7
51.6
283.4
1,627.9
93.8
47.6
Upper Bound
2,220.5
1.3
10.8
144.1
NE
2,072.5
4.3
1,229.9
297.7
183.2
439.0
38.0
292.8
1.7
2,518.5
112.5
56.7
386.0
1,857.2
101.8
57.2
Lower Bound
-3%
-5%
-4%
-3%
NA
-3%
-12%
-1%
-2%
-2%
-3%
-2%
-3%
-12%
-5%
-5%
-4%
-13%
-6%
-3%
-7%
Estimate"
(%)
Upper Bound
+10%
+16%
+16%
+17%
NA
+10%
+20%
+5%
+7%
+7%
+8%
+7%
+5%
+17%
+6%
+6%
+5%
+18%
+7%
+6%
+12%
Total (excluding
Geothermal)b
5,551.2
5,474.0
5,863.0
-1%
+6%
j2 In the SAIC/EIA (2001) report, the quantitative uncertainty estimates were developed for each of the three major fossil fuels
used within each end-use sector; the variations within the sub-fuel types within each end-use sector were not modeled. However,
for purposes of assigning uncertainty estimates to the sub-fuel type categories within each end-use sector in the current
uncertainty analysis, SAIC/EIA (2001)-reported uncertainty estimates were extrapolated.
JJ Although, in general, random uncertainties are the main focus of statistical uncertainty analysis, when the uncertainty
estimates are elicited from experts, their estimates include both random and systematic uncertainties. Hence, both these types of
uncertainties are represented in this uncertainty analysis.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 67
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Geothermal 0.3 NE NE NE NE
Total (including
Geothermal)b'c 5,551.6 5,474.3 5,863.3 -1% +6%
NA (Not Applicable)
NE (Not Estimated)
Notes:
aRange of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
"The low and high estimates for total emissions were calculated separately through simulations and, hence, the low and high
emission estimates for the sub-source categories do not sum to total emissions.
0 Geothermal emissions added for reporting purposes, but an uncertainty analysis was not performed for CO2 emissions from
geothermal production.
QA/QC and Verification
A source-specific QA/QC plan for CO2 from fossil fuel combustion was developed and implemented. This effort
included a Tier 1 analysis, as well as portions of a Tier 2 analysis. The Tier 2 procedures that were implemented
involved checks specifically focusing on the activity data and methodology used for estimating CO2 emissions from
fossil fuel combustion in the United States. Emission totals for the different sectors and fuels were compared and
trends were investigated to determine whether any corrective actions were needed. Minor corrective actions were
taken.
Recalculations Discussion
A major change this year was the decision to report emissions from fuels used for non-energy purposes separately
from fuel combustion emission estimates. Previously, the carbon stored from non-energy uses was subtracted from
total carbon in fuels. However, this method resulted in non-energy emissions being reported within the emission
estimates for fuel combustion. This year, these emissions are reported separately in the section entitled "Carbon
Emitted and Stored in Products from Non-Energy Uses of Fossil Fuels."
Bunker fuel consumption estimates are now subtracted out from total fuel consumption, instead of subtracting the
total carbon in bunker fuels from total potential carbon. This change in methodology does not have any affect on
emission estimates, though it allows for clearer and more transparent emission calculations.
Adjustments are now made to the consumption data for residual oil and other oils (>401 deg F) to subtract
consumption for carbon black production, for which emissions are estimated in the Petrochemical Production
section of the Industrial Processes chapter.
EIA statistics report consumption for non-energy use for a number of fuels to be roughly equivalent to total use of
these fuels, though for certain years these data series did not match exactly. After discussions with EIA, it was
assumed that 100 percent of the use of these fuels should be assumed to be for non-energy purposes. These fuels
are asphalt & road oil, lubricants, naphtha, other oil (>401 deg. F), special naphtha, waxes, and miscellaneous
products.
The Energy Information Administration (EIA 2004a) updated energy consumption data for all years. These
revisions primarily impacted the emission estimates for 2002.
The combination of the methodological and historical data changes, as well as changes in the estimates of Carbon
Emitted and Stored in Products from Non-Energy Uses of Fossil Fuels and International Bunker Fuels (which affect
emissions from this source) resulted in an average annual decrease of 115.8 Tg CO2 Eq. (2.2 percent) in CO2
emissions from fossil fuel combustion for the period 1990 through 2002. This decrease is largely a result of
reporting emissions from non-energy uses separately this year.
Planned Improvements
Several items are being evaluated to improve the estimates of CO2 emissions from fossil fuel combustion and to
reduce uncertainty:
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 68
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• Currently, the IPCC guidelines recommend a default factor of 0.99 to represent the fraction of carbon in fossil
fuels that is oxidized to CO2 during the fuel combustion of petroleum, though national experts are encouraged
to improve upon this assumption if better data is available. As a result, carbon mass balances for light-duty
gasoline cars and trucks have been analyzed to assess what would be the most appropriate carbon oxidation
fraction for these vehicles. The analysis, currently under peer review, suggests that the amount of unoxidized
carbon is insignificant compared to the gaseous carbon fraction, and that 1.00 should be used to represent the
oxidized carbon fraction in future inventories for gasoline fueled light-duty vehicles. Upon further peer review,
the revised factor is expected to be used in future inventories. A further examination into diesel fueled vehicles
is also planned.
• The 0.99 oxidation factor for coal will be further investigated in order to verify or revise this value.
• Efforts will be taken to work with EIA and other agencies to improve the quality of the U. S. territories data.
These improvements are not all-inclusive, but are part of an ongoing analysis and efforts to continually improve the
CO2 from fossil fuel combustion estimates.
3.2. Carbon Emitted from Non-Energy Uses of Fossil Fuels (IPCC Source
Category 1A)
In addition to being combusted for energy, fossil fuels are also consumed for non-energy uses (NEU). These fuels
are used in the industrial and transportation end-use sectors and are quite diverse, including natural gas, liquid
petroleum gases (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, and synthetic fibers.
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, throughout the time series
and across all uses, about 65 percent of the total carbon consumed for non-energy purposes is stored in products,
and not released to the atmosphere; the remaining 35 percent is emitted.
There are several areas in which non-energy uses of fossil fuels relates closely to other parts of the inventory. For
example, some of the NEU products release CO2 at the end of their commercial life when they are combusted; these
emissions are reported separately within this sector in the Waste Combustion source category. In addition, there is
some overlap between fossil fuels consumed for non-energy uses and the fossil-derived CO2 emissions accounted
for in the Industrial Processes sector. To avoid double-counting, the "raw" non-energy fuel consumption data
reported by EIA are modified to account for these overlaps, resulting in the adjusted consumption values shown in
Table 3-12. There are also net exports of petrochemicals that are not completely accounted for in the EIA data, and
these affect the mass of carbon in non-energy applications; the effects of these adjustments are also shown in Table
3-11.
As shown in Table 3-11, fossil fuel emissions in 2003 from the non-energy uses of fossil fuels were 118.0 Tg CO2
Eq., which constituted 2 percent of overall fossil fuel emissions, approximately the same proportion as in 1990. In
2003, the consumption of fuels for non-energy uses (after the adjustments described above) was 5,264 TBtu, an
increase of 24 percent since 1990 (see Table 3-12). About 66.1 Tg of the C (242.5 Tg CO2 Eq.) in these fuels was
stored, while the remaining 32.2 Tg C (118.0 Tg CO2 Eq.) was emitted. The proportion of C emitted has remained
about constant since 1990, at about 31 to 35 percent of total non-energy consumption (see Table 3-13).
Table 3-11: CO2 Emissions from Non-Energy Use Fossil Fuel Consumption (Tg CO2 Eq.)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 69
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Year
Potential Emissions
Carbon Stored
Emissions
1990 1>;
2993 ,,„
191 4 '",•
1080 !u
1997
348.3
228.0
120.3
1998
373.3
238.0
135.4
1999
395.0
253.4
141.6
2000
365.8
241.1
124.7
2001
357.8
237.7
120.1
2002
360.9
242.1
118.8
2003
360.5
242.5
118.0
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. Both the non-energy fuel consumption and
carbon content data were supplied by the EIA (2003) (see Annex 2.1). Consumption of natural gas, LPG, pentanes
plus, naphthas, other oils, and special naphtha were adjusted to account for net exports of these products that are not
reflected in the raw data from EIA. Consumption values for industrial coking coal, petroleum coke, other oils, and
natural gas in Table 3-12 and Table 3-13, have been adjusted to subtract non-energy uses that are included in the
source categories of the Industrial Processes sector.34
For the remaining non-energy uses, the amount of C stored was estimated by multiplying the potential emissions by
a storage factor. For several fuel types—petrochemical feedstocks (natural gas for non-fertilizer uses, LPG,
pentanes plus, naphthas, other oils, still gas, special naphtha, and industrial other coal), asphalt and road oil,
lubricants, and waxes—U.S. data on C stocks and flows were used to develop C storage factors, calculated as the
ratio of (a) the C stored by the fuel's non-energy products to (b) the total C 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. Because losses associated with municipal solid waste management are handled separately
in this sector under the Waste Combustion source category, the storage factors do not account for losses at the
disposal end of the life cycle. For industrial coking coal and distillate fuel oil, storage factors were taken from the
IPCC Guidelines for National Greenhouse Gas Inventories, which in turn draws from Marland and Rotty (1984).
For the remaining fuel types (petroleum coke, miscellaneous products, and other petroleum), IPCC does not provide
guidance on storage factors, and assumptions were made based on the potential fate of carbon in the respective NEU
products.
j4 These source categories include Iron and Steel Production, Ammonia Manufacture, Carbon Black Manufacture (included in
Petrochemical Production), Titanium Dioxide Production, Ferroalloy Production, and Aluminum Production.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 70
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Table 3-12: Adjusted Consumption of Fossil Fuels for Non-Energy Uses (TBtu)
Year
Industry
Industrial Coking Coal
Industrial Other Coal
Natural Gas to Chemical Plants,
Other Uses
Asphalt & Road Oil
LPG
Lubricants
Pentanes Plus
Naphtha (<401 deg. F)
Other Oil (>401 deg. F)
Still Gas
Petroleum Coke
Special Naphtha
Distillate Fuel Oil
Waxes
Miscellaneous Products
Transportation
Lubricants
U.S. Territories
Lubricants
Other Petroleum (Misc. Prod.)
Total
1990 V'
1379 <;t
176.0 ,'-,7
1760 '*t
86.7 ':'•*,
07 ,-!, ;
86,0 ;£;
4,255.9;^
1997
4,794.6
27.6
11.2
323.7
1,223.6
1,440.9
182.3
260.9
467.8
608.8
2.1
29.9
63.8
10.4
43.7
97.8
172.1
172.1
92.5
2.5
90,0
5,059.3
1998
5,127.6
15.4
10.4
376.3
1,262.6
1,568.1
190.8
185.2
529.1
593.8
0.0
124.7
98.1
11.7
42.4
119.0
180.2
180.2
94.8
1.3
93,5
5,402.5
1999
5,398.1
6.3
11.1
390.3
1,324.4
1,651.2
192.8
239.0
458.6
619.5
16.1
193.9
133.9
11.7
37.4
111.9
182.1
182.1
114.5
1.4
113,1
5,694.6
2000
4,985.1
14.8
12.4
388.9
1,275.7
1,497.2
189.9
214.7
556.5
515.5
12.6
53.9
89.1
11.7
33.1
119.3
179.4
179.4
165.5
16.4
149,1
5,330.0
2001
4,933.3
23.7
11.3
394.0
1,256.9
1,483.9
174.0
193.2
473.2
506.1
35.8
132.8
75.5
11.7
36.3
124.9
164.3
164.3
80.3
0.0
80,3
5,177.9
2002
5,016.4
7.0
12.0
402.0
1,240.0
1,550.4
171.9
164.6
559.5
460.9
57.8
113.6
98.7
11.7
32.2
134.2
162.4
162.4
80.6
0.0
80,5
5,259.4
2003
5,023.4
3.0
11.9
401.0
1,217.4
1,478.4
160.8
162.4
588.4
530.0
133.0
90.9
77.5
11.7
31.0
126.0
151.8
151.8
88.7
0.0
88,7
5,263.9
Note: To avoid double-counting, coal coke, petroleum coke, natural gas consumption, and other oils are adjusted for industrial
process consumption reported in the Industrial Processes sector. Natural gas, LPG, Pentanes Plus, Naphthas, Special Naphtha,
and Other Oils are adjusted to account for exports of chemical intermediates derived from these fuels. For residual oil (not
shown in the table), all non-energy use is assumed to be consumed in carbon black production, which is also reported in the
Industrial Processes sector.
- Not applicable.
Note: Totals may not sum due to independent rounding.
Table 3-13: 2003 Adjusted Non-Energy Use Fossil Fuel Consumption, Storage, and Emissions
Sector/Fuel Type Adjusted Carbon
Consumption Content
(TBtu) (Tg C)
Industry
Industrial Coking Coal
Industrial Other Coal
Natural Gas to Chemical Plants
Asphalt & Road Oil
LPG
Lubricants
Pentanes Plus
Naphtha (<401 deg. F)
Other Oil (>401 deg. F)
Still Gas
Petroleum Coke
Special Naphtha
Distillate Fuel Oil
Waxes
Miscellaneous Products
Transportation
Lubricants
5,023.0
3.0
11.9
401.0
1,217.4
1,478.4
160.8
162.4
588.4
530.0
133.0
90.9
77.5
11,7
31.0
126.0
151.8
151.8
93.5
0.1
0.3
5.8
25.1
24.9
o o
J.J
3.0
10.7
10.6
2.3
2.5
1.5
0,2
0.6
2.5
3.1
3.1
Storage Carbon Carbon Carbon
Factor Stored Emissions Emissions
(Tg C) (Tg C) (Tg C02 Eq.)
-
0.75
0.65
0.65
1.00
0.65
0.09
0.65
0.65
0.65
0.65
0.50
0.65
0,50
0.58
0.00
-
0.09
65.7
0.1
0.2
3.8
25.1
16.2
0.3
1.9
6.9
6.9
1.5
1.3
1.0
0,1
0.4
0.0
0.3
0.3
27.8
0.0
0.1
2.0
0.0
8.7
3.0
1.0
3.7
3.7
0.8
1.3
0.5
0,1
0.3
2.5
2.8
2.8
101.8
0.1
0.4
7.4
0.0
31.9
10.8
3.8
13.7
13.5
3.0
4.6
2.0
0,4
0.9
9.3
10.2
10.2
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 71
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U.S. Territories
Lubricants
Other Petroleum (Misc. Prod.)
Total
88.7
0.0
88.7
5,263.9
1.8
0.0
1.8
98.3
0.2
0.09 0.0
0.10 0.2
66.1
1.6
0.0
1.60
32.2
5.9
0.0
5.9
118.0
a To avoid double-counting, coal coke, petroleum coke, natural gas consumption, and other oils are adjusted for industrial
process consumption reported in the Industrial Processes sector. Natural gas, LPG, Pentanes Plus, Naphthas, Special Naphtha,
and Other Oils are adjusted to account for exports of chemical intermediates derived from these fuels. For residual oil (not
shown in the table), all non-energy use is assumed to be consumed in carbon black production, which is also reported in the
Industrial Processes sector.
- Not applicable.
Note: Totals may not sum due to independent rounding.
Lastly, emissions were estimated by subtracting the carbon stored from the potential emissions (see Table 3-11).
More detail on the methodology for calculating storage and emissions from each of these sources is provided in
Annex 2.3.
Where storage factors were calculated specifically for the United States, data were obtained on fuel products such as
asphalt, plastics, synthetic rubber, synthetic fibers, carbon black, personal cleansers, pesticides, and solvents, and
industrial releases including VOC, solvent, and non-combustion CO emissions, TRI releases, refinery wastewater,
hazardous waste incineration, and energy recovery. Data were taken from a variety of industry sources, government
reports, and expert communications. Sources include EPA's compilations of air emission factors (EPA 1995,
2001), National Air Quality and Emissions Trends Report data (EPA 2004a), Toxics Release Inventory, 1998
(2000a), Biennial Reporting System data (EPA 2004b), pesticide sales and use estimates (EPA 1998, 1999, 2002)
and hazardous waste data (EPA 2004b); the EIA Manufacturer's Energy Consumption Survey (MEGS) (EIA 1994,
1997, 2001b); the National Petrochemical & Refiners Association (NPRA 2001); the National Asphalt Pavement
Association (Connolly 2000); the Emissions Inventory Improvement Program (EIIP 1998, 1999); the U.S. Bureau
of the Census (1999, 2003); the American Plastics Council (APC 2000, 2001, 2003; Eldredge-Roebuck 2000); the
Society of the Plastics Industry (SPI 2000); the Rubber Manufacturers' Association (RMA 2002; STMC 2003); the
International Institute of Synthetic Rubber Products (IISRP 2000); the Fiber Economics Bureau (FEE 2001); the;
Material Safety Data Sheets (Miller 1999); and the Chemical Manufacturer's Association (CMA 1999); Specific
data sources are listed in full detail in Annex 2.3.
Uncertainty
A Tier 2 Monte Carlo analysis was performed using @RISK software to determine the level of uncertainty
surrounding the estimates of emissions and storage factors from non-energy uses. The Tier 2 analysis was
performed to allow the specification of probability density functions for key variables, within a computational
structure that mirrors the calculation of the inventory estimate.
As noted above, the non-energy use analysis is based on U.S.-specific storage factors for (1) feedstock materials
(natural gas, LPG, pentanes plus, naphthas, other oils, still gas, special naphthas, and other industrial coal), (2)
asphalt, (3) lubricants, and (4) waxes. For the remaining fuel types (the "other" category), the storage factors were
taken directly from the IPCC Guidelines for National Greenhouse Gas Inventories, where available, and otherwise
assumptions were made based on the potential fate of carbon in the respective NEU products. To characterize
uncertainty, five separate analyses were conducted, corresponding to each of the five categories. In all cases,
statistical analyses or expert judgments of uncertainty were not available directly from the information sources for
all the activity vanables; thus, uncertainty estimates were determined using assumptions based on source category
knowledge.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-14 (emissions) and Table 3-15
(storage factors). Carbon emitted from non-energy uses of fossil fuels in 2003 was estimated to be between 97.5
and 130.9 Tg CO2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Simulations). This indicates
a range of 17 percent below to 11 percent above the 2003 emission estimate of 118.0 Tg CO2 Eq. The uncertainty
in the emission estimates are a function of uncertainty in both the quantity of fuel used for non-energy purposes and
the storage factor.
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Table 3-14: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Non-Energy Uses of Fossil Fuels
(Tg CO, Eq. and Percent)
Source
Feedstocks
Asphalt
Lubricants
Waxes
Other
Total
Gas
CO2
CO2
C02
C02
CO,
CO2
2003 Emission
Estimate
(TgC02Eq.)
75.3
0.0
21.1
0.9
20.9
118.0
Uncertainty Range Relative to
(Tg C02 Eq.)
Lower
Bound
61.0
0.2
17.4
0.7
8.9
97.5
Upper
Bound
90.5
0.9
24.4
1.5
23.2
130.9
Emission
(%)
Lower
Bound
-19%
NA
-17%
-24%
-57%
-17%
Estimate"
Upper
Bound
+20%
NA
+16%
+54%
+11%
+11%
aRange of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
NA (Not Applicable)
Table 3-15: Tier 2 Quantitative Uncertainty Estimates for Storage Factors of Non-Energy Uses of Fossil Fuels
(Percent)
Source
Feedstocks
Asphalt
Lubricants
Waxes
Other
Total
Gas
CO,
CO2
CO,
CO,
CO,
CO2
2003 Storage
Factor
(%)
65%
100%
9%
58%
24%
65%
Uncertainty Range Relative to Inventory Factor"
(%) (%, Relative)
Lower
Bound
63%
99%
4%
44%
18%
63%
Upper
Bound
67%
100%
18%
69%
67%
67%
Lower
Bound
-3%
-1%
-58%
-24%
-24%
-3%
Upper
Bound
+3%
+0%
+90%
+19%
+180%
+3%
aRange of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
In Table 3-15, feedstocks and asphalt contribute least to overall storage factor uncertainty. Although the feedstocks
category—the largest use category in terms of total carbon flows—appears to have tight confidence limits, this is to
some extent an artifact of the way the uncertainty analysis was structured. As discussed in Annex 2.3, the storage
factor for feedstocks is based on an analysis of five fates that result in long-term storage (e.g., plastics production),
and ten that result in emissions (e.g., volatile organic compound emissions). Rather than modeling the total
uncertainty around all 15 of these fate processes, the current analysis addresses only the storage fates, and assumes
that all C that is not stored is emitted. As the production statistics that drive the storage values are relatively well-
characterized, this approach yields a result that is probably biased toward understating uncertainty.
As is the case with the other uncertainty analyses discussed throughout this document, the uncertainty results above
address only those factors that can be readily quantified. More details on the uncertainty analysis are provided in
Annex 2.3.
QA/QC and Verification
A source-specific QA/QC plan for non-energy uses of fossil fuels was developed and implemented. This effort
included a Tier 1 analysis, as well as portions of a Tier 2 analysis for non-energy uses involving petrochemical
feedstocks. The Tier 2 procedures that were implemented involved checks specifically focusing on the activity data
and methodology for estimating the fate of C (in terms of storage and emissions) across the various end-uses of
fossil carbon. Emission and storage totals for the different subcategories were compared, and trends across the time
series were carefully analyzed to determine whether any corrective actions were needed. Corrective actions were
taken to rectify minor errors and to improve the transparency of the calculations, facilitating future QA/QC.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 73
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Recalculations Discussion
This year's methodology reflects several refinements and improvements. First and most fundamentally, this year
the NEU analysis is presented as its own source category. In the past, the NEU component of this category was
described in the context of a calculation sequence that first determined potential emissions (based on total fuel
consumption for all purposes), and then deducted (1) C not oxidized (e.g., in ash) and (2) C put into long-term
storage as a result of NEUs. In this context, the focus of the NEU section was previously on carbon storage rather
than emissions. This year, the presentation within this source category emphasizes emissions, though the storage
factors (i.e., fraction of C stored rather than emitted) are still presented to facilitate comparison with IPCC guidance.
Several substantive changes also appear in this year's inventory. First, a U. S.-specific storage factor (58 percent)
was developed for waxes. Previously, the IPCC storage factor for wax (100 percent stored) had been used.
In addition, the methodology for calculating emissions and storage for feedstocks has been revised in several ways.
First, three additional fuel types have been added as inputs to the system covered by the feedstocks mass balance
calculations: other industrial coal, still gas, and special naphthas. The other significant improvement for feedstocks
is that the estimates of U.S. plastics consumption have been revised: in previous years, the consumption data for
some of the plastic resins in the dataset included consumption in Canada and Mexico. By adjusting the data to
reflect U.S. (rather than North American) consumption for those resins, the accuracy of the estimate for feedstocks
has improved. In addition, several minor adjustments were made (e.g., the calculations for storage now include
synthetic rubber in durable and non-durable goods other than tires, and the calculations for emissions include losses
due to abrasion/ oxidation of rubber from tires).
As noted in the beginning of the section, there are several areas where the boundaries of the NEU analysis adjoin
the systems covered within the Industrial Processes sector. Carbon black production has been removed from the
NEU analysis, as it is now addressed as a subcategory of IP-petrochemical emissions (if it was retained in NEU,
there would be double-counting). As a result of this change, residual oil—which is an input to carbon black
production, and had been among the fuels covered in the NEU section in previous years—no longer appears in the
list of fuels in this section. A portion of other oils is also assumed to be used in the production of carbon black, and
therefore other oils consumption is adjusted to account for the amount of fuel used in the C black calculation.
The storage factor for miscellaneous products also changed. In prior years, a value of 100 percent was used; in this
year's inventory, based on a review of the specific applications of these products, there is now assumed to be no
storage at all from these products.
There have been several updates to the data used to calculate storage factors, not only by adding information for
2003 (where available) but also for updating data sets for earlier years. For example, the results reflect new data for
hazardous waste incineration (1999 through 2001) and fiber production (2001 through 2002).
Planned Improvements
There are several improvements planned for the future:
• Collecting additional information on energy recovery from Manufacturing Energy Consumption Surveys. An
effort is planned to carefully examine the "microdata" from these surveys to determine the nature and quantity
of materials initially identified as being destined for "non-energy use" that are actually combusted for energy
recovery.
• Improving the uncertainty analysis. Most of the input parameter distributions are based on professional
judgment rather than rigorous statistical characterizations of uncertainty.
• Better characterizing flows of fossil carbon. Additional "fates" may be researched, including: the fossil carbon
load in organic chemical wastewaters; an expanded import and export analysis (i.e., evaluating additional
commodities); and improving the characterization of cleansers (to exclude any potential biogenic carbon
sources).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 74
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Finally, although U.S.-specific storage factors have been developed for feedstocks, asphalt, lubricants, and waxes,
default values from IPCC are still used for two of the non-energy fuel types (industrial coking coal and distillate
oil), and broad assumptions are being used for the remaining fuels (petroleum coke, miscellaneous products, and
other petroleum). Over the long term, there are plans to improve these storage factors by conducting analyses of C
fate similar to those described in Annex 2.3.
3.3. Stationary Combustion (excluding CO2) (IPCC Source Category 1A)
Stationary combustion encompasses all fuel combustion activities from fixed sources (versus 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.35 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-fuel mixes and combustion
temperatures, as well as the characteristics of any pollution control equipment that is employed. Carbon monoxide
emissions from stationary combustion are generally a function of the efficiency of combustion; they are highest
when less oxygen is present in the air-fuel mixture than is necessary for complete combustion. These conditions are
most likely to occur during start-up, shutdown and during fuel switching (e.g., the switching of coal grades at a
coal-burning electric utility plant). Methane and NMVOC emissions from stationary combustion are primarily a
function of the CH4 and NMVOC content of the fuel and combustion efficiency.
Emissions of CH4 decreased 15 percent overall to 6.7 Tg CO2Eq. (319 Gg) in 2003. 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 13.8 Tg CO2 Eq. (45 Gg) in 2003. The largest source of N2O emissions was coal
combustion by electricity generators, which alone accounted for 63 percent of total N2O emissions from stationary
combustion in 2003. Overall, however, stationary combustion is a small source of CH4 and N2O in the United
States.
In contrast, stationary combustion is a significant source of NOX emissions, though a smaller source of CO and
NMVOCs. In 2003, emissions of NOX from stationary combustion represented 39 percent of national NOX
emissions, while CO and NMVOC emissions from stationary combustion contributed approximately 5 and 7
percent, respectively, to the national totals. From 1990 to 2003, emissions of NOX and CO from stationary
combustion decreased by 27 and 11 percent, respectively, and emissions of NMVOCs increased by 10 percent.
The decrease in NOX emissions from 1990 to 2003 are mainly due to decreased emissions from electric power. 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 3-16 through Table 3-19 provide CH4 and N2O emission estimates from stationary combustion
by sector and fuel type. Estimates of NOX, CO, and NMVOC emissions in 2003 are given in Table 3-20.36
Table 3-16: CH4 Emissions from Stationary Combustion (Tg CO2 Eq.)
Sector/Fuel Type
Electric Power
Coal
Fuel Oil
Natural gas
1990 xv
0
0
0
0
.6 >;.
.3 •/>:
1 •:''?
1 "f,
1997
0.6
0.4
0.1
0.1
1998
0
0
0
0
.7
.4
.1
.1
1999
0.7
0.4
0.1
0.1
2000
0.7
0.4
0.1
0.1
2001
0
0
0
0
.7
.4
.1
.1
2002
0.7
0.4
0.1
0.1
2003
0.7
0.4
0.1
0.1
Sulfur dioxide (SO2) emissions from stationary combustion are addressed in Annex 6.3.
See Annex 3.1 for a complete time series of ambient air pollutant emission estimates for 1990 through 2003.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 75
-------
Wood
Industrial
Coal
Fuel Oil
Natural gas
Wood
Commercial
Coal
Fuel Oil
Natural gas
Wood
Residential
Coal
Fuel Oil
Natural Gas
Wood
U.S. Territories
Coal
Fuel Oil
Natural Gas
Wood
Total
+ Does not exceed 0.05 Tg CO2
o i ';i(;-
2.1 •','/;
03 ,•?!
o i ''"),:"
os -\\\
09 ,'?!
0.7 ';•;;
+ -vr''.
02 ,-;?:
03 '',•;;;
02 •'>{.:
4.4 •';?>
•> i
0 2 ,;;;
03 •'>{.'.
05 .-;
3 5 _',;>,
+ "''\,
+ ;^.'f,
+ '.;'t,
+ :'"^l
+ i :'T;;
7.8 .?";> ,
Eq.
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
0.1
+
0.1
+
+
7.4
0.1
2.3
0.3
0.1
0.9
1.0
0.8
+
0.1
0.3
0.3
3.1
0.1
0.3
0.5
2.3
0.1
+
0.1
+
+
6.9
0.1
2.2
0.3
0.1
0.9
1.0
0.8
+
0.1
0.3
0.3
3.4
0.1
0.3
0.5
2.5
0.1
+
0.1
+
+
7.1
0.1
2.3
0.3
0.1
0.9
1.0
0.8
+
0.2
0.3
0.3
3.5
0.1
0.3
0.5
2.6
0.1
+
+
+
+
7.3
0.1
2.1
0.3
0.1
0.8
0.9
0.7
+
0.2
0.3
0.2
3.1
0.1
0.3
0.5
2.2
0.1
+
0.1
+
+
6.7
0.1
2.1
0.3
0.1
0.8
0.9
0.7
+
0.2
0.3
0.3
2.8
0.1
0.3
0.5
1.9
0.1
+
0.1
+
+
6.4
0.1
2.1
0.3
0.1
0.8
0.9
0.8
+
0.2
0.3
0.3
3.1
0.1
0.3
0.5
2.1
0.1
+
0.1
+
+
6.7
Note: Totals may not sum due to independent rounding.
Table 3-17: N2O Emissions
Sector/Fuel Type
Electric Power
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
U.S. Territories
Coal
Fuel Oil
Natural Gas
Wood
Total
+ Does not exceed 0.05 Tg CO2
from Stationary
1990 v;
7.6 ;,"-,.).'
7 1 •''"'•'
' if"l 'n
0 2 ?->:'"t
0 1 1'^j
02;'^''.'
3.2;v':-'
0 7 1^*1
0 5 ;',/.'
0.2 p. "':s
1 7 ;,<2*;
0.4 ;';!/.
0 H:>"':8
02^*;
o i i ,',./.
+ ;-«::
i.if.^:*;
+K-, '-,
0 3?-""1
o i \!'^l
o 7 [(*-, ;.,
0. if '""•'"
+ ?'y~
o i \y
+ •''";;'"
A ft ,VJ^ !
12.3 K.'
Eq.
Combustion (Tg
1997
8.6
8.2
0.2
0.1
0.2
3.5
0.7
0.5
0,3
2.0
0.3
0.1
0.1
0.1
0.1
0.9
+
0.3
0.2
0.5
0.1
+
0.1
+
+
13.5
1998
8.9
8.3
0.2
0.1
0.2
3.3
0.7
0.5
0,3
1.9
0.3
+
0.1
0.1
0.1
0.8
+
0.2
0.1
0.5
0.1
+
0.1
+
+
13.4
; CO2 Eq.
1999
8.9
8.3
0.2
0.1
0.2
3.3
0.6
0.5
0,3
1.9
0.3
+
0.1
0.1
0.1
0.9
+
0.3
0.1
0.5
0.1
+
0.1
+
+
13.5
)
2000
9.3
8.7
0.2
0.2
0.2
3.3
0.6
0.5
0,3
1.9
0.3
+
0.1
0.1
0.1
1.0
+
0.3
0.2
0.5
0.1
+
0.1
+
+
14.0
2001
9.0
8.5
0.2
0.2
0.1
3.1
0.6
0.6
0,2
1.7
0.3
+
0.1
0.1
+
0.9
+
0.3
0.1
0.4
0.1
+
0.1
+
+
13.5
2002
9.1
8.6
0.2
0.2
0.2
3.2
0.6
0.6
0,2
1.8
0.3
+
0.1
0.1
+
0.8
+
0.3
0.1
0.4
0.1
+
0.1
+
+
13.5
2003
9.3
8.7
0.2
0.2
0.2
3.2
0.6
0.6
0,2
1.8
0.3
+
0.1
0.1
+
0.9
+
0.3
0.2
0.4
0.1
+
0.1
+
+
13.8
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 76
-------
Note: Totals may not sum due to independent rounding.
Table 3-18: CH4 Emissions from Stationary Combustion (Gg)
Sector/Fuel Type
Electric Power
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
U.S. Territories
Coal
Fuel Oil
Natural Gas
Wood
Total
+ Does not exceed 0.5 Gg
1990 •£*;,
27 ';•;;'
16 -\\\
4 ,•?!
3 "',;;;'
4 -\\\
101 X^
17 ',;-'
6 •'>{„'
37 /'?>•
41 U;
35 ;>^
1 ,*7:
•>'i
10 ,;v.
13 ;'^
*JXS
•>'l
209 .V.
8 'Vi"
14 .•;•?'
21 '•;>,
166 ;'V!
2 .'!"!?
+ t*f!
2 ''•':?
+ :V,'
+ • '•;
373 IS ;|
1997
29
19
3
4
4
115
16
6
44
49
38
1
7
16
14
167
5
14
24
123
2
+
2
+
+
351
1998
31
19
4
4
4
108
15
5
43
46
36
1
7
15
14
150
4
13
22
110
2
+
2
+
+
328
1999
31
19
4
5
4
107
14
5
41
46
37
1
7
15
15
160
4
15
23
118
2
+
2
+
+
338
2000
32
20
3
5
4
108
15
6
42
47
39
1
8
16
15
167
4
16
24
123
2
+
2
+
+
349
2001
32
19
4
5
4
100
14
6
38
41
35
1
7
15
12
148
4
15
23
105
3
+
3
+
+
318
2002
32
20
3
5
4
102
13
6
39
44
35
1
7
15
12
132
3
15
24
89
3
+
3
+
+
305
2003
33
20
4
5
5
100
13
6
37
43
36
1
8
15
12
146
4
15
25
102
4
+
3
+
+
319
Note: Totals may not sum due to independent rounding.
Table 3-19: N2O Emissions
Sector/Fuel Type
Electricity Generation
Coal
Fuel Oil
Natural Gas
Wood
Industrial
Coal
Fuel Oil
Natural Gas
Wood
Commercial
Coal
Fuel Oil
Natural Gas
Wood
Residential
Coal
Fuel Oil
Natural Gas
from Stationary
1990 U\
24 t',i' •'•',
23 ,/-;,,;
1 ; ;?„ '.•
+ t',V""<
+ 1''''1',
ior;x%;,
2 t- ,<;?••
2 ; ' '•" "i
i f 3is;
5^<
1 C:'''':''
+ cH \'
i •"',«>'
'"'..i.jh**1'
+ !>'/;"-'
4;;:*v';
+ ;" v'-'
1 ^'-v"
'/" "-"ti
Combustion (Gg)
1997
28
26
1
+
1
11
2
2
1
7
1
+
+
+
+
3
+
1
1998
29
27
1
+
1
11
2
2
1
6
1
+
+
+
+
3
+
1
1999
29
27
1
+
1
11
2
2
1
6
1
+
+
+
+
3
+
1
2000
30
28
1
1
1
11
2
2
1
6
1
+
+
+
+
3
+
1
2001
29
27
1
1
+
10
2
2
1
5
1
+
+
+
+
3
+
1
2002
29
28
1
1
1
10
2
2
1
6
1
+
+
+
+
3
+
1
2003
30
28
1
+
1
10
2
2
1
6
1
+
+
+
+
3
+
1
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 77
-------
Wood
U.S. Territories
Coal
Fuel Oil
Natural Gas
Wood
Total
2 »;.y, 2122111
+ "'"' , + + + + + + +
+ .^'l + + + + + + +
+ '.;•$,; + + + + + + +
+ ">\/, + + + + + + +
+ '.':.;; + + + + + + +
40 :"• ; 44 43 43 45 43 44 45
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding.
Table 3-20: NOX, CO, and NMVOC Emissions from Stationary Combustion in 2003 (Gg)
Sector/Fuel Type
Electric Generation
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Industrial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Residential
Coalb
Fuel Oilb
Natural Gasb
Wood
Other Fuels
Total
NOX
4,045
3,447
135
301
34
NA
127
2,516
522
154
920
NA
116
803
244
19
49
155
NA
21
417
NA
NA
NA
20
397
7,222
CO
480
240
30
101
NA
35
73
1,249
138
50
402
NA
353
307
149
13
17
82
NA
37
2,575
NA
NA
NA
2,358
217
4,454
NMVOC
50
24
4
11
NA
2
10
154
10
8
52
NA
28
55
29
1
3
13
NA
11
773
NA
NA
NA
748
25
1,007
NA (Not Available)
a Includes LPG, waste oil, coke oven gas, and coke (EPA 2003), (EPA 2004a).
b Residential coal, fuel oil, and natural gas emissions are included in "Other Fuels" (EPA 2003), (EPA 2004a).
Note: Totals may not sum due to independent rounding. See Annex 3.1 for emissions in 1990 through 2003.
Methodology
Methane and N2O emissions were estimated by multiplying fossil fuel and wood consumption data by emission
factors (by sector and fuel type). National coal, natural gas, fuel oil, and wood consumption data were grouped by
sector: industrial, commercial, residential, electric power, and U.S. territories. For the CH4 and N2O estimates, fuel
consumption data for the United States were obtained from EIA's Monthly Energy Review and unpublished
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 78
-------
supplemental tables on petroleum product detail (EIA 2004). Because the United States does not include territories
in its national energy statistics, fuel consumption data for territories were provided separately by the Grillot
(2004).37 Fuel consumption for the industrial sector was adjusted to subtract out construction and agricultural use,
which is reported under mobile sources.38 Construction and agricultural fuel use was obtained from EPA (2004b).
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 for the four end-use sectors were provided by the Revised 1996IPCC Guidelines for National
Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997). U.S. territories' emission factors were estimated
using the U.S. emission factors for the primary sector in which each fuel was combusted.
Emission estimates for NOX, CO, and NMVOCs in this section were obtained from preliminary data (EPA 2004a)
and disaggregated based on EPA (2003), which, in its final iteration, will be published on the National Emission
Inventory (NEI) Air Pollutant Emission Trends web site. The major categories included in this section are those
reported in EPA (2003) and EPA (2004a): 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.
The overall emission control efficiency of a source category was derived 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 3.1.
Uncertainty
Methane emission estimates from stationary sources exhibit high uncertainty, 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).
An uncertainty analysis was performed by primary fuel type for each end-use sector, using the IPCC-recommended
Tier 2 uncertainty estimation methodology, Monte Carlo Simulation technique, with @RISK software.
The uncertainty estimation model for this source category was developed by integrating the CH4 and N2O stationary
source inventory estimation models with the model for CO2 from fossil fuel combustion to realistically characterize
the interaction (or endogenous correlation) between the variables of these three models. A total of 115 input
variables were simulated for the uncertainty analysis of this source category (85 from the CO2 emissions from fossil
fuel combustion inventory estimation model and 30 from the stationary source inventory models).
j7 U.S. territories data also include combustion from mobile activities because data to allocate territories' energy use were
unavailable. For this reason, CH4 and N2O emissions from combustion by U.S. territories are only included in the stationary
combustion totals.
38 Though emissions from construction and farm use occur due to both stationary and mobile sources, detailed data was not
available to determine the magnitude from each. Currently, these emissions are assumed to be predominantly from mobile
sources.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 79
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In developing the uncertainty estimation model, uniform distribution was assumed for all activity-related input
variables and N2O emission factors, based on the SAIC/EIA (2001) report.-'" For these variables, the uncertainty
ranges were assigned to the input variables based on the data reported in SAIC/EIA (2001). However, the CH4
emission factors differ from those used by EIA. Since these factors were obtained from IPCC/UNEP/OECD/IEA
(1997), uncertainty ranges were assigned based on IPCC default uncertainty estimates (IPCC Good Practice
Guidance 2000).
The uncertainty ranges for the activity-related input variables and N2O emission factors were typically asymmetric
around their inventory estimates. The uncertainty ranges for the non-biomass-related CH4 emission factors were
symmetric around their inventory estimates; for biomass, they were asymmetric around their emission factor
estimates. Bias (or systematic uncertainties) associated with these variables accounted for much of the uncertainty
associated with the activity data and N2O emission factor variables. 1 For purposes of this uncertainty analysis,
each input variable was simulated 10,000 times through Monte Carlo sampling.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-21. Stationary combustion
CH4 emissions in 2003 (including biomass) were estimated to be between 4.8 and 13.4 Tg CO2 Eq. at a 95 percent
confidence level (or in 19 out of 20 Monte Carlo Simulations). This indicates a range of 28 percent below to 99
percent above the 2003 emission estimate of 6.7 Tg CO2 Eq.42 Stationary combustion N2O emissions in 2003
(including biomass) were estimated to be between 10.9 and 39.5 Tg CO2 Eq. at a 95 percent confidence level (or in
19 out of 20 Monte Carlo Simulations). This indicates a range of 22 percent below to 184 percent above the 2003
emissions estimate of 13.8 Tg CO2 Eq.
Table 3-21: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Energy-Related Stationary
Combustion, Including Biomass (Tg CO2 Eq. and Percent)
Source
Stationary Combustion
Stationary Combustion
Gas
CH4
N2O
2003 Emission
Estimate
(Tg C02 Eq.)
6.7
13.8
Uncertainty Range Relative to
(Tg C02 Eq.)
Lower Upper
Bound Bound
4.8 13.4
10.9 39.5
Emission Estimate"
(%)
Lower Upper
Bound Bound
-28% +99%
-22% +184%
a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
The uncertainties associated with the emission estimates of CH4 and N2O are greater than those associated 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
j9 SAIC/EIA(2001) characterizes the underlying probability density function for the input variables as a combination of uniform
and normal distributions (the former distribution to represent the bias component and the latter to represent the random
component). However, for purposes of the current uncertainty analysis, it was determined that uniform distribution was more
appropriate to characterize the probability density function underlying each of these variables.
40 In the SAIC/EIA (2001) report, the quantitative uncertainty estimates were developed for each of the three major fossil fuels
used within each end-use sector; the variations within the sub-fuel types within each end-use sector were not modeled. However,
for purposes of assigning uncertainty estimates to the sub-fuel type categories within each end-use sector in the current
uncertainty analysis, SAIC/EIA (2001)-reported uncertainty estimates were extrapolated.
41 Although, in general, random uncertainties are the main focus of statistical uncertainty analysis, when the uncertainty
estimates are elicited from experts, their estimates include both random and systematic uncertainties. Hence, both these types of
uncertainties are represented in this uncertainty analysis.
42 The low emission estimates reported in this section have been rounded down to the nearest integer values and the high
emission estimates have been rounded up to the nearest integer values.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 80
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partly due to assumptions concerning combustion technology types, age of equipment, emission factors used, and
activity data projections.
QA/QC and Verification
A source-specific QA/QC plan for stationary combustion was developed and implemented. This effort included a
Tier 1 analysis, as well as portions of a Tier 2 analysis. The Tier 2 procedures that were implemented involved
checks specifically focusing on the activity data and emission factor sources and methodology used for estimating
CH4, N2O, and the ambient air pollutants from stationary combustion in the United States. Emission totals for the
different sectors and fuels were compared and trends were investigated.
A few corrective actions were taken. It was determined that emissions from construction and farm use had been
previously estimated in both this source category (in the industrial sector) and for mobile sources. To avoid double-
counting, these emissions are now reported only under mobile sources. Therefore, it was necessary to subtract out
energy consumption from construction and agriculture from the industrial sector. Also, a small error was corrected
in the conversion of natural gas and wood energy consumption from gross calorific value to net calorific value.
Recalculations Discussion
Historical CH4 and N2O emissions from stationary sources (excluding CO2) were revised due to several changes.
First, industrial sector energy consumption was adjusted downward to avoid double-counting of emissions from
construction and agriculture. Second, the conversion of natural gas and wood energy consumption from gross
calorific value to net calorific value was corrected. These adjustments have been explained in the previous section.
Third, slight changes to emission estimates for the other sectors are due to revised data from EIA (2004). This latter
revision is explained in greater detail in the section on CO2 Emissions from Fossil Fuel Combustion within this
sector. The combination of the methodological and historical data changes resulted in an average annual decrease
of 0.4 Tg CO2 Eq. (5.2 percent) in CH4 emissions from stationary combustion and an average annual decrease of 0.4
Tg CO2 Eq. (3.2 percent) in N2O emissions from stationary combustion for the period 1990 through 2002.
Planned Improvements
Several items are being evaluated to improve the CH4 and N2O emission estimates from stationary source
combustion and to reduce uncertainty. Efforts will be taken to work with EIA and other agencies to improve the
quality of the U.S. territories data. Because these data are not broken out by stationary and mobile uses, further
research will be aimed at trying to allocate consumption appropriately. In addition, the uncertainty of biomass
emissions will be further investigated. Currently, the exclusion of biomass increases the uncertainty, although it
was expected to reduce the uncertainty. These improvements are not all-inclusive, but are part of an ongoing
analysis and efforts to continually improve these stationary estimates.
3.4. Mobile Combustion (excluding CO2) (IPCC Source Category 1A)
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 gases 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 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 81
-------
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
3-22 and Table 3-23 provide CH4 and N2O emission estimates, respectively, in Tg CO2Eq.; Table 3-24 and Table
3-25 present these estimates in Gg of each gas. Estimates of NOX, CO, and NMVOC emissions are given in Table
3-26 through Table 3-28.43
Mobile combustion was responsible for a small portion of national CH4 emissions (0.5 percent) but was the second
largest source of N2O (11.2 percent) in the United States. From 1990 to 2003, CH4 emissions declined by 44
percent, to 2.7 Tg CO2 Eq. (128 Gg), due largely to control technologies employed on highway vehicles in the
United States that reduce CO, NOX, NMVOC, and CH4 emissions. The same technologies, however, resulted in
higher N2O emissions, causing a 27 percent increase in N2O emissions from mobile sources between 1990 and
1998. Nitrous oxide emissions have subsequently declined 24 percent as improvements in the emission control
technologies installed on new vehicles have reduced emission rates of both NOX and N2O per vehicle mile traveled.
As a result, N2O emissions in 2003 were 4 percent lower than in 1990, at 42.1 Tg CO2 Eq. (136 Gg) (see Figure
3-17). Overall, CH4 and N2O emissions were predominantly from gasoline-fueled passenger cars and light-duty
gasoline trucks.
Figure 3-17: Mobile Source CH4 and N2O Emissions
Table 3-22: CH4 Emissions from Mobile Combustion (Tg CO2 Eq.)
Fuel Type/Vehicle Type"
1990 i;
1997 1998 1999 2000 2001 2002 2003
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
Otherb
4.3
26
1 4
03
+
+
+
+
+
+
0.5
0 1
0 1
02
01
+
+
i
;
'*
i'i
f-.
*'f
*fi
'',-'
/•""
f">'
'/I
f'."
/•""
/(''
»*•>'<
1'.""
'* f
f, ffV
,''°VT
V ^
3.5
1.9
1.3
0.2
+
+
+
+
+
0.1
0.5
0.1
0.1
0.2
0.1
0.1
+
3.3
1.8
1.3
0.2
+
+
+
+
+
0.1
0.5
0.1
0.1
0.1
0.1
0.1
+
3.0
1.7
1.1
0.2
+
+
+
+
+
0.1
0.5
0.1
0.1
0.2
0.1
0.1
+
2.7
1.5
1.0
0.1
+
+
+
+
+
0.1
0.5
0.1
0.1
0.2
0.1
0.1
+
2.4
1.4
0.9
0.1
+
+
+
+
+
0.1
0.5
0.1
0.1
0.1
0.1
0.1
+
2.2
1.2
0.8
0.1
+
+
+
+
+
0.1
0.5
0.1
0.1
0.1
0.1
0.1
0.1
2.0
1.1
0.8
0.1
+
+
+
+
+
0.1
0.5
0.1
0.1
0.1
0.1
0.1
0.1
Total
4.8
4.0
3.9
3.6
3.4
3.1
2.9
2.7
+ Less than 0.05 Tg CO2 Eq.
Note: Totals may not sum due to independent rounding.
a See Annex 3.2 for definitions of highway vehicle types.
b "Other" includes snowmobiles and other recreational equipment, logging equipment, lawn and garden equipment, railroad
equipment, airport equipment, commercial equipment, and industrial equipment.
Table 3-23: N2O Emissions from Mobile Combustion (Tg CO2 Eq.)
Fuel Type/Vehicle Type
1990R-*1-'-
1997 1998 1999 2000 2001 2002 2003
Gasoline Highway
40.3|r.fe; 51.5 51.7 50.8 49.1 45.0 41.6
38.0
43 See Annex 3.2 for a complete time series of emission estimates for 1990 through 2003.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 82
-------
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
+ Less than 0.05 Tg CO2 Eq.
Note: Totals may not sum due
25.5
14.1
0.7
+
0.2
+
+
0.2
+
3.2
0.4
0.3
1.7
0.2
0.3
0.2
!!"•'*""'
l<"'"i''"
)<'•',,, '<„'
£?:'£
;<'"''",
!<; T >
^- ?'# •'<
)' \ t *
)' ' , i S
'' s * *
y "'^/S
y M,,/^
)' 'l \"vv
43.7p.'<:t'
26.7
23.7
1.1
+
0.3
+
+
0.2
0.1
3.3
0.3
0.3
1.7
0.3
0.4
0.3
55.2
26
23
1
0
0
0
3
0
0
1
0
0
0
55
.7
.7
o
.3
+
.3
+
+
o
.3
.1
.3
.3
.3
.8
.3
.4
o
.3
.3
25.9
23.6
1.3
+
0.3
+
+
0.3
0.1
3.4
0.3
0.3
1.8
0.3
0.4
0.3
54.6
24.7
23.0
1.3
+
0.3
+
+
0.3
0.1
3.7
0.5
0.3
1.9
0.3
0.4
0.3
53.2
23
20
1
0
0
0
3
0
0
1
0
0
0
49
.1
.6
.4
+
.3
+
+
.3
.1
.5
.3
.3
.8
.3
.4
.3
.0
21.6
18.6
1.4
+
0.3
+
+
0.3
0.1
3.6
0.5
0.3
1.7
0.3
0.4
0.3
45.6
19.8
16.7
1.4
+
0.3
+
+
0.3
0.1
3.6
0.5
0.3
1.7
0.3
0.5
0.3
42.1
to independent rounding.
*"Other" includes snowmobiles and other recreationa
equipment, airport equipment,
commercial equipment
equipment, lo£
, and industrial
Table 3-24: CH4 Emissions from Mobile Combustion
(Gg)
jging equipment, lawn
equipment.
and
garden
equipment, railroad
Fuel Type/Vehicle Type
1990
1997 1998 1999 2000 2001 2002 2003
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*
205
125
65
13
1
1
+
+
1
1
22
4
3
7
4
2
2
I'-.f"-'' 166
B£ 91
Wti 64
1; '•£' 10
B<: l
1 V'-;n 1
j;Y;/C +
1; '$•-, +
I;*-?"' 1
t' '' V*' •">
<, .?/>'.' 3
W": 23
t v; 3
i?j " '''X 3
tV'& 7
tV"'- "-, 5
v^r, 3
\;Vi 2
158
87
60
10
1
1
+
+
1
3
23
3
3
7
5
3
2
143
82
52
9
1
1
+
+
1
4
24
3
3
7
5
3
2
130
73
49
7
1
1
+
+
1
4
26
5
3
7
5
3
2
116
65
44
6
1
1
+
+
1
5
25
3
3
7
6
3
2
105
59
40
5
1
1
+
+
1
5
26
4
^
7
6
3
2
95
53
38
5
1
1
+
+
1
6
26
4
3
7
6
3
2
Total
228
193
185
172
161
147
138
128
+ Less than 0.5 Gg
Note: Totals may not sum due to independent rounding.
* "Other" includes snowmobiles and other recreational equipment, logging equipment, lawn and garden equipment, railroad
equipment, airport equipment, commercial equipment, and industrial equipment.
Table 3-25: N2O Emissions from Mobile Combustion (Gg)
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
1990 1;;; ;•!••••
130 •?«;.!,
82 :;?-,;;
46 "v^i>;
2 ;vV'<
+ ;?V)i
1 -:l^
+ .•,',v''f';
1997
166
86
76
4
+
1
+
1998
167
86
76
4
+
1
+
1999
164
84
76
4
+
1
+
2000
158
80
74
4
+
1
+
2001
145
74
66
4
+
1
+
2002
134
70
60
5
+
1
+
2003
123
64
54
5
+
1
+
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 83
-------
Light-Duty Trucks
Heavy-Duty Vehicles
Alternative Fuel Highway
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
1 »' |J °
1 ?;;,;,:
+ ;V\
10 v'V
1 ;t 4'
l V:"
6 ;'!f;
1 tf;1;
i L/;'
1 .;/•'•
141 .^X, •',
+
1
+
11
1
1
6
1
1
1
178
+
1
+
11
1
1
6
1
1
1
179
+
1
+
11
1
1
6
1
1
1
176
+
1
+
12
2
1
6
1
1
1
171
+
1
+
11
1
1
6
1
1
1
158
+
1
+
12
2
1
6
1
1
1
147
+
1
+
12
1
1
5
1
1
1
136
+ Less than 0.5 Gg
Note: Totals may not sum due to independent rounding.
* "Other" includes snowmobiles and other recreational equipment, logging equipment, lawn and garden equipment, railroad
equipment, airport equipment, commercial equipment, and industrial equipment.
Mobile sources comprise the single largest source category of CO, NOX, and NMVOC emissions in the United
States. In 2003, mobile combustion contributed 89 percent of CO emissions, 56 percent of NOX emissions, and 46
percent of NMVOC emissions. Since 1990, emissions of NMVOCs from mobile combustion decreased by 42
percent, CO emissions decreased 37 percent, and emissions of NOX decreased by 14 percent.
Table 3-26: NOX Emissions from Mobile Combustion (Gg)
Fuel Type/Vehicle Type 1990
Gasoline Highway 5,746
Passenger Cars 3,847
Light-Duty Trucks 1,364
Heavy-Duty Vehicles 515
Motorcycles 20
Diesel Highway 2,956
Passenger Cars 39
Light-Duty Trucks 20
Heavy-Duty Vehicles 2,897
Alternative Fuel Highway" IE
Non-Highway 3,432
Ships and Boats 953
Locomotives 857
Farm Equipment 63
Construction Equipment 437
Aircraft5 641
Other" 480
Total 12,134
t;;':'k;); 1997 1998
*> 4,268 4,090
r'/|.» 2,447 2,316
£;-/., 1,334 1,294
':/; */ 475 467
ft\I 13 13
;'/;;'< 3,708 3,729
!>''' 13 11
.:'r,": 10 9
f IV i 3,685 3,709
;'7;'v IE IE
V'J' 3,792 3,772
••,& 963 919
?,',-;'; 962 973
;' !?;: 75 83
:&l>\ 487 487
£."•; : 708 706
.>;';'•• 597 604
."' X, 11,768 11,592
1999
3,924
2,158
1,268
485
13
3,671
10
8
3,653
IE
3,705
818
910
84
497
765
632
11,300
2000
3,812
2,084
1,303
411
13
3,803
7
6
3,791
IE
3,780
966
908
80
484
697
645
11,395
2001
3,715
2,027
1,285
390
14
3,338
6
5
3,326
IE
3,770
971
907
73
480
690
650
10,823
2002
3,519
1,920
1,217
369
13
3,162
6
5
3,151
IE
3,707
954
891
72
472
678
639
10,389
2003
3,527
1,924
1,220
370
13
3,169
6
5
3,158
IE
3,722
958
895
72
474
681
642
10,418
IE (Included Elsewhere)
Note: Totals may not sum due to independent rounding.
aNOx emissions from alternative fuel highway vehicles are included under gasoline and diesel highway vehicles.
b Aircraft estimates include only emissions related to landing and take-off (LTO) cycles, and therefore do not include cruise
altitude emissions.
0 "Other" includes gasoline- and diesel-powered recreational, industrial, lawn and garden, light commercial, logging, airport
service, and other equipment.
Table 3-27: CO Emissions from Mobile Combustion (Gg)
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
1990f^,;lf
98,328 ; v:
60,757 ;VX'
29,237 VV,
8,093 .,•$,?
1997
67,509
36,825
25,748
4,787
1998
65,246
35,686
24,754
4,642
1999
61,210
32,921
23,343
4,782
2000
60,657
32,867
24,532
3,104
2001
56,716
31,600
22,574
2,411
2002
55,541
30,945
22,107
2,361
2003
52,544
29,275
20,914
2,234
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 84
-------
Motorcycles 240
Diesel Highway 1,696
Passenger Cars 35
Light-Duty Trucks 22
Heavy-Duty Vehicles 1,639
Alternative Fuel Highway" IE
Non-Highway 19,459
Ships and Boats 1,679
Locomotives 85
F arm Equipment 2 1 7
Construction Equipment 582
Aircraft5 1,090
Other" 15,807
Total 119,482
;"'»XV 150 163
;i ; 1,301 1,202
:/:)•' 13 10
&;•; 13 12
:•'',!,£ 1,276 1,179
£.,;'£ IE IE
:/;);; 21,474 21,493
&K, 1,948 1,943
:;'',!,;,' 89 83
i,,; ;i 250 274
;'•"*•: 636 633
'•:'!'j; 1,098 1,081
Hj 17,453 17,478
li :v/ 90,284 87,940
164
1,122
10
9
1,103
IE
21,152
2,121
98
285
630
1,074
16,943
83,484
154
1,088
7
6
1,075
IE
21,935
1,946
90
245
626
1,047
17,981
83,680
131
869
6
5
858
IE
22,387
1,952
90
233
621
1,041
18,449
79,972
129
851
6
5
840
IE
22,181
1,934
89
231
615
1,032
18,280
78,574
122
805
5
5
795
IE
22,177
1,934
89
231
615
1,031
18,276
75,526
IE = Included Elsewhere
Note: Totals may not sum due to independent rounding.
a CO emissions from alternative fuel highway vehicles are included under gasoline and diesel highway vehicles.
b Aircraft estimates include only emissions related to landing and take-off (LTO) cycles, and therefore do not include cruise
altitude emissions.
0 "Other" includes gasoline- and diesel-powered recreational, industrial, lawn and garden, light commercial, logging, airport
service, and other equipment.
Table 3-28: NMVOC Emissions from Mobile Combustion (Gg)
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Alternative Fuel Highway"
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraftb
Otherc
Total
1990 .>: V; 1997
8,110
5,120
2,374
575
42
406
16
14
377
IE
2,416
608
33
28
85
149
1,513
jji::.v 5,167
ip,''5"' 2,928
:;;;:::.»;'• 1,882
j£v> 336
jP-''''< 22
l-'k 263
'$:•:•'. 6
$ •''•'''; 8
£-'k 249
!:;•'// IE
£"•''; 2,498
£-•!• 766
?:R? 35
!;/'#, 32
Sj?!'^'-" 83
|'P 142
^!.V, i;44i
10,933 |fe!;j 7,928
1998
5,067
2,895
1,812
335
25
249
5
7
237
IE
2,427
763
33
35
81
137
1,378
7,742
1999
4,924
2,810
1,734
351
28
230
5
6
219
IE
2,432
769
38
38
81
141
1,366
7,586
2000
4,615
2,610
1,750
232
23
216
3
4
209
IE
2,398
744
35
24
76
130
1,390
7,230
2001
4,285
2,393
1,664
206
22
207
3
4
201
IE
2,379
730
35
19
72
125
1,397
6,872
2002
3,931
2,195
1,527
189
20
190
3
3
184
IE
2,438
748
36
20
74
128
1,432
6,560
2003
3,832
2,140
1,488
184
20
185
3
^
179
IE
2,333
716
35
19
71
123
1,370
6,351
IE (Included Elsewhere)
Note: Totals may not sum due to independent rounding.
a NMVOC emissions from alternative fuel highway vehicles are included under gasoline and diesel highway vehicles.
b Aircraft estimates include only emissions related to landing and take-off (LTO) cycles, and therefore do not include cruise
altitude emissions.
0 "Other" includes gasoline- and diesel-powered recreational, industrial, lawn and garden, light commercial, logging, airport
service, and other equipment.
Methodology
Estimates of CH4 and N2O emissions from mobile combustion were calculated by multiplying emission factors by
measures of activity for each fuel and vehicle type (e.g., light-duty gasoline trucks). Depending upon the category,
activity data included such information as fuel consumption, and vehicle miles traveled (VMT). The activity data
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 85
-------
and emission factors used are described in the subsections that follow. A complete discussion of the methodology
used to estimate emissions from mobile combustion and the emission factors used in the calculations is provided in
Annex 3.2.
EPA (2003) provided emissions estimates of NOX, CO, and NMVOCs for eight categories of highway vehicles,44
aircraft, and seven categories of non-highway vehicles.45 These emission estimates were provided from preliminary
EPA data, which, in its final iteration, will be published on the National Emission Inventory (NEI) Air Pollutant
Emission Trends web site. The methodology used to develop these estimates can be found on EPA's Air Pollutant
Emission Trends website, at .
Highway Vehicles
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)46 were based
on VMT by vehicle and fuel type.
Emission factors for gasoline and diesel highway vehicles were developed by ICF (2004). These factors were based
on EPA and California Air Resources Board (CARB) laboratory test results of different vehicle and control
technology types. The EPA and CARB tests were designed following the Federal Test Procedure (FTP), which
covers three separate driving segments, since vehicles emit varying amounts of GHGs depending on the driving
segment. These driving segments are: (1) a transient driving cycle that includes cold start and running emissions,
(2) a cycle that represents running emissions only, and (3) a transient driving cycle that includes hot start and
running emissions. For each test run, a bag was affixed to the tailpipe of the vehicle and the exhaust was collected;
the content of this bag was then analyzed to determine quantities of gases present. The emission charactenstics of
segment 2 was used to define running emissions, and subtracted from the total FTP emissions to determine start
emissions. These were then recombined based upon the ratio of start to running emissions for each vehicle class
from MOBILE6.2 to approximate average driving characteristics.
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 (CRC 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. While the formation of N2O is highly dependent on the type of catalyst used and the catalyst
temperature, tailpipe N2O is likely to increase as engine out NOX emissions increase. Thus, as a first approximation,
the NOX to N2O emission ratio will likely be constant for a given emission control group. A complete discussion of
the data source and methodology used to determine emission factors from AFVs is provided in Annex 3.2.
Annual VMT data for 1990 through 2003 were obtained from the Federal Highway Administration's (FHWA)
Highway Performance Monitoring System database as reported in Highway Statistics (FHWA 1996 through 2004).
VMT was then allocated from FHWA's vehicle categories to fuel-specific vehicle categories based on estimates of
fuel consumption by fuel type for each vehicle category, developed using information on shares of vehicle fuel use
for each vehicle category by fuel type reported in DOE (2004) and information on total motor vehicle fuel
44 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.
45 These categories included: locomotives, marine vessels, farm equipment, construction equipment, other off-highway liquid
fuel (e.g. recreational vehicles and lawn and garden equipment), and other off-highway gaseous fuel (e.g., other off-highway
equipment running on compressed natural gas).
46 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 86
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consumption by fuel type from FHWA (1996 to 2004). VMT for AFVs were taken from Browning (2003). The age
distributions of the U. S. vehicle fleet were obtained from EPA (2004b) and EPA (2000), and the average annual
age-specific vehicle mileage accumulation of U.S. vehicles were obtained from EPA (2000).
Control technology and standards data for highway vehicles were obtained from the EPA's Office of Transportation
and Air Quality (EPA 2004a, 2004d, 2000, 1998, and 1997). These technologies and standards are defined in
Annex 3.2, and were compiled from EPA (1993), EPA (1994a), EPA (1994b), EPA (1998), EPA (1999), and
IPCC/UNEP/OECD/IEA (1997).
Preliminary estimates for NOX, CO, and NMVOCs were obtained from EPA (2004e) and disaggregated based on
EPA (2003), which, in its final iteration, will be published on the National Emission Inventory (NEI) Air Pollutant
Emission Trends web site.
Non-Highway
Fuel consumption data were employed as a measure of activity for non-highway vehicles, and then fuel-specific
emission factors were applied.47 Activity data were obtained from AAR (2004), BEA (1991 through 2004), Benson
(2002 through 2004), DOE (1993 through 2004), DESC (2004), DOC (1991 through 2004), DOT (1991 through
2004), EIA (2002a), EIA (2002b), EIA (2004a), EIA (2004b), EIA (2003 through 2004), EIA (1991 through 2004),
EPA (2004c), and FAA (2004), Emission factors for non-highway modes were taken from IPCC/UNEP/OECD/IEA
(1997).
Uncertainty
This section discusses the uncertainty of the emissions estimates for CH4 and N2O. Uncertainty was analyzed
separately for highway vehicles and non-highway vehicles, due to differences in their characteristics and their
contributions to total mobile source emissions.
Uncertainty analyses were not conducted for CO, NOX, or NMVOC emissions. Emission factors for these gases
have been extensively researched, since these gases are regulated emissions from motor vehicles in the United
States, and the uncertainty of these emissions estimates is believed to be relatively low. A much higher level of
uncertainty is associated with CH4 and N2O emission factors, since emissions of these gases are not regulated in the
United States, and unlike CO2 emissions, the emission pathways of CH4 and N2O are also highly complex.
Highway Vehicles
A quantitative uncertainty analysis was conducted for the highway portion of the mobile source sector using the
IPCC-recommended Tier 2 uncertainty estimation methodology, Monte Carlo Simulation technique, using @RISK
software. The uncertainty analysis was performed on 2003 estimates of CH4 and N2O emissions, incorporating
probability distribution functions associated with the major input variables. For the purposes of this analysis, the
uncertainty was modeled for the following two major sets of input variables: (1) vehicle mile traveled (VMT) data,
by vehicle and fuel type and (2) emission factor data, by vehicle, fuel, and control technology type.
Mobile combustion emissions of CH4 and N2O per vehicle mile traveled vary significantly due to fuel type and
composition, technology type, operating speeds and conditions, type of emission control equipment, equipment age,
and operating and maintenance practices. The primary activity data, VMT, are collected and analyzed each year by
government agencies.
47 The consumption of international bunker fuels is not included in these activity data, but is estimated separately under the
International Bunker Fuels source category.
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To determine the uncertainty associated with the activity data used in the calculations of CH4 and N2O emissions,
the agencies and the experts that supply the data were contacted. Because few of these sources were able to provide
quantitative estimates of uncertainty, expert quantitative judgments were used to assess the uncertainty associated
with the activity data.
The emission factors for highway vehicles used in the Inventory were obtained from ICF (2004). These factors
were based on laboratory testing of vehicles. While the controlled testing environment simulates real driving
conditions, emission results from such testing can only approximate real world conditions and emissions. For some
vehicle and control technology types, the testing did not yield statistically significant results within the 95 percent
confidence interval, requiring expert judgments to be used in developing the emission factors. In those cases, the
emission factors were developed based on comparisons of fuel consumption between similar vehicle and control
technology categories.
The estimates of VMT for highway vehicles by vehicle type in the United States were provided by FHWA (1996
through 2004), and were generated though the cooperation of FHWA and state and local governments. These
estimates are subject to several possible sources of error, such as unregistered vehicles, unreported fuel sales to
avoid fuel taxes, differences in achieved versus estimated fuel economy, and measurement and estimation errors.
These VMT were apportioned by fuel type, and then allocated to individual model years using temporal profiles of
both the vehicle fleet by age and vehicle usage by model year in the United States provided by EPA (2004b) and
EPA (2000). While the uncertainty associated with total U.S. VMT is believed to be low, the uncertainty within
individual source categories was assumed to be higher given uncertainties associated with apportioning total VMT
into individual vehicle categories, by technology type, and equipment age. The uncertainty of individual estimates
was assumed to relate to the magnitude of estimated VMT (i.e., it was assumed smaller sources had greater
percentage uncertainty). A further source of uncertainty occurs since FHWA and EPA use different definitions of
vehicle type and estimates of VMT by vehicle type (provided by FHWA) are broken down by fuel type using EPA
vehicle categories.
A total of 69 highway data input variables were simulated through Monte Carlo Simulation technique using @RISK
software. Variables included VMT and emission factors for individual vehicle categories and technologies. In
developing the uncertainty estimation model, a normal distribution was assumed for all activity-related input
variables (e.g., VMT) except in the case of buses, in which a triangular distribution was used. The dependencies
and other correlations among the activity data were incorporated into the model to ensure consistency in the model
specification and simulation. Emission factors were assigned uniform distributions, with upper and lower bounds
assigned to input variables based on 97.5 percent confidence intervals of laboratory test data. In cases where data
did not yield statistically significant results within the 95 percent confidence interval, estimates of upper and lower
bounds were made using expert judgment. The bounds for the emission factor-related input variables were typically
asymmetrical around their inventory estimates. Bias (or systematic uncertainties) associated with the emission
factors was incorporated into the analysis when expert judgments were applied to the laboratory test results in
determining the uncertainty characteristics and/or the bounds of the emission factors.48 The results of this analysis
are reported in the section below, titled Quantitative Estimates of Uncertainty.
Non-Highway
Emissions from non-highway vehicles are a small portion of total emissions from mobiles sources, representing 20
percent of CH4 emissions from mobile sources and 9 percent of N2O emissions from mobile sources in 2003. Since
they comprise a small share of mobile source emissions, even large uncertainties in these estimates would have a
relatively small impact on the total emission estimate for mobile sources. As a result, a quantitative analysis of
uncertainty of emissions from non-highway vehicles has not been performed. However, sources of uncertainty for
48 Random uncertainties are the main focus of statistical uncertainty analysis. Uncertainty estimates elicited from experts
include both random and systematic uncertainty. Hence, both these types of uncertainty are represented in this uncertainty
analysis.
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non-highway vehicles are being investigated by examining the underlying uncertainty of emission factors and fuel
consumption data.
Overall, a significant amount of uncertainty is associated with the emission estimates for non-road sources. A
primary cause is a large degree of uncertainty surrounding emission factors. The IPCC Good Practice Guidance
and Uncertainty Management in National Greenhouse Gas Inventories reports that CH4 emissions from aviation
and marine sources may be uncertain by a factor of two, while N2O emissions may be uncertain by an order of
magnitude for marine sources and several orders of magnitude for aviation. No information is provided on the
uncertainty of emission factors for other non-highway sources.
Fuel consumption data have a lower uncertainty than emission factors, though large uncertainties do exist for
individual sources. Fuel consumption for off-highway vehicles (i.e., equipment used for agriculture, construction,
lawn and garden, railroad, airport ground support, etc., as well as recreational vehicles) was generated by EPA's
NONROAD model (EPA 2004c). This model estimates fuel consumption based on estimated equipment/vehicle
use (in hours) and average fuel consumed per hour of use. Since the fuel estimates are not based upon documented
fuel sales or consumption, a fair degree of uncertainty accompanies these estimates.
Distillate consumption for ships and boats was obtained from sales estimates from EIA 's Fuel Oil and Kerosene
Sales (EIA 1991 through 2004). The estimates for distillate consumption have associated uncertainty, as EIA's
estimates are based on sales to economic sectors, and it can be difficult to determine how much of the fuel sold in
each sector is used by mobile or stationary sources and to further attribute this consumption to specific final users.
For example, some fuel purchased by the marine sector may be used for operating heavy equipment or even
generators, instead of being used entirely by ships and boats. This distinction between mobile and stationary fuel
users is not made by EIA.
EIA does provide coefficients of variation to estimate sampling error, which occurs due to the fact that these
estimates are based on a sample set. However, as EIA points out, these coefficients do not take into account all the
sources of potential bias, which includes incomplete information, misinterpretation of survey questions, and other
factors that may cause estimates of fuel sales to be different from actual sales. In addition, diesel for ships and boats
is adjusted for bunker fuel consumption, which introduces an additional (and much higher) level of uncertainty.
Domestic consumption for residual fuel consumption by ships and boats is obtained from EIA (2004a). These
estimates fluctuate widely from year to year. Such fluctuations cannot be fully explained without further analysis of
the underlying activity data sets and, as such, the estimates are believed to be highly uncertain. The estimate of
domestic consumption is then adjusted downward to account for international bunker fuels, which represents the
primary use of residual fuel by ships and boats. As the international bunker fuel data are considered to have a
moderate level of uncertainty,49 the overall uncertainty of the domestic ships and boats estimate for residual fuel
consumption is considered high.
Domestic jet fuel and aviation gasoline consumption data are obtained from EIA (2004a). Like diesel and residual
marine fuel consumption, jet fuel consumption for aviation is adjusted downward to account for international
bunker fuels. The international bunker fuel estimates introduce a significant amount of uncertainty. Additionally,
all jet fuel consumption in the transportation sector is assumed to be consumed by aircraft. Some fuel purchased by
airlines is not 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
49 This is discussed in the section on International Bunker Fuels.
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(LTO) cycles, with no CH4 being emitted during the cruise cycle. However, a better approach would be to apply
emission factors based on the number of LTO cycles.
Finally, U.S. aircraft emission estimates for CO, NOX, and NMVOCs from EPA (2004e and 2003) are based on
LTO cycles and 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 may
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.
Quantitative Estimates of Uncertainty
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-29. Mobile combustion CLL,
emissions in 2003 were estimated to be between 2.5 and 2.8 Tg CO2 Eq. at a 95 percent confidence level (or in 19
out of 20 Monte Carlo Simulations). This indicates a range of 9 percent below to 4 percent above the 2003
emission estimate of 2.7 Tg CO2 Eq. Also at a 95 percent confidence level, mobile combustion N2O emissions in
2003 were estimated to be between 35.2 and 52.8 Tg CO2 Eq., indicating a range of 16 percent below to 26 percent
above the 2003 emission estimate of 42.1 Tg CO2 Eq.
Table 3-29: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Mobile Sources (Tg CO2
Eq, and Percent)
2003
Emission
Source Gas Estimate Uncertainty Range Relative to Emission Estimate"
(TgC02Eq.) (TgC02Eq.) (%)
Mobile Sources CH4 2.7
Mobile Sources N,O 42.1
Lower Bound
2.5
35.2
Upper Bound
2.8
52.8
Lower Bound
-9%
-16%
Upper Bound
+4%
+26%
aRange of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
This uncertainty analysis is a continuation of a multi-year process for developing credible quantitative uncertainty
estimates for this source category using the IPCC Tier 2 approach to uncertainty analysis. In the upcoming years,
the type and the characteristics of the actual probability density functions underlying the input variables will be
identified and more credibly characterized. Accordingly, the quantitative uncertainty estimates reported in this
section should be considered as preliminary and illustrative.
QA/QC and Verification
A source-specific QA/QC plan for mobile combustion was developed and implemented. This effort included a Tier
1 analysis, as well as portions of a Tier 2 analysis. The Tier 2 procedures focused on the emission factor and
activity data sources, as well as the methodology used for estimating emissions. Because significant changes were
made to highway vehicle emission factors and non-highway fuel consumption estimates (see Recalculations
Discussion below), QA/QC efforts were focused in particular on emissions impacted by these changes. These
procedures included a qualitative assessment of the emission estimates to determine whether they appear consistent
with the most recent activity data and emission factors available. A comparison of historical emissions between this
year's and last year's Inventories was also conducted, and was qualitatively assessed to ensure that the changes in
estimates were consistent with the changes in activity data and emission factors.
Recalculations Discussion
In order to ensure the highest quality estimates, the methodology is continuously revised based on comments from
internal and external reviewers. This year, adjustments were made to emission factors and activity data to
incorporate new research and additional data sources.
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The most significant changes in this year's Inventory are the revisions to the highway emission factors for CH4 and
N2O. The previous emission factors had been derived using methodology similar to that outlined in
IPCC/UNEP/OECD/IEA (1997). However, preliminary tests suggested that these emission factors may not have
been representative of actual emissions. EPA sponsored laboratory testing that resulted in the new emission factors
used in this report. The emission factors changed notably, ranging from a decrease of 97 percent to an increase of
114 percent for individual vehicle/fuel type/technology types; the combined effect of these changes in emission
factors significantly lowered CH4 and N2O emissions from highway vehicles. Given the large contribution of
highway vehicles to the mobile totals, these new emission factors were major drivers behind the changes in CH4 and
N2O estimates. However, because these emission factors do not impact CO2 emissions, their impact is less
significant when considering total mobile source emissions of all GHGs.
Additionally, the methodology for estimating VMT by vehicle/fuel type category (e.g., LDGV, LDDV, LDGT,
LDDT, etc.) was revised. The purpose of this revision was to ensure that the VMT estimates for individual vehicle
categories match up with VMT estimates by vehicle type from FHWA (1996 through 2004), which is the
recognized source of national VMT estimates. The new methodology apportions FHWA's estimate of VMT for
each vehicle category (e.g., light-duty vehicles, light-duty trucks, buses, heavy-duty trucks) to fuel-based vehicle
categories based on estimates of gasoline and diesel fuel consumption for each vehicle category, drawn from DOE
(2004). This change had a small impact on emissions.
The vehicle age distribution values for highway vehicles were also revised. Previously, the Inventory relied on one
vehicle age distribution across 25 model years from EPA (2000), which was applied for each year. For the current
Inventory, that same distribution was applied for years 1990 through 1998, and annually variable vehicle age
distributions were applied for years 1999 through 2003 based on data obtained from EPA's MOVES model (EPA
2004b). The annually variable age distributions more accurately reflect changes in the vehicle stock, and include 31
model years.
Emissions from gasoline- and diesel-electric hybrid vehicles are now included under gasoline and diesel vehicles
instead of alternative fuel/advanced technology category, since these vehicles only run on traditional motor
gasoline. This change did not have an impact on total emissions.
EPA's NONROAD model is now used as the primary data source for fuel consumption by off-highway equipment
(e.g., construction, agricultural, lawn and garden equipment), rather than data from FHWA's Highway Statistics
(FHWA 1996 through 2004), EIA's Fuel Oil and Kerosene Sales (EIA 1991 through 2004), and several other
sources. The NONROAD model is also used to estimate fuel consumption by recreational boats, rather than data
from FHWA's Highway Statistics. Some of the individual sources used in the previous Inventory had not been
updated for several years, while others had updated their methodologies, resulting in large variations in estimates
from year to year. Use of the NONROAD Model for all of these estimates is believed to provide more accurate, up-
to-date, and consistent estimates.
Other changes include minor revisions to historical aircraft fuel consumption estimates in FAA (2004) and rail
consumption provided from Benson (2004). These revisions were not significant, and the overall impact on
emissions estimates is small.
Overall, these changes resulted in an average annual decrease of 0.6 Tg CO2 Eq. (14 percent) in CH4 emissions from
mobile combustion and an average annual decrease of 6.2 Tg CO2 Eq. (11 percent) in N2O emissions from mobile
combustion for the period 1990 through 2002.
Planned Improvements
While the data used for this report represent the most accurate information available, three areas have been
identified that could potentially be improved in the short term given resource availability:
1) Reconcile Fuel Consumption Estimates used for Calculating N2O/CH4 and CO2 - Estimates of transportation fuel
consumption by fuel type from EIA are used as the basis for estimating CO2 emissions from the transportation
sector. These estimates are then apportioned to mode and vehicle category based on "bottom up" estimates of fuel
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 91
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consumption from sources such as FHWA's Highway Statistics (FHWA 1996 through 2004) and DOE's
Transportation Energy Data Book (DOE 1993 through 2004). These sources are also used to develop N2O and CH4
estimates. The EIA fuel consumption estimates, however, differ from the estimates derived using "bottom up"
sources. For certain vehicle categories this leads to CO2 emissions trends that conflict with those of the "bottom up"
sources. Potential improvements include reconciling fuel consumption estimates from EIA and other data sources,
and revising the current process of allocating CO2 emissions to reflect trends from the more detailed vehicle
category estimates of fuel consumption.
2) Improve consideration of emissions from trucks used off-road - Some light- and heavy-duty trucks travel for a
portion of their mileage off-road. N2O and CH4 estimates for highway vehicles are developed based on vehicle
mileage data from FHWA's Highway Statistics, which in turn, are drawn from the Highway Performance
Monitoring System (HPMS). These emissions estimates do not address travel by trucks off-road. Gasoline fuel
consumed by trucks used off-road for construction, agriculture, and other industrial/commercial uses is reported in
Highway Statistics, and is included as part of the non-road agriculture and construction categories. However, diesel
fuel consumed by trucks used off-road is not addressed in the current Inventory, and further work should be
conducted to develop estimates of off-road truck use of diesel fuel. In addition, default emission factors from IPCC
are applied to the off-highway modes. As a result, the emissions factors for agricultural equipment are applied both
to equipment and trucks used in agriculture, and emissions factors for construction equipment are applied both to
equipment and trucks used in construction. Emission estimates would be improved through an investigation of
more appropnate emission factors for off-road trucks.
3) Improve estimation ofVMT by vehicle/fuel type category - The current Inventory process for estimating VMT by
vehicle/fuel type category involves apportioning VMT by vehicle type to each fuel type on the basis of fuel
consumption. While this is a reasonable simplification, this approach implicitly assumes the same average fuel
economy for gasoline and diesel vehicles. A more accurate apportionment for VMT by fuel type for light-duty
trucks and medium/heavy-duty trucks could potentially be developed using data on vehicle travel from the Vehicle
Inventory and Use Survey and other publications, or using VMT breakdowns by vehicle/fuel type combinations
from the MOBILE6 or MOVES models. These sources should be investigated in order to develop a more robust
apportionment method.
3.5. Coal Mining (IPCC Source Category 1B1a)
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 101 gassy 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 2003, ten coal mines collected CH4 from degasification
systems and sold this gas to a pipeline, thus reducing emissions to the atmosphere. In addition, one coal mine used
CH4 from its degasification system to heat mine ventilation air on site. 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 2003 were estimated to be 53.8 Tg CO2 Eq. (2,561 Gg), a decline of 34 percent since 1990
(see Table 3-30 and Table 3-31). Of this amount, underground mines accounted for 70 percent, surface mines
accounted for 16 percent, and post-mining emissions accounted for 14 percent. In 1993, CH4 generated from
underground mining dropped, primarily due to labor strikes at many large underground mines. In 1994 and 1995,
CH4 emissions increased due to resumed production at high emitting mines after the labor strike. The decline in
CH4 emissions from underground mines from 1996 to 2002 was the result of the reduction of overall coal
production, the mining of less gassy coal, and an increase in CH4 recovered and used. CH4 emissions increased
slightly in 2003 due to additional gas drainage being vented to the atmosphere and a reduction in CH4 recovery.
Surface mine emissions and post-mining emissions remained relatively constant from 1990 to 2003.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 92
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Table 3-30: CH4 Emissions from Coal Mining (Tg CO2 Eq.)
Activity
Underground Mining
Liberated
Recovered & Used
Surface Mining
Post-Mining (Underground)
Post-Mining (Surface)
Total
1990 ;•• *
62 i ,f ,-;;' '
676 f;-;-v
(5.6) v'.1,^
104 :V'.;
77 ;«*•.,.
17 ">. '"
81.9 |t' 'f*'
1996
45.3
59.8
(14.5)
9.2
7.2
1.5
63.2
1997
44.3
55.7
(11.4)
9.3
7.4
1.5
62.6
1998
44.4
58.6
(14.2)
9.4
7.4
1.5
62.8
1999
41.6
54.4
(12.7)
9.0
6.8
1.5
58.9
2000
39.4
54.0
(14.6)
8.8
6.7
1.4
56.2
2001
38.1
54.2
(16.1)
9.2
6.8
1.5
55.6
2002
35.8
53.3
(17.5)
8.8
6.4
1.4
52.4
2003
37.6
53.6
(16.1)
8.4
6.4
1.4
53.8
Note: Totals may not sum due to independent rounding.
Table 3-31: CH4 Emissions from Coal Mining (Gg)
Activity
Underground Mining
Liberated
Recovered & Used
Surface Mining
Post-Mining (Underground)
Post-Mining (Surface)
Total
1990 j^v;
2,956 ;.;•- •»',
3,220r.5,/;
(265 )?'/;';;;
497 j,;;:;,;,'
367s.r,v*
•>.'.,'"','>
3,900 -'.U,
1996
2,158
2,850
(692)
438
341
71
3,008
1997
2,111
2,654
(543)
445
354
72
2,983
1998
2,117
2,791
(674)
448
352
73
2,989
1999
1,982
2,589
(607)
428
325
69
2,805
2000
1,876
2,573
(697)
417
317
68
2,677
2001
1,816
2,580
(765)
438
323
71
2,647
2002
1,705
2,538
(833)
420
304
68
2,497
2003
1,788
2,554
(766)
402
305
65
2,561
Note: Totals may not sum due to independent rounding.
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
detectable50 CH4 concentrations. These mine-by-mine measurements are used to estimate CH4 emissions from
ventilation systems.
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 published by
state petroleum and natural gas agencies 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 2003, ten active coal mines sold recovered CH4 into the local gas pipeline
50 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.
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networks, while one coal mine used recovered CH4 on site. 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, obtained from the Energy Information Administration's Coal Industry
Annual (see Table 3-32) (EIA 2003), 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. Revised data on in situ CH4 content and emissions factors are taken from EPA (1996) and AAPG (1984).
This calculation 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.
Table 3-32: Coal Production (Thousand Metric Tons)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Underground
384,250
368,635
368,627
318,478
362,065
359,477
371,816
381,620
378,964
355,433
338,173
345,305
324,219
320,047
Surface
546,818
532,656
534,290
539,214
575,529
577,638
593,315
607,163
634,864
642,877
635,592
676,142
667,619
651,251
Total
931,068
901,291
902,917
857,692
937,594
937,115
965,131
988,783
1,013,828
998,310
973,765
1,021,446
991,838
971,297
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.
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.
However, since underground emissions comprise the majority of total coal mining emissions, the uncertainty
associated with underground emissions is the primary factor that determines overall uncertainty. The results of the
Tier 2 quantitative uncertainty analysis are summarized in Table 3-33. Coal mining CH4 emissions in 2003 were
estimated to be between 51.9 and 55.7 Tg CO2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo
Simulations). This indicates a range of 4 percent below to 4 percent above the 2003 emission estimate of 53.8 Tg
CO2 Eq.
Table 3-33: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Coal Mining (Tg CO2 Eq. and
Percent)
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Source
Coal Mining
2003 Emission
Gas Estimate
(Tg C02 Eq.)
CH4 53.8
Uncertainty Range Relative
(TgC02Eq.)
Lower Upper
Bound Bound
51.9 55.7
to Emission Estimate"
(%)
Lower Upper
Bound Bound
-4% +4%
a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
Recalculations Discussion
In-situ gas content is the principal variable used to determine post-mining methane emissions of mined coal.
Previously, in-situ values used were based on average CH4 content values summarized in Exhibit 3-4 of the U.S.
EPA publication, EPA/400/9-90/008; Methane Emissions From Coal Mining, Issues and Opportunities, September
1990. The original source of information is derived from three primary sources: 1986 USBM Circular 9067, Results
of the Direct Method Determination of the Gas Contents of U.S. Coal Basins, 1983 U.S. DOE Report
(DOE/METC/83-76), Methane Recovery from Coalbeds: A Potential Energy Source, and a series of 1986-88 Gas
Research Institute Topical Reports called^ Geologic Assessment of Natural Gas from Coal Seams. No data was
available for eight of the coal mining states and therefore default values from other coal basins were assigned to
those states.
Since Circular 9067 contained only a portion of the gas content data compiled by USBM, the complete dataset,
published in 1996 Evaluation and Analysis of Gas Content and Coal Properties of Major Coal Bearing Regions of
the United States, EPA/600/R-96-065, is now the basis of new in-situ gas content value. In addition, gas content
data from the U.S. DOE Methane Recovery from Coalbed Projects (MRCP), which was the original source of data
for the GRI Topical Reports noted above, was utilized. (Condensed versions of the original MRCP reports for 13
U.S. coal basins are compiled in Coalbed Methane Resources of the United States, AAPG Studies in Geology Series
#17, published in 1984).
The compiled gas content data for each of the coal basins was sorted by depth to determine in-situ values for surface
and underground mines, separately. Overburden depths of surface mines were analyzed using Keystone Coal
Industry Manuals from 1991 through 2003 and found that the maximum depth was 250 feet. Therefore, gas content
data from samples taken less than 250 feet deep were assigned to surface mines and the samples collected from
deeper depths to underground mines. The combination of these changes resulted in an average annual decrease of
0.2 Tg CO2 Eq. (0.3 percent) in CH4 emissions from coal mining for the period 1990 through 2002.
Planned Improvements
To reduce the uncertainty associated with the radius of influence of each well, the appropriate drainage radius will
be investigated for future inventories. Since the number of wells counted may increase if the drainage area is found
to be larger than currently estimated, additional mines may be included in future estimates of recovery.
3.6. Abandoned Underground Coal Mines (IPCC Source Category 1B1a)
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 resides in the coal ("in situ") and surrounding strata when mining occurs.
The m-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, more deeply buried deposits tend
to generate more CH4 and retain more of the gas after uplift to minable depths. Deep underground coal seams
generally have higher CH4 contents than shallow coal seams or surface deposits.
Underground coal mines contribute the largest share of CH4 emissions, with active underground mines the leading
source of underground emissions. However, mines also continue to release CH4 after closure. As mines mature and
coal seams are mined through, mines close and are abandoned. Many are sealed and some flood through intrusion
of groundwater or surface water into the void. Shafts or portals are generally filled with gravel and capped with a
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concrete seal, while vent pipes and boreholes are plugged in a manner similar to oil and gas wells. Some abandoned
mines are vented to the atmosphere to prevent the buildup of CH4 that may find its way to surface structures through
overburden fractures. As work stops within the mines, the CH4 liberation decreases but it does not stop completely.
Following an initial decline, abandoned mines can liberate CH4 at a near-steady rate over an extended period of
time, or, if flooded, produce gas for only a few years. The gas can migrate to the surface through the conduits
described above, particularly if they have not been sealed adequately. In addition, diffuse emissions can occur
when CH4 migrates to the surface through cracks and fissures in the strata overlying the coal mine. The following
factors influence abandoned mine emissions:
• Time since abandonment;
• Gas content and adsorption characteristics of coal;
• Methane flow capacity of the mine;
• Mine flooding;
• Presence of vent holes; and
• Mine seals.
Gross abandoned mine methane emissions ranged from 6.1 to 9.6 Tg CO2Eq. from 1990 through 2003, varying as
much as 1.3 Tg CO2 Eq. from year to year. Fluctuations were due mainly to the number of mines closed during a
given year as well as the magnitude of the emissions from those mines when active. Abandoned mine emissions
peaked in 1996 (8.6 Tg CO2Eq.) due to the large number of mine closures from 1994 to 1996 (70 gassy mines
closed during the three-year period). In spite of this rapid rise, abandoned mine emissions have been generally on
the decline since 1996 (with slight increases in 1999 and 2000). There were fewer than thirteen gassy mine closures
during each of the years from 1998 through 2003. By 2003, abandoned mine emissions were reduced to 6.4 Tg CO2
Eq. (see Table 3-34 and Table 3-35).
Table 3-34: CH4 Emissions from Abandoned Coal Mines (Tg CO2 Eq.)
Activity
Abandoned Underground Mines
Recovered & Used
Total
1990
6.1
0
6.1
~ , 1997
9.6
;: 1.5
'i ; 8.1
1998
8.8
1.7
7.1
1999
9.0
1.6
7.3
2000
9.3
1.5
7.7
2001
8.5
1.5
6.9
2002
8.0
1.6
6.4
2003
7.9
1.5
6.4
Note: Totals may not sum due to independent rounding.
Table 3-35: CH4 Emissions from Abandoned Coal Mines (Gg)
Activity
Abandoned Underground Mines
Recovered & Used
Total
1990
288
288
, 1997
:.;• 458
74
:v, 385
1998
421
80
341
1999
426
78
349
2000
441
73
369
2001
403
73
331
2002
380
77
303
2003
377
72
306
Note: Totals may not sum due to independent rounding.
Methodology
Estimating CH4 emissions from an abandoned coal mine requires predicting the emissions of a mine from the time
of abandonment through the inventory year of interest. The flow of CH4 from the coal to the mine void is primarily
dependent on mine's emissions when active and the extent to which the mine is flooded or sealed. The CH4
emission rate before abandonment reflects the gas content of the coal, rate of coal mining, and the flow capacity of
the mine in much the same way as the initial rate of a water-free conventional gas well reflects the gas content of the
producing formation and the flow capacity of the well. Existing data on abandoned mine emissions through time,
although sparse, appear to fit the hyperbolic type of decline curve used in forecasting production from natural gas
wells.
In order to estimate CH4 emissions over time for a given mine, it is necessary to apply a decline function, initiated
upon abandonment, to that mine. In the analysis, mines were grouped by coal basin with the assumption that they
will generally have the same initial pressures, permeability and isotherm. As CH4 leaves the system, the reservoir
pressure, Pr, declines as described by the isotherm. The emission rate declines because the mine pressure (Pw) is
essentially constant at atmosphenc pressure, for a vented mine, and the PI term is essentially constant at the
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pressures of interest (atmospheric to 30 psia). A rate-time equation can be generated that can be used to predict
future emissions. This decline through time is hyperbolic in nature and can be empirically expressed as:
q=q1(l+bD1t)(-1/b)
Where:
• q is the gas rate at time t in mcf/d
• q; is the initial gas rate at time zero (t0) in million cubic feet per day (mcfd)
• b is the hyperbolic exponent, dimensionless
• D; is the initial decline rate, 1/yr
• t is elapsed time from to in years
This equation is applied to mines of various initial emission rates that have similar initial pressures, permeability
and adsorption isotherms (EPA 2003).
The decline curves are also affected by both sealing and flooding. Based on field measurement data, it was assumed
that most U.S. mines prone to flooding will become completely flooded within 8 years and therefore no longer have
any measurable CH4 emissions. Based on this assumption, an average decline rate for flooding mines was
established by fitting a decline curve to emissions from field measurements. An exponential equation was
developed from emissions data measured at eight abandoned mines known to be filling with water located in two of
the five basins. Using a least squares, curve-fitting algorithm, emissions data were matched to the exponential
equation shown below. There was not enough data to establish basin-specific equations as was done with the
vented, non-flooding mines (EPA 2003).
Where:
• q is the gas flow rate at time t in mcf/d
• q; is the initial gas flow rate at time zero (t0) in mcfd
• D is the decline rate, 1/yr
• t is elapsed time from t0 in years
Seals have an inhibiting effect on the rate of flow of CH4 into the atmosphere compared to the rate that would be
emitted if the mine had an open vent. The total volume emitted will be the same, but will occur over a longer
period. The methodology, therefore, treats the emissions prediction from a sealed mine similar to emissions from a
vented mine, but uses a lower initial rate depending on the degree of sealing. The computational fluid dynamics
simulator was again used with the conceptual abandoned mine model to predict the decline curve for inhibited flow.
The percent sealed is defined as 100 x (1 - initial emissions from sealed mine / emission rate at abandonment prior
to sealing). Significant differences are seen between 50 percent, 80 percent and 95 percent closure. These decline
curves were therefore used as the high, middle, and low values for emissions from sealed mines (EPA 2003).
For active coal mines, those mines producing over 100 mcfd account for 98 percent of all CH4 emissions. This
same relationship is assumed for abandoned mines. It was determined that 434 abandoned mines closing after 1972
produced emissions greater than 100 mcfd when active. Further, the status of 256 of the 434 mines (or 59 percent)
is known to be either 1) vented to the atmosphere, 2) sealed to some degree (either earthen or concrete seals), or 3)
flooded (enough to inhibit methane flow to the atmosphere). The remaining 41 percent of the mines were placed in
one of the three categories by applying a probability distribution analysis based on the known status of other mines
located in the same coal basin (EPA 2003).
Inputs to the decline equation require the average emission rate and the date of abandonment. Generally this data is
available for mines abandoned after 1972; however, such data are largely unknown for mines closed before 1972.
Information that is readily available such as coal production by state and county are helpful, but do not provide
enough data to directly employ the methodology used to calculate emissions from mines abandoned after 1971. It is
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assumed that pre-1972 mines are governed by the same physical, geologic, and hydrologic constraints that apply to
post-1972 mines; thus, their emissions may be characterized by the same decline curves.
During the 1970s, 78 percent of CH4 emissions from coal mining came from seventeen counties in seven states. In
addition, mine closure dates were obtained for two states, Colorado and Illinois, throughout the 20th century. The
data was used to establish a frequency of mine closure histogram (by decade) and applied to the other five states
with gassy mine closures. As a result, basin-specific decline curve equations were applied to 145 gassy coal mines
estimated to have closed between 1920 and 1971 in the United States, representing 78 percent of the emissions.
State-specific, initial emission rates were used based on average coal mine methane emissions rates during the
1970s (EPA 2003).
Abandoned mines emission estimates are based on all closed mines known to have active mine CH4 ventilation
emission rates greater than 100 mcfd at the time of abandonment. For example, for 1990 the analysis included 145
mines closed before 1972 and 259 mines closed between 1972 and 1990. Initial emission rates based on MSHA
reports, time of abandonment, and basin-specific decline curves influenced by a number of factors were used to
calculate annual emissions for each mine in the database. Coal mine degasification data are not available for years
prior to 1990, thus the initial emission rates used reflect ventilation emissions only for pre-1990 closures. Methane
degasification amounts were added to ventilation data for the total CH4 liberation rate for fourteen mines that closed
between 1992 and 2003. Since the sample of gassy mines (with active mine emissions greater than 100 mcfd) is
assumed to account for 78 percent of the pre-1971 and 98 percent of the post-1971 abandoned mine emissions, the
modeled results were multiplied by 1.22 and 1.02 to account for all U. S. abandoned mine emissions. Once the 1991
through 2003 totals were calculated, they were downwardly adjusted to reflect abandoned mine CH4 emissions
avoided from those mines. The inventory totals were not adjusted for abandoned mine reductions in 1990 through
1992, because no data was reported for abandoned coal mining methane recovery projects during that time.
Uncertainty
The parameters for which values must be estimated for each mine in order to predict its decline curve are: 1) the
coal's adsorption isotherm; 2) CH4 flow capacity as expressed by permeability; and 3) pressure at abandonment.
Because these parameters are not available for each mine, an approach was used that generates a probability
distribution of potential outcomes based on the most likely value and the probable range of values for each
parameter. The range of values is not meant to capture the extreme values, but values that represent the highest and
lowest quartile of the cumulative probability density function of the parameter. Once the low, mid, and high values
are selected, they are applied to a probability density function.
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.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-36. Abandoned coal mines
CH4 emissions in 2003 were estimated to be between 5.4 and 7.8 Tg CO2 Eq. at a 95 percent confidence level (or in
19 out of 20 Monte Carlo Simulations). This indicates a range of 16 percent below to 22 percent above the 2003
emission estimate of 6.4 Tg CO2 Eq. One of the reasons for the relatively narrow range is that mine-specific data is
used in the methodology. The largest degree of uncertainty is associated with the unknown status mines (which
account for 41 percent of the mines), with a ±50 percent uncertainty.
Table 3-36: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Abandoned Underground Coal
Mines (Tg CO2 Eq. and Percent)
Source
2003
Emission
Gas Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (%)
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Lower Upper Lower Upper
Bound Bound Bound Bound
Abandoned Coal Mines CH4 6.4 5_4 7_8 -16% +22%
aRange of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
QA/QC and Verification
As part of a Tier 2 analysis, the United States undertook an effort to verify the model results used in the U.S.
Inventory with field measurements. Field measurements were used to test the accuracy of the mathematical decline
curves to be used for basin-specific emissions estimates. A series of field measurements were conducted at
abandoned mine vent locations across the United States. Between November 1998 and February 2000, EPA
recorded measurements at five mines that were not flooded. Measurements were recorded at two abandoned mines
located in Ohio and Virginia continuously for 6 to 12 hours. As the methodology was finalized, EPA measured
emissions from three additional mines located in Illinois and Colorado. These measurements were recorded hourly
for 3 to 4 days and were normalized to average barometric pressures. Prior to these measurements, EPA's Office of
Research and Development initiated a field research program in the early 1990s. Data for 21 abandoned mines
located throughout the Northern and Central Appalachian, Black Warrior, and Illinois Basins were collected using
similar techniques.
Measurements for all field data recorded were plotted against predicted emissions as part of the two studies from
1991 through 2000. Emission rates from nine of the ten mines that were measured fall very close to the predicted
mid-case decline rate for their respective basins. For the exponential decline curve fit to the flooding mines, six of
nine measurements fall within a 95 percent predictive confidence interval of the mean.
Of the abandoned mines in the database, only about 13 percent of the mines maintain vents to the atmosphere.
Therefore, it is difficult to obtain field data. Additional field measurements, however, would be beneficial to further
calibrate the equations defined above. Furthermore, it would be useful to extend measurements of diffuse emissions
from sealed mines, since they comprise 43 percent of total mines.
Recalculations Discussion
In 2003, all methane emissions from abandoned coal mines were recalculated using: 1) an updated mine list based
on 1985 and 1988 USBM records (adding 41 mines to the inventory), 2) updated coal seam permeabilities based on
a 2004 EPA study, and 3) revised closure dates for 43 of the mines based on MSHA's data retrieval system. The
combination of these changes resulted in an average annual increase of 2.8 Tg CO2 Eq. (64.5 percent) in CH4
emissions from abandoned coal mines for the period 1990 through 2002.
3.7. Petroleum Systems (IPCC Source Category 1B2a)
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 2003 were 17.1 Tg CO2 Eq. (815 Gg). Since 1990, emissions declined due to a decline in
domestic oil production and industry efforts to make emissions reductions (see Table 3-37 and Table 3-38). The
various sources of emissions are detailed below.
Production Field Operations. Production field operations account for over 95 percent of total CH4 emissions from
petroleum systems. Vented CH4 from field operations account for approximately 83 percent of the emissions from
the production sector, fugitive emissions account for six percent, combustion emissions ten percent, and process
upset emissions barely one percent. The most dominant sources of vented emissions are field storage tanks, natural-
gas-powered pneumatic devices (low bleed, high bleed, and chemical injection pumps). These four sources alone
emit 79 percent of the production field operations emissions. Emissions from storage tanks occur when the CH4
entrained in crude oil under pressure volatilizes once the crude oil is put into storage tanks at atmospheric pressure.
Emissions from high and low-bleed pneumatics occur when pressurized gas that is used for control devices is bled
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to the atmosphere as they cycle up and down to modulate the system. Emissions from chemical injection pumps
occur as high-pressure gas that is used to drive the pumps is vented to the atmosphere. Two additional large
sources, oil well heads and gas engines, together account for 12 percent of emissions from the production sector.
The remaining nine percent of the emissions are distributed among 33 additional activities within these four
categories.
Crude Oil Transportation. Crude oil transportation activities account for less than one percent of total CH4
emissions from the oil industry. Venting from tanks and marine vessel loading operations accounts for 65 percent
of CH4 emissions from crude oil transportation. Fugitive emissions, almost entirely from floating roof tanks,
account for 18 percent. The remaining 17 percent is distributed among 4 additional sources within these two
categories.
Crude Oil Refining. Crude oil refining processes and systems account for only three 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. There is an insignificant amount of methane in all refined products. Within refineries, vented
emissions account for about 87 percent of the emissions, while fugitive and combustion emissions account for
approximately six and seven percent respectively. Refinery system blowdowns for maintenance and the process of
asphalt blowing—with air, to harden the asphalt—are the primary venting contributors. Most of the fugitive
emissions from refineries are from leaks in the fuel gas system. Refinery combustion emissions include small
amounts of unburned CH4 in process heater stack emissions and from unburned CH4 in engine exhausts and flares.
Table 3-37: CH4 Emissions from Petroleum Systems (Tg CO2 Eq.)
Activity 1990 1997 1998 1999 2000 2001 2002 2003
Production Field Operations
Pneumatic device venting
Tank Venting
Combustion & process upsets
Misc. venting & fugitives
Wellhead fugitives
Crude Oil Transportation
Refining
19
11
o
j
2
1
0
0
0
.3
.5
.8
.2
,4
.5
.1
.5
18
10
3
2
1
0
0
0
.1
.8
.4
.0
o
.3
.5
.1
.6
17.8
10.6
3.4
2.0
1,3
0.5
0.1
0.6
17
10
3
1
1
0
0
0
.1
.3
.2
.9
,3
.5
.1
.6
16.9
10.0
3.2
1.9
1,2
0.5
0.1
0.6
16.8
10.0
3.2
1.9
1,2
0.5
0.1
0.6
16.4
9.8
3.2
1.8
1,2
0.4
0.1
0.6
16.4
9.8
3.2
1.8
1,2
0.4
0.1
0.6
Total estimated emissions
20.0
18.8 18.5 17.8 17.6 17.4 17.1 17.1
Table 3-38: CH4 Emissions from Petroleum Systems (Gg)
Activity
Production Field Operations
Pneumatic device venting
Tank Venting
Combustion & process upsets
Misc. venting & fugitives
Wellhead fugitives
Crude Oil Transportation
Refining
Total estimated emissions
1990
920
545
179
103
66
26
7
25
951
1997
862
515
164
96
62
25
6
27
895
1998
846
504
162
94
61
25
6
27
879
1999
815
488
153
90
60
24
6
27
848
2000
803
478
154
89
59
22
5
28
836
2001
799
475
154
89
59
22
5
27
831
2002
783
465
151
87
58
21
5
27
815
2003
782
465
151
86
57
21
5
27
815
Methodology
The methodology for estimating CH4 emissions from petroleum systems is a bottom-up approach, based on a
comprehensive study of CH4 emissions from U.S. petroleum systems (EPA 1999, Radian 1996e). These studies
combined emission estimates from 70 activities occurring in petroleum systems from the oil wellhead through crude
oil refining, including 39 activities for crude oil production field operations, 11 for crude oil transportation
activities, and 20 for refining operations. Annex 3.5 provides greater detail on the emission estimates for these 70
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Page 100
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activities. The estimates of CH4 emissions from petroleum systems do not include emissions downstream of oil
refineries because these emissions are very small compared to CH4 emissions upstream of oil refineries.
The methodology for estimating CH4 emissions from the 70 oil industry activities employs emission factors initially
developed by EPA (1999) and activity factors that are based on EPA (1999) and Radian (1996e) studies. 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 (MMS 2004b). Emission factors were held constant for the period 1990
through 2003.
Activity factors for years 1990 through 2003 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
(1996e). For example, Radian (1996e) 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 were used, along with the ratios developed for Radian (1996e). In other
cases, the activity factor was held constant from 1990 through 2003 based on EPA (1999). Lastly, the previous
year's data were used when data for the current year were unavailable. See Annex 3.5 for additional detail.
Nearly all emission factors were taken from Radian (1996e) and EPA (1999). The remaining emission factors were
taken from the following sources: EPA default values, MMS reports (MMS 1995), the Exploration and Production
(E&P) Tank model (DB Robinson Research Ltd. 1997), 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 1990-2003, 1995-2003a-b), the API Basic Petroleum Data Book (API 2003),
Methane Emissions from the Natural Gas Industry'by the Gas Research Institute and EPA (Radian 1996a-d),
consensus of industry peer review panels, MMS reports (MMS 1995, 2000, 2004a-b), and the Oil & Gas Journal
(OGJ 2003a-b). Forecasts of activity factors for petroleum systems were developed using production and refining
capacity data from the EIA Annual Energy Outlook (EIA 2004) as well as offshore activity projections from MMS
(2001 and 2004a). Annex 3.5 provides a complete list of references.
Uncertainty
The detailed, bottom-up inventory 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, some uncertainty still remains.
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 major sources, which account for 90
percent of the total emissions, the uncertainty surrounding these six sources has been estimated most rigorously, and
serves as the basis for determining the overall uncertainty of petroleum systems emission estimates.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-39. Petroleum systems CH4
emissions m2003 were estimated to be between 11.9 and 51.4 Tg CO2Eq. at a 95 percent confidence level (orm 19
out of 20 Monte Carlo Simulations). This indicates a range of 30 percent below to 200 percent above the 2003
emission estimate of 17.1 Tg CO2 Eq.
Table 3-39: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Petroleum Systems (Tg CO2 Eq. and
Percent)
2003 Emission
Source Gas Estimate Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 101
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Lower Upper Lower Upper
Bound Bound Bound Bound
Petroleum Systems CH4 17.1 11.9 51.4 -30% +200%
a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
Recalculations Discussion
Estimates of CH4 from petroleum systems contain two changes with respect to previous inventories. First, the
emission factor for CH4 emissions from oil tanks in the production sector was modified to remove venting from
condensate tanks and only account for venting from crude oil tanks. The previous methodology included an
emissions factor that was averaged from the API E&P Tank Calc runs on both oil and condensate tanks. The new
calculation is averaged from API E&P Tank Calc runs (DB Robinson Research Ltd. 1997) for API gravity of 44
degrees and below. The adjustment has been made so that vented emissions from condensate tanks can be moved
into the emissions from natural gas systems, where they are more relevant. The second change was the
development of a new activity factor for offshore Gulf of Mexico platform venting in the production sector.
Previously, the activity factor was obtained through MMS, the total number of Gulf of Mexico platforms, and an
assumption of what percentage were oil producing platforms. The number of Gulf of Mexico platforms, platform
data, and field data is now available on an annual basis from MMS (2000, 2004b, 2004c). From the field and
platform data, a new estimate was developed for the percentage of oil producing platforms. This change results in
the model reflecting the trend towards more natural gas production than oil production in the Gulf of Mexico. A
change in the Gulf of Mexico platform activity resulted in an indirect change in the emissions factor that is
calculated from the known base-year emissions value.
The combination of these changes resulted in an average annual decrease of 7.1 Tg CO2 Eq. (27.4 percent) in CH4
emissions from petroleum systems for the period 1990 through 2002. Oil tank venting accounted for virtually all of
the decrease while Gulf of Mexico platform venting and fugitives remained relatively unchanged.
Planned Improvements
Several improvements to the emission estimates are being evaluated that fine-tune and better track changes in
emissions. These include, but are not limited to, some activity factors that are also accounted for in the Natural Gas
STAR Program emission reductions, some emission factors for consistency between emission estimates from
Petroleum Systems and Natural Gas Systems, and new data from recent studies that bear on both emission factors
and activity factors. The growing body of data in the Natural Gas STAR Program, coupled with an increasing
number of oil and gas companies doing internal greenhouse gas emissions inventories, provides an opportunity to
reevaluate emission and activity factors, as well as the methodology currently used to project emissions from the
base year.
3.8. Natural Gas Systems (IPCC Source Category 1B2b)
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 125.9 Tg CO2
Eq. (5,998 Gg) of CH4 in 2003, a slight decrease over 1990 emissions (see Table 3-40 and Table 3-41).
Improvements in management practices and technology, along with the replacement of older equipment, have
helped to stabilize emissions (EPA 2002).
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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 102
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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 34 percent of CH4 emissions from natural gas systems
in 2003.
Processing. In this stage, natural gas liquids and various other constituents from the raw gas are removed, resulting
in "pipeline quality" gas, which is injected into the transmission system. Fugitive emissions from compressors,
including compressor seals, are the primary emission source from this stage. Processing plants account for about 12
percent of 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.
Natural gas is also injected and stored in underground formations, or liquefied and stored in above ground tanks,
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. Methane emissions from transmission and storage sector account for approximately 32 percent of
emissions from natural gas systems.
Distribution. Distribution pipelines take the high-pressure gas from the transmission system at "city gate" stations,
reduce the pressure and distribute the gas through primarily underground mains and service lines to individual end
users. There were over 978,000 miles of distribution mains in 2003, an increase from just over 789,500 miles in
1990 (OPS 2002a). Distribution system emissions, which account for approximately 22 percent of emissions from
natural gas systems, result mainly from fugitive emissions from gate stations and non-plastic piping (cast iron,
steel).51 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 2003 were 10 percent lower than 1990 levels.
Table 3-40: CH4 Emissions from Natural Gas Systems (Tg CO2 Eq.)*
Stage
Field Production
Processing
1990
36
14
8
':•;," 1997
;,'i'";v 40
if: i4
Transmission and Storage 46.8f>;?/>,<" 46
Distribution
Total
30.5;^;- 32
128.
3
--"A 133.
4
9
1
4
6
1998
41.2
14.7
44.7
31.2
131.8
1999
37.5
14.6
43.4
31.9
127.4
2000
41
14
43
32
132.
0
9
4
8
1
2001
44.5
15.1
40.2
32.1
131.8
2002
44.5
14.6
42.0
29.5
130.6
2003
43.4
14.5
40.6
27.4
125.9
""Including CH4 emission reductions achieved by the Natural Gas STAR program.
Note: Totals may not sum due to independent rounding.
Table 3-41: CH4 Emissions from Natural Gas Systems (Gg)*
Stage
Field Production
Processing
Transmission and Storage
Distribution
1990
1,731
704
2,226
1,450
K'^ 1997
;•:%;'; 1,921
;;:,;- 708
='•:,";.: 2,193
&,:,' U541
1998
1,962
702
2,127
1,484
1999
1,785
696
2,068
1,517
2000
1,953
708
2,067
1,560
2001
2,117
717
1,914
1,530
2002
2,121
693
2,002
1,405
2003
2,068
691
1,933
1,305
51 The percentages of total emissions from each stage may not add to 100 because of independent rounding.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 103
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Total 6,112 V: 6,363 6,276 6,066 6,289 6,277 6,221 5,998
""Including CH4 emission reductions achieved by the Natural Gas STAR program.
Note: Totals may not sum due to independent rounding.
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, a 1992 emission estimate was developed using the emission and activity factors. For other
years, a set of industry activity factor drivers was developed 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 3.4 for more detailed information on the methodology and data used to calculate CH4 emissions from
natural gas systems.
Activity factor data were taken from the following sources: American Gas Association (AGA 1991-1998);
American Petroleum Institute (API 2002, 2003); Annual Energy Review (EIA 20021); Historical Natural Gas
Annual (EIA 2003e); Minerals and Management Service (MMS 1998, 1999, 2000, 2001, 2002a-b, 2003, 2004a-d);
Monthly Energy Review (EIA 2004d); Natural Gas Annual (EIA 1993, 1996a, 1997a, 1998a-b, 2001 a, 2002a,
2003a); Natural Gas Liquids Reserves Report (EIA 1996b, 1997b, 1998c, 1999, 2000, 200Ic, 2002d); Natural Gas
Monthly (EIA 2001b, 2002b-c, 2003b-d, 2004a-c,); the Natural Gas STAR Program annual emissions savings (EPA
2004); Oil and Gas Journal (OGJ 1999 - 2004); Office of Pipeline Safety (OPS 2004a-b) other Energy Information
Administration publications (EIA 2002e, 2004e-f). The Gas Systems Analysis model was used to aid in collecting
data for non-associated and associated wells (GSAM 1997). Data from a program for estimating emissions from
hydrocarbon production tanks is incorporated (DB Robinson Research Ltd. 1997). Coalbed Methane well activity
factors were taken from the Wyoming Oil and Gas Conservation Commission (Wyoming 2004) and the Alabama
State Oil and Gas Board (Alabama 2004). Other state well data was taken from : American Association of
Petroleum Geologists (AAPG 2204); Brookhaven College (Brookhaven 2004); Kansas Geological Survey (Kansas
2004); Rocky Mountain Production Report (Lippman (2003); Montana Board of Oil and Gas Conservation
(Montana 2004); Oklahoma Geological Survey (Oklahoma 2004); Utah Division of Oil, Gas and Mining (Utah
2004). 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. The results of the Tier 2 quantitative uncertainty analysis are
summarized in Table 3-42. Natural gas systems CH4 emissions in 2003 were estimated to be between 87.1 and
166.7 Tg CO2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Simulations). This indicates a
range of 31 percent below to 32 percent above the 2003 emission estimate of 125.9 Tg CO2 Eq.
Table 3-42: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Natural Gas Systems (Tg CO2 Eq.
and Percent)
2003
Emission Uncertainty Range Relative to Emission
Source Gas Estimate Estimate"
Natural Gas
(Tg C02 Eq.)
CH4 125.9
(TgC02Eq.)
Lower Upper
Bound Bound
87.1 166.7
(%)
Lower
Bound
-31%
Upper
Bound
+32%
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 104
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Systems
a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
Recalculations Discussion
Emissions with Natural Gas STAR Program reductions were updated using new Gas STAR emissions reduction
data from the iSTAR database. Gas STAR reductions reported retroactively for the years 1990 to 1992 are assumed
to be characterized in the GRI/EPA 1996 study for the base year 1992. Therefore, to avoid double counting, those
emissions reductions are not counted in the inventory. Gas STAR reductions are also subject to sunsetting rules that
prevent perpetual crediting of all reductions. The inventory assumes that once an emissions reducing technology is
put in place, it will continue to provide emissions savings and thus the sunsetting rule is not be implemented in the
inventory.
Three new sources of emissions in the production sector of the natural gas systems were added this year:
• Gas condensate stored in tanks vents methane and other hydrocarbons to the atmosphere. Emissions from
condensate tanks can be divided into two categories: tanks with control devices such as vapor recovery
units or flares, and tanks that have no control devices. Condensate tanks contributed an estimated 52.3 Gg
of methane emissions that represents 0.87 percent of total methane emissions from natural gas systems in
2003. In 1990, Condensate tanks were estimated to contribute 39.9 Gg of emissions or about 0.65 percent
of total emissions from natural gas systems.
• Another source added to the production sector for the 2003 reporting year was unconventional gas well
fugitives. Wells in this source were previously treated as conventional wells in the rest of U. S. (western)
geographic region. Unconventional well fugitives include fugitive emissions from coal bed CH4 and shale
wells. From 1990 through 2003, unconventional well fugitives accounted for a small amount of emissions
from natural gas systems.
• The production sector also had flaring from offshore Gulf of Mexico operations added, using a 2 percent
uncombusted hydrocarbon factor. This source contributed to less than 0.1 percent to the emissions from
the entire time series. A second Gulf of Mexico source added to the production sector was Gulf of Mexico
offshore well venting. This contributed about 2.4 percent of the 2003 emissions and about 2.6 percent in
1990.
The combination of these methodological and historical data changes resulted in an average annual increase of 6.7
Tg CO2 Eq. (5.3 percent) in CH4 emissions from natural gas systems for the penod 1990 through 2002.
Planned Improvements
Several improvements to the emission estimates are being evaluated that fine-tune and better track changes in
emissions. These include, but are not limited to, some activity factors that are also accounted for in the Natural Gas
STAR Program emission reductions, some emission factors for consistency between emission estimates from the
Petroleum Systems and Natural Gas Systems source categories, and new data from recent studies that bear on both
emission factors and activity factors. The growing body of data in the Natural Gas STAR Program, coupled with an
increasing number of oil and gas companies doing internal greenhouse gas emissions inventories, provides an
opportunity to reevaluate emission and activity factors, as well as the methodology currently used to project
emissions from the base year. Two improvements that are of particular note are in the production and processing
sector. Recent data has suggested that the emission factor for well clean-ups in the production sector is low, and
additional data sources are being investigated to produce a more robust emission factor. In the processing sector,
improvements are being considered across the entire sector based on studies completed and near completion at five
or more processing plants. These studies suggest the need for changing several emission factors as well as adding
some additional sources within the processing sector.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 105
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3.9. Municipal Solid Waste Combustion (IPCC Source Category 1A5)
Combustion is used to manage about 7 to 17 percent of the municipal solid wastes 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, Kaufman et al. 2004). Almost all combustion of municipal solid wastes 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 municipal solid wastes results in conversion of
the organic inputs to CO2. According to the IPCC Guidelines, when the CO2 emitted is of fossil origin, it is counted
as a net anthropogenic emission of CO2 to the atmosphere. Thus, the emissions from waste combustion are
calculated by estimating the quantity of waste combusted and the fraction of the waste that is carbon derived from
fossil sources.
Most of the organic materials in municipal solid wastes 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 3-3).
However, some components—plastics, synthetic rubber, synthetic fibers, and carbon black—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
municipal solid wastes are predominantly from clothing and home furnishings. Tires (which contain rubber and
carbon black) are also considered a "non-hazardous" waste and are included in the municipal solid waste
combustion estimate, though waste disposal practices for tires differ from the rest of municipal solid waste.
[Begin Text Box]
Box 3-3: Biogenic Emissions and Sinks of Carbon
For many countries, CO2 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 CO2. 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. However, the focus of the UNFCCC 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 the combustion or decomposition of 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 CO2 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, yard trimmings, and food scraps resulted in net long-
term storage of 10.1 Tg CO2 Eq. in 2003, as described in the Land-Use Change and Forestry chapter.
[End Box]
Approximately 24 million metric tons of municipal solid wastes were combusted in the United States in 2003.
Carbon dioxide emissions from combustion of municipal solid wastes rose 72 percent since 1990, to an estimated
18.8 Tg CO2 Eq. (18,781 Gg) in 2003, as the volume of plastics and other fossil carbon-containing materials in
MSW increased (see Table 3-43 and Table 3-44). Waste combustion is also a source of N2O emissions (De Soete
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 106
-------
1993). Nitrous oxide emissions from municipal solid waste combustion were estimated to be 0.5 Tg CO2 Eq. (1 Gg)
in 2003, and have not changed significantly since 1990.
Table 3-43: CO2 and N2O Emissions from Municipal Solid Waste Combustion (Tg CO2 Eq.)
Gas/Waste Product
C02
Plastics
Synthetic Rubber in Tires
Carbon Black in Tires
Synthetic Rubber in MSW
Synthetic Fibers
N2O
Total
1990 ;Vi,V;:
10.9 •''•' /.,.
8.0 lf::"\*.
0.2 ;.'-V'
r v.
0.2 ''""'-
1.3 ,/.,*•
1.2 •;„ v
0.4 ''•'/'.:;•
H.3 Sii;S.
1997
17.8
11.9
0.9
1.2
1.7
2.1
0.4
18.1
1998
17.1
11.4
0.9
1.2
1.6
2.0
0.3
17.4
1999
17.6
12.0
0.9
1.2
1.6
2.0
0.3
18.0
2000
18.0
12.1
0.9
1.2
1.7
2.1
0.4
18.3
2001
18.8
12.7
0.9
1.2
1.8
2.2
0.5
19.2
2002
18.8
12.7
0.9
1.2
1.8
2.2
0.5
19.2
2003
18.8
12.7
0.9
1.2
1.8
2.2
0.5
19.2
Table 3-44: CO2 and N2O Emissions from Municipal Solid Waste Combustion (Gg)
Gas/Waste Product
CO2
Plastics
Synthetic Rubber in Tires
Carbon Black in Tires
Synthetic Rubber in MSW
Synthetic Fibers
N2O
1990 (A'.,;,:
10,919 ',;<"•
7,953 > '•',,
191 ;/. •;
249 !;„« '
1,330 ,;;''"'
1,196 j;',
1 V,
1997
17,761
11,914
891
1,165
1,725
2,065
1
1998
17,094
11,427
887
1,160
1,627
1,992
1
1999
17,632
11,950
890
1,164
1,612
2,016
1
2000
17,979
12,145
893
1,167
1,689
2,086
1
2001
18,781
12,718
895
1,170
1,810
2,187
1
2002
18,781
12,718
895
1,170
1,810
2,187
1
2003
18,781
12,718
895
1,170
1,810
2,187
1
Ambient air pollutants are also emitted during waste incineration and open burning, as shown in Table 3-45. These
emissions are a relatively small portion of the overall ambient air pollutant emissions, comprising less than 5 percent
for each gas over the entire time series.
Table 3-45: NOX, CO, and NMVOC Emissions from Municipal Solid Waste Combustion (Gg)
Gas/Source
NOX
Waste Incineration
Open Burning
CO
Waste Incineration
Open Burning
NMVOCs
Waste Incineration
Open Burning
1990 |;£y
82 V,f
44 >'';•
38 >';
978 'il,
337 ;// V
641 i^,;
222 ;,'f'
44 >:",,
178 '>,l i
1997
140
48
92
2,668
68
2,600
313
23
290
1998
145
49
96
2,826
69
2,757
326
23
303
1999
143
48
95
2,725
66
2,659
302
19
284
2000
114
38
76
1,670
40
1,630
257
15
242
2001
114
38
76
1,672
41
1,631
258
16
242
2002
134
45
89
1,672
41
1,631
281
18
264
2003
121
41
80
1,674
41
1,633
263
16
246
Note: Totals may not sum due to independent rounding.
Methodology
Emissions of CO2 from MSW combustion include CO2 generated by the combustion of plastics, synthetic fibers,
and synthetic rubber, as well as the combustion of synthetic rubber and carbon black in tires. These emissions were
calculated by multiplying the amount of each material combusted by the carbon content of the material and the
fraction oxidized (98 percent). Plastics combusted in municipal solid wastes 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 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
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 107
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number of scrap tires used for fuel and the synthetic rubber and carbon black content of the tires. More detail on the
methodology for calculating emissions from each of these waste combustion sources is provided in Annex 3.6.
For each of the methods used to calculate CO2 emissions from municipal solid waste combustion, data on the
quantity of product combusted and the carbon content of the product are needed. For plastics, synthetic rubber, and
synthetic fibers, the amount of material in municipal solid wastes and its portion combusted were taken from the
Characterization of Municipal Solid Waste in the United States (EPA 2000c, 2002a, 2003). For synthetic rubber
and carbon black in scrap tires, this information was provided by the U.S. Scrap Tire Markets 2001 (RMA 2002)
and Scrap Tires, Facts and Figures (STMC 2000, 2001, 2002, 2003). Data were not available for 2002 or 2003, so
the values for these years were assumed to equal the value for 2001.
Average carbon contents for the "Other" plastics category, synthetic rubber in municipal solid wastes, and synthetic
fibers were calculated from 1998 production statistics, which divide their respective markets by chemical
compound. For synthetic rubber in scrap tires information about scrap tire composition was taken from the Scrap
Tire Management Council's internet site (STMC 2003).
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 (EPA 2002b).
Combustion of municipal solid waste also results in emissions of N2O. These emissions were calculated as a
function of the total estimated mass of municipal solid waste combusted and an emission factor. The N2O emission
estimates are based on different data sources. As noted above, N2O emissions are a function of total waste
combusted in each year; for 1990 through 2002, these data were derived from the information published in BioCycle
(Kaufman et al 2004). As for the activity data for CO2 emissions, data on total waste combusted was not available
for 2003, so the value for this year was assumed to equal the most recent value available (2002). Table 3-46
provides data on municipal solid waste generation and percentage combustion for the total waste stream. The
emission factor of N2O emissions per quantity of municipal solid waste combusted is an average of values from
IPCC's Good Practice Guidance (2000).
Table 3-46: Municipal Solid Waste Generation (Metric Tons) and Percent Combusted
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Waste Generation
266,365,714
254,628,360
264,668,342
278,388,835
292,915,829
296,390,405
297,071,712
308,870,755
339,865,243
347,089,277
371,071,109
404,002,786a
436,934,464
436,934,464b
Combusted (%)
11.5
10.0
11.0
10.0
10.0
10.0
10.0
9.0
7.5
7.0
7.0
7.4a
7.7
7.7b
a Interpolated between 2000 and 2002 values.
bAssumed equal to 2002 value.
EPA (2003) provided emission estimates for NOX, CO, and NMVOCs from waste incineration and open burning,
which were determined using industry published production data and applying average emission factors.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 108
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Uncertainty
A Tier 2 Monte Carlo analysis was performed to determine the level of uncertainty surrounding the estimates of
CO2 emissions and N2O emissions from municipal solid waste combustion. IPCC Tier 2 analysis allows the
specification of probability density functions for key variables within a computational structure that mirrors the
calculation of the inventory estimate. Uncertainty estimates and distributions for waste generation variables (i.e.,
plastics, synthetic rubber, and textiles generation) were obtained through a conversation with one of the authors of
the Municipal Solid Waste in the United States reports. Statistical analyses or expert judgments of uncertainty were
not available directly from the information sources for the other variables; thus, uncertainty estimates for these
variables were determined using assumptions based on source category knowledge and the known uncertainty
estimates for the waste generation variables. The highest levels of uncertainty surround the variables that are based
on assumptions (e.g., percent of clothing and footwear composed of synthetic rubber); the lowest levels of
uncertainty surround variables that were determined by quantitative measurements (e.g., combustion efficiency,
carbon content of carbon black).
The results of the 2003 uncertainty analysis of CO2 emissions are the same as the 2002 results, given that the data
for the two years is identical (no data updated for 2003 were available). The results of the Tier 2 quantitative
uncertainty analysis are summanzed in Table 3-47. Municipal solid waste combustion CO2 emissions in 2003 were
estimated to be between 15.2 and 21.6 Tg CO2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo
Simulations). This indicates a range of 19 percent below to 15 percent above the 2003 emission estimate of 18.8 Tg
CO2 Eq. Also at a 95 percent confidence level, municipal solid waste combustion N2O emissions in 2003 were
estimated to be between 0.13 and 1.34 Tg CO2 Eq. This indicates a range of 71 percent below to 192 percent above
the 2003 emission estimate of 0.5 Tg CO2 Eq.
Table 3-47: Tier 2 Quantitative Uncertainty Estimates for CO2 and N2O from Municipal Solid Waste Combustion
(Tg CO2 Eq. and Percent)
2003 Emission Uncertainty Range Relative to
Source Gas Estimate Emission Estimate"
(TgC02Eq.) (TgC02Eq.) (%)
Municipal Solid Waste Combustion CO2 18.8
Municipal Solid Waste Combustion N2O 0.5
Lower
Bound
15.2
0.13
Upper
Bound
21.6
1.34
Lower
Bound
-19%
-71%
Upper
Bound
+15%
+192%
a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
The 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, 2003) estimates of materials generated, discarded, and
combusted carry considerable uncertainty associated with the matenal flows methodology used to generate
them. Similarly, the BioCycle (Glenn 1999, Goldstein and Matdes 2000, Goldstein and Matdes 2001, Kaufman
et al. 2004) 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. The survey methodology changed significantly and thus the results reported for 2002
are not directly comparable to the earlier results (Kaufman et al. 2004), introducing further uncertainty. Despite
the differences in methodology and data sources, the two references— the EPA's Office of Solid Waste (EPA
2000a, 2002b, 2003) and the BioCycle series—provide estimates of total solid waste combusted that are
relatively consistent (see Table 3-48).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 109
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Table 3-48: U.S. Municipal Solid Waste Combusted, as Reported by EPA and BioCycle (Metric Tons)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
EPA
28,855,809
27,773,783
29,568,442
28,696,188
29,532,844
32,182,194
32,831,450
33,597,844
31,205,358
30,859,134
30,512,946
30,569,746
NA
NA
BioCycle
30,632,057
25,462,836
29,113,518
27,838,884
29,291,583
29,639,040
29,707,171
27,798,368
25,489,893
24,296,249
25,974,978
29,694,205a
33,643,954
NA
NA (Not Available)
a Interpolated between 2000 and 2002 values.
• 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. Despite this variability in oxidation rates, a value of 98 percent was
assumed for this analysis.
• Missing Data on Municipal Solid Waste Composition. Disposal rates have been interpolated when there is an
incomplete interval within a time series. Where data are not available for years at the end of a time series
(1990, 2003), they are set equal to the most recent years for which estimates are available.
• Average Carbon Contents. Average carbon contents were applied to the mass of "Other" plastics combusted,
synthetic rubber in tires and municipal solid waste, 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 chemical formulation 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 municipal solid waste is biogenic in
origin. Assumptions have been made concerning the allocation between synthetic and biogenic materials based
primarily on expert judgment.
• Combustion Conditions Affecting N2O Emissions. Because insufficient data exist to provide detailed estimates
of N2O emissions for individual combustion facilities, the estimates presented exhibit high uncertainty. The
emission factor for N2O from municipal solid waste combustion facilities used in the analysis is an average of
default values used to estimate N2O emissions from facilities worldwide (Johnke 1999, UK: Environment
Agency 1999, Yasuda 1993). These factors span an order of magnitude, reflecting considerable variability in
the processes from site to site. 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 also exhibits uncertainty.
Recalculations Discussion
The N2O emissions estimates for 2001 and 2002 are slightly different from those reported in last year's inventory
because newly-available data (Kaufman et al. 2004) were used for the tonnage of waste burned in municipal solid
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 110
-------
waste combustion for those years. The change resulted in 2001 and 2002 N2O emissions from municipal solid
waste combustion that increased by less than 0.1 Tg CO2 Eq. (14.7 percent and 26.4 percent, respectively).
The NOX, CO, and NMVOC emissions estimates for 1999 through 2002 also vary slightly from last year's inventory
due to revised criteria pollutant data from EPA. The change constituted less than a 1687 Gg decrease in NOX, CO,
and NMVOC emissions in 2002.
3.10. Natural Gas Flaring and Ambient Air Pollutant Emissions from Oil and Gas
Activities (IPCC Source Category 1B2)
The flaring of natural gas from on- and off-shore oil wells is a small source of CO2. 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.
The flaring (i.e. combustion) and venting of natural gas during petroleum production result in the release of CO2
and CH4 emissions, respectively. Barns and Edmonds (1990) noted that of total reported U.S. venting and flaring,
approximately 20 percent may be vented, with the remaining 80 percent flared, but it is now believed that flaring
accounts for an even greater proportion. Studies indicate that the percentage of natural gas that is flared from off-
shore U.S. production is considerably lower (approximately 30 percent in 2003), due in part to differences in the
legislation governing on- and off-shore natural gas production. Methane emissions from venting are accounted for
in the Petroleum Systems source category. For 2003, total CO2 emissions from flaring activities were estimated to
be 5.9 Tg CO2 Eq. (5,970 Gg), an increase of 3 percent from 1990 levels. On-shore flaring activities accounted for
5.7 Tg CO2 Eq. (5,743 Gg), or 96 percent, of the total flaring emissions, while off-shore flaring constituted 0.2 Tg
CO2 Eq. (227 Gg), or 4 percent, of the total (see Table 3-49).
Table 3-49: CO2 Emissions from On-Shore and Off-Shore Natural Gas Flaring (Tg CO2 Eq.)
On-Shore Flaring
Off-Shore Flanng
Total Flaring
1990 1997
5.5
0.3
;" ::: 7.6
$•' 0.3
5.8 '• 7.9
1998
6.3
0.3
6.6
1999
6.7
0.3
7.0
2000
5.5
0.2
5.8
2001
5.9
0.2
6.1
2002
6.0
0.2
6.2
2003
5.7
0.2
5.9
Note: Totals may
Table 3-50: CO2 Emissions from On-Shore and Off-Shore Natural Gas Flaring (Gg)
On-Shore Flaring
Off-Shore Flaring
1990 1997
5,514
296
r j: 7,565
£$ 309
1998
6,250
316
1999
6,679
264
2000
5,525
244
2001
5,858
236
2002
6,006
227
2003
5,743
227
Total Flaring
5,810
i inai narmg 3,oiu '• /,o/t 0,31
Note: Totals may not sum due to independent rounding
7,874 6,566 6,943 5,769 6,094 6,233 5,970
In addition, oil and gas activities, including production, transportation, and storage, result in the release of small
amounts of NOX, CO, and NMVOCs. Ambient air pollutant emissions from this source from 1990 to 2003 are
presented below (see Table 3-51).
Table 3 -51:
Year
1990
|}s " i , ? ^ ;,( ,
|v'4 ' 1°' i ^ i „' UV
1996
1997
1998
1999
2000
2001
NOX, NMVOCs,
NOX
139
' * ' ;ini "'''«/ y,\Vv;> ,*' V',,
• i^'f '•f < >£f A1"' i1 '*!' * j,jy
126 "
130
130
109
111
113
and CO Emissions from Oil
CO
302
tWj ' •" ' '' ~ A '
/ t' *i f (
321
333
332
145
146
147
NMVOCs
555
'-,*,* u ' \ A
' '„ ^ ,,'M H'\ ,/M ,/V
433
442
440
414
389
400
and Gas Activities (Gg)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 111
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2002 135 116 340
2003 124 125 345
Methodology
Estimates of CO2 emissions from on- and off-shore natural gas flaring 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.
Total on-shore natural gas vented and flared was taken from EIA's Natural Gas Annual (EIA 2004); however, there
is a discrepancy in the time series. One facility in Wyoming had been incorrectly reporting CO2 vented as CH4.
EIA noted and 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 3-52. 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). The emission and thermal
conversion factors were also provided by EIA (2001) and are included in Table 3-52.
The total off-shore natural gas vented and flared was obtained from the Minerals Management Service's OGOR-B
reports (MMS 2003). The percentage of natural gas flared was estimated using data from a 1993 air quality study
and emissions inventory of the Gulf of Mexico (MOADS) and a 2000 emissions inventory conducted for the Breton
National Wilderness Area Management Plan (BOADS). See Table 3-53
Emission estimates for NOX, CO, and NMVOCs from petroleum refining, petroleum product storage and transfer,
and petroleum marketing operations were obtained from preliminary data (EPA 2003), which, in its final iteration,
will be published on the National Emission Inventory (NEI) Air Pollutant Emission Trends web site. 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.
Table 3-52: Total Natural Gas Reported Vented and Flared (Million Ft3) and Thermal Conversion Factor (Btu/Ft3)
Year Vented and Vented and Flared Thermal
Flared (original) (revised)* Conversion
Factor
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
150,415
169,909
167,519
226,743
228,336
283,739
272,117
256,351
103,019
110,285
91,232
96,913
99,173
94,929
91,130
92,207
83,363
108,238
109,493
144,265
135,709
124,918
103,019
110,285
91,232
96,913
99,173
94,929
1,105
1,108
1,110
1,106
1,105
1,106
1,109
1,107
1,109
1,107
1,107
1,105
1,107
1,106
Wyoming venting and flaring estimates were revised. See text for further explanation.
Table 3-53: Volume Flared Offshore (MMcf) and Fraction Vented and Flared (Percent)
1990||| 1997 1998 1999 2000 2001 2002 2003
Total Gulf of Mexico (GOM) i|§i
Vented & Flared (MMcf) 13,610i|;| 15,440 16,280 14,05712,97112,990 12,487 12,487
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 112
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Estimated Flaring Fraction of GOM *j§&
Vented & Flared 36%||j 33% 32% 31% 31% 30% 30% 30%
Total 4,900J| 5,095 5,210 4,358 4,021 3,897 3,746 3,746
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.
Recalculations Discussion
The historical data for natural gas flaring was adjusted slightly, which resulted in an average annual increase in CO2
emissions from flaring of 0.1 Tg CO2 Eq. (2.3 percent) for the period 1990 through 2002.
3.11. International Bunker Fuels (IPCC Source Category 1: Memo Items)
Emissions resulting from the combustion of fuels used for international transport activities, termed international
bunker fuels under the 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.52 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/IEA 1997),53
Greenhouse gases emitted from the combustion of international bunker fuels, like other fossil fuels, include CO2,
CH4, N2O, CO, NOX, NMVOCs, particulate matter, and SO2.54 Two transport modes are addressed under the IPCC
definition of international bunker fuels: aviation and marine.55 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 compnses 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.,
52 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).
5j Note that the definition of international bunker fuels used by the UNFCCC differs from that used by the International Civil
Aviation Organization.
54 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.
55 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).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 113
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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.56
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.57 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.58 The vast majority of aircraft NOX emissions occur at these
lower cruising altitudes of commercial subsonic aircraft (NASA 1996).59
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 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 2003 from the combustion of international bunker fuels from both
aviation and marine activities were 85.1 Tg CO2 Eq., or 26 percent below emissions in 1990 (see Table 3-54).
Although emissions from international flights departing from the United States have increased significantly (29
percent), emissions from international shipping voyages departing the United States have decreased by 63 percent
since 1990. 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 3-55).
Table 3-54: Emissions from International Bunker Fuels (Tg CO2 Eq.)
Gas/Mode
C02
Aviation
Marine
CH4
Aviation
Marine
N2O
Aviation
Marine
Total
1990 M/,
H3.5 ';f^i
46.2 :':„ ;.
67.3 ,».£
0.2 'jfy
+ '-il^'l
0.1 >« $
1.0 $?
0.5 '-•:';[
0.5 ;^*
114.6 "/;?
1997
109.9
55.9
54.0
0.1
+
0.1
1.0
0.5
0.4
111.0
1998
114.6
56.7
57.9
0.2
+
0.1
1.0
0.6
0.4
115.7
1999
105.3
58.9
46.4
0.1
+
0.1
0.9
0.6
0.4
106.4
2000
101.4
60.5
40.9
0.1
+
0.1
0.9
0.6
0.3
102.4
2001
97.9
59.4
38.5
0.1
+
0.1
0.9
0.6
0.3
98.9
2002
89.5
61.8
27.7
0.1
+
0.1
0.8
0.6
0.2
90.4
2003
84.2
59.6
24.6
0.1
+
0.1
0.8
0.6
0.2
85.1
+ Does not exceed 0.05 Tg CO2 Eq
56 Naphtha-type jet fuel was used in the past by the military in turbojet and turboprop aircraft engines.
57 Currently there are only around a dozen civilian supersonic aircraft in service around the world that fly at these altitudes,
however.
58 However, at this lower altitude, ozone does little to shield the earth from ultraviolet radiation.
59 Cruise altitudes for civilian subsonic aircraft generally range from 8.2 to 12.5 km (27,000 to 41,000 feet).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 114
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Note: Totals may not sum due to independent rounding. Includes aircraft cruise altitude emissions.
Table 3-55: Emissions from International Bunker Fuels (Gg)
Gas/Mode
C02
Aviation
Marine
CH4
Aviation
Marine
N2O
Aviation
Marine
CO
Aviation
Marine
NOX
Aviation
Marine
NMVOC
Aviation
Marine
1990 .yv''
46,230 £ L')'. f;
67,272 £ A'x?
si\'$
1 L ,'^ ,7^
7 £ 'i:: ;
3^
l^^V
2 ^ •';,,',*'
115$: -v.'.
76^V';
39^4>:
1,985 £;£•>
182^',-x"
1,803 ^;>'-Tsj.
59 Ux
11 ";Q-
48^1;
1997
109,858
55,899
53,960
7
2
5
3
2
1
124
92
32
1,668
221
1,446
52
14
38
1998
114,557
56,657
57,900
7
2
6
3
2
1
127
93
34
1,778
224
1,554
55
14
41
1999
105,294
58,865
46,429
6
2
5
3
2
1
124
97
27
1,478
233
1,245
48
15
33
2000
101,404
60,545
40,859
6
2
4
3
2
1
124
100
24
1,334
240
1,095
44
15
29
2001
97,865
59,388
38,477
5
2
4
3
2
1
120
98
23
1,266
235
1,031
42
15
27
2002
89,489
61,787
27,701
4
2
3
3
2
1
118
102
16
988
245
743
35
15
20
2003
84,193
59,558
24,635
4
2
2
2
2
1
113
98
15
900
236
664
32
15
18
Note: Totals may not sum due to independent rounding. Includes aircraft cruise altitude emissions.
Methodology
Emissions of CO2 were estimated by applying 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. Carbon
content and fraction oxidized factors for jet fuel, distillate fuel oil, and residual fuel oil were taken directly from the
EIA and are presented in Annex 2.1, Annex 2.2, and Annex 3.7. Heat content and density conversions were taken
from EIA (2004) and USAF (1998). A complete description of the methodology and a listing of the various factors
employed can be found in Annex 2.1. See Annex 3.7 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. Emission factors used in the calculations of CH4, N2O, CO,
NOX, and NMVOC emissions were obtained from the Revised 1996IPCC 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 N2O, 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 for N2O, 1.9 for CO, 87 for NOX, and 0.052 g/MJ for NMVOCs. Activity
data for aviation included solely jet fuel consumption statistics, while the marine mode included both distillate
diesel and residual fuel oil.
Activity data on aircraft fuel consumption were collected from three government agencies. Jet fuel consumed by
U.S. flag air earners for international flight segments was supplied by the Bureau of Transportation Statistics (DOT
1991 through 2004). 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. 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 2004). Approximate average fuel prices paid by air carriers for aircraft on international flights
was taken from DOT (1991 through 2004) 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
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 115
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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 2004). 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 3-56. See Annex 3.7 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 2004). Activity data on distillate diesel
consumption by military vessels departing from U.S. ports were provided by DESC (2004). 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 3-57.
Table 3-56: Aviation Jet Fuel Consumption for International Transport (Million Gallons)
Nationality
U.S. Carriers
Foreign Carriers
U.S. Military
Total
1990
1,954
2,051
862
4,867
•'•;;;> 1997
*? ', 2,457
•;;' ; 2,939
'•> ••, '' 496
;,A; 5,892
1998
2,462
3,009
502
5,973
1999
2,625
3,093
488
6,206
2000
2,737
3,166
480
6,384
2001
2,619
3,118
524
6,261
2002
2,495
3,537
482
6,515
2003
2,418
3,388
473
6,280
Note: Totals may not sum due to independent rounding.
Table 3-57: Marine Fuel Consumption for International Transport (Million Gallons)
Fuel Type
Residual Fuel Oil
Distillate Diesel Fuel & Other
U.S. Military Naval Fuels
Total
1990 ;
4,781 ,/,,;
617 ;i '-
522 "V:
5,920 IsS.
; 1997
;, 3,843
421
': 484
;, 4,748
1998
3,974
627
518
5,119
1999
3,272
308
511
4,091
2000
2,967
290
329
3,586
2001
2,846
204
318
3,368
2002
1,937
158
348
2,443
2003
1,597
137
459
2,193
Note: Totals may not sum due to independent rounding.
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.60 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.
See uncertainty discussions under Carbon Dioxide Emissions from Fossil Fuel Combustion.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 116
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Particularly for aviation, the DOT (1991 through 2004) 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 2004) 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.61
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 associated with ground fuel estimates for 1997 through 2001. Small fuel
quantities may have been used in vehicles or equipment other than that which was assumed for each fuel type.
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. The data were adjusted for trends in fuel use based on a closely
correlating, but not matching, data set. All assumptions used to develop the estimate were based on process
knowledge, Department and Component 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 emission estimates could be reduced through additional data collection.
Although aggregate fuel consumption data have 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 CO2.62
There is also concern as to the reliability of the existing DOC (1991 through 2004) data on marine vessel fuel
consumption reported at U.S. customs stations due to the significant degree of inter-annual variation.
61 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.
62 U.S. aviation emission estimates for CO, NOX, and NMVOCs are reported by EPA's National Emission Inventory (NEI) Air
Pollutant Emission Trends web site, and reported under the Mobile Combustion section. It should be noted that these estimates
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 reported under
the Mobile Combustion section overestimate IPCC-defmed 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. The estimates in Mobile Combustion are also likely to include emissions from
ocean-going vessels departing from U.S. ports on international voyages.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 117
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QA/QC and Verification
A source-specific QA/QC plan for international bunker fuels was developed and implemented. This effort included
a Tier 1 analysis, as well as portions of a Tier 2 analysis. The Tier 2 procedures that were implemented involved
checks specifically focusing on the activity data and emission factor sources and methodology used for estimating
CO2, CH4, and N2O from international bunker fuels in the United States. Emission totals for the different sectors
and fuels were compared and trends were investigated. No corrective actions were necessary.
Recalculations Discussion
Historical activity data for aviation was slightly revised for both U.S. and foreign carriers. These changes were due
to revisions to international fuel cost for foreign carriers and international jet fuel consumption for U.S. carriers,
provided by DOT (1991 through 2004). These historical data changes resulted in minimal changes to the emission
estimates for 1990 through 2002, which averaged to an annual increase in emissions from international bunker fuels
of less than 0.1 Tg CO2 Eq. (0.1 percent) in CO2 emissions, annual increase of less than 0.1 Tg CO2 Eq. (less than
0.1 percent) in CH4 emissions, and annual increase of less than 0.1 Tg CO2 Eq. (0.1 percent) in N2O emissions.
3.12. Wood Biomass and Ethanol Consumption (IPCC Source Category 1A)
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 CO2. 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 2003, total CO2 emissions from the burning of woody biomass in the industrial, residential, commercial, and
electricity generation sectors were approximately 201.0 Tg CO2 Eq. (201,042 Gg) (see Table 3-58 and Table 3-59).
As the largest consumer of woody biomass, the industrial sector was responsible for 71 percent of the CO2
emissions from this source. The residential sector was the second largest emitter, constituting 18 percent of the
total, while the commercial and electricity generation sectors accounted for the remainder.
Table 3-58: CO2 Emissions from Wood Consumption by End-Use Sector (Tg CO2 Eq.)
End-Use Sector
Industrial
Residential
Commercial
Electricity Generation
Total
1990|;;r>, 1997
135.
59
4
13
212.
3
9
0
3
s-CvW 162
*>;'/ 44
y ' ;J ) " ' ^
y,
C?J 14
5 ,1',C •' 226
.4
.6
.0
.1
.3
1998
150.5
39.9
5.0
14.1
209.5
1999
152.0
42.7
5.4
14.2
214.3
2000
153
44
5
13
217
.6
.7
.5
.9
.6
2001
135.4
38.2
4.2
13.0
190.8
2002
143.7
32.3
4.3
15.5
195.8
2003
143.1
37.0
4.4
16.6
201.0
Note: Totals may not sum due to independent rounding.
Table 3-59: CO2 Emissions from Wood Consumption by End-Use Sector (Gg)
End-Use Sector
Industrial
Residential
Commercial
Electricity Generation
Total
1990 j,
135,347
59,911
4,037
13,252 •
212,547 ,
•;,iL",* 1
;;;,, •, 162
'>"?; 44
;,;••.;• 5
|£- 14
:\,\ 226
1996
,447
650
,042
,126
,265
1997
150,510
39,920
4,963
14,097
209,490
]
152
4?
5
14
214
1998
,019
677
,394
,233
,323
1999
153,559
44,685
5,481
13,851
217,577
135
38
4
13
190
JOOO
,413
153
,175
,034
,776
2001
143,694
32,276
4,319
15,487
195,775
2002
143,084
37,019
4,369
16,570
201,042
Note: Totals may not sum due to independent rounding.
Biomass-derived fuel consumption in the United States consisted primarily of ethanol use in the transportation
sector. Ethanol is primarily produced from corn grown in the Midwest, and was used mostly in the Midwest and
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 118
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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.
These fuels burn cleaner than gasoline (i.e., lower in NOX and hydrocarbon emissions), and have been employed in
urban areas with poor air quality. However, because ethanol is a hydrocarbon fuel, its combustion emits CO2.
In 2003, the United States consumed an estimated 239 trillion Btus of ethanol, and as a result, produced
approximately 15.8 Tg CO2 Eq. (15,771 Gg) (see Table 3-60) of CO2 emissions. Ethanol production and
consumption has grown steadily every year since 1990, with the exception of 1996 due to short corn supplies and
high prices in that year.
Table 3-60: CO2 Emissions from Ethanol Consumption
Year Tg CO2 Eq. Gg
1990
1997
1998
1999
2000
2001
2002
2003
42
M"",; '., ,,;>;«
7.0
7.7
8.0
9.2
9.7
11.5
15.8
4,155
;,:''••. -4 '''''•'• V
6,978
7,711
8,017
9,188
9,701
11,473
15,771
Methodology
Woody biomass emissions were estimated by taking U.S. consumption data (EIA 2004) (see Table 3-61), provided
in energy units for the industrial, residential, commercial, and electric generation sectors, and applying two EIA
gross heat contents (Lindstrom 2003). One heat content (16.953114 MMBtu/MT Wood & Wood Waste) was
applied to the industrial sector's consumption, while the other heat content (15.432359 MMBtu/MT Wood & Wood
Waste) was applied to the consumption data for the other sectors. An EIA emission factor of 0.434 MT C/MT
Wood (Lindstrom 2003) was then applied to the resulting quantities of woody biomass to obtain CO2 emissions
estimates. It was assumed that the woody biomass contains black liquor and other wood wastes, has a moisture
content of 12 percent, and is converted into carbon dioxide with 100 percent efficiency. The emissions from
ethanol consumption were calculated by applying an EIA emission factor of 17.99 Tg C/QBtu (Lindstrom 2003) to
U.S. ethanol consumption data that were provided in energy units (EIA 2004) (see Table 3-62).
Table 3-61: Woody Biomass Consumption by Sector (Trillion Btu)
Year Industrial Residential Commercial Electricity Generation
1990 1,442 581 39 129
fi'«/%':r;, i, •*•;, '
1997
1998
1999
2000
2001
2002
2003
V i "' i 1 t> **' t> ' ' V,^, •
1,731
1,603
1,620
1,636
1,443
1,531
1,524
•', ,», ;•';",»",';•';","".,.''/' •'•*'
433
387
414
433
370
313
359
• '' !•'' • ,'•""' ',.•','.'' ',. • >• . 'Ai -X1 • '«<'«<'«<"'«<'«<•
49'
48
52
53
40
42
42
137"*
137
138
134
126
150
161
Table 3-62: Ethanol Consumption
Year Trillion Btu
1990 63
1997 106
1998 117
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 119
-------
1999
2000
2001
2002
2003
122
139
147
174
239
Uncertainty
It is assumed that the combustion efficiency for woody biomass is 100 percent, which is believed to be an
overestimate of the efficiency of wood combustion processes in the United States. Decreasing the combustion
efficiency would increase emission estimates. Additionally, the heat content applied to the consumption of woody
biomass in the residential, commercial, and electric power sectors is unlikely to be a completely accurate
representation of the heat content for all the different types of woody biomass consumed within these sectors.
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.
Recalculations Discussion
The historical data for wood biomass consumption was adjusted slightly, which resulted in an average annual
decrease in emissions from wood biomass and ethanol consumption of 0.3 Tg CO2 Eq. (0.1 percent) from 1990
through 2002.
[BEGIN BOX]
Box 3-4: Formation of CO2 through Atmospheric CH4 Oxidation
Methane emitted to the atmosphere will eventually oxidize into CO2, 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 Conformation that results from this CH4 oxidation. The IPCC Guidelines for Greenhouse Gas Inventories
(IPCC/UNEP/OECD/IEA 1997) do not explicitly recommend a procedure for accounting for oxidized CH4, but
some of the resulting CO2 is, in practice, included in the inventory estimates because of the intentional "double-
counting" structure for estimating CO2 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 CO2 in the atmosphere. This is accomplished by using CO2
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 CO2 molecule.63 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 CO2.
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
6j 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).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 120
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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 CO2 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 CO2 burden in the atmosphere, and this effect is not captured
in the inventory. The following tables provide estimates of the equivalent CO2 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 3-63. The CO2 estimates are summarized in Table
3-64.
Table 3-63: CH4 Emissions from Non-Combustion Fossil Sources (Gg)
Source
Coal Mining
Abandoned Coal Mines
Natural Gas Systems
Petroleum Systems
Petrochemical Production
Silicon Carbide
Production
Iron and Steel Production
Total
1990
3,900 £
288 £
6,112 £
951 g
56 g
1 S
:£••:
63 v.f
11,371
1997
2,983
385
6,363
895
78
1
60
10,765
]
2
6
10
1998
,989
341
976
879
80
1
57
,622
1999
2,805
349
6,066
848
81
1
56
10,205
2000
2,677
369
6,289
836
80
1
57
10,308
2001
2,647
331
6,277
831
68
+
51
10,206
2002
2,497
303
6,221
815
72
+
48
9,956
2003
2,561
306
5,998
815
72
+
49
9,801
Note: These emissions are accounted for under their respective source categories. Totals may not sum due to independent
rounding.
Table 3-64: Formation of CO2 through Atmospheric CH4 Oxidation (Tg CO2 Eq.)
Source
Coal Mining
Abandoned Coal Mines
Natural Gas Systems
Petroleum Systems
Petrochemical Production
Silicon Carbide Production
Iron and Steel Production
Total
1990
10.7 :;>
16.8 :;>
2.6 >
+ i^
0.2 ^v
31.3 -a
1997
8.2
1.1
17.5
2.5
0.2
: +
0.2
29.6
1998
8.2
0.9
17.3
2.4
0.2
+
0.2
29.2
1999
7.7
1.0
16.7
2.3
0.2
+
0.2
28.1
2000
7.4
1.0
17.3
2.3
0.2
+
0.2
28.3
2001
7.3
0.9
17.3
2.3
0.2
+
0.1
28.1
2002
6.9
0.8
17.1
2.2
0.2
+
0.1
27.4
2003
7.0
0.8
16.5
2.2
0.2
+
0.1
27.0
Note: Totals may not sum due to independent rounding.
+ Does not exceed 0.05 Tg CO2 Eq.
The estimates of CO2 formation are calculated by applying a factor of 44/16, which is the ratio of molecular weight
of CO2 to the molecular weight of CH4. For the purposes of the calculation, it is assumed that CH4 is oxidized to
CO2 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 CO2 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 CO2 emissions in
the mass balance.64
[END BOX]
64 See Annex 2.3 for a more detailed discussion on accounting for indirect emissions from CO and NMVOCs.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 121
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Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 122
-------
Fossil Fuel Combustion
Natural Gas Systems
Mobile Sources
Coal Mining
Stationary Sources
Waste Combustion
Petroleum Systems
Natural Gas Flaring
5,551.6
Energy as a Portion
of all Emissions
20 40 60 80 100 120 140
Tg C02Eq.
Figure 3-1: 2003 Energy Sector Greenhouse Gas Sources
-------
3-2
2003 U.S. (Tg Eq.)
Note: Totals may not sum due to independent rounding.
The "Balancing Item" above accounts for statistical imbalances and unknowns in the reportei
data sets combined here.
NEU = Non-Energy Use
NG = Natural Gas
-------
6.1% Renewable
8.0% Nuclear
22.5%
Natural Gas
22.8% Coal
39.1%
Petroleum
Figure 3-3: 2003 U.S. Energy Consumption by Energy Source
120 -,
100 -
S"
m
g 80 J
CL
I 60 ^
3
§; 40 ^
-------
2,000 -
1,500 -
1,000 -
500 -
o -
Relative Contribution by
Fuel Type
~1 Natural Gas
'•: Petroleum
I Coal
8
Figure 3-5: 2003 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
Note: The electricity generation sector also includes emissions of less than 0.01 Tg CO2 Eq.
from geothermal-based electricity generation
-------
15 -,
Normal
(4,576 Heating Degree Days)
1954 1958 1962 1966
1970
1974 1978 1982 1986 1990 1994 1998 2002
Figure 3-6. Annual Deviations from Normal Heating Degree Days for the United States (1949-2003)
Note: Climatological normal data are highlighted.
Statistical confidence interval for "normal" climatology period of 1961 through 1990.
1950 1954 1958 1962 1966 1970 1974 1978 1982 1986 1990 1994 1998 2002
Figure 3-7: Annual Deviations from Normal Cooling Degree Days for the United States (1949-2003)
Note: Climatological normal data are highlighted.
Statistical confidence interval for "normal" climatology period of 1961 through 1990.
-------
100
Figure 3-8: Aggregate Nuclear and Hydroelectric Power Plant Capacity Factors in the United States (1973-2003)
2000 -
1800 -
1600 -
a- 140° "
^ 1200 -
o 1000 -
01 800 -
600 -
400 -
200 -
0 -
• From Electricity
Consumption
• From Direct Fossil
Fuel Combustion
Figure 3-9: 2003 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion
110 -,
105 -
8 100 -
A 95 -
8
90 -
80 -
Cents per Gallon
Cents per VMT
75 -I
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Figure 3-10: Motor Gasoline Retail Prices (Real)
-------
24 -i
Passenger Cars
14 -1
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Figure 3-11: Motor Vehicle Fuel Efficiency
-------
130 i Total excluding Computers, Total Industrial
Communications Equip., and Index
Semiconductors
90 -
70 -
120 -,
100 ^f
80 -
110 -
90 -
70 -
110 -
90 -
70 -
Paper
Foods
Stone, Clay & Glass
Products
Figure 3-12: Industrial Production Indexes (Index 1997=100)
-------
120 -,
no -
E100
90
80 -I
Normal
(5,424 Heatinq Deqree Days)
Figure 3-13: Heating Degree Days
Note: Excludes Alaska and Hawaii
120 -,
Hno -
=100
Normal
(1,215 Cooling Degree Days)
90 -
80 -1
Figure 3-14: Cooling Degree Days
Note: Excludes Alaska and Hawaii
1,400 -i
1,200 -
2003
Figure 3-15: Electric Generation Retail Sales by End-Use Sector
Note: The transportation end-use sector consumes minor quanties of electricity.
-------
103 -
99 -
§ 95 -
M
g 91 -
s
'x' 87 -
OJ
-c
•5 83 -
79 -
CO2/capita
inergy
Consumption/
capita
75 J
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Figure 3-16: U.S. Energy Consumption and Energy-Related CO2 Emissions
Per Capita and Per Dollar GDP
CO2/$GDP
Energy
Consumption/$GDP
8
20-
10 -
N20
CH4
Figure 3-17: Mobile Source CH4 and N2O Emissions
-------
4. 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
manufacture, ammonia manufacture and urea application, lime manufacture, limestone and dolomite use (e.g., flux
stone, flue gas desulfurization, and glass manufacturing), soda ash manufacture and use, titanium dioxide
production, phosphoric acid production, ferroalloy production, CO2 consumption, aluminum production,
petrochemical production, silicon carbide production, nitric acid production, and adipic acid production (see Figure
4-1).
Figure 4-1: 2003 Industrial Processes Chapter Greenhouse Gas Sources
In addition to the three greenhouse gases listed above, there are also industrial sources 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. In addition, many of these gases have high global warming potentials; SF6 is the most
potent greenhouse gas the IPCC has evaluated. 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, SF6, and other fluorinated compounds are employed and emitted by a number of other
industrial sources in the United States. These industries include aluminum production, HCFC-22 production,
semiconductor manufacture, electric power transmission and distribution, and magnesium metal production and
processing.
In 2003, industrial processes generated emissions of 308.6 teragrams of CO2 equivalent (Tg CO2 Eq.), or 4.5
percent of total U.S. greenhouse gas emissions. Carbon dioxide emissions from all industrial processes were 147.2
Tg CO2 Eq. (147,172 Gg) in 2003. This amount accounted for only 2.5 percent of national CO2 emissions.
Methane emissions from petrochemical, silicon carbide, and iron and steel production resulted in emissions of
approximately 2.5 Tg CO2 Eq. (121 Gg) in 2003, which was 0.5 percent of U.S. CH4 emissions. Nitrous oxide
emissions from adipic acid and nitric acid production were 21.8 Tg CO2 Eq. (71 Gg) in 2003, or 5.8 percent of total
U.S. N2O emissions. In 2003, combined emissions of HFCs, PFCs and SF6 totaled 137.0 Tg CO2 Eq. Overall,
emissions from industrial processes increased by 2.9 percent from 1990 to 2003 despite decreases in emissions from
several industrial processes, such as iron and steel, electrical transmission and distribution, HCFC-22 production,
and aluminum production. The increase in overall emissions was driven by a rise in the emissions originating from
cement manufacture and, primarily, the emissions from the use of substitutes for ozone depleting substances.
Table 4-1 summarizes emissions for the Industrial Processes chapter in units of Tg CO2 Eq., while unweighted
native gas emissions in gigagrams (Gg) are provided in Table 4-2.
Table 4-1: Emissions from Industrial Processes (Tg CO2 Eq )
Gas/Source
C02
Iron and Steel Production
Cement Manufacture
Ammonia Manufacture & Urea Application
Lime Manufacture
Limestone and Dolomite Use
Aluminum Production
1990 £
173.1 11
854 •:;'
33 3 I-'"
193 •;;
1 1 2 11
5 5 '.'.
63 ,"
'2: 19!
•;*,• ITO
V 71
;••' 38
•!V 20
vj, 13
'<;;,* 7
'^ « r-
:,-i 5
)7
.9
.9
o
.7
.7
.2
.6
19<
169
67
3Q
21
13
7
5
J8
.4
.4
o
.9
.9
.4
.8
1999
165.9
64.4
40 0
20.6
13.5
8.1
5.9
20(
164
65
41
19
13
6
5
)0
.7
.7
T
.6
.3
.0
.7
2001
151.8
58.9
41 4
16.7
12.8
5.7
4.1
2002
151.5
55.1
42 9
18.6
12.3
5.9
4.2
2003
147.2
53.8
43 0
15.6
13.0
4.7
4.2
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 123
-------
Soda Ash Manufacture and Consumption
Petrochemical Production
Titanium Dioxide Production
Phosphoric Acid Production
Ferroalloy Production
Carbon Dioxide Consumption
CH4
Petrochemical Production
Iron and Steel Production
Silicon Carbide Production
N2O
Nitric Acid Production
Adipic Acid Production
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
+ Does not exceed 0.05 Tg CO2 Eq.
41 )'•'*••• 4'4
22j;f;<;'- 2.9
i 3 f :•*'.• •;' 1-8
1 5j-;:';«- ,- 1.5
20j;f;<;'- 2.0
0 9 (-.;*••<' 0.8
2.5 j-.'';:' ,; 2.9
12j;V' 1.6
13 {'.?;•'?' L3
+ ;'•«;•; +
33.0 1 ;-,;''• 31.5
17 8 (:?;•;' 21.2
152t'',i"';:; 10.3
91.2 [A;; '; 121.7
04f,;V:l 46.5
/• *' ', '"•'
35oi;:v;( 30,o
292f.;v\ 21.7
183t-7'fr H-0
2 9 i'^' 6.3
54^f; 6.3
299.9 .?";>. 327.1
4.3
3.0
1.8
1.6
2.0
0.9
2.9
1.7
1.2
+
26.9
20.9
6.0
135.7
56.6
40.1
17.1
9.1
7.1
5.8
334.9
4.2
3.1
1.9
1.5
2.0
0.8
2.9
1.7
1.2
+
25.6
20.1
5.5
134.8
65.8
30.4
16.4
9.0
7.2
6.0
329.2
4
^
1
1
1
1
2
1
1
25
19
6
138
75
29
15
9
6
3
332
2
0
9
4
7
0
.9
7
2
+
.6
6
0
.9
0
8
6
0
3
2
.1
4.1
2.8
1.9
1.3
1.3
0.8
2.5
1.4
1.1
+
20.8
15.9
4.9
4.1
2.9
2.0
1.3
1.2
1.0
2.5
1.5
1.0
+
23.1
17.2
5.9
129.5 138.3
83.3
19.8
15.4
4.0
4.5
2.6
91.5
19.8
14.7
5.2
4.4
2.6
304.7 315.4
4
2
2
1
1
1
2
1
1
21
15
6
137
99
12
14
3
4
3
308
1
8
0
4
4
3
.5
5
0
+
.8
8
0
.0
5
3
1
8
3
0
.6
Note: Totals may not sum due to independent rounding.
Table 4-2: Emissions from Industrial Processes (Gg)
Gas/Source
C02
Iron and Steel Production
Cement Manufacture
Ammonia Manufacture & Urea
Application
Lime Manufacture
Limestone and Dolomite Use
Aluminum Production
Soda Ash Manufacture and Consumption
Petrochemical Production
Titanium Dioxide Production
Phosphoric Acid Production
Ferroalloy Production
Carbon Dioxide Consumption
CH4
Petrochemical Production
Iron and Steel Production
Silicon Carbide Production
N2O
Nitric Acid Production
Adipic Acid Production
HFCs, PFCs, and SF6
Substitution of Ozone Depleting
Substances
HCFC-22 Production3
Electrical Transmission and Distribution1"
Aluminum Production
1990 > 1997
173,122
85413
33,278
19,306
11,238
5,533
6,315
4,141
2,221
1,308
1,529
1,980
860
120
56
63
1
107
58
49
M
M
3
1
1998
t 170,884 169,425
V- 71,863
i: 38,323
'f. 20,650
"l
'";• 13,685
{' 7,242
t" 5>621
£ 4,354
'ff 2,919
(' 1,836
!''. 1,544
*- 2,038
'fft 808
> 139
;'. 78
t 60
"'"" 1
V 102
!;. 68
V 33
*'; M
,V M
*",'
"i * i
i J
' 1
M '•';- M
67,428
39218
21,934
13,914
7,449
5,792
4,325
3,015
1,819
1,593
2,027
912
138
80
57
1
87
67
19
M
M
3
1
M
1999
165,908
64,376
39,991
20,615
13,466
8,057
5,895
4,217
3,054
1,853
1,539
1,996
849
138
81
56
1
83
65
18
M
M
3
1
M
2000
164,657
65,
41,
19,
13,
5,
5,
4,
3,
1,
1,
1,
693
190
616
315
959
723
181
004
918
382
719
957
138
80
57
1
83
63
19
M
M
3
1
M
2001
151,835
58,887
41,357
16,719
12,823
5,733
4,114
4,147
2,787
1,857
1,264
1,329
818
119
68
51
+
67
51
16
M
M
2
1
M
2002
151,
55,
42,
18,
12,
5,
4,
4,
2,
1,
1,
1,
2003
506 147
082
898
571
304
885
220
139
857
997
338
237
978
120
72
48
+
75
56
19
M
M
2
1
M
53
,172
.763
43,030
15,560
12,983
4
4
4
2
2
1
1
,720
,219
,082
,777
,013
,382
,374
1,267
121
72
49
+
70
51
19
M
M
1
1
M
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 124
-------
Semiconductor Manufacture M ?,' > M M M M M M M
Magnesium Production and Processing1" + ;"",% + + + + + + +
NOX 591 : J 629 637 595 626 656 630 648
CO 4,124 :,; 3,153 3,163 2,156 2,217 2,339 2,308 2,431
NMVOCs 2,426 ft 2,038 2,047 1,813 1,773 1,769 1,725 1,711
+ 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.
In order to ensure the quality of the emission estimates from industrial processes, Tier 1 procedures and checks have
been performed on all industrial process sources. If performed, Tier 2 procedures focused on the emission factor
and activity data sources and methodology used for estimating emissions procedures, and will be described within
the QA/QC and Verification Discussion of that source description. In addition to the national QA/QC plan, a more
detailed plan was developed specifically for the CO2 and CH4 industrial processes sources. This plan was based on
the U.S. strategy, but was tailored to include specific procedures recommended for these sources.
The general method employed to estimate emissions for industrial processes, as recommended by the
Intergovernmental Panel on Climate Change (IPCC), involves multiplying production data (or activity data) for
each process by an emission factor per unit of production. The uncertainty of the emission estimates is therefore
generally a function of a combination of the uncertainties surrounding the production and emission factor variables.
Uncertainty of activity data and the associated probability density functions for industrial processes CO2 sources
were estimated based on expert assessment of available qualitative and quantitative information. Uncertainty
estimates and probability density functions for the emission factors used to calculate emissions from this source
were devised based on IPCC recommendations.
Activity data is obtained through a survey of manufacturers conducted by various organizations (specified within
each source); the uncertainty of the activity data is a function of the reliability of plant-level production data and is
influenced by the completeness of the survey response. 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; therefore, they may not represent U.S. national averages. Additional assumptions
are described within each source.
The uncertainty analysis performed to quantify uncertainties associated with the 2003 inventory estimates from
industrial processes continues a multi-year process for developing credible quantitative uncertainty estimates for
these source categories using the IPCC Tier 2 approach. As the process continues, the type and the characteristics
of the actual probability density functions underlying the input variables are identified and better characterized
(resulting in development of more reliable inputs for the model, including accurate characterization of correlation
between variables), based primarily on expert elicitation. Accordingly, the quantitative uncertainty estimates
reported in this section should be considered illustrative and as iterations of ongoing efforts to produce accurate
uncertainty estimates. The correlation among data used for estimating emissions for different sources can influence
the uncertainty analysis of each individual source. While the uncertainty analysis recognizes very significant
connections among sources, a more comprehensive approach that accounts for all linkages will be identified as the
uncertainty analysis moves forward.
4.1. Iron and Steel Production (IPCC Source Category 2C1)
In addition to being an energy intensive process, the production of iron and steel also generates process-related
emissions of CO2 and CH4. 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 coking coal as a raw material. Iron may be introduced into the blast
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 125
-------
furnace in the form of raw iron ore, pellets, briquettes, or sinter. Pig iron (containing about 0.4 percent carbon by
weight) is used as a raw material in the production of steel. Pig iron is also used as a raw material in the production
of iron products in foundries. The pig iron production process produces CO2 emissions and fugitive CH4 emissions.
The production of metallurgical coke from coking coal and the consumption of the metallurgical coke used as a
reducing agent in the blast furnace are considered in the inventory to be non-energy (industrial) processes, not
energy (combustion) processes. Coal coke is produced by heating coking coal in a coke oven in a low-oxygen
environment. The process drives off the volatile components of the coking coal and produces coal coke. Coke
oven gas and coal tar are carbon by-products of the coke manufacturing process. Coke oven gas is generally burned
as a fuel within the steel mill. Coal tar is used as a raw material to produce anodes used for primary aluminum
production and other electrolytic processes, and also used in the production of other coal tar products. The coke
production process produces CO2 emissions and fugitive CH4 emissions.
Smtenng is a thermal process by which fine iron-bearing particles, such as air emission control system dust, are
baked, which causes the material to agglomerate into roughly one-inch pellets that are then recharged into the blast
furnace for pig iron production. Iron ore particles may also be formed into larger pellets or bnquettes by
mechanical means, and then agglomerated by heating prior to being charged into the blast furnace. The sintering
process produces CO2 emissions and fugitive CH4 emissions.
The metallurgical coke is a reducing agent in the blast furnace. 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 and CH4 from iron and steel production in 2003 were 53.8 Tg CO2 Eq. (53,763 Gg) and 1.0 Tg
CO2 Eq. (48.7 Gg), respectively (see Table 4-3 and Table 4-4). Emissions have fluctuated significantly from 1990
to 2003 due to changes in domestic economic conditions and changes in product imports and exports. In 2003,
domestic production of pig iron and coal coke increased by 2.2 and 2.4 percent, respectively. Despite these
increases, domestic pig iron and coke production have declined since the 1990s. Pig iron production in 2003 was
15 percent lower than in 2000 and 19 percent below 1995 levels. Coke production in 2003 was 17 percent lower
than in 2000 and 38 percent below 1990 levels. A slowdown in the domestic and worldwide economy and the
availability of low-priced imports limit growth in domestic production (USGS 2002).
Table 4-3: CO2 and CH4 Emissions from Iron and Steel Production (Tg CO2 Eq.)
Year
C02
CH4
Total
Table 4-4:
Year
CO,
CH4
1990
85.4 ff-«
• •• .• '.. '
1.3 ":--v
86.7 v>::
CO2 and CH4
1990
85,413 :!™r
63 ,JX..
; 1997
:;;. 71.9
;"•; 1.3
<•• 73.1
Emissions from
1997
:" 71,863
^ 60
1998
67.4
1.2
68.6
Iron and Steel
1998
67,428
57
1999
64.4
1.2
65.5
Production
1999
64,376
56
2000
65.7
1.2
66.9
(Gg)
2000
65,693
58
2001
58.9
1.1
60.1
2001
58,887
51
2002
55.1
1.0
56.1
2002
55,082
48
2003
53.8
1.0
54.8
2003
53,763
49
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 2.1.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 126
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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 during 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 used in the production of
steel in electric arc furnaces 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 have already been
accounted for earlier in the iron and steel emissions calculation as part of the coking process, the emission factor
was reduced by 20 percent to avoid double counting. Additionally, emissions from the coal tar pitch component of
carbon anodes consumed during the production of aluminum, which are accounted for in the aluminum production
section of this chapter, have been subtracted from the total coal tar emissions that were calculated above.
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 by-weight carbon content of 4 percent.
The production processes for coal coke, sinter, and pig iron result in fugitive emissions of CH4, which are emitted
via leaks in the production equipment rather than through the emission stacks or vents of the production plants. The
fugitive emissions were calculated by applying emission factors taken from the 1996IPCC Guidelines
(IPCC/UNEP/OECD/IEA 1997) (see Table 4-5) to annual domestic production data for coal coke, sinter, and pig
iron.
Table 4-5: CH4 Emission Factors for Coal Coke, Sinter, and Pig Iron Production (g/kg)
Material Produced g CH^kg produced
Coal Coke 0,5
Pig Iron 0.9
Sinter 0.5
Source: IPCC/UNEP/OECD/IEA 1997
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 the Energy
Information Administration (EIA), Quarterly Coal Report January through December 2003 (EIA 2004); U.S. Coal
Domestic and International Issues (EIA 2001); Mineral Yearbook: Iron and Steel (USGS 1993, 1995a, 1997, 1999,
2000a, 2001 a, 2002a) and the American Iron and Steel Institute (AISI), Annual Statistical Report (AISI 2001, 2002,
2003, 2004). Scrap steel and imported pig iron consumption data for 1990 through 2003 were obtained from
Annual Statistical Reports (AISI 1995, 2001, 2002, 2003, 2004) (see Table 4-6). Crude steel production, as well as
pig iron use for purposes other than steel production, was also obtained from Annual Statistical Reports (AISI 1996,
2001, 2002, 2004). Carbon content percentages for pig iron and crude steel and the CO2 emission factor for carbon
anode emissions from steel production were obtained from. IPCC Good Practice Guidance and Uncertainty
Management (IPCC 2000). Aluminum production data for 1990 through 2003 were obtained from Mineral
Industry Surveys: Aluminum Annual Report (USGS 1995b, 1998, 2000b, 200 Ib, 2002b, 2003, 2004a). Annual
consumption of iron ore used in sinter production for 1990 through 2003 were obtained from the USGS Iron Ore
yearbook (USGS 1994, 1995c, 1996, 1997b, 1998b, 1999b, 2000c, 2001c, 2002c, 2004b). The CO2 emission factor
for carbon anode emissions from aluminum production was taken from the Revised 1996IPCC Guidelines
(IPCC/UNEP/OECD/IEA 1997). Estimates for the composition of carbon anodes used during steel and aluminum
production were obtained from Energy and Environmental Profile of the U.S. Aluminum Industry (DOE 1997).
Table 4-6: Production and Consumption Data for the Calculation of CO2 and CH4 Emissions from Iron and Steel
Production (Thousand Metric Tons)
Gas/Activity Data 1990 1997 1998 1999 2000 2001 2002 20oJ
C02
Coal Consumption at Coke Plants 35,289 :t' 27,400 25,573 25,499 26,253 23,655 21,460 21,997
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 127
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Coke Consumption for Pig Iron
Domestic Pig Iron Production for Steel
Basic Oxygen Furnace Steel Production
Electric Arc Furnace Steel Production
CH4
Coke Production
Iron Ore Consumption for Sinter
Domestic Pig Iron Production for Steel
24,946 ;;;;
49,061 I;
56,227 I;
33,517 1;
25,054 |
12,239 i"
49,061 u
22,100 19,800 18,700 19,215 17,129 15,850 15,379
48,676 47,470 45,677 47,399 41,740 39,600 40,487
55,386 54,146 52,364 53,964 47,359 45,463 45,873
43,098 44,513 45,063 47,859 42,743 46,124 47,803
20,063 18,181 18,240 18,877 17,190 15,220 15,579
•:' 11,426 10,791 11,072 10,784 9,234 9,018 8,984
. 48,676 47,470 45,677 47,399 41,740 39,600 40,487
Uncertainty
The time series data for production of coal coke, sinter, pig iron, steel, and aluminum and import and export data
upon which the calculations are based are considered to be consistent for the entire time series. The estimates of
CO2 emissions from the production and utilization of coke are based on energy consumption data, average carbon
contents, and the fraction of carbon oxidized. These data and factors produce a relatively accurate estimate of CO2
emissions. However, there are uncertainties associated with each of these factors. For example, carbon oxidation
factors may vary depending on inefficiencies in the combustion process, where varying degrees of ash or soot can
remain unoxidized.
Simplifying assumptions were made concerning the composition of carbon anodes (80 percent petroleum coke and
20 percent coal tar). For example, within the aluminum industry, the coal tar pitch content of anodes can vary from
15 percent in prebaked anodes to 24 to 28 percent in Soderberg anode pastes (DOE 1997). An average value was
assumed and applied to all carbon anodes utilized during aluminum and steel production. The assumption is also
made that all coal tar used during anode production originates as a by-product of the domestic coking process.
Similarly, it was assumed that all pig iron and crude steel have carbon contents of 4 percent and 0.4 percent,
respectively. The carbon content of pig iron can vary between 3 and 5 percent, while crude steel can have a carbon
content of up to 2 percent, although it is typically less than 1 percent (IPCC 2000).
There is uncertainty in the most accurate CO2 emission factor for carbon anode consumption in aluminum
production. Emissions vary depending on the specific technology used by each plant (Prebake or Soderberg). The
Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) provide CO2 emission factors for each technology
type. Consistent with the assumptions used in the Aluminum Production source, 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.
For the purposes of the CH4 calculation it is assumed that none of the CH4 is captured in stacks or vents and that all
of the CH4 escapes as fugitive emissions. Additionally, the CO2 emissions calculation is not corrected by
subtracting the carbon content of the CH4, which means there may be a slight double counting of carbon as both
CO2 and CH4.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-7. Iron and Steel CO2
emissions were estimated to be between 32.0 and 76.4 Tg CO2 Eq. at the 95 percent confidence level (or in 19 out
of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 41 percent below and 42
percent above the emission estimate of 53.8 Tg CO2 Eq. Iron and Steel CH4 emissions were estimated to be
between 0.9 Tg CO2 Eq. and 1.1 Tg CO2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo
Stochastic Simulations). This indicates a range of approximately 11 percent below and 11 percent above the
emission estimate of 1.0 Tg CO2 Eq.
Table 4-7: Tier 2 Quantitative Uncertainty Estimates for CO2 and CH4 Emissions from Iron and Steel Production
(Tg. CO2 Eq. and Percent)
Source
Gas
2003 Emission
Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (%)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 128
-------
Lower Bound Upper Bound Lower Bound Upper Bound
Iron and Steel CO2 53.8 32.0 76.4 -41% +42%
Iron and Steel CH4 1_0 0_9 1_1 -11% +11%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Recalculations Discussion
Estimates of CO2 from iron and steel production increased due to revised production data found in American Iron
and Steel Institute's 2003 Annual Statistical Report (AISI 2004) and EIA's 2003 Quarterly Coal Report (EIA
2004). These changes resulted in an average increase of 0.2 Tg CO2 Eq. (0.5 percent) in CO2 emissions from iron
and steel production for 2001 and 2002.
Estimates of CH4 2002 were revised due to revised sinter production data provided by the U.S. Geological Survey's
Iron and Steel Report 2003 (USGE 2004b). This change resulted in an increase of less than 0.1 Tg CO2 Eq. (0.8
percent) in CH4 emissions from iron and steel production for 2002.
4.2. Cement Manufacture (IPCC Source Category 2A1)
Cement manufacture is an energy and raw material intensive process that results in the generation of CO2 from both
the energy consumed in making the cement and the chemical process itself.l Cement production has accounted for
about 2.4 percent of total global industrial and energy-related CO2 emissions, and the United States is the world's
third largest cement producer (IPCC 1997, USGS 2003). Cement is manufactured in nearly 40 states. Carbon
dioxide emitted from the chemical process of cement production represents one of the largest sources of industrial
CO2 emissions in the United States.
During the cement production process, calcium carbonate (CaCO3) is heated in a cement kiln at a temperature of
about 1,300°C (2,400°F) to form lime (i.e., calcium oxide or CaO) and CO2. This process is known as calcination or
calcining. Next, the lime is combined with silica-containing materials to produce clinker (an intermediate product),
with the earlier by-product CO2 being released to the atmosphere. The clinker is then allowed to cool, mixed with a
small amount of gypsum, and used to make portland cement. The production of masonry cement from portland
cement requires additional lime and, thus, results in additional CO2 emissions. However, this additional lime is
already accounted for in the Lime Manufacture source category in this chapter; therefore, the additional emissions
from making masonry cement from clinker are not counted in this source category's total. They are presented here
for informational purposes only.
In 2003, U.S. clinker production—including Puerto Rico—totaled 83,214 thousand metric tons (Van Oss 2004).
The resulting emissions of CO2 from 2003 cement production were estimated to be 43.0 Tg CO2 Eq. (43,030 Gg)
(see Table 4-8). Emissions from masonry production from clinker raw material are accounted for under Lime
Manufacture.
Table 4-8: CO2 Emissions from Cement Production (Tg CO2 Eq. and Gg)*
Year Tg CO2 Eq. Gg
1990 33.3 33,278
1997 38.3 38,323
1998 39.2 39,218
1999 40.0 39,991
1 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 129
-------
2000 41.2 41,190
2001 41.4 41,357
2002 42.9 42,898
2003 43.0 43,030
* Totals exclude CO2 emissions from making masonry cement from clinker, which are accounted for under Lime Manufacture.
After falling in 1991 by two percent from 1990 levels, cement production emissions have grown every year since.
Overall, from 1990 to 2003, emissions increased by 29 percent. 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 + CO2
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:
. ,
Clinker
=0.646 CaO:
44.01g/moleCO
2
56.08 g/moleCaO
= 0.507 tons CO /ton clinker
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 two 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
five 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:
0.6x0.057(1+0.05) = 2.86%
An emission factor for this added lime can then be calculated by multiplying this 2.86 percent by the molecular
weight ratio of CO2 to CaO (0.785) to yield 0.0224 metnc tons of additional CO2 emitted for every metnc 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, the activity data for masonry cement
production are shown in this chapter for informational purposes only, and are not included in the cement emission
totals.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 130
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The 1990 through 2003 activity data for clinker and masonry cement production (see Table 4-9) was obtained
through a personal communication with Hendrick Van Oss (Van Oss 2004) of the USGS and through the USGS
Mineral Yearbook: Cement (USGS 1992 through 2003). Data for 2003 masonry cement production were
unavailable and were assumed to equal 2002 data. The data were compiled by USGS through questionnaires sent to
domestic clinker and cement manufacturing plants.
Table 4-9: Cement Production (Gg)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Clinker
64,355
62,918
63,415
66,957
69,786
71,257
71,706
74,112
75,842
77,337
79,656
79,979
82,959
83,214
Masonry
3,209
2,856
3,093
2,975
3,283
3,603
3,469
3,634
3,989
4,375
4,332
4,450
4,449
4,449
Uncertainty
The uncertainties contained in these estimates are primarily due to uncertainties in the lime content of clinker and in
the percentage of CKD recycled inside the clinker kiln. There is also an uncertainty in the amount of lime added to
masonry cement, but it is accounted for under the Lime Manufacture source category. The lime content of clinker
varies from 64 to 66 percent. CKD loss can range from 1.5 to eight percent depending upon plant specifications.
Additionally, some amount of CO2 is reabsorbed when the cement is used for construction. As cement reacts with
water, alkaline substances such as calcium hydroxide are formed. During this curing process, these compounds may
react with CO2 in the atmosphere to create calcium carbonate. This reaction only occurs in roughly the outer 0.2
inches of surface area. Because the amount of CO2 reabsorbed is thought to be minimal, it was not estimated.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-10. Cement Manufacture CO2
emissions were estimated to be between 39.7 and 46.3 Tg CO2 Eq. at the 95 percent confidence level (or in 19 out
of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 8 percent below and 8 percent
above the emission estimate of 43.0 Tg CO2 Eq.
Table 4-10: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Cement Manufacture (Tg CO2 Eq.
and Percent)
Source
Cement
Manufacture
„ 2003 Emission TT . . . „ T> • ^ ± ^ • • ^ ±- ± a
Gas _ , . , Uncertainty Range Relative to Emission Estimate
Estimate J s
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower Bound Upper Bound Lower Bound
CO2 43,0 39,7 46,3 -8%
Upper Bound
+8%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
QA/QC and Verification
Based on the results of the Tier 2 uncertainty analysis conducted on the cement emissions estimate for the 2004 U.S.
GHG Inventory, the United States decided to conduct Tier 2 QA procedures on two elements of the cement
emissions estimate for the current inventory submission: the CaO content of clinker and emissions from production
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 131
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of CKD. The United States currently uses the IPCC default values for these input values and the current
investigation seeks to determine whether these default values are reflective of U.S. circumstances. We are currently
in the process of conducting a form of expert elicitation on these values. Preliminary results suggest that the default
values seem appropriate for the U.S. cement industry however there may be small differences. We are currently
investigating any differences and will include any results in future inventories, if appropriate.
4.3. Ammonia Manufacture and Urea Application (IPCC Source Category 2B1)
Emissions of CO2 occur during the production of synthetic ammonia, primarily through the use of natural gas as a
feedstock. One ammonia production plant located in Kansas is producing ammonia from petroleum coke feedstock.
The natural gas-based, naphtha-based, and petroleum coke-based processes produce CO2 and hydrogen (H2), the
latter of which is used in the production of ammonia. In some plants the CO2 produced is captured and used to
produce urea. The brine electrolysis process for production of ammonia does not lead to CO2 emissions.
There are five principal process steps in synthetic ammonia production from natural gas feedstock. The primary
reforming step converts 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 (N2) 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)
0.88 CH4 + 1.26 Air + 1.24 H2O -- > 0.88 CO2 + N2 + 3 H2
To produce synthetic ammonia from petroleum coke, the petroleum coke is gasified and converted to CO2 and H2.
These gases are separated, and the H2 is used as a feedstock to the ammonia production process, where it is reacted
with N2 to form ammonia.
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 + C02 -» NH2COONH4 -» CO(NH2)2 + H2O
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 manufacture in 2003 were 9. 1 Tg CO2 Eq. (9,097 Gg), and are summarized in
Table 4-11 and Table 4-12. Emissions of CO2 from urea application in 2003 totaled 6.5 Tg CO2 Eq. (6,463Gg), and
are summarized in Table 4-1 1 and Table 4-12.
Table 4-11: CO2 Emissions from Ammonia Manufacture and Urea Application (Tg CO2 Eq.) _
Source _ 1990 •;££ I"7 I"8 I"9 200° 20°1 2002 2003
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 132
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Ammonia Manufacture 126 ,-','.-. 14.0 14.2 12.9 12.1 9.3 10.6 9.1
Urea Application 68 j-',' 6.6 7.7 7.7 7.5 7.4 8.0 6.5
Total 19.31-^' 20.7 21.9 20.6 19.6 16.7 18.6 15.6
Table 4-12: CO2 Emissions from Ammonia Manufacture and Urea Application (Gg)
Source
Ammonia Manufacture
Urea Application
1990 .,;£:<
12,553 Iffy.
6,753 j~\,"
; 1997 1998 1999 2000 2001 2002 2003
14,028 14,215 12,948 12,128 9,321 10,561 9,097
6,622 7,719 7,667 7,488 7,398 8,010 6,463
Methodology
The calculation methodology for non-combustion CO2 emissions from production of nitrogenous fertilizers from
natural gas feedstock is based on a CO2 emission factor published by the European Fertilizer Manufacturers
Association (EFMA). The CO2 emission factor (1.2 metric tons CO2/metric ton NH3) is applied to the percent of
total annual domestic ammonia production from natural gas feedstock. 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 do not change as a
result of this calculation, but some of the CO2 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 are assumed to be from the same process—conventional
catalytic reforming of natural gas feedstock, with the exception of ammonia production from petroleum coke
feedstock at one plant located in Kansas. The CO2 emission factor for production of ammonia from petroleum coke
is based on plant specific data, wherein all carbon contained in the petroleum coke feedstock that is not used for
urea production is assumed to be emitted to the atmosphere as CO2 (Bark 2004). 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. The CO2 emission factor (3.57 metric tons CO2/metric ton NH3) is
applied to the percent of total annual domestic ammonia production from petroleum coke feedstock.
The emission factor of 1.2 metric ton CO2/metric ton NH3 for production of ammonia from natural gas feedstock
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 metric ton
CO2/metric ton NH3, with 1.2 metric ton CO2/metric 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.
The emission factor of 3.57 metric ton CO2/metric ton NH3 for production of ammonia from petroleum coke
feedstock was developed from plant-specific ammonia production data and petroleum coke feedstock utilization
data for the ammonia plant located in Kansas (Bark 2004). Ammonia and urea production data (see Table 4-13 and
Table 4-14, respectively) were obtained from the Census Bureau of the U.S. Department of Commerce (U.S. Census
Bureau 1991 through 2004) as reported in Current Industrial Reports Fertilizer Materials and Related Products
annual and quarterly reports. Import and export data for 2003 were unavailable and were assumed to equal 2002
data (see Table 4-15). These 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 2002, 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.
Table 4-13: Ammonia Production (Gg)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 133
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Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Table 4- 14:
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Table 4- 15:
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Gg
15,425
15,576
16,261
15,599
16,211
15,788
16,260
16,231
16,761
15,728
14,342
11,092
12,577
10,468
Urea Production (Gg)
Gg
8,124
7,373
8,142
7,557
7,584
7,363
7,755
7,430
8,042
8,080
6,969
6,080
7,038
5,783
Urea Net Imports (Gg)
Gg
1,086
648
656
2,305
2,249
2,055
1,051
1,600
2,483
2,374
3,241
4,008
3,884
3,030
Uncertainty
The uncertainties contained in these estimates are primarily due to how accurately the emission factor used
represents an average across all ammonia plants using natural gas feedstock. The EFMA reported an emission
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 134
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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.2
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 from EIA for other years, and data for 1991 and previous years may underestimate feedstock natural
gas consumption, and therefore the EFMA 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, with the exception of one ammonia production plant located in Kansas
that is manufacturing ammonia from petroleum coke feedstock. Research indicates that there is only one U.S. plant
that manufactures ammonia from petroleum coke. CO2 emissions from this plant are explicitly accounted for in the
Inventory estimates. No data for ammonia plants using naphtha or other feedstocks other than natural gas have been
identified. Therefore, all other CO2 emissions from ammonia plants are calculated using the emission factor for
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.
Such recovery may or may not affect the overall estimate of CO2 emissions from that sector depending upon the end
use to which the recovered CO2 is applied. For example, research has identified one ammonia production plant that
is recovering byproduct CO2 for use in EOR. Such CO2 would be assumed to remain sequestered [see the section of
2 It appears 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 CO2per ton ammonia, respectively) and it is likely that if one value
does not include fuel use, the other value also does not. For the conventional steam reforming process, however, 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 CO2per ton ammonia reported
by the EFMA. Because it appears that the emission factors cited in the IPCC Guidelines may actually include natural gas used as
fuel, we use the 1.2 tons/ton emission factor developed by the EFMA.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 135
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this chapter on Carbon Dioxide Consumption] however, time series data for the amount of CO2 recovered from this
plant is not available and therefore all of the CO2 produced by this plant is assumed to be emitted to the atmosphere
and allocated to Ammonia Manufacture. Further research is required to determine whether byproduct CO2 is being
recovered from other ammonia production plants for application to end uses that are not accounted for elsewhere.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-16. Ammonia CO2 emissions
were estimated to be between 7.7 and 10.4 Tg CO2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte
Carlo Stochastic Simulations). This indicates a range of approximately 15 percent below and 15 percent above the
emission estimate of 9.1 Tg CO2 Eq. Urea CO2 emissions were estimated to be between 6.0 and 7.0 Tg CO2 Eq. at
the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of
approximately 8 percent below and 8 percent above the emission estimate of 6.5 Tg CO2 Eq.
Table 4-16: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Ammonia Manufacture and Urea
Application (Tg CO2 Eq. and Percent)
Source
Ammonia
Urea
2003 Emission TT . . . „ ^ , +• + ^ • • ^ +• ^ a
„ „ , . Uncertainty Range Relative to Emission Estimate
Gas Estimate
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower Bound
CO2 9.1 7.7
CO2 6.5 6.0
Upper Bound
10.4
7.0
Lower Bound
-15%
-8%
Upper Bound
+15%
+8%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Recalculations Discussion
Estimates of CO2 emissions from ammonia manufacture for the years 2000, 2001, and 2002 were updated to reflect
revisions made to the methodology to include ammonia manufactured from petroleum coke. The plant, located in
Kansas, began ammonia production in 2000. This change resulted in an average annual increase in CO2 emissions
from ammonia manufacture of 0.5 Tg CO2 Eq. (2.7 percent) for the years 2000 through 2002.
Planned Improvements
The United States recognizes that the Tier 2 methodology is preferred for estimating CO2 emissions from ammonia
manufacture. Historically, efforts have been made to acquire feedstock data for this source category however the
relevant data were not available. In addition to some of the future work noted in the Uncertainty section, additional
planned improvements for this source category include developing a plan to determine the feasibility of acquiring
the relevant data for the Tier 2 assessment. If successful, the results will be included in future inventory
submissions.
4.4. Lime Manufacture (IPCC Source Category 2A2)
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, 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 given off as a gas and is normally emitted to the
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 136
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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)3 production. It is also important to note that, for
certain applications, lime reabsorbs CO2 during use (see Uncertainty, below).
Lime production in the United States—including Puerto Rico—was reported to be 19,164 thousand metric tons in
2003 (USGS 2004). This resulted in estimated CO2 emissions of 13.0 Tg CO2 Eq. (or 12,983 Gg) (see Table 4-17
and Table 4-18).
Table 4-17: Net CO2 Emissions from Lime Manufacture (Tg CO2 Eq.)
Year Tg CO2 Eq.
1990 11.2
1997
1998
1999
2000
2001
2002
2003
13.7
13.9
13.5
13.3
12.8
12.3
13.0
Table 4-18: CO2 Emissions from Lime Manufacture (Gg)
Year
1990
;J' -" \ '
; '" *"'"
1997
1998
1999
2000
2001
2002
2003
Potential
11,730
"v^>,,,:^:,iC:L^,kA"i'"s
14,649
14,975
14,655
14,548
13,941
13,355
14,132
Recovered*
(493)
•'jVftu',1 7! '','•'?
(964)
(1,061)
(1,188)
(1,233)
(1,118)
(1,051)
(1,149)
Net Emissions
11,238
; ' : ",:,, ,,",,
13,685 *
13,914
13,466
13,315
12,823
12,304
12,983
* For sugar refining and precipitated calcium carbonate production.
Note: Totals may not sum due to independent rounding.
At the turn of the 20th Century, over 80 percent of lime consumed in the United States went for construction uses.
The contemporary quicklime market is distributed across four end-use categories as follows: metallurgical uses, 35
percent; environmental uses, 28 percent; chemical and industrial uses, 23 percent, construction uses, 13 percent; and
refractory dolomite, one percent. In the construction sector, hydrated lime is still used to improve durability in
plaster, stucco, and mortars. The use of hydrated lime for traditional building increased by nearly seven percent in
2003 (USGS 2004).
Lime production in 2003 increased by nearly seven percent from 2002, the first increase in production in five years.
Overall, from 1990 to 2003, lime production has increased by 17 percent. The increase in production is attributed in
part to growth in demand for environmental applications, especially flue gas desulfurization technologies. In 1993,
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 flue gas desulfurization end-use to
expand significantly over the years. Phase II of the Clean Air Act Amendments, which went into effect on January
1, 2000, remains the dnvmg force behind the growth in the flue gas desulfurization market (USGS 2003).
J Precipitated calcium carbonate is a specialty filler used in premium-quality coated and uncoated papers.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 137
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Methodology
During the calcination stage of lime manufacture, CO2 is given 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/mole CO2) - (56.08 g/mole CaO)] x (0.95 CaO/lime) = 0.75 g CO2/g lime
For dolomitic lime:
[(88.02 g/mole CO2) - (96.39 g/mole CaO)] x (0.95 CaO/lime) = 0.87 g CO2/g lime
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 19,164 thousand metric tons in 2003 (USGS 2004), resulting in potential
CO2 emissions of 14.1 Tg CO2 Eq. 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 1,926 thousand metric tons in 2003. It was assumed that approximately 80
percent of the CO2 involved in sugar refining and PCC was recovered, resulting in actual CO2 emissions of 13.0 Tg
CO2 Eq.
The activity data for lime manufacture and lime consumption by sugar refining and PCC production for 1990
through 2003 (see Table 4-19) were obtained from USGS (1992 through 2004). Hydrated lime production is
reported separately in Table 4-20. The CaO and CaO'MgO contents of lime were obtained from the IPCC Good
Practice Guidance (IPCC 2000). Since data for the individual lime types (high calcium and dolomitic) was not
provided prior to 1997, total lime production for 1990 through 1996 was calculated according to the three year
distribution from 1997 to 1999. 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).
Table 4-19: Lime Production and Lime Use for Sugar Refining and PCC (Gg)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
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
15,630
14,900
16,040
Dolomitic Productiona'b
2,895
2,838
2,925
3,024
3,116
3,305
3,434
3,552
3,423
3,598
3,621
3,227
3,051
3,124
Use for Sugar Refining
and PCC
826
964
1,023
1,279
1,374
1,503
1,429
1,616
1,779
1,992
2,067
1,874
1,762
1,926
a Includes hydrated lime.
b Includes dead-burned dolomite.
Table 4-20: Hydrated Lime Production (Gg)
Year
High-Calcium Hydrate Dolomitic Hydrate
1990
1,781
319
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 138
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1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
1,841
1,892
1,908
1,942
2,027
1,858
1,820
1,950
2,010
1,550
2,030
1,500
2,140
329
338
342
348
363
332
352
383
298
421
447
431
464
Uncertainty
The uncertainties contained in these estimates can be attributed to slight differences in the chemical composition of
these products. Although the methodology accounts for various formulations of lime, it does not account for the
trace impurities found in lime, such as iron oxide, alumina, and silica. Due to differences in the limestone used as a
raw material, a rigid specification of lime material is impossible. As a result, few plants manufacture lime with
exactly the same properties.
In addition, a portion of the CO2 emitted during lime manufacture will actually be reabsorbed when the lime is
consumed. As noted above, lime has many different chemical, industrial, environmental, and construction
applications. In many processes, CO2 reacts with the lime to create calcium carbonate (e.g., water softening).
Carbon dioxide reabsorption rates vary, however, depending on the application. For example, 100 percent of the
lime used to produce precipitated calcium carbonate 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.4
In some cases, lime is generated from calcium carbonate by-products at pulp mills and water treatment plants.5 The
lime generated by these processes is not included in the USGS data for commercial lime consumption. In the
pulping industry, mostly using the Kraft (sulfate) pulping process, lime is consumed in order to causticize a process
liquor (green liquor) composed of sodium carbonate and sodium sulfide. The green liquor results from the dilution
of the smelt created by combustion of the black liquor where biogenic carbon is present from the wood. Kraft mills
recover the calcium carbonate "mud" after the causticizing operation and 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 is not 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
4 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).
5 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 CO9 is released.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 139
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research is necessary to determine the degree to which lime recycling is practiced by water treatment plants in the
United States.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-21. Lime CO2 emissions were
estimated to be between 12.0 and 14.1 Tg CO2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte
Carlo Stochastic Simulations). This indicates a range of approximately 8 percent below and 8 percent above the
emission estimate of 13.0 Tg CO2 Eq.
Table 4-21: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Lime Manufacture (Tg CO2 Eq. and
Percent)
_ _ 2003 Emission TT ^ . ^ „ „ , ^. + ^ • • ^ +• + a
Source Gas „ ,. , Uncertainty Range Relative to Emission Estimate
Estimate J s
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower Bound Upper Bound Lower Bound Upper Bound
Lime Manufacture CO2 13.0 12.0 14.1 -8% +8%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
4.5. Limestone and Dolomite Use (IPCC Source Category 2A3)
Limestone (CaCO3) and dolomite (CaCO3MgCO3)6 are basic raw materials used by a wide variety of industries,
including construction, agriculture, chemical, metallurgy, glass manufacture, and environmental pollution control.
Limestone is widely distributed throughout the world in deposits of varying sizes and degrees of purity. Large
deposits of limestone occur in nearly every state in the United States, and significant quantities are extracted for
industrial applications. For some of these applications, limestone is sufficiently heated during the process to
generate CO2 as a by-product. Examples of such applications include limestone used as a flux or purifier in
metallurgical furnaces, as a sorbent in flue gas desulfurization systems for utility and industrial plants, or as a raw
material in glass manufacturing and magnesium production.
In 2003, approximately 8,074 thousand metric tons of limestone and 2,446 thousand metric tons of dolomite were
consumed for these applications. Overall, usage of limestone and dolomite resulted in aggregate CO2 emissions of
4.7 Tg CO2 Eq. (4,720 Gg) (see Table 4-22 and Table 4-23). Emissions in 2003 decreased 20 percent from the
previous year and have decreased 15 percent overall from 1990 through 2003.
Table 4-22: CO2 Emissions from Limestone & Dolomite Use (Tg CO2 Eq.)
Activity
Flux Stone
Glass Making
FGD
Magnesium Production
Other Miscellaneous Uses
Total
1990 ^
3
0
1
0
0
5
OJT 'I
2i^«
4 1'"' f'll
1 f.r-^
8l^"t'
.5 •;„•,;,
1997
5.
0.
1.
0.
0.
7.
0
3
4
1
4
2
1998
5
0
1
0
0
7
.1
.2
.2
.1
.9
.4
1999
6.0
0
1.2
0.1
0.7
8.1
2000
2.8
0.4
1.8
0.1
0.9
6.0
2001
2.5
0.1
2.6
0.1
0.5
5.7
2002
2.4
0.1
2.8
0.0
0.7
5.9
2003
2.1
0.3
1.9
0.0
0.4
4.7
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 4-23: COi Emissions from Limestone & Dolomite Use
Activity
Flux Stone
1990|;V? 1997
2,999 .,•$ 5,023
1998
5,132
(Gg)
1999
6,030
2000
2,829
2001
2,514
2002
2,405
2003
2,072
6 Limestone and dolomite are collectively referred to as limestone by the industry, and intermediate varieties are seldom
distinguished.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 140
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Limestone
Dolomite
Glass Making
Limestone
Dolomite
FGD
Magnesium Production
Other Miscellaneous Uses
Total
2,554 ;.-'•»
446 ;*t'
217 >
189 ^
28 [f
1,433 :;r
64 :•••'•*
819 '."
5,533 \
':, 3,963
.;'' 1,060
> 319
V 319
1 0
^ 1,426
•\ 73
v 401
7,242
4,297
835
157
65
91
1,230
73
858
7,449
4,265
1,765
0
0
0
1,240
73
713
8,057
1,810
1,020
368
368
0
1,773
73
915
5,959
1,640
874
113
113
0
2,551
53
501
5,733
1,330
1,075
61
61
0
2,766
0
652
5,885
904
1,168
337
337
0
1,932
0
380
4,720
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.
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, flue gas desulfurization systems, chemical stone, mine dusting or acid water treatment, acid
neutralization, and sugar refining and then converting to CO2 using a molecular weight ratio.
Traditionally, the production of magnesium metal was the only other use of limestone and dolomite that produced
CO2 emissions. At the start of 2001, there were two magnesium production plants operating in the United States
and they used different production methods. One plant produced magnesium metal using a dolomitic process that
resulted in the release of CO2 emissions, while the other plant produced magnesium from magnesium chloride using
a CO2-emissions-free process called electrolytic reduction. However, the plant utilizing the dolomitic process
ceased its operations prior to the end of 2001, so beginning in 2002 there were no emissions from this particular
sub-use.
Consumption data for 1990 through 2003 of limestone and dolomite used for flux stone, glass manufacturing, flue
gas desulfurization systems, chemical stone, mine dusting or acid water treatment, acid neutralization, and sugar
refining (see Table 4-24) were obtained from personal communication with Valentine Tepordei of the USGS
regarding data in the Minerals Yearbook: Crushed Stone Annual Report (Tepordei 2002, 2003, 2004 and USGS
1993, 1995a, 1995b, 1996a, 1997a, 1998a, 1999a, 2000a, 2001a, 2002a, 2003a). The production capacity data for
1990 through 2003 of dolomitic magnesium metal (see Table 4-25) also came from the USGS (1995c, 1996b,
1997b, 1998b, 1999b, 2000b, 200Ib, 2002b, 2003b, 2004). During 1990 and 1992, the USGS did not conduct a
detailed survey of limestone and dolomite consumption by end-use. Consumption for 1990 was estimated by
applying the 1991 percentages of total limestone and dolomite use constituted by the individual limestone and
dolomite uses to 1990 total use. 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.
Additionally, each year the USGS withholds data on certain limestone and dolomite end-uses due to confidentiality
agreements regarding company proprietary data. 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
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 141
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for "unspecified uses" was, therefore, allocated to each reported end-use according to each end uses fraction of total
consumption in that year.7
Table 4-24: Limestone and Dolomite Consumption (Thousand Metric Tons)
Activity
1990 fe:^ 1997
1998
1999
2000
2001
2002
2003
Flux Stone
Limestone
Dolomite
Glass Making
Limestone
Dolomite
FGD
Other Miscellaneous Uses
6,738;
5,804 =
933 =
489;
430;
59;
3,258;
1,835;
3t4: n=226
V';i'; 9,007
''!':/•„; 2,219
;tr 725
;;*/;.; 725
\ ,vf? o
'<;••>'>;, 3,242
A;-'^1- 898
11,514
9,767
1,748
340
149
191
2,795
1,933
13,390
9,694
3,696
0
0
0
2,819
1,620
6,248
4,113
2,135
836
836
0
4,030
2,080
5,558
3,727
1,831
258
258
0
5,798
1,138
5,275
3,023
2,252
139
139
0
6,286
1,483
4,501
2,055
2,466
765
765
0
4,390
863
Total
12,319 \,'v>
16,091 16,582 17,830 13,194 12,751 13,183 10,520
Note: "Other miscellaneous uses"
refining.
includes chemical stone, mine dusting or acid water treatment, acid neutralization, and sugar
Table 4-25: Dolomitic Magnesium Metal Production Capacity (Metric Tons)
Year Production Capacity
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
35,000
35,000
14,909
12,964
21,111
22,222
40,000
40,000
40,000
40,000
40,000
29,167
0
0
Note: Production capacity for 2002 and 2003 amount to zero because the last U.S. production plant employing the dolomitic
process shut down mid-2001 (USGS 2002).
Uncertainty
Uncertainties in this estimate are due, in part, to variations in the chemical composition of limestone. In addition to
calcium carbonate, 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
7 This approach was recommended by USGS.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 142
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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.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-26. Limestone and Dolomite
Use CO2 emissions were estimated to be between 4.4 and 5.1 Tg CO2 Eq. at the 95 percent confidence level (or in
19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 7 percent below and 8
percent above the emission estimate of 4.7 Tg CO2 Eq.
Table 4-26: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Limestone and Dolomite Use (Tg
CO2 Eq. and Percent)
„ „ 2003 Emission Uncertainty Range Relative to
Source Gas _ A. * . ^ a
Estimate Estimate
(TgC02Eq.) (TgC02Eq.) ('
Limestone and Dolomite Use CO^ 4.7
Lower
Bound
4.4
Upper
Bound
5.1
Lower
Bound
-7%
Emission
Upper
Bound
+8%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Recalculations Discussion
A spreadsheet error was corrected for the limestone and dolomite use emission estimate for 2002. The change
resulted in an increase of less than 0.1 Tg CO2 Eq. (0.8 percent) in CO2 emissions from limestone and dolomite use
for that year.
4.6. Soda Ash Manufacture and Consumption (IPCC Source Category 2A4)
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 net
emissions of CO2 from Wyoming were calculated. This difference is a result of the production processes employed
in each state.8 During the production process used in Wyoming, trona ore is treated to produce soda ash. 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 2003, CO2 emissions from the manufacture of soda ash from trona were approximately 1.5 Tg CO2 Eq. (1,509
Gg). Soda ash consumption in the United States generated 2.6 Tg CO2 Eq. (2,573 Gg) in 2003. Total emissions
from soda ash manufacture in 2003 were 4.1 Tg CO2 Eq. (4,082 Gg) (see Table 4-27 and Table 4-28). Emissions
8 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 143
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have fluctuated since 1990. These fluctuations were strongly related to the behavior of the export market and the
U.S. economy. Emissions in 2003 decreased by approximately 1 percent from the previous year, and have
decreased overall by approximately 1 percent since 1990.
Table 4-27: CO2 Emissions from Soda Ash Manufacture and Consumption (Tg CO2Eq.)
Year Manufacture Consumption Total
1990 14 2.7 41
1997
1998
1999
2000
2001
2002
2003
1.7
1.6
1.5
1.5
1.5
1.5
1.5
2.7
2.7
2.7
2.7
2.6
2.7
2.6
4.4
4.3
4.2
4.2
4.1
4.1
4.1
Note: Totals may not sum due to independent rounding.
Table 4-28: CO2 Emissions from Soda Ash Manufacture and Consumption (Gg)
Year
1990
i'wl/»ulo»i'«l'C,,
199*7*
1998
1999
2000
2001
2002
2003
Manufacture Consumption Total
1,431
."•>-,* '.<'.'.• *. ty<
1,665
1,607
1,548
1,529
1,500
1,470
1,509
2,710
f^'i V \>\*V>
2,689
2,718
2,668
2,652
2,648
2,668
2,573
4,141
'.\ y-'"' :"'•:''>', >::>
4,354
4,325
4,217
4,181
4,147
4,139
4,082
Note: Totals may not sum due to independent rounding.
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 2003 was glass making, 49 percent; chemical production, 26
percent; soap and detergent manufacturing, 11 percent; distributors, five percent; flue gas desulfurization, pulp and
paper production, two percent each; water treatment, one percent; and miscellaneous, four percent (USGS 2004).
Although the United States continues to be the major supplier of world soda ash, China's soda ash manufacturing
capacity is rapidly increasing and is expected to surpass that of the United States. 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 (USGS 2004).
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] [soda ash]
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 144
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Based on this formula, approximately 10.27 metric tons of trona are required to generate one metric ton of CO2.
Thus, the 15.5 million metric tons of trona mined in 2003 for soda ash production (USGS 2004) resulted in CO2
emissions of approximately 1.5 Tg CO2Eq. (1,509 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 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.
The activity data for trona production and soda ash consumption (see Table 4-29) were taken from USGS (1994
through 2004). Soda ash manufacture and consumption data were collected by the USGS from voluntary surveys of
the U.S. soda ash industry.
Table 4-29: Soda Ash Manufacture and Consumption (Gg)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Manufacture*
14,700
14,700
14,900
14,500
14,600
16,500
16,300
17,100
16,500
15,900
15,700
15,400
15,100
15,500
Consumption
6,530
6,280
6,320
6,280
6,260
6,500
6,390
6,480
6,550
6,430
6,390
6,380
6,430
6,200
* Soda ash manufactured from trona ore only.
Uncertainty
Emission estimates from soda ash manufacture are considered to have low associated uncertainty. Both the
emission 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, there is uncertainty surrounding the emission factors from the consumption of soda ash.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-30. Soda Ash Manufacture
and Consumption CO2 emissions were estimated to be between 3,9 and 4,2 Tg CO2 Eq, at the 95 percent confidence
level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 4 percent
below and 4 percent above the emission estimate of 4.1 Tg CO2 Eq.
Table 4-30: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Soda Ash Manufacture and
Consumption (Tg CO2 Eq. and Percent)
_ _ 2003 Emission Uncertainty Range Relative to Emission
Source Gas „ ,. _ ,. , a
Estimate Estimate
(TgC02Eq.) (TgC02Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper
Bound
Soda Ash Manufacture
and Consumption CO2 4_1 3_9 42 -4% +4%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 145
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Planned Improvements
Emissions from soda ash production in Colorado, which is produced using the nahcolite production process, will be
investigated for inclusion in future inventories.
4.7. Titanium Dioxide Production (IPCC Source Category 2B5)
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.
The chloride process is based on the following chemical reactions:
2 FeTiC-3 + 7 C12 + 3 C ->• 2 TiCL, + 2 FeCl3 + 3 CO2
2 TiCL, + 2 O2 ->• 2 TiO2 + 4 C12
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 2003 were 2.0 Tg CO2 Eq. (2,013 Gg), an increase
of less than one percent from the previous year and 54 percent from 1990, due to increasing production within the
industry (see Table 4-31).
Table 4-31: CO2 Emissions from Titanium Dioxide (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq. Gg
1990 1.3 1,308
1997
1998
1999
2000
2001
2002
2003
1.8
1.8
1.9
1.9
1.9
2.0
2.0
',,,''"/>'"*
1,836
1,819
1,853
1,918
1,857
1,997
2,013
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 97 percent
of the total production in 2003 was produced using the chlonde process. 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. An emission factor of 0.4 metric tons C/metnc 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 146
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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 2003 (see Table 4-32) were obtained from personal communication with Joseph Gambogi, USGS
Commodity Specialist, of the USGS (Gambogi 2004) and through the Minerals Yearbook: Titanium Annual Report
(USGS 1991 through 2003). Data for the percentage of the total titanium dioxide production capacity that is
chloride process for 1994 through 2002 were also taken from the USGS Minerals Yearbook and from Joseph
Gambogi for 2003. 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 (2002).
By 2002, only one sulfate plant remained online in the United States. The composition data for petroleum coke
were obtained from Onder and Bagdoyan (1993).
Table 4-32: Titanium Dioxide Production (Gg)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Gg
979
992
1,140
1,160
1,250
1,250
1,230
1,340
1,330
1,350
1,400
1,330
1,410
1,420
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.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-33. Titanium Dioxide
Consumption CO2 emissions were estimated to be between 1.7 and 2.3 Tg CO2 Eq. at the 95 percent confidence
level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 16 percent
below and 16 percent above the emission estimate of 2.0 Tg CO2 Eq.
Table 4-33: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Titanium Dioxide Production (Tg
CO2 Eq. and Percent)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 147
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2003
Source Gas Emission
Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate"
(TgC02Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Titanium Dioxide Production CO2 2.0
1.7 2.3 -16% +16%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
4.8. Phosphoric Acid Production (IPCC Source Category 2A7)
Phosphoric acid [H3PO4] is a basic raw material in the production of phosphate-based fertilizers. Phosphate rock is
mined in Florida, North Carolina, Idaho, Utah, and other areas of the United States and is used primarily as a raw
material for phosphoric acid production. The production of phosphoric acid from phosphate rock produces
byproduct gypsum [CaSO4-2H2O], referred to as phosphogypsum.
The composition of natural phosphate rock varies depending upon the location where it is mined. Natural
phosphate rock mined in the United States generally contains inorganic carbon in the form of calcium carbonate
(limestone) and also may contain organic carbon. The chemical composition of phosphate rock (francolite) mined
in Florida is:
Ca10.x.y Nax Mgy (PO4)6_x(CO3)xF2+(,4x
The calcium carbonate component of the phosphate rock is integral to the phosphate rock chemistry. Phosphate
rock can also contain organic carbon that is physically incorporated into the mined rock but is not an integral
component of the phosphate rock chemistry. Phosphoric acid production from natural phosphate rock is a source of
CO2 emissions, due to the chemical reaction of the inorganic carbon (calcium carbonate) component of the
phosphate rock.
The phosphoric acid production process involves chemical reaction of the calcium phosphate (Ca3(PO4)2)
component of the phosphate rock with sulfuric acid (H2SO4) and recirculated phosphoric acid (H3PO4) (EFMA
1997). The primary chemical reactions for the production of phosphoric acid from phosphate rock are:
Ca3(PO4)2 + 4H3PO4 -> 3Ca(H2PO4)2
3Ca(H2PO4)2 + 3H2SO4 + 6H2O -> 3CaSO4 6H2O + 6H3PO4
The limestone (CaCO3) component of the phosphate rock reacts with the sulfuric acid in the phosphoric acid
production process to produce calcium sulfate (phosphogypsum) and carbon dioxide. The chemical reaction for the
limestone-sulfuric acid reaction is:
CaC03+H2S04 +H20 -> CaSO4 2H2O + CO2
Total marketable phosphate rock production in 2003 was 38.7 million metric tons. Approximately 86 percent of
domestic phosphate rock production was mined in Florida and North Carolina, while approximately 14 percent of
production was mined in Idaho and Utah. Florida alone represented more than 75 percent of domestic production.
In addition, 2.4 million metric tons of crude phosphate rock was imported for consumption in 2003. Marketable
phosphate rock production, including domestic production and imports for consumption, increased by
approximately 3.7 percent between 2002 and 2003. However, over the 1990 to 2003 period, production decreased
by 12 percent. The 35.3 million metric tons produced in 2001 was the lowest production level recorded since 1965
and was driven by a worldwide decrease in demand for phosphate fertilizers. Total CO2 emissions from phosphoric
acid production were 1.4 Tg CO2 Eq. (1,382 Gg) in 2003 (see Table 4-34).
Table 4-34: CO2 Emissions from Phosphoric Acid Production (Tg CO2 Eq. and Gg)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 148
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Year
1990
1997
1998
1999
2000
2001
2002
2003
TgC02
1.5
******* *^
1.6
1.5
1.4
1.3
1.3
1.4
Eq. Gg
1,529
"""1,544" '
1,593
1,539
1,382
1,264
1,338
1,382
Methodology
Carbon dioxide emissions from production of phosphoric acid from phosphate rock is calculated by multiplying the
average amount of calcium carbonate contained in the natural phosphate rock by the amount of phosphate rock that
is used annually to produce phosphoric acid, accounting for domestic production and net imports for consumption.
The USGS reports in the Minerals Yearbook, Phosphate Rock, the aggregate amount of phosphate rock mined
annually in Florida and North Carolina and the aggregate amount of phosphate rock mined annually in Idaho and
Utah, and reports the annual amounts of phosphate rock exported and imported for consumption (see Table 4-35).
Data for domestic production of phosphate rock, exports of phosphate rock, and imports of phosphate rock for
consumption for 1990 through 2003 were obtained from USGS Mineral Yearbook, Phosphate Rock (USGS 1994
through 2004).
The carbonate content of phosphate rock varies depending upon where the material is mined. Composition data for
domestically mined and imported phosphate rock were provided by the Florida Institute of Phosphate Research
(FIPR 2003). Phosphate rock mined in Florida contains approximately 3.5 percent inorganic carbon (as CO2), and
phosphate rock imported from Morocco contains approximately 5 percent inorganic carbon (as CO2). Calcined
phosphate rock mined in North Carolina and Idaho contains approximately 1.5 percent and 1.0 percent inorganic
carbon (as CO2), respectively (see Table 4-36).
Carbonate content data for phosphate rock mined in Florida are used to calculate the CO2 emissions from
consumption of phosphate rock mined in Florida and North Carolina (86 percent of domestic production) and
carbonate content data for phosphate rock mined in Morocco are used to calculate CO2 emissions from consumption
of imported phosphate rock. The CO2 emissions calculation is based on the assumption that all of the domestic
production of phosphate rock is used in uncalcmed form. The USGS reported that one phosphate rock producer in
Idaho is producing calcined phosphate rock; however, no production data were available for this single producer
(USGS 2003). Carbonate content data for uncalcmed phosphate rock mined in Idaho and Utah (14 percent of
domestic production) were not available, and carbonate content was therefore estimated from the carbonate content
data for calcined phosphate rock mined in Idaho.
The CO2 emissions calculation methodology is based on the assumption that all of the inorganic carbon (calcium
carbonate) content of the phosphate rock reacts to CO2 in the phosphoric acid production process and is emitted
with the stack gas. The methodology also assumes that none of the organic carbon content of the phosphate rock is
converted to CO2 and that all of the organic carbon content remains in the phosphoric acid product.
Table 4-35: Phosphate Rock Domestic Production, Exports, and Imports (Gg)
Location/Year
U.S. Production
FL&NC
ID&UT
Exports - FL & NC
Imports - Morocco
Total U.S. Consumption
1990 r,:v;-
42,494|rt-fv
7,306r;;''5
6,240/;?
451 ;1?
44,01ll!-Y
1997
36,604
5,496
335
1,830
43,595
1998
38,000
5,640
378
1,760
45,022
1999
35,900
5,540
272
2,170
43,338
2000
31,900
5,470
299
1,930
39,001
2001
28,100
4,730
9
2,500
35,321
2002
29,800
4,920
62
2,700
37,358
2003
31,300
5,100
64
2,400
38,746
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 149
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Source: USGS 2004, 2003, 2002, 2001, 2000, 1999, 1998, 1997, 1996, 1995.
Table 4-36: Chemical Composition of Phosphate Rock (percent by weight)
Composition
Total Carbon (as C)
Inorganic Carbon (as C)
Organic Carbon (as C)
Inorganic Carbon (as CO2)
Central North Carolina Idaho
Florida North Florida (calcined) (calcined)
1.60
1.0
0.60
3.67
1.76
0.93
0.83
3.43
0.76
0.41
0.35
1.50
0.60
0.27
1.0
Morocco
1.56
1.46
0.1
5.0
Source: FIPR 2003
(—): Assumed equal to zero.
Uncertainty
Phosphate rock production data used in the emission calculations are developed by the USGS through monthly and
semiannual voluntary surveys of the eleven companies that owned phosphate rock mines during 2003. The
phosphate rock production data are not considered to be a significant source of uncertainty, because all eleven of the
domestic phosphate rock producers are reporting their annual production to the USGS. Data for imports for
consumption and exports of phosphate rock used in the emission calculation are based on international trade data
collected by the U.S. Census Bureau. These U.S. government economic data are not considered to be a significant
source of uncertainty.
One source of potentially significant uncertainty in the calculation of CO2 emissions from phosphoric acid
production is the data for the carbonate composition of phosphate rock. The composition of phosphate rock varies
depending upon where the material is mined, and may also vary over time. Only one set of data from the Florida
Institute of Phosphate Research was available for the composition of phosphate rock mined domestically and
imported, and data for uncalcined phosphate rock mined in North Carolina and Idaho were unavailable. Inorganic
carbon content (as CO2) of phosphate rock could vary ±1 percent from the data included in Table 4-36, resulting in
a variation in CO2 emissions of ±20 percent. Another source of uncertainty is the disposition of the organic carbon
content of the phosphate rock. A representative of the FIPR indicated that in the phosphoric acid production
process the organic carbon content of the mined phosphate rock generally remains in the phosphoric acid product,
which is what produces the color of the phosphoric acid product (FIPR 2003 a). Organic carbon is therefore not
included in the calculation of CO2 emissions from phosphoric acid production. However, if, for example, 50
percent of the organic carbon content of the phosphate rock were to be emitted as CO2 in the phosphoric acid
production process, the CO2 emission estimate would increase by on the order of 50 percent.
A third source of uncertainty is the assumption that all domestically-produced phosphate rock is used in phosphoric
acid production and used without first being calcined. Calcination of the phosphate rock would result in conversion
of some of the organic carbon in the phosphate rock into CO2. However, according to the USGS, only one producer
in Idaho is currently calcining phosphate rock, and no data were available concerning the annual production of this
single producer (USGS 2003). Total production of phosphate rock in Utah and Idaho combined amounts to
approximately 14 percent of total domestic production in 2003. If it is assumed that 100 percent of the reported
domestic production of phosphate rock for Idaho and Utah was first calcined, and it is assumed that 50 percent of
the organic carbon content of the total production for Idaho and Utah was converted to CO2 in the calcination
process, the CO2 emission estimate would increase on the order of 10 percent.
Finally, USGS indicated that 5 percent of domestically-produced phosphate rock is used to manufacture elemental
phosphorus and other phosphorus-based chemicals, rather than phosphoric acid (USGS 2003a). According to
USGS, there is only one domestic producer of elemental phosphorus, in Idaho, and no data were available
concerning the annual production of this single producer. Elemental phosphorus is produced by reducing phosphate
rock with coal coke, and it is therefore assumed that 100 percent of the carbonate content of the phosphate rock will
be converted to CO2 in the elemental phosphorus production process. The calculation for CO2 emissions is based
on the assumption that phosphate rock consumption, for purposes other than phosphoric acid production, results in
CO2 emissions from 100 percent of the inorganic carbon content in phosphate rock, but none from the organic
carbon content. This phosphate rock, consumed for other purposes, constitutes approximately 5 percent of total
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 150
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phosphate rock consumption. If it were assumed that there are zero emissions from other uses of phosphate rock,
CO2 emissions would fall 5 percent.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-37. Phosphoric acid
production CO2 emissions were estimated to be between 1.1 and 1.6 Tg CO2 Eq. at the 95 percent confidence level
(or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 18 percent below
and 18 percent above the emission estimate of 1.4 Tg CO2 Eq.
Table 4-37: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Phosphoric Acid Production (Tg
CO2 Eq. and Percent)
Source
Phosphoric Acid Production
Gas
CO,
2003 Emission
Estimate
(Tg C02 Eq.)
1.4
Uncertainty Range Relative to Emission
Estimate3
(Tg C02 Eq.) (%)
Lower Upper Lower
Bound Bound Bound
1.1 1.6 -18%
Upper
Bound
+18%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Recalculations Discussion
The historical activity data used to calculate the emissions from phosphoric acid production were updated for the
year 2002. The change resulted in a decrease of less than 0.1 Tg CO2 Eq. (less than 0.1 percent) in CO2 emissions
from phosphoric acid production for that year.
Planned Improvements
The estimate of CO2 emissions from phosphoric acid production could be improved through collection of additional
data. Additional data is being collected concerning the carbonate content of uncalcined phosphate rock mined in
various locations in the United States. Additional research will also be conducted concerning the disposition of the
organic carbon content of the phosphate rock in the phosphoric acid production process. Only a single producer of
phosphate rock is calcining the product, and only a single producer is manufacturing elemental phosphorus. Annual
production data for these single producers will probably remain unavailable.
4.9. Ferroalloy Production (IPCC Source Category 2C2)
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 production facilities. Similar to emissions from
the production of iron and steel, CO2is emitted when metallurgical coke is oxidized during a high-temperature
reaction with iron and the selected alloying element. Due to the strong reducing environment, CO is initially
produced, and eventually oxidized to CO2. A representative reaction equation for the production of 50 percent
ferrosilicon is given below:
Fe2O3 +2SiO2 +7C -> 2FeSi + 7CO
Emissions of CO2 from ferroalloy production in 2003 were 1.4 Tg CO2 Eq. (1,374 Gg) (see Table 4-38), an 11
percent increase from the previous year and a 31 percent reduction since 1990.
Table 4-38: CO2 Emissions from Ferroalloy Production (Tg CO2 Eq. and Gg)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 151
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Year
1990
1997
1998
1999
2000
2001
2002
2003
TgC02Eq.
, 2.0
2.0
2.0
2.0
1.7
1.3
1.2
1.4
Gg
1,980
2,038
2,027
1,996
1,719
1,329
1,237
1,374
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.
Ferroalloy production data for 1990 through 2003 (see Table 4-39) were obtained from the USGS through personal
communications with Lisa Corathers (2004), the Silicon Commodity Specialist, and through the Minerals
Yearbook: Silicon Annual Report (USGS 1991, 1992, 1993, 1994, 1995, 1996, 1997, 1998, 1999, 2000, 2001, 2002,
2003). 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 4-39). The composition data for petroleum coke was obtained from Onder and
Bagdoyan(1993).
Table 4-39: Production of Ferroalloys (Metric Tons)
Year
1,"°.
1997
1998
1999
2000
2001
2002
2003
Ferrosilicon
25%-55%
,, 32U85
175,000
162,000
252,000
229,000
167,000
156,000
113,000
Ferrosilicon
56%-95%
109,566
147,000
147,000
145,000
100,000
89,000
98,600
75,800
Silicon Metal
^.J^™;.-
187,000
195,000
195,000
184,000
137,000
113,000
189,000
Misc. Alloys
(32-65%)
J2,442
106,000
99,800
NA
NA
NA
NA
NA
NA (Not Available)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 152
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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.9 Even though emissions
from ferroalloys produced with coking coal or graphite inputs would be counted in national trends, they may be
generated with varying amounts of CO2 per unit of ferroalloy produced. The most accurate method for these
estimates would be to base calculations on the amount of reducing agent used in the process, rather than the amount
of ferroalloys produced. These data, however, were not available.
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.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-40. Ferroalloy Production CO2
emissions were estimated to be between 1.3 and 1.4 Tg CO2 Eq. at the 95 percent confidence level (or in 19 out of
20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 3 percent below and 3 percent
above the emission estimate of 1.4 Tg CO2 Eq.
Table 4-40: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Ferroalloy Production (Tg CO2 Eq.
and Percent)
„ „ 2003 Emission
Source Gas _ A.
Estimate
(TgC02Eq.)
Ferroalloy Production CO2 1.4
Uncertainty Range Relative to Emission Estimate"
(TgC02Eq.) (%)
Lower
Bound
1.3
Upper
Bound
1.4
Lower
Bound
-3%
Upper
Bound
+3%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
4.10. Carbon Dioxide Consumption (IPCC Source Category 2B5)
Carbon dioxide (CO2) is used for a variety of commercial applications, including food processing, chemical
production, carbonated beverage production, and refrigeration, and is also used in petroleum production for
enhanced oil recovery (EOR). Carbon dioxide used for EOR is injected into the underground reservoirs to increase
the reservoir pressure to enable additional petroleum to be produced.
For the most part, CO2 used in non-EOR applications will eventually be released to the atmosphere, and for the
purposes of this analysis CO2 used in commercial applications other than EOR is assumed to be emitted to the
atmosphere. Carbon dioxide used in EOR applications is considered for the purposes of this analysis to remain
sequestered in the underground formations into which the CO2 is injected.
It is unclear to what extent the CO2 used for EOR will be re-released to the atmosphere. Carbon dioxide used in
EOR applications is compressed at the CO2 production source, transported by pipeline to the EOR field, and
injected into wellheads. Potential CO2 leakage pathways from CO2 production, transportation, and injection process
include fugitive emissions from the compressors, pipeline equipment, and wellheads. Also, the CO2 used for EOR
may show up at the wellhead after a few years of injection (Hangebrauk et al. 1992) or may be partially recovered
9 Emissions and sinks of biogenic carbon are accounted for in the Land-Use Change and Forestry chapter.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 153
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as a component of crude oil produced from the wells (Denbury Resources 2003a). This CO2 may be recovered and
re-injected into the wellhead or separated from the petroleum produced and vented to the atmosphere. More
research is required to determine the amount of CO2 that may escape from EOR operations through leakage from
equipment, as a component of the crude oil produced, or as leakage directly from the reservoir through geologic
faults and fractures or through improperly plugged or improperly completed wells. For the purposes of this
analysis, it is assumed that all of the CO2 produced for use in EOR applications is injected into reservoirs (i.e., there
is no loss of CO2to the atmosphere during CO2 production, transportation, or injection for EOR applications) and
that all of the injected CO2 remains sequestered within the reservoirs.
Carbon dioxide is produced from naturally occurring CO2 reservoirs, as a by-product from the energy and industrial
production processes (e.g., ammonia production, fossil fuel combustion, ethanol production), and as a by-product
from the production of crude oil and natural gas, which contain naturally occurring CO2 as a component. Carbon
dioxide produced from naturally occurring CO2 reservoirs and used in industrial applications other than EOR is
included in this analysis. Neither by-product CO2 generated from energy or industrial production processes nor CO2
separated from crude oil and natural gas are included in this analysis for a number of reasons.
Depending on the raw materials that are used, by-product CO2 generated during energy and industrial production
processes may already be accounted for in the CO2 emission estimates from fossil fuel consumption (either from
fossil fuel combustion or from non-energy uses of fossil fuels). For example, ammonia is primarily manufactured
using natural gas as both a feedstock and energy source. Carbon dioxide emissions from natural gas combustion for
ammonia production are accounted for in the CO2 from Fossil Fuel Combustion source category of the Energy
sector and, therefore, are not included under Carbon Dioxide Consumption. Likewise, CO2 emissions from natural
gas used as feedstock for ammonia production are accounted for in this chapter under the Ammonia Manufacture
source category and, therefore, are not included here.10
Carbon dioxide is produced as a by-product of crude oil and natural gas production. This CO2 is separated from the
crude oil and natural gas using gas processing equipment, and may be emitted directly to the atmosphere, or
captured and reinjected into underground formations, used for EOR, or sold for other commercial uses. The amount
of CO2 separated from crude oil and natural gas has not been estimated.11 Therefore, the only CO2 consumption
that is accounted for in this analysis is CO2 produced from natural wells other than crude oil and natural gas wells
that is used in commercial applications other than EOR.
There are currently two facilities, one in Mississippi and one in New Mexico, producing CO2 from natural CO2
reservoirs for use in both EOR and in other commercial applications (e.g., chemical manufacturing, food
production). There are other naturally occurring CO2 reservoirs, mostly located in the western U.S. Facilities are
producing CO2 from these natural reservoirs, but they are only producing CO2 for EOR applications, not for other
commercial applications (Allis, R. et al. 2000). In 2003, the amount of CO2 produced by the Mississippi and New
Mexico facilities for commercial applications and subsequently emitted to the atmosphere were 1.3 Tg CO2Eq.
(1,267 Gg) (see Table 4-41). This amount represents an increase of 29 percent from the previous year and an
increase of 47 percent from emissions in 1990. This increase was due to an increase in the Mississippi facility's
reported production for use in other commercial applications.
Table 4-41: CO2 Emissions from Carbon Dioxide Consumption (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq. Gg
10 One ammonia manufacturer located in Oklahoma is reportedly capturing approximately 35 MMCF/day (0.67 Tg/yr) of by-
product CO2 for use in EOR applications. According to the methodology used in this analysis, this amount of CO2 would be
considered to be sequestered and not emitted to the atmosphere. However, time series data for the amount of CO2 captured from
the ammonia plant for use in EOR applications are not available, and therefore all of the CO2 produced by the ammonia plant is
assumed to be emitted to the atmosphere and is accounted for in this chapter under Ammonia Manufacture.
11 The United States is in the process of developing a methodology to account for CO2 emissions from natural gas systems and
petroleum systems for inclusion in future Inventory submissions. For more information see Annex 5.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 154
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1990 0.9 860
1997
1998
1999
2000
2001
2002
2003
0.8
0.9
0.8
1.0
0.8
1.0
1.3
808
912
849
957
818
979
1,267
Methodology
Carbon dioxide emission estimates for 2001, 2002, and 2003 were based on production data for the two facilities
currently producing CO2 from naturally-occurring CO2 reservoirs. Some of the CO2 produced by these facilities is
used for EOR and some is used in other commercial applications (e.g., chemical manufacturing, food production).
Carbon dioxide produced from these two facilities that was used for EOR is assumed to remain sequestered and is
not included in the CO2 emissions totals. It is assumed that 100 percent of the CO2 production used in commercial
applications other than EOR is eventually released into the atmosphere.
Carbon dioxide production data for the Jackson Dome, Mississippi facility in 2001, 2002, and 2003 and the
percentage of total production that was used for EOR and in non-EOR applications were obtained from the Annual
Reports for Denbury Resources, the operator of the facility (Denbury Resources 2002, Denbury Resources 2003b,
Denbury Resources 2004). Denbury Resources reported the average CO2 production in units of MMCF CO2 per
day for 2001, 2002, and 2003, and reported the percentage of the total average annual production that was used for
EOR. Carbon dioxide production data for the Bravo Dome, New Mexico facility were obtained from the New
Mexico Bureau of Geology and Mineral Resources for the years 1990 through 2001 (Broadhead 2003). According
to the New Mexico Bureau, the amount of CO2 produced from Bravo Dome for use in non-EOR applications is less
than one percent of total production (Broadhead 2003). Production data for 2002 and 2003 were not available for
Bravo Dome, so it is assumed that the production values for those years are equal to the 2001 value.
Denbury Resources acquired the Jackson Dome facility in 2001 and CO2 production data for the Jackson Dome
facility are not available for years prior to 2001. Therefore, for 1990 through 2000, CO2 emissions from CO2
consumption in commercial applications other than EOR are estimated based on the total annual domestic
consumption of CO2 in commercial applications other than EOR in 2001 multiplied by the percentage of the total
CO2 consumed in commercial applications other than EOR that originated from CO2 production at the Jackson
Dome and Bravo Dome facilities in 2001. The total domestic commercial consumption of CO2 in commercial
applications other than EOR as reported by the U. S. Census Bureau was about 11,414 thousand metric tons in 2001.
The total non-EOR CO2 produced from the Jackson Dome and Bravo Dome natural reservoirs in 2001 was about
820 thousand metric tons, corresponding to 7.2 percent of the total domestic non-EOR commercial CO2
consumption. This 7.2 percent factor was applied to the annual non-EOR commercial CO2 consumption data for the
years 1990 through 2000 to estimate annual CO2 emissions from non-EOR commercial consumption of CO2
produced from naturally occurring CO2 reservoirs. The remaining 92.8 percent of the total annual non-EOR
commercial CO2 consumption is assumed to be accounted for in the CO2 emission estimates from other categories
(e.g., Ammonia Manufacture, CO2 from Fossil Fuel Combustion, Wood Biomass and Ethanol Consumption).
Non-EOR commercial CO2 consumption data (see Table 4-42) for years 1991 and 1992 were obtained from
Industry Report 1992 (U.S. Census 1993). Consumption data are not available for 1990, and therefore CO2
consumption data for 1990 is assumed to be equal to that for 1991. Consumption data for 1993 and 1994 were
obtained from U.S. Census Bureau Manufacturing Profile, 1994 (U.S. Census 1995). Consumption data for 1996
through 2003 were obtained from the U.S. Census Bureau's Industry Report, 1996, 1998, 2000, 2002, and 2003
(U.S. Census 1997, 1999, 2001, 2003, 2005).
Table 4-42: Carbon Dioxide Consumption (Metric Tons)
Year Metric Tons
1990 11,997,726
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 155
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1997
1998
1999
2000
2001
2002
2003
11,268,219
12,716,070
11,843,386
13,354,262
11,413,889
11,313,478
11,103,777
Uncertainty
Uncertainty exists in the assumption that 92.6 percent of the total domestic CO2 production for commercial
consumption other than EOR from 1990 through 2000 came from energy and industrial production processes, while
7.4 percent came from naturally occurring CO2 reservoirs. The allocation for these years is assumed to be the same
allocation as for 2001, the last year for which data are available to calculate the allocation.
Uncertainty also exists with respect to the number of facilities that are currently producing CO2 from naturally
occurring reservoirs for commercial uses other than EOR, and for which the CO2 emissions are not accounted for
elsewhere. Research indicates that there are only two such facilities, which are in New Mexico and Mississippi,
however, additional facilities may exist that have not been identified. In addition, it is possible that CO2 recovery
exists in particular production and end-use sectors that are not accounted for elsewhere. Such recovery may or may
not affect the overall estimate of CO2 emissions from that sector depending upon the end use to which the recovered
CO2 is applied. For example, research has identified one ammonia production facility that is recovering CO2 for use
in EOR. Such CO2 would be assumed to remain sequestered, however, time series data for the amount of recovered
is not available and therefore all of the CO2 produced by this plant is assumed to be emitted to the atmosphere and is
allocated to Ammonia Manufacture. Recovery of CO2 from ammonia production facilities for use in EOR is further
discussed in this chapter under Ammonia Manufacture. Further research is required to determine whether CO2 is
being recovered from other facilities for application to end uses that are not accounted for elsewhere.
Uncertainty also exists in the assumption that 100 percent of the CO2 used for EOR is sequestered. Operating
experience with EOR systems indicates that 100 percent of the CO2 used in EOR applications does not remain
sequestered, but rather that it may be emitted to the atmosphere as leakage from equipment and reservoirs or
recovered as a component of the crude oil produced. Potential sources of CO2 emissions from EOR applications
include leakage from equipment used to produce, transport, compress, and inject the CO2, leakage from equipment
used to process the crude oil produced, separate the CO2 from the crude oil and recompress and recycle [remject]
the CO2 recovered from the crude oil. Other potential sources of CO2 emissions from EOR applications include
leakage from the reservoir itself, either through migration of the injected CO2 beyond the boundaries of the
reservoir, chemical interactions between the injected CO2 and the reservoir rock, and leakage via faults, fractures,
oil and gas well bores, and water wells.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-43. Carbon dioxide
consumption CO2 emissions were estimated to be between 1.2 and 1.3 Tg CO2 Eq. at the 95 percent confidence
level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 5 percent
below to 5 percent above the emission estimate of 1.3 Tg CO2 Eq.
Table 4-43: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Carbon Dioxide Consumption (Tg
CO2 Eq. and Percent)
Source
_, 2003 Emission
Gas „ ,.
Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to
(TgC02Eq.)
Lower Upper
Bound Bound
Emission Estimate"
(%)
Lower Upper
Bound Bound
Carbon Dioxide Consumption CO2 1_3 1_2 1_3 -5% +5%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 156
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Recalculations Discussion
Carbon dioxide consumption values were updated for 2001 for the Bravo Dome, and for both 2001 and 2002 for the
Jackson Dome. For the Bravo Dome, updated values are based on new production data from the facility. For
Jackson Dome, previous production data was based on fourth quarter reporting by Denbury Resources, which was
annualized for the entire year. Updated production values are based on annual production numbers reported by
Denbury Resources. For 2001, updated production values resulted in a 4 percent decrease in emissions, and for
2002 updated production values resulting in a 23 percent decrease in emissions. Based on updated 2001
consumption values for Jackson Dome, the percent of CO2 emissions from CO2 consumption in commercial
applications other than EOR applied to years 1990 through 2000 decreased by 0.2 percent relative to the percent
previously assumed. These changes resulted in an average annual decrease in CO2 emissions from CO2
consumption of less than 0.1 Tg CO2 Eq. (5.1 percent) for the years 1990 through 2002.
4.11. Petrochemical Production (IPCC Source Category 2B5)
The production of some petrochemicals results in the release of small amounts of CH4 and CO2 emissions.
Petrochemicals are chemicals isolated or derived from petroleum or natural gas. Methane emissions are presented
here from the production of carbon black, ethylene, ethylene dichloride, styrene, and methanol, while CO2
emissions are presented here for only carbon black production. The CO2 emissions from petrochemical processes
other than carbon black are currently included in the Carbon Stored in Products from Non-Energy Uses of Fossil
Fuels Section of the Energy chapter. The CO2 from carbon black production is included here to allow for the direct
reporting of CO2 emissions from the process and direct accounting of the feedstocks used in the process.
Carbon black is an intensely black powder generated by the incomplete combustion of an aromatic petroleum or
coal-based 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 (HOPE,
LDPE, LLDPE), polyvmyl chlonde (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.
Emissions of CO2 and CH4 from petrochemical production in 2003 were 2.8 Tg CO2 Eq. (2,777 Gg) and 1.5 Tg CO2
Eq. (72 Gg), respectively (see Table 4-44 and Table 4-45). While emissions of CO2 from carbon black production
in 2003 decreased by three percent from the previous year, there has been an overall increase in CO2 emissions from
carbon black production of 25 percent since 1990. Methane emissions from petrochemical production decreased by
less than one percent from the previous year and increased 30 percent since 1990.
Table 4-44: CO2 and CH4 Emissions from Petrochemical Production (Tg CO2 Eq.)
Year
C02
CH4
Total
1990 /rv-
2.2 £-;.:.•;;
1.2-:;1:V
3.4,- TV-
1997
2.9
1.6
4.6
1998
3.0
1.7
4.7
1999
3.1
1.7
4.8
2000
3.0
1.7
4.7
2001
2.8
1.4
4.2
2002
2.9
1.5
4.4
2003
2.8
1.5
4.3
Table 4-45: CO2 and CH4 Emissions from Petrochemical Production (Gg)
Year
CO2
CH4
1990 :
2,221 ;%• :,%
56 ;::x.;i
1997
2,919
78
1998
3,015
80
1999
3,054
81
2000
3,004
80
2001
2,787
68
2002
2,857
72
2003
2,777
72
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 157
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Methodology
Emissions of CH4 were calculated by multiplying annual estimates of chemical production by the appropriate
emission factor, as follows: 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. Although the production
of other chemicals may also result in CH4 emissions, there were not sufficient data available to estimate their
emissions.
Emission factors were taken from the Revised 1996IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). Annual
production data for 1990 (see Table 4-46) were obtained from the Chemical Manufacturer's Association Statistical
Handbook (CMA 1999). Production data for 1991 through 2003 were obtained from the American Chemistry
Council's Guide to the Business of Chemistry (2003).
Table 4-46: Production of Selected Petrochemicals (Thousand Metric Tons)
Chemical
Carbon Black
Ethylene
Ethylene Bichloride
Styrene
Methanol
1990 ,/;,;• 1997
1,307
16,542
6,282
3,637
3,785
'•«'.-•' ,, 1
V,O 23
,719
,088
1% 10,324
/*",' •'; s
i ' * W ~*
M.;', 5
,171
743
1998
1,775
23,474
11,080
5,183
5,860
1999
1
25
10
5
5
,798
,118
,308
,410
,303
2000
1
24
9
5
4
,769
,971
,866
,420
,876
2001
1,641
22,521
9,294
4,277
3,402
2002
1,682
23,623
9,288
4,974
3,289
2003
1,635
22,957
9,952
5,239
3,166
Almost all carbon black in the United States is produced from petroleum-based or coal-based feedstocks using the
"furnace black" process (European IPPC Bureau 2004). The furnace black process is a partial combustion process
in which a portion of the carbon black feedstock is combusted to provide energy to the process. Carbon black is
also produced in the United States by the thermal cracking of acetylene-containing feedstocks ("acetylene black
process") and by the thermal cracking of other hydrocarbons ("thermal black process"). One U.S. carbon black
plant produces carbon black using the thermal black process, and one U.S. carbon black plant produces carbon
black using the acetylene black process (The Innovation Group 2004).
The furnace black process produces carbon black from "carbon black feedstock" (also referred to as "carbon black
oil"), which is a heavy aromatic oil that may be derived as a byproduct of either the petroleum refining process or
the metallurgical (coal) coke production process. For the production of both petroleum-derived and coal-derived
carbon black, the "primary feedstock" (i.e., carbon black feedstock) is injected into a furnace that is heated by a
"secondary feedstock" (generally natural gas). Both the natural gas secondary feedstock and a portion of the carbon
black feedstock are oxidized to provide heat to the production process and pyrolyze the remaining carbon black
feedstock to carbon black. The "tail gas" from the furnace black process contains CO2, carbon monoxide, sulfur
compounds, CH4, and non-methane volatile organic compounds. A portion of the tail gas is generally burned for
energy recovery to heat the downstream carbon black product dryers. The remaining tail gas may also be burned
for energy recovery, flared, or vented uncontrolled to the atmosphere.
The calculation of the carbon lost during the production process is the basis for determining the amount of CO2
released during the process. The carbon content of national carbon black production is subtracted from the total
amount of carbon contained in primary and secondary carbon black feedstock to find the amount of carbon lost
during the production process. It is assumed that the carbon lost in this process is emitted to the atmosphere as
either CH4 or CO2. The carbon content of the CH4 emissions, estimated as described above, is subtracted from the
total carbon lost in the process to calculate the amount of carbon emitted as CO2. The total amount of primary and
secondary carbon black feedstock consumed in the process (see Table 4-47) is estimated using a primary feedstock
consumption factor and a secondary feedstock consumption factor estimated from U.S. Census Bureau (1999 and
2004) data. The average carbon black feedstock consumption factor for U. S. carbon black production is 1.43 metric
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 ethylene dichloride (C2H4C12) rather than dichloroethylene (C2H2C12).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 158
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tons of carbon black feedstock consumed per metric ton of carbon black produced. The average natural gas
consumption factor for U.S. carbon black production is 341 normal cubic meters of natural gas consumed per metric
ton of carbon black produced. The amount of carbon contained in the primary and secondary feedstocks is
calculated by applying the respective carbon contents of the feedstocks to the respective levels of feedstock
consumption.
Table 4-47: Carbon Black Feedstock (Primary Feedstock) and Natural Gas Feedstock (Secondary Feedstock)
Consumption (Thousand Metric Tons)
Activity 1990 1,. 1997 1998 1999 2000 2001 2002 2003
Primary Feedstock 1,864 ?'*, 2,450 2,530 2,563 2,521 2,339 2,398 2,331
Secondary Feedstock 302 t' ' 378 397 410 415 408 379 388
For the purposes of emissions estimation, 100 percent of the primary carbon black feedstock is assumed to be
derived from petroleum refining byproducts. Carbon black feedstock derived from metallurgical (coal) coke
production (e.g., creosote oil) is also used for carbon black production; however, no data are available concerning
the annual consumption of coal-derived carbon black feedstock. Carbon black feedstock derived from petroleum
refining byproducts is assumed to be 89 percent elemental carbon (Srivastava et al. 1999). It is assumed that 100
percent of the tail gas produced from the carbon black production process is combusted and that none of the tail gas
is vented to the atmosphere uncontrolled. The furnace black process is assumed to be the only process used for the
production of carbon black because of the lack of data concerning the relatively small amount of carbon black
produced using the acetylene black and thermal black processes. The carbon black produced from the furnace black
process is assumed to be 97 percent elemental carbon (Othmer et al. 1992).
Uncertainty
The CH4 emission factors used for petrochemical production are based on a limited number of studies. Using plant-
specific factors instead of average factors could increase the accuracy of the emission 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.
The results of the quantitative uncertainty analysis for the CO2 emissions from carbon black production calculation
are based on feedstock consumption, import and export data, and carbon black production data. The composition of
carbon black feedstock varies depending upon the specific refinery production process, and therefore the
assumption that carbon black feedstock is 89 percent carbon gives rise to uncertainty. Also, no data are available
concerning the consumption of coal-derived carbon black feedstock, so CO2 emissions from the utilization of coal-
based feedstock are not included in the emission estimate. In addition, other data sources indicate that the amount
of petroleum-based feedstock used in carbon black production may be underreported by the U.S. Census Bureau.
Finally, the amount of carbon black produced from the thermal black process and acetylene black process, although
estimated to be a small percentage of the total production, is not known. Therefore, there is some uncertainty
associated with the assumption that all of the carbon black is produced using the furnace black process.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-48. Petrochemical production
CH4 emissions were estimated to be between 1.4 and 1.6 Tg CO2 Eq. at the 95 percent confidence level (or in 19 out
of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 7 percent below to 7 percent
above the emission estimate of 1.5 Tg CO2 Eq. Petrochemical production CO2 emissions were estimated to be
between 2.8 and 3.1 Tg CO2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic
Simulations). This indicates a range of approximately 10 percent below to 10 percent above the emission estimate
of2.8TgCO2Eq.
Table 4-48: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Petrochemical Production and CO2
Emissions from Carbon Black Production (Tg CO2 Eq. and Percent)
„ „ 2003 Emission TT . . . „ ^ , +• + ^ • • ^ +• ^ a
Source Gas _ A. ^ Uncertainty Range Relative to Emission Estimate
Estimate J 6
(TgC02Eq.) (TgC02Eq.)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 159
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Petrochemical Production
Petrochemical Production
CH4
CO2
1.5
2.8
Lower
Bound
1.4
2.5
Upper
Bound
1.6
3.1
Lower
Bound
-7%
-10%
Upper
Bound
+7%
+10%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Recalculations Discussion
In previous inventories, CO2 emissions from carbon black production were not calculated and reported separately in
the Industrial Processes sector, but were included in the Carbon Stored in Products from Non-Energy Uses of Fossil
Fuels in the Energy sector. Although the CH4 emissions from petrochemical production did not change for 1990
through 2002 compared to the previous Inventory, the addition of CO2 emissions from carbon black production
caused a large increase in petrochemical production emissions for every year of the time series. Overall, the change
resulted in an average annual increase of 2.7 Tg CO2 Eq. (183 percent) in combined CO2 and CH4 emissions from
petrochemical production for the period 1990 through 2002.
4.12. Silicon Carbide Production (IPCC Source Category 2B4)
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. During this reaction,
methane is produced from volatile compounds in the petroleum coke. While CO2 is also emitted from the
production process, the requisite data were unavailable for these calculations. CO2 emissions associated with the
use of petroleum coke in the silicon carbide process are accounted for in the Non-energy Uses of Fossil Fuels
section in the Energy Chapter. Emissions of CH4 from silicon carbide production in 2003 were 0.4 Gg CH4 (0.01
Tg CO2 Eq.) (see Table 4-49).
Table 4-49: CH4 Emissions from Silicon Carbide Production (Tg CO2 Eq. and Gg)
Year Tg CO2
1990
' '•- l'!n?$:£ V'u'7 V ' '•' '.x '
1997
1998
1999
2000
2001
2002
2003
+ Does not exceed 0.05
Eq. Gg
+ 1
1 i ' i } '' * ^ ,-' / j / M
+ 1
+ 1
+ 1
+ 1
+ +
+ +
+ +
Tg CO2 Eq. or 0.5 Gg
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).
Production data for 1990 through 2003 (see Table 4-50) 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, 2003, 2004).
Table 4-50: Production of Silicon Carbide (Metric Tons)
Year Metric Tons
1990 105,000
1991 78,900
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 160
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1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
84,300
74,900
84,700
75,400
73,600
68,200
69,800
65,000
45,000
40,000
30,000
35,000
Uncertainty
The emission factor used for silicon carbide production was based on one study of Norwegian plants. The
applicability of this factor to average U.S. practices at silicon carbide plants is uncertain. An 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. However, these data were not available.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-51. Silicon carbide production
CO2 emissions were estimated to be between 0.008 and O.OlTg CO2 Eq. at the 95 percent confidence level (or in 19
out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 10 percent below to 10
percent above the emission estimate of 0.009 Tg CO2 Eq.
Table 4-51: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Silicon Carbide Production (Tg CO2
Eq, and Percent)
„ „ 2003 Emission TT ^ . ^ _, _, , ^. ^ „ . .
Source Gas „ , . , Uncertainty Range Relative to Emission
Estimate J s
(TgC02Eq.) (TgC02Eq.) (»/„;
Silicon Carbide Production CO2 +
Lower
Bound
+
Upper
Bound
+
Lower
Bound
-10%
Estimate"
)
Upper
Bound
+10%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
+ Does not exceed 0.05 Tg CO2 Eq. or 0.5 Gg.
4.13.Nitric Acid Production (IPCC Source Category 2B2)
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 effective 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 to be 15.8 Tg CO2 Eq. (51.1 Gg) in 2003 (see Table 4-52).
Emissions from nitric acid production have decreased by 11 percent since 1990, with the trend in the time series
closely tracking the changes in production.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 161
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Table 4-52: N2O Emissions from Nitric Acid Production (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq. G£
1990 17.8 58
1997
1998
1999
2000
2001
2002
2003
21.2
20.9
20.1
19.6
15.9
17.2
15.8
68
67
65
63
51
56
51
Methodology
Nitrous oxide emissions were calculated by multiplying nitric acid production by the amount of N2O emitted per
unit of nitric acid produced. The emission 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 metnc ton HNO3.
Nitric acid production data for 1990 (see Table 4-53) was obtained from Chemical and Engineering News, "Facts
and Figures" (C&EN 2001). Nitric acid production data for 1991 through 1992 (see Table 4-53) were obtained
from Chemical and Engineering News, "Facts and Figures" (C&EN 2002). Nitric acid production data for 1993
through 2003 were obtained from Chemical and Engineering News, "Facts and Figures" (C&EN 2004). The
emission factor range was taken from Choe et al. (1993).
Table 4-53: Nitric Acid Production (Gg)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Gg
7,196
7,191
7,379
7,486
7,904
8,018
8,349
8,556
8,421
8,113
7,898
6,416
6,939
6,388
Uncertainty
The uncertainties contained in these estimates are primarily due to the current organization within the nitric acid
industry. 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
quantity 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 a diverse range of technologies.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 162
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The results of the Tier 1 quantitative uncertainly analysis are summarized in Table 4-54. Nitric acid production N2O
emissions were estimated to be between 13.2 and 18.5 Tg CO2 Eq. at the 95 percent confidence level. This
indicates a range of 17 percent above to below the 2003 emission estimate of 15.8 Tg CO2 Eq.
Table 4-54: Tier 1 Quantitative Uncertainty Estimates for N2O Emissions from Nitric Acid Production (Tg CO2 Eq.
and Percent)
Year 2003 Uncertainty Range Relative to
Source Gas Emissions Uncertainty 2003 Emission Estimate
(Tg C02 Eq.) (%) (Tg C02 Eq.)
Lower Bound Upper Bound
Nitnc Acid Production N2O 15.8 17% 13.2 18.5
Recalculations Discussion
The nitric acid production values for all years 1993 through 2002 were updated using newly published figures
(C&EN 2004). Published figures remained consistent for all years of the historical time series except 2002. The
updated production data for 2002 resulted in an increase of 0.5 Tg CO2 Eq. (2.8 percent) in N2O emissions from
nitric acid production for that year.
Planned Improvements
Planned improvements are focused on assessing the plant-by-plant implementation of NOX abatement technologies
to more accurately match plant production capacities to appropriate emission factors, instead of using a national
profiling of abatement implementation. Also, any large scale updates to abatement configurations would be useful
in revising the national profile.
4.14. Adipic Acid Production (IPCC Source Category 2B3)
Adipic acid production is an anthropogenic source of 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. Approximately 90 percent of all adipic acid
produced in the United States is used in the production of nylon 6,6 (CMR 2001). Food grade adipic acid is also
used to provide some foods with a "tangy" flavor (Thiemens and Trogler 1991).
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 emission controls employed by a facility. In 1990, two of the three major adipic acid-producing plants had N2O
abatement technologies in place and, as of 1998, the three major adipic acid production facilities had control
systems in place.13 Only one small plant, representing approximately two percent of production, does not control
for N2O (Reimer 1999).
Nitrous oxide emissions from this adipic acid production were estimated to be 6.0 Tg CO2 Eq. (19.4 Gg) in 2003
(see Table 4-55).
^During 1997, the N2O emission controls installed by the third plant operated for approximately a quarter of the year.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 163
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Table 4-55: N2O Emissions from Adipic Acid Production (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq. G£
1990 15.2 49
1997
1998
1999
2000
2001
2002
2003
10.3
6.0
5.5
6.0
4.9
5.9
6.0
33
19
18
20
16
19
19
National adipic acid production has increased by approximately 28 percent over the period of 1990 through 2003, to
approximately one 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 2002 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 (Childs 2002, 2003).
These estimates were based on continuous emissions monitoring equipment installed at the two facilities. Measured
estimates for 2003 were unavailable and, thus, were calculated by applying a 1.8 percent production growth rate
representative of the industry (see discussion below on sources of production data). For the other two plants, N2O
emissions were calculated by multiplying adipic acid production by an emission factor (i.e., N2O emitted per unit of
adipic acid produced) and adjusting for the actual percentage of N2O released as a result of plant-specific emission
controls. On the basis of experiments, the overall reaction stoichiometry for N2O production in the preparation of
adipic acid was estimated at approximately 0.3 MT of N2O per MT of product (Thiemens and Trogler 1991).
Emissions are estimated using the following equation:
N2O emissions = [production of adipic acid (MT of adipic acid)] x [0.3 MT N2O / mt adipic acid] x [1 -
(N2O destruction factor x abatement system utility factor) ]
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). For the one plant that uses thermal
destruction and for which no reported plant-specific emissions are available, the abatement system utility factor is
assumed to be 98 percent.
In order to calculate emissions for the two plants where direct emissions measurements were not available, plant-
specific production data needed to be estimated since it was unavailable due to reasons of confidentiality. In order
to calculate plant-specific production for the two plants, national adipic acid production was allocated to the plant
level using the ratio of their known plant capacities to total national capacity for all U.S. plants. The estimated plant
production for the two plants was then used for calculating emissions as described above.
National adipic acid production data (see Table 4-56) for 1990 through 2002 were obtained from the American
Chemistry Council (ACC 2003). Production Data for 2003 were estimated based on an abstract from a Chemical
Economics Handbook report entitled "Adipic Acid" indicating that production will increase by an annual average of
1.8 percent from year 2002 to 2006. 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
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 164
-------
focus: adipic acid/adiponitrile (CW 1999). Plant capacity data for 2000 for three of the plants were updated usin£
Chemical Market Reporter, "Chemical Profile: Adipic Acid" (CMR 2001). For 2001 through 2003, the plant
capacities for these three plants were kept the same as the year 2000 capacities. Plant capacity data for 1999 to
2003 for the one remaining plant was kept the same as 1998.
Table 4-56: Adipic Acid Production (Gg)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Gg
735
708
724
769
821
830
839
871
862
907
925
835
921
937
Uncertainty
The emission factor for adipic acid was based on experiments (Thiemens and Trogler 1991) that attempt to replicate
the industrial process and, thereby, measure the reaction stoichiometry for N2O production in the preparation of
adipic acid. However, the extent to which the lab results are representative of actual industrial emission rates is not
known.
The allocation of national production data for the two facilities where direct emission measurements were
unavailable 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. Also, plant capacity reference data is inconsistently
available from year to year, which can affect the uncertainty of the allocated production through the time series.
A 5 percent uncertainty level was associated with the activity data available for the two plants that reported
emissions. For the remaining two plants, a 20 percent uncertainty level was assumed for production. The emission
factor uncertainty for each of these two plants was estimated separately to account for the differences in the use of
abatement technologies. For the plant that uses no abatement technology, a 10 percent IPCC-default emission factor
uncertainty was assumed appropriate. The abatement factor uncertainty used for the second plant was based on a 5
percent IPCC estimate for the N2O destruction factor and an assumed 5 percent uncertainty in the abatement system
utility factor (IPCC 2000). These two estimates result in an overall uncertainty associated with abatement potential
of 7 percent. This abatement uncertainty, combined with the 10 percent IPCC default uncertainty value associated
with the emissions factor for unabated emissions, results in an overall 12 percent emission factor uncertainty.
Combining the reporting plants emissions uncertainty with the activity data uncertainty and the emission factor
uncertainty for the remaining two plants yields an overall uncertainty for the inventory estimate equal to 9 percent
of 2003 emissions (see Table 4-57).
The results of the Tier 1 quantitative uncertainly analysis are summarized in Table 4-57. Adipic acid production
N2O emissions were estimated to be between 5.5 and 6.5 Tg CO2 Eq. at the 95 percent confidence level. This
indicates a range of 9 percent above to below the 2003 emission estimate of 6.0 Tg CO2 Eq.
Table 4-57: Tier 1 Quantitative Uncertainty Estimates for N2O Emissions from Adipic Acid Production (Tg CO2
Eq, and Percent)
Source Gas Year 2003 Uncertainty Uncertainty Range Relative to
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 165
-------
Emissions (%) 2003 Emission Estimate
(TgC02Eq.) (TgC02Eq.)
Lower Bound
Adipic Acid Production N2O 6.0 9% 5.5
Upper Bound
6.5
QA/QC and Verification
In addition to performing Tier 1 level QA/QC and verification, trends in the production of the synthetic nylon fibers
industry were compared to trends in adipic acid production to confirm a reasonable agreement, since almost 90
percent of the adipic acid produced in the United States is used in the production of nylon 6,6.
Planned Improvements
Improvement efforts will be focused on obtaining direct measurement data from the remaining two plants when and
if they become available. If they become available, cross verification with top-down approaches will provide a
useful Tier 2 level QA check. Also, additional information on the actual performance of the latest catalytic and
thermal abatement equipment at plants with continuous emission monitoring may support the re-evaluation of
current default abatement values.
4.15. Substitution of Ozone Depleting Substances (IPCC Source Category 2F)
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 1990.14 Ozone depleting substances—chlorofluorocarbons (CFCs), halons, carbon
tetrachlonde, 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, 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 4-58 and Table 4-59,
Table 4-58: Emissions of HFCs and PFCs from OPS Substitution (Tg CO2 Eq.)
Gas 1990
HFC-23 +1
HFC-32 +1
HFC-125 +t
HFC-134a +1
HFC-143a +;
HFC-236fa +t
CF4 +1
Others* 0 4;
Total 0.4
*'.-\r 199
'« * '
'", ' :< 0
i":''V 7
'.-,* 31
;-M 3
,'Vv 0
/"^^
2.4- 4
:\," 46
7
+
2
0
4
5
1
+
2
5
19<
0
8
36
5
0
5
56
)8
+
o
. j
.8
.7
.2
.4
+
.2
.6
19<
0
0
10
42
6
0
5
65
)9
,1
o
.3
.0
.2
.6
.9
+
.7
.8
2000
0,1
0.3
11.2
48.0
8.2
1.4
+
5.9
75.0
20(
0
0
12
52
10
1
6
83
)1
,1
.3
.3
.7
.1
.8
+
.1
.3
2002
0,1
0.3
13.4
56.9
12.2
2.1
+
6.5
91.5
2003
0,1
0.4
14.7
60.5
14.6
2.3
+
6.9
99.5
+ Does not exceed 0.05 Tg CO2 Eq.
* Others include HFC-152a, HFC-227ea, HFC-245fa, HFC-4310mee, and PFC/PFPEs, the latter being a proxy for a diverse
collection of PFCs and perfluoropoly ethers (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 4-59: Emissions of HFCs and PFCs from ODS Substitution (Mg)
14 [42 U.S.C § 7671, CAA § 601]
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 166
-------
Gas 1990'::. 1997 1998 1999 2000 2001 2002 2003
HFC-23 +
HFC-32 +
HFC-125 +
HFC-134a +
HFC-143a +
HFC-236fa +
CF4 +
Others* M
,-?.•;/ 3
Vi;>; 289
'/.'":.':, 2,516
•;:;'*;24,i36
!;?/£ 926
;•{/'•'•' 9
o
J
28
1
4
430
,134
,202
,369
64
1
M
4
439
3,571
32,491
1,738
142
1
M
4
36
2
5
441
,004
,888
,162
214
1
M
4
40
2
5
459
,385
,512
,647
281
1
M
4
43
3
6
492
,777
,798
,203
341
2
M
6
541
5,246
46,559
3,834
369
2
M
M (Mixture of Gases)
+ Does not exceed 0.5 Mg
* Others include HFC-152a, HFC-227ea, HFC-245fa, HFC-4310mee and PFC/PFPEs, the latter being a proxy for a diverse
collection of PFCs and perfluoropolyethers (PFPEs) employed for solvent applications.
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 99.5 Tg CO2 Eq. in 2003. This increase was in large part the result of efforts to phase out CFCs and other
ODSs in the United States. In the short term, this trend is expected to continue, and will likely accelerate over 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
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 3.8.
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
15 R-404A contains HFC-125, HFC-143a, and HFC-134a.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 167
-------
equipment sales, equipment characteristics, and end-use emissions profiles that were used to estimate annual
emissions for the various compounds.
The Vintaging Model estimates emissions from over 40 end-uses, but the uncertainty estimation was performed on
only the top 14 end-uses, which account for 95 percent of emissions from this source category. In order to calculate
uncertainty, functional forms were developed to simplify some of the complex "vintaging" aspects of some end-use
sectors, especially with respect to refrigeration and air-conditioning, and to a lesser degree, fire extinguishing.
These sectors calculate emissions based on the entire lifetime of equipment, not just equipment put into commission
in the current year, which necessitated these simplifying equations. The functional forms used variables that
included growth rates, emission factors, transition from ODSs, change in charge size as a result of the transition,
disposal quantities, disposal emission rates, and either stock for the current year or original ODS consumption.
Uncertainty was estimated around each variable within the functional forms based on expert judgment, and a Monte
Carlo analysis was performed.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-60. Substitution of ozone
depleting substances HFC and PFC emissions were estimated to be between 89.9 and 108.4 Tg CO2 Eq. at the 95
percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of
approximately 10 percent below to 10 percent above the emission estimate of 99.5 Tg CO2 Eq.
Table 4-60: Tier 2 Quantitative Uncertainty Estimates for HFC and PFC Emissions from ODS Substitution (Tg
CO2 Eq. and Percent)
2003
Source Gases Emission
Estimate
(TgC02Eq.)
Substitution of Ozone HFCs and
Depleting Substances PFCs 99.5
Uncertainty Range Relative to
(TgC02Eq.)
Lower
Bound
89.9
Upper
Bound
108.4
Emission Estimate"
Lower
Bound
-10%
Upper
Bound
+9%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Recalculations Discussion
An extensive review of the chemical substitution trends, market sizes, growth rates, and charge sizes, together with
input from industry representatives, resulted in updated assumptions for the Vintaging Model. These changes
resulted in an average annual net increase of less than 0.1 Tg CO2 Eq. (4.1 percent) in HFC and PFC emissions from
the substitution of ozone depleting substances for the period 1990 through 2002.
4.16. HCFC-22 Production (IPCC Source Category 2E1)
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. Between 1990 and 2000, U.S. production of HCFC-22 rose significantly as
HCFC-22 replaced chlorofluorocarbons (CFCs) in many applications. Since 2000, however, U.S. production has
declined to levels near those of the early to mid 1990s. 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. 1"
Feedstock production, however, is permitted to continue indefinitely.
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]
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 168
-------
HCFC-22 is produced by the reaction of chloroform (CHC13) and hydrogen fluoride (HF) in the presence of a
catalyst, SbQ5. The reaction of the catalyst and HF produces SbClxFy, (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-fluormated 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 2003 were estimated to be 12.3 Tg CO2 Eq. (1.1 Gg). This quantity represents a 38 percent
decline from 2002 emissions and a 65 percent decline from 1990 emissions. Both declines are primarily due to the
steady decline in the emission rate of HFC-23 (i.e., the amount of HFC-23 emitted per kilogram of HCFC-22
manufactured). Three HCFC-22 production plants operated in the United States in 2003, two of which used thermal
oxidation to significantly lower their HFC-23 emissions.
Table 4-61: HFC-23 Emissions from HCFC-22 Production (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq. Gg
1990 35.0 3
1997
1998
1999
2000
2001
2002
2003
30.0
40.1
30.4
29.8
19.8
19.8
12.3
3
3
o
J
3
2
2
1
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 chromatography. 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.
Production data and emission estimates were prepared in cooperation with the U.S. manufacturers of HCFC-22
(ARAP 1997, 1999, 2000, 2001, 2002, 2003, 2004; RTI 1997). Annual estimates of U.S. HCFC-22 production are
presented in Table 4-62.
Table 4-62:
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
HCFC-22 Production
Gg
138,9
142.7
149.6
132.4
146.8
154.7
166.1
164.5
182.8
(Gg)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 169
-------
1999
2000
2001
2002
2003
165.5
186.9
152.4
144.2
138.0
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. The results of the Tier 1
quantitative uncertainly analysis are summarized in Table 4-63. HCFC-22 production HFC-23 emissions were
estimated to be between 11.1 and 13.6 Tg CO2 Eq. at the 95 percent confidence level. This indicates a range of 10
percent above and below the 2003 emission estimate of 12.3 Tg CO2 Eq.
Table 4-63: Tier 1 Quantitative Uncertainty Estimates for HFC-23 Emissions from HCFC-22 Production (Tg CO2
Eq, and Percent)
Year 2003 Uncertainty Range Relative to
Source Gas Emissions Uncertainty 2003 Emission Estimate
(Tg C02 Eq.) (%) (Tg C02 Eq.)
Lower Bound Upper Bound
HCFC-22 Production HFC-23
12.3
10%
11.1
13.6
Recalculations Discussion
The historical time series was adjusted to fully reflect reports from the Alliance for Responsible Atmospheric
Policy. These changes resulted in an average annual decrease of less than 0.1 Tg CO2 Eq. (0.01 percent) in HFC
emissions from HCFC-22 through the period 1990 through 2002.
4.17. Electrical Transmission and Distribution (IPCC Source Category 2F7)
The largest use of SF6, both in the United States and internationally, is as an electrical insulator and interrupter in
equipment that transmits and distributes electricity (RAND 2002). 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
charactenstics. 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 manufacturing, installation, servicing, and
disposal. Emissions of SF6 from electrical transmission and distribution systems were estimated to be 14.1 Tg CO2
Eq. (0.6 Gg) in 2003. This quantity represents a 52 percent decrease from the estimate for 1990 (see Table 4-64 and
Table 4-65). This decrease, which is reflected in the atmospheric record (Maiss and Brenninkmeijer 2000), is
believed to be a response to increases in the price of SF6 during the 1990s and to growing awareness of the
environmental impact of SF6 emissions, through programs such as the EPA's SF6 Emission Reduction Partnership
for Electric Power Systems.
Table 4-64: SF6 Emissions from Electric Power Systems and Original Equipment Manufactures (Tg CO2 Eq.)
Year Electric Power Original Equipment Total
Systems Manufacturers
1990
1997
1998
1999
28.9
0.3
29.2
•' L M W M M M ^ W M M *W ' •%
21.3
16.7
15.8
•a^fiLxtLjsixfiLxtLjsixfiLxtLj
0.3
0.4
0.6
»»*• Ax^Sx^MfcxS)
21.7
17.1
16.4
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 170
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2000
2001
2002
2003
15.0
14.7
14.0
13.4
0.7
0.7
0.7
0.7
15.6
15.4
14.7
14.1
Table 4-65: SF6 Emissions from Electric Power Systems and Original Equipment Manufacturers (Gg)
Year Emissions
1990L2
1997
1998
1999
2000
2001
2002
2003
0.9
0.7
0.7
0.7
0.6
0.6
0.6
Methodology
The estimates of emissions from electric transmission and distribution are comprised of emissions from electric
power systems and emissions from the manufacture of electrical equipment. The methodologies for estimating both
sets of emissions are descnbed below.
1999 to 2003 Emissions from Electric Power Systems
Emissions from electric power systems from 1999 to 2003 were estimated based on (1) reporting from utilities
participating in EPA's SF6 Emissions Reduction Partnership for Electric Power Systems, which began in 1999, and
(2) utilities' transmission miles as reported in the 2001 and 2004 Utility Data Institute (UDI) Directories of Electric
Power Producers and Distributors (UDI 2001, 2004). (Transmission miles are defined as the miles of lines carrying
voltages above 34.5 kV.) Between 1999 and 2003, participating utilities represented between 31 percent and 35
percent of total U. S. transmission miles. The emissions reported by participating utilities each year were added to
the emissions estimated for non-reporting utilities in that year. Emissions from non-reporting utilities were
estimated using the results of a regression analysis that showed that the emissions of reporting utilities were most
strongly correlated with their transmission miles. As described further below, the transmission miles of the various
types of non-reporting utilities were multiplied by the appropriate regression coefficients, yielding an estimate of
emissions. Transmission miles are clearly physically related to emissions, since in the United States, SF6 is
contained primarily in transmission equipment rated at or above 34.5 kV.
The regression equations reflect two distinctions among non-reporting utilities: (1) between small and large utilities
(i.e., with less or more than 10,000 transmission miles, respectively), and (2) between utilities that do not participate
in the SF6 Emission Reduction Partnership (non-partners) and those that participate but that have not reported in a
given year (non-reporting partners). (Historically, these non-reporting partners have accounted for 5 percent or less
of total estimated partner emissions.) The distinction between small and large utilities was made because the
regression analysis showed that the relationship between emissions and transmission miles differed for small and
large facilities. The distinction between non-partners and non-reporting partners was made because the emission
trends of these two groups were believed to be different. Reporting partners have reduced their emission rates
significantly since 1999. The emission trend of non-reporting partners was believed to be similar to that of the
reporting partners, because all partners commit to reducing SF6 emissions through technically and economically
feasible means. However, non-partners were assumed not to have implemented any changes that would have
reduced emissions over time.
To estimate emissions from non-partners in every year since 1999, the following regression equations were used.
These equations were developed based on the 1999 SF6 emissions reported by 49 partner utilities (representing
approximately 31 percent of U.S. transmission miles), and 2000 transmission mileage data obtained from the 2001
UDI Directory of Electric Power Producers and Distributors (UDI 2001):
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 171
-------
Non-partner small utilities (less than 10,000 transmission miles, in kilograms):
Emissions = 0.874 x Transmission Miles
Non-partner large utilities (more than 10,000 transmission miles, in kilograms):
Emissions = 0.558 x Transmission Miles
To estimate emissions from non-reporting partners in each year, the regression equations based on the emissions
reported by partners in that year were used. To estimate non-reporting partner emissions in 2003, the regression
equations were based on the 2003 SF6 emissions reported by 51 partner utilities, and updated 2003 transmission
mileage data obtained from the 2004 UDI Directory of Electric Power Producers and Distributors (UDI 2004). The
resulting equations for 2003 are:
Non-reporting partner small utilities (less than 10,000 transmission miles, 2003, in kilograms):
Emissions = 0.398 x Transmission Miles
Non-reporting partner large utilities (more than 10,000 transmission miles, 2003, in kilograms):
Emissions = 0.387 x Transmission Miles
As indicated from the 2001 and 2004 UDI Directories of Electric Power Producers and Distributors (UDI 2001,
2004), the U.S. transmission system has grown by over 14,000 miles between 2000 and 2003. To reflect the fact
that this increase probably occurred gradually, transmission mileage was assumed to increase exponentially at an
annual rate of approximately 0.7 percent during the 2000 to 2003 time period.
For each year, total emissions were then determined by summing the partner-reported emissions, the non-reporting
partner emissions (determined with that year's regression equation for the partners), and the non-partner emissions
(determined using the 1999 regression equation).
1990 to 1998 Emissions from Manufacture of Electric Equipment
Because most participating utilities reported emissions only for 1999 through 2003, modeling SF6 emissions from
electric power systems for the years 1990 through 1998 was necessary. To do so, it was assumed that during this
period, U.S. emissions followed the same trajectory as global emissions from this source. To estimate global
emissions, the RAND survey of global SF6 sales to electric utilities was used, together with the following equation,
which is derived from the equation for emissions in the IPCC report, Good Practice Guidance and Uncertainty
Management in National Greenhouse Gas Inventories (IPCC 2001):
Emissions (kilograms) = SF6 purchased to refill existing equipment (kilograms) + nameplate capacity of
retiring equipment (kilograms)
Note that the above equation holds whether the gas from retiring equipment is released or recaptured; if the gas is
recaptured, it is used to refill existing equipment, lowering the amount of SF6 purchased by utilities for this purpose.
Sulfur hexaflouride purchased to refill existing equipment in a given year was assumed to be approximately equal to
the SF6 purchased by utilities in that year. Gas purchases by utilities and equipment manufacturers from 1961
through 2001 are available from the RAND (2002) survey. To estimate the quantity of SF6 released from retiring
equipment, the nameplate capacity of retinng equipment in a given year was assumed to equal 77.5 percent of the
amount of gas purchased by electrical equipment manufacturers 30 years previous (e.g., in 1990, the nameplate
capacity of retiring equipment was assumed to equal 77.5 percent of the gas purchased in 1960). The remaining
22.5 percent was assumed to have been emitted at the time of manufacture. The 22.5 percent emission rate is an
average of IPCC SF6 emission rates for Europe and Japan for years before 1996 (IPCC 2001). The 30-year lifetime
for electrical equipment is also drawn from IPCC (2001). The results of the two components of the above equation
were then summed to yield estimates of global SF6 emissions from 1990 through 1998.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 172
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To estimate U.S. emissions for 1990 through 1998, estimated global emissions for each year from 1990 through
1998 were divided by the estimated global emissions from 1999. The result was a time series of factors that express
each year's global emissions as a multiple of 1999 global emissions. To estimate historical U.S. emissions, the
factor for each year was multiplied by the estimated U.S. emissions of SF6 from electric power systems in 1999
(estimated to be 15.8 Tg CO2 Eq.).
1990 to 2003 Emissions from Manufacture of Electrical Equipment
The 1990 to 2003 emissions estimates for original equipment manufacturers (OEMs) were 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 was estimated based on statistics compiled by the National Electrical Manufacturers
Association (NEMA). These statistics were provided for 1990 to 2000; the quantities of SF6 charged into new
equipment for 2001 to 2003 were assumed to equal that charged into equipment 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 (O'Connell et al. 2002),
Uncertainty
For electric power systems, individual partner-reported SF6 data was assumed to have an uncertainty of 10 percent.
This uncertainty was assumed to incorporate potential errors associated with the weighing of SF6 cylinders and the
tracking of SF6 purchases and use. Using error propagation, the cumulative uncertainty of all partner-reported data
was estimated to be 5 percent.
There are two sources of uncertainty associated with the regression equations used to extrapolate U.S. emissions
from participant reports: 1) uncertainty in the coefficients (as defined by the regression standard error estimate); and
2) the uncertainty in total transmission miles for non-partners and non-reporting partners, which is assumed to be 10
percent. In addition, there is also uncertainty in the basic assumption that all non-reporting partners will follow the
trend defined by reporting partners in a specific year, as well as uncertainty that the emission factor used for utilities
that were not participants, which accounted for approximately 65 percent of U.S. transmission miles, will remain at
levels defined by partners who reported in 1999. However, neither of these uncertainties was modeled.
For OEMs, uncertainty estimates are based on the assumption that SF6 statistics obtained from NEMA have an
uncertainty of 10 percent. Additionally, the OEMs SF6 emissions rate has an uncertainty bounded by the proposed
"actual" and "ideal" emission rates defined in O'Connell, et al. (2002). That is, the uncertainty in the emission rate
is approximately 65 percent.
A Monte Carlo analysis was applied to estimate the overall uncertainty of the emission estimate for SF6 from
electrical transmission and distribution. For each defined parameter (i.e., equation coefficient, transmission
mileage, and partner-specific SF6 emissions data for electric power systems; and SF6 emission rate and statistics for
OEMs), random variables were selected from probability density functions, all assumed to have normal distributions
about the mean. The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-67. Electrical
Transmission and Distribution SF6 emissions were estimated to be between 12.3 and 16.1 Tg CO2 Eq. at the 95
percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of
approximately 13 percent below and 14 percent above the emission estimate of 14.1 Tg CO2 Eq.
Table 4-66: Simulated Variables for Tier 2 Uncertainty Analysis
Parameter
Total Partner-Reported SF6 Data (kg SF6)
Coefficient - Small Utilities, Non-Partners
Coefficient - Large Utilities, Non-Partners
Coefficient - Small Utilities, Non-Reporting Partners
Coefficient - Large Utilities, Non-Reporting Partners
Transmission Miles - Small Utilities, Non-Partners
Probability
Distribution
Normal
Normal
Normal
Normal
Normal
Normal
Uncertainty3
(%)
5
11
21
21
NAb
10
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 173
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Transmission Miles - Large Utilities, Non-Partners
Transmission Miles - Small Utilities, Non-Reporting Partners
Transmission Miles - Large Utilities, Non-Reporting Partner
OEM SF6 Emission Rate (percent)
SF6 Charged to Equipment (kg SF6)
Normal
Normal
Normal
Normal
Normal
10
10
NAb
65
10
a Reflects a 95 percent confidence interval.
b Not applicable. In 2003, all large utility partners reported to the SF6 Emission Reduction Partnership.
Table 4-67: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Electrical Transmission and
Distribution (Tg CO2 Eq. and Percent)
2003 Uncertainty Range Relative to 2003 Emission
„ r Emission
SOUrCe ^aS Estimate (Tg CO2 Eq.) (%)
(Tg C02 Eq.)
Lower
Bound
Upper
Bound
Lower
Bound
Estimate"
Upper
Bound
Electrical Transmission
and Distribution SFg 14.1 12.3 16.1 -13% +14%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Recalculations Discussion
Electric power system emission estimates for the years 2000, 2001 and 2002 were recalculated based on a
combination of additional historical partner data and the incorporation of more up-to-date transmission mileage
data. For historical partner submissions, the regression equations for each respective year were updated and new
extrapolations to non-reporting partners were made. Additionally, recalculations were conducted using updated
transmission mileage data, which reflect the growth of the U.S. transmission system. Previously-reported 2001 and
2002 emission estimates had utilized the 2001 UDI Directory of Electric Power Producers and Distributors (UDI
2001) for transmission mileage data (i.e., 2000 data). As mentioned above, transmission mileage data for 2001 and
2002 were adjusted to account for increases in transmission mileage during this period. These adjustments have
been incorporated in non-reporting partner regression equation re-calculations, resulting in revised estimates of non-
partner and non-reporting partner emissions. The combination of these changes resulted in an average annual
decrease of less than 0.1 Tg CO2 Eq. (0.2 percent) in SF6 emissions from electrical transmission and distribution for
the period 2000 through 2002,
4.18. Aluminum Production (IPCC Source Category 2C3)
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 2003, the United States was the third largest
producer of primary aluminum, with 10 percent of the world total (USGS 2004). 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) and perfluoroethane (C2F6).
Carbon dioxide is emitted during the aluminum smelting process when alumina (aluminum oxide, A12O3) is reduced
to aluminum using the Hall-Heroult reduction process. The reduction of the alumina occurs through electrolysis in
a molten bath of natural or synthetic cryolite (Na3AlF6). The reduction cells contain a carbon lining that serves as
the cathode. Carbon is also contained in the anode, which can be a carbon mass of paste, coke bnquettes, or
prebaked carbon blocks from petroleum coke. During reduction, most of this carbon is oxidized and released to the
atmosphere as CO2.
Process emissions of CO2 from aluminum production were estimated to be 4.2 Tg CO2 Eq. (4,219 Gg) in 2003 (see
Table 4-68). 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
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 174
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considered to be a non-energy use of petroleum coke, and is accounted for here and not under the CO2 from Fossil
Fuel Combustion source category of the Energy sector. Similarly, the coal tar pitch portion of these CO2 process
emissions is accounted for here rather than in the Iron and Steel source category of the Industrial Processes sector.
Table 4-68: CO2 Emissions from Aluminum Production (Tg CO2 Eq. and Gg)
Year TgCO2Eq. Gg
1990 6.3 6,315
1997
1998
1999
2000
2001
2002
2003
5.6
5.8
5.9
5.7
4.1
4.2
4.2
5,621
5,792
5,895
5,723
4,114
4,220
4,219
In addition to CO2 emissions, the aluminum production industry is also a source of PFC emissions. 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 frequency and duration of the anode effects increase, a corresponding rise in
emission levels occurs.
Emissions of PFCs from primary aluminum production are estimated to have declined 79 percent since 1990. Since
1990, emissions of CF4 and C2F6 have declined 80 percent and 77 percent, respectively, to 3.3 Tg CO2 Eq. of CF4
(0.5 Gg) and 0.5 Tg CO2 Eq. of C2F6 (0.1 Gg) in 2003, as shown in Table 4-69 and Table 4-70. This decline was
due both to reductions in domestic aluminum production and to actions taken by aluminum smelting companies to
reduce the frequency and duration of anode effects.
Table 4-69: PFC Emissions from Aluminum Production (Tg CO2 Eq.)
Year
1990
1997
1998
1999
2000
2001
2002
2003
CF4
^16.1
9.8
8.1
8.0
8.1
3.5
4.5
3.3
C2F6
2-3,
1.2
1.0
0.9
0.9
0.5
0.7
0.5
Total
18.3
11.0
9.1
9.0
9.0
4.0
5.2
3.8
Note: Totals may not sum due to independent rounding.
Table 4-70: PFC Emissions from Aluminum Production (Gg)
Year CF4 C2F6
1990 2.5 0.2
1997 1.5 0.1
1998 1.2 0.1
1999 1.2 0.1
2000 1.2 0.1
2001 0.5 0.1
2002 0.7 0.1
2003 0.5 0.1
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 175
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U.S. primary aluminum production for 2003—totaling 2.7 million metric tons—remained similar to 2002
production levels. Due to high electric power costs in various regions of the country, aluminum production has
been curtailed at several U.S. smelters, which resulted in current production levels that were nearly 26 percent lower
than 2000 levels in 2003. The transportation industry remained the largest domestic consumer of primary
aluminum, accounting for about 35 percent of U.S. consumption (USGS 2004).
Methodology
Carbon dioxide is generated during alumina reduction to aluminum metal following the reaction below:
2A12O3 + 3C -» 4A1 + 3CO2
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 1996IPCC 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 x Anode Effect Minutes/Cell-Day
where,
S = Slope coefficient (kg PFC/metric ton Al/(Anode Effect minutes/cell day))
Anode Effect Minutes/Cell-Day = Anode Effect Frequency/Cell-Day x Anode Effect Duration (minutes)
Smelter-specific slope coefficients that are based on field measurements yield the most accurate results. To estimate
emissions between 1990 and 2002, smelter-specific coefficients were available and were used for 12 out of the 23
U.S. smelters. To estimate 2003 emissions, smelter-specific coefficients were available and were used for 6 out of
the 17 operating U.S. smelters. For the remaining 11 operating smelters, technology-specific slope coefficients
from Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2001)
were applied. The slope coefficients were combined with smelter-specific anode effect data, collected by aluminum
companies and reported to the VAIP, to estimate emission factors over time. In 2003, smelter-specific anode effect
data was available for 15 of the 17 operating smelters. Where smelter-specific anode effect data were not available
(i.e., 2 out of 17 smelters in 2003, 2 out of 23 smelters between 1990 and 2002), industry averages were used. For
all smelters, emission factors were multiplied by annual production to estimate annual emissions at the smelter level.
In 2003, smelter-specific production data was available for 16 of the 17 operating smelters; production at the one
remaining smelter was estimated based on national aluminum production and capacity data (USGS). Between 1990
and 2003, production data has been provided by 21 of the 23 U.S. smelters. 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 2001).
National primary aluminum production data for 1990 through 2001 (see Table 4-71) were obtained from USGS,
Mineral Industry Surveys: Aluminum Annual Report (USGS 1995, 1998, 2000, 2001, 2002). For 2002 and 2003,
national aluminum production data were obtained from the United States Aluminum Association's Primary
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 176
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Aluminum Statistics (USAA 2004). The CO2 emission factors were taken from the Revised 1996IPCC Guidelines
(IPCC/UNEP/OECD/IEA 1997).
Table 4-7 1 : Production of Primary Aluminum (Gg)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Gg
4,048
4,121
4,042
3,695
3,299
3,375
3,577
3,603
3,713
3,779
3,668
2,637
2,705
2,705
Uncertainty
The overall uncertainty associated with the 2003 CO2, CF4, and C2F6 emission estimates were calculated using the
IPCC Good Practice Guidance Tier 2 methodology. Uncertainty associated with the parameters used to estimate
CO2 emissions included that associated with production data, with the share of U.S. aluminum production
attributable to each smelter type, and with the emission factors applied to production data to calculate emissions.
Uncertainty surrounding production data was assumed to be characterized as described below, and other variables
were modeled assuming triangular distributions. Emission factors were determined through expert elicitation to be
50 percent certain at a 95 percent confidence level, while the share of production attributed to smelter types were
determined to be associated with a 25 percent uncertainty. A Monte Carlo analysis was applied to estimate the
overall uncertainty of the emissions estimate for the U.S. aluminum industry as a whole and the results are provided
below.
In determining uncertainty associated with emissions of CF4 and C2F6, for each smelter, uncertainty associated with
the quantity of aluminum produced and the frequency and duration of anode effects was estimated. A Monte Carlo
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. Data on anode effect frequency and duration and production data are assumed
to be characterized by a normal distribution. The uncertainty of aluminum production estimates was assumed to be
1 percent or 25 percent, depending on whether a smelter's production was reported or estimated. The uncertainty of
the anode effect frequency was assumed to be 2 percent if the data was reported; however, if the data was estimated,
the uncertainty ranged from 33 to 78 percent, depending on the smelter technology type. Similarly, the uncertainty
in anode effect duration was assumed to be 5 percent for data that was reported, but between 28 and 70 percent for
data that was estimated. The uncertainty ranges for estimated technology-specific anode effect frequency and
duration are based on the standard deviation of reported anode-effect frequency and duration in the International
Aluminum Institute's anode effect survey (IAI 2000).
Additionally, for CF4 and C2F6 emission estimates, uncertainties associated with slope coefficients were calculated.
Data for the slope coefficients are assumed to be characterized by a normal distribution. For the three smelters that
participated in the 2003 EPA-funded measurement study, CF4 and C2F6 slope coefficient uncertainties were
calculated to be 10 percent. For the remaining smelters, given the limited uncertainty data on site-specific slope
coefficients (i.e., those developed using IPCC Tier 3b methodology), the overall uncertainty associated with the
slope coefficients is conservatively assumed to be similar to that given by the IPCC guidance for technology-
specific slope coefficients. Consequently, the uncertainty assigned to the slope coefficients ranged between 10
percent and 35 percent, depending upon the gas and the smelter technology type. In general, where precise
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 177
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quantitative information was not available on the uncertainty of a parameter, a conservative (upper-bound) value
was used.
The results of this Tier 2 quantitative uncertainty analysis are summarized in Table 4-72. Aluminum production
CO2 emissions were estimated to be between 2.8 and 5.9 Tg CO2 Eq. at the 95 percent confidence level (or in 19 out
of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 34 percent below to 40 percent
above the emission estimate of 4.2 Tg CO2 Eq. Also at the 95 percent confidence interval, aluminum production
CF4 emissions were estimated to be between 2.9 and 3.7 Tg CO2 Eq. at the 95 percent confidence level. This
indicates a range of approximately 11 percent below to 11 percent above the emission estimate of 3.3 Tg CO2 Eq.
Finally aluminum production C2F6 emissions were estimated to be between 0.46 and 0.59 Tg CO2 Eq. at the 95
percent confidence level. This indicates a range of approximately 12 percent below to 13 percent above the emission
estimate of 0.5 Tg CO2 Eq.
Table 4-72: Tier 2 Quantitative Uncertainty Estimates for PFC Emissions from Aluminum Production (Tg CO2 Eq.
and Percent)
Source
Aluminum Production
Aluminum Production
Aluminum Production
2003 Uncertainty Range Relative to 2003 Emission
„ Emission
Estimate
(TgC02Eq.)
CO, 4.2
CF4 3.3
C2F6 0.5
(Tg
Lower
Bound
2.8
2.9
0.5
CO2 Eq.)
Upper
Bound
5.9
3.7
0.6
Lower
Bound
-34%
-11%
-12%
Estimate"
Upper
Bound
+40%
+11%
+13%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Occasionally, SF6 may be 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 generally isolated to secondary casting firms. The aluminum industry in the
United States and Canada has been estimated to use 230 metric tons 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
explanation that any emissions would be insignificant (Ko et al. 1993, Victor and MacDonald 1998). Emissions are
considered 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).
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.
Recalculations Discussion
The smelter-specific emission factors used for estimating PFC emissions, as well as aluminum production levels,
were revised to reflect recently-reported data concerning smelter operating parameters, as well as measurements
conducted at three U. S. aluminum smelters. The measurements were part of an EPA-funded study to determine
facility-specific slope coefficients. Consequently, these coefficients were used instead of IPCC defaults to calculate
smelter-specific emission factors. These data were provided in cooperation with participants in the VAIP program.
The combination of these changes resulted in an average annual increase of less than 0.1 Tg CO2 Eq. (0.2 percent)
in PFC emissions from aluminum production for the period 1990 through 2002.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 178
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Carbon dioxide emission estimates from aluminum production for 2002 were updated to include aluminum
production data from the USAA. Previous CO2 emission estimates for 2002 were based on aluminum production
data from the USGS. This change resulted in a decrease in CO2 emissions from aluminum production of less than
0.1 Tg CO2 Eq. (less than -0.1 percent) for 2002.
4.19. Semiconductor Manufacture (IPCC Source Category 2F6)
The semiconductor industry uses multiple long-lived fluorinated gases in plasma etching and plasma enhanced
chemical vapor deposition (PECVD) processes to produce semiconductor products. The gases most commonly
employed are trifluoromethane (HFC-23 or CHF3), perfluoromethane (CF4), perfluoroethane (C2F6), nitrogen
trifluoride (NF3), and sulfur hexafluoride (SF6), although other compounds such as perfluoropropane (C3F8) and
perfluorocyclobutane (c-C4F8) are also used. The exact combination of compounds is specific to the process
employed.
A single 300 mm silicon wafer that yields between 400 to 500 semiconductor products (devices or chips) may
require as many as 100 distinct fluorinated-gas-using process steps, principally to deposit and pattern dielectric
films. Plasma etching (or patterning) of dielectric films, such as silicon dioxide and silicon nitride, is performed to
provide pathways for conducting material to connect individual circuit components in each device. The patterning
process uses plasma-generated fluorine atoms, which chemically react with exposed dielectric film, to selectively
remove the desired portions of the film. The material removed as well as undissociated fluorinated gases flow into
waste streams and, unless emission abatement systems are employed, into the atmosphere. PECVD chambers, used
for depositing dielectric films, are cleaned periodically using fluorinated and other gases. During the cleaning cycle
the gas is converted to fluorine atoms in a plasma, which etches away residual material from chamber walls,
electrodes, and chamber hardware. Undissociated fluorinated gases and other products pass from the chamber to
waste streams and, unless abatement systems are employed, into the atmosphere. In addition to emissions of
unreacted gases, some fluorinated compounds can also be transformed in the plasma processes into different
fluorinated compounds which are then exhausted, unless abated, into the atmosphere. For example, when C2F6 is
used in cleaning or etching, CF4 is generated and emitted as a process by-product. Besides dielectric film etching
and PECVD chamber cleaning, much smaller quantities of fluorinated gases are used to etch polysilicon films and
refractory metal films like tungsten.
For 2003, total weighted emissions of all fluorinated greenhouse gases by the U.S. semiconductor industry were
estimated to be 4.3 Tg CO2 Eq. Combined emissions of all fluorinated greenhouse gases are presented in Table
4-73 and Table 4-74 below. The rapid growth of this industry and the increasing complexity of semiconductor
products which use more PFCs in the production process have led to an increase in emissions of 48 percent since
1990. The emissions growth rate began to slow after 1997, and emissions declined by 40 percent between 1999 and
2003. This decline is due both to a drop in production (with a continuing decline in silicon consumption) and to the
initial implementation of PFC emission reduction methods such as process optimization.
Table 4-73:
Year
CF4
C,F6
C3F8
C4F8
HFC-23
SF6
NF3*
Total
PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Tg CO2 Eq.)
1990
0.7
1.5
0.0
0.0
0.2
0.5
0.0
2.9
1997
1.6
3.2
0.0
0.0
0.4
1.1
0.1
6.3
1998
1.8
3.6
0.0
0.0
0.4
1.3
0.1
7.1
1999
1.8
3.7
0.0
0.0
0.4
1.3
0.1
7.2
2000
1.8
3.0
0.1
0.0
0.3
1.1
0.1
6.3
2001
1.3
2.1
0.1
0.0
0.2
0.8
0.1
4.5
2002
1.1
2.2
0.1
0.0
0.2
0.7
0.3
4.4
2003
1.0
2.1
0.1
0.1
0.2
0.8
0.2
4.3
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.
Table 4-74: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Mg)
Year19901997199819992000200120022003
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 179
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CF4
C,F6
C3F8
C4F8
HFC-23
SF6
NF3
115
160
0
0
15
22
3
245
347
0
0
33
48
8
277
391
0
0
37
54
9
281
397
0
0
37
55
9
281
324
17
0
23
46
11
202
231
14
0
16
31
12
175
244
9
5
15
28
32
161
228
13
8
17
35
30
Methodology
Emissions from semiconductor manufacturing were estimated using three distinct methods, one each for the periods
1990 through 1994, 1995 through 1999, and 2000 and beyond. For 1990 through 1994, emissions were estimated
using the most recent version of EPA's PFC Emissions Vintage Model (PEVM) (Burton & Beizaie 2001).17 PFC
emissions per square centimeter of silicon increase as the number of layers in semiconductor devices increases.
Thus, PEVM incorporates information on the two attributes of semiconductor devices that affect the number of
layers: (1) linewidth technology (the smallest feature size, which decreases as layers increase), and (2) product type
(memory vs. logic). PEVM derives historical consumption of silicon (i.e., square centimeters) by linewidth
technology from published data on annual wafer starts and average wafer size (VLSI 2003a,b,c). For each
linewidth technology, a weighted average number of layers is estimated using VLSI product-specific worldwide
silicon demand data in conjunction with complexity factors (i.e., the number of layers per 1C) specific to product
type (International SEMATECH 1998-2003). The distribution of memory/logic devices ranges over the period
covered from 52 percent logic devices in 1995 to 59 percent logic devices in 2000. These figures were used to
determine emission factors that express emissions per average layer per unit of area of silicon consumed during
product manufacture. The per-layer emission factor was based on the total annual emissions reported by
participants in EPA's PFC Reduction/Climate Partnership for the Semiconductor Industry in 1995 and later years.
For 1995 through 1999, total U.S. emissions were extrapolated from the total annual emissions reported by the
Partnership participants (Burton & Lieberman 2004). The emissions reported by the participants were divided by
the ratio of the total layer-weighted capacity of the plants operated by the participants and the total layer-weighted
capacity of all of the semiconductor plants in the United States; this ratio represents the share of layer-weighted
capacity attributable to partnership 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 to fabricate products at that plant. This
method assumes that participants and non-participants have similar capacity utilizations and per-layer emission
factors.
The U.S. estimate for the years 2000 through 2003—the period during which partners began the consequential
application of PFC-reduction measures—used a different estimation method. The emissions reporting by
Partnership participants for each year were accepted as the quantity emitted from the share of the industry
represented by those Partners. Remaining emissions (those from non-partners), however, were estimated using
PEVM and the method described above. (Non-partners are assumed not to have implemented any PFC-reduction
measures, and PEVM models emissions without such measures.) The portion of the U. S. total attributed to non-
Partners is obtained by multiplying PEVM's total U.S. figure by the non-partner share of total layer-weighted
silicon capacity for each year (as described above). Annual updates to PEVM reflect published figures for actual
silicon consumption from VLSI Research, Inc. as well as revisions and additions to the world population of
semiconductor manufacturing plants.
Two different approaches were also used to estimate the distribution of emissions of specific PFCs. Before 1999,
when there was no consequential adoption of PFC-reducing measures, a fixed distribution was assumed to apply to
the entire U.S. industry. This distribution was based upon the average PFC purchases by semiconductor
17 The most recent version of this model is v.3.1.0306.0304r, completed in March 2004.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 180
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manufacturers during this period and the application of IPCC default emission factors for each gas. For the 2000
through 2003 period, the 1990 through 1999 distribution was assumed to apply to the non-Partners. Partners,
however, began to report gas-specific emissions during this period. Thus, gas specific emissions for 2000 through
2003 were estimated by adding the emissions reported by the Partners to those estimated for the non-Partners.
Partners estimate their emissions using a range of methods. For 2003, most participants cited a method at least as
accurate as the IPCC's Tier 2c Methodology, 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 used to develop emission estimates were prepared in cooperation with the Partnership. Estimates of operating
plant capacities and characteristics for participants and non-participants were derived from the Semiconductor
Equipment and Materials International (SEMI) World Fab Watch (formerly International Fobs on Disk) database
(1996 to 2003). Estimates of silicon consumed by line-width from 1990 through 2003 were derived from
information from VLSI Research (2003d), and the number of layers per line-width was obtained from International
SEMATECH's International Technology Roadmap: 1998 - 2003.
Uncertainty
Quantitative uncertainty of this source category was performed using the IPCC-recommended Tier 2 uncertainty
estimation methodology, Monte Carlo Stochastic Simulation technique. Uncertainty is associated with the emission
estimates reported by the Partners, with the estimated share of total layer-weighted silicon capacity in 2003
attributable to the Partners, and with the total U.S. PFC emissions estimate as determined by PEVM.
The Monte Carlo analysis presented below relied on estimates of uncertainty attributed to these three variables.
Estimates of uncertainty for the three variables were in turn developed using the estimated uncertainties associated
with the individual inputs to each variable, error propagation analysis, and expert judgment. For the first variable,
the aggregate PFC emissions data supplied to the partnership, EPA estimated an uncertainty of ±10 percent
(representing a 95 percent confidence interval). This value accounts for uncertainty in partners' estimates of gas-
volume usage, and was calculated using 2003 Partnership submittals. Through expert judgment and review of the
emission reports submitted by companies under the Partnership agreement, the relative uncertainties were assumed
to be the same for each submittal in 2003, equal to ±29 percent of the individual Partner's reported value. Under
that assumption, uncertainty propagated across all Partners resulted in a combined relative uncertainty equal to
about 10 percent of the aggregate emissions reports under the Partnership. For the second variable, the share of
U.S. layer-weighted silicon capacity accounted for by non-Partners, an uncertainty of ±36 percent was estimated
based on the variability of the share over the period 1995 through 2003.
For the third variable, the relative error associated with the PEVM estimate in 2003, EPA estimated an uncertainty
of ±44 percent, using the calculus of error propagation and considering the aggregate average emission factor,
world silicon consumption, the U.S. share of layer-weighted silicon capacity, and the number of layers. The
uncertainty associated with the aggregate average emission factor was estimated to be 15 percent based on the
variability exhibited by the emission factor from 1996 through 1999. The uncertainty associated with the U.S.
share of capacity was estimated to be 10 percent based on information from the firm that compiled the database; the
principal source of errors was determined to be incomplete e-mail and telephone surveys of manufacturers (SMA
2003). The uncertainty associated with silicon consumption data was estimated to be 10 percent, based on the
reliability of industry surveys of world silicon consumption by technology node. Finally, the uncertainty associated
with the number of layers was estimated to be 39 percent.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-75. The emissions estimate for
total U.S. PFC emissions from semiconductor manufacturing were estimated to be between 3.7 and 5.7 Tg CO2 Eq.
at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of
20 percent below to 23 percent above the emissions estimate of 4.6 Tg CO2 Eq. It should be noted that this range
and the associated percentages apply to the estimate of total emissions rather than those of individual gases.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 181
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Uncertainties associated with individual gases will be somewhat higher than the aggregate, but were not explicitly
modeled.
Table 4-75: Tier 2 Quantitative Uncertainty Estimates for HFC, PFC, and SF6 Emissions from Semiconductor
Manufacture (Tg CO2 Eq. and Percent)
Source
Semiconductor
Manufacture
Gas
HFC, PFC,
and SF6
2003
Emission
Estimate3
(TgC02Eq.)
4.6
Uncertainty Range
Relative to Emission Estimate1"
(TgC02Eq.) (%)
Lower Upper Lower
Bound Bound Bound
3.7 5.7 -20%
Upper
Bound
+23%
a Because the uncertainty analysis covered all emissions (including NF3), the emission estimate presented here does not match
that shown in Table 4-73.
b Range of emissions estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Planned Improvements
The method by which non-partner related emissions are estimated (i.e., PEVM) is not expected to change (with the
exception of possible future updates to emission factors and added technology nodes). Future improvements to the
national emission estimates will primarily be associated with determining the portion of national emissions to
attribute to partner report totals (about 80 percent in recent years). As the nature of the partner reports change
through time and industry-wide reduction efforts increase, consideration will be given to what emission reduction
efforts—if any—are likely to be occurring at non-partner facilities (currently none are assumed to occur.)
4.20. Magnesium Production and Processing (IPCC Source Category 2C4)
The magnesium metal production and casting industry uses sulfur hexafluoride (SF6) as a cover gas to prevent the
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 small portion of
the SF6 reacts with the magnesium to form a thin molecular film of mostly magnesium oxide and magnesium
fluoride. The amount of SF6 reacting in magnesium production and processing is assumed to be 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 SO2, which are more toxic and corrosive than SF6.
The magnesium industry emitted 3.0 Tg CO2 Eq. (0.1 Gg) of SF6 in 2003 (see Table 4-76). This represents a 12
percent increase from 2002. The increase is attributable to a 1.5 percent rise in production and casting levels and to
a 10.5 percent increase in the weighted-average SF6 usage rate at these facilities. 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. In the
last ten years, the quantity of magnesium used in North American-produced vehicles has doubled (USGS 2004a).
Foreign magnesium producers are expected to meet the growing U.S. demand for primary magnesium (USGS
2004a).
Table 4-76: SF6 Emissions from Magnesium Production and Processing (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq. Gg
1990 5.4 0.2
1997
1998
1999
2000
2001
63
5.8
6.0
3.2
2,6
03
0.2
0.3
0.1
0,1
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 182
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2002 2.6 0.1
2003 3.0 0.1
Methodology
Emission estimates for the magnesium industry incorporate information provided by industry participants in EPA's
SF6 Emission Reduction Partnership for the Magnesium Industry. The partnership started in 1999 and, currently,
participating companies represent 100 percent of U.S. primary production and over 80 percent of the casting sector
(i.e., die, gravity, wrought, and anode casting). Emissions for 1999 through 2003 from primary production, some
secondary production (i.e., recycling), and a large fraction of die casting were reported by participants. The 1999
through 2003 emissions from the remaining secondary production and casting were estimated by multiplying
industry emission factors (kg SF6 per 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 below in Table 4-77. Because only one primary producer existed in the United States in 2003, 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 SF6 per metric ton.
Die casting emissions for 1999 through 2003, which accounted for 48 to 75 percent of all SF6 emissions from U.S.
casting and recycling processes during this period, were estimated based on information supplied by industry
partners. From 2000 to 2003, partners accounted for all U.S. die casting that was tracked by USGS. In 1999,
partners did not account for all die casting tracked by USGS, and, therefore, it was necessary to estimate the
emissions of die casters who were not partners. Die casters who were not partners were assumed to be similar to
partners who cast small parts. Due to process requirements, these casters consume larger quantities of SF6 per
metric ton of processed magnesium than casters that process large parts. Consequently, emissions estimates from
this group of die casters were developed using an average emission factor of 5.2 kg SF6 per metric ton of
magnesium. The emission factors for the other industry sectors (i.e., secondary production, gravity, wrought, and
anode casting) were based on discussions with industry representatives.
Table 4-77: SF6 Emission Factors (kg SF6 per metric ton of magnesium)
Year Secondary Die Casting Gravity Wrought Anodes
1999
2000
2001
2002
2003
1 2.14a
1 0.73
1 0.77
1 0.70
1 0.84
2
2
2
2
2
1 1
1 1
1 1
1 1
1 1
a The 1999 factor is a weighted average that includes an estimated emission factor of 5.2 kg SF6 per metric ton of magnesium for
die casters that do not participate in the Partnership.
Data used to develop these emission estimates were provided by the magnesium partnership participants and the
USGS. U.S. magnesium metal production (primary and secondary) and consumption (casting) data from 1990
through 2003 were available from the USGS (USGS 2002, 2003, 2004b). Emission factors from 1990 through
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 of 4.1 kg per metric ton was available
for the mid-1990s from an international survey (Gjestland & Magers 1996).
To estimate emissions for 1990 through 1998, industry emission factors were multiplied by the corresponding metal
production and consumption (casting) statistics from USGS. The primary production emission factors were 1.2 kg
per metric ton for 1990 through 1993, and 1.1 kg per metric ton for 1994 through 1996. For die casting, an emission
factor of 4.1 kg per metric ton was used for the period 1990 through 1996. For 1996 through 1998, the emission
factors for primary production and die casting were assumed to decline linearly to the level estimated based on
partner reports in 1999. This assumption is consistent with the trend in SF6 sales to the magnesium sector that is
reported in the RAND survey of major SF6 manufacturers, which shows a decline of 70 percent from 1996 to 1999
(RAND 2002). The emission factors for the other processes (i.e., secondary production, and gravity, wrought, and
anode casting), about which less is known, were assumed to remain constant at levels defined in Table 4-65.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 183
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Uncertainty
An uncertainty of 5 percent was assigned to the SF6 emissions data reported by each participant in the SF6 Emission
Reduction Partnership. These data have low uncertainty since they are prepared through facility-specific tracking of
SF6 cylinder purchases, usage, and returns. If partners did not report emissions data during the current reporting
year, SF6 emissions data were estimated using available emission factor and production information reported in
prior years. For example, to estimate 2003 emission factors, the average change in emission factor from 2002 to
2003 for reporting partners was applied to the 2002 emission factor of the non-reporting partner. The uncertainty
associated with the extrapolated emission factor was assumed to be 25 percent. For production data, if estimates
were unavailable for the current reporting year, data from the last reported year was applied.
For 2003, the uncertainty associated with this approach was assumed to be 30 percent. Between 1999 and 2003,
non-reporting partners have accounted for between 0 and 17 percent of total estimated sector emissions. For those
industry processes that are not represented in EPA's partnership, such as gravity, anode, and wrought casting, SF6
emissions were estimated using production and consumption statistics reported by USGS and an estimated process-
specific emission factor (see Table 4-78). The uncertainty associated with USGS-reported statistics and emission
factors were assumed to be 25 percent and 75 percent, respectively. In general, where precise quantitative
information was not available on the uncertainty of a parameter, a conservative (upper-bound) value was used.
Table 4-78: Simulated Variables for Tier 2 Uncertainty Analysis
Parameter
Partner-Reported SF6 Data (kg SF6)
SF6 Emission Factor for Non-Reporting Partners (kg SF6/metric ton Mg)
Production Data for Non-Reporting Partners (metric ton Mg)
USGS Production Data for Gravity, Anode, Wrought Casting and Secondary
Production (metric ton Mg)
SF6 Emission Factor for Gravity, Anode, Wrought Casting and Secondary
Production (kg SF6/metric ton Mg)
Probability
Distribution
Normal
Normal
Normal
Normal
Normal
Uncertainty"
(%)
5
25
30
25
75
a Reflects a 95 percent confidence interval.
Additional uncertainties exist in these estimates, such as the basic assumption that SF6 neither reacts nor
decomposes during use. The melt surface reactions and high temperatures associated with molten magnesium could
potentially cause some gas degradation. Recent measurement studies have identified SF6 cover gas degradation at
hot-chambered die casting machines on the order of 10 percent (Bartos et al. 2003). As is the case for other sources
of SF6 emissions, total SF6 consumption data for magnesium production and processing in the United States were
not available. Sulfur hexafluoride may also be used as a cover gas for the casting of molten aluminum with high
magnesium content; however, to what extent this technique is used in the United States is unknown.
A Monte Carlo analysis was applied to estimate the overall uncertainty of the emission estimate for the U.S.
magnesium industry. Random variables were selected from the probability density functions for each parameter,
which were assumed to be characterized by normal distributions. In the cases of estimates developed from partners
and non-reporting partners, probability density functions were applied to parameters (i.e., SF6 emissions data,
emission factors and production data) at the facility-specific level. The results of the Tier 2 quantitative uncertainty
analysis are summarized in Table 4-79. Magnesium production and processing SF6 emissions were estimated to be
between 2.6 and 3.3 Tg CO2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic
Simulations). This indicates a range of approximately 11 percent below to 13 percent above the emission estimate
of 3.0TgCO2Eq.
Table 4-79: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Magnesium Production and
Processing (Tg CO2 Eq. and Percent)
Source
2003
Gas Emission
Estimate
(TgC02Eq.)
Uncertainty Range Relative to 2003 Emission Estimate"
(TgC02Eq.) (%)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 184
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Lower Upper Lower Upper
Bound Bound Bound Bound
Magnesium Production
and Processing SFg 3_0 2.6 13 -11% +13%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Recalculations Discussion
The emission estimates for 2000, 2001, and 2002 were adjusted upward slightly from the previously reported
values. This revision reflects an update to historical data supplied by partnership participants and the USGS. The
changes resulted in an average annual increase of less than 0.1 Tg CO2 Eq. (4.1 percent) in SF6 emissions from
magnesium production and processing for the period 2000 through 2002.
Planned Improvements
As more work assessing the degree of cover gas degradation and associated byproducts is undertaken and
published, results could potentially be used to refine the emission estimates, which currently assume (per IPCC
Good Practice Guidance 2001) that all SF6 utilized is emitted to the atmosphere. EPA-funded measurements of SF6
in hot chamber die casting have indicated that the latter assumption may be incorrect, with observed SF6
degradation on the order of 10 percent (Bartos et al. 2003). More recent EPA-funded measurement studies have
confirmed this observation for cold chamber die casting (EPA 2004). Another issue that will be addressed in future
inventories is the likely adoption of alternate cover gases by U.S. magnesium producers and processors. These
cover gases, which include Am-Cover™ (containing HFC-134a) and Novec™ 612, have lower GWPs than SF6, and
tend to quickly decompose during their exposure to the molten metal. Additionally, as more companies join the
partnership, in particular those from sectors not currently represented, such as gravity and anode casting, emission
factors will be refined to incorporate these additional data.
[BEGIN BOX]
Box 4-1: Potential Emission Estimates of HFCs, PFCs, and SF6
Emissions of FJFCs, 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 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997) 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. 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, no delay between consumption and emission is assumed and, consequently, no destruction of the
chemical takes place. In this case, actual emissions equal potential emissions.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 185
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Table 4-80 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 using the EPA's Vintaging Model. Estimates of HFCs, PFCs, and SF6
consumed by semiconductor manufacture were developed by dividing chemical-by-chemical emissions by the
appropnate 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. Potential SF6
emissions estimates for electrical transmission and distribution were developed using U.S. utility purchases of SF6
for electrical equipment. From 1999 through 2003, estimates were obtained from reports submitted 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 4-80: 2003 Potential and Actual Emissions
Source
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production
Semiconductor Manufacture
Magnesium Production and Processing
Electrical Transmission and Distribution
of HFCs, PFCs,
Potential
181.0
-
6.6
3.0
21.8
and SF6 from Selected Sources (Tg CO2 Eq.)
Actual
99.5
3.8
12.3
4.3
3.0
14.1
- Not applicable.
[END BOX]
4.21. 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 2003 are reported in Table 4-81.
Table 4-81: NOX, CO, and NMVOC Emissions from Industrial Processes (Gg)
Gas/Source
NOX
Chemical & Allied Product Manufacturing
Metals Processing
Storage and Transport
Other Industrial Processes
Miscellaneous*
CO
Chemical & Allied Product Manufacturing
Metals Processing
Storage and Transport
Other Industrial Processes
Miscellaneous*
1990 :
591
152
88
3
343
5
4,124
1,074
2,395
69
487
101
Jvi;,., 1997
"i'jVV" 629
v";'-v;;,f 115
:,f.;' ''•"' 81
: '•;*>•, is
:;':V: v; 417
:£''•*• l
•'••• >.t 3>153
;.;.;/<"• 971
:;;Vf;- 1,551
;/":?'' 64
• :>.•<>; 528
"',?$',• 38
1998
637
117
81
15
424
1
3,163
981
1,544
65
535
38
1999
595
93
78
13
409
2
2,156
317
1,138
148
518
35
2000
626
95
81
14
434
2
2,217
327
1,175
154
538
23
2001
656
97
86
15
457
1
2,339
338
1,252
162
558
30
2002
630
95
76
14
442
3
2,308
306
1,174
195
576
57
2003
648
92
83
14
457
2
2,431
299
1,290
219
575
49
18 See Annex 5 for a discussion of sources of SF6 emissions excluded from the actual emissions estimates in this report.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 186
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NMVOCs 2,426 '..;•'?"', J 2,038 2,047 1,813 1,773 1,769 1,725 1,711
Chemical & Allied Product Manufacturing
Metals Processing
Storage and Transport
Other Industrial Processes
Miscellaneous*
575 :,',.> .;
in :'.-o
1,356 '.?•$,
364 :^'c
20 -;n:;
'•• 352
*»" 71
', 1,205
v 397
13
357
71
1,204
402
13
228
60
1,122
398
6
230
61
1,067
412
3
238
65
1,082
381
4
194
62
1,093
369
7
198
65
1,069
374
5
* 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
Field Burning of Agricultural Residues source.
Note: Totals may not sum due to independent rounding.
Methodology
These emission estimates were obtained from preliminary data (EPA 2004), and disaggregated based on EPA
(2003), which, in its final iteration, will be published on the National Emission Inventory (NEI) Air Pollutant
Emission Trends web site. Emissions were calculated either for individual categories or for many categones
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 categones 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. A quantitative uncertainty analysis was not performed.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 187
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Substitution of Ozone Depleting Substances
Iron and Steel Production
Cement Manufacture
Nitric Acid ^^H
Ammonia Production and Urea Application ^^^|
Electrical Transmission and Distribution ^^B
Lime Manufacture ^^|
MCFC-22 Production ^H
Aluminum Production ^|
AdipicAcid |
Limestone and Dolomite Use |
Semiconductor Manufacture |
Petrochemical Production |
Soda Ash Manufacture and Consumption |
Magnesium Production and Processing |
Titanium Dioxide Production |
Phosphoric Acid Production |
Ferroalloys |
Carbon Dioxide Consumption |
Silicon Carbide Production <0.05
Industrial Processes
as a Portion of all
Emissions
4.5%
0
20
40
60
Tg C02Eq.
80
100
120
Figure 4-1: 2003 Industrial Processes Chapter Greenhouse Gas Sources
-------
5. Solvent and Other Product Use
Greenhouse gas emissions are produced as a by-product of various solvent and other product uses. In the United
States, emissions from Nitrous Oxide (N2O) Product Usage, the only source of greenhouse gas emissions from this
sector, accounted for less than 0.1 percent of total U.S. anthropogenic greenhouse gas emissions on a carbon
equivalent basis in 2003 (see Table 5-1). Ambient air pollutant emissions also result from solvent and other product
use, and are presented in Table 5-2.
Table 5-1: N2O Emissions from Solvent and Other Product Use (Tg CO2 Eq. and Gg)
Gas/Source
Nitrous Oxide
Tg CO, Eq.
Gg
Product Usage
1990 1
4.3
13.9
!*: 1997
h
I; 4.8
\" 15.4
1998
4.8
15.4
1999
4.8
15.4
20(
4
15
10
8
4
2001
4.8
15.4
20C
4
15
2
8
4
2003
4.8
15.4
Table 5-2: Ambient Air Pollutant Emissions from Solvent and Other Product Use (Gg)
Gas/Source
NOX
CO
NMVOCs
1990' 1997
i: ' 3
4:, 1
5,217 5,100
1998
3
1
4,671
1999
3
46
4,569
2000
3
46
4,384
2001
3
45
4,547
2002
5
46
4,256
2003
4
65
4,138
5.1. Nitrous Oxide Product Usage (IPCC Source Category 3D)
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 through a low-pressure, low-temperature (SOOT) reaction. Once the
steam is removed through condensation, the remaining N2O is purified, compressed, dried, and liquefied for storage
and distribution. Two companies operate a total of five N2O production facilities 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 also are used in the following applications:
• 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 2003 was approximately 17 Gg. Nitrous oxide emissions were 4.8 Tg CO2 Eq. (15.4 Gg) in
2003 (see Table 5-3). 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 that do not require N2O. 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 (Heydorn 1997).
Table 5-3: N2O Emissions from Nitrous Oxide Product Usage (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq. Gg
1990
1997
1998
43
.-'"if •' ' -
48
4.8
13.9
154
15.4
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 189
-------
1999
2000
2001
2002
2003
4.8
4.8
4.8
4.8
4.8
15.4
15.4
15.4
15.4
15.4
Methodology
Emissions from N2O product usage were calculated by first multiplying the total amount of N2O 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 = Za [Total U.S. Production of Nitrous Oxide] x [Share of Total
Quantity of N2O Usage by Sector i] x [Emissions Rate for Sector i], where i = sector.
The share of total quantity of N2O usage by subcategory represents the share of national N2O produced that is used
by the specific subcategory (i.e., anesthesia, food processing, etc.). In 2002, and also assumed for 2003, the
medical/dental industry used an estimated 86 percent of total N2O produced, followed by food processing
propellants at 6.5 percent. All other categories combined used the remainder of the N2O produced (Tupman 2002).
This subcategory breakdown has changed only slightly over the past decade. For instance, the small share of N2O
usage in the production of sodium azide has declined significantly during the decade of the 1990s. Due to the lack
of information on the specific time period of the phase-out in this market subcategory, most of the N2O usage for
sodium azide production is assumed to have ceased after 1996, with the majority of its small share of the market
assigned to the larger medical/dental consumption subcategory. Once the N2O is allocated across these
subcategories, a usage emissions rate is then applied for each sector to estimate the amount of N2O emitted.
Only the medical/dental and food propellant subcategories are estimated to release emissions into the atmosphere,
and therefore these subcategories are the only usage subcategories with emission rates. For the medical/dental
subcategory, 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 emission factor of
97.5 percent is used for this subcategory (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 subcategory (Heydorn 1997). For the remaining
subcategories, all of the N2O is consumed/reacted during the process, and therefore the emissions rate is considered
to be zero percent (Tupman 2002).
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. Tupman (2003) was able to
provide a narrower range for 1996 that falls within the production bounds described by Heydorn (1997). These data
are considered more industry specific and current. 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 2002 (Tupman 2003).
Production data for 2003 was assumed to equal 2002 data.
The 1996 share of the total quantity of N2O used by each subcategory 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
subcategory was kept the same as the 1996 number provided by SRI Consulting. The 1997 through 2002 share of
total quantity of N2O usage by sector was obtained from communication with a N2O industry expert (Tupman
2003). Share of total quantity of N2O usage data for 2003 was assumed to equal that of 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
subcategories was obtained from communication with a N2O industry expert (Tupman 2002). The emissions rate
for the medical/dental subcategory was substantiated by the Encyclopedia of Chemical Technology (Othmer 1990).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 190
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Table 5-4: N2O Production (Gg)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
Gg
16.3
15.9
15.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
17.0
Uncertainty
Since plant-specific N2O production data is confidential, emissions are based on national production statistics
acquired as ranges through reports and interviews with industry experts Heydorn (1997) and Tupman (2002).
Based on these ranges, the uncertainty associated with the production estimate that was used to develop industry
emissions in 2003 was calculated. Information regarding the industry-specific use of N2O is confidential. Thus, the
predicted share of the total quantities of N2O used by each subcategory is somewhat uncertain because they are also
based on industry expert opinion.
While the level of certainty differs by industry, the minimum and maximum market shares, expressed as a percent of
N2O usage, are within 2 to 3 percentage points of the estimated market share. The emissions rate for the
medical/dental industry, an estimate also based on industry opinion, carries an uncertainty level of 3 percent.
Unquantified areas of uncertainty include the schedule of the market decline of sodium azide production.
An uncertainty analysis, based on the Tier 1 methods found in IPCC's Good Practice Guidance and Uncertainty
Management in National Greenhouse Gas Inventories, was conducted for all inputs to the N2O Product Usage
source category analysis, including activity data, subcategory shares of N2O consumption, and emission factors.
The results of the Tier 1 quantitative uncertainly analysis are summarized in Table 5-5. N2O Product Usage N2O
emissions were estimated to be between 4.4 and 5.1 Tg CO2 Eq. at the 95 percent confidence level. This indicates a
range of 7 percent above and below the 2003 emission estimate of 4.8 Tg CO2 Eq.
Table 5-5: Tier 1 Quantitative Uncertainty Estimates for N2O Emissions from Nitrous Oxide Product Usage (Tg
CO2 Eq. and Percent)
IPCC Source
Category
N2O Product Usage
Gas
N,O
Year 2003
Emissions
(TgC02Eq.)
A Q
4.5
Uncertainty
7%
Uncertainty Range Relative to
2003 Emission Estimate
(Tg C02 Eq.)
Lower Bound Upper Bound
4.4 5.1
Planned Improvements
Planned improvements include a continued evaluation of alternative production statistics for cross verification and a
reassessment of subcategory usage to accurately represent the latest trends in the product usage.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 191
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5.2. Ambient Air Pollutants from Solvent Use
The use of solvents and other chemical products can result in emissions of various ozone precursors (i.e., ambient
air pollutants).1 Nonmethane volatile organic compounds (NMVOCs), commonly referred to as "hydrocarbons,"
are the primary gases emitted from most processes employing organic or petroleum based solvents. As some of
industrial applications also employ thermal incineration as a control technology, combustion by-products, such as
carbon monoxide (CO) and nitrogen oxides (NOx), are also reported with this source category. Surface coatings
accounted for approximately 41 percent of NMVOC emissions from solvent use in 2003, 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 2003; NMVOC emissions from solvent use have
decreased 21 percent since 1990.
Although NMVOCs are not considered direct greenhouse gases, their role as precursors to the formation of
ozone—which is a greenhouse gas—results in their inclusion in a greenhouse gas inventory. Emissions from
solvent use have been reported separately by the United States to be consistent with the inventory reporting
guidelines recommended by the IPCC. These guidelines identify solvent use as one of the major source categories
for which countries should report emissions. In the United States, emissions from solvents are primarily the result
of solvent evaporation, whereby the lighter hydrocarbon molecules in the solvents escape into the atmosphere. The
evaporation process varies depending on different solvent uses and solvent types. The major categories of solvent
uses include: degreasing, graphic arts, surface coating, other industrial uses of solvents (i.e., electronics, etc.), dry
cleaning, and non-industrial uses (i.e., uses of paint thinner, etc.).
Total emissions of NOX, NMVOCs, and CO from 1990 to 2003 are reported in Table 5-6.
Table 5-6: Emissions of NOX, CO, and NMVOC from Solvent Use (Gg)
Activity
NOX
Degreasing
Graphic Arts
Dry Cleaning
Surface Coating
1990 |;>'^
i ••'•%
+ v-
+ *';;
1997
3
1
2
1998
3
1
2
1999
3
3
2000
3
3
2001
3
3
2002
5
5
2003
4
4
Other Industrial Processes3 + S.j.ll + + + + + + +
Non-Industrial Processes1* + rj•;..-', + + + + + + +
Other NA ?(; '+ + + + + + +
CO 4 ffy 1 1 46 46 45 46 65
Degreasing + S,j«',l + + + + + + +
Graphic Arts + ^';.••', + + + + + + +
Dry Cleaning + f^ + + + + + + +
Surface Coating + ;',<;t 1 1 46 46 45 46 65
Other Industrial Processes3 4 &.)>••, + + + + + + +
Non-Industrial Processes1* + ;y->; + + + + + + +
Other NA ^ + + + + + + +
NMVOCs 5,217 ;':?. 5,100 4,671 4,569 4,384 4,547 4,256 4,138
Degreasing 675 ?>•: 566 337 363 316 331 310 301
Graphic Arts 249 v^ 266 272 224 222 229 214 208
Dry Cleaning 195 .'i:vy 148 151 267 265 272 254 247
1 Solvent usage in the United States also results in the emission of small amounts of hydrofluorocarbons (HFCs) and
hydrofluoroethers (HFEs), which are included under Substitution of Ozone Depleting Substances in the Industrial Processes
chapter.
2 "Non-industrial" uses include cutback asphalt, pesticide application adhesives, consumer solvents, and other miscellaneous
applications.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 192
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Surface Coating
Other Industrial Processes3
Non-Industrial Processes1"
Other
2,289
85
1,724
+
:';;*5;i 2,228
;\C; 100
C'« 1,790
w^. 3
1,989
101
1,818
3
1,865
95
1,714
40
1,767
98
1,676
40
1,863
103
1,707
42
1,744
97
1,598
40
1,695
94
1,554
38
a Includes rubber and plastics manufacturing, and other miscellaneous applications.
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.
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.
These emission estimates were obtained from preliminary data (EPA 2004), and disaggregated based on EPA
(2003), which, in its final iteration, will be published on the National Emission Inventory (NEI) Air Pollutant
Emission Trends web site. Emissions were calculated either for individual categories or for many categones
combined, using basic activity data (e.g., the amount of solvent purchased) as an indicator of emissions. National
activity data were collected for individual applications from various agencies.
Activity data were used in conjunction with emission factors, which together relate the quantity of emissions to the
activity. Emission factors are generally available from the EPA's Compilation of Air Pollutant Emission Factors,
AP-42 (EPA 1997). The EPA currently derives the overall emission control efficiency of a source category from a
variety of information sources, including published reports, the 1985 National Acid Precipitation and Assessment
Program emissions inventory, and other EPA data bases.
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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 193
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6. 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 categones: enteric
fermentation in domestic livestock, livestock manure management, rice cultivation, agricultural soil management,
and field burning of agricultural residues (see Figure 6-1). Carbon dioxide (CO2) emissions and removals from
agriculture-related land-use activities, such as conversion of grassland to cultivated land, are presented in the Land-
Use Change and Forestry sector. Carbon dioxide emissions from on-farm energy use are accounted in the Energy
chapter.
Figure 6-1: 2003 Agriculture Chapter Greenhouse Gas Emission Sources
In 2003, the agricultural sector was responsible for emissions of 433.3 Tg CO2 Eq., or 6.3 percent of total U.S.
greenhouse gas emissions. Methane (CH4) and nitrous oxide (N2O) were the primary greenhouse gases emitted by
agncultural activities. Methane emissions from enteric fermentation and manure management represent about 21
percent and 7 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 67 percent. Manure management
and field burning of agricultural residues were also small sources of N2O emissions.
Table 6-1 and Table 6-2 present emission estimates for the Agriculture sector. Between 1990 and 2003, CH4
emissions from agricultural activities increased by 3.2 percent while N2O emissions increased by 0.7 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 (NOX).
Table 6-1: Emissions from Agriculture (Tg CO2 Eq.)
Gas/Source
CH4
Enteric Fermentation
Manure Management
Rice Cultivation
Field Burning of Agricultural
Residues
N2O
Agricultural Soil Management
Manure Management
Field Burning of Agricultural
Residues
Total
19905
156.9
1179
31 2
7 1
07
269.6
2530
163
04
426.5
i,,'" 1997
r :; i63.o
.;.'<, 118-3
'i-iti 36.4
•';> 7.5
f ^ ,'
.;.':•?• 0.8
>;>:; 269.8
". ;. 252.0
•'I*,; '
i!W 17.3
!'<;
:J.f; 0.4
|,A ;, 432.8
1998
164.2
116.7
38.8
7.9
0.8
285.6
267.7
17.4
0.5
449.8
1999
164.6
116.8
38.8
8.3
0.8
261.3
243.4
17.4
0.4
425.9
2000
162.0
115.6
38.1
7.5
0.8
282.1
263.9
17.8
0.5
444.1
2001
161.9
114.5
38.9
7.6
0.8
275.6
257.1
18.0
0.5
437.5
2002
161.5
114.6
39.3
6.8
0.7
270.9
252.6
17.9
0.4
432.4
2003
161.8
115.0
39.1
6.9
0.8
271.5
253.5
17.5
0.4
433.3
Note: Totals may not sum due to independent rounding.
Table 6-2: Emissions from Agriculture (Gg)
Gas/Source
CH4
Enteric Fermentation
Manure Management
Rice Cultivation
Field Burning of Agricultural
Residues
N2O
1990
7,470 S
5,612-
1,485!
339:
33 |
870;
!»»!' 1997
,;$•• 7,760
;•/'; 5,634
'">''„, 1,733
rv 356
i$t 37
;',;';;;' 870
1998
7,821
5,557
1,850
376
38
921
1999
7,838
5,561
1,846
395
37
843
2000
7,713
5,505
1,813
357
38
910
2001
7,708
5,454
1,853
364
37
889
2002
7,689
5,458
1,873
325
34
874
2003
7,705
5,475
1,864
328
38
876
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 195
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Agricultural Soil Management
Manure Management
Field Burning of Agricultural
Residues
CO
NOX
816;
52;
1;
689:
28;
\
I
r-v 813
£;' 56
•Y
v'r i
S, 767
•ftf, 34
864
56
1
789
35
785
56
1
767
34
851
57
1
790
35
829
58
1
770
35
815
58
1
706
33
818
57
1
794
33
Note: Totals may not sum due to independent rounding.
6.1. Enteric Fermentation (IPCC Source Category 4A)
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 absorbed and
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 affect CH4 emissions. In
general, lower feed quality or higher feed intake lead 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 6-3 and Table 6-4. Total livestock
CH4 emissions in 2003 were 115 Tg CO2 Eq. (5,475 Gg), increasing very slightly since 2002 due to minor increases
in some animal populations and dairy cow milk production in some regions. Beef cattle remain the largest
contributor of CH4 emissions from enteric fermentation, accounting for 72 percent in 2003. Emissions from dairy
cattle in 2003 accounted for 24 percent, and the remaining emissions were from horses, sheep, swine, and goats.
From 1990 to 2003, emissions from enteric fermentation have decreased by 2 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.
Table 6-3: CH4 Emissions from Enteric Fermentation (Tg CO2 Eq.)
Livestock Type 1990
Beef Cattle 83 2
Dairy Cattle 28 9
Horses 1 9
Sheep 1 9
Swine 1 7
Goats 0 3
Total 117.9
!>;'//';,'' 1997
ix;t 86
^';... 26
•:;•'• v,; 2
l-l '• '.-' l
•>/' 0
it'-r*. 118
.6
.4
.0
.3
.8
.2
.3
1998
85
26
2
1
2
0
116
.0
.3
.0
.3
.0
.2
.7
1999
84
26
2
1
1
0
116
.9
.6
.0
.2
.9
.2
.8
2000
83.4
27.0
2.0
1.2
1.9
0.2
115.6
2001
82
26
2
1
1
0
114
.4
.9
.0
.2
.9
.2
.5
2002
82.3
27.1
2.0
1.1
1.9
0.2
114.6
2003
82.5
27.3
2.0
1.1
1.9
0.2
115.0
Note: Totals may not sum due to independent rounding.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 196
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Table 6-4: CH4 Emissions from Enteric Fermentation (Gg)
Livestock Type 1990|- ti 1997 1998 1999 2000 2001 2002 2003
Beef Cattle
Dairy Cattle
Horses
Sheep
Swine
Goats
3,961
1,375
91
91
81
13
:•-•/:. 4,124
> ':',:: 1,255
;: »*'-,•, 93
:.\'%f 64
:•• t& ss
v& 10
4,047
1,251
94
63
93
10
4,045
1,265
93
58
90
10
3,973
1,283
94
56
88
10
3,923
1,282
95
56
88
10
3,919
1,290
95
53
90
10
3,930
1,300
95
50
90
10
Total 5,612 V. 5,634 5,557 5,561 5,505 5,454 5,458 5,475
Note: Totals may not sum due to independent rounding.
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. A more detailed methodology (i.e., IPCC Tier 2) was therefore applied to estimating
emissions for all cattle except for bulls. Emission estimates for other domesticated animals (horses, sheep, swine,
goats, and bulls) 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 (Heifers and Steers)
• Cows
• Bulls
Calf birth rates, end-of-year population statistics, detailed feedlot placement information, and slaughter weight data
were used to model cohorts of individual animal types and their specific emission profiles. The key variables
tracked for each of the cattle population categories are described in Annex 3.9. These variables include
performance factors such as pregnancy and lactation, as well as average weights and weight gain. 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, 2003a,c,d,f, 2004a,c,d,f).
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 other well-fed cattle
consuming temperate-climate feed types. Given the availability of detailed diet information for different regions
and animal types in the United States, DE and Ym values unique to the United States were developed, rather than
using the recommended IPCC values. The diet characterizations and estimation of DE and Ym values were based on
information from state agricultural extension specialists, a review of published forage quality studies, expert
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 197
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opinion, and modeling of animal physiology. The 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
Feedstuffs (1998), Western Dairyman (1998), and expert opinion. See Annex 3.9 for more details on the method
used to characterize cattle diets in the United States.
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 3.9.
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 2003. 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. Annual livestock population data for these 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, 1995a-b, 1998a-b, 1999a-c, 2000a-g, 2001a-f, 2002a-f, 2003a-f,
2004a-f). Horse population data were obtained from the FAOSTAT database (FAO 2004), because USDA does not
estimate U.S. horse populations annually. Goat population data were obtained from the Census of Agriculture
(USDA 1999g). 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).
See Annex 3.9 for more detailed information on the methodology and data used to calculate CH4 emissions from
enteric fermentation.
Uncertainty
Uncertainty estimates were developed for the emission estimates presented in EPA (2003). No significant changes
occurred in the method of data collection, data estimation methodology, or other factors that influence the
uncertainty ranges around the 2003 activity data and emission factor input variables. Consequently, the EPA (2003)
uncertainty estimates were directly applied to the 2003 emission estimates.
A total of 185 primary input variables (178 for cattle and 8 for non-cattle) were identified as key input variables for
the uncertainty analysis. A normal distribution was assumed for almost all activity- and emission factor-related
input variables. A triangular distribution was assigned for three input vanables (specifically cow-birth ratios for the
current and the past two years). For some key input variables, the uncertainty ranges around their estimates (used
for inventory estimation) were collected from published documents and other public sources. In addition, both
endogenous and exogenous correlations between selected primary input variables were modeled. The exogenous
correlation coefficients between the probability distributions of selected activity-related variables were developed as
educated estimates.
The uncertainty ranges associated with the activity-related input variables were no larger in magnitude than plus or
minus 10 percent. However, for many emission factor-related input variables, the lower- and/or upper-bound
uncertainty estimates were over 20 percent. The results of the Tier 2 quantitative uncertainty analysis are
summarized in Table 6-5. Enteric fermentation CH4 emissions in 2003 were estimated to be between 102.3 and
135.7 Tg CO2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This
indicates a range of 11 percent below to 18 percent above the 2003 emission estimate of 115.0 Tg CO2 Eq. Among
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 198
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the individual sub-source categories, beef cattle accounts for the largest amount of CH4 emissions as well as the
largest degree of uncertainty in the emission estimates. Consequently, the cattle sub-source categories together
contribute to the largest degree of uncertainty to the estimates of CH4 emissions from livestock enteric fermentation.
Among non-cattle, horses account for the largest degree of uncertainty in the emission estimates.
Table 6-5: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Enteric Fermentation (Tg CO2 Eq.
and Percent)
2003 Emission Uncertainty Range Relative to Emission
Source Gas Estimate Estimate"
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper
Bound
Enteric Fermentation CH4 115.0 102.3 135.7 -11% +18%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
QA/QC and Verification
In order to ensure the quality of the emission estimates from enteric fermentation, the IPCC Tier 1 and Tier 2
Quality Assurance/Quality Control (QA/QC) procedures were implemented consistent with the U.S. QA/QC plan.
Tier 2 QA procedures included independent peer review of emission estimates. Particular emphasis was placed on
cattle population and growth data, and on evaluating the effects of data updates as described in the recalculations
discussion below.
Recalculations Discussion
While there were no changes in the methodologies used for estimating CH4 emissions from enteric fermentation,
emissions were revised slightly due to changes in historical data. USDA published revised population estimates in
2004 for some cattle statistics; these include population, livestock placements, and slaughter statistics for 2000,
2001, and 2002. Emission estimates changed for these years for both beef and dairy cattle as a result of revised
inputs that reflect USDA updates.
The rate of weight gam for growing steers and heifers was increased for the modeling of 2000 through 2003. The
model uses the weight gain data to estimate the number of cattle (steers and heifers) available to be placed into
feedlots (by weight class). These estimates were compared to the USDA statistics on actual feedlot placements (by
weight class). The updated USDA data show increases in feedlot placements in the heavy weight classes, and
required an increase in the rate of weight gain in the modeled population in order to match the observed statistics.
Additionally, the distribution of cattle by weight at the start of the year was adjusted to reflect the larger portion of
heavier animals.
In 2000, both beef and dairy cattle emissions changed less than 3 Gg (0.1 percent) as a result of the recalculations.
In 2001, beef cattle CH4 emissions increased 12 Gg (0.3 percent), while dairy cattle emissions decreased 1 Gg (0.1
percent). In 2002, beef cattle CH4 emissions increased 8 Gg (0.2 percent), while dairy cattle emissions increased
less than 1 Gg (0.03 percent). For other livestock types, a slight upward revision in the swine population for 2002
resulted in an increase in CH4 emissions of less than 1 Gg (0.06 percent) in that year. Overall, the changes resulted
in an average annual increase of less than 0.1 Tg CO2 Eq. (0.04 percent) in CH4 emissions from enteric fermentation
for the period 1990 through 2002.
Planned Improvements
The revised and updated USDA data discussed above highlight the need to re-examine several model inputs.
Although the enteric fermentation model was constructed to identify the imbalances mentioned in the recalculations
discussion, the current inventory presents the first effort to address such differences by making adjustments to
model inputs. The updates are based both on expert opinion and on equations published by the American Society of
Agricultural Engineers (ASAE) that predict weight versus age statistics for steers and imply growth rates larger than
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 199
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those used in previous years (ASAE 1999). In addition, in 2001, USDA reported increased rates of gains for
yearlings (USDA 200Ig). While these two sources provide support for the updates, further research is necessary to
verify the changes and to understand what changes over time may be necessary in future inventory analyses.
6.2. Manure Management (IPCC Source Category 4B)
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-producmg 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 types and the growth rate of the animals will affect the quantity and characteristics
of the 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 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 in the Agricultural Soil Management source category within
the Agriculture sector. 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 6-6 and Table 6-7 provide estimates of CH4 and N2O emissions from manure management by animal
category. Estimates for CH4 emissions in 2003 were 39.1 Tg CO2 Eq. (1,864 Gg), 25 percent higher than in 1990.
The majority of this increase was from swine and dairy cow manure, where emissions increased 30 and 38 percent,
respectively. The increase in emissions from these animal types is primarily 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 toward larger facilities is translated into an increasing use of liquid
manure management systems, which have higher potential CH4 emissions than dry systems. This shift was
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 200
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accounted for by incorporating state-specific weighted CH4 conversion factor (MCF) values in combination with the
1992 and 1997 farm-size distribution data reported in the Census of Agriculture (USDA 1999e). From 2002 to
2003, there was a 0.5 percent decrease in CH4 emissions, due to minor shifts in the animal populations and the
resultant effects on manure management system allocations. A description of the emission estimation methodology
is provided in Annex 3.10.
Total N2O emissions from manure management systems in 2003 were estimated to be 17.5 Tg CO2 Eq. (57 Gg).
The 8 percent increase in N2O emissions from 1990 to 2003 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 2002,
although swine populations periodically declined slightly throughout the time series. Nitrous oxide emissions
showed a 2 percent decrease from 2002 to 2003, due to minor shifts in animal population.
The population of beef cattle in feedlots increased over the period of 1990 to 2003, resulting in increased N2O
emissions from this sub-category of cattle. Although dairy cow populations decreased overall for the period 1990 to
2003, the population of dames managing and stonng manure on-site—as opposed to using pasture, range, or
paddock or daily spread systems—increased. Over the same period, dairies also experienced a shift to more liquid
manure management systems at large operations, which result in lower N2O emissions then dry systems. The net
result is a slight decrease in dairy cattle N2O emissions over the period 1990 to 2003. 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 in the Agricultural Soil Management source category of the
Agriculture sector.
Table 6-6: CH4 and N2O Emissions from Manure Management (Tg CO2Eq.)
Gas/Animal
Type
CH4
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
N2O
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
Total
+ Does not exceed
Note: Totals may
1990
31.2 ;
11,4 ;
32 ;
13 1 ;
0.2 :
+ ;
2.7 :
0.6 :
16.3 :
4.3 :
4.9 :
0.4 :
o.i :
+ !
6.4 :
0.2 '
47.4 •
0.05 Tg CO2
^ 1997
'^ 36.4
'^i 13,4
V '-.;>; 3.2
'(• ';','" 16.4
lx' o-i
*•''*"'„ +
V'-'j 2.7
'.'.\' '' 0.6
;'•; •-, I"7-3
t',"', 4.0
y.-it/ 5-4
>;f-) O-4
;'•';£ o.i
?, •'!' +
'.; t 7.2
fV'>! 0.2
At;,!1 53.7
Eq.
not sum due to independent
1998
38.8
13,9
3.1
18.4
0.1
+
2.7
0.6
17.4
3.9
5.5
0.5
0.1
+
7.2
0.2
56.2
rounding.
1999
38.8
14,7
3.1
17.6
0.1
+
2.6
0.6
17.4
4.0
5.5
0.4
0.1
+
7.2
0.2
56.2
2000
38.1
14,5
3.1
17.1
0.1
+
2.6
0.6
17.8
4.0
5.9
0.4
0.1
+
7.2
0.2
55.9
2001
38.9
15,0
3.1
17.4
0.1
+
2.7
0.6
18.0
3.9
6.1
0.4
0.1
+
7.3
0.2
57.0
2002
39.3
15,2
3.1
17.7
0.1
+
2.7
0.6
17.9
3.9
5.9
0.4
0.1
+
7.4
0.2
57.3
2003
39.1
15,7
3.1
17.0
0.1
+
2.7
0.6
17.5
3.9
5.6
0.4
0.1
+
7.3
0.2
56.7
Table 6-7: CH4 and N2O Emissions from Manure Management (Gg)
Gas/Animal
Type
CH4
Dairy Cattle
Beef Cattle
Swine
Sheep
1990;;;;*,,;
1,485?: V:
545 ?;••<• ,.
153?:^'.'
622 ?: ' •• ,
9?",,. '
1997
1,733
639
152
780
6
1998
1,850
662
149
874
6
1999
1,846
700
150
837
6
2000
1,813
692
149
812
5
2001
1,853
715
148
826
5
2002
1,873
111
147
843
5
2003
1,864
748
146
808
5
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 201
-------
Goats
Poultry
Horses
N2O
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
1
128
27
52
14
16
1
+
+
21
1
f "'!," '"*V
t ;'*"*.'
if- •'"'«]>•
if- ,''
f- .*, l " ".
if- "•< ' , -
f; V,.;/'
£ :;!; ',
^ ;f ': "'
f- //.,'
i^*1'
f- "j . ' •'
if; V ' ;
J ;'''!'*
itfj&;
1
127
28
56
13
17
1
+
+
23
1
1
130
28
56
13
18
1
+
+
23
1
1
125
28
56
13
18
1
+
+
23
1
1
125
28
57
13
19
1
+
+
23
1
1
129
29
58
13
20
1
+
+
24
1
1
126
29
58
13
19
1
+
+
24
1
1
127
29
57
13
18
1
+
+
24
1
+ Does not exceed 0.5 Gg.
Note: Totals may not sum due to independent rounding.
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 emission 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 (excretion rate by animal type times animal population);
• Amount of volatile solids produced (excretion rate by animal type times animal population);
• 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, including the impacts of any biogas collection efforts);
• 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.
This section presents a summary of the methodologies used to estimate CH4 and N2O emissions from manure
management for this inventory. See Annex 3.10 for more detailed information on the methodology and data used to
calculate CH4 and N2O emissions from manure management.
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, UEP 1999). For other animal types, manure management system usage
was based on previous 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 for temperate climates (IPCC 2000).
MCFs for liquid/slurry, anaerobic lagoon, and deep pit systems were calculated based on the forecast performance
of biological systems relative to temperature changes as predicted in the van't Hoff-Arrhenius equation (see Annex
3.10 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 202
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For each animal group, 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, volatile solids production was calculated using a national average volatile solids
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 volatile solids production rates that are related to the diet of the animal for each year of the
inventory were used (Lieberman et al, 2004). The resulting volatile solids for each animal group was then
multiplied by the maximum CH4 producing capacity of the waste (B0) 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 based on measurements of excreted manure. 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.
The data used to calculate the inventory estimates were based on a variety of 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, 2003a-f,
2004a-f). Horse population data were obtained from the FAOSTAT database (FAO 2004), because USDA does not
estimate U.S. horse populations annually. Goat population data were obtained from the Census of Agriculture
(USDA 1999d). Information regarding poultry turnover (i.e., slaughter) rate was obtained from state Natural
Resource Conservation Service (NRCS) personnel (Lange 2000). Dairy cow and swine population data by farm
size for each state, used for the weighted MCF and emission factor calculations, were obtained from the Census of
Agriculture, which is conducted every five years (USDA 1999e).
Manure management system usage data for dairy and swine operations were obtained from USDA's Centers for
Epidemiology and Animal Health (USDA 1996b, 1998d, 2000h) for small operations and from preliminary
estimates for EPA's Office of Water regulatory effort for large operations (ERG 2000a; EPA 2001a, 2001b). Data
for layers were obtained from a voluntary United Egg Producers' survey (UEP 1999), previous EPA estimates (EPA
1992), and USDA's Animal Plant Health Inspection Service (USDA 2000i). Data for beef feedlots were also
obtained from EPA's Office of Water (ERG 2000a; EPA 2001a, 2001b). Manure management system usage data
for other livestock were taken from previous 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, 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 2004), and the county population data were calculated from state-
level population data from NASS and county-state distribution data from the 1992 and 1997 Census data (USDA
1999e). County population distribution data for 1990 and 1991 were assumed to be the same as 1992; county
1 Total Kjeldahl nitrogen is a measure of organically bound nitrogen and ammonia nitrogen.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 203
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population distribution data for 1998 through 2003 were assumed to be the same as 1997; and county population
distribution data for 1993 through 1996 were extrapolated based on 1992 and 1997 data.
The maximum CH4 producing capacity of the volatile solids, or B0, was determined based on data collected in a
literature review (ERG 2000b). B0 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
(ASAE 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 Lieberman et al. (2004) 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
An analysis was conducted for the manure management emission estimates presented in EPA (2003) to determine
the uncertainty associated with estimating N2O and CH4 emissions from livestock manure management. Because no
substantial modifications were made to the inventory methodology since the development of these estimates, it is
expected that this analysis is applicable to the uncertainty associated with the current manure management emission
estimates.
The EPA (2003) quantitative uncertainty analysis for this source category was performed through the IPCC-
recommended Tier 2 uncertainty estimation methodology, Monte Carlo Stochastic Simulation technique. The
uncertainty analysis was developed based on the methods used to estimate N2O and CH4 emissions from manure
management systems. A normal probability distribution was assumed for each source data category. The series of
equations used were condensed into a single equation for each animal type and state. The equations for each animal
group contained four to five variables around which the uncertainty analysis was performed for each state.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 6-8. Manure management CH4
emissions in 2003 were estimated to be between 32.1 and 47.0 Tg CO2 Eq. at a 95 percent confidence level (or 19 of
20 Monte Carlo Stochastic Simulations). This indicates a range of 18 percent below to 20 percent above the 2003
emission estimate of 39.1 Tg CO2 Eq. At the 95 percent confidence level, N2O emissions were estimated to be
between 14.7 and 21.7 Tg CO2 Eq. (or approximately 16 percent below and 24 percent above the 2003 emission
estimate of 17.5 Tg CO2 Eq.).
Table 6-8: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Manure Management (Tg
CO2 Eq. and Percent)
2003 Emission
Source Gas Estimate
(TgC02Eq.)
Manure Management CH4 39.1
Manure Management N2O 17.5
Uncertainty Range Relative to Emission
Estimate"
(TgC02Eq.) (%)
Lower
Bound
32.1
14.7
Upper
Bound
47.0
21.7
Lower
Bound
-18%
-16%
Upper
Bound
+20%
+24%
aRange of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
The primary factors that contribute 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
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 204
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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, a 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 this 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.
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.
Uncertainty also exists with the maximum CH4 producing potential of volatile solids excreted by different animal
groups (i.e., B0). The B0 values used in the CH4 calculations are published values for U.S. animal waste. However,
there are several studies that provide a range of B0 values for certain animals, including dairy and swine. The B0
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 B0 values are sparse, and do not necessarily reflect the rapid changes that have occurred in this
industry with respect to feed regimens.
QA/QC and Verification
Tier 1 and Tier 2 QA/QC activities were conducted consistent with the U.S. QA/QC plan. Tier 2 activities focused
on comparing estimates for the 2002 and 2003 Inventories for N2O emissions from managed systems and CH4
emissions from livestock manure. All errors identified were corrected. Order of magnitude checks were also
conducted, and corrections made where needed. Manure nitrogen data were quality assured by comparing state-level
data with bottom up estimates derived at the county level and summed to the state level. Similarly, a comparison
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 205
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was made by animal and waste management system type for the full time series, between national level estimates for
nitrogen excreted and the sum of county estimates for the full time series. Efforts also continue to transition various
components of the manure management inventory into a database to facilitate current and future QA checks.
Recalculations Discussion
No changes have been incorporated into the overall methodology for the manure management emission estimates;
however, changes were made to the calculation of CH4 emissions from sheep, goats, and horses. Changes were also
made to address errors and updates in the population and waste management system data from previous inventory
submittals. Additionally the population distribution of horses and poultry were adjusted, the typical animal mass for
sheep was adjusted, and the temperature estimations were changed to reflect a refined methodology. Each of these
changes is described in detail below.
• Methane emission estimation from sheep, goats, and horses. The sheep, goats, and horses emission
methodologies were changed to be consistent with the methodologies used for the other animal groups.
Previously, the sheep, goat, and horse methane estimates were scaled based on population data and earlier
estimates of methane emissions (EPA 1992).
• Population. All USDA data from 1998 through the present year underwent review pursuant to USDA
NASS annual review procedures. The population data in these years reflect some adjustments due to this
review. For horses, state-level populations were estimated using the national FAO population data and the
state distributions from the 1992 and 1997 Census of Agriculture. For poultry, populations for states
reporting non-disclosed populations were estimated by distributing population values attributed to "other"
states.
• Waste management system. The waste management system data for poultry were adjusted based on more
recent data. Previously, layers were estimated to be 99 percent managed (EPA 1992). More recent WMS
data available from USDA's Animal Plant and Health Inspection Service Layers 99 study (USDA 2000i)
and the United Egg Producers Study (UEP 1999) indicate that layers are 100 percent managed. Therefore,
the layer WMS estimates have been updated accordingly. Also, the waste management system distribution
for dairy cows was adjusted to correct rounding errors.
• Typical animal mass. The typical animal mass for sheep were reevaluated and adjusted. Typical animal
mass of sheep was adjusted from 27 kg to 68.6 kg (see Annex 3.10 for details).
• Temperature data: Temperature data are not available for every county with animal populations.
Previously, counties without temperature data were not accounted for in the estimate of average weighted
temperature. This methodology was changed to use the state average temperature for counties without
temperature data available.
The combination of these changes resulted in an average annual increase of 0.1 Tg CO2 Eq. (0.3 percent) in CH4
emissions and an average annual increase of 0.1 Tg CO2 Eq. (0.4 percent) in N2O emissions from manure
management for the period 1990 through 2002.
Planned Improvements
Currently, temperate zone MCFs are used for non-liquid waste management systems, including pasture, range, and
paddock, daily spread, solid storage, and drylot operations. However, there are some states that have an annual
average temperature that would fall below 15°C (i.e., "cool"). Therefore, CH4 emissions from certain non-liquid
waste management systems may be overestimated; however, the difference is expected to be relatively small due to
the low MCFs for all "dry" management systems. The use of both cool and temperate MCFs for non-liquid waste
management systems will be investigated for future inventories.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 206
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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.
The American Society of Agricultural Engineers is publishing new standards for manure production characteristics
in 2004. These data will be investigated and evaluated for incorporation into future estimates.
The development of the National Ammonia Emissions Inventory for the United States (EPA 2004) used similar data
sources to the current estimates of emissions from manure management, and through the course of development of
the ammonia inventory, updated waste management distribution data were identified. Future estimates will attempt
to reflect these updated data.
The methodology to calculate MCFs for liquid systems will be examined to determine how to account for a
maximum temperature in the liquid systems. Additionally, available research will be investigated to develop a
relationship between ambient air temperature and temperature in liquid waste management systems in order to
improve that relationship in the MCF methodology.
Research will be initiated into the estimation and validation of the maximum CH4-producmg capacity of animal
manure (B0), for the purpose of obtaining more accurate data to develop emission estimates.
The 2002 Census of Agriculture became available in mid-2004. These data will be used to update assumptions that
previously relied on the 1992 and 1997 Census of Agriculture.
6.3. Rice Cultivation (IPCC Source Category 4C)
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 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, seeding and
weeding practices). The factors that determine the amount of organic material that is available to decompose (i.e.,
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 207
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organic fertilizer use, soil type, rice variety,2 and cultivation practices) are the most important variables influencing
the amount of CH4 emitted over an entire growing season because the total amount of CH4 released depends
primarily on the amount of organic substrate available. Soil temperature is known to be an important factor
regulating the activity of methanogenic bacteria, and therefore the rate of CH4 production. However, although
temperature controls the amount of time it takes to convert a given amount of organic material to CH4, that time is
short relative to a growing season, so the dependence of total emissions over an entire growing season on soil
temperature is weak. The application of synthetic fertilizers has also been found to influence CH4 emissions; in
particular, both nitrate and sulfate fertilizers (e.g., ammonium nitrate, and ammonium sulfate) appear to inhibit CH4
formation.
Rice is cultivated in eight states: Arkansas, California, Florida, Louisiana, Mississippi, Missouri, Oklahoma, 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. Methane emissions from ratoon crops have been found to be considerably higher than those from the
primary 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.
Rice cultivation is a small source of CH4 in the United States (Table 6-9 and Table 6-10). In 2003, CH4 emissions
from rice cultivation were 6.9 Tg CO2 Eq. (328 Gg). Although annual emissions fluctuated unevenly between the
years 1990 and 2003, ranging from an annual decrease of 11 percent to an annual increase of 17 percent, there was
an overall decrease of 3 percent over the thirteen-year penod, due to an overall decrease in ratoon crop 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. Pnce is the primary factor affecting nee 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 by affecting the price received for a rice crop (Slaton 200Ib, Mayhew
1997). California rice area is primarily influenced by price and government programs, but is also affected by water
availability (Mutters 2001). In Florida, rice acreage is largely a function of the price of rice relative to sugarcane
and corn. Most rice in Florida is rotated with sugarcane, but sometimes it is more profitable for farmers to follow
their sugarcane crop with sweet corn or more sugarcane instead of rice (Schueneman 1997, 2001b). In Louisiana,
rice area is influenced by government support programs, the price of rice relative to cotton, soybeans, and corn, and
in some years, weather (Saichuk 1997, Linscombe 200Ib). For example, a drought in 2000 caused extensive
saltwater intrusion along the Gulf Coast, making over 32,000 hectares unplantable. The dramatic decrease in
ratooned area in Louisiana in 2002 was the result of hurricane damage to that state's rice-cropped area. 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 Oklahoma, the state having the smallest harvested rice area, rice acreage is limited to the areas in the state with
the right type of land for rice cultivation. Acreage is limited to growers who can afford the equipment, labor, and
land for this intensive crop (Lee 2003). Texas rice area is affected mainly by the price of rice, government support
programs, and water availability (Klosterboer 1997, 2001b).
Table 6-9: CH4 Emissions from Rice Cultivation (Tg CO2Eq.)
2 The roots office 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.
J The 11 percent decrease occurred between 1992 and 1993; the 17 percent increase happened between 1993 and 1994.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 208
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State
1990
1997
1998 1999 2000 2001
2002 2003
Primary
Arkansas
California
Florida
Louisiana
Mississippi
Missouri
Oklahoma
Texas
Ratoon
Arkansas
Florida
Louisiana
Texas
Total
5.1 "";,, '.
2.1 :,Y;
0.7 ;•(;$,
+ ","'', ";
1.0 =.Y;
o 4 :tf\
o i %;.;
+ ;,'--.'*}
0.6 :<••;
2.1 '!,;,';-,
+ '«'-""
+ ."''•', X
1 1 ",,;•
0 9 :"" "
l.l\lift<
5.6
2.5
0.9
+
1.0
0.4
0.2
+
0.5
1.9
+
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
NA
0.4
2.0
+
0.1
1.3
0.7
7.5
5.9
2.9
0.8
+
1.0
0.5
0.4
+
0.4
1.7
+
+
1.1
0.6
7.6
5.7
2.7
0.9
+
1.0
0.5
0.3
+
0.4
1.1
+
+
0.5
0.5
6.8
5.4
2.6
0.9
+
0.8
0.4
0.3
+
0.3
1.5
+
+
1.0
0.5
6.9
+ Less than 0.05 Tg CO2 Eq.
NA (Not Available)
Note: Totals may not sum due to independent rounding.
Table 6-10: CH4 Emissions from Rice Cultivation (Gg CH4)
State
Primary
Arkansas
California
Florida
Louisiana
Mississippi
Missouri
Oklahoma
Texas
Ratoon
Arkansas
Florida
Louisiana
Texas
Total
1990
241
102
34
1
46
21
7
30
98
+
2
52
45
339
'£•:"• 1997
265
118
'$'•• 44
, K 2
50
20
•K) 10
22
*' •»" 91
»'i *1ji
*':' ' '"', 3
55
;::' ' 33
^ 356
1998
279
126
39
2
53
23
12
24
98
+
3
59
36
376
1999
300
138
43
2
52
27
16
22
95
+
4
58
33
395
2000
260
120
47
2
41
19
14
NA
18
97
+
2
61
34
357
2001
283
138
40
1
46
22
18
18
81
+
2
52
27
364
2002
274
128
45
1
45
22
15
18
52
+
2
25
24
325
2003
255
124
43
1
38
20
15
15
73
+
2
50
22
328
+ Less than 0.5 Gg
NA (Not Available)
Note: Totals may not sum due to independent rounding.
Methodology
The Revised 1996IPCC 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 U. S.-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 approach is
consistent with IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas
Inventories (IPCC 2000).
The harvested rice areas for the primary and ratoon crops in each state are presented in Table 6-11. Primary crop
areas for 1990 through 2003 for all states except Florida and Oklahoma were taken from U.S. Department of
Agriculture's Field Crops Final Estimates 1987-1992 (USDA 1994), Field Crops Final Estimates 1992-1997
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 209
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(USDA 1998), Crop Production 2000 Summary (USDA 2001), Crop Production 2001 Summary (USDA 2002),
Crop Production 2002 Summary (USDA 2003), and Crop Production 2003 Summary (USDA 2004). Harvested
rice areas in Florida, which are not reported by USDA, were obtained from Tom Schueneman (1999b, 1999c, 2000,
2001 a) and Arthur Kirstein (2003), Florida agricultural extension agents, Dr. Chris Deren (2002) of the Everglades
Research and Education Centre at the University of Florida, and Gaston Cantens (2004), Vice President of
Corporate Relations of the Florida Crystals Company. Harvested rice areas for Oklahoma, which also are not
reported by USDA, were obtained from Danny Lee of the Oklahoma Farm Services Agency (Lee 2003, 2004).
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), about 60 percent of the primary area in 2001 (Deren
2002), about 54 percent of the primary area in 2002 (Kirstein 2003) and about 100 percent of the primary area in
2003 (Kirsetm 2004). In Louisiana, the percentage of the primary area that was ratooned was constant at 30 percent
over the 1990 to 1999 period, increased to approximately 40 percent in 2000, returned to 30 percent in 2001,
dropped to 15 percent in 2002, and rose to 35 percent in 2003 (Lmscombe 1999a, 200la, 2002, 2003, 2004 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; it then
decreased to 40 percent in 2001, 37 percent in 2002, and 38 percent in 2003 (Klosterboer 1999, 2000, 2001a, 2002,
2003, Stansel 2004).
Table 6-11: Rice Areas Harvested (Hectares)
State/Crop
1990
1997
1998
1999
2000
2001
2002
2003
Arkansas
Primary
Ratoon*
California
Florida
Primary
Ratoon
Louisiana
Primary
Ratoon
Mississippi
Missouri
Oklahoma
Texas
Primary
Ratoon
485,633 ;
NO;
159,854;
4,978 ;
2,489 ;
220,558 ;
66,168;
101,174;
32,376 :
en:
142,857 :
57,143;
,
562,525
NO
208,822
7,689
3,845
235,937
70,781
96,317
47,349
12
104,816
41,926
600,971
202
185,350
8,094
4,047
250,911
75,273
108,458
57,871
19
114,529
45,811
657,628 570,619 656,010 608,256 588,830
202 NO NO NO NO
204,371 221,773 190,611 213,679 205,180
7,229 7,801 4,562 5,077 2,315
4,673 3,193 2,752 2,734 2,315
249,292 194,253 220,963 216,512 182,113
74,788 77,701 66,289 32,477 63,739
130,716 88,223 102,388 102,388 94,699
74,464 68,393 83,772 73,654 69,203
220 NA 265 274 53
104,816 86,605 87,414 83,367 72,845
41,926 43,302 34,966 30,846 27,681
Total
Primary
1,148,04?: . 1,263,468 1,326,203 1,428,736 1,237,668 1,345,984 1,303,206 1,215,237
Total Ratoon 125,799
116,552 125,334 121,589 124,197 104,006 66,056 93,735
Total
1,273,847 \, 1,380,020 1,451,536 1,550,325 1,361,864 1,449,991 1,369,262 1,308,972
* Arkansas ratooning occurred only in 1998 and 1999.
NO (Not Occurring)
NA (Not Available)
Note: Totals may not sum due to independent rounding.
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 atypical
or nonrepresenative management practices (e.g., the application of nitrate or sulfate fertilizers, or other substances
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 210
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believed to suppress CH4 formation), as well as experiments in which measurements were not made over an entire
flooding season or floodwaters were drained mid-season, were excluded from the analysis. The remaining
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 added synthetic and organic fertilizer (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 added synthetic fertilizer (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 inherent variability is due to differences in cultivation practices, in particular, fertilizer type,
amount, and mode of application; differences in cultivar type; and differences in soil and climatic conditions. A
portion of this variability is accounted for by separating primary from ratooned areas. However, even within a
cropping season or a given management regime, measured emissions may vary significantly. Of the experiments
used to derive the emission factors applied 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. From these ranges, an uncertainty for the
emission factors of 109 percent for primary crops and 65 percent for ratoon was calculated. In order to perform a
Tier 2 Monte Carlo uncertainty analysis, some information regarding the statistical distribution of the uncertainty is
required. Variability about the rice emission factor means were not normally distributed for either primary or
ratooned crops, but rather skewed, with a tail trailing to the right of the mean, therefore a lognormal-type statistical
distribution was applied. The bounds of the distribution were set at 0 (indicating that CH4 absorption was unlikely
given this management system) and three times the emission factor.
Uncertainty regarding primary cropping area is an additional consideration. Uncertainty associated with primary
rice-cropped area for each state was obtained from expert judgment, and ranged from 1 percent to 5 percent of the
mean area. A triangular distribution of uncertainty was assumed about the mean for areas, which was bounded at
half and one and a half times the estimated area.
Another source of uncertainty lies in the ratooned areas, which are not compiled regularly. Ratooning accounts for
less than 8 percent of the total rice-cropped area, though it is responsible for a proportionately larger portion of
emissions. Based on expert judgment, the uncertainty associated with ratooned areas is between 1 percent and 5
percent. A triangular distribution of uncertainty was assumed, and bound at half and one and a half times the
estimated proportion of ratooned area.
A final source of uncertainty is in the practice of flooding outside of the normal rice season. According to
agricultural 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, however, CH4 flux measurements have not been undertaken over a sufficient geographic range or under
representative conditions to account for this source or its associated uncertainty adequate for inclusion in the
emission estimates or uncertainty evaluations presented here.
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/mVday 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).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 211
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To quantify the uncertainties for emissions from rice cultivation, a Monte Carlo (Tier 2) uncertainty analysis was
performed using the information provided above. The results of the Tier 2 quantitative uncertainty analysis are
summarized in Table 6-12. Rice cultivation CH4 emissions in 2003 were estimated to be between 2.9 and 13.9 Tg
CO2 Eq. at a 95 percent confidence level (or 19 of 20 Monte Carlo Stochastic Simulations). This indicates a range
of 58 percent below to 101 percent above the 2003 emission estimate of 6.9 Tg CO2 Eq.
Table 6-12: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Rice Cultivation (Tg CO2 Eq. and
Percent)
Source
Rice Cultivation
Gas
CH4
2003 Emission
Estimate
(Tg C02 Eq.)
6.9
Uncertainty Range Relative to Emission
(Tg C02 Eq.)
Lower
2.
Bound Upper Bound
9 13.9
Lower Bound
-58%
Estimate"
(%)
Upper Bound
+101%
aRange of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Planned Improvements
In performing a Monte Carlo-type uncertainty analysis, a higher level Tier 2 type emission mean is calculated
incidentally. One would expect there to be a difference in the emission means calculated by these different
methods, because under the IPCC default Tier 2 method used here to estimate CH4 emissions, the statistical
distribution of all parameters (i.e., activity data and emission factors) is implicitly considered to be normal. As
described above, that is not the case with the uncertainty analysis, which allows for several asymmetrical statistical
distributions. Here, the lower and upper bounds have been reported, directly from the Monte Carlo analysis.
However, the percentages for the upper and lower bounds of the range have been calculated based on the reported
emission mean rather than that mean calculated by the Monte Carlo software (as is the case with all reported Tier 2
analyses). Because that mean may represent an improvement to the current Tier 2 methodology, including the
higher level Tier 2 estimate in future inventories is being investigated.
6.4. Agricultural Soil Management (IPCC Source Category 4D)
Nitrous oxide is produced naturally in soils through the microbial processes of nitrification and denitrification.5 A
number of agricultural activities add nitrogen (N) to soils, thereby increasing the amount available for nitrification
and denitrification, and ultimately the amount of nitrous oxide (N2O) emitted. These activities may add N to soils
either directly or indirectly (see Figure 6-2). Direct additions occur through various soil management practices and
from the deposition of manure on soils by animals on pasture, range, and paddock (PRP) (i.e., by animals whose
manure is not managed). Soil management practices that add N to soils include fertilizer use, application of
managed livestock manure and sewage sludge, production of N-fixing crops and forages, retention of crop residues,
and cultivation of histosols (i.e., soils with a high organic matter content, otherwise known as organic soils).6 Only
direct emissions from agricultural lands (i.e., croplands and grasslands), along with emissions from PRP manure are
included in this section. The direct emissions from forest lands and settlements are presented within the LUCF
sector. Indirect nitrous oxide emissions from all land use types resulting from N additions to croplands, grasslands,
forestlands, and settlements are also included in this section. These indirect emissions occur through two
5 Nitrification and denitrification are two processes within the N 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 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" N to soils. Instead, the process of cultivation enhances mineralization ofN-rich
organic matter that is present in histosols, thereby enhancing N2O emissions from histosols.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 212
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mechanisms: 1) volatilization and subsequent atmospheric deposition of applied N;7 and 2) surface runoff and
leaching of applied N into groundwater and surface water. Other agricultural soil management activities, 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 and are partially accounted for in the analysis.
Figure 6-2: Direct N2O Emissions Pathways from Cropland and Grassland Soils, and Indirect N2O Emissions
Pathways from All Sources.
Agricultural soils are responsible for the majority of U.S. N2O emissions. Estimated emissions from this source in
2003 were 253.5 Tg CO2 Eq. (818 Gg N2O) (see Table 6-13 and Table 6-14). Annual agricultural soil management
N2O emissions fluctuated between 1990 and 2003; however, overall emissions were 0.2% greater in 2003 than in
1990. Year-to-year fluctuations are largely a reflection of annual variations in climate, synthetic fertilizer
consumption, and crop production.
Table 6-13: N2O Emissions from Agricultural Soils (Tg CO2 Eq.)
1990
Direct
Agricultural Soils
Pasture, Range & Paddock Livestock
Manure
Indirect (All Land Use Types)*
Total
140
100
40
112
253
.4
.1
.2
.6
.0
1997
155.9
113.6
42.2
96.2
252.0
1998
158.6
116.5
42.1
109.1
267.7
1999
151.1
111.0
40.1
92.3
243.4
2000
156.3
116.4
39.8
107.6
263.9
2001
154.5
113.0
41.5
102.6
257.1
2002
159.9
118.5
41.4
92.7
252.6
2003
155.3
114.8
40.5
98.2
253.5
Note: Totals may not sum due to independent rounding.
"Includes cropland, grassland, forest land and settlements.
Table 6-14: N2O Emissions from Agricultural Soils
Direct
Agricultural Soils
Pasture, Range & Paddock Livestock
Manure
Indirect (All Land Use Types)*
Total
1990
453
323
130
363
816
1997
503
367
136
310
813
1998
512
376
136
352
864
1999
487
358
129
298
785
2000
504
376
129
347
851
2001
498
365
134
331
829
2002
516
382
134
299
815
2003
501
370
131
317
818
Note: Totals may not sum due to independent rounding.
"Includes cropland, grassland, forest land and settlements.
Estimated direct and indirect N2O emissions by sub-source category are provided in Table 6-15, Table 6-16, and
Table 6-17.
Table 6-15: Direct N2O Emissions from Agricultural Soils (Tg CO2 Eq.)
Activity
1990;
1997 1998 1999 2000 2001 2002 2003
Mineral
Histosol
Agricultural
Cultivation
Soils
97.3- t,f
2.8 -K
; no
2
.8
.9
113.7
2.9
108.2
2.9
113.6
2.9
110.1
2.9
115.6
2.9
111.9
2.9
7 These processes entail volatilization of applied N as ammonia (NH3) and oxides of N (NOX), transformations of these gases
within the atmosphere (or upon deposition), and deposition of the N primarily in the form of particulate ammonium (NHt), nitric
acid (HNO3), and oxides of N.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 213
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Pasture, Range & Paddock Livestock 'V.'.M
Manure 40 2 v^ 42.2 42.1 40.1 39.8 41.5 41.4 40.5
Total 140.4 ^M 155.9 158.6 151.1 156.3 154.5 159.9 155.3
Note: Totals may not sum due to independent rounding. Excludes sewage sludge and livestock manure used as commercial
fertilizers.
Table 6-16: Direct N2O Emissions from PRP Livestock Manure (Tg CO2 Eq.)
Animal Type
Beef Cattle
Dairy Cows
Swine
Sheep
Goats
Poultry
Horses
Total
1990!
34.
1.
0,
0.
0,
0.
2.
40,
.91
,9|
.5!
.4!
.2!
.11
2!
.2!
! 1997
1 37
1 1
1 0
! o
1 o
! o
! 2
! 42
.8
.4
,2
.3
,2
.1
.3
.2
1998
37.
1.
0,
0.
0,
0.
2.
42.
6
4
2
3
2
1
3
1
1999
35.7
1.3
0,2
0.3
0,2
0.1
2.3
40.1
2000
35.5
1.3
0,2
0.3
0,2
0.1
2.3
39.8
2001
37.1
1.3
0,2
0.3
0,2
0.1
2.3
41.5
2002
37.0
1.3
0,2
0.2
0,2
0.1
2.3
41.4
2003
36.1
1.3
0,2
0.2
0,2
0.1
2.3
40.5
Table 6-17: Indirect N2O Emissions from all Land Use Types* (Tg CO2 Eq.)
1990
Volatilization and Atm. Deposition 15.6
Surface Leaching & Run-Off 97 . 1
Total 112.6
! 1997
| 16.5
I 79.6
! 96.2
1998
16.4
92.7
109.1
1999
16.4
75.9
92.3
2000
16.8
90.8
107.6
2001
16.4
86.3
102.6
2002
16.6
76.1
92.7
2003
16.5
81.8
98.2
Note: Totals may not sum due to independent rounding.
"Includes cropland, grassland, forest land and settlements.
Methodology
The methodology used to estimate emissions from agricultural soil management is consistent with the Tier 3
approach of 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) and Good
Practice Guidance for Land Use, Land-Use Change and Forestry (IPCC 2003). Current methods divide this N2O
source category into three components: 1) direct emissions from managed soils due to applied N and the cultivation
of histosols; 2) direct emissions from soils due to the deposition of manure by livestock on PRP lands; and 3)
indirect emissions from soils or water induced by additions of fertilizers, sewage sludge, and livestock manure (both
managed and unmanaged) to soils of all land use types.
Annex 3.11 provides more detailed information on the methodologies and data used to calculate N2O emissions
from each of the components.
The methodology applied in this Inventory is a hybrid approach for estimating N2O emissions from mineral
agricultural soils. This involves using the process-based model DAYCENT to estimate emissions from major crops
on mineral (i.e., non-histosol) soils, and the IPCC methodology for non-major crops on mineral soils, PRP manure,
as well as all emissions from histosols.
Direct N2O Emissions from Mineral Agricultural Soils
Different methodologies were used in quantifying direct N2O emissions from mineral agricultural soils with major
crop types and those with non-major crop types as described below.
Major Crop Types
The DAYCENT ecosystem model (Del Grosso et al. 2001, Parton et al. 1998) was used to estimate direct soil N2O
emissions from mineral agricultural soils cropped with major crop types. DAYCENT has been parameterized to
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 214
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simulate most of the major cropping systems (corn, soybean, wheat, alfalfa hay, other hay, sorghum, and cotton) in
the United States. These cropping systems simulated by DAYCENT represent approximately 90 percent of total
cropped land in the United States. DAYCENT simulates crop growth, soil organic matter decomposition,
greenhouse gas fluxes, N deposited by grazing animals, and other biogeochemical processes using daily climate
data, land management information, and soil physical properties as model inputs. The scale of DAYCENT
simulations is dictated by the scale of available input data. Soil and climate inputs were available for every county
with more than 100 acres of agricultural land. Therefore, a single parameter value (e.g., maximum temperature for a
particular day) is applied at the county-level for those variables. Land management data (e.g., timing of planting,
harvesting, applying fertilizer, intensity of cultivation, rate of fertilizer application) were available at the agricultural
region level as defined by the Agricultural Sector Model (McCarl el al. 1993). There are 63 regions in the
contiguous United States; most states correspond to one region, except for states that are divided into two or more
regions if there is sufficient variability in cropping practices within the state. Although various cropping systems
were simulated for each county, the parameters controlling management activities (e.g., when crops were
planted/harvested, amount of fertilizer added), did not change within an agncultural region.
Nitrous oxide emissions estimated by DAYCENT account for N additions, crop type, irrigation, and other factors.
However, because DAYCENT is a process-based model that simulates the N cycle, N2O emissions cannot be
partitioned into the contribution of N2O from different N inputs (e.g., N2O emissions from synthetic fertilizer
applications cannot be distinguished from those emissions resulting from manure applications). Therefore, it was
not possible to separate out these individual contributors to N2O flux, as is suggested in the IPCC Guidelines.
In addition to simulating N2O emissions from mineral agricultural soils cropped with major crop types, a
DAYCENT simulation was performed of those same areas as though they were covered by native vegetation, so
that anthropogenic emissions could be isolated from natural background emissions. Emissions from managed
agricultural lands are the result of complex and interactive processes, practices, and inputs arising from
anthropogenic intervention. Because removing inputs alone would not reflect the full anthropogenic greenhouse
gas signature, managed soil emissions have been compared to those soils under native vegetation as a means of
identifying the anthropogenic contribution. The reported estimates of emissions from managed soils therefore
represent the difference between simulated emissions from native vegetation and emissions from cropland soils.
Estimates of direct N2O emissions from N applications were based on the total amount of N applied to soils
annually through the following practices: 1) the application of synthetic and organic commercial fertilizers, 2) 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, 3) the application of sewage sludge, 4) the production
of N-fixing crops and forages, and 5) the retention of crop residues (i.e., leaving residues in the field after harvest).
For each of these practices, annual N applications were obtained from the following sources:
• Crop-specific N-fertilization rates: Alexander and Smith (1990), Anonymous (1924), Battaglin and
Goolsby (1994), Engle and Makela (1947), ERS (1994, 2003), Fraps and Asbury (1931), Ibach and Adams
(1967), Ibach et al. (1964), NFA (1946), NRIAI (2003), Ross and Mehnng (1938), Skinner (1931),
Smalley et al. (1939), Taylor (1994), USDA (1966, 1957, 1954, 1946).
• 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 Safely
(2000), USDA (1996, 1998d), and ASAE (1999); daily rates of N excretion from ASAE (1999) and USDA
(1996). Comparisons of estimates of managed manure production (i.e. non-PRP manure) with estimates of
the amount of manure actually consumed by soils showed that manure consumed by soils accounted for
approximately one-third of managed manure production). Values for manure consumption (Kellogg et al.
2000; Edmonds et al. 2003) were subtracted from values of managed manure production. Only consumed
manure N was applied to agricultural soils. The remainder was assumed to have volatized during storage
and transport. In contrast to the IPCC methodology that only considers volatilization of manure that was
applied to soils, the manure that was assumed to volatilize during transport and storage was included in the
volatilization component of indirect N2O emissions. Instead of assuming that 10 percent of synthetic and
20 percent of organic N applied to soils is volatilized and 30 percent of applied N was leached/runoff as
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with IPCC methodology, volatilization and N leaching/runoff were internally calculated by the process-
based model.
• Sewage sludge: Bastian (2002); USDA (1998a); EPA (1993, 1999); Metcalf and Eddy (1991).
• Nitrogen-fixing crops and forages and retention of crop residue. Using the IPCC approach, these are
considered activity data. However, when using DAYCENT, they should not be considered activity data
because they are internally generated by the model. In other words, DAYCENT accounts for the influence
of N fixation and retention of crop residue on N2O emissions, but these are not model inputs.
• Historical and modern crop rotation and management information (e.g., timing and type of cultivation,
timing of planting/harvest, etc.): Hurd (1930, 1929), Latta (1938), Iowa State College Staff Members
(1946), Bogue (1963), Hurt (1994), USDA (2004), USDA (2000h), as extracted by Eve (2001), and
revised by Ogle (2002), CTIC (1998), Piper et al. (1924), Hardies and Hume (1927), Holmes (1902, 1929),
Spillman(1902, 1905, 1907, 1908), Chilcott (1910), Smith (1911), Kezerca. (1917), Hargreaves (1993),
ERS (2002), Warren (1911), Langtson et al. (1922), Russell et al. (1922), Elliot and Tapp (1928), Elliot
(1933), Ellsworth (1929), Garey (1929), Holmes (1929), Hodges et al. (1930), Bonnen and Elliot (1931),
Brenner et al. (2002, 2001), Smith et al. (2002).
Applied N was subject to volatilization and leaching/runoff according to the climatic conditions, soil type and
condition, crop type, and land management practices such as cultivation and irrigation, as simulated by DAYCENT.
These amounts were then applied in the calculation of indirect emissions as described below. The remaining
applied soil N was then added to the applied N from N-fixing crops and crop residues to yield total soil N additions
for the DAYCENT simulation of direct N2O emissions from soils cropped with major crop types. Because the
model is sensitive to actual interannual variability in those factors to which N2O emissions are sensitive (e.g.,
climate), emissions vary through time rather than demonstrate a linear, monotomc response.
Non-Major Crop Types
For lands cropped with non-major crop types, the IPCC emission factor methodology was used to estimate N2O
emissions from mineral agricultural soils, as described below.
Estimates of direct N2O emissions from N applications to non-major crop types were based on the amount of N
applied to soils annually through the following practices: 1) the application of synthetic commercial fertilizers, 2)
the production of N-fixing crops and forages, and 3) the retention of crop residues. No organics were considered
here because 100 percent of these were assumed to be applied to crops simulated by DAYCENT. This assumption is
reasonable because DAYCENT simulated the 6 major cropping systems (corn, hay, pasture, sorghum, soybean,
wheat) that receive the vast majority (approximately 95 percent) of manure applications (Kellogg et al. 2000,
Edmonds et al. 2003).
Yearly synthetic fertilizer N additions to non-major crop types were calculated by process of elimination. For each
year, fertilizer accounted for by the cropping systems simulated by DAYCENT (approximately 75 percent of the
U.S. total), fertilizer estimated to be applied to forests (less than 1 percent of the U.S. total), and fertilizer estimated
to be applied in settlements (approximately 10 percent of the U.S. total) were summed and subtracted from total
fertilizer used in the United States. This difference was assumed to be applied to non-major crop types and
accounted for approximately 15 percent of total N fertilizer used in the United States. Non-major crop types include
fruits, nuts, and vegetables, which account for approximately 5 percent of U.S. N fertilizer use (TFI 2000) and other
crops not simulated by DAYCENT (barley, oats, tobacco, sugar cane, sugar beets, sunflower, millet, peanuts, etc.)
which account for approximately 10 percent of total U.S. fertilizer use. The non-volatilized proportion was
obtained by reducing total applications by the default IPCC volatilization fraction (IPCC 1997, 2000). In addition
to synthetic fertilizer-N applied to non-major crop types, N in soils due to the cultivation of non-major N-fixing
crops (e.g., edible legumes) was included in these estimates. Finally, crop residue N retention was derived from
information about which residues are typically left on the field, the fractions that remain, annual crop production,
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 216
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mass ratios of aboveground residue to crop product, and dry matter fractions and N contents of the residues. For
each of these practices, annual N applications were obtained from the following sources:
• Mass ratios of aboveground residue to crop product, dry matter fractions, and N contents for N-fixing
crops: Strehler and Stutzle (1987), Barnard and Knstoferson (1985), Karkosh (2000), Ketzis (1999),
IPCC/UNEP/OECD/IEA (1997).
• Annual production statistics for crops whose residues are left on the field: USDA (1994a, 1998b, 2000i,
2001 a, 2002a, 2003a), Schueneman (1999, 2001), Deren (2002), Schueneman and Deren (2002), Cantens
(2004), Lee (2003, 2004).
• Aboveground residue to crop mass ratios, residue dry matter fractions, and residue N contents: Strehler and
Stutzle (1987), Turn et al. (1997), Ketzis (1999), Barnard and Knstoferson (1985), Karkosh (2000).
The net amount of N remaining on the soil from applied fertilizer was added to the N from N-fixing crops and crop
residues to yield total unvolatilized applied N, which was multiplied by the IPCC default emission factor to derive
an estimate of cropland N2O emissions from non-major crop types.
Total annual emissions from major crops and other crops were summed to obtain total emissions from cropped
mineral soils (see Table 6-13 and Table 6-14).
Direct N2O Emissions from Histosols
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. Histosol area was
obtained from the Natural Resources Inventory (USDA 2000h, as extracted by Eve 2001, and revised by Ogle
2002). 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.
Total Direct N2O Emissions from Nitrogen Applications to Agricultural Soils
Total annual N2O emissions from N applications to mineral agricultural soils and annual N2O emissions from
histosol cultivation were then summed to estimate total direct N2O emissions from agricultural soils.
Direct N2O Emissions from Pasture, Range, and Paddock Livestock Manure
As with N2O from major row crops, dual methodologies incorporating the process-based simulation model
DAYCENT and IPCC methods were applied in tandem to estimate total emissions from PRP manure. For
DAYCENT simulations, annual county-level pasture area data were not available so county-level pasture area
estimates from Kellogg et al. (2000) and Edmonds et al. (2003) were used. DAYCENT does not simulate paddocks
and no county level area data for rangeland were available so IPCC methodology was used to estimate emissions
from these sources. Because DAYCENT simulated only pastures and not paddocks or rangeland, the amount of
manure accounted for by DAYCENT (manure N added to soil is an output variable in DAYCENT) was subtracted
from annual estimates of total PRP manure and assumed that this manure contributed to emissions from paddocks
and rangeland.
Estimates of N2O emissions from PRP livestock manure are based on the amount of N in the manure that is
deposited annually on soils by livestock on PRP. Estimates of annual manure N 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 N excretion rates for each animal type. The amount of manure N
from each animal type was summed over all animal types to yield total PRP manure N. Nitrous oxide emissions
resulting from manure deposited on pastures by livestock was simulated by DAYCENT in each county. The
emissions were obtained by multiplying DAYCENT emissions (in g N2O-N m"2) by the total reported pasture area
for each county, and summing across all counties to achieve a nationwide value. All of the manure accounted for by
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DAYCENT was assumed to come from cattle because DAYCENT has been parameterized to simulate cattle
manure, and cattle are responsible for approximately 90 percent of total PRP manure. The PRP manure N from
paddocks and rangeland not accounted for by DAYCENT in the pasture component was multiplied by the IPCC
default emission factor to estimate N2O emissions from paddock and rangeland manure deposition. Emissions from
the three types of PRP manure were summed to provide total national emissions from PRP manure in the United
States.
Indirect N2O Emissions from Managed Soils of All Land Use Types
This section describes the method for estimating indirect N2O emissions from managed soils of all land use types
(i.e., cropland, grassland, forest land and settlements). Indirect emissions of N2O are composed of two parts, which
are estimated separately and then summed. These parts are 1) emissions resulting from volatilization of non-N2O
gases (i.e., NOX and NH3) from synthetic fertilizer and manure additions to managed soils and from managed
manure during storage, treatment and transport that are subsequently deposited onto other areas and eventually
emitted to the atmosphere as N2O, and 2) leaching and runoff of N (in the form of NO3") from all soils where N
additions have been made that is eventually denitrified and emitted as N2O from a water body. Regardless of the
original source or eventual land use type where these indirect N2O emissions actually occur, all indirect N2O
emissions are accounted for in this section of the Inventory.
A mix of approaches was used to obtain the necessary information required to estimate indirect N2O emissions.
While DAYCENT simulates NOX and NH3 volatilization as well as NO3 leaching/runoff, it does not model their
transport or subsequent off-site conversion to N2O. Therefore, DAYCENT was used to simulate N volatilization
and leaching/runoff losses for major crop types. Volatilized and leached/runoff N from non-major crops,
settlements and forest lands were obtained by applying the IPCC default fractions to total fertilizer applications to
those crops and/or land areas. The volatilization and leaching/runoff components of indirect emissions for PRP
manure were obtained by using a combination of DAYCENT generated outputs for manure deposited on
pasturelands and applying IPCC defaults to manure deposited on paddocks and rangelands. Manure from managed
systems assumed to be volatilized during storage, treatment and transport was included in the indirect emission
calculations as well. In contrast to the IPCC approach that has been used in the past, DAYCENT simulations for
major crops, where all managed manure is assumed to be applied, do not assume that 100 percent of the N in
managed manure is available to be applied to soils. According to data in Kellogg et al. (2000) and Edmonds et al.
(2003), more than 50 percent of the N in managed manure is lost to volatilization, spillage and leaching/runoff
during storage, treatment and transport. Consequently, manure N applied to soils, based on data from Kellogg et al.
(2000) and Edmonds et al. (2003), is subtracted from total managed manure N and assumed to volatilize during
storage, treatment, and transport where it is then included in the volatilization component of indirect emissions.
Results from this mix of approaches described above were then summed for the appropriate indirect N2O emission
pathway as described below.
Voltilized Indirect Emissions
Volatilized N emissions for settlements, forest lands, PRP manure, major crops, non-major crops, and volatilized
managed manure prior to land application were summed. The IPCC default emission factor for indirect N2O was
applied to the total to give total indirect N2O emissions from N volatilization from soils of all land use types and
volatilized managed manure.
Leaching/Runoff Indirect Emissions
The amounts of leached/runoff N from settlements, forest lands, PRP manure, major and non-major crop types
were summed and multiplied by the IPCC default emission factor for leached/runoff N.
Total Indirect Emissions from Volatilization and Leaching/Runoff
Total indirect emissions from volatilization and from leaching/runoff were summed to estimate total indirect
emissions of N2O from croplands (Table 6-17).
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Uncertainty
The DAYCENT biogeochemical ecosystem model was used to calculate N2O emissions from major crop types.
There are two broad classes of uncertainty in such analyses: that inherent in the activity data and emission factors,
and structural uncertainty inherent to the model used to estimate emissions. Consistent with the United States'
uncertainty management plan, uncertainty inherent to the DAYCENT model was not quantified as part of
the IPCC Tier 1 approach described below.
Three types of approaches were taken for estimating different types of emissions in this chapter: 1) Direct
emissions calculated by DAYCENT; 2) Direct emissions not calculated by DAYCENT; and 3) Indirect emissions.
Uncertainty was estimated differently for each category.
For direct emissions calculated by DAYCENT (99.3 of the total direct 155.3 Tg CO2 Eq.), uncertainty in national
totals for N inputs and uncertainty in how N application rates change with crop type, year, and agricultural region
contribute to total uncertainty in the N application activity data. Total uncertainty in N inputs was estimated at 20
percent (Mosier 2004). Other activity data include climate data, for which uncertainty was estimated to be 19
percent, and soil type, which was estimated to have an uncertainty of 12 percent (Del Grosso 2005a). Their
combined uncertainty, according to the sum-of-squares method, is approximately 30.1 percent. To estimate the
uncertainty associated with the effective emission factor, DAYCENT outputs were compared with N2O
measurements from various cropped soils over the annual cycle (Del Grosso et al. in press). Through this method,
the uncertainty associated with the effective emission factor was estimated at 57 percent (Del Grosso 2005b).
Through the calculus of error propagation, overall uncertainty for direct emissions calculated by DAYCENT was 64
percent.
Direct N2O emissions not calculated by DAYCENT were assumed to maintain the 64 percent uncertainty.
Finally, indirect emissions were calculated according to the default IPCC methodology, as has been performed in
past Inventories. Consequently, the maximum uncertainty calculated for last year's indirect N2O emissions from
agricultural soil management of 286 percent (U.S. EPA 2004) was applied to conservatively address the uncertainty
in indirect emissions here.
The results of the Tier 1 quantitative uncertainty analysis are summarized in Table 6-18. Agricultural soil
management N2O emissions in 2003 were estimated to be between 45.2 and 461.8 Tg CO2 Eq. at a 95 percent
confidence level. This indicates a range of 82 percent above and below the 2003 emission estimate of 253.5 Tg
CO2 Eq.
Table 6-18: Tier 1 Quantitative Uncertainty Estimates of N2O Emissions from Agricultural Soil Management in
2003 (Tg CO2 Eq. and Percent)
Source
2003 Emission
Estimate
Gas (Tg C02 Eq.)
Uncertainty Range Relative to
Uncertainty Emission Estimate
(%) (TgC02Eq.)
Lower Bound Upper Bound
Agricultural Soil Management N2O 253.5 82% 45.2 461.8
Recalculations Discussion
Differences in the present report compared to previous years exist for two reasons: differences in sources and
differences in methodologies. In previous Inventories, fertilizer applied to forests and settlements were included in
the agricultural sector. For the current Inventory, for the direct emissions, these fertilizer additions were included in
the LUCF sector, and therefore approximately 15 percent less synthetic fertilizer is counted in the agricultural sector
than in previous Inventories. Also in previous Inventories, the default Tier 1 IPCC methodology was used to
estimate emissions from this sector. That methodology relied solely on N inputs, and did not account for effects of
climate, soil type, and other factors that influence N2O emissions. To account for some of these additional factors
and increase confidence in estimates, a Tier 3 method, the DAYCENT ecosystem model, was used to account for
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 219
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N2O emissions from major cropping systems. Overall, the changes resulted in an average annual decrease of 31.2
Tg CO2 Eq. (11 percent) in N2O emissions from agricultural soil management for the period 1990 through 2002.
The IPCC emission factor methodology is an example of a Tier 1 approach. This approach is activity driven, i.e.,
total N from different sources (e.g. synthetic fertilizer, manure, N fixation, etc.) is used to estimate N2O from these
sources. The Tier 3 approach in this case uses a process-based model (i.e., DAYCENT) and is area driven, i.e., it is
necessary to know the annual area of major crop types and the N amendment rates for each of these crops. With the
Tier 3 approach, emissions cannot be separated by N inputs because once N is in the plant/soil system, the model
does not distinguish its source according to IPCC categorizations (e.g., whether the N2O emitted was synthetic
fertilizer-derived or derived from manure). Because the Tier 3 approach was used for approximately 90 percent of
fertilized soils in the United States, N2O emissions are not partitioned into the IPCC's N-input categories, as has
been done in the past.
The Tier 3 approach requires some of the same activity data as the Tier 1 approach, plus additional information.
Like the Tier 1 approach, the Tier 3 approach requires national totals for N amendments, but it also requires data on
N amendment rates for different cropping systems. Consequently, the total amounts of N fertilizer and organic N
additions were identical to previous years but assumptions regarding the fate of these amendments are different. For
example, in previous years, 100 percent of managed manure was assumed to be applied to cropped soils, though
here approximately 64 percent of manure N was lost to volatilization during transport and storage before it was
applied to soil. This manure that was assumed to volatilize before soil application was included with indirect
emissions, which is different than previous years. In addition to N amendments, the Tier 3 approach requires area
data for different cropping systems. The Tier 3 approach distinguishes different cropping systems because crops
vary in growth rates, fertilization rates, biomass N concentration, and timing for planting, harvesting, and
cultivating. These crop system specific factors are important because they influence N availability in soil, which
controls N2O emissions.
An important difference between Tier 1 and Tier 3 approaches relates to assumptions regarding N cycling. Tier 1
assumes that N added to a system in one year completely cycles during that year; e.g., N added as fertilizer or
through fixation contributes to N2O emission for that year, but cannot be stored in soil or biomass and be recycled
and contribute to N2O emission in subsequent years. In contrast, the process-based models used in the Tier 3
approach include legacy effects such that N added to the system in one year may be taken up by vegetation and
returned to the soil in organic form during that year, then re-mineralized and emitted as N2O during subsequent
years. In addition to previous years' fertilizer additions, other long-term management practices that affect current
soil organic matter (SOM) levels (e.g., intensive cultivation, summer fallow) also affect current N2O emission,
because in process based models, N from internal cycling (mineralization of SOM) contributes to N2O emission.
Thus, while Tier 1 estimates are influenced only by the current year's N inputs, Tier 3 emissions are also influenced
by management in previous years.
Another difference in methodologies is that the Tier 1 method assumes that 10 percent of synthetic fertilizer and 20
percent of applied manure are volatilized, and 30 percent of applied N is leached or run-off. DAYCENT, however,
calculates N volatilization and N leached and run-off internally based on specific climatic, environmental, and
management conditions.
Consideration of N-fixation highlights another difference in the approaches. In the Tier 1 approach, a certain
portion of aboveground fixed N is assumed to be emitted as direct soil N2O. In the Tier 3 approach, N fixation is
calculated by the model and fixed N can be harvested, lost as N2O, lost in some other form (e.g., leached NO3), or
stored in the plant/soil system.
The Tier 1 approach also assumes that only N from fertilizer and organic matter additions contributes to indirect
N2O emissions whereas the Tier 3 approach assumes that once N is in the plant/soil system, it can be cycled and lost
thorough various pathways, regardless of its source. Similar to N fixation, N deposited on soil by pasture and range
animals and N added to soils from crop residue are simulated by DAYCENT. More N from manure was assumed to
volatilize before application to soils and hence less N from manure was available for leaching than previous years.
However, total N volatilization and leaching/runoff were both still higher than previous years. This is because IPCC
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 220
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methodology considers only N from synthetic and organic fertilizer to contribute to indirect emissions whereas
other sources of N (e.g., fixation, crop residue) contribute to volatilization and N leaching/runoff in DAYCENT.
The methodology used here estimated total N2O emissions to be approximately 5 to 10 percent less than estimates
based on the IPCC methodology due to changes in the calculation method, as well as accounting for N2O from
fertilization of forest and settlement soils within the LUCF sector. The current method estimates lower direct N2O
emissions Table 6-19, but higher indirect N2O emissions (Table 6-20) than the IPCC method. Differences in total
N2O emissions are shown in Table 6-21. Direct emissions were lower because of different assumptions regarding
the cycling of fixed N and lower manure N applications to the major crop types under the current methodology
compared with that used in the past. Indirect emissions, on the other hand, were larger because more contributors to
N volatilization and leaching/runoff are accommodated by the simulation (by including crop residue applications,
for example). Mean direct emissions from non-N fixing crops differed by approximately one percent, whereas
direct emissions from N fixing crops were approximately 30 percent less with hybrid than IPCC methodology.
Interestingly, total N fixation with the hybrid approach was only approximately two percent lower than with IPCC
methodology and the implied emission factor for direct N2O emissions from fixation is approximately 0.9 percent
using hybrid methodology; i.e., these DAYCENT simulations suggest that the 1.25 percent emissions factor used
for direct N2O emissions from N fixation is too high. This is consistent with field data showing that IPCC
methodology may overestimate N2O emissions from soybean and alfalfa cropping (Del Grosso et al. in press,
Rochette et al. 2004).
Table 6-19. Comparison of Direct Soil N2O Emission Estimates for IPCC versus Current Methodologies (Tg CO2
Eg.).
Method
IPCC
Current Simulation*
Difference
1990 - •' 1997
191
146
45
.2
.0
\",J/{ 214
£*$•' 162
.2 V;;,< 52
.9
o
. J
.6
1998
216.
165.
51.
1
1
0
1999
213.9
157.7
56.2
2000
213.0
162.6
50.4
2001
213.2
160.7
52.5
2002
210.1
166.3
43.8
2003
205.8
161.7
44.1
* Unlike Table 6-13, emissions due to N applied to forest lands and settlements are included here, to be consistent with IPCC
estimates used in previous reports.
Table 6-20. Comparison of Indirect Soil N2O Emission Estimates for IPCC versus Current Methodologies (Tg CO2
Eq.)
Method
IPCC
Current Simulation
Difference
1990 W
72.6 :;.;
112.6 :'-'
-40.01s:
1997
:,"•' 79.0
', , 96.2
'£ -17.2
1998
78.8
109.1
-30.3
1999
78.8
92.3
-13.5
2000
77.4
107.6
-30.2
2001
76.0
102.6
-26.6
2002
77.2
92.7
-15.5
2003
77.3
98.2
-20.9
Table 6-21. Comparison of Total Soil N2O Emission Estimates for IPCC versus Current Methodologies (Tg CO2
Eq.)
Method 1990 :;:'rv 1997 1998 1999 2000 2001 2002 2003
IPCC
Current Simulation*
263.8
258.6
^":,:;'- 293.9 294.9 292.8 290.4 289.2 287.2 283.1
;v;i*;'. 258.4 274.2 250.0 270.2 263.3 259.0 259.9
Difference 5.2' t- -.v 35.4 20.7 42.7 20.2 25.9 28.2 23.2
* Unlike Table 6-13, emissions due to N applied to forest land and settlements are included here, to be consistent with IPCC
estimates used in previous reports.
Compared with the IPCC methodology used in the past, the current methodology shows a smaller increase in total
N2O emissions from 1990 through 2003. The current methodology takes into account climate patterns as well as
annual fluctuations in N additions. The linear regression between emissions estimated with the new method and
time shows a trend toward increasing emissions of approximately 0.39 percent per year. During this time period,
synthetic N fertilizer applications increased by nine percent, manure additions increased by 11 percent, and N
fixation increased by about 17 percent. Soybean cropped area increased by 27 percent, corn area increased by six
percent, and wheat area decreased by 20 percent. The increase in soybean area is largely responsible for the
increase in fixation. Because total non-legume cropped area decreased and total fertilizer applied to major crops
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 221
-------
increased, the average rate of fertilizer applied to major crops increased by 32 percent from 1990 through 2003.
The current method accounts for each of these variables plus the effects of climate variability, whereas the previous
method accounted only for changes in fertilizer and manure additions. Climate interacts with N additions to control
emissions with the new methodology. Total N additions from fertilizer are important with the IPCC methodology,
while the current method accounts for total N additions, the area that receives the N are important, as well as
environmental and management conditions. As a result, simulated N2O emission estimates may increase or decrease
non-linearly, whereas emissions always increase linearly with N applications when using the IPCC methodology.
Planned Improvements
The presented uncertainty estimate is incomplete in that uncertainty in model activity data besides N inputs (county
level weather and soil type) was not included. Because county level soil and climate data are applied across the
entire county, within which a great deal of variability may occur, there is inherent uncertainty in assuming that soil
type and climate do not vary within a county. Future estimates of uncertainty will include sensitivity analyses so
that the response of model N2O output to variations in climate, soil type, and N inputs can be quantified. Also, a
more appropnate methodology than Tier 1 will also be used in future uncertainty estimates. Future efforts at
characterizing uncertainty will work toward the inclusion of all agricultural soil management subsource categories
in a Monte Carlo style calculation.
6.5. Field Burning of Agricultural Residues (IPCC Source Category 4F)
Large quantities of agricultural crop residues are produced by farming activities. A variety of ways exist 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.8 Annual emissions from this source over the period 1990 through 2003 have remained
relatively constant, averaging approximately 0.7 Tg CO2 Eq. (35 Gg) of CH4, 0.4 Tg CO2 Eq. (1 Gg) of N2O, 737
Gg of CO, and 32 Gg of NOX (see Table 6-22 and Table 6-23).
Table 6-22: Emissions from Field Burning of Agricultural Residues (Tg CO2 Eq.)
Gas/Crop Type
CH4
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
N2O
Wheat
1990
0.7
0.1
0.1
+
0.3
+
0.1
+
0.4
1997
"'" /- 0.8
V- o.i
'>•:".' o.i
Vi -" +
»,"*''"' 0-3
;;•"", +
v-;. 0.2
v'' +
0.4
1998
0.8
0.1
0.1
+
0.3
+
0.2
+
0.5
1999
0.8
0.1
0.1
+
0.3
+
0.2
+
0.4
2000
0.8
0.1
0.1
+
0.4
+
0.2
+
0.5
2001
0.8
0.1
0.1
+
0.3
+
0.2
+
0.5
2002
0.7
0.1
0.1
+
0.3
+
0.2
+
0.4
2003
0.8
0.1
0.1
+
0.4
+
0.2
+
0.4
The fraction office straw burned each year is significantly higher than that for other crops (see "Methodology" discussion
below).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 222
-------
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
Total
+ Does not exceed
Note: Totals may
+
+
0.1
+
0.2
+ '
1.1
;•"',' .',' +
V;.*': +
;%• o.i
^.,* +
-)'•'•; 0.3
',.",' ; +
:i ; , 1.2
+
+
0.1
+
0.3
+
1.2
+
+
0.1
+
0.3
+
1.2
+
+
0.1
+
0.3
+
1.2
+
+
0.1
+
0.3
+
1.2
+
+
0.1
+
0.3
+
1.1
+
+
0.1
+
0.2
+
1.2
0.05 Tg CO2 Eq.
not sum due
to independent rounding.
Table 6-23: Emissions from Field Burning
Gas/Crop Type
CH4
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
N2O
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
CO
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
NOX
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
1990
33 £
7^
4 •<*-
x.
lit
\t
it
+t
ll
+£
+t
+>-
+ ^r
1 t
+ t
689 £
137 £
86 £
18£
282 £
16£
148 £
2t
28 t
4i
"3 f"
-' >'-
+ t
it
1 £
14$
+i
-•"'},;: 1997
,'x? 37
^ 6
'J-I:V; 3
»r\ 1
,'x? 16
ij'bj 1
>vi!< 10
^••'f, +
_;;/? i
i\ '•"*') +
fy +
:/^ +
^'x? +
i '•'*v +
jfJd j i
»V f, +
?$ 767
l"«V I24
:;i' 72
/V,; 21
;\^ 328
4:;*V 13
.';fv*1' 207
%,', 2
?;>V'i 34
i:>: 3
,!'''' V
:rt- -^
..;/.; +
, ' ^ ' o
!, ' - ; -'• °
v •' :' +
;9', 20
,*2ii; +
of Agricultural Residues (Gj
1998
38
6
3
1
17
1
10
+
1
+
+
+
+
+
1
+
789
128
65
22
347
13
211
2
35
3
2
+
8
+
20
+
1999
37
5
4
1
16
+
10
+
1
+
+
+
+
+
1
+
767
115
76
23
336
10
204
2
34
3
^
+
8
+
19
+
2000
38
5
4
1
17
1
10
+
1
+
+
+
+
+
1
+
790
112
76
24
353
12
212
2
35
3
3
+
8
+
20
+
0*
2001
37
5
4
1
16
+
11
+
1
+
+
+
+
+
1
+
770
98
77
23
338
9
222
3
35
3
3
+
8
+
21
+
2002
34
4
3
1
15
+
10
+
1
+
+
+
+
+
1
+
706
81
60
23
320
8
211
2
33
2
2
+
8
+
20
+
2003
38
6
5
1
17
0
9
0
1
+
+
+
+
+
1
+
794
117
96
23
360
10
186
3
33
3
^
+
9
+
18
+
* Full molecular weight basis.
+ Does not exceed
Note: Totals may
0.5 Gg
not sum due
to independent rounding.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 223
-------
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)9. In order to estimate the amounts of
carbon and nitrogen released during burning, the following equations were used:10
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)11
Nitrogen Released = (Annual Crop Production) x (Residue/Crop Product Ratio)
x (Fraction of Residues Burned in situ) x (Dry Matter Content of the Residue)
x (Burning Efficiency) x (Nitrogen Content of the Residue) x (Combustion Efficiency)
Emissions of CH4 and CO were calculated by multiplying the amount of carbon released by the appropnate 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).
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 and Oklahoma were taken from the USDA's Field Crops,
Final Estimates 1987-1992, 1992-1997 (USDA 1994, 1998), Crop Production 1999 Summary (USDA 2000), Crop
Production 2000 Summary (USDA 2001), Crop Production 2001 Summary (USDA 2002), Crop Production 2002
Summary (USDA 2003) and Crop Production 2003 Summary (USDA 2004). Rice production data for Florida and
Oklahoma, which are not collected by USDA, were estimated by applying average primary and ratoon crop yields
for Florida (Schueneman and Deren 2002) to Florida acreages (Schueneman 1999b, 2001; Deren 2002; Kirstein
2003, 2004; Cantens 2004) and Oklahoma acreages12 (Lee 2003, 2004). The production data for the crop types
whose residues are burned are presented in Table 6-24.
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 extension agents in each state and reports of the California Air Resources Board (GARB) (Bollich 2000;
Deren 2002; Guethle 1999, 2000, 2001, 2002, 2003, 2004; Fife 1999; California Air Resources Board 1999, 2001;
9 The IPCC Good Practice Guidance (IPCC 2000) provided no updates the methodology for estimating field burning of
agricultural residues.
10 Note: As is explained later in this section, 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.
11 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.
12 Rice production yield data are not available for Oklahoma so the Florida values are used as a proxy.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 224
-------
Klosterboer 1999a, 1999b, 2000, 2001, 2002, 2003; Lmdberg 2002, 2003, 2004; Lmscombe 1999a, 1999b, 2001,
2002, 2003, 2004; Mutters 2002, 2003; Najita2000, 2001; Schueneman 1999a, 1999b, 2001; Slaton 1999a, 1999b,
2000; Stansel 2004; Street 1999a, 1999b, 2000, 2001, 2002, 2003; Walker 2004; Wilson 2001, 2002, 2003, 2004)
(see Table 6-25 and Table 6-26). The estimates provided for Florida remained constant over the entire 1990
through 2003 period, while the estimates for all other states varied over the time series. For California, the annual
percents of rice area burned in the Sacramento Valley are assumed to be 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
values declined between 1990 and 2003 because of a legislated reduction in rice straw burning (Lindberg 2002) (see
Table 6-26).
All residue/crop product mass ratios except sugarcane were obtained from Strehler and Stiltzle (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
Sttitzle (1987). Peanut dry matter content was obtained through personal communications with Jen Ketzis (1999),
who accessed Cornell University's Department of Animal Science's computer model, Cornell Net 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 1997). The nitrogen content of soybeans is from Barnard and Knstoferson (1985). The
nitrogen content of peanuts is from Ketzis (1999). These data are listed in Table 6-27. 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 6-28) were taken from the Revised 1996IPCC Guidelines
(IPCC/UNEP/OECD/IEA 1997),
Table 6-24: Agricultural Crop Production (Gg of Product)
Crop
Wheat
Rice
Sugarcane
Corn*
Barley
Soybeans
Peanuts
1990 1
74,292 :
7,113:
25,525 :
201,534:
9,192:
52,416:
1,635:
' 1997
\»;S' 67,534
;[,'.' V 8,346
', "I: 28,766
•yf 233,864
'i'.,-.," 7,835
;"!:•;; 73,176
.'•A' 1,605
1998
69,327
8,578
30,896
247,882
7,667
74,598
1,798
1999
62,569
9,391
32,023
239,549
6,103
72,223
1,737
2000
60,758
8,703
32,762
251,854
6,939
75,055
1,481
2001
53,262
9,794
31,377
241,485
5,430
78,671
1,940
2002
43,992
9,601
32,597
228,805
4,940
74,291
1,506
2003
63,590
9,050
31,178
256,905
6,011
65,795
1,880
*Corn for grain (i.e., excludes corn for silage).
Table 6-25: Percentage of Rice Area Burned by State
State Percent Burned Percent Burned
1990-1998 1999
Arkansas
California
Florida"
Louisiana
Mississippi
Missouri
Oklahoma
Texas
13
variable3
0
6
10
5
3
1
13
27
0
0
40
5
3
2
Percent Burned
2000
13
27
0
5
40
8
3
0
Percent Burned
2001
13
23
0
4
40
5
3
0
Percent Burned
2002
16
13
0
3
8
5
3
0
Percent Burned
2003
22
14
0
3
65
4
0
0
a Values provided in Table 6-26.
b Although rice is cultivated in Florida, crop residue burning is illegal. Therefore, emissions remain 0 throughout the time series.
Table 6-26: Percentage of Rice Area Burned in California
Year California
1990
1991
1992
1993
75
75
66
60
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 225
-------
1994 69
1995 59
1996 63
1997 34
1998 33
Table 6-27: Key Assumptions for Estimating Emissions from Field Burning of Agricultural Residues
Crop Residue/Crop Fraction of Dry Matter Carbon Nitrogen Burning Combustion
Ratio Residue Burned Fraction Fraction Fraction Efficiency Efficiency
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
0.93
0.93
0.93
0.93
0.93
0.93
0.93
0.88
0.88
0.88
0.88
0.88
0.88
0.88
Table 6-28: Greenhouse Gas Emission Ratios
Gas Emission Ratio
CH4a
coa
N-?Ob
N0xb
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
One 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. Based on
expert judgment, uncertainty in the fraction of crop residue burned ranged from zero to 100 percent, depending on
the state and crop type.
Based on expert judgment, the uncertainty in production for all crops considered here is estimated to be 5 percent.
Residue/crop product ratios can vary among cultivars. For all crops except sugarcane, generic residue/crop product
ratios, rather than ratios specific to the United States, have been used. An uncertainty of 10 percent was applied to
the residue/crop product ratios for all crops.
Based on the range given for measurements of soybean dry matter fraction (Strehler and Stutzle 1994), residue dry
matter contents were assigned an uncertainty of 3.1 percent for all crop types.
Burning and combustion efficiencies were assigned an uncertainty of 5 percent based on expert judgment.
The N2O emission ratio was estimated to have an uncertainty of 28.6 percent based on the range reported in IPCC
(2000). The uncertainty estimated for the CH4 emission ratio was 40 percent based on the range of ratios reported
in IPCC (2000).
The results of the Tier 1 quantitative uncertainty analysis are summarized in Table 6-29. Field burning of
agricultural residues CH4 emissions in 2003 were estimated to be between 0.2 and 1.3 Tg CO2 Eq. at a 95 percent
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 226
-------
confidence level. This indicates a range of 69 percent above and below the 2003 emission estimate of 0.8 Tg CO2
Eq. Also at the 95 percent confidence level, N2O emissions were estimated to between 0.1 and 0.7 Tg CO2 Eq. (or
approximately 68 percent above and below the 2003 emission estimate of 0.4 Tg CO2 Eq.).
Table 6-29: Tier 1 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Field Burning of
Agricultural Residues (Tg CO2 Eq. and Percent)
2003
Emission Uncertainty Range Relative to
Estimate Uncertainty 2003 Emission Estimate
Source Gas (Tg CO2 Eq.) (%) (Tg CO2 Eq.)
Field Burning of
Agricultural Residues
Field Burning of
Agricultural Residues
CH4
N2O
0.8
0.4
69%
68%
Lower Bound
0.2
0.1
Upper Bound
1.3
0.7
Recalculations Discussion
For the current Inventory, a transcription error was fixed for the 1998 rice production data for California from the
USDA 2000 Crop Production Summary Report (2001). The change resulted in increases of less than 0.1 Tg CO2
Eq. (0.1 percent) in CH4 and N2O emissions from the field burning of agricultural residues for 1998. Additionally,
the 2002 rice production data was updated from the USDA 2003 Crop Production Summary Report (2004). The
change resulted in increases of less than 0.1 Tg CO2 Eq. (0.2 and 0.4 percent, respectively) in CH4 and N2O
emissions from the field burning of agricultural residues for that year.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 227
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-------
Agricultural Soil
Management
Enteric
Fermentation
Manure
Management
Rice Cultivation
Agricultural Residue
Burning
1.2
50
Agriculture as a
Portion of all
Emissions
100 150 200
Tg CO2 Eq
250
300
Figure 6-1: 2003 Agriculture Chapter GHG Sources
-------
Figure 6-2
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 respresented with arrows on the left-hand side of the
graphic. Emissions 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.
-------
7. Land-Use Change and Forestry
This chapter provides an assessment of the net greenhouse gas flux1 resulting from forest lands, croplands, and
settlements. IPCC Good Practice Guidance for Land Use, Land-Use Change and Forestry (IPCC 2003)
recommends reporting fluxes according to changes within and conversions between these land use types, as well as
grassland and wetlands. However, consistent datasets are not available for the entire United States to allow results
to be partitioned in this way. Therefore, greenhouse gas flux has been estimated for the following categories: 1)
forest land remaining forest land 2) croplands remaining croplands, and 3) settlements remaining settlements. This
categorization provides additional sources of information regarding N2O emissions by major land use type.
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 comprehensively accounted for currently. These fluxes include emissions of CH4 from
managed forest soils, as well as CH4 emissions from artificially flooded lands, which result 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.
The greenhouse gas flux from forest land remaining forest land is reported using estimates of changes in forest
carbon stocks and the application of nitrous oxide (N2O) fertilizers to forest soils. Seven components of forest
carbon stocks are analyzed: aboveground biomass, belowground biomass, dead wood, litter, soil organic carbon,
harvested wood products in use, and harvested wood products in landfills. The estimated carbon dioxide (CO2) flux
from each of these forest components was derived from U.S. forest inventory data, using methodologies that are
consistent with LULUCF Good Practice Guidance (IPCC 2003) and the Revised 1996 IPCC Guidelines
(IPCC/UNEP/OECD/IEA 1997). In addition, this year, according to the new L UL UCF Good Practice Guidance
(IPCC 2003), N2O emissions from fertilized forest soils are accounted for utilizing a default methodology.
Croplands remaining croplands emission estimates are a reflection of the changes in agricultural soil carbon stocks
on both cropland and grazing land since the necessary datasets were not available to separate cropland and grassland
fluxes. 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 flux in
agricultural soil carbon stocks are consistent with the Revised 1996IPCC Guidelines and the LULUCF Good
Practice Guidance (IPCC 2003).
Fluxes resulting from settlements remaining settlements include landfilled yard trimmings and food scraps, urban
trees, and soil N2O emissions from fertilization. Changes in yard trimming and food scrap carbon stocks in landfills
are estimated using analysis of life-cycle greenhouse gas emissions and sinks associated with solid waste
management (EPA 1998). Changes in carbon stocks in urban trees are estimated based on field measurements in
ten U.S. cities and data on national urban tree cover, using a methodology consistent with the LULUCF Good
Practice Guidance (IPCC 2003). Finally, this year, according to the new LULUCF Good Practice Guidance (IPCC
2003), N2O emissions from fertilized settlement soils are accounted for according to a default methodology. 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.
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."
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 229
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Unlike the assessments in other sectors, which are based on annual activity data, the flux estimates in this chapter,
with the exception of those from wood products, urban trees, liming, and settlement and forest N2O emissions, 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 from data collected in intervals ranging from 1 to 10
years. The resulting annual averages are applied to years between surveys. Because state surveys are collected at
different times, using this data structure, the estimated CO2 fluxes from forest carbon stocks differ at the national
level from year to year. Agricultural soil carbon flux calculations are constant over multi-year intervals, with large
discontinuities between intervals; however, fluxes after 1997 are inconsistent due to the method of accounting for
the application of manure and sewage sludge amendments to mineral soils after 1997. For the landfilled yard
trimmings and food scraps source, 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 prior to 2003, the estimates of CO2 flux from forests, agricultural soils, and landfilled yard
trimmings and food scraps are based in part on modeled projections or extrapolation. 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.
Land use, land-use change, and forestry activities in 2003 resulted in a net carbon sequestration of 828 Tg CO2 Eq.
(226 Tg C) (Table 7-land Table 7-2). This represents an offset of approximately 14 percent of total U.S. CO2
emissions. Total land use, land-use change, and forestry net carbon sequestration declined by approximately 21
percent between 1990 and 2003. This decline was primarily due to a decline in the rate of net carbon accumulation
in forest carbon stocks. Annual carbon accumulation in landfilled yard trimmings and food scraps also slowed over
this period, as did annual carbon accumulation in agricultural soils. As described above, the constant rate of carbon
accumulation in urban trees is a reflection of limited underlying data (i.e., this rate represents an average for 1990
through 1999).
Table 7-1: Net CO2 Flux from Land-Use Change and Forestry (Tg CO2 Eq.)
Sink Category
Forest Land Remaining Forest Land
Changes in Forest Carbon Stocks
Cropland Remaining Cropland
Changes in Agricultural Soil Carbon
Stocks
Settlements Remaining Settlements
Urban Trees
Landfilled Yard Trimmings and Food
Scraps
1990 I
(949.3) |
(949.3) i
(8.1)
(8.1) I
(84.7) i
(58.7) {
(26.0)
1997
(851.0)
(851.0)
(7.4)
(7.4)
(71.6)
(58.7)
(12.9)
1998
(805.5)
(805.5)
(4.3)
(4.3)
(71.2)
(58.7)
(12.5)
1999
(751.7)
(751.7)
(4.3)
(4.3)
(70.0)
(58.7)
(11.4)
2000
(747.9)
(747.9)
(5.7)
(5.7)
(68.9)
(58.7)
(10.2)
2001
(750.9)
(750.9)
(7.1)
(7.1)
(68.9)
(58.7)
(10.3)
2002
(751.5)
(751.5)
(6.2)
(6.2)
(68.8)
(58.7)
(10.2)
2003
(752.7)
(752.7)
(6.6)
(6.6)
(68.7)
(58.7)
(10.1)
Total
(1042.0)
(930.0) (881.0) (826.1) (822.4) (826.9) (826.5) (828.0)
Note: Parentheses indicate net sequestration. Totals may not sum due to independent rounding.
Table 7-2: Net CO2 Flux from Land-Use Change and Forestry (Tg C)
Sink Category
Forest Land Remaining Forest Land
Changes in Forest Carbon Stocks
Cropland Remaining Cropland
Changes in Agricultural Soil Carbon
Stocks
Settlements Remaining Settlements
Urban Trees
Landfilled Yard Trimmings and Food
Scraps
Total
1990 i
(259) i
(259) |
(2) |
(2) i
(23) i
(16) i
(7) I
(284) |
1997
(232)
(232)
(2)
(2)
(20)
(16)
(4)
(254)
1998
(220)
(220)
(1)
(1)
(19)
(16)
(3)
(240)
1999
(205)
(205)
(1)
(1)
(19)
(16)
(3)
(225)
2000
(204)
(204)
(2)
(2)
(19)
(16)
(3)
(224)
2001
(205)
(205)
(2)
(2)
(19)
(16)
(3)
(226)
2002
(205)
(205)
(2)
(2)
(19)
(16)
(3)
(225)
2003
(205)
(205)
(2)
(2)
(19)
(16)
(3)
(226)
Note: 1 Tg C = 1 teragram carbon = 1 million metric tons carbon. Parentheses indicate net sequestration. Totals may not sum
due to independent rounding.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 230
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Land use, land-use change, and forestry activities in 2003 resulted in a net flux of 6.4 Tg CO2 Eq. of N2O (20.7 Gg)
(Table 7-3 and Table 7-4). Total N2O emissions from the application of fertilizers to forests and settlements
increased by approximately 14 percent between 1990 and 2003.
Table 7-3: Net N2O Emissions from Land-Use Change and Forestry (Tg CO2 Eq.)
Sink Category
Forest Land Remaining Forest Land
N2O Fluxes from Soils
Settlements Remaining Settlements
N2O Fluxes from Soils
Total
1990 |
0.1 i
0.1 |
5.5 |
5.5 |
5.6 i
1997
0.3
0.3
6.1
6.1
6.4
1998
0.4
0.4
6.1
6.1
6.5
1999
0.5
0.5
6.2
6.2
6.6
2000
0.4
0.4
6.0
6.0
6.3
2001
0.4
0.4
5.8
5.8
6.2
2002
0.4
0.4
6.0
6.0
6.4
2003
0.4
0.4
6.0
6.0
6.4
Note: Totals may not sum due to independent rounding.
Table 7-4: Net N2O Emissions from Land-Use Change and Forestry (Gg)
Sink Category
Forest Land Remaining Forest Land
N2O Fluxes from Soils
Settlements Remaining Settlements
N2O Fluxes from Soils
Total
1990 |
0.2 |
0.2 i
17.9 i
17.9 i
18.1 i
1997
1.0
1.0
19.8
19.8
20.7
1998
1.1
1.1
19.8
19.8
20.9
1999
1.5
1.5
19.9
19.9
21.4
2000
1.1
1.1
19.3
19.3
20.4
2001
1.3
1.3
18.7
18.7
20.0
2002
1.3
1.3
19.4
19.4
20.7
2003
1.3
1.3
19.4
19.4
20.7
Note: Totals may not sum due to independent rounding.
7.1. Forest Land Remaining Forest Land
Changes in Forest Carbon Stocks (IPCC Source Category 5A1)
For estimating carbon (C) stocks or stock change (flux), C in forest ecosystems can be divided into the following
five storage pools (IPCC 2003):
• Aboveground biomass, all living biomass above the soil including stem, stump, branches, bark, seeds, and
foliage. This category includes live understory.
• Belowground biomass, all living biomass of coarse living roots greater than 2 mm diameter.
• Dead wood, including all non-living woody biomass either standing, lying on the ground (but not including
litter), or in the soil.
• Litter, including the litter, fumic, and humic layers, and all non-living biomass with a diameter less than 7.5
cm at transect intersection, lying on the ground.
• Soil organic carbon (SOC), including all organic material in soil to a depth of 1 meter but excluding the
coarse roots of the above pools.
In addition, there are two harvested wood pools also necessary for estimating C flux, which are:
• Harvested wood products in use.
• Harvested wood products in landfills.
Carbon is continuously cycled among these storage pools and between forest ecosystems and the atmosphere as a
result of biological processes in forests (e.g., photosynthesis, growth, mortality, decomposition, and disturbances
such as fires or pest outbreaks) and anthropogenic activities (e.g., harvesting, thinning, clearing, and replanting). As
trees photosynthesize and grow, C is removed from the atmosphere and stored in living tree biomass. As trees age,
they continue to accumulate C until they reach maturity, at which point they store a relatively constant amount of C.
As trees die and otherwise deposit litter and debris on the forest floor, C is released to the atmosphere or transferred
to the soil by organisms that facilitate decomposition.
The net change in forest C is not equivalent to the net flux between forests and the atmosphere because timber
harvests do not cause an immediate flux of C to the atmosphere. Instead, harvesting transfers C to a "product pool."
Once in a product pool, the C is emitted over time as CO2 when the wood product combusts or decays. The rate of
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 231
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emission varies considerably among different product pools. For example, if timber is harvested to produce energy,
combustion releases C immediately. Conversely, if timber is harvested and used as lumber in a house, it may be
many decades or even centuries before the lumber decays and C is released to the atmosphere. If wood products are
disposed of in landfills, the C contained in the wood may be released many years or decades later, or may be stored
almost permanently in the landfill.
This section quantifies the net changes in C stocks in the five forest C 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. Thus, the focus on C implies that all C-based greenhouse gases are included, and the focus on stock
change suggests that specific ecosystem fluxes are not separately itemized in this report. Disturbances from forest
fires and pest outbreaks are implicitly included in the net changes. For instance, an inventory conducted after fire
counts only trees left. The change between inventories thus counts the carbon changes due to fires; however, it may
not be possible to attribute the changes to the disturbance specifically. The IPCC LULUCF Good Practice
Guidance (IPCC 2003) recommends reporting C stocks according to several land use types and conversions,
specifically forest land remaining forest land, nonforest land becoming forest, and forest becoming non-forest.
Currently, consistent datasets are not available for the entire United States to allow results to be partitioned in this
way. Instead, net changes in all forest-related land, including non-forest land converted to forest and forests
converted to non-forest are reported here.
Forest C storage pools, and the flows between them via emissions, sequestration, and transfers, are shown in Figure
7-1. In the figure, boxes represent forest C storage pools and arrows represent flows between storage pools or
between storage pools and the atmosphere. 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 C from one pool to another, and emissions to the atmosphere as well as uptake
from the atmosphere.
Figure 7-1: Forest Sector Carbon Pools and Flows.
Note: Boxes represent forest C storage pools and arrows represent flows between storage pools or between storage pools and the
atmosphere.
Approximately 33 percent (303 million hectares) of the U.S. land area is forested (Smith et al. 2004b). From the
early 1970s to the early 1980s, forest land declined by approximately 2.4 million hectares. During the 1980s and
1990s, forest area increased by about 3.7 million hectares. These net 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 C flux from forest land are management activities and the ongoing impacts of previous
land-use changes. These activities affect the net flux of C by altering the amount of C 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 C. Harvesting forests removes much of the aboveground C,
but trees can grow on this area again and sequester C. The reversion of cropland to forest land increases C storage
in biomass, forest floor, and soils. The net effects of forest management and the effects of land-use change
involving forest lands are captured in the estimates of C stocks and fluxes presented in this chapter.
In the United States, improved forest management practices, the regeneration of previously cleared forest areas, as
well as timber harvesting and use have resulted in net uptake (i.e., net sequestration) of C each year from 1990
2 The term "biomass density" refers to the mass of vegetation per unit area. It is usually measured on a dry-weight basis. Dry
biomass is about 50 percent carbon by weight.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 232
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through 2003. 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 still affect C fluxes from forests in the East. In addition, C fluxes from eastern forests have
been affected by a trend toward managed growth on private land. Collectively, these changes have nearly doubled
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 C fluxes. Because most of the timber harvested
from U.S. forests is used in wood products, and many discarded wood products are disposed of in landfills rather
than by incineration, significant quantities of C in harvested wood are transferred to long-term storage pools rather
than being released rapidly to the atmosphere (Skog and Nicholson 1998). The size of these long-term C storage
pools has increased during the last century.
Changes in C stocks in U.S. forests and harvested wood were estimated to account for an average annual net
sequestration of 832 Tg CO2 Eq. (227 Tg C) over the period 1990 through 2003 (Table 7-5, Table 7-6, and Figure
7-2). In addition to the net accumulation of C in harvested wood pools, sequestration is a reflection of net forest
growth and increasing forest area over this period, particularly before 1997. The increase in forest sequestration is
due more to an increasing C density per area than to the increase in area of forestland. Forestland in the
conterminous United States was approximately 246, 250, and 251 million hectares for 1987, 1997, and 2002,
respectively, only a 2 percent increase over the period (Smith et al. 2004b). Continuous, regular annual surveys are
not available over the period for each state; therefore, estimates for non-survey years were derived by interpolation
between known data points. Survey years vary from state to state. National estimates are a composite of individual
state surveys. Total sequestration declined by 21 percent between 1990 and 2003. This decline was primarily due
to a decline in the estimated rate of sequestration in forest soils. Inventory derived estimates of soil C stocks are
based solely on forest area and type. Thus, changes in soil C over time are directly the result of changes in total
forest area or changes in forest type from forest inventory data.
Table 7-5. Net Annual Changes in Carbon Stocks (Tg CO2 Eq. yr"1) in Forest and Harvested Wood Pools
Carbon Pool
Forest
Aboveground Biomass
Belowground Biomass
Dead Wood
Litter
Soil Organic Carbon
Harvested Wood
Wood Products
Landfilled Wood
Total Net Flux
1990
(739);;
(396),;
(77);:-:
(74);:-:
(67):;:
(125);:-:
(210);:
(48);
(162) .:.
(949)
* 1997
I;* (638)
;•* (457)
I;* (89)
I:* (53)
I:* (31)
1:?* (8)
i:.C (213)
-•: (58)
::- (155)
:r (851)
1998
(599)
(437)
(85)
(51)
(28)
1
(206)
(52)
(154)
(806)
1999
(537)
(400)
(78)
(45)
(26)
12
(215)
(62)
(153)
(752)
2000
(537)
(400)
(78)
(45)
(26)
12
(211)
(59)
(152)
(748)
2001
(537)
(400)
(78)
(45)
(26)
12
(214)
(59)
(155)
(751)
2002
(537)
(400)
(78)
(45)
(26)
12
(214)
(59)
(155)
(751)
2003
(537)
(400)
(78)
(45)
(26)
12
(216)
(60)
(155)
(753)
Note: Parentheses indicate net C sequestration (i.e., a net removal of C from the atmosphere). Total net flux is an estimate of the
actual net flux between the total forest C pool and the atmosphere. Forest estimates are based on interpolation and extrapolation
of inventory data as described in the text and in Annex 3.12. Harvested wood estimates are based on results from annual surveys
and models. Totals may not sum due to independent rounding.
Table 7-6. Net Annual Changes in Carbon Stocks (Tg C yr"1) in Forest and Harvested Wood Pools
Carbon Pool 1990 S 1997 1998 1999 2000 2001 2002 2003
Forest (202) | (174) (163) (146) (146) (146) (146) (146)
Aboveground Biomass (108) | .: (125) (119) (109) (109) (109) (109) (109)
Belowground Biomass (21) i|,^: (24) (23) (21) (21) (21) (21) (21)
Dead Wood (20) I"• ••- (14) (14) (12) (12) (12) (12) (12)
Litter (18);/;.vv (9) (8) (7) (7) (7) (7) (7)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 233
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Soil Organic Carbon
Harvested Wood
Wood Products
Landfilled Wood
Total Net Flux
(34):;,
(57):;,
(13):;
(44) ;:,
(259) ;;;
:: (2)
"* (58)
.!,: (16)
:::; (42)
-.- (232)
0
(56)
(14)
(42)
(220)
^
(59)
(17)
(42)
(205)
3
(57)
(16)
(41)
(204)
3
(58)
(16)
(42)
(205)
^
(58)
(16)
(42)
(205)
^
(59)
(16)
(42)
(205)
Note: Parentheses indicate net C sequestration (i.e., a net removal of C from the atmosphere). Total net flux is an estimate of the
actual net flux between the total forest C pool and the atmosphere. Forest estimates are based on interpolation and extrapolation
of inventory data as described in the text and in Annex 3.12. Harvested wood estimates are based on results from annual surveys
and models. Fotals may not sum due to independent rounding.
Stock estimates for forest and harvested wood C storage pools are presented in Table 7-7. Together, the
aboveground live and forest soil pools account for a large proportion of total forest C stocks. C stocks in all non-
soil pools increased over time. Therefore, C sequestration was greater than C emissions from forests, as discussed
above. Figure 7-3 shows the average carbon density in forests by state, estimated for 2004.
Table 7-7. Carbon Stocks (Tg C) in Forest and Harvested Wood Pools
Carbon Pool
Forest
Aboveground Biomass
Belowground Biomass
Dead Wood
Litter
Soil Organic Carbon
Harvested Wood
Wood Products
Landfilled Wood
Total Carbon Stock
1990
39,498 x
14, 114; ^
2,805;x
2,444 : x
4,496 ;x
1 5,640 :;>
1,915 5
1,134:;;.
781 •: .
41,414
1997
40,812
14,928
2,963
2,572
4,598
15,750
2,307
1,232
1,074
43,119
1998
40
15
2
2
4
15
2
1
1
43
,986
,053
,987
,587
,606
,752
,365
,248
,117
,351
1999
41,149
15,172
3,011
2,600
4,614
15,752
2,421
1,262
1,159
43,570
2000
41,296
15,281
3,032
2,613
4,621
15,749
2,480
1,279
1,200
43,775
2001
41
15
3
2
4
15
2
1
1
43
,442
,390
,053
,625
,628
,745
,537
,295
,242
,979
2002
41,589
15,499
3,074
2,638
4,636
15,742
2,595
1,311
1,284
44,184
2003
41,735
15,608
3,095
2,650
4,643
15,738
2,654
1,327
1,327
44,389
2004
41,882
15,717
3,117
2,662
4,650
15,735
2,713
1,344
1,369
44,594
Note: Forest C stocks do not include forest stocks in Alaska, Hawaii, or U.S. territories, or trees on non-forest land (e.g., urban
trees). Wood product stocks include exports, even if the logs are processed in other countries, and exclude imports. Forest
estimates are based on interpolation and extrapolation of inventory data as described in the text and in Annex 3.12. Harvested
wood estimates are based on results from annual surveys and models. Totals may not sum due to independent rounding.
Inventories are assumed to represent stocks as of January 1 of the inventory year. Flux is the net annual change in stock. Thus,
an estimate of flux for 2003 requires estimates of C stocks for 2003 and 2004.
Figure 7-2: Estimates of Net Annual Changes in Carbon Stocks for Major Carbon Pools (Tg C yr"1)
Note: Estimates for harvested wood are based on the same methodology and data as the previous U.S. Inventory (EPA 2004).
Estimates for all pools are based on measured forest inventory data as described in the text. Total Net includes all forest pools:
biomass, dead wood, litter, forest soils, wood products, and landfilled wood.
Figure 7-3: Average Carbon Density in the Forest Tree Pool in the Conterminous U.S. During 2004.
Methodology
The methodology described herein is consistent with LULUCF Good Practice Guidance (IPCC 2003) and the
Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). Estimates of net C flux from Land-Use Change
and Forestry, including all pools except harvested wood, were derived from periodic and annualized inventories of
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
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forest stocks. Net changes in C stocks were interpolated between survey years. Carbon emissions from harvested
wood were determined by accounting for the variable rate of decay of harvested wood according to its disposition
(e.g., product pool, landfill, combustion).3 Different data sources were used to estimate the C stocks and stock
change in (1) forests (aboveground and below ground biomass, dead wood, and litter), (2) forest soils, and (3)
harvested wood products. Therefore, these pools are described separately below.
Live Biomass, Dead Wood, and Litter Carbon
The estimates of non-soil forest C stocks are based on data derived from forest inventory surveys. Forest survey
data were obtained from the USDA Forest Service, Forest Inventory and Analysis (FIA) program (Prayer and
Furnival 1999, Smith et al. 2001). Surveys provide estimates of the merchantable volume of wood and other
variables that are used to estimate C stocks. Estimates of temporal change such as growth, mortality, harvests, or
area change are derived from repeated surveys, which were conducted every 5 to 14 years, depending on the state.
Historically, the FIA program did not conduct detailed surveys of all forest land, but instead focused on land
capable of supporting timber production (timberland4). However, over time individual state surveys gradually
started to include reserved and less productive forest lands. The C stock estimates provided here include all forest
land, see Annex 3.12 for discussion of how past data gaps on these lands were filled.
Temporal and spatial gaps in surveys were addressed with the new national plot design and annualized sampling
(Miles et al. 2001, Alerich et al. 2004), which were recently introduced by FIA. Annualized sampling means that a
portion of plots throughout each state is sampled each year, with the goal of measuring all plots once each 5 years.
Sampling is designed such that partial inventory cycles provide usable, unbiased samples of forest inventory. Thus,
many states have relatively recent partial inventories, yet not all states are currently surveyed this way. All
annualized surveys initiated since 1998 have followed the new national plot design for all forestlands, including
reserved and less productive lands. Inventories are assumed to represent stocks as of January 1 of the inventory
year.
For each periodic or annualized inventory in each state, each C pool was estimated using coefficients from the
FORCARB2 model (Birdsey and Heath 1995, Birdsey and Heath 2001, Heath et al. 2003, Smith et al. 2004a).
Estimates of C stocks made by the FORCARB2 coefficients at the plot level are organized somewhat differently
than the standard IPCC pools reported in Table 7-7. However, the estimators are compatible with reorganizing the
pools following IPCC LULUCF Good Practice Guidance (2003). For example, the biomass pools here include the
FORCARB2 pools of live trees and understory vegetation, each of which are divided into aboveground versus
belowground portions. Calculations for the tree portion of the aboveground biomass C pool were made using
volume-to-biomass conversion factors for different types of forests as presented in Smith et al. (2003). Biomass
was converted to C mass by dividing by two because dry biomass is approximately 50 percent C
(IPCC/UNEP/OECD/IEA 1997). The other portion of aboveground biomass, live understory C, was estimated from
inventory data using tables presented in Birdsey (1996). Litter C was estimated from inventory data using the
equations presented in Smith and Heath (2002). Down dead wood was estimated using a FORCARB2 simulation
and U.S. forest statistics (Smith et al. 2001).
J The wood product stock and flux estimates presented here use the production approach, meaning that they do not account for C
stored in imported wood products, but do include C stored in exports, even if the logs are processed in other countries. This
approach is used because it follows the precedent established in previous reports (Heath et al. 1996).
4 Forest land in the U.S. includes land that is at least 10 percent stocked with trees of any size. Timberland is the most
productive type of forest land, which is on unreserved land and is producing or capable of producing crops of industrial wood.
Productivity is at a minimum rate of 20 cubic feet of industrial wood per acre per year. The remaining portion of forest land is
classified as either reserved forest land, which is forest land withdrawn from timber use by statute or regulation, or other forest
land, which includes less productive forests on which timber is growing at a rate less than 20 cubic feet per acre per year. In
2002, there were about 199 million hectares of timberland in the conterminous U.S., which represented 79 percent of all forest
lands over the same area (Smith et al. 2004b).
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Forest Soil Carbon
Estimates of soil organic carbon stocks are based solely on forest area and on average soil C density for each broad
forest type group. Thus, any changes in soil C stocks are due to changes in total forest area or the distribution of
forest types within that area. Estimates of the organic C content of soils are based on the national STATSGO spatial
database (USDA 1991) and follow methods of Amichev and Galbraith (2004). These data were overlaid with FIA
survey data to estimate soil C on forest lands by broad forest type group.
Forest Carbon Stocks and Fluxes
The overall approach for determining forest C stock change was to estimate forest C stocks based on data from two
forest surveys conducted several years apart. Carbon stocks were calculated separately for each state based on
inventories available since 1990 and for the most recent inventory prior to 1990. Thus, the number of separate
stock estimates for each state was one less than the number of available inventories. For each pool in each state in
each year, C stocks were estimated by linear interpolation between survey years. Similarly, fluxes were estimated
for each pool in each state by dividing the difference between two successive stocks by the number of intervening
years between surveys. Note that inventories are assumed to represent stocks as of January 1 of the inventory year;
thus, stocks in 1989 and 1993 can be used to estimate flux for 1989 through 1992, for example. Stocks and fluxes
since the most recent survey were based on extrapolating estimates from the last two surveys. C stock and flux
estimates for each pool were summed over all states to form estimates for the conterminous United States. Data
sources and methods for estimating individual C pools are described more fully in Annex 3.12.
Harvested Wood Carbon
Estimates of C stock changes in wood products and wood discarded in landfills were based on the methods
described by Skog and Nicholson (1998). Carbon stocks in wood products in use and wood products stored in
landfills were estimated from 1910 onward based on historical data from the USDA Forest Service (USDA 1964,
Ulrich 1989, Howard 2001), and historical data as implemented in the framework underlying the North American
Pulp and Paper (NAPAP, Ince 1994) and the Timber Assessment Market and the Aggregate Timberland Assessment
System Timber Inventory models (TAMM/ATLAS, Haynes 2003, Mills and Kincaid 1992). Beginning with data
on annual wood and paper production, the fate of C in harvested wood was tracked for each year from 1910 through
2003, and included the change in C stocks in wood products, the change in C in landfills, and the amount of C
emitted to the atmosphere (CO2 and CH4) both with and without energy recovery. To account for imports and
exports, the production approach was used, meaning that C in exported wood was counted as if it remained in the
United States, and C in imported wood was not counted.
Uncertainty
The forest survey data that underlie the forest C estimates are based on a statistical sample designed to represent the
wide variety of growth conditions present over large territories. However, forest survey data that are currently
available generally exclude timber stocks on most forest land in Alaska, Hawaii, and U. S. territories. For this
reason, estimates have been developed only for the conterminous United States. Within the conterminous United
States, the USDA Forest Service mandates that forest area data are accurate within 3 percent at the 67 percent
confidence level (one standard error) per 405,000 ha of forest land (Miles et al. 2001). For larger areas, the
uncertainty in area is concomitantly smaller. For volume data, the accuracy is targeted to be 5 percent for each
28,300 m3 at the same confidence level. An analysis of uncertainty in growing stock volume data for timber
producing lands was undertaken for five states: Florida, Georgia, North Carolina, South Carolina, and Virginia
(Phillips et al. 2000). Nearly all of the uncertainty was found to be due to sampling rather than the regression
equations used to estimate volume from tree height and diameter. Standard errors for growing stock volume ranged
from 1 to 2 percent for individual states and less than 1 percent for the 5-state region. However, the total standard
error for the change in growing stock volume was estimated to be 12 to 139 percent for individual states, and 20
percent for the 5-state region. The high relative uncertainty for growing stock volume change in some states was
due to small net changes in growing stock volume. However, the uncertainty in volume change may be smaller than
was found in this study because estimates from samples taken at different times on permanent survey plots are
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correlated, and such correlation reduces the uncertainty in estimates of changes in volume or C over time (Smith and
Heath 2000). Based on these accuracy guidelines and these results for the Southeastern United States, forest area
and volume data for the conterminous United States are expected to be reasonably accurate, although estimates of
small changes in growing stock volume may have substantial uncertainty.
In addition to uncertainty in growing stock volume, there is uncertainty associated with the estimates of C stocks in
other ecosystem pools. Estimates for these pools are derived from extrapolations of site-specific studies to all forest
land since survey data on these pools are not generally available. Such extrapolation introduces uncertainty because
available studies may not adequately represent regional or national averages. Uncertainty may also arise 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 there is little consensus from available data sets on the effect of land use change and forest
management activities (such as harvest) on soil C stocks. For example, while Johnson and Curtis (2001) found little
or no net change in soil C 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
limited their usefulness for determining effects of harvesting on soil C. Because soil C stocks are large, estimates
need to be very precise, since even small relative changes in soil C sum to large differences when integrated over
large areas. The soil C stock and stock change estimates presented herein are based on the assumption that soil C
density for each broad forest type group stays constant over time. As more information becomes available, the
effects of land use and of changes in land use and forest management will be better accounted for in estimates of
soil C (see "Planned Improvements," below).
Recent studies have begun to quantify the uncertainty in national-level forest C budgets based on the methods
adopted here. Smith and Heath (2000) and Heath and Smith (2000a) report on an uncertainty analysis they
conducted on C sequestration in privately owned timberlands throughout the conterminous United States. These
studies are not directly comparable to the estimates in this chapter because they used an older version of the
FORCARB model and are based on older data. However, the relative magnitudes of the uncertainties are
informative. For the period 1990 through 1999, the true mean C flux was estimated to be within 15 percent of the
reported mean at the 80 percent confidence level. The corresponding true mean C stock estimate for 2000 was
within approximately 5 percent of the reported mean value at the 80 percent confidence level. The relatively greater
uncertainty in flux estimates compared to stock estimates is roughly similar to that found for estimates of growing
stock volume discussed above (Phillips et al. 2000). In both analyses, there are greater relative uncertainties
associated with smaller estimates of flux. Uncertainty in the estimates presented in this inventory may be greater
than those presented by Heath and Smith (2000a) for several reasons. Most importantly, their analysis did not
include uncertainty in growing stock volume data or uncertainties in stocks and fluxes of C from harvested wood.
The uncertainty analysis was performed using the IPCC-recommended Tier 2 uncertainty estimation methodology,
Monte Carlo Simulation technique. The results of the Tier 2 quantitative uncertainty analysis are summarized in
Table 7-8. The 2003 flux estimate for forest C stocks is estimated to be between (1,120.5) and (383.5) Tg CO2 Eq.
at a 95 percent confidence level (or 19 of 20 Monte Carlo Stochastic Simulations). This indicates a range of 49
percent below to 49 percent above the 2003 flux estimate of (752.7) Tg CO2 Eq.
Table 7-8: Tier 2 Quantitative Uncertainty Estimates for CO2 Net Flux from Forest Land Remaining Forest Land:
Changes in Forest Carbon Stocks (Tg CO2 Eq. and Percent)
2003 Flux
Source Gas Estimate Uncertainty Range Relative to 2003 Estimate"
(TgC02Eq.) (TgC02Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper
Bound
Forests Remaining
Forests: Changes in Forest
Carbon Stocks CO2 (752.7) (1,120.5) (383.5) -49% +49%
aRange of flux estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
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QA/QC and Verification
As discussed above, the USDA Forest Service Forest Inventory and Analysis program has conducted consistent
forest surveys based on extensive statistically-based sampling of most of the forest land in the conterminous United
States since 1952. 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. The Forest Inventory and Analysis
program includes numerous quality assurance and quality control procedures, including calibration among field
crews, duplicate surveys of some plots, and systematic checking of recorded data. Because of the statistically-based
sampling, the large number of survey plots, and the quality of the data, the survey databases developed by the Forest
Inventory and Analysis program form a strong foundation for C stock estimates. Field sampling protocols,
summary data, and detailed inventory databases are archived and are publicly available on the Internet (FIA
Homepage).
Many key calculations for estimating current forest C stocks based on FIA data are based on coefficients from the
FORCARB2 model (see additional discussion in the Methods section above and in Annex 3.12). The model has
been used for many years to produce national assessments of forest C stocks and stock changes. General quality
control procedures were used in performing calculations to estimate C stocks based on survey data. For example,
the derived C datasets, which include inventory variables such as areas and volumes, were compared with standard
inventory summaries such as Resources Planning Act (RPA) Forest Resource Tables or selected population
estimates generated from the FIADB, which are available at an FIA Internet site (FIA Database Retrieval System).
Agreement between the C datasets and the original inventories is important to verify accuracy of the data used.
Forest Inventory and Analysis data and some model projections are given in English units, but C stock estimates
were developed using metric units. To avoid unit conversion errors, a standard conversion table in electronic form
was used (Appendix B of Smith et al. 2001). Finally, C stock estimates were compared with previous inventory
report estimates to assure that any differences could be explained by either new data or revised calculation methods
(see the "Recalculations" discussion below).
Recalculations Discussion
The overall scheme for developing annualized estimates of C stocks based on the individual state surveys is similar
to that presented in the previous Inventory (EPA 2003). Methods for estimating soil organic carbon are new for the
current Inventory; differences are in the interpretation of STATSGO data and their relationship with FIA survey
data as described by Amichev and Galbraith (2004)—see Annex 3.12 for additional information. Similar to that
reported in the previous Inventory, estimates of forest C stocks and fluxes are based on forest inventory data from
individual states rather than regions, and the data collected in states were assigned an average survey inventory plot
date rather than simply assigned the year for which the database was compiled. However, the selection and
compilation of survey data was implemented differently for the current Inventory, and there were some important
differences in the underlying data.
Three differences in methods can affect the non-soil forest C estimates. First, the selection of the datasets
representing individual state surveys was independent of last year's selections. Both RPA and the newer FIADB
datasets were considered, whereas last year only RPA data were used. The RPA data represent specific
compilations of survey data and include some older data not currently available in the FIADB. Using both ensured
the most recent data were used, yet older data were available as needed. Inventory data—even older surveys—are
occasionally modified so that RPA and FIADB data of ostensibly the same survey may have some slight differences
that can affect the C estimates. This is likely to have a very minor effect on recalculation of C stocks. Another
minor change in method is that fluxes were separately determined from the original survey data for each state for
each pool; in contrast, last year stocks were interpolated and summed to a national total for each year before flux
was calculated. Finally, separate stocks and fluxes were determined for National Forest lands where, in the past,
independent surveys were conducted at distinctly different times.
Pool definitions have changed for the current Inventory, as suggested by IPCC LULUCF Good Practice Guidance
(IPCC 2003). In previous Inventories, the pools were trees, understory, forest floor, down dead wood, and forest
soils. The forest soil pool is now soil organic carbon; forest floor is called litter. The previous tree pool included
both above- and belowground biomass and mass of standing dead trees. The mass of standing dead trees was added
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 238
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to the down dead wood pool and is called dead wood. The remainder of the tree pool, live biomass, as well as the
understory pool, was split into above- and belowground portions. The aboveground tree and understory pools were
summed into the aboveground biomass pool; the belowground portions of these pools were added to create the
belowground biomass pools.
Two changes in the use of data are also likely to affect the recalculation of C. The equations used to estimate tree C
from forest inventory data have been revised slightly; the net effect is that total tree C (live plus standing dead trees,
which are part of both the biomass and dead wood pools as summarized here) calculated for the 2002 RPA database
(Smith et al. 2004b) was 0.3 percent greater with the new set of equations relative to those used last year. Perhaps
the largest effect on C recalculations is that for the previous Inventory the final C stocks were modeled. This year,
however, values are simply extrapolated. The principal reason for eliminating the projections was the difficulty in
establishing projections consistent with the available forest inventory data.
Overall, these changes resulted in an average annual increase of 103.3 Tg CO2 Eq. (16 percent) in forest carbon
stocks for the period 1990 through 2002.
Planned Improvements
The Forest Inventory and Analysis program has adopted a new annualized design, such that a portion of each state
will be surveyed each year (Gillespie 1999). The annualized survey also includes measuring attributes that are
needed to estimate C in various pools, such as soil C and forest floor C, on a subset of the plots. During the next
several years, the use of annual data, including new data on soil and forest floor C stocks, and new data on non-
timberlands, will improve the precision and accuracy of estimates of forest C stocks and fluxes.
As more information becomes available about historical land use, the ongoing effects of changes in land use and
forest management will be better accounted for in estimates of soil C (Birdsey and Lewis 2003). Currently, soil C
estimates are based on the assumption that soil C density depends only on broad forest type group, not on land use
history. However, many forests in the Eastern United States are re-growing on abandoned agricultural land. During
such regrowth, soil and forest floor C stocks often increase substantially over many years or even decades,
especially on highly eroded agricultural land. In addition, with deforestation, soil C stocks often decrease over many
years. A new methodology is being developed to account for these changes in soil C over time. This methodology
includes estimates of area changes among land uses (especially forest and agriculture), estimates of the rate of soil C
stock gain with afforestation, and estimates of the rate of soil C stock loss with deforestation over time. This topic
is important because soil C stocks are large, and soil C flux estimates contribute substantially to total forest C flux,
as shown in Table 7-6 and Figure 7-2.
The estimates of C stored in harvested wood products are currently being revised using more detailed wood
products production and use data, and more detailed parameters on disposition and decay of products.
N20 Fluxes from Soils (IPCC Source Category 5.A.1)
Of the fertilizers applied to soils in the United States, no more than one percent is applied to forest soils.
Application rates are similar to those occurring on cropped soils, but in any given year, only a small proportion of
total forested land receives fertilizer. This is because forests are typically fertilized only twice during their
approximately 40 year growth cycle (once at planting and once at approximately 20 years). Thus, although the rate
of fertilizer application for the area of forests that receives fertilizer in any given year is relatively high, average
annual applications, inferred by dividing all forest land by the amount of fertilizer added to forests in a given year,
is quite low. Nitrous oxide (N2O) emissions from forest soils for 2003 were almost 7 times higher than the baseline
year (1990). The trend toward increasing N2O emissions is a result of an increase in fertilized area of pine
plantations in the southeastern United States. Total 2003 forest soil N2O emissions are roughly equivalent to 3.3
percent of the total forest soil carbon flux, and 0.07 percent of the total sequestration in standing forests, and are
summarized in Table 7-9.
Table 7-9. N2O Fluxes from Soils in Forests Remaining Forests (Tg CO2 Eq. and Gg)
Forests Remaining Forests: N2O Fluxes 1990 1997 1998 1999 2000 2001 2002 2003
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from Soils 1
Tg
Gg
CO2 Eq.
0
0
.06
.19
0
0
.30
.96
0.35
1.14
0.47
1.50
0.35
1.14
0.39
1.26
0.39
1.26
0.39
1.26
Methodology
According to U.S. Forest Service statistics for 1996 (USDA Forest Service 2001), approximately 75 percent of
trees planted for timber, and about 60 percent of national total harvested forest area are in the southeastern United
States. Consequently, it was assumed that southeastern pine plantations represent the vast majority of fertilized
forests in the United States. Therefore, estimates of direct N2O emissions from fertilizer applications to forests were
based on the area of pine plantations receiving fertilizer in the southeastern United States and estimated application
rates (North Carolina Sate Forest Nutrition Cooperative 2002). Not accounting for fertilizer applied to non-pine
plantations is justified because fertilization is routine for pine forests but rare for hardwoods (Binkley et al. 1995).
For each year, the area of pine receiving N fertilizer was multiplied by the midpoint of the reported range of N
fertilization rates (150 Ibs. N per acre). Data for areas of forests receiving fertilizer outside the southeastern United
States were not available, so N additions to non-southeastern forests are not included here; however, it should be
expected that emissions from the small areas of fertilized forests in other regions would be insubstantial because the
majority of trees planted and harvested for timber are in the southeastern United States (USDA Forest Service
2001). Area data for pine plantations receiving fertilizer in the southeast were not available for 2002 and 2003, so
data from 2001 were substituted for these years. The proportion of N additions that volatilized from forest soils was
assumed to be 10 percent of total amendments, according to the IPCC's default. The unvolatilized N applied to
forests was then multiplied by the IPCC default emission factor of 1.25 percent to estimate direct N2O emissions.
The volatilization and leaching/runoff fractions, calculated according to the IPCC default factors of 10 percent and
30 percent, respectively, were included with all sources of indirect emissions in the Agricultural Soil Management
source category of the Agriculture sector.
Uncertainty
The amount of N2O emitted from forests 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, temperature, and tree
planting/harvesting cycles. The effect of the combined interaction of these variables on N2O flux is complex and
highly uncertain. The IPCC default methodology used here does not incorporate any of these variables and only
accounts for variations in estimated fertilizer application rates and estimated areas of forested land receiving
fertilizer. All forest soils are treated equivalently under this methodology. Furthermore, only synthetic fertilizers
are captured, so applications of organic fertilizers are not accounted for here.
Uncertainties exist in the fertilizer application rates, the area of forested land receiving fertilizer, and the emission
factors used to derive emission estimates. Uncertainty was calculated according to a modified IPCC Tier 1
methodology. The 95 percent confidence interval of the IPCC default emission factor for synthetic fertilizer applied
to soil, according to Chapter 4 of IPCC (2000), ranges from 0.25 to 6 percent. While a Tier 1 analysis should be
generated from a symmetrical distribution of uncertainty around the emission factor, an asymmetrical distribution
was imposed here to account for the fact that the emission used was not the mean of the range given by IPCC.
Therefore, an upper bound of 480 percent and a lower bound of 80 percent were assigned to the emission factor.
The higher uncertainty percentage is shown below, but the lower bound reflects a truncated distribution. The
uncertainties in the area of forested land receiving fertilizer and fertilization rates were conservatively estimated to
be ±54 percent (Binkley 2004). The results of the Tier 1 quantitative uncertainty analysis are summarized in Table
7-10. N2O fluxes from soils were estimated to be between 0.01 and 2.3 Tg CO2 Eq. at a 95 percent confidence
level. This indicates a range of 96 percent below and 483 percent above the 2003 emission estimate of 0.4 Tg CCS
Eq.
Table 7-10: Tier 1 Quantitative Uncertainty Estimates of N2O Fluxes from Forest Soils (Tg CO2 Eq. and Percent)
Year 2003 Uncertainty Range Relative to
IPCC Source Emissions Uncertainty 2003 Emission Estimate
Category Gas (Tg CO2 Eq.) (%) (Tg CO2 Eq.)
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Lower Bound Upper Bound
Forests Remaining
Forests: N2O Fluxes
from Soils N2O 0.4 96 to 483% 0.01 2.3
Recalculations Discussion
The current Inventory reports N2O emissions from soils in forested areas separately for the first time. In previous
Inventories, N2O emissions from this source were implicitly included with N2O emissions from agricultural soils.
The net effect of separating forest soils from agricultural soils for the current Inventory is to reduce emissions
reported from the agricultural sector by a very small amount. However, because the methods for reporting that
source have changed significantly this year, it is impossible to isolate the magnitude of change caused by this
recalculation alone on the overall differences in N2O emissions from agricultural soils. The 2003 direct emission
estimate for N2O from forest soils amounts to an offset of total forest carbon sequestration of approximately 0.5
percent (including standing forests and wood products).
7.2. Land Converted to Forest Land (Source Category 5A2)
Land-use change is constantly occurring, and areas under a number of differing land use types are converted to
forest each year, just as forest lands are converted to other uses. However, the magnitude of these changes is not
currently known. Given the paucity of available land use information relevant to this particular IPCC source
category, it is not possible to quantify CO2 or N2O fluxes from land converted to forest land at this time.
7.3. Croplands Remaining Croplands
Changes in Agricultural Soil Carbon Stocks (IPCC Source Category 5B1)
Soils contain both organic and inorganic forms of carbon (C) that contribute to the total soil carbon stock. It is the
organic soil carbon (SOC) stocks in mineral and organic soils that may respond to management practices by
producing or sequestering greenhouse gases. The IPCC methodology for estimating impacts of agricultural
practices on soil C stocks (IPCC/UNEP/OECD/IEA 1997) is divided into three categories of land-use/land-
management activities: 1) agricultural land-use and land-management activities on mineral soils; 2) agricultural
land-use and land-management activities on organic soils; and 3) liming of soils. Nitrous oxide emissions from
agricultural soils are presented within the Agriculture sector.
Mineral soils contain comparatively low amounts of organic C, much of which is concentrated near the soil surface.
Typical well-drained mineral surface soils contain from 1 to 6 percent organic C (by weight), although some
mineral soils that experience long-term saturation during the year may contain significantly more C (NRCS 1999).
Mineral subsoils contain even lower amounts of organic C (NRCS 1999, Brady and Weil 1999). When mineral
soils undergo conversion from their native state to agricultural use, as much as half the SOC can be lost to the
atmosphere. The rate and ultimate magnitude of C 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 C loss generally
occurs within the first 10 years following conversion; after that, C stocks continue to decline but at a much slower
rate. In temperate regions, C loss can continue for several decades. Eventually, the soil will reach a new
equilibrium that reflects a balance between C accumulation from plant biomass and C loss through oxidation. Any
changes in land-use or management practices that result in increased organic inputs or decreased oxidation of
organic C (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 SOC until a new equilibrium is achieved.
Organic soils, also referred to as histosols, include all soils with more than 12 to 20 percent organic C by weight,
depending on clay content (NRCS 1999, Brady and Weil 1999). The organic layer of these soils is also typically
extremely deep. Organic soils form under waterlogged conditions, in which minimal decomposition of plant
residue occurs. 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, C loss from cultivated organic soils can continue over long periods of time.
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When organic soils are disturbed for cultivation purposes, which invariably include drainage, the rate at which
organic matter decomposes and CO2 emissions are generated, is determined primarily by climate, composition (i.e.,
decomposability) of the organic matter, and the specific land-use practices undertaken. The use of organic soils for
annual crop production results in greater C 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/IEA 1997).
The last category of the IPCC methodology addresses emissions from lime (in the form of crushed limestone
(CaCO3)) and dolomite (CaMg(CO3)2) additions to agricultural soils. Lime and dolomite are added by land
managers to ameliorate acidification. When these compounds come in contact with acid soils, they degrade, thereby
generating CO2. Complete degradation of applied limestone and dolomite could take several years, but it could also
take significantly less time, depending on the soil conditions and the type of mineral applied.
The estimates in this section include management impacts on mineral and organic soil C stocks for croplands and
grasslands. Due to limited data availability, it is impossible to differentiate between the stock changes resulting
from management practices on croplands or grasslands and those resulting from conversions between the two (i.e.,
statistics have been developed in a manner that only net changes in conversions are determined with no tracking of
the total amount of land converted between cropland and grassland uses).
Total SOC stock 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 C 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 C to or from soils.
Of the three activities (those associated with mineral soils, organic soils, and liming of soils) land use and
management of mineral soils was the most important component of total flux during the 1990 through 2003 period.
C sequestration in mineral soils in 2003 was estimated to be approximately 51.7 Tg CO2 Eq. (14 Tg C), while
emissions from organic soils were estimated to be 35.6 Tg CO2 Eq. (10 Tg C), and emissions from the practice of
liming were estimated at 9.5 Tg CO2 Eq. (3 Tg C). Together, the three activities accounted for net sequestration of
approximately 6.6 Tg CO2 Eq. (2 Tg C) in 2003. Total annual net CO2 flux was negative (i.e., net sequestration
occurred) each year over the inventory period, although the net C storage in soils did decline by 18 percent between
1990 and 2003. Net sequestration was largely due to annual cropland enrolled in the Conservation Reserve
Program, 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 decline in net sequestration was attributed to two management practices. First, the amount of
organic soils that were drained for agricultural production increased during the time period, thus leading to higher
emissions. Second, manure production declined over the inventory period, particularly during the last few years,
and this decline reduced the amount of crop and grazing lands receiving organic amendments, and thus there was a
small decline in C sequestration attributed to this activity.
The spatial variability in annual CO2 flux for mineral and organic soils is displayed in Figure 7-4 through Figure
7-7. The highest rates of sequestration occur mostly in the southern and northern Great Plains, southern portions of
the corn-belt in the Midwest, and the lower Mississippi River Valley. Sequestration rates are also relatively high in
the southeastern United States. These regions either have high Conservation Reserve Program enrollment
(particularly the Great Plains region), and/or have adopted conservation tillage at a higher rate than other regions of
the country. The greatest organic soil emission rates are from drained peatlands along the southeastern coastal
region, in the northeast central United States surrounding the Great Lakes, and along the central and northern
portions of the west coast.
Table 7-11: Net CO2 Flux from Agricultural Soils (Tg CO2 Eq.)
Soil Type
Mineral Soils
Organic Soils
Liming of Soils
1990 ;;C:
(52.4) £/
34.8 >
9.5 .C
1997
(51.7) ;
35.6 ,
8.7
1998
9.6
1999
.,,(4S:9J;:::;U-
9.1
2000
• .. ••: '..... "2-.iC jC- ..... -. .
. ••..,-.:,-..V> *J , V .- .'
8.8
2001
9.0
2002 2003
1 *" l-.-X'J..- ........ ••'-.'• V.i^/i. •.;•*"/ •
."•'•• •.•,"•'••• ;'/ • •_ ... v "•."•\; ..
loi f:;s ;••• :;:-9 .:5:f
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 242
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Total Net Flux (8.1) :%fr- (7.4) .^^{Cffi^';^
Note: Parentheses indicate net sequestration. Shaded areas indicate values based on a combination of historical data and
projections. All other values are based on historical data only. Estimates include the change in C storage resulting from the
annual application of sewage sludge and the change in manure amendments or Conservation Reserve Program enrollment after
1997.
Table 7-12: Net Carbon Flux from Agricultural Soils (Tg C)
Soil Type
Mineral Soils
Organic Soils
Liming of Soils
Total Net Flux
1990
(14.3)
95
2.6
(2.2)
1997
>"•'•"•• 97 C
•,-',:v 2.4
V (2.0) i
1998
;" ,'••'."'"'
2.6
il(l,2):; ::';
1999
Ia|fi;
' ' ' '2.5 '
-•••(l;2^£;::
2000
^(l3:.6)-g:,
'2.4"
iii&S) •'•"''
2001
Wjji^.
2.4
^•;1(3U$)X,V
2002 2003
-llf^SS^i
20 '" •. • ':;.••• .- '^ z" '^
.0 .:.;•...•,;.>•• ."-".-Z':^/
;.r:,;
-------
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. Manure N
production was denved from USDA livestock population data (USDA 1994a,b; 1995a,b; 1998a,b; 1999a-e; 2000a-
g; 2001 a-f; 2002a-f; 2003a-f), the FAOSTAT database (FAO 2003), and Lange (2000). Manure management
information was obtained from Poe et al. (1999), Safley et al. (1992), and personal communications with
agncultural 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, 1998c), and ASAE
(1999); daily rates of N excretion from ASAE (1999) and USDA (1996); and information about the fraction of
poultry litter used as a feed supplement from Carpenter (1992).
For estimating the emissions from both mineral and organic soils, Major Land Resource Areas 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).6 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).
For mineral soils, reference C stocks were estimated using the National Soil Survey Characterization Database
(NRCS 1997) with cultivated cropland as the reference condition, 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) than those which are not considered cultivated
cropland. U.S. management factors7 were derived from published literature to determine the impact of management
practices on SOC storage, including changes in tillage, cropping rotations and intensification, land-use change
between cultivated and uncultivated conditions, as well as C loss rates associated with drainage of organic soils
under agncultural management (Ogle et al. 2003, Ogle et al. in review). U.S. management factors associated with
organic matter amendments and improving grazing lands were not estimated because of few studies analyzing those
impacts. Instead, IPCC factors from LULUCF Good Practice Guidance (IPCC 2003) formed the basis for
quantifying the effect of those activities. Euliss and Gleason (2002) provided the data for computing the change in
SOC 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, SOC stocks for mineral soils 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 C stocks, and land-use activity data (Ogle et al. 2003, Ogle et al. 2002). The
annual C flux for 1990 through 1992 was determined by calculating the annual change in stocks between 1982 and
1992; annual C flux for 1993 through 2003 was determined by calculating the annual change in stocks between
1992 and 1997. Annual C flux estimates for mineral soils between 1990 and 2003 were adjusted to account for
additional C sequestration from sewage sludge applications, as well as gains or losses in C sequestration after 1997
due to changes in Conservation Reserve Program enrollment and manure N production. For the entire inventory
period, the amount of land amended with sewage sludge was estimated from N application data from the Soil
Management section of the Agriculture chapter of this volume, and an assumed application rate derived from
Kellogg et al. (2000). To estimate the impact of manure amendments after 1997, the change in manure N
production was determined relative to the amount produced in 1997, and then similar to sewage sludge calculations,
the production values were multiplied by the assumed application rate to determine the change in land area that was
amended with manure. Carbon storage rate was estimated at 0.22 metric tons C per hectare per year for both the
manure and sewage sludge amendments. To estimate the impact of enrollment in the Conservation Reserve
6 The polygons displayed in Figure 6-5 through Figure 6-8 are the Major Land Resource Areas.
7 Management factors have been derived from published literature to reflect changes in tillage, cropping rotations and
intensification, land-use change between cultivated and uncultivated conditions, as well as drainage of organic soils.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 244
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Program after 1997, the change in enrollment acreage relative to 1997 was derived based on Barbarika (2004), and
the differences in mineral soil areas were multiplied by 0.5 metric tons C per hectare per year.
Annual C emission estimates from organic soils between 1990 and 2002 were derived using Revised 1996IPCC
Guidelines (IPCC/UNEP/OECD/IEA 1997), except that U.S.-specific C loss rates were used in the calculations
rather than default IPCC rates (Ogle et al. 2003). Similar to mineral soils, the final estimates included a measure of
uncertainty as determined from the Monte Carlo simulation with 50,000 iterations. Emissions were based on the
1992 and 1997 land areas from the 1997 National Resources Inventory (USDA-NRCS 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 2003.
Liming
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 7-13) by CO2 emission factors
(0.120 metric ton C/metric ton limestone, 0.130 metric ton C/metric ton dolomite) (IPCC 2003).8 These emission
factors are based on the assumption that all of the C 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, 2003, 2004; USGS 2002, 2003, 2004). 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, the fractions of "unspecified" and "estimated" production that were applied to agricultural soils in a specific
year were assumed to be 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 2003 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 2003 data, the previous year's
fractions were applied to a 2003 estimate of total crushed stone presented in the USGS Mineral Industry Surveys:
Crushed Stone and Sand and Gravel in the First Quarter of 2004 (USGS 2004).
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 used. It then reported revised (rounded) quantities for each of the years from 1990 to 1993. In order to minimize
the inconsistencies in the activity data, these revised production numbers have been used in all of the subsequent
calculations.
Table 7-13: Quantities of Applied Minerals (Thousand Metric Tons)
Mineral 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
8 The default emission factor for dolomite provided in the Workbook volume of the Revised 1996 IPCC Guidelines
(IPCC/UNEP/OECD/IEA 1997) and the Good Practice Guidance for Land Use, Land-Use Change, and Forestry (IPCC 2003) 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 245
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Limestone 19,012 20,312 17,984 15,609 16,686 17,297 17,479 16,539 14,882 16,894 15,863 16,097 20,449 19,163
Dolomite 2,360 2,618 2,232 1,740 2,264 2,769 2,499 2,989 6,389 3,420 3,812 3,951 2,353 2,205
Uncertainty
Uncertainties for mineral and organic soils were quantified using a Monte Carlo Approach by constructing
probability distribution functions (PDF) for inputs to the IPCC equations, including management factors, C
emission rates for organic soils, and land use and management activity data, and then simulating a range of values
using the Monte Carlo framework (Ogle et al. 2003, Annex 3.13). Uncertainty estimates do not include sewage
sludge impacts on SOC storage for any year in the inventory period, or contributions of changing manure
management and enrollment in the Conservation Reserve Program after 1997. PDFs for management factors were
derived from a synthesis of 91 published studies, which addressed the impact of management on SOC storage.
Uncertainties in land use and management activity data were also derived from a statistical analysis. The National
Resources Inventory (NRI) has a two-stage sampling design that allowed PDFs to be constructed assuming a
multivariate normal distribution accounting for dependencies in activity data. PDFs for the tillage activity data, as
provided by the Conservation Technology and Information Center, were constructed on a bivariate normal
distribution with a log-ratio scale, accounting for the negative dependence among the proportions of land under
conventional and conservation tillage practices. PDFs for the crop and grazing land area receiving manure
amendments were based on the data sources given for manure amendments in the methodology section, and a
statistical relationship between production and the amount of land area that is amended according to manure
management information derived from the USDA Census of Agriculture (Edmonds et al. 2003). Lastly, enrollment
in wetland restoration programs was estimated from contract agreements, but due to a lack of information, PDFs
were constructed assuming a nominal ±50 percent uncertainty range.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 7-14. CO2 flux from mineral and
organic agricultural soil carbon stocks in 2003 was estimated to be between -40.0 and +5.9 Tg CO2 Eq. at a 95
percent confidence level (or 19 of 20 Monte Carlo Stochastic Simulations). This indicates a range of 148 percent
belowto 136 percent above the 2003 flux estimate of-16.1 TgCO2Eq.
Table 7-14: Tier 2 Quantitative Uncertainty Estimates for CO2 Flux from Mineral and Organic Agricultural Soil
Carbon Stocks (Tg CO2 Eq. and Percent)
2003 Flux
Estimate
Source Gas (Tg CO2 Eq.)
Mineral and Organic
Soil Uncertainty CO2 (16.1)
Uncertainty Range Relative to Flux Estimate"
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
(40.0) 5.9 -148% +136%
a Includes mineral and organic soils only; estimates do not include the change in C storage resulting from the annual application
of sewage sludge, or the change in manure amendments or Conservation Reserve Program enrollment after 1997.
bRange of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
The time-series calculations were consistent for each reporting year of the inventory in terms of methodology, with
the only difference in reported values stemming from the changes in land use and management activities across U.S.
agricultural lands. In addition, the same management factors (i.e., emission factors) were used each year for
calculating the impact of land use and management on SOC stocks. There is no evidence that changing
management practices has a quantitatively different impact on SOC stocks over the inventory period. For example,
changing from conventional to no-till management in 1990 is assumed to have the same impact on soil C stocks
over the course of this first year as it is over the course of each year in the 20 year period following the management
change.
Although the mineral and organic soil estimates have been improved during the last two years using a Monte Carlo
approach with the incorporation of U.S.-specific reference C stocks management factor values, and a more
comprehensive accounting of manure amendment impacts on SOC storage, several limitations remain in the
analysis. First, minimal data exist on where and how much sewage sludge has been applied to U.S. agricultural
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 246
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lands and the accounting of this activity appears to be much more difficult than the related-activity of using manure
to amend agricultural soils. Consequently, uncertainties have not been estimated for the change in SOC storage
resulting from sludge applications. Second, due to the IPCC requirement that inventories include all land areas that
are potentially subject to land-use change, the 1997 National Resources Inventory dataset includes some points
designated as non-agricultural land-uses if the points were once categorized as agricultural land use and their
designation changed during the period from 1992 to 1997. The non-agricultural land uses are urban, water, and
miscellaneous non-cropland (e.g., roads and barren areas). The impact on SOC storage that results from converting
cropland to non-agricultural uses is not well-understood, and therefore, those points were not included in the
calculations for mineral soils (emissions from organic soils, however, were computed for those points in the years
that they were designated as an agricultural use). Third, the current estimates may underestimate losses of C from
organic soils because the 1997 National Resources Inventory was not designed as a soil survey and organic soils
frequently occur as relatively small inclusions within major soil types. Lastly, this methodology does not take into
account changes in SOC stocks due to pre-1982 land use and land-use change.
Uncertainties in the estimates of emissions from liming result from both the methodology and the activity data. The
IPCC method assumes that all inorganic C 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 C
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 senes, 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 reporting 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.
Uncertainty regarding lime applications was estimated at 15 percent (Tepordei 2003). While IPCC provides no
uncertainty values for the emission factor from this subsource, there is uncertainty stemming primarily from the
inherent assumption that all applications are converted to CO2 within the year of application. In fact, limestone may
persist in the soil for 3 to 4 years following application (Nardozzi 2004), indicating that emissions may continue
throughout that period of time. Taking this into account, the resulting uncertainty in the emission factor is estimated
to be 75 percent. The preliminary results of the Tier 1 quantitative uncertainty analysis are summarized in Table
7-15. Liming of agricultural soils CO2 emissions in 2003 were estimated to be between 2.2 and 10.9 Tg CO2 Eq. at
the 95 percent confidence level. This indicates a range of 76 percent above and below the 2003 emission estimate
of 9.5TgCO2Eq.
Table 7-15: Tier 1 Quantitative Uncertainty Estimates for CO2 Emissions from Liming of Agricultural Soils (Tg
CO2 Eq. and Percent)
IPCC Source
Category
Year 2003
Emissions
Gas (Tg CO2 Eq.)
Uncertainty Range Relative to
Uncertainty 2003 Emission Estimate
(%) (Tg C02 Eq.)
Upper
Lower Bound Bound*
Liming of
Agricultural Soils CO2 9.5 76% 22 10.9
* Because the current Inventory methodology assumes that all of the limestone and dolomite decomposes in the year of
application, the emission factors could be significantly lower, but could not be higher. Consequently, the emissions estimate
may only be higher due to the uncertainty in the application data. Therefore, while normally, Tier 1 analyses generate a
symmetrical distribution of uncertainty around the emission estimate, an asymmetrical distribution was necessarily imposed here.
It is not currently possible to combine the results of this Tier 1 uncertainty analysis with those of the Tier 2
uncertainty analyses for CO2 fluxes from mineral soils and histosols.
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Recalculations Discussion
The estimates of changes in agricultural SOC stocks have been modified in several ways. First, uncertainty in
manure amendments was evaluated and incorporated into the general inventory calculations for agricultural soil C,
using the Tier 2 IPCC methodology (IPCC/UNEP/OECD/IEA 1997). In previous Inventories, the change in SOC
storage attributed to organic amendments was estimated as a post-analysis calculation using a simplistic activity-
based approach. Incorporating amendment data into the IPCC analysis led to a decline in the estimated change for
SOC storage attnbuted to manure management, relative to previous years. The activity-based approach assumed
that all of the applied manure was leading to an increase in SOC, while the IPCC method only accounted for the
changes in organic amendments from the baseline year to estimate the impact on SOC storage. In general, the IPCC
approach assumes that impacts on SOC storage are manifested in the first 20 years following a management change,
and consequently, this method does not account for smaller residual changes in SOC storage that can occur in later
years. However, the activity-based approach also has limitations because it does not account for the possibility that
a portion of the manure applied in a year is simply maintaining SOC storage from past applications. In fact, the
production of manure has not changed to a large extent since 1982 according to USDA statistics (see Annex 3.13),
and, therefore, many of the current amendments are only serving the purpose of maintaining past storage. Hence,
incorporating manure management into the IPCC calculations has produced a more conservative estimate by
reducing the potential for over-estimating the impact of longer-term manure amendments, but also does not capture
the residual change in SOC storage occurring after the first 20 years.
Two additional revisions have been incorporated into the analysis since the previous Inventory. As part of the
revision, management factors provided in the IPCC LULUCF Good Practice Guidance (IPCC 2003) now form the
basis to estimate management impacts for which U.S.-specific factors have not been derived (i.e., improving grazing
lands and organic amendments). Previously, defaults factor values from the Revised 1996IPCC Guidelines formed
the basis for these calculations using the IPCC method, but greater disaggregation of management factors by climate
in the IPCC LULUCF Good Practice Guidance was assumed to produce more realistic estimates of those
management impacts, compared to the single global values provided in the Revised 1996 IPCC Guidelines.
Lastly, emissions from organic soils have changed slightly from those reported in the previous inventory, as a result
of revising the land area included in the emission calculation. In previous years, lands that were converted between
agricultural and non-agricultural uses (i.e., urban, water, and miscellaneous non-cropland) were not included in the
estimation of emissions from organic soils, and this led to a slight under-estimation of emissions from organic soils.
Specifically, a small amount of land area under agricultural management in 1992 or 1997 was not included in the
emission calculation because it had been converted from a non-agricultural use.
Estimates of CO2 emissions from agricultural soil management have been revised due to methodological and
historical data changes in the calculations of N from livestock that is applied to soils. These changes include
corrections to: the typical animal mass value for beef cows and calves; the accounting of sheep in New England
states; state broiler populations; and updated NASS animal population estimates for the years 1998 through 2001
(NASS 2000). Additionally, the factor for converting short tons to metric tons was revised to include another
significant digit, and the percent residue applied for rice in the year 2001 was corrected. In combination, these
changes resulted in a minor effect on the agricultural soil C estimates with a reduction in the CO2 sink by less than 1
percent.
The quantity of applied minerals reported in the previous inventory for 2002 has been revised. Consequently, the
reported emissions resulting from liming in 2002 have also changed. In the previous inventory, to estimate 2002
data, the previous year's fractions were applied to a 2002 estimate of total crushed stone presented in the USGS
Mineral Industry Surveys: Crushed Stone and Sand and Gravel in the First Quarter of 2003 (USGS 2003). Since
publication of the previous inventory, the Minerals Yearbook has published actual quantities of crushed stone sold
or used by producers in the United States in 2002. These values have replaced those used in the previous inventory
to calculate the quantity of minerals applied to soil and the emissions from liming.
Overall, these changes resulted in an average annual decrease of 14.2 Tg CO2 Eq. (67 percent) in agricultural soil
carbon stocks for the period 1990 through 2002.
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Planned Improvements
A major planned improvement is currently underway that will enhance reporting of changes in agricultural soil C
stocks and deals with an alternative inventory approach to better represent between-year variability in annual fluxes.
This new annual activity-based inventory will use the Century ecosystem simulation model, which relies on actual
climate, soil, and land use/management databases to estimate variation in fluxes. This inventory will provide a more
robust accounting of C stock changes in U.S. agricultural lands than the more simplistic IPCC soil C accounting
approach. This approach is likely to be used in the future for reporting of land use and management impacts on
agricultural soil C stocks, and therefore a short description of this method compared to the IPCC approach is
provided.
The Century ecosystem model has been widely tested and found to be successful in simulating those processes
affecting SOC storage (Metherell et al. 1993, Parton et al. 1994). Simulation modeling differs from the IPCC
approach in that annual changes are computed dynamically as a function of inputs of C and N to soil (e.g., crop
residues, manure) and C emissions from organic matter decomposition, which are governed by climate and soil
factors as well as management practices. The model distinguishes between all major field crops (maize, wheat and
other small grains, soybean, sorghum, cotton) as well as hay and pasture (grass, alfalfa, clover). Management
vanables include tillage, fertilization, irrigation, drainage, and manure addition.
Input data are largely derived from the same sources as the IPCC-based method (i.e., climate variables come from
the Parameter-Evaluation Regressions on Independent Slopes Models (PRISM) database; crop rotation, irrigation
and soil charactenstics from the National Resources Inventory (NRI); and tillage data from the Conservation
Technology Information Center (CTIC)). In addition, the Century analysis uses detailed information on crop
rotation-specific fertilization 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 are 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, are not included. Thus, the
total area included in the Century analysis (149 million hectares) will be 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 C sink. The Century model estimates that U.S. cropland soils
sequestered an average of approximately 77 Tg CO2 Eq. annually (21 Tg C/year) for 1992 through 1997. Organic
soils (which contribute large C losses) have not yet been simulated by Century.
As with the IPCC method, increases in mineral SOC 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, contributing to increasing SOC stocks. Work is underway 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 C
change. This would facilitate annual estimates of SOC stock changes and CO2 emissions from soils that would
better reflect mterannual variability in cropland production and weather influences on C cycle processes.
7.4. Lands Converted to Croplands (Source Category 5B2)
Land-use change is constantly occurring, and areas under a number of differing land use types are converted to
croplands each year, just as croplands are converted to other uses. However, while the C stocks for Land Converted
to Cropland are included in the Croplands Remaining Croplands section, it is not possible to sub-divide it and
determine the magnitude of the change at this time. Additionally, given the lack of available land use information
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 249
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relevant to this particular IPCC source category, it is not possible to quantify the N2O flux from Lands Converted to
Cropland at this time.
7.5. Settlements Remaining Settlements
Changes in Yard Trimming and Food Scrap Carbon Stocks in Landfills (IPCC Source
Category 5E1)
As is the case with carbon in landfilled forest products, carbon contained in landfilled yard trimmings and food
scraps can be stored for very long periods. In the United States, yard trimmings (i.e., grass clippings, leaves, and
branches) and food scraps comprise a significant portion of the municipal waste stream, and a large fraction of the
collected yard trimmings and food scraps are discarded in landfills. However, both the amount of yard trimmings
and food scraps collected annually and the fraction that is landfilled have declined over the last decade. In 1990,
nearly 51 million metric tons (wet weight) of yard trimmings and food scraps were generated (i.e., put at the curb
for collection or taken to disposal or composting facilities) (EPA 2003). Since then, programs banning or
discouraging disposal have led to an increase in backyard composting and the use of mulching mowers, and a
consequent 20 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 34 percent in 2003. There is considerably less centralized
composting of food scraps; generation has grown by 26 percent since 1990, though the proportion of food scraps
discarded in landfills has decreased slightly from 81 percent in 1990 to 77 percent in 2003. Overall, there has been
a decrease in the yard trimmings and food scrap landfill disposal rate, which has resulted in a decrease in the rate of
landfill carbon storage to 10.1 Tg CO2 Eq. in 2003 from 26.0 Tg CO2 Eq in 1990 (Table 7-16 and Table 7-17).
Table 7-16: Net Changes in Yard Trimming and Food Scrap Stocks in Landfills (Tg CO2 Eq.)
Carbon Pool 1990 •>:~\^.^ 1996 1997 1998 1999 2000 2001 2002 2003
Yard Trimmings
Grass
Leaves
Branches
Food Scraps
Total Net Flux
(23.2) ;j ;:/?;;
(2.5);;::-:k&-
(ii.2)::>::,^
(9.6)^.::.;;
(2.8) ::.,;•;•;•:
(26.0) iiU
^:: (H.3)
^'- (1-0)
? : (5.9)
••.-: (4.4)
vvv (2.2)
iii (13.5)
(10.4)
(0.9)
(5.4)
(4.0)
(2.6)
(12.9)
(9.6)
(0.8)
(5.1)
(3.7)
(2.9)
(12.5)
(8.5)
(0.7)
(4.5)
(3.2)
(2.9)
(11.4)
(7.2)
(0.6)
(4.0)
(2.6)
(3.0)
(10.2)
(7.4)
(0.7)
(4.0)
(2.7)
(2.9)
(10.3)
(7.5)
(0.7)
(4.0)
(2.7)
(2.7)
(10.2)
(7.5)
(0.7)
(4.0)
(2.8)
(2.6)
(10.1)
Note: Totals may not sum due to independent rounding.
Table 7-17: Net Changes in Yard Trimming and Food Scrap Stocks in Landfills (Tg C)
Carbon Pool
Yard Trimmings
Grass
Leaves
Branches
Food Scraps
Total Net Flux
1990
(6.3)-;::-j:,
(0.7) -;;:-•, :
(3.0) ;£H^
(2.6)^,;,;
(0.8):: S i;
(7.1) :v;^:x
1996
V (3.1)
:i:;- (0.3)
3: (1-6)
-;; (i.2)
r (0.6)
^ (3.7)
1997
(2.8)
(0.2)
(1.5)
(1-1)
(0.7)
(3.5)
1998
(2.6)
(0.2)
(1.4)
(1.0)
(0.8)
(3.4)
1999
(2.3)
(0.2)
(1.2)
(0.9)
(0.8)
(3.1)
2000
(2.0)
(0.2)
(1.1)
(0.7)
(0.8)
(2.8)
2001
(2.0)
(0.2)
(1.1)
(0.7)
(0.8)
(2.8)
2002
(2.0)
(0.2)
(1.1)
(0.7)
(0.7)
(2.8)
2003
(2.0)
(0.2)
(1.1)
(0.8)
(0.7)
(2.7)
Note: Totals may not sum due to independent rounding.
Methodology
Estimates of net carbon flux resulting from landfilled yard trimmings and food scraps were developed by estimating
the change in landfilled carbon stocks between inventory years. Carbon stock estimates were calculated by
determining the mass of landfilled carbon resulting from yard trimmings or food scraps discarded in a given year;
adding the accumulated landfilled carbon from previous years; and subtracting the portion of carbon landfilled in
previous years that decomposed.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 250
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To determine the total landfilled carbon stocks for a given year, the following were estimated: 1) the composition of
the yard trimmings, 2) the mass of yard trimmings and food scraps discarded in landfills, 3) the carbon storage
factor of the landfilled yard trimmings and food scraps, and 4) the rate of decomposition of the degradable carbon.
The composition of yard trimmings was assumed to be 30 percent grass clippings, 40 percent leaves, and 30 percent
branches on a wet weight basis (Oshins and Block 2000). The yard trimmings were subdivided because each
component has its own unique carbon storage factor and rate of decomposition. The mass of yard trimmings and
food scraps disposed of in landfills was estimated by multiplying the quantity of yard trimmings and food scraps
discarded by the proportion of discards managed in landfills. Data on discards (i.e., the amount generated minus the
amount diverted to centralized composting facilities) for both yard trimmings and food scraps were taken primarily
from Municipal Solid Waste in the United States: 2001 Facts and Figures (EPA 2003). That report provides data
for 1 960, 1 970, 1 980, 1 990, 1 995, and 1 999 through 200 1 . To provide data for some of the missing years in the
1990 through 1 999 period, two earlier reports were used (Characterization of Municipal Solid Waste in the United
States: 1998 Update (EPA 1999), and Municipal Solid Waste in the United States: 2000 Facts and Figures (EPA
2002)). Remaining years in the time series for which data were not provided were estimated using linear
interpolation, except for 2002 and 2003, which was assumed to have the same discards as 2001 . These reports do
not subdivide discards of individual materials into volumes landfilled and combusted, although they provide an
estimate of the proportion of overall wastestream discards managed in landfills and combustors (i.e., ranging from
81 percent and 19 percent respectively in 1990, to 79 percent and 21 percent in 2001).
The amount of carbon disposed of in landfills each year, starting in 1960, was estimated by converting the discarded
landfilled yard trimmings and food scraps from a wet weight to a dry weight basis, and then multiplying by the
initial (i.e., pre -decomposition) carbon content (as a fraction of dry weight). The dry weight of landfilled material
was calculated using dry weight to wet weight ratios (Tchobanoglous et al. 1993 cited by Barlaz 1998) and the
initial carbon contents were determined by Barlaz (1998) (Table 7-18).
The amount of carbon remaining in the landfill for each subsequent year was tracked based on a simple model of
carbon fate. According to Barlaz (1998), a portion of the initial carbon resists decomposition and is essentially
persistent in the landfill environment; the modeling approach applied here builds on his findings. Barlaz (1998)
conducted a series of experiments designed to measure biodegradation of yard trimmings, food scraps, and other
materials, in conditions designed to promote decomposition (i.e., by providing ample moisture and nutrients). After
measuring the initial carbon content, the materials were placed in sealed containers along with a "seed" containing
methanogenic microbes from a landfill. Once decomposition was complete, the yard trimmings and food scraps
were re-analyzed for carbon content. The mass of carbon remaining, divided by the original dry weight of the
material, was reported as the carbon storage factor (Table 7-18).
For purposes of simulating U.S. landfill carbon flows, the carbon storage factors are divided by the initial carbon
content to determine the proportion of initial carbon that does not decompose. The remaining portion is assumed to
degrade (and results in emissions of CH4 and CO2). For example, for branches Barlaz (1998) reported the carbon
storage factor as 38 percent (of dry weight), and the initial carbon content as 49 percent (of dry weight). Thus, the
proportion of initial carbon that does not decompose is 77 percent (i.e., 0.38/0.49). The remaining 23 percent
degrades.
The degradable portion of the carbon is assumed to decay according to first order kinetics. Grass and food scraps
are assumed to have a half-life of 5 years; leaves and branches are assumed to have a half-life of 20 years.
For each of the four materials (grass, leaves, branches, food scraps), the stock of carbon in landfills for any given
year is calculated according to the following formula:
where,
LFCi,t = L Wu * (1 - MQ) * ICQ * {[CSF, / ICQ] + [(1 - (CSF, / ICQ )) * e'k*(t-n) ]}
t = the year for which carbon stocks are being estimated,
LFC it = the stock of carbon in landfills in year t, for waste /' (grass, leaves, branches, food scraps)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 251
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W; n = the mass of waste /' disposed in landfills in year n, in units of wet weight
n = the year in which the waste was disposed, where 1960 < n < t
MQ = moisture content of waste /',
ICQ = the initial carbon content of waste /',
CSF; = the carbon storage factor of waste /',
e = the natural logarithm, and
k = the first order rate constant for waste /', and is equal to 0.693 divided by the half-life for
decomposition.
For a given year t, the total stock of carbon in landfills (TLFCt) is the sum of stocks across all four materials. The
annual flux of carbon in landfills (Ft) for year t is calculated as the change in stock compared to the preceding year:
Ft= TLFQ - TLFCt_!
Thus, the carbon placed in a landfill in year n is tracked for each year t through the end of the inventory period
(2003). For example, disposal of food scraps in 1960 resulted in depositing about 1,140,000 metric tons of carbon.
Of this amount, 16 percent (180,000 metric tons) is persistent; the remaining 84 percent (960,000 metric tons) is
degradable. By 1965, half of the degradable portion (480,000 metric tons) decomposes, leaving a total of 660,000
tonnes (the persistent portion, plus the remaining half of the degradable portion).
Continuing the example, by 2003, the total food scraps carbon originally disposed in 1960 had declined to 181,000
metric tons (i.e., virtually all of the degradable carbon had decomposed). By summing the carbon remaining from
1960 with the carbon remaining from food scraps disposed in subsequent years (1961 through 2003), the total
landfill carbon from food scraps in 2003 was 29.3 million metric tons. This value is then added to the carbon stock
from grass, leaves, and branches to calculate the total landfill carbon stock in 2003, yielding a value of 241.6
million metric tons (as shown in Table 7-19). In exactly the same way total net flux is calculated for forest carbon
and harvested wood products, the total net flux of landfill carbon for yard trimmings and food scraps for a given
year (Table 7-17) is the difference in the landfill carbon stock for a given year and the stock in the preceding year.
For example, the net change in 2003 shown in Table 7-17 (2.7 Tg C) is equal to the stock in 2003 (241.6 Tg C)
minus the stock in 2002 (238.9 Tg C).
When applying the carbon storage factor data reported by Barlaz (1998), an adjustment was made to the reported
value for leaves, because the carbon storage factor was higher than the initial carbon content. This anomalous
result, probably due to errors in the laboratory measurements, was addressed by applying a mass balance
calculation, and assuming that (a) the initial carbon content was correctly measured, and (b) the carbon storage
factor was incorrect. The same experiment measured not only the persistence of carbon (i.e., the carbon storage
factor), but also the yield of methane for each of the individual waste materials (Eleazer et al. 1997). The anaerobic
decomposition process results in release of equal molar volumes of CH4 and CO2. Thus, to derive a more realistic
estimate of the carbon storage factor for leaves, the carbon released in the form of methane during decomposition
was multiplied by two (to include the loss of carbon through CO2, which is generated in approximately equal molar
amounts as CH4), and then subtracted from the initial carbon content of the leaves. This estimate of carbon
remaining was used to derive the carbon storage factor (0.46).
Table 7-18: Moisture Content (%), Carbon Storage Factor, Initial Carbon Content (%), Proportion of Initial Carbon
Sequestered (%), and Half-Life (years) for Landfilled Yard Trimmings and Food Scraps in Landfills
Yard Trimmings
Variable
Moisture Content (% H2O)
CSF (kg C sequestered / dry kg waste)
Initial Carbon Content (%)
Proportion of initial carbon sequestered (%)
Half-life (years)
Grass
70
0.32
45
71
5
Leaves
30
0.46a
49
94
20
Branches
10
0.38
49
77
20
Food Scraps
70
0.08
51
16
5
"Adjusted using CH4 yields in Eleazer et al. (1997).
Table 7-19: Carbon Stocks in Yard Trimmings and Food Scraps in Landfills (Tg C)
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Carbon Pool
Yard Trimmings
Grass
Leaves
Branches
Food Scraps
Total Carbon
Stocks
1990 ?
167.8 5
i8.8i! ;
78.7 ;;K-
70.3;-;.
20.3
188.1 V
1996
i 196.5
- 21.7
••: 92.9
81.9
24.0
:• 220.5
1997
199.3
21.9
94.3
83.0
24.7
224.0
1998
201.9
22.2
95.7
84.0
25.5
227.4
1999
204.2
22.4
97.0
84.9
26.3
230.5
2000
206.2
22.5
98.0
85.6
27.1
233.3
2001
208.2
22.7
99.1
86.4
27.9
236.1
2002
210.2
22.9
100.2
87.1
28.6
238.9
2003
212.3
23.1
101.3
87.9
29.3
241.6
Note: Totals may not sum due to independent rounding.
Uncertainty
The estimation of carbon storage in landfills is directly related to the following yard trimming and food scrap data
and factors: disposal in landfills per year (tons of carbon), initial carbon content, moisture content, decomposition
rate (half-life), and proportion of carbon stored. The carbon storage landfill estimates are also a function of the
composition of the yard trimmings (i.e. the proportions of grass, leaves and branches in the yard trimmings
mixture). There are uncertainties associated with each of these factors.
The uncertainty ranges were assigned based on expert judgment and are assumed to be uniformly distributed around
the inventory estimate (e.g., +10 percent), except for the values for decomposition rate, proportion of carbon stored,
and moisture content for branches.
The uncertainty ranges associated with the input variables for the proportion of grass and leaves in yard trimmings,
as well as the initial carbon content and moisture content for grass, leaves, and food scraps (all expressed as
percentages in the calculations for the inventory) were plus or minus 10 percent. For the moisture content of
branches (where the inventory estimate is 10 percent), the uncertainty range was assumed to be 5 to 30 percent.
The uncertainty ranges associated with the disposal of grass, leaves, branches, and food scraps were bound at 50
percent to 150 percent times the inventory estimates. The half-life of grass and food scraps were assumed to range
from 1 to 20 years, and the half-lives of leaves and branches were assumed to range from 5 to 30 years. Finally, the
proportion of carbon stored in grass, leaves, branches, and food scraps was assumed to vary by the addition of 20
percent or subtraction of 10 percent from the best estimate, with an upper bound of 100 percent and a lower bound
of 0 percent.
A Monte Carlo (Tier 2) uncertainty analysis was then applied to estimate the overall uncertainty of the sequestration
estimate. The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 7-20. Total yard
trimmings and food scraps CO2 flux in 2003 was estimated to be between -17.5 and -7.0 Tg CO2 Eq. at a 95 percent
confidence level (or 19 of 20 Monte Carlo Stochastic Simulations). This indicates a range of 73 percent below to 31
percent above the 2003 flux estimate of -10.1 Tg CO2 Eq.
Table 7-20: Tier 2 Quantitative Uncertainty Estimates for CO2 Flux from Yard Trimmings and Food Scraps in
Landfills (Tg CO2 Eq. and Percent)
Source
Yard Trimmings
Food Scraps
Total
Gas
C02
CO,
CO2
2003 Flux
Estimate
(Tg C02 Eq.)
(7.5)
(2.6)
(10.1)
Uncertainty Range Relative to Flux Estimate"
(Tg C02 Eq.) (%)
Lower
Bound
(11.3)
(8.9)
(17.5)
Upper
Bound
(4.4)
(1.2)
(7.0)
Lower
Bound
-51%
-246%
-73%
Upper
Bound
+41%
+54%
+31%
aRange of flux estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Negative values indicate net carbon storage (positive values denote emissions).
The uncertainty of the landfilled carbon storage estimate arises from the disposal data and the factors applied to the
following data.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 253
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Disposal per Year (tons of carbon)
A source of uncertainty affecting CO2 sequestration is the estimate of the tonnage of yard trimmings and food scraps
which are disposed of in landfills each year. Of all the individual inputs tested for sensitivity in the uncertainty
analysis, net carbon storage in landfills is most sensitive to the estimate of the food scrap disposal rate. The
estimates for yard trimming and food scrap disposal in landfills are determined using data from the EPA (1999,
2002, 2003) estimates of materials generated, discarded, and combusted, which carry considerable uncertainty
associated with the wastestream sampling methodology used to generate them.
Moisture Content and Initial Carbon Content
Moisture content, and to a lesser extent carbon content, vary widely. Moisture content for a given sample of waste
can be affected by the precipitation conditions when the waste is placed at the curb for collection, as well as the
status and condition of the landfill cover. Carbon content (on a dry weight basis) is a function of the specific waste
constituents (e.g., oak leaves versus pine needles or banana peels versus bacon grease), which in turn vary
temporally, geographically, and demo graphic ally (i.e., characteristics of households in the wasteshed).
Decomposition Rate
Although several investigators have made estimates of the decomposition rate of mixed solid waste in a landfill
environment, there are no known studies of decomposition rates for individual materials in actual landfills, and thus
the inventory estimate is based on assumed values. The uncertainty analysis indicates that the results are sensitive
to decomposition rates, especially the food scraps half-life, and thus the decomposition rates introduce considerable
uncertainty into the analysis.
Proportion of Carbon Stored
The estimate of the proportion of carbon stored is based on a set of experiments measuring the amount of carbon
persisting in conditions promoting decomposition. Because these experiments have only used conditions conducive
to decomposition, they are more likely to underestimate than to overestimate carbon storage. Thus, the uncertainty
analysis used asymmetrical values (up to 10 percent less storage, up to 20 percent more storage) as inputs.
Several of the planned improvements to the analysis, described later in this section, are intended to reduce the
uncertainty associated with these factors.
Recalculations Discussion
While conducting quality control procedures, it was found that the 1994 value for the amount of discards that are
landfilled (or disposed of by means other than combustion) had been incorrectly recorded. The error was corrected,
resulting in reduced carbon storage values by less than 1.0 Tg C for the years 1994 through 2003. Overall, this
change, in combination with historical data revisions, resulted in an average annual decrease of 0.2 Tg CO2 Eq. (0.7
percent) in carbon sequestration from yard trimming and food scraps over the period 1990 through 2002.
Planned Improvements
As noted above, the estimates presented in this section are driven by a small carbon storage factor data set, and
some of these measurements (especially for leaves) deserve close scrutiny. There are ongoing efforts to conduct a
re-analysis of the leaves experiment, using the same techniques as in the original experiments cited, and future work
may evaluate the potential contribution of inorganic carbon to landfill sequestration and to assure consistency
between the estimates of carbon storage described in this chapter and the estimates of landfill CH4 emissions
described in the Waste chapter.
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Changes in Carbon Stocks in Urban Trees (IPCC Source Category 5E1)
Urban forests constitute a significant portion of the total U.S. tree canopy cover (Dwyer et al. 2000). Urban areas
(cities, towns, and villages), which cover 3.5 percent of the continental United States, are estimated to 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 (Nowak et al. 2001). Trees in urban areas of the
continental United States were estimated by Nowak and Crane (2002) to account for an average annual net
sequestration of 58.7 Tg CO2 Eq. (16 Tg C). These data were collected throughout the 1990s, and have been
applied to the entire time series in this report (see Table 7-21). Annual estimates of CO2 flux have not been
developed, but are believed to be relatively constant from 1990 through 2003.
Net carbon flux from urban trees is proportionately greater on an area basis than that of forests. This trend is
primarily the result of different net growth rates in urban areas versus forests—urban trees often grow faster than
forest trees because of the relatively open structure of the urban forest (Nowak and Crane 2002). Also, areas in
each case are accounted for differently. Because urban areas contain less tree coverage than forest areas, the carbon
storage per hectare of land is in fact smaller for urban areas. However, urban tree reporting occurs on a per unit tree
cover basis (tree canopy area), rather than total land area. Urban trees therefore appear to have a greater carbon
density than forested areas (Nowak and Crane 2002).
Table 7-21: Net C Flux from Urban Trees (Tg CO2Eq. and Tg C)
Year Tg CO2 Eq. Tg C
1990 (58.7) (16)
1997
1998
1999
2000
2001
2002
2003
(58,7)
(58.7)
(58.7)
(58.7)
(58.7)
(58.7)
(58.7)
(16)
(16)
(16)
(16)
(16)
(16)
(16)
Note: Parentheses indicate net sequestration.
Methodology
The methodology used by Nowak and Crane (2002) 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 the default IPCC methodology in the IPCC LULUCF Good Practice Guidance (IPCC 2003),
although sufficient data are not yet available to determine interannual changes in carbon stocks in the living biomass
of urban trees.
Nowak and Crane (2002) 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, NT; 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 field data from the 10 cities, some of which are unpublished, are
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 255
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described in Nowak and Crane (2002) 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 2002). 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.
Annual gross carbon emission estimates were derived by applying estimates of annual mortality and condition, and
assumptions about whether dead trees were removed from the site, to carbon stock estimates. These values were
derived as intermediate steps in the sequestration calculations, and different decomposition rates were applied to
dead trees left standing compared with those removed from the site. 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. 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 2002).
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.9 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. The urban areas are based on 1990 U.S. Census data, which define "urban
land" as areas having a population density greater than 1,000 people per square mile and adjacent urban places, with
predefined political boundaries, having a 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. The 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).
Table 7-22: Carbon Stocks (Metric Tons C)
(Percent), and Annual Carbon Sequestration
, Annual Carbon Sequestration (Metric Tons C/yr), Tree Cover
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
Carbon Gross Annual Net Annual
Stocks Sequestration Sequestration
1,225,200
1,220,200
1,107,300
854,800
528,700
481,000
289,800
148,300
145,800
38,400
42,100
20,200
40,100
14,800
14,600
9,500
4,700
NA
20,800
32,200
NA
NA
10,800
10,700
6,900
3,500
NA
Gross Annual Net Annual
Tree Sequestration per Sequestration per
Cover Area of Tree Cover Area of Tree Cover
20.9
36.7
13.0
11.0
25.2
15.7
22.3
24.4
21.0
0.23
0.34
0.66
0.61
0.28
0.27
0.30
0.30
NA
0.12
0.26
NA
NA
0.20
0.20
0.22
0.22
NA
Three cities did not have net estimates.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 256
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Jersey City, NJ
19,300
800
600
11.5
0.18
0.13
NA = not analyzed
Uncertainty
The only quantifiable uncertainty associated with changes in C stocks in urban trees was sampling, as reported by
Nowak and Crane (2002). The average standard deviation for urban tree carbon storage was 27 percent of the mean
carbon storage on an area basis. Additionally, a 5 percent uncertainty was associated with national urban tree
covered area. These estimates are based on field data collected in ten U.S. cities, and uncertainty in these estimates
increases as they are scaled up to the national level.
There is additional uncertainty associated with the biomass equations, conversion factors, and decomposition
assumptions used to calculate carbon sequestration and emission estimates (Nowak et al. 2002). These results also
exclude 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). Because these are inestimable, they are not
quantified as part of this analysis.
The results of the Tier 1 quantitative uncertainty analysis are summarized in Table 7-23. Net C flux from changes
in C stocks in urban trees was estimated to be between -80.3 and -37.0 Tg CO2 Eq. at a 95 percent confidence level.
This indicates a range of 37 percent above and below the 2003 flux estimate of -58.7 Tg CO2 Eq.
Table 7-23: Tier 1 Quantitative Uncertainty Estimates for Net C Flux from Changes in Carbon Stocks in Urban
Trees (Tg CO2 Eq. and Percent)
2003 Flux
Source Gas Estimate
(TgC02Eq.)
Uncertainty Range Relative to
Uncertainty 2003 Flux Estimate
(%) (Tg CO2 Eq.)
Lower Bound Upper Bound
Changes in C Stocks
in Urban Trees
CO,
(58.7)
37%
(80.3)
(37.0)
Note: Parentheses indicate net sequestration.
QA/QC and Verification
The net carbon flux resulting from urban trees was calculated using estimates of gross and net carbon sequestration
estimates for urban trees and urban tree coverage area found in literature. The validity of these data for their use in
this section of the Inventory was evaluated through correspondence established with an author of the papers.
Through the correspondence, the methods used to collect the urban tree sequestration and area data were further
clarified and the use of these data in the Inventory was reviewed and validated (Nowak 2002).
Planned Improvements
Some sources indicate a reduction in urban tree coverage in the United States over the Inventory period of
approximately 21 percent over the last 10 years (AF 2004). However, because the methods for making this
assertion have not yet been made available and their definition of urban land is unclear, the veracity and potential
application of this estimate cannot currently be established. Because the magnitude of the urban tree greenhouse
gas sink in the United States is not insignificant, identifying changes in this sector is considered a priority and is
being actively pursued for inclusion in future Inventories. Should this diminishment prove to be accurate, it could
mean the urban tree sink estimates will need to be significantly revised.
Changes in Soil Carbon Stocks (IPCC Source Category 5E1)
Given the lack of available land use information relevant to this particular IPCC source category, it is not possible to
quantify the CO2 flux from soils in Settlements Remaining Settlements at this time.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 257
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N20 Fluxes from Soils (IPCC Source Category 5E1)
Of the fertilizers applied to soils in the United States, approximately 10 percent are applied to lawns, golf courses,
and other landscaping occurring within settled areas. Application rates are less than those occurring on cropped
soils, and therefore account for a smaller proportion of total U.S. soil N2O emissions per unit area. In 2003, N2O
emissions from this source were 6.0 Tg CO2 Eq. (19.4 Gg N2O). There was an overall increase of 9 percent over
the thirteen year period due to a general increase in the application of synthetic fertilizers. Interannual variability in
these emissions is directly attributable to interannual variability in total synthetic fertilizer consumption in the
United States.
Emissions from this source are summarized in Table 7-24.
Table 7-24: N2O Fluxes from Soils in Settlements Remaining Settlements (Tg CO2 Eq.)
Settlements Remaining Settlements: N2O |
Fluxes from Soils 1990! I 1997 1998 1999 2000 2001 2002 2003
TgC02
Gg
Eq.
5.
17
.5
.9;
! 6.1
1 19.8
6.1
19.8
6.
19.
2
9
6.0
19.3
5.8
18.7
6.0
19.4
6.0
19.4
Methodology
Estimates of direct N2O emissions from soils in settlements were based on the amount of N applied to turf grass
annually through the application of synthetic commercial fertilizers. Nitrogen applications to turf grass are assumed
to be 10 percent of the total synthetic fertilizer used in the United States (Qian 2004). Total synthetic fertilizer
applications were derived from fertilizer statistics (TVA 1991, 1992, 1993, 1994; AAPFCO 1995, 1996, 1997,
1998, 1999, 2000b, 2002, 2003, 2004) and a recent AAPFCO database (AAPFCO 2000a). Unvolatilized N applied
to turf grass was multiplied by the IPCC default emission factor (1.25 percent) to estimate direct N2O emissions.
The volatilized and leached/runoff proportion, calculated with the IPCC default volatilization factor of 10 percent
and 30 percent, respectively, for synthetic fertilizers, was included with the total N contributions to indirect
emissions, as reported in the N2O Emissions from Agncultural Soil Management source category of the Agriculture
sector.
Uncertainty
The amount of N2O emitted from settlements 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, temperature, and
irrigation/watering practices. The effect of the combined interaction of these variables on N2O flux is complex and
highly uncertain. The IPCC default methodology used here does not incorporate any of these variables and only
accounts for variations in national fertilizer application rates. All settlement soils are treated equivalently under this
methodology. Furthermore, only synthetic fertilizers are captured, so applications of organic fertilizers are not
accounted for here. Uncertainties exist in both the fertilizer application rates and the emission factors used to derive
emission estimates.
The 95 percent confidence interval for the IPCC's default emission factor for synthetic fertilizer applied to soil
ranges from 0.25 to 6 percent, according to Chapter 4 of IPCC (2000). While a Tier 1 analysis should be generated
from a symmetrical distribution of uncertainty around the emission factor, an asymmetrical distribution was
imposed here to account for the fact that the emission used was not the mean of the range given by IPCC.
Therefore, an upper bound of 480 percent and a lower bound of 80 percent were assigned to the emission factor.
The higher uncertainty percentage is shown below, but the lower bound reflects a truncated distribution. The
uncertainty in the amount of synthetic fertilizer N applied to settlement soils was conservatively estimated to be 50
percent (Qian 2004). The results of the Tier 1 quantitative uncertainty analysis are summarized in Table 7-25. N2O
emissions from soils in settlements remaining settlements in 2003 were estimated to be between 0.3 and 35.1 Tg
CO2 Eq. at a 95 percent confidence level. This indicates a range of 94 percent below to 483 percent above the 2003
emission estimate of 6.0 Tg CO2 Eq.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 258
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Table 7-25: Tier 1 Quantitative Uncertainty Estimates of N2O Emissions from Soils in Settlements Remaining
Settlements (Tg CO2 Eq. and Percent)
IPCC Source
Category
Gas
Year 2003 Uncertainty Range Relative to
Emissions Uncertainty 2003 Emission Estimate
(Tg C02 Eq.) (%) (Tg C02 Eq.)
Lower Bound Upper Bound
Settlements Remaining
Settlements: N2O
Fluxes from Soils
N,0
6.0
94 to 483%
0.3
35.1
Recalculations Discussion
The current Inventory presents N2O emissions from soils in settlements separately for the first time. Previously,
N2O emissions from this source were included with N2O emissions from agricultural soils. The net effect of
separating this source from agricultural soils is to reduce emissions reported from that source. However, because
the methods for reporting that source category have changed significantly this year, it is not possible to isolate the
magnitude of change caused by this recalculation alone on the overall differences in N2O emissions from
agricultural soils.
Planned Improvements
The process-based model DAYCENT, which was used to estimate N2O emissions from cropped soils this year,
could also be used to simulate emissions as well as volatilization and leaching/runoff from settlements. DAYCENT
has been parameterized to simulate turf grass. State-level settlement area data is available from the National
Resource Inventory. Future inventories will include DAYCENT simulations to estimate emissions from
settlements.
7.6. Lands Converted to Settlements (Source Category 5E2)
Land-use change is constantly occurring, and land under a number of uses undergoes urbanization in the United
States each year. However, data on the amount of land converted to settlements is currently lacking. Given the lack
of available information relevant to this particular IPCC source category, it is not possible to quantify CO2 or N2O
fluxes from lands converted to settlements at this time.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 259
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Figure 7-1
Forest Sector Carbon Pools and Flows
Legend
Q Carbon Pool
—>• Carbon transfer or flux
Combustion
Source: Heath et al. 2003
-------
Year
50
i -50
s
I -100
15 -150
z
I -200
&
oc
1 -250
-300
Soil
Harvested Wood
Forest, nonsoil
Total Net Change
Figure 7-2: Estimates of Net Annual Changes in Carbon Stocks for Major Carbon Pools
-------
Figure 7-3
Average Carbon Density in the Forest Tree Pool in the Conterminous U.S. During 2004
*** If-
Total Forest Tree
Pool Carbon
(l/ha)
Note: Estimates are based on forest inventory data as described in the text.
-------
Figure 7-4
Net Annual CO, Flux, per Hectare, From Mineral Soils Under Agricultural Management, 1990-1992
33$
v-«;
r - -imnn^;|
j?
Note: Values greater than zero represent
emissions and values less than zero
represent sequestration. Map accounts
only for fluxes in agricultural soils and does
not include SOC storage resulting from
sewage sludge amendments in any year.
metric ton C02/ha
|| < -0.5
| |-0.5 to-0.25
-0.25 to -0.01
| | -0.01 to 0
>o
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 7-5
Net Annual CO, Flux, per Hectare, From Mineral Soils Under Agricultural Management, 1993-2003
represent sequestration. Map accounts
only for fluxes in agricultural soils and does
not include SOC storage resulting from sewage
sludge amendments in any year, or CRP
enrollment and manure management after 1997.
metric ton C02/ha
|| < -0.3
|| -0.5 to -0.25
-0.25 to -0.01
| | -0.01 to 0
>o
This map shows the spatial variability in net annual carbon dioxide flux from mineral soils for the year 1993 through 2003.
The color assigned to each polygon represents the average annual flux per hectare for the area of managed mineral soils in that polygon.
-------
Figure 7-6
Net Annual CO, Flux, per Hectare, From Organic Soils Under Agricultural Management, 1990-1992
metric ton C02/ha
| | no organic soils
| |0to5
| | 5 to 25
BB1>25
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 7-7
Net Annual C02 Flux, per Hectare, From Organic Soils Under Agricultural Management, 1993-2003
metric ton C02/ha
| | no organic soils
| | Oto5
| | 5 to 25
>25
This map shows the spatial variability in net annual carbon dioxide flux from organic soils for the year 1993 through 2003.
The color assigned to each polygon represents the average annual flux per hectare for the area of managed organic soils in that polygon.
-------
-------
8. Waste
Waste management and treatment activities are sources of greenhouse gas emissions (see Figure 8-1). Landfills
were the largest source of anthropogenic methane (CH4) emissions, accounting for 24 percent of total U.S. CH4
emissions.l 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 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 and ambient air pollutant emissions from the Waste chapter is presented in Table 8-1 and Table 8-2.
Figure 8-1: 2003 Waste Chapter Greenhouse Gas Sources
Overall, in 2003, waste activities generated emissions of 183.8 Tg CO2 Eq., or 2.6 percent of total U.S. greenhouse
gas emissions.
Table 8-1: Emissions from Waste (Tg CO2 Eq.)
Gas/Source 1990 "'-&/ 1997 1998 1999 2000 2001 2002 2003
CH4
Landfills
Wastewater Treatment
N2O
Human Sewage
197.1
172.2
24.8
13.0
13.0
? 179.0
•-Y; 147.4
'--;', 31.7
>•'';• I4-7
>'•;'.- 14.7
171.0
138.5
32.6
15.0
15.0
167.7
134.0
33.6
15.4
15.4
165.0
130.7
34.3
15.6
15.6
160.9
126.2
34.7
15.6
15.6
162.6
126.8
35.8
15.7
15.7
167.9
131.2
36.8
15.9
15.9
Total 210.1
193.7 186.0 183.1 180.6 176.5 178.3 183.8
Note: Totals may not sum due to independent rounding.
Table 8-2: Emissions from Waste (Gg)
Gas/Source
CH4
Landfills
Wastewater Treatment
N2O
Human Sewage
NOX
CO
NMVOCs
1990
9,385
8,202
1,183
42
42
+
1
673
/ 1997
v'. 8,526
it 7,017
:v4r 1,509
47
'i\', 47
'•''';«•"' 3
;•:":;•; 5
:i ; , 157
1998
8,145
6,595
1,550
48
48
3
5
161
1999
7,984
6,382
1,602
50
50
3
13
140
2000
7,858
6,223
1,635
50
50
2
8
119
2001
7,660
6,010
1,651
50
50
2
8
122
2002
7,744
6,039
1,705
51
51
2
8
133
2003
7,997
6,246
1,751
51
51
2
8
125
Note: Totals may not sum due to independent rounding.
8.1. Landfills (IPCC Source Category 6A1)
Landfills are the largest anthropogenic source of CH4 emissions in the United States. In 2003, landfill CH4
emissions were approximately 131 Tg CO2 Eq. (6,246 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. Approximately 1,800
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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 261
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operational landfills exist in the United States (BioCycle 2004), 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 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 2003, net CH4 emissions from landfills decreased by approximately 24 percent (see Table 8-3 and
Table 8-4), with small increases occurring in some interim years. This 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 an increase in the amount of municipal solid waste landfilled.
Methane emissions from landfills are a function of several factors, including: (1) the total amount of municipal
solid waste in landfills, which is related to total municipal solid waste landfilled annually; (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 CH4 oxidized in landfills instead of being
released into the atmosphere. The estimated annual quantity of waste placed in landfills increased from about 209
Tg in 1990 to 279 Tg in 2003, an increase of 33 percent (see Annex 3.14). During this period, the estimated CH4
recovered and combusted from landfills increased as well. In 1990, for example, approximately 935 Gg of CH4
were recovered and combusted (i.e., used for energy or flared) from landfills. In 2003, the estimated quantity of
CH4 recovered and combusted increased to 5,545 Gg.
Over the next several years, the total amount of municipal solid waste 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 federal regulation that requires large municipal solid waste landfills to collect and combust
landfill gas (see 40 CFR Part 60, Subparts Cc 2002), and the Landfill Methane Outreach Program (LMOP), an EPA
program that encourages voluntary CH4 recovery and use at landfills not affected by the regulation.
Table 8-3: CH4 Emissions from Landfills (Tg CO2 Eq.)
Activity
MSW Landfills
Industrial Landfills
Recovered
Gas-to-Energy
Flared
Oxidized3
Total
1990 :;>::,
197.2 :-f,;n,
13 8 !';;;*
(140) :;>^
(5 6) ' "v
(19 1) .;»?;
172.2 kSi
1997
215.9
15.1
(34.7)
(32.6)
(16.4)
147.4
1998
219.1
15.3
(42.4)
(38.2)
(15.4)
138.5
1999
222.3
15.6
(48.0)
(41.0)
(14.9)
134.0
2000
226.5
15.9
(51.9)
(45.2)
(14.5)
130.7
2001
231.9
16.2
(57.5)
(50.5)
(14.0)
126.2
2002
238.6
16.7
(59.1)
(55.3)
(14.1)
126.8
2003
245.0
17.2
(61.9)
(54.6)
(14.6)
131.2
Note: Totals may not sum due to independent rounding.
a Includes oxidation at both municipal and industrial landfills.
Table 8-4: CH4 Emissions from Landfills (Gg)
2 The percentage of CO2in 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 typically composed of non-methane volatile
organic compounds (NMVOCs).
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 262
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Activity
MSW Landfills
Industrial Landfills
Recovered
Gas-to-Energy
Flared
Oxidized3
Total
1990
9,391
657
(669)
(266)
(911)
8,202
1997
10,279
720
(1,652)
(1,551)
(780)
7,017
1998
10,435
730
(2,018)
(1,821)
(733)
6,595
1999
10,588
741
(2,287)
(1,951)
(709)
6,382
2000
10,785
755
(2,472)
(2,154)
(691)
6,223
2001
11,045
773
(2,738)
(2,403)
(668)
6,010
2002
11,364
795
(2,814)
(2,635)
(671)
6,039
2003
11,669
817
(2,946)
(2,599)
(694)
6,246
Note: Totals may not sum due to independent rounding.
aIncludes oxidation at municipal and industrial landfills.
Methodology
Methane emissions from landfills were estimated to equal the CH4 produced from municipal solid waste landfills,
minus the CH4 recovered and combusted, plus the CH4 produced by industrial landfills, minus the CH4 oxidized
before being released into the atmosphere:
- [(CH4-MSW - R) + CH4ind]- Ox
Where,
CH4, solid waste = CH4 emissions from solid waste
CH4 MSW = CH4 generation from municipal solid waste landfills,
R = CH4 recovered and combusted,
CH4 ind = CH4 generation from industrial landfills, and
Ox = CH4 oxidized from MSW and industrial landfills before release to the atmosphere.
The methodology for estimating CH4 emissions from municipal solid waste landfills is based on the first order
decay model described in the IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse
Gas Inventories and in a background paper prepared by Jensen and Papatti (2002). Values for the CH4 generation
potential (L0) and rate constant (k) were obtained from an analysis of CH4 recovery rates for a database of 52
landfills and from published studies of other landfills (RTI 2004; EPA 1998; SWANA 1998; Peer, Thorneloe, and
Epperson 1993). The rate constant was found to increase with average annual rainfall; consequently, values of k
were developed for 3 ranges of rainfall. The annual quantity of waste placed in landfills was apportioned to the 3
ranges of rainfall based on the percent of the U.S. population in each of the 3 ranges, and historical census data were
used to account for the shift in population to more arid areas over time. For further information, see Annex 3.14.
National landfill waste generation and disposal data for 1989 through 2003 were obtained from BioCycle (2004).
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 (2004) and national per capita solid waste
generation from BioCycle (2004). Estimates of the annual quantity of waste landfilled for 1960 through 1988 were
obtained from EP A's Anthropogenic Methane Emissions in the United States, Estimates for 1990: Report to
Congress (EPA 1993) and an extensive landfill survey by the EPA's Office of Solid Waste in 1986 (EPA 1988).
Although waste placed in landfills in the 1940s and 1950s contributes very little to current CH4 generation,
estimates for those years were included in the first order decay model for completeness in accounting for methane
generation rates and are based on the population in those years and the per capita rate for land disposal for the
1960s.
The estimated landfill gas recovered per year was based on updated data collected from vendors of flaring
equipment, a database of landfill gas-to-energy (LFGTE) projects compiled by EPA's Landfill Methane Outreach
Program (LMOP), and a database maintained by the Energy Information Administration (EIA) for the voluntary
reporting of greenhouse gases (EIA 2004). The three databases were carefully compared to identify landfills that
were in two or all three of the databases to avoid double-counting reductions. Based on the information provided by
the EIA and flare vendor databases, the CH4 combusted by flares in operation from 1990 to 2003 was estimated.
This quantity likely underestimates flaring, because these databases do not have information on all flares in
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 263
-------
operation. Additionally, the EIA and LMOP databases provided data on landfill gas flow and energy generation for
358 landfills with LFGTE projects. If a landfill in the EIA database was also in the LMOP and/or the flare vendor
database, the emissions avoided were based on the EIA data because landfill owners or operators reported the
amount recovered based on measurements of gas flow and concentration, and the reporting accounted for changes
over time. If both flare data and LMOP recovery data were available for any of the remaining landfills (i.e., not in
the EIA database), then the emissions recovery was based on the LMOP data, which provides reported 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 in
the LMOP database 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 (Mancinelli and McKay 1985;
Czepiel et al. 1996). To calculate net CH4 emissions, both CH4 recovered and CH4 oxidized were subtracted from
CH4 generated at municipal and industrial landfills.
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 the waste placed in every
landfill for each year of its operation—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 CH4 generation potential
and the rate of decay that produces CH4 as determined from several studies of CH4 recovery at landfills are
representative of U.S. landfills and reflects this heterogeneity. Also, the approach used to estimate the contribution
of industrial non-hazardous wastes to total CH4 generation introduces uncertainty. Aside from uncertainty in
estimating CH4 generation potential, uncertainty exists in the estimates of oxidation efficiency.
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 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 189 to 247 Gg total
N between 1990 and 2002. The quantity of sewage sludge applied to landfills decreased from 28 to 11 percent from
1990 to 2001 (EPA 1993).
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 8-5. Landfill CH4 emissions in
2003 were estimated to be between 84.0 and 152.2 Tg CO2 Eq. at a 95 percent confidence level (or in 19 out of 20
Monte Carlo Stochastic Simulations). This indicates a range of 36 percent below to 16 percent above the 2003
emission estimate of 131.2 Tg CO2 Eq.
Table 8-5: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Landfills (Tg CO2 Eq. and Percent)
2003 Emission
Source Gas Estimate Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (Tg C02 Eq.) (%)
J 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.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 264
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Lower Bound Upper Bound Lower Bound Upper Bound
Landfills CH4 131.2 84.0 152.2 -36% +16%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Recalculations Discussion
The estimates for the current inventory are based on the first order decay model rather than the linear regression
model for 30-year waste in place used for previous inventories. The first order decay model was recommended by
U.S. landfill and landfill gas experts and is the preferred approach in the IPCC guidance. Data are now available to
develop reliable estimates of the two parameters needed for the first order decay model: CH4 generation potential
and the first order decay rate constant. In the past, these parameters were considered highly variable, thus making
the first order decay methodology less desirable.
In addition to the change in method, improved estimates of the annual quantity of waste placed in landfills were
developed, particularly for the time period of 1960 through 1988. These two methodological improvements resulted
in a reduction in the estimate of CH4 generation of approximately 20 percent for 1990 and 27 percent for 2002.
About half of this reduction is due to the use of the first order decay model to estimate emissions, while the other
half is due to the improved estimates of the annual quantity of waste placed in landfills.
Another revision was incorporating data from the EIA to improve estimates of emissions avoided by LFGTE
projects and flaring. The use of the EIA data resulted in a decrease of about 11 percent in CH4 emissions avoided
(using 2002 as an example), primarily due to improved estimates for landfills with flares. Changes were also made
to the LFGTE database used to estimate emissions avoided by these projects. The changes included corrections to
megawatt capacity and gas flow rates, adding new projects that started in 2003, and accounting for projects that shut
down. These changes had only a very small effect on emissions avoided by LFGTE projects. Overall, these
changes resulted in an average annual decrease of 52.9 Tg CO2 Eq. (26 percent) in CH4 emissions from landfills for
the period 1990 through 2002.
Planned Improvements
For the future inventories, efforts will be made to improve the estimates of CH4 generation at industrial landfills and
estimates of oxidation, especially for landfills with gas recovery systems. Improvements to the flare database will
be investigated, and an effort will be made to identify additional landfills that have flares. The parameters for the
first order decay model will be re-evaluated as more data become available.
8.2. Wastewater Treatment (IPCC Source Category 6B)
Wastewater from domestic (municipal sewage) and industrial sources is treated to remove soluble organic matter,
suspended solids, pathogenic organisms, and chemical contaminants. Treatment may either occur off-site or on-site.
For example, in the United States, approximately 25 percent of domestic wastewater is treated in septic systems or
other on-site systems. Soluble organic matter is generally removed using biological processes in which
microorganisms consume the organic matter for maintenance and growth. The resulting biomass (sludge) is
removed from the effluent prior to discharge to the receiving stream. Microorganisms can biodegrade soluble
organic material in wastewater under aerobic or anaerobic conditions, where the latter condition produces methane.
During collection and treatment, wastewater may be accidentally or deliberately managed under anaerobic
conditions. In addition, the sludge may be further biodegraded under aerobic or anaerobic conditions.
The organic content, expressed in terms of either biochemical oxygen demand (BOD) or chemical oxygen demand
(COD), determines the methane producing potential of wastewater. BOD represents the amount of oxygen that
would be required to completely consume the organic matter contained in the wastewater through aerobic
decomposition processes. COD refers to the amount of oxygen consumed under specified conditions in the
oxidation of the organic and oxidizable inorganic matter and is a parameter typically used to characterize industrial
wastewater.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 265
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In 2003, CH4 emissions from domestic wastewater treatment were estimated to be 19.8 Tg CO2 Eq. (944 Gg).
Emissions have increased since 1990 in response to the increase in the U.S. human population. Also, the per capita
organic wastewater loading has increased. Industrial emission sources include wastewater from the pulp and paper,
meat and poultry processing, and the vegetables, fruits and juices processing industry.4 In 2003, CH4 emissions
from industrial wastewater treatment were estimated to be 16.9 Tg CO2Eq. (807 Gg). Table 8-6 and Table 8-7
provide emission estimates from domestic and industrial wastewater treatment.
Table 8-6: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Tg CO2 Eq.)
Activity
Domestic
Industrial*
Total
1990 w.< 1997
11.4
13.5
P^'- 15.8
»$'&. 15.9
24.8 ,1',C • 31.7
1998
16.5
16.1
32.6
1999
17.1
16.5
33.6
2000
17.8
16.5
34.3
2001
18.5
16.2
34.7
2002
19.2
16.7
35.8
2003
19.8
16.9
36.8
* Industrial activity includes the pulp and paper, meat and poultry, and the vegetables, fruits and juices processing industry.
Note: Totals may not sum due to independent rounding.
Table 8-7: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Gg)
Activity 1990 : > 1997
Domestic 543
Industrial* 640
pi
-------
Methane emissions estimates from industrial wastewater were developed according to the methodology described in
the IPCC (2000). Industry categories that are likely to have significant CH4 emissions from their wastewater
treatment were identified. High volumes of wastewater generated and a high organic COD wastewater load were
the main criteria. The top three industries that met these criteria included pulp and paper manufacturing, meat and
poultry packing, and vegetables, fruits and juices processing.
Methane emissions from these categories were estimated by multiplying the annual product output (metric
tons/year) by the average outflow (m3/metric ton of output), the organics loading in the outflow (grams of organic
BOD/m3), the emission factor (grams CH4/grams BOD), and the percentage of organic BOD assumed to degrade
anaerobically. In developing estimates for the vegetables, fruits, and juices category, COD was used instead of
BOD, because no accurate BOD numbers were available. The emission factor used for pulp and paper as well as
meat and poultry wastewater is 0.6 kg CH4/kg BOD5, whereas the emission factor for vegetables, fruits and juices
category is 0.25 kg CH4/kg COD (IPCC 2000). The pertinent industry-specific parameters are specified below.
Wastewater treatment for the pulp and paper industry typically includes neutralization, screening, sedimentation,
and flotation/hydrocycloning to remove solids (World Bank 1999, Nemerow and Dasgupta 1991). The most
important step is lagooning for storage, settling, and biological treatment (secondary treatment).
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 and, consequently, the primary lagoons are assumed to be 1.4 percent anaerobic.
Approximately 42 percent of the BOD passes on to secondary treatment, which is 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). Consequently, the overall percentage of
wastewater organics that degrade anaerobically was determined to be 10.3 percent (i.e., 58% x 1.4% + 42% x 90%
x 25%). A time series of CH4 emissions for post-1990 years was developed based on production figures reported in
the Lockwood-Post Directory (Lockwood-Post 2002). The overall wastewater outflow was estimated to be 85
m3/metric ton, and the average BOD loading entering the secondary treatment lagoons was estimated to be 0.4 gram
BOD/hter (EPA 1997b, EPA 1993, WorldBank 1999).
The meat and poultry processing industry makes extensive use of anaerobic lagoons in sequence with screening, fat
traps and dissolved air flotation. Production data, in carcass weight for the meat and poultry industry, were obtained
from the U.S. Census (2004). EPA (2002) provided wastewater flows into the anaerobic lagoons of 7.9 and 16.6
m3/metric ton for meat and poultry production, respectively. The loadings are 2.8 and 1.5 g BOD/liter for meat and
poultry, respectively, while 90 percent of organic BOD is believed to degrade anaerobically in the lagoon (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. This industry is likely to use lagoons intended for
aerobic operation, but the large seasonal loadings may develop limited anaerobic zones. In addition, some
anaerobic lagoons may also be used (Nemerow and Dasgupta 1991). Consequently, 5 percent of these wastewater
organics are assumed to degrade anaerobically. The USDA National Agricultural Statistics Service (USDA 2004)
provided production data for the fruits, vegetables, and juices processing sector. Outflow data for various
subsectors (canned fruit, canned vegetables, frozen vegetables, fruit juices, jams, baby food) were obtained from
World Bank (1999) and an average wastewater outflow of 5.6 m3/metric ton was used. For the organics loading, a
COD value of 5 g/liter was used (EPA 1997b).
Table 8-9: U.S. Pulp and Paper, Meat and Poultry, and Vegetables, Fruits and Juices Production (Tg)
Meat Poultry Vegetables,
Year Pulp and Paper (carcass weight) (carcass weight) Fruits and Juices
1990
1991
1992
1993
128.9
129.2
134.5
134.1
17.9
18.5
18.7
18.9
10.6
11.2
12.0
12.3
30.2
31.3
33.5
34.1
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 267
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1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
139.3
140.9
140.3
145.6
144.0
145.1
142.8
134.3
137.5
140.0
19.2
19.8
19.8
19.7
20.5
21.0
21.0
20.8
21.5
21.8
13.2
13.8
14.5
15.0
15.1
16.0
16.4
16.8
17.3
17.6
37.3
36.8
36.4
37.7
36.5
37.4
38.9
35.0
36.7
34.4
Uncertainty
Significant uncertainties are associated with the industrial wastewater emission estimates. Wastewater outflows and
organics loadings vary considerably for different plants and different sub-sectors (e.g., paper vs. board, poultry vs.
beef, or baby food vs. juices). For pulp and paper industrial wastewater, five key variables were simulated:
material output, with a standard deviation of 10 percent; wastewater outflow, with a standard deviation of 48
percent; BOD5 concentration, with a standard deviation of 25 percent; percent anaerobically treated, with a standard
deviation of 50 percent; and the BOD5IPCC methane emission factor, with a standard deviation of 30 percent. For
industrial wastewater from meat and poultry processing, five key variables were simulated: material output, with a
standard deviation of 10 percent; wastewater outflow, with a standard deviation of 59 percent; BOD5 concentration,
with a standard deviation of 51 percent; percent anaerobically treated, with a standard deviation of 10 percent; and
the BOD5 IPCC methane emission factor, with a standard deviation of 30 percent. For industrial wastewater from
processing fruit and vegetables, five variables were simulated: material output, with a standard deviation of 10
percent; wastewater outflow, with a standard deviation of 55 percent; COD5 concentration, with a standard
deviation of 60 percent; percent anaerobically treated, with a standard deviation of 50 percent; and the BOD5 IPCC
methane emission factor, with a standard deviation of 30 percent.
In summary, uncertainties for outflows are approximately 50 percent for the different source categories and are
based on a standard deviation calculation for meat and poultry, and on expert judgment and the literature for the
pulp and paper and the vegetables, fruits, and juices category (Nemerow and Dasgupta 1991; World Bank 1999).
Uncertainties for organic loadings are based on the same approach and are estimated at 25, 50, and 60 percent for
pulp and paper, meat and poultry, and fruits, vegetables and juices, respectively. The uncertainty associated with
the degree in which anaerobic degradation occurs in treatment systems is estimated at 50 percent for the pulp and
paper and vegetables, fruits, and juices categories, while this factor for the meat and poultry industry is 10 percent,
because the flow data are from the entrance of the anaerobic lagoons.
For domestic wastewater uncertainty, a normal probability distribution was assumed for the four key variables
simulated: population, with a standard deviation of 5 percent; BOD5, with a standard deviation of 30 percent;
percent of wastewater treated anaerobically, with a standard deviation of 25 percent; and the BOD5 IPCC CH4
emission factor, with a standard deviation of 30 percent.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 8-10. Wastewater treatment CH4
emissions in 2003 were estimated to be between 25.2 and 50.3 Tg CO2 Eq. at a 95 percent confidence level (or in 19
out of 20 Monte Carlo Stochastic Simulations). This indicates a range of 32 percent below to 37 percent above the
2003 emission estimate of 36.8 Tg CO2 Eq.
Table 8-10: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Wastewater Treatment (Tg CO2 Eq.
and Percent)
2003 Emission Uncertainty Range Relative to Emission
Source Gas Estimate Estimate"
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper
Bound
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 268
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Wastewater Treatment CH4 36.8 25.2 50.3 -32% +37%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Recalculations Discussion
Population estimates for the United States from 1990 through 2002 have been adjusted to include U.S. territories
(i.e., American Samoa, Guam, Northern Mariana Islands, and the Virgin Islands). Emission estimates from
previous years have only considered estimates of U.S. states and Puerto Rico. On average, updated U.S. population
estimates increased total annual CH4 emissions from wastewater treatment by less than one percent.
The time series for domestic wastewater has been updated due to an adjustment in the per capita BOD factor. The
BOD factor changed from a constant value of 0.06 kg per capita per day to an increasing value from 0.06 in 1990 to
0.09 kg per capita per day in 2003. Compared to 2002 estimates, methane emissions from domestic wastewater
increased 37 percent. The time series for industrial wastewater changed because more detailed field data became
available for the meat and poultry industry (EPA 2002) that include new flow and organic loading data. As a result,
estimates for the meat and poultry industrial subcategories have been separated. Organic matter loading
calculations are also now based on BOD rather than COD estimates. The new flow data reflect field measurements
at the anaerobic lagoon inlet, as opposed to more general plant outflow data. Industrial CH4 emissions increased 14
percent compared to 2002 estimates, as a result of the more detailed meat and poultry data and a slight increase in
pulp and paper production. The total 2002 CH4 emissions from wastewater treatment increased by 25 percent
compared to the emissions in the previous Inventory. Overall, these changes resulted in an average annual increase
of 3.8 Tg CO2 Eq. (14 percent) in CH4 emissions from wastewater treatment for the period 1990 through 2002.
Planned Improvements Discussion
The Authors/Experts Meeting for the Preparation of 2006 IPCC National Greenhouse Gas Inventones Guidelines
for the Wastewater Sector, held in November 2004, will likely generate improved methodological data.
Improvements will be planned accordingly.
8.3. Human Sewage (Domestic Wastewater) (IPCC Source Category 6B)
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 system, or a centralized wastewater treatment system. Decentralized
wastewater treatment systems are septic systems and package plants. Centralized wastewater treatment systems
may include a variety of processes, ranging from lagoomng to advanced tertiary treatment technology for removing
nutrients. Often, centralized wastewater treatment systems also treat certain flows of industrial, commercial, and
institutional wastewater. After processing, treated effluent is discharged to a receiving water environment (e.g.,
river, lake, estuary, etc.), or 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. These compounds 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 dmitrogen gas (N2). Nitrous oxide can be an
intermediate product of both processes, but is more often associated with denitrification.
The United States identifies two distinct sources for N2O emissions from domestic wastewater: emissions from
centralized wastewater treatment processes; and emissions from effluent that has been discharged into aquatic
environments. The 2003 emissions of N2O from wastewater treatment processes and from effluent were estimated
to be 0.3 Tg CO2 Eq. (0.9 Gg) and 15.6 Tg CO2 Eq. (50 Gg), respectively. Total N2O emissions from domestic
wastewater were estimated to be 15.9 Tg CO2 Eq. (51 Gg) (see Table 8-11). Emissions from wastewater treatment
processes have gradually increased as a result of increasing U.S. population and protein consumption.
Table 8-11: N2O Emissions from Human Sewage (Tg CO2 Eq. and Gg)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 269
-------
Year
1990
1997
1998
1999
2000
2001
2002
2003
TgC02Eq.
13.0
"''•"•' •''' '/ ,""'-, ;' ", '"
14.7
15.0
15.4
15.6
15.6
15.7
15.9
Gg
42
,-^>r, *
47
48
50
50
50
51
51
Methodology
The IPCC default methodology (IPCC/UNEP/OECD/IEA 1997) assumes that nitrogen disposal, and thus N2O
emissions associated with land disposal, subsurface disposal, and domestic wastewater treatment are negligible and
all nitrogen is discharged directly into aquatic environments. For the United States, N2O emissions from domestic
wastewater (human sewage) were estimated using the IPCC methodology with three modifications:
• In the United States, a certain amount of nitrogen is removed with the sewage sludge, which is land
applied, incinerated or landfilled (Nsiudge). The nitrogen disposal into aquatic environments is reduced to
account for the sewage sludge application.
o The IPCC methodology 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. A factor of 1.4 is introduced to
account for non-consumption nitrogen.6 Furthermore, a significant quantity of industrial wastewater
(nitrogen) is co-discharged with domestic wastewater. To account for this, a factor of 1.25 is
introduced.7 In summary, a factor of 1.75 (1.4 x 1.25) is used to account for the extra nitrogen
discharge from kitchen, bath, and laundry wastes, as well as industrial wastewater that is co-
discharged into sewers, based on Metcalf & Eddy (1991) and expert judgment.
• Process emissions from wastewater treatment plants are not accounted for in the current IPCC
methodology. To estimate N2O emissions from U.S. wastewater treatment plants, an overall emission
factor (4 g N2O/person.year) was introduced. This emission factor is based on a factor of 3.2 g
N2O/person.year (Czepiel 1995) multiplied by the 1.25 factor mentioned above, which adjusts for co-
discharged industrial nitrogen and is based on expert judgment. The nitrogen quantity associated with
" Metcalf & Eddy (1991) provides an indication of the nitrogen concentration of 40 mg Total Kjeldahl Nitrogen (TKN)/liter for
average wastewater from residences, which includes bathwater, laundry, and the use of garbage disposals. According to the
NEEDS Survey (1996), the total volume of wastewater generated in the US in 1996 was 32,175 million gallons per day (MGD),
serving 189,710,899 people (72 percent of population, not including the septic system users). In 1996, the per capita TKN
loading was: 40 [mg/1] x 32,175 x 106 [gal/day] x 3.8 [1/gal] x 365 days/yr x 17(189.7 x 106) x 10'6 = 9.4 [kg TKN/yr.person].
Average protein intake in 1996 was 41 kg/year (6.6 kg N/year), leading to a factor of 1.4 (9.4/6.6).
' The type, composition, and quantity of this co-discharged wastewater will vary greatly between municipalities. Metcalf &
Eddy (1991) provide an indicative nitrogen loading of 20 to 85 mg TKN/liter (average 55) for combined residential and
industrial wastewater, while residential wastewater loading was roughly estimated at 40 mg TKN/liter (see footnote 1). Until
better data become available, the amount of N in wastewater was increased by 10 mg/1 to account for industrial co-discharge
(factor of 1.25.)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 270
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these emissions (NWWT) is calculated by multiplying the N2O emitted by (2 x 14)/44 and is subtracted
from the total quantity of nitrogen that is ultimately disposed into the aquatic environment.
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:
N2O(s) = (USpop x 0.75 x EFi x 10~3) + {[(Protein x 1.75 x FracNPR x USPOP) - NWWT - Nshldge] x EF2 x 44/28}
where,
N2O(s) = N2O emissions from domestic wastewater ("human sewage") [kg/year]
USpop = U.S. population
0.75 = Fraction of population using centralized wastewater treatment plants (as opposed to septic
systems)
EFj = Emission factor (4 g N2O/person.year) expressing emissions from the Centralized wastewater treatment plants
Protein = Annual per capita protein consumption [kg N/(person.year)]
1.75 = Fraction of non-consumption protein in domestic wastewater
FracNPR = Fraction of nitrogen in protein (i.e., 0. 16 kg N/kg protein)
NWWT = Quantity of wastewater nitrogen removed by wastewater treatment processes [(USPOp x 0.75 x
EFjX 10'3) x 28/44] (kgN/year).
Ndudge = Quantity of sewage sludge N not entering aquatic environments (kg N/year)
EF2 = Emission factor (kg N2O-N/kg sewage-N produced)
(44/2g) = Molecular weight ratio of N2O to N2.
U.S. population data were taken from the U.S. Census Bureau (2003). The fraction of the U.S. population using
wastewater treatment plants is from the NEEDS Survey (EPA 1 996). The emission factor (EF]) to estimate
emissions from wastewater treatment is based on Czepiel, et al. (1995). Data on annual per capita protein intake
were provided by the United Nations Food and Agriculture Organization for the 1 990 to 2002 time frame (FAO
2004). Because data on protein intake were unavailable for 2003, the value of per capita protein consumption was
extrapolated from previous years. Table 8-12 presents the data for U.S. population and average protein intake. An
emission factor to estimate emissions from effluent (EF2) has not been specifically estimated for the United States,
thus the default IPCC value (0.01 kg N2O-N/kg sewage-N produced) was applied. The fraction of nitrogen in
protein (0.16 kg N/kg protein) was also obtained from IPCC/UNEP/OECD/IEA (1997).
Table 8-12: U.S. Population (Millions) and Average Protein Intake [kg/(person.year)]
Year Population Protein
1990 254 39.2
1997
1998
1999
2000
2001
2002
2003
277
280
283
287
289
292
295
40.9
41.2
42.0
41.9
41.8
41.6
41.8
Uncertainty
Nitrous oxide emissions from wastewater treatment are estimated to be substantially less than emissions from
effluent-surface water. Thus, this wastewater treatment subcategory was not considered in the uncertainty analysis.
A triangular distribution was used to simulate land application of sludge as defined for the agricultural soil
management sector. The same distribution was assumed for landfilled sludge. The means for the distributions were
the estimates used for the 2003 inventory estimate. Based on professional judgment, the standard deviation for
population was 5 percent, the standard deviation for per capita protein consumption was 5 percent, the standard
deviation of the fraction of nitrogen in protein (FracNPR) was 2 percent, and the standard deviation of the non-
consumption protein in domestic wastewater was 25 percent based on professional judgment. The standard
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 271
-------
deviation emission factor for effluent is 80 percent based on the range provided in IPCC (1996). For the triangular
distributions, the lower bound and upper estimates for the land applied and landfilled sludge were 50 percent below
and above the respective estimates used for the 2003 inventory. A normal distribution was used to simulate five
variables: population, per capita protein intake data, fraction of nitrogen in protein (FracNPR), non-consumption
protein in domestic wastewater, and the IPCC emission factor.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 8-13. Human sewage N2O
emissions in 2003 were estimated to be between 4.2 and 29.9 Tg CO2 Eq. at a 95 percent confidence level (or in 19
out of 20 Monte Carlo Stochastic Simulations). This indicates a range of 74 percent below to 88 percent above the
2003 emission estimate of 15.9 Tg CO2 Eq.
Table 8-13: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from Human Sewage (Tg CO2 Eq. and
Percent)
2003 Emission Uncertainty Range Relative to Emission
Source Gas Estimate Estimate"
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper
Bound
Human Sewage N2O 15.9 42 29.9 -74% +88%
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
QA/QC and Verification
An IPCC Tier 1 level QA/QC verification was performed. During the QA/QC process the values for Wastewater
BOD produced per capita (kg/capita/day) were adjusted to be based on a calculated rather than estimated
interpolated value between the reported 1990 and 2003 values. In addition, the documentation of references in the
spreadsheets was improved.
Planned Improvements
The default emission factor for N2O from wastewater effluent has a high uncertainty. Future research may identify
new studies that include updated data. The factor that accounts for non-sewage nitrogen in wastewater (bath,
laundry, kitchen, industrial components) also has a high uncertainty. Several parameters constituting this factor are
based on references that have since been updated, including Needs Survey (1996) and Metcalf & Eddy (1991). The
uncertainty associated with this factor can likely be reduced incorporating more recent data.
Recalculations Discussion
Population estimates for the U.S. from 1990 through 2002 have been adjusted to include U.S. territories (i.e.,
American Samoa, Guam, Northern Mariana Islands, and the Virgin Islands). Emission estimates from previous
years have only considered estimates of U.S. states and Puerto Rico. Overall, the change resulted in an average
annual increase of 0.2 Tg CO2 Eq. (1.7 percent) in N2O emissions from wastewater treatment processes and effluent
for the period 1990 through 2002.
8.4. Waste Sources of Ambient Air Pollutants
In addition to the main greenhouse gases addressed above, waste generating and handling processes are also sources
of ambient air pollutant emissions. Total emissions of NOX, CO, and NMVOCs from waste sources for the years
1990 through 2003 are provided in Table 8-14.
Table 8-14: Emissions of NOX, CO, and NMVOC from Waste (Gg)
Gas/Source
NOX
Landfills
1990 ;;« , 1997
+?:'•;; 3
+ b:.'.J 2
1998
3
2
1999
3
3
2000
2
2
2001
2
2
2002
2
2
2003
2
2
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 272
-------
Wastewater Treatment
Miscellaneous3
CO
Landfills
Wastewater Treatment
Miscellaneous3
NMVOCs
Landfills
Wastewater Treatment
Miscellaneous3
+ £ .';>' +
+£%', i
l£^-;. 5
i $. ;;, >x 5
+ t ;'*'•'• i +
+ £ ^v" +
673v;>':f.;. 157
58 £t>:' 32
57 $. •',[, ?• 62
558 w&v 64
+
1
5
5
+
+
161
33
63
65
+
+
13
12
1
+
140
27
59
54
+
+
8
7
1
+
119
23
51
46
+
+
8
7
1
+
122
23
53
46
+
+
8
7
1
+
133
25
58
51
+
+
8
7
1
+
125
24
54
47
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
Methodology and Data Sources
These emission estimates were obtained from preliminary data (EPA 2004), and disaggregated based on EPA
(2003), which, in its final iteration, will be published on the National Emission Inventory (NEI) Air Pollutant
Emission Trends web site. Emission estimates of these gases were provided 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 databases.
Uncertainty
No quantitative estimates of uncertainty were calculated for this source category. Uncertainties in these estimates,
however, are primarily due to the accuracy of the emission factors used and accurate estimates of activity data.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 273
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Landfills
Human Sewage
20 40 60 80 100 120 140
Tg C02 Eq
Figure 8-1: 2003 Waste Chapter Greenhouse Gas Sources
-------
9. Other
The United States does not report any greenhouse gas emissions under the "other" IPCC sector.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 275
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10. Recalculations and Improvements
Each year, emission and sink estimates are recalculated and revised for all years in the Inventory of U.S.
Greenhouse Gas Emissions and Sinks, as attempts are made to improve both the analyses themselves, through the
use of better methods or data, and the overall usefulness of the report. In this effort, the United States follows the
IPCC Good Practice Guidance (IPCC 2000), which states, regarding recalculations of the time series, "It is good
practice to recalculate historic emissions when methods are changed or refined, when new source categories are
included in the national inventory, or when errors in the estimates are identified and corrected (IPCC 2000)."
The results of all methodology changes and historical data updates are presented in this section; detailed
descriptions of each recalculation are contained within each source's description contained in this report, if
applicable. Table 10-1 summarizes the quantitative effect of these changes on U.S. greenhouse gas emissions and
Table 10-2 summarizes the quantitative effect on U.S. sinks, both relative to the previously published U.S.
Inventory (i.e., the 1990 through 2002 report). These tables present the magnitude of these changes in units of Tg
CO2 Eq. In addition to the changes summarized by the tables below, four new sources—CO2 emissions from non-
energy use of fossil fuels and petrochemical production and N2O emissions from settlements remaining settlements
and forest land remaining forest land—have been added to the current Inventory.
The Recalculations Discussion section of each source presents the details of each recalculation. In general, when
methodological changes have been implemented, the entire time series (i.e., 1990 through 2002) has been
recalculated to reflect the change, per IPCC Good Practice Guidance. 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.
The following emission sources, which are listed in descending order of absolute average annual change in
emissions from 1990 through 2002, underwent some of the most important methodological and historical data
changes. A brief summary of the recalculation and/or improvement undertaken is provided for each emission
source.
• CO2from Fossil Fuel Combustion. The most important change in the calculation was the revision that removed
emissions from the non-energy use of fuels, which allowed them to be reported separately in the Carbon
Emitted from Non-Energy Uses of Fossil Fuels source category. Overall, this change, along with several other
alterations, resulted in an average annual decrease of 115.8 Tg CO2 Eq. (2.2 percent) in CO2 emissions from
fossil fuel combustion for the period 1990 through 2002.
• Land-Use Change and Forestry. The most influential of the changes in the Land-Use Change and Forestry
sector occurred in calculations for agricultural soil carbon stocks. These changes include: a new methodology
for the evaluation and incorporation of uncertainty in manure amendments into the calculations for agricultural
soil carbon, the use of new management factors provided in the IPCC LULUCF Good Practice Guidance
(IPCC 2003), and revision of the land area included in the emission calculation for organic soils. Overall, these
changes, in combination with adjustments in the other sources/sinks, resulted in an average annual decrease in
net flux of CO2 to the atmosphere from the land-use change and forestry sector of 89.0 Tg CO2 Eq. (12.1
percent) for the period 1990 through 2002.
• Landfills. Revisions to the emissions calculation incorporated the use of a first order decay model rather than a
linear regression model for 30-year waste in place figures, improved estimates of the annual quantity of waste
placed in landfills, and more accurate estimates of emissions avoided by landfill gas to energy (LFGTE)
projects and flaring. Overall, changes resulted in an average annual decrease in CH4 emissions from landfills of
52.9 Tg CO2 Eq. (26.0 percent) for the period 1990 through 2002.
• Agricultural Soil Management. The emissions calculation changed to incorporate the reallocation of emissions
from fertilizer applied to forests and urban areas from the agricultural soil management source category within
the Agriculture sector to the Land-Use Change and Forestry sector and the use of a Tier 3 methodology
utilizing the DAYCENT ecosystem model rather than the Tier 1 methodology used in the past. Overall,
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 277
-------
changes resulted in an average annual decrease in N2O emissions from agricultural soil management of 31.2 Tg
CO2 Eq. (11.0 percent) for the period 1990 through 2002.
• Petroleum Systems. The calculation of emissions was revised to incorporate a modified emission factor for
CH4 emissions from oil tanks in the production sector and new activity factor for offshore Gulf of Mexico
platform venting in the production sector. Overall, changes resulted in an average annual decrease in CH4
emissions from petroleum systems of 7.1 Tg CO2 Eq. (27.4 percent) for the period 1990 through 2002.
• Natural Gas Systems. The emissions calculation was revised to incorporate new Gas STAR emissions
reduction data and the addition of three new emission sources in the production sector: CH4 from gas
condensate stored in tanks, unconventional gas well fugitives, and flaring from offshore Gulf of Mexico
operations. Overall, changes resulted in an average annual increase in CH4 emissions from natural gas systems
of 6.7 Tg CO2 Eq. (5.3 percent) for the period 1990 through 2002.
• Mobile Combustion. The most significant changes to this source were revisions to the emission factors for CH4
and N2O from highway vehicles, which were generated from EPA-sponsored laboratory vehicle testing.
Revisions to these emission factors resulted in lower emission estimates for both CH4 and N2O emissions from
highway vehicles. Overall, changes resulted in an average annual decrease in N2O emissions from mobile
combustion of 6.2 Tg CO2 Eq. (10.9 percent) and an average annual decrease in CH4 emissions from mobile
combustion of 0.6 Tg CO2 Eq. (13.6 percent) for the period 1990 through 2002.
• Wastewater Treatment. The most influential changes in the calculation were the use of an adjusted per capita
BOD factor in the domestic wastewater emissions calculations and the use of more detailed field data for the
meat and poultry industry in the industrial wastewater emissions calculations. Overall, changes resulted in an
average annual increase in CH4 emissions from wastewater treatment of 3.8 Tg CO2 Eq. (14.0 percent) for the
period 1990 through 2002.
• Abandoned Coal Mines. The calculation of emissions was revised to incorporate an updated mine list, updated
coal seam permeabilities, and revised closure dates for 43 of the mines. Overall, changes resulted in an average
annual increase in CH4 emissions from abandoned coal mines of 2.8 Tg CO2 Eq. (64.5 percent) for the period
1990 through 2002.
Table 10-1: Revisions to U.S. Greenhouse Gas Emissions (Tg CO2 Eq.)
Gas/Source
C02
Fossil Fuel Combustion
Non-Energy Use of Fuels3
Natural Gas Flaring
Cement Manufacture
Lime Manufacture
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Carbon Dioxide Consumption
Waste Combustion
Titanium Dioxide Production
Aluminum Production
Iron and Steel Production
Ferroalloys
Ammonia Manufacture & Urea Application
Petrochemical Production3
Phosphoric Acid Production
Land-Use Change and Forestry (Sink)
International Bunker Fuels
Biomass Combustion
CH4
Stationary Sources
1990
7.2 ;;;
(102.9) l;5
108.0 l;5
+ :-5
NC 1:5
NC i;5
NC iiJ
NC x
+ :S
NC x
NC :x
NC \ +
+ :•?
NC \1
NC ^
NC ;;
2.2 ^
(84.2) IS
(0.4) ;<
NC -i
(37.3) !?
(0.4) •: .
" 1997
:-. 2.3
?: (120.8)
?'. 120.3
1 NC
?'. NC
1 NC
1 NC
;• '. NC
5. +
1 NC
i; • NC
1: NC
:;. +
1 NC
:;• NC
:;; NC
:;; 2.9
I (109.1)
••: +
!i NC
s (49.3)
.- (0.4)
1998
4.7
(133.7)
135.4
NC
NC
NC
NC
NC
+
NC
NC
NC
+
NC
NC
NC
3.0
(175.2)
(0.5)
NC
(51.0)
(0.3)
1999
1.7
(142.9)
141.6
NC
NC
NC
NC
NC
+
NC
NC
NC
+
NC
NC
NC
3.1
(150.4)
+
NC
(55.8)
(0.4)
2000
(0.8)
(128.5)
124.7
+
NC
NC
NC
NC
+
NC
NC
NC
+
NC
+
NC
3.0
(132.3)
+
NC
(60.3)
(0.4)
2001
13.0
(110.8)
120.1
0.7
NC
NC
NC
NC
+
NC
NC
NC
(0.2)
NC
0.5
NC
2.8
(137.1)
+
(3,9)
(58.3)
(0.6)
2002
14.4
(109.5)
118.8
0.9
NC
NC
+
NC
(0.3)
NC
NC
+
0.7
NC
0.9
+
2.9
(135.8)
2.6
0,2
(55.6)
(0.5)
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 278
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Mobile Sources
Coal Mining
Abandoned Coal Mines
Natural Gas Systems
Petroleum Systems
Petrochemical Production
Silicon Carbide Production
Iron and Steel Production
Enteric Fermentation
Manure Management
Rice Cultivation
Field Burning of Agricultural Residues
Landfills
Wastewater Treatment
International Bunker Fuels
N20
Stationary Sources
Mobile Sources
Adipic Acid
Nitric Acid
Manure Management
Agricultural Soil Management
Field Burning of Agricultural Residues
Human Sewage
N2O Product Usage
Waste Combustion
Settlements Remaining Settlements3
Forest Land Remaining Forest Land3
International Bunker Fuels
HFCs, PFCs, and SF6
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production
Semiconductor Manufacture
Electrical Transmission and Distribution
Magnesium Production and Processing
Net Change in Total Emissions1"
Percent Change
(0.2)
+
2.7
6.3
(8.9)
NC
NC
+
+
0.2
NC
NC
(37.7)
0.7
+
(11.2)
(0.4)
(6.9)
NC
NC
0.1
(9,8)
NC
0.2
NC
NC
5.5
0.1
+
0.3
0.1
0.2
NC
NC
+
NC '
(41.0)
•'••: (0.6)
••:': NC
••:': 2.5
^ 7.5
- (6.7)
••••:• NC
:^ NC
-: +
•:': +
- 0.1
•:': NC
- NC
••: (56.0)
'•;f: 4.3
•'•(• +
(40.0)
•:: (0.4)
:: (5.1)
::- NC
••!•. NC
:: : o.i
::•: (41.2)
::::: NC
::::: 0.2
::::: NC
::::: NC
::•: 6.1
::•: 0.3
::•: +
0.1
:-;: o.i
" .' 1
:;•: +
< NC
y +
•'.•:• NC
:r (86.9)
(0.7%) i.^ (1.3%)
(0.7)
+
2.4
7.3
(6.5)
NC
NC
+
+
0.1
NC
+
(58.1)
4.8
+
(24.4)
(0.4)
(4.2)
NC
NC
0.1
(26,5)
+
0.3
NC
NC
6.1
0.4
+
+
+
+
+
NC
+
NC
(70.7)
(1.0%)
(0.9)
+
2.9
6.5
(5.9)
NC
NC
+
0.2
0.1
NC
NC
(63.8)
5.4
+
(46.2)
(0.4)
(4.0)
NC
NC
0.1
(48,7)
NC
0.3
NC
NC
6.2
0.5
+
+
+
+
+
NC
+
NC
(100.3)
(1.5%)
(1.0)
NC
3.3
6.4
(5.9)
NC
NC
+
(0.1)
0.1
NC
NC
(68.6)
6.0
+
(23.9)
(0.4)
(4.2)
NC
NC
0.1
(25,9)
NC
0.3
NC
NC
6.0
0.4
+
(0.2)
(0.1)
0.1
+
NC
(0.2)
+
(85.2)
(1.2%)
(1.2)
+
2.7
6.9
(6.0)
NC
NC
+
0.2
0.1
NC
NC
(67.0)
6.5
+
(31.4)
(0.4)
(6.1)
NC
NC
0.1
(31,5)
NC
0.2
NC
0.1
5.8
0.4
+
(0.2)
(0.1)
+
+
NC
(0.2)
+
(77.0)
(1.1%)
(1.3)
0.2
2.2
8.8
(6.1)
NC
NC
+
0.2
(0.1)
NC
+
(66.2)
7.1
+
(35.3)
(0.5)
(7.3)
NC
0.5
0.1
(34,8)
+
0.1
NC
0.1
6.0
0.4
+
+
(0.2)
+
NC
NC
(0.1)
0.2
(76.5)
(1.1%)
+ Absolute value does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.
NC (No Change)
a New source category relative to previous inventory.
bExcludes sinks from land-use change and forestry, and emissions from international bunker fuels and biomass combustion.
Note: Totals may not sum due to independent rounding.
Table 10-2: Revisions to Net Flux of CO2 to the Atmosphere from Land-Use Change and Forestry (Tg CO2 Eq.)
Component
1990
1997
1998
1999
2000
2001
2002
Forest Land Remaining Forest
Land
Cropland Remaining Cropland
Settlements Remaining Settlements
Net Change in Total Flux
Percent Change
+ Absolute value does not exceed 0.05
NC (No Change)
(102.7) ;;:
18.5 :;'
NC ::,
(84.2) iv
(8.8%)
•:: (120.9)
11.9
- (0.1)
(109.1)
(13.3%)
(187.7)
12.6
(0.1)
(175.2)
(24.8%)
(163.3)
13.0
(0.1)
(150.4)
(22.2%)
(145.6)
13.4
(0.1)
(132.3)
(19.2%)
(150.7)
13.6
+
(137.1)
(19.9%)
(150.7)
15.0
+
(135.8)
(19.7%)
Tg CO2 Eq. or 0.05 percent.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003
Page 279
-------
Note: Numbers in parentheses indicate a decrease in estimated net flux of CO2 to the atmosphere, or an increase in net
sequestration.
Note: Totals may not sum due to independent rounding.
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page 280
-------
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2001. September 2001. Available online at .
U.S. Census Bureau (200 Ib) Current Industrial Reports Fertilizer Materials and Related Products: Annual Report
2000. Available online at .
U.S. Census Bureau (2000) Current Industrial Reports Fertilizer Materials and Related Products: Annual Report
1999. Available online at .
U.S. Census Bureau (1999) Current Industrial Reports Fertilizer Materials and Related Products: Annual Report
1998. Available online at .
U.S. Census Bureau (1998) Current Industrial Reports Fertilizer Materials and Related Products: Annual Report
1997. Available online at .
U.S. Census Bureau (1994) Current Industrial Reports Fertilizer Materials Annual Report 1993, Report No.
MQ28B.
U.S. Census Bureau (1993) Current Industrial Reports Fertilizer Materials Annual Report 1992, Report No.
MQ28B.
U.S. Census Bureau (1992) Current Industrial Reports Fertilizer Materials Annual Report 1991, Report No.
MQ28B.
U.S. Census Bureau (1991) Current Industrial Reports Fertilizer Materials Annual Report 1990, Report No.
MQ28B.
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Lime Manufacture
IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories,
Intergovernmental Panel on Climate Change, National Greenhouse Gas Inventories Programme, Montreal, IPCC-
XVI/Doc. 10 (1.IV.2000), May 2000.
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Males, E. (2003) Public review comments received in a memorandum from Eric Males, National Lime Association
to Mr. William N. Irving & Mr. Leif Hockstad, Environmental Protection Agency. Memorandum dated March 6,
2003.
USGS (2004) Minerals Yearbook: Lime Annual Report 2003. U.S. Geological Survey, Reston, VA.
USGS (2003) Minerals Yearbook: Lime Annual Report 2002. U.S. Geological Survey, Reston, VA.
USGS (2002) Minerals Yearbook: Lime Annual Report 2001. U.S. Geological Survey, Reston, VA.
USGS (2001) Minerals Yearbook: Lime Annual Report 2000. U.S. Geological Survey, Reston, VA.
USGS (2000) Minerals Yearbook: Lime Annual Report 1999. U.S. Geological Survey, Reston, VA.
USGS (1999) Minerals Yearbook: Lime Annual Report 1998. U.S. Geological Survey, Reston, VA.
USGS (1998) Minerals Yearbook: Lime Annual Report 1997. U.S. Geological Survey, Reston, VA.
USGS (1997) Minerals Yearbook: Lime Annual Report 1996. U.S. Geological Survey, Reston, VA.
USGS (1996) Minerals Yearbook: Lime Annual Report 1995. U.S. Geological Survey, Reston, VA.
USGS (1995) Minerals Yearbook: Lime Annual Report 1994. U.S. Geological Survey, Reston, VA.
USGS (1994) Lime: Annual Report 1993. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau
of Mines. Washington, DC. September.
USGS (1992) Lime: Annual Report 1991. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau
of Mines. Washington, DC. November.
Limestone and Dolomite Use
Tepordei (2004) Telephone Conversations between Matthew Stanberry of ICF Consulting and Valentin Tepordei,
Commodity Specialist, USGS, 20 October.
Tepordei (2003) Telephone Conversations between Matthew Stanberry of ICF Consulting and Valentin Tepordei,
Commodity Specialist, USGS, 23 October- 31 October.
Tepordei (2002) Telephone Conversations between Matthew Stanberry of ICF Consulting and Valentin Tepordei,
Commodity Specialist, USGS, 29 October- 8 November.
USGS (2004a) Minerals Yearbook: Crushed Stone Annual Report 2003. U.S. Geological Survey, Reston, VA.
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USGS (2003a) Minerals Yearbook: Crushed Stone Annual Report 2002. U.S. Geological Survey, Reston, VA.
USGS (2003b) Minerals Yearbook: Magnesium Annual Report 2002. U.S. Geological Survey, Reston, VA.
USGS (2002a) Minerals Yearbook: Crushed Stone Annual Report 2001. U.S. Geological Survey, Reston, VA.
USGS (2002b) Minerals Yearbook: Magnesium Annual Report 2001. U.S. Geological Survey, Reston, VA.
USGS (2001 a) Minerals Yearbook: Crushed Stone Annual Report 2000. U.S. Geological Survey, Reston, VA.
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USGS (200Ib) Minerals Yearbook: Magnesium Annual Report 2000. U.S. Geological Survey, Reston, VA.
USGS (2000a) Minerals Yearbook: Crushed Stone Annual Report 1999. U.S. Geological Survey, Reston, VA.
USGS (2000b) Minerals Yearbook: Magnesium Annual Report 1999. U.S. Geological Survey, Reston, VA.
USGS (1999a) Minerals Yearbook: Crushed Stone Annual Report 1998. U.S. Geological Survey, Reston, VA.
USGS (\999b~) Minerals Yearbook: Magnesium Annual Report 1998. U.S. Geological Survey, Reston, VA.
USGS (1998a) Minerals Yearbook: Crushed Stone Annual Report 1997. U.S. Geological Survey, Reston, VA.
USGS (\99%\)) Minerals Yearbook: Magnesium Annual Report 1997. U.S. Geological Survey, Reston, VA.
USGS (1997a) Minerals Yearbook: Crushed Stone Annual Report 1996. U.S. Geological Survey, Reston, VA.
USGS (1997b) Minerals Yearbook: Magnesium Annual Report 1996. U.S. Geological Survey, Reston, VA.
USGS (1996a) Minerals Yearbook: Crushed Stone Annual Report 1995. U.S. Geological Survey, Reston, VA.
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Soda Ash Manufacture and Consumption
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USGS (2001) Minerals Yearbook: Soda Ash Annual Report 2000. U.S. Geological Survey, Reston, VA.
USGS (2000) Minerals Yearbook: Soda Ash Annual Report 1999. U.S. Geological Survey, Reston, VA.
USGS (1999) Minerals Yearbook: Soda Ash Annual Report 1998. U.S. Geological Survey, Reston, VA.
USGS (199%) Minerals Yearbook: Soda Ash Annual Report 1997. U.S. Geological Survey, Reston, VA.
USGS (1997) Minerals Yearbook: Soda Ash Annual Report 1996. U.S. Geological Survey, Reston, VA.
USGS (1996) Minerals Yearbook: Soda Ash Annual Report 1995. U.S. Geological Survey, Reston, VA.
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USGS (1995) Minerals Yearbook: Soda Ash Annual Report 1994. U.S. Geological Survey, Reston, VA.
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Titanium Dioxide Production
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USGS (1994) Minerals Yearbook: Titanium Annual Report 1993. U.S. Geological Survey, Reston, VA.
USGS (1993) Minerals Yearbook: Titanium Annual Report 1992. U.S. Geological Survey, Reston, VA.
USGS (1992) Minerals Yearbook: Titanium Annual Report 1991. U.S. Geological Survey, Reston, VA.
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Phosphoric Acid
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FIPR (2003) Florida Institute of Phosphate Research, Analyses of Some Phosphate Rocks, facsimile from Mr. Gary
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USGS(2004) Minerals Yearbook. Phosphate Rock Annual Report 2003. U.S. Geological Survey, Reston, VA.
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USGS (2003a) Electronic mail from Mr. Stephen M Jasinski, USGS Commodity Specialist, Phosphate Rock,
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USGS (1999) Minerals Yearbook. Phosphate Rock Annual Report 1998. U.S. Geological Survey, Reston, VA.
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Ferroalloy Production
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Commodity Specialist, U.S. Geological Survey, 21 October.
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Carbon Dioxide Consumption
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Petrochemical Production
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European IPPC Bureau (2004) Draft Reference Document on Best Available Techniques in the Large Volumen
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Othmer, Kirk (1992) Carbon (Carbon Black). Volume 4. Page 1045.
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Silicon Carbide Production
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Nitric Acid Production
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Substitution of Ozone Depleting Substances
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