United States
Environmental Protection
Agency
Office of
Policy, Planning
and Evaluation (2122)
EPA 236-R-98-006
March 1998
Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-1996
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Acknowledgements
The U.S. Environmental Protection Agency, Office of Policy, Planning and Evaluation would like to acknowl-
edge the many individual and organizational contributors to this document, without whose efforts this report would
not be complete. Although the list of researchers, government employees, and consultants who have provided tech-
nical and editorial support is too long to list here, we would like to thank some key contributors whose work has
significantly improved this year's report. In particular, we wish to acknowledge the efforts of Dr. Arvin Mosier at the
Department of Agriculture's Agricultural Research Service for his groundbreaking work on new methodologies for
estimating N2O emissions from soils; Mr. Arthur Rypinski of the Energy Information Administration who provided
detailed statistics and insightful analysis on numerous energy-related topics; Drs. Richard Birdsey and Linda Heath
of the U.S. Forest Service for preparing the forest carbon inventory; and Dr. Bo Lim and all her staff at the IPCC
Inventory Program whose technical expertise was invaluable in updating and improving the IPCC Guidelines for
National Greenhouse Gas Inventories.
Many EPA Offices contributed data, analysis and technical review for this report. The EPA Office of Air and
Radiation, in particular, provided hours of analysis and produced the final estimates for many of the source categories
addressed in this report. Among the many experts who developed estimates and provided explanatory text and
discussion are Dina Kruger, Bill Irving, Elizabeth Dutrow, and Rey Forte in the Office of Atmospheric Programs.
Phil Lorang, Harvey Michaels, Joe Somers, and all the staff in the Office of Mobile Sources made a significant
contribution to the inventory community by measuring nitrous oxide emissions from motor vehicles in an accelerated
summer test program. As always, the Office of Air Quality Planning and Standards and the Office of Research and
Development provided data, analysis, and support.
Other government agencies have contributed data as well, including the U.S. Geological Survey, the Federal
Highway Administration and the Federal Aviation Administration. In addition, we would like to thank Craig Ebert,
Michael Gillenwater and the entire staff of the Global Environmental Issues Group at ICF Incorporated for organiz-
ing and integrating many different bits and pieces of data into a cohesive and internally consistent document. Numer-
ous ICF analysts contributed to this inventory including Dana Palmer, Barbara Braatz, Heike Mainhardt, Michael
Gibbs, Kenneth Fernandez, Paul Jun, Stephen Abseck, Vikram Bakshi, David Conneely, Brad Kagawa, Beverly
Grossman, Karen Lawson, Catherine Leining, Andrew Martin, Elizabeth O'Neill, Muhib Rahman, Holly Simpkins,
Deborah Eckbreth, and Alex McDonald.
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Table of Contents
Acknowledgements i
Table of Contents ii
List of Tables and Figures iv
Tables iv
Figures viii
Executive Summary ES-1
Recent Trends in U.S. Greenhouse Gas Emissions ES-1
Global Warming Potentials ES-6
Carbon Dioxide Emissions ES-6
Methane Emissions ES-11
Nitrous Oxide Emissions ES-14
HFCs, PFCs and SF Emissions ES-15
Criteria Pollutant Emissions ES-16
1. Introduction 1-1
What is Climate Change? 1-2
Greenhouse Gases 1-2
Global Warming Potentials 1-6
Organization of Report 1-7
Recent Trends in U.S. Greenhouse Gas Emissions 1-7
Methodology and Data Sources 1-14
Uncertainty in and Limitations of Emission Estimates 1-15
Changes in the U.S. Greenhouse Gas Inventory Report 1-16
2. Energy 2-1
Carbon Dioxide Emissions from Fossil Fuel Combustion 2-3
Stationary Source Fossil Fuel Combustion (excluding CO ) 2-11
Mobile Source Fossil Fuel Combustion (excluding CO ) 2-15
Coal Mining ] 2-20
Natural Gas Systems 2-22
Petroleum Systems 2-24
Natural Gas Flaring and Criteria Pollutant Emissions from Oil and Gas Activities 2-26
WoodBiomass andEthanol Consumption 2-27
3. Industrial Processes 3-1
Cement Manufacture 3-2
Lime Manufacture 3-5
Limestone and Dolomite Use 3-7
Soda Ash Manufacture and Consumption 3-9
Carbon Dioxide Manufacture 3-11
Iron and Steel Production 3-12
Ammonia Manufacture 3-13
Ferroalloy Production 3-14
Petrochemical Production 3-15
Silicon Carbide Production 3-15
Adipic Acid Production 3-16
Nitric Acid Production 3-17
Substitution of Ozone Depleting Substances 3-18
Aluminum Production 3-22
ii Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
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HCFC-22 Production 3-25
Semiconductor Manufacture 3-26
Electrical Transmission and Distribution 3-26
Magnesium Production and Processing 3-27
Industrial Sources of Criteria Pollutants 3-28
4. Solvent Use 4-1
5. Agriculture 5-1
Enteric Fermentation 5-1
Manure Management 5-4
Rice Cultivation 5-7
Agricultural Soil Management 5-11
Agricultural Residue Burning 5-17
6. Land-Use Change and Forestry 6-1
Changes inForest Carbon Stocks 6-2
Changes in Non-Forest Soil Carbon Stocks 6-7
7. Waste 7-1
Landfills 7-1
Wastewater Treatment 7-4
Human Sewage 7-5
Waste Combustion 7-6
Waste Sources of Criteria Pollutants 7-7
8. References 8-1
Executive Summary 8-1
Introduction 8-1
Energy 8-1
Industrial Processes 8-4
Solvent Use 8-7
Agriculture 8-7
Land-Use Change and Forestry 8-11
Waste 8-13
Annexes
ANNEX A: Methodology for Estimating Emissions of CO from Fossil Fuel Combustion A-1
ANNEX B: Methodology for Estimating Emissions of CH , N O, and
Criteria Pollutants from Stationary Sources B-l
ANNEX C: Methodology for Estimating Emissions of CH , N O, and Criteria
Pollutants from Mobile Sources C-l
ANNEX D: Methodology for Estimating Methane Emissions from Coal Mining D-l
ANNEXE: Methodology for Estimating Methane Emissions from Natural Gas Systems E-
ANNEX F: Methodology for Estimating Methane Emissions from Petroleum Systems F-
ANNEX G: Methodology for Estimating Methane Emissions from Enteric Fermentation G-
ANNEX H: Methodology for Estimating Methane Emissions from Manure Management H-
ANNEXI: Methodology for Estimating Methane Emissions from Landfills I-
ANNEXJ: Global Warming Potentials J-
ANNEX K: Ozone Depleting Substance Emissions K-
ANNEXL: Sulfur Dioxide Emissions L-
ANNEXM: Complete List of Sources M-
ANNEXN: IPCC Reporting Tables N-
ANNEXO: IPCC Reference O-
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List of Tables and Figures
Tables
Table ES-1: Recent Trends in U.S. Greenhouse Gas Emissions
and Sinks (MMTCE) ES-3
Table ES-2: Transportation Related Greenhouse Gas Emissions (MMTCE) ES-5
Table ES-3: Electric Utility Related Greenhouse Gas Emissions (MMTCE) ES-6
Table ES-4: Global Warming Potentials (100 Year Time Horizon) ES-7
Table ES-5: U.S. Sources of CO2 Emissions and Sinks (MMTCE) ES-8
Table ES-6: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (MMTCE)* ES-9
Table ES-7: U.S. Sources of Methane Emissions (MMTCE) ES-12
Table ES-8: U.S. Sources of Nitrous Oxide Emissions (MMTCE) ES-14
Table ES-9: Emissions of MFCs, PFCs, and SF6 (MMTCE) ES-17
Table ES-10: Emissions of Ozone Depleting Substances (Mg) ES-18
Table ES-11: Emissions of NOX, CO, NMVOCs, and SO2 (Gg) ES-19
Table 1-1: Global Warming Potentials and Atmospheric Lifetimes (Years) 1-6
Table 1-2: U.S. Greenhouse Gas Emissions and Sinks (MMTCE) 1-10
Table 1-3: U.S. Greenhouse Gas Emissions and Sinks (Tg) 1-11
Table 1-4: U.S. Greenhouse Gas Emissions and Sinks by Sector (MMTCE) 1-12
Table 1-5: Transportation Related Greenhouse Gas Emissions (MMTCE) 1-13
Table 1-6: Electric Utility Related Greenhouse Gas Emissions (MMTCE) 1-14
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
Table
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Table
Table
Table
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Table
2-1: Emissions from the Energy Sector (MMTCE) 2-2
2-2: Emissions from the Energy Sector (Tg) 2-2
2-3: CO2 Emissions from Fossil Fuel Combustion by Fuel Type and End-Use Sector (MMTCE) 2-4
2-4: CO2 Emissions from Fossil Fuel Combustion by Fuel Type and End-Use Sector (Tg) 2-5
2-5: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (MMTCE)* 2-6
2-6: CO2 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (MMTCE) 2-8
2-7: CH4 Emissions from Stationary Sources (MMTCE) 2-12
2-8: N2O Emissions from Stationary Sources (MMTCE) 2-12
2-9: CH4 Emissions from Stationary Sources (Gg) 2-13
N2O Emissions from Stationary Sources (Gg) 2-13
2-10:
2-11:
2-12:
2-13:
2-14:
2-15:
2-16:
2-17:
2-18:
2-19:
2-20:
2-21:
1996 Emissions of NOX, CO, and NMVOC from Stationary Sources (Gg)
2-14
CH4 Emissions from Mobile Sources (MMTCE) 2-16
N2O Emissions from Mobile Sources (MMTCE) 2-16
CH4 Emissions from Mobile Sources (Gg) 2-17
N2O Emissions from Mobile Sources (Gg) 2-17
1996 Emissions of NOX, CO, and NMVOC from Mobile Sources (Gg) 2-18
Methane Emissions from Coal Mining (MMTCE) 2-20
Methane Emissions from Coal Mining (Tg) 2-21
Coal Production (Thousand Metric Tons) 2-22
Methane Emissions from Natural Gas Systems (MMTCE) 2-23
Methane Emissions from Natural Gas Systems (Tg) 2-23
2-22: Methane Emissions from Petroleum Systems (MMTCE) 2-25
2-23: Methane Emissions from Petroleum Systems (Gg) 2-25
2-24: Uncertainty in Methane Emissions from Petroleum Systems (Gg) 2-26
2-25: CO2 Emissions from Natural Gas Flaring 2-27
2-26: NOX, NMVOCs, and CO Emissions from Oil and Gas Activities (Gg) 2-27
2-27: CO2 Emissions from Wood Consumption by End-Use Sector (MMTCE) 2-28
2-28: CO2 Emissions from Wood Consumption by End-Use Sector (Tg) 2-28
IV
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
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Table 2-29: CC>2 Emissions fromEthanol Consumption 2-28
Table 2-30: Residential and Industrial Biomass Consumption (Trillion Btu) 2-29
Table 2-31: Ethanol Consumption 2-29
Table 3-1: Emissions from Industrial Processes (MMTCE) 3-3
Table 3-2: Emissions from Industrial Processes (Tg) 3-4
Table 3-3: CC>2 Emissions from Cement Production* 3-4
Table 3-4: Cement Production (Thousand Metric Tons) 3-5
Table 3-5: Net CC>2 Emissions from Lime Manufacture 3-6
Table 3-6: CC>2 Emissions from Lime Manufacture (Tg) 3-6
Table 3 -7: Lime Manufacture and Lime Use for Sugar Refining and PCC (Thousand Metric Tons) 3-6
Table 3-8: CC>2 Emissions from Limestone & Dolomite Use (MMTCE) 3-8
Table 3-9: CC>2 Emissions from Limestone & Dolomite Use (Tg) 3-8
Table 3-10: Limestone & Dolomite Consumption (Thousand Metric Tons) 3-8
Table 3-11: CC>2 Emissions from Soda Ash Manufacture and Consumption 3-10
Table 3-12: CO2 Emissions from Soda Ash Manufacture and Consumption (Tg) 3-10
Table 3-13: Soda Ash Manufacture and Consumption (Thousand Metric Tons) 3-10
Table 3-14: CC>2 Emissions from Carbon Dioxide Manufacture 3-11
Table 3-15: Carbon Dioxide Consumption 3-11
Table 3-16: CC>2 Emissions from Iron and Steel Production 3-12
Table 3-17: Pig Iron Production 3-12
Table 3-18: CC>2 Emissions from Ammonia Manufacture 3-13
Table 3-19: Ammonia Manufacture 3-13
Table 3-20: CC>2 Emissions from Ferroalloy Production 3-14
Table 3-21: Production of Ferroalloys (Metric Tons) 3-14
Table 3-22: CH^ Emissions from Petrochemical Production 3-15
Table 3-23: Production of Selected Petrochemicals (Metric Tons) 3-15
Table 3-24: CH^ Emissions from Silicon Carbide Production 3-16
Table 3-25: Production of Silicon Carbide 3-16
Table 3-26: ^O Emissions from Adipic Acid Manufacture 3-16
Table 3-27: Adipic Acid Manufacture 3-17
Table 3-28: ^O Emissions from Nitric Acid Manufacture 3-17
Table 3-29: Nitric Acid Manufacture 3-18
Table 3-30: Emissions of HFCs and PFCs from ODS Substitution (MMTCE) 3-19
Table 3-31: Emissions of HFCs and PFCs from ODS Substitution (Mg) 3-19
Table 3-32: CC>2 Emissions from Aluminum Production 3-23
Table 3-33: PFC Emissions from Aluminum Production (MMTCE) 3-23
Table 3-34: PFC Emissions from Aluminum Production (Mg) 3-23
Table 3-35: Production of Primary Aluminum 3-24
Table 3-36: HFC-23 Emissions from HCFC-22 Production 3-25
Table 3-37: PFC Emissions from Semiconductor Manufacture 3-26
Table 3-38: SFg Emissions from Electrical Transmission and Distribution 3-27
Table 3-39: SFg Emissions from Magnesium Production and Processing 3-27
Table 3-40: Emissions of NOX, CO, and NMVOC from Industrial Processes (Gg) 3-29
Table 4-17: Emissions of NOX, CO, and NMVOC from Solvent Use (Gg) 4-2
Table 5-1: Emissions from the Agriculture Sector (MMTCE) 5-2
Table 5-2: Emissions from the Agriculture Sector (Tg) 5-2
Table 5-3: Methane Emissions from Enteric Fermentation (MMTCE) 5-3
Table 5-4: Methane Emissions from Enteric Fermentation (Tg) 5-3
Table 5-5: Cow Populations (thousands) and Milk Production (million kilograms) 5-4
Table 5-6: CELj and ^O Emissions from Manure Management (MMTCE) 5-5
Table 5-7: Methane Emissions from Manure Management (Tg) 5-6
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Table 5-8: N2O Emissions from Manure Management (Gg) 5-6
Table 5-9: Methane Emissions from Rice Cultivation (MMTCE) 5-8
Table 5-10: Methane Emissions from Rice Cultivation (Gg) 5-9
Table 5-11: Area Harvested for Rice-Producing States (hectares) 5-9
Table 5-12: Primary Cropping Flooding Season Length (days) 5-11
Table 5-13: N2O Emissions from Agricultural Soil Management (MMTCE) 5-11
Table 5-14: N2O Emissions from Agricultural Soil Management (Gg N2O) 5-12
Table 5-15: Commercial Fertilizer Consumption (Metric Tons of Nitrogen) 5-15
Table 5-16: Animal Excretion (Metric Tons of Nitrogen) 5-15
Table 5-17: Bean, Pulse, and Alfalfa Production (Metric Tons of Product) 5-15
Table 5-18: Corn and Wheat Production (Metric Tons of Product) 5-15
Table 5-19: Histosol Area Cultivated 5-16
Table 5-20: Direct N2O Emissions from Agricultural Cropping Practices (MMTCE) 5-16
Table 5-21: Direct N2O Emissions from Pasture, Range, and Paddock Animals (MMTCE) 5-16
Table 5-22: Indirect N2O Emissions (MMTCE) 5-16
Table 5-23: Emissions from Agricultural Residue Burning (MMTCE) 5-18
Table 5-24: Emissions from Agricultural Residue Burning (Gg) 5-19
Table 6-1: Net CO2 Flux from Land-Use Change and Forestry (MMTCE) 6-1
Table 6-2: Net CO2 Flux from Land-Use Change and Forestry (Tg CO2) 6-2
Table 6-3: Net CO2 Flux from U.S. Forests (MMTCE) 6-4
Table 6-4: U.S. Forest Carbon Stock Estimates (Tg of Carbon) 6-6
Table 6-5: CO2 Flux From Non-Forest Soils (MMTCE) 6-8
Table 6-6: CO2 Flux From Non-Forest Soils (Tg CO2) 6-8
Table 6-7: Areas of Cultivated Organic Soils and Quantities of Applied Minerals 6-9
Table 7-1: Emissions from the Waste Sector (MMTCE) 7-2
Table 7-2: Emissions from the Waste Sector (Tg) 7-2
Table 7-3: CH4 Emissions from Landfills (MMTCE) 7-3
Table 7-4: CH4 Emissions from Landfills (Tg) 7-3
Table 7-5: CH4 Emissions from Domestic Wastewater Treatment 7-4
Table 7-6: U.S. Population (millions) and Wastewater BOD Produced (Gg) 7-5
Table 7-7: N2O Emissions from Human Sewage 7-5
Table A-l: 1996 Energy Consumption Data and CO2 Emissions from Fossil Fuel
Combustion by Fuel Type A-4
Table A-5: 1992 Energy Consumption Data and CO2 Emissions from Fossil Fuel
Combustion by Fuel Type A-8
Table A-6: 1991 Energy Consumption Data and CO2 Emissions from Fossil Fuel
Combustion by Fuel Type A-9
Table A-7: 1990 Energy Consumption Data and CO2 Emissions from Fossil Fuel
Combustion by Fuel Type A-10
Table A-8: 1996 Emissions From International Bunker Fuel Consumption A-ll
Table A-9: 1996 Carbon Stored In Products A-ll
Table A-10: Key Assumptions for Estimating Carbon Dioxide Emissions A-12
Table A-ll: Annually Variable Carbon Content Coefficients by Year (MMTCE/QBtu) A-13
Table A-12: Electricity Consumption by End-Use Sector (Billion Kilowatt-hours) A-13
Table B-l: Fuel Consumption by Stationary Sources for Calculating CH4 and N2O Emissions (TBtu) B-3
Table B-2: CH4 and N2O Emission Factors by Fuel Type and Sector (g/GJ) B-3
Table B-3: 1996 NOX, NMVOC, and CO Emissions from Stationary Sources (Gg) B-4
Table B-4: 1995 NOX, NMVOC, and CO Emissions from Stationary Sources (Gg) B-4
Table B-5: 1994 NOX, NMVOC, and CO Emissions from Stationary Sources (Gg) B-5
Table B-6: 1993 NOX, NMVOC, and CO Emissions from Stationary Sources (Gg) B-5
Table B-7: 1992 NOX, NMVOC, and CO Emissions from Stationary Sources (Gg) B-6
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
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Table B-8: 1991 NOX, NMVOC, and CO Emissions from Stationary Sources (Gg) B-6
Table B-9: 1990 NOX, NMVOC, and CO Emissions from Stationary Sources (Gg) B-7
Table C-l: Vehicle Miles Traveled for Gasoline Highway Vehicles (10 Miles) C-3
Table C-2: Vehicle Miles Traveled for Diesel Highway Vehicles (10 Miles) C-3
Table C-3: VMT Profile by Vehicle Age (years) and Vehicle/Fuel Type for
Highway Vehicles (percent of VMT) C-4
Table C-4: Fuel Consumption for Non-Highway Vehicles by Fuel Type (U.S. Gallons) C-5
Table C-5: Control Technology Assignments for Gasoline Passenger Cars (percentage of VMT) * C-6
Table C-6: Control Technology Assignments for Gasoline Light-Duty Trucks (percentage of VMT) * C-6
Table C-7: Control Technology Assignments for California Gasoline Passenger Cars and
Light-Duty Trucks (percentage of VMT) C-6
Table C-8: Control Technology Assignments for Gasoline Heavy-Duty Vehicles (percentage of VMT) C-7
Table C-9: Control Technology Assignments for Diesel Highway VMT C-7
Table C-10: Emission Factors (g/km) for CH4 and ^O and "Fuel
Economy" (g CO2/km)c for Highway Mobile Sources C-8
Table C-l 1: Emission Factors for CH4 and ^O Emissions from Non-Highway
Mobile Sources (g/kgfuel) C-9
Table C-12: 1996 Emissions of NOX, CO, and NMVOC from Mobile Sources (Gg) C-10
Table C-13: 1995 Emissions of NOX, CO, and NMVOC from Mobile Sources (Gg) C-10
Table C-14: 1994 Emissions of NOX, CO, and NMVOC from Mobile Sources (Gg) C-10
Table C-15: 1993 Emissions of NOX, CO, and NMVOC from Mobile Sources (Gg) C-ll
Table C-16: 1992 Emissions of NOX, CO, and NMVOC from Mobile Sources (Gg) C-12
Table C-17: 1991 Emissions of NOX, CO, and NMVOC from Mobile Sources (Gg) C-12
Table C-18: 1990 Emissions of NOX, CO, and NMVOC from Mobile Sources (Gg) C-13
Table D-l: Mine-Specific Data Used to Estimate Ventilation Emissions D-l
Table D-2: Coal Basin Definitions by Basin and by State D-3
Table D-3: Annual Underground Coal Production (thousand short tons) D-4
Table D-4: Surface and Post-Mining Coal Emission Factors (ft per short ton) D-4
Table D-5: Underground Coal Mining Methane Emissions (billion cubic feet) D-5
Table D-6: Total Coal Mining Methane Emissions (billion cubic feet) D-5
Table E-l: 1992 Data and Emissions (Mg) for Venting and Flaring from Natural Gas Field Production Stage . E-2
Table E-2: Activity Factors for Key Drivers E-3
Table E-3: Emission Estimates for Venting and Flaring from the Field Production Stage (Mg) E-4
Table F-l: Emissions from Petroleum Production Field Operations F-2
Table F-2: Emissions from Petroleum Storage F-2
Table F-3: Emissions from Petroleum Refining F-2
Table F-4: Emissions from Petroleum Transportation: Loading Alaskan Crude Oil onto Tankers (Barrels/day*)F-3
Table F-5: Emissions from Petroleum Transportation: Crude Oil Transfers to Terminals (Barrels/day*) F-3
Table F-6: Emissions from Petroleum Transportation: Ballast Emissions (Barrels/day*) F-3
Table F-7: Total Methane Emissions from Petroleum Transportation F-3
Table G-l: Livestock Population (thousand head) G-2
Table G-2: Dairy Cow Emission Factors and Milk Production Per Cow G-2
Table G-3: Emission factors Beef Cows and Replacements (kg/head/yr) G-2
Table G-4: Emissions from Livestock Enteric Fermentation (Tg) G-3
Table G-5: Enteric Fermentation Emission Factors G-3
Table H-l: Livestock Population (1000 head) H-2
Table H-2: Dairy Cow and Swine Methane Conversion Factors H-3
Table H-3: Dairy Cow and Swine Constants H-3
Table H-4: Emissions from Livestock Manure Management (Tg) H-4
VII
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Table 1-1: Municipal Solid Waste (MSW) Contributing to Methane Emissions (Tg) 1-2
Table 1-2: Methane Emissions from Landfills (Tg) 1-2
Table 1-3: Municipal Solid Waste Landfill Size Definitions (Tg) 1-3
Table J-l: Global Warming Potentials and Atmospheric Lifetimes (years) J-l
Table K-l: Emissions of Ozone Depleting Substances (Mg) K-2
Table L-l: Emissions of SO2 (Gg) L-2
Table L-2: Emissions of SC^ from Electric Utilities (Gg) L-2
Table O-l: 1996 U.S. Energy Statistics (physical units) O-5
Table O-2: Conversion Factors to Energy Units (heat equivalents) O-6
Table O-3: 1996 Apparent Consumption of Fossil Fuels (trillion Btu) O-7
Table O-4: 1996 Potential Carbon Emissions O-8
Table O-5: 1996 Carbon Stored in Products O-9
Table O-6: Reference Approach CC>2 Emissions from Fossil Fuel Consumption
(MMTCE unless otherwise noted) O-9
Table O-7: 1996 Energy Consumption in the United States: Sectoral vs. Reference
Approaches (trillion BTU) O-10
Table O-8: 1996 CC>2 Emissions from Fossil Fuel Combustion by Estimating
Approach (MMTCE) O-10
Table P-l: Preliminary 1997 Estimates of U.S. Greenhouse Gas Emissions and Sinks P-2
Figures
Figure ES-1: Recent Trends inU.S. Greenhouse Gas Emissions ES-2
Figure ES-2: 1996 Greenhouse Gas Emissions by Gas ES-2
Figure ES-3: 1996 Sources of CO2 ES-8
Figure ES-4: 1996 U.S. Energy Consumption ES-8
Figure ES-5: 1996 CC>2 Emissions from Fossil Fuel Combustion by End-Use Sector and Fuel Type ES-9
Figure ES-6: 1996 Sources of CH4 ES-11
Figure ES-7: 1996 Sources of N2O ES-15
Figure ES-8: 1996 Sources of HFCs, PFCs, and SF6 ES-16
Figure 1-1: Recent Trends in U.S. GHG Emissions 1-8
Figure 1-2: U.S. GHG Emissions by Gas 1-9
Figure 1-3: Total U.S. GHG Emissions by Sector 1-9
Figure 2-1: 1996 Energy Sector GHG Sources 2-1
Figure 2-2: 1996 U.S. Energy Consumption 2-3
Figure 2-3: Fossil Fuel Production Prices 2-3
Figure 2-4: 1996 CC>2 Emissions from Fossil Fuel Combustion by End-Use Sector and Fuel Type 2-6
Figure 2-5: Motor Vehicle Fuel Efficiency 2-7
Figure 2-6: U.S. Vehicle Miles Traveled 2-7
Figure 2-7: Mobile Source CH4 andN2O Emissions 2-15
Figure 3-1: 1996 Industrial Processes Sector GHG Sources 3-1
Figure 5-1: 1996 Agriculture Sector GHG Sources 5-1
Figure 7-1: 1996 Waste Sector GHG Sources 7-1
viii Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
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Executive Summary
Central to any study of climate change is the development of an emission inventory that identifies and
quantifies a country's primary anthropogenic sources and sinks of greenhouse gas (GHG) emissions. This
inventory adheres to both (1) a comprehensive and detailed methodology for estimating sources and sinks of anthro-
pogenic greenhouse gases, and (2) a common and consistent mechanism that enables signatory countries to the
United Nations' Framework Convention on Climate Change (FCCC) to compare the relative contribution of different
emission sources and greenhouse gases to climate change. Moreover, systematically and consistently estimating
national and international emissions is a prerequisite for evaluating the cost-effectiveness and feasibility of mitigation
strategies and emission reduction technologies.
This chapter summarizes the latest information on U.S. anthropogenic greenhouse gas emission trends from
1990 through 1996.' To ensure that the U.S. emissions inventory is comparable to those of other FCCC signatory
countries, the estimates presented here were calculated using methodologies similar to those recommended in the
Revised 1996IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997). For emis-
sion sources related to energy consumption, land-use change and forestry, hydrofluorocarbons (HFCs), perfluorocarbons
(PFCs), sulfur hexafluoride (SF6), and select methane (CH4) sources, the IPCC default methodologies were expanded,
resulting in a more comprehensive and detailed estimate of emissions.
Recent Trends in U.S. Greenhouse Gas Emissions
Naturally occurring greenhouse gases include water vapor, carbon dioxide (CO2), methane (CH4), nitrous oxide
(N2O), and ozone (O3). Several classes of halogenated substances that contain fluorine, chlorine, or bromine are also
greenhouse gases, but they are, for the most part, solely a product of industrial activities. Chlorofluorocarbons
(CFCs) and hydrochlorofluorocarbons (HCFCs) are halocarbons that contain chlorine, while halocarbons that con-
tain bromine are referred to as halons. Other fluorine containing halogenated substances include hydrofluorocarbons
(HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6).
There are also several gases that, although they do not have a direct global warming effect, do influence the
formation and destruction of ozone, which does have such a terrestrial radiation absorbing effect. These gases-
referred to here as ozone precursors-include carbon monoxide (CO), oxides of nitrogen (NOx), and nonmethane
volatile organic compounds (NMVOCs).2 Aerosols-extremely small particles or liquid droplets often produced by
emissions of sulfur dioxide (SO2)-can also affect the absorptive characteristics of the atmosphere.
See Introduction chapter for discussion of changes in this inventory relative to previous U.S. greenhouse gas inventories.
Also referred to in the U.S. Clean Air Act as "criteria pollutants."
Executive Summary ES-1
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Although CO2, CH4, and N2O occur naturally in
the atmosphere, the atmospheric concentration of each
of them has risen, largely as a result of human activities.
Since 1800, atmospheric concentrations of these green-
house gases have increased by 30, 145, and 15 percent,
respectively (IPCC 1996). This build-up has altered the
composition of the earth's atmosphere, and may affect
the global climate system.
Beginning in the 1950s, the use of CFCs and other
ozone depleting substances (ODSs) increased by nearly
10 percent a year, until the mid-1980s when international
concern about ozone depletion led to the signing of the
Montreal Protocol. Since then, the consumption of
ODSs has rapidly declined as they are phased-out. In
contrast, use of ODS substitutes such as HFCs, PFCs.
and SF6 has grown significantly.
Figure ES-1 and Table ES-1 summarize the trends
in U.S. greenhouse gas emissions and sinks for 1990
through 1996. Estimates are presented in units of mil-
lions of metric tons of carbon equivalents (MMTCE),
which weights each gas by its GWP value, or global
warming potential (see following section).
Figure ES-2 illustrates the relative contribution of
the primary greenhouse gases to total U.S. emissions in
1996. The largest source of CO2 and of overall GHG
emissions in the United States was fossil fuel combus-
tion. Methane emissions resulted primarily from de-
composition of wastes in landfills, manure and enteric
fermentation associated with domestic livestock, natu-
ral gas systems, and coal mining. Emissions of nitrous
Figure ES-1
Recent Trends in U.S. Greenhouse Gas Emissions
Figure ES-2
MFCs. PFCa, & SFfi
6,8% N20
02.3% CO,
Carbon Dioxide
Oxide
1,reo
1,540
1.2 50
1.0011
1C 30 -J01 139Z 1W3 1D94 19*5
oxide were dominated by agricultural soil management
and mobile source fossil fuel combustion. The substitu-
tion of ozone depleting substances and emissions of HFC-
23 during the production of HCFC-22 were the primary
contributors to aggregate HFC emissions. PFC emissions
came mainly from primary aluminum production, while
electrical transmission and distribution systems emitted
the majority of SF6.
Total U.S. greenhouse gas emissions rose in 1996
to 1,788.0 MMTCE (9.5 percent above 1990 baseline
levels). The largest single year increase in emissions over
this time period was registered in 1996 (57.0 MMTCE
or 3.3 percent).
The largest source of U.S. GHG
emissions was CO2 from fossil fuel com-
bustion, which accounted for 81 percent
in 1996. Emissions of CO2 from fossil
fuel combustion grew by 9 percent (118.9
MMTCE) over the seven year period and
were responsible for over two-thirds of the
I increase in national emissions. The larg-
est annual increase in emissions from this
source was also registered in 1996, when
increased fuel consumption drove CO2
emissions up by 3.7 percent. The primary
factors for this later single year increase
ASF
ES-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table ES-1: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (MMTCE)
Gas/Source 1990 1991 1992 1993 1994
1995
1996
C02
Fossil Fuel Combustion
Natural Gas Flaring
Cement Manufacture
Lime Manufacture
Limestone and Dolomite Use
1,348.3
1,331.4
2.0
8.9
3.3
1.4
Soda Ash Manufacture and Consumption 1.1
Carbon Dioxide Manufacture
Land-Use Change and Forestry (Sink)*
CH4
Stationary Sources
Mobile Sources
Coal Mining
Natural Gas Systems
Petroleum Systems
Petrochemical Production
Silicon Carbide Production
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Residue Burning
Landfills
Wastewater Treatment
N20
Stationary Sources
Mobile Sources
Adipic Acid
Nitric Acid
Manure Management
Agricultural Soil Management
Agricultural Residue Burning
Human Sewage
Waste Combustion
MFCs, PFCs, and SF6
Substitution of Ozone
Depleting Substances
Aluminum Production
HCFC-22 Production
Semiconductor Manufacture
Electrical Transmission and Distribution
Magnesium Production and Processing
Total Emissions
Net Emission (Sources and Sinks)
0.2
(311.5)
169.9
2.3
1.5
24.0
32.9
1.6
0.3
+
32.7
14.9
2.5
0.2
56.2
0.9
92.3
3.7
13.2
4.7
3.4
2.6
62.4
0.1
2.1
0.1
22.2
0.3
4.9
9.5
0.2
5.6
1.7
1,632.7
1,321.2
1,333.2
1,316.4
2.2
8.7
3.2
1.3
1.1
0.2
(311.5)
171.1
2.3
1.4
22.8
33.3
1.6
0.3
+
32.8
15.4
2.5
0.2
57.6
0.9
94.4
3.7
13.9
4.9
3.3
2.8
63.4
0.1
2.1
0.1
21.6
0.2
4.7
8.4
0.4
5.9
2.0
1,620.2
1,308.7
1,353.4
1,336.6
2.2
8.8
3.3
1.2
1.1
0.2
(311.5)
172.5
2.4
1.4
22.0
33.9
1.6
0.3
+
33.2
16.0
2.8
0.2
57.8
0.9
96.8
3.7
14.8
4.6
3.4
2.8
65.2
0.1
2.2
0.1
23.0
0.4
4.1
9.5
0.6
6.2
2.2
1,645.7
1,334.2
1,385.6
1,367.5
3.0
9.3
3.4
1.1
1.1
0.2
(208.6)
171.9
2.3
1.4
19.2
34.1
1.6
0.4
+
33.6
16.1
2.5
0.2
59.7
0.9
97.1
3.8
15.6
4.9
3.5
2.9
64.1
0.1
2.2
0.1
23.4
1.4
3.5
8.7
0.8
6.4
2.5
1,678.0
1,469.4
1,408.5
1,389.6
3.0
9.6
3.5
1.5
1.1
0.2
(208.6)
175.9
2.3
1.4
19.4
33.9
1.6
0.4
+
34.5
16.7
3.0
0.2
61.6
0.9
104.9
3.8
16.3
5.2
3.7
2.9
70.4
0.1
2.3
0.1
25.9
4.0
2.8
8.6
1.0
6.7
2.7
1,715.3
1,506.7
1,419.2
1,398.7
3.7
9.9
3.7
1.8
1.2
0.3
(208.6)
179.2
2.4
1.4
20.3
33.8
1.6
0.4
+
34.9
16.9
2.8
0.2
63.6
0.9
101.9
3.8
16.6
5.2
3.7
2.9
67.2
0.1
2.2
0.1
30.8
9.5
2.7
7.4
1.2
7.0
3.0
1,731.1
1,522.5
1,471.1
1,450.3
3.5
10.1
3.8
1.8
1.2
0.3
(208.6)
178.6
2.5
1.4
18.9
34.1
1.5
0.4
+
34.5
16.6
2.5
0.2
65.1
0.9
103.7
4.0
16.5
5.4
3.8
3.0
68.6
0.1
2.3
0.1
34.7
11.9
2.9
8.5
1.4
7.0
3.0
1,788.0
1,579.5
+ Does not exceed 0.05 MMTCE
* Sinks are only included in net emissions total. Estimates of net carbon sequestration due to land-use change and forestry activities exclude
non-forest soils, and are based partially upon projections of forest carbon stocks.
Note: Totals may not sum due to independent rounding.
Executive Summary ES-3
-------
were (1) fuel switching by electric utilities from natural
gas to more carbon intensive coal as gas prices rose
sharply, (2) higher petroleum consumption in the trans-
portation end-use sector as travel increased and fuel effi-
ciency stagnated, (3) greater natural gas consumption for
heating in the residential end-use sector due to colder
weather, and (4) overall robust domestic economic
growth.
• Other significant trends in emissions over the seven
year period of 1990 through 1996 included:
• Combined N2O and CH4 emissions from mobile
source fossil fuel combustion rose 3.2 MMTCE
(22 percent), primarily due to increased rates of N2O
generation in highway vehicles.
• Aggregate HFC and PFC emissions resulting from
the substitution of ozone depleting substances (e.g.,
CFCs) increased dramatically (by 11.6 MMTCE);
however PFC emissions from aluminum production
decreased significantly (41 percent) as a result of
both voluntary industry emission reduction efforts
and falling domestic aluminum production.
Methane emissions from the decomposition of waste
in municipal and industrial landfills rose by 8.9
MMTCE (16 percent) as the amount of organic mat-
ter in landfills steadily accumulated.
Emissions from coal mining dropped by 5.1
MMTCE (21 percent) as the use of methane from
degasification systems increased significantly.
Nitrous oxide emissions from agricultural soil man-
agement increased by 6.2 MMTCE (10 percent) as
fertilizer consumption and cultivation of nitrogen fix-
ing crops rose.
Greenhouse Gas Emissions from Transportation Activities
Motor vehicle usage is increasing all over the world, including in the United States. Since the 1970s, the number of highway vehicles
registered in the United States has increased faster than the overall population, according to the Federal Highway Administration.
Likewise, the number of miles driven-up 15 percent since 1990-and gallons of gasoline consumed each year in the United States has
increased relatively steadily since the 1980s, according to the Energy Information Administration. These increases in motor vehicle
usage are the result of a confluence of factors including population growth, economic growth, increasing urban sprawl, and low fuel prices.
One of the unintended consequences of these changes was a slowing of progress toward cleaner air in both urban and rural parts of the
country. Passenger cars, trucks, motorcycles, and buses emit significant quantities of air pollutants with local, regional, and global
effects. Motor vehicles were major sources of carbon monoxide, carbon dioxide (C02), methane (CH4), nonmethane volatile organic
compounds, nitrogen oxides, nitrous oxide (N20), and hydrofluorocarbons (MFCs). Motor vehicles were also important contributors to
many serious air pollution problems, including ground level ozone or smog, acid rain, fine paniculate matter, and global warming. Within
the United States and abroad, government agencies have taken strong actions to reduce these emissions. Since the 1970s, the EPA has
reduced lead in gasoline, developed strict emission standards for new passenger cars and trucks, directed states to enact comprehensive
motor vehicle emission control programs, required inspection and maintenance programs, and more recently, introduced the use of
reformulated gasoline to mitigate the air pollution impacts from motor vehicles. New vehicles are now equipped with advanced emissions
controls, which are designed to reduce emissions of nitrogen oxides, hydrocarbons, and carbon monoxide.
This report reflects new data on the role that automotive catalytic converters play in emissions of N20, a powerful greenhouse gas. The
EPA's Office of Mobile Sources has recently conducted a series of tests in order to measure the magnitude of N20 emissions from
gasoline-fueled passenger cars and light-duty trucks equipped with catalytic converters. Results show that N20 emissions are lower
than the IPCC default factors and the United States has shared this data with the IPCC. Now, new emission factors developed from
these measurements and from previously published literature were used to calculate emissions from mobile sources in the United States
(see Annex C).
Table ES-2 summarizes greenhouse gas emissions from all transportation related activities. Overall, transportation activities accounted
for an almost constant 26 percent of total U.S. greenhouse gas emissions from 1990 to 1996. These emissions were primarily C02from
fuel combustion, which increased by 8.8 percent from 1990 to 1996. However, because of larger increases in N20and HFC emissions
during this period, overall emissions from transportation activities actually increased by 10.1 percent.
ES-4
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table ES-2: Transportation Related Greenhouse Gas Emissions (MMTCE)
Gas/Vehicle Type
Aircraft
Boats and Vessels
Locomotives
1990
1991
1992
1993
1994
0.1
0.1
0.1
1995
1996
C02
Passenger Cars3
Light-Duty Trucks3
Other Trucks
Buses
Aircraft
Boats and Vessels
Locomotives
Other"
CH4
Passenger Cars
Light-Duty Trucks
Other Trucks and Buses
409.6
169.3
77.5
56.8
2.7
55.9
16.3
7.4
23.7
1.5
0.8
0.4
0.1
400.8
167.8
77.2
54.7
2.9
53.8
15.0
6.9
22.4
1.4
0.7
0.4
0.1
406.7
172.0
77.2
56.6
2.9
53.0
15.3
7.4
22.4
1.4
0.7
0.4
0.1
414.1
173.5
80.5
59.7
3.0
53.5
13.4
6.7
23.7
1.4
0.7
0.4
0.2
427.4
172.5
87.2
62.4
3.3
55.6
13.7
8.0
24.8
1.4
0.7
0.4
0.2
432.8
160.0
104.9
64.0
3.5
55.0
12.5
8.1
24.9
1.4
0.7
0.4
0.2
445.5
163.2
107.1
67.0
3.7
57.4
13.2
8.5
25.5
1.4
0.6
0.4
0.2
Other0
N20
Passenger Cars
Light-Duty Trucks
Other Trucks and Buses
Aircraft"
Boats and Vessels
Locomotives
Other0
HFCs
Mobile Air Conditioners6
Total
0.1
13.2
8.7
3.4
0.7
+
0.2
0.1
0.2
+
+
424.3
0.1
13.9
9.1
3.7
0.7
+
0.2
0.1
0.2
+
+
416.1
0.1
14.8
9.7
3.9
0.7
+
0.2
0.1
0.2
0.2
0.2
423.2
0.1
15.6
10.1
4.2
0.7
+
0.2
0.1
0.2
0.7
0.7
431.7
0.1
16.3
10.0
5.1
0.8
+
0.2
0.1
0.2
1.3
1.3
446.4
0.1
16.6
10.1
5.2
0.8
+
0.2
0.1
0.2
2.5
2.5
453.3
0.1
16.5
10.1
5.1
0.9
+
0.2
0.1
0.2
3.6
3.6
467.0
+ Does not exceed 0.05 MMTCE
Note: Totals may not sum due to independent rounding.
' In 1995, the U.S. Federal Highway Administration modified the definition of light-duty trucks to include minivans and sport utility vehicles.
Previously, these vehicles were included under the passenger cars category. Hence the sharp drop in C02 emissions for passenger cars from
1994 to 1995 was observed. This gap, however, was offset by an equivalent rise in C02 emissions from light-duty trucks.
" "Other" C02 emissions includes motorcycles, construction equipment, agricultural machinery, pipelines, and lubricants.
c "Other" CH4 and N20 emissions includes motorcycles, construction equipment, agricultural machinery, gasoline-powered recreational,
industrial, lawn and garden, light commercial, logging, airport service, other equipment; and diesel-powered recreational, industrial, lawn and
garden, light construction, airport service.
d Aircraft N20 emissions include aviation gasoline combustion but exclude jet fuel combustion due to insufficient data availability.
'Includes primarily HFC-134a
Overall, from 1990 to 1996 total emissions of CO2,
CH4, and N2O increased by 122.8 (9 percent), 8.6 (5 per-
cent), and 11.4 MMTCE (12 percent), respectively. During
the same period, weighted emissions of HFCs, PFCs, and
SF6 rose by 12.5 MMTCE (56 percent). Despite being
emitted in smaller quantities, emissions of HFCs, PFCs,
and SF6 are significant because of their extremely high glo-
bal warming potentials and, in the cases of PFCs and SF6,
long atmospheric lifetimes. U.S. greenhouse gas emissions
were partly offset by carbon sequestration in forests.
The following sections describe the concept of Glo-
bal Warming Potentials (GWPs), present the anthropo-
genic sources and sinks of greenhouse gas emissions in
the United States, briefly discuss emission pathways,
summarize the emission estimates, and explain the rela-
tive importance of emissions from each source category.
Executive Summary ES-5
-------
Electric Utility Related Greenhouse Gas Emissions
Like transportation, activities related to the generation, transmission and distribution of electricity in the United States result in
greenhouse gas emissions. Table ES-3 presents greenhouse gas emissions from electric utility related activities. Overall emis-
sions from electric utilities increased by 8.6 percent from 1990 to 1996, and accounted for just under 30 percent of total U.S.
greenhouse emissions during the same period.
Table ES-3: Electric Utility Related Greenhouse Gas Emissions (MMTCE)
Gas/Fuel Type or Source
1990
1991
1992
1993
1994
1995
1996
C02
Natural Gas
Petroleum
Geothermal
CH
Stationary Sources (Utilities)
N20
Stationary Sources (Utilities)
SF6
Electrical Transmission and Distribution
Total
476.8
41.2
26.6
0.1
0.1
0.1
2.0
2.0
5.6
5.6
484.6
473.4
41.1
25.1
0.1
0.1
0.1
2.0
2.0
5.9
5.9
481.4
472.5
40.7
19.9
0.1
0.1
0.1
2.0
2.0
6.2
6.2
480.8
490.7
39.5
22.5
0.1
0.1
0.1
2.1
2.1
6.4
6.4
499.3
494.8
44.0
20.6
+
0.1
0.1
2.1
2.1
6.7
6.7
503.7
493.8
47.2
14.0
+
0.1
0.1
2.1
2.1
7.0
7.0
503.1
516.8
40.3
15.6
+
0.1
0.1
2.2
2.2
7.0
7.0
526.2
+ Does not exceed 0.05 MMTCE
Note: Totals may not sum due to independent rounding.
Global Warming Potentials
Gases in the atmosphere can contribute to the green-
house effect both directly and indirectly. Direct effects oc-
cur when the gas itself is a greenhouse gas; indirect radia-
tive forcing occurs when chemical transformations of the
original gas produce a gas or gases that are greenhouse gases,
or when a gas influences the atmospheric lifetimes of other
gases. The concept of Global Warming Potential (GWP)
has been developed to compare the ability of each green-
house gas to trap heat in the atmosphere relative to another
gas. Carbon dioxide was chosen as the reference gas to be
consistent with IPCC guidelines.
Global Warming Potentials are not provided for the
criteria pollutants CO, NOx, NMVOCs, and SO2 because
there is no agreed upon method to estimate their contri-
bution to climate change. These gases affect radiative
forcing indirectly (IPCC 1996).
All gases in this inventory are presented in units of
million metric tons of carbon equivalents (MMTCE). Car-
bon comprises 12/44ths of carbon dioxide by weight. In
order to convert emissions reported in teragrams (Tg) of
greenhouse gas to MMTCE, the following equation was
used:
MMTCE = (Tgof gas)x(GWP)x| —
The GWP of a greenhouse gas is the ratio of global
warming, or radiative forcing (both direct and indirect), from
one unit mass of a greenhouse gas to one unit mass of car-
bon dioxide over a period of time. While any time period
can be selected, the 100 year GWPs recommended by the
IPCC, and employed by the United States for policy mak-
ing and reporting purposes, were used in this report (IPCC
1996). A tabulation of GWPs is shown in Table ES-4.
Carbon Dioxide Emissions
The global carbon cycle is made up of large car-
bon flows and reservoirs. Hundreds of billions of tons
of carbon in the form of CO2 are ab sorbed by oceans and
living biomass (sinks) and are emitted to the atmosphere
annually through natural processes (sources). When in
equilibrium, carbon fluxes among these various reser-
voirs are roughly balanced.
Since the Industrial Revolution, the equilibrium of
atmospheric carbon has been increasingly compromised.
Atmospheric concentrations of CO2 have risen about 28
percent (IPCC 1996), principally because of fossil fuel
combustion, which accounted for 99 percent of total U.S.
ES-6
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table ES-4: Global Warming Potentials (100 Year Time Horizon)
Gas GWP
Gas
Carbon dioxide (C02) 1
Methane (CH4)* 21
Nitrous oxide (N20) 310
HFC-23 11,700
HFC-125 2,800
HFC-134a 1,300
HFC-143a 3,800
HFC-152a 140
HFC-227ea
HFC-236fa
HFC-4310mee
CF,
GWP
2,900
6,300
1,300
6,500
9,200
7,000
7,400
23,900
Source: (IPCC 1996)
* The methane GWP includes the direct effects and those indirect effects due to the production of tropospheric ozone and stratospheric
water vapor. The indirect effect due to the production of C02 is not included.
CO2 emissions in 1996. Changes in land-use and for-
estry practices can also emit CO2 (e.g., through conver-
sion of forest land to agricultural or urban use) or can act
as a sink for CO2 (e.g., through net additions to forest
biomass).
Table ES-5 and Figure ES-3 summarizes U.S.
sources and sinks of CO2, while the remainder of this
section discusses CO2 emission trends in greater detail.
Energy Sector
Energy related activities accounted for 86 percent
of all U.S. greenhouse gas emissions in 1996. Carbon
dioxide from fossil fuel combustion was the main con-
tributor, although CH4 and N2O were also emitted. Ap-
proximately 85 percent of U.S. energy was produced
through the combustion of fossil fuels in 1996. The re-
maining 15 percent came from renewable or other en-
ergy sources such as hydropower, biomass, and nuclear
energy (see Figure ES-4). Energy related activities other
than fuel combustion, such as those associated with the
production, transmission, storage, and distribution of fos-
sil fuels, also emit GHGs (primarily methane). A dis-
cussion of specific Energy sector trends is presented be-
low.
Fossil Fuel Combustion
As fossil fuels are combusted, the carbon stored in
them is almost entirely emitted as CO2. The amount of
carbon in fuels with a given energy content varies sig-
nificantly by fuel type. For example, coal contains the
highest amount of carbon per unit of energy, while pe-
troleum has about 25 percent less carbon than coal, and
natural gas has about 45 percent less. Petroleum sup-
plied the largest share of U.S. energy demands, account-
ing for an average of 3 9 percent of total energy consump-
Table ES-5: U.S. Sources of CO Emissions and Sinks (MMTCE)
Source
1990
1991
1992
1993
1994
1995
1996
Fossil Fuel Combustion 1,331.4
Natural Gas Flaring 2.0
Cement Manufacture 8.9
Lime Manufacture 3.3
Limestone and Dolomite Use 1 .4
Soda Ash Manufacture and Consumption 1.1
Carbon Dioxide Manufacture 0.2
Land-Use Change and Forestry (Sink)* (311.5)
Total Emissions 1,348.3
Net Emissions (Sources and Sinks) 1,036.8
1,316.4
2.2
8.7
3.2
1.3
1.1
0.2
(311.5)
1,333.2
1,021.7
1,336.6
2.2
8.8
3.3
1.2
1.1
0.2
(311.5)
1,353.4
1,041.9
1,367.5
3.0
9.3
3.4
1.1
1.1
0.2
(208.6)
1,385.6
1,177.0
1,389.6
3.0
9.6
3.5
1.5
1.1
0.2
(208.6)
1,408.5
1,200.0
1,398.7
3.7
9.9
3.7
1.8
1.2
0.3
(208.6)
1,419.2
1,210.6
1,450.3
3.5
10.1
3.8
1.8
1.2
0.3
(208.6)
1,471.1
1,262.5
+ Does not exceed 0.05 MMTCE
* Sinks are only included in net emissions total. Estimates of net carbon sequestration due to land-use change and forestry activities exclude
non-forest soils, and are based partially upon projections of forest carbon stocks.
Note: Totals may not sum due to independent rounding.
Executive Summary ES-7
-------
Figure ES-3
Figure ES-4
1996 Sources o
LlmeMorte and
Mmiurnctur-
and ConBumptiwi |
Carbon thoclda
I'n-lnr ptf>l Er^»nm
H
I •
wrct
10 13
tion over the 1990 through 1996 period. Natural gas and
coal followed in order of importance, accounting for an
average of 24 and 22 percent of total consumption, re-
spectively. Most petroleum was consumed in the trans-
portation end-use sector, while the vast majority of coal
was used by electric utilities, with natural gas consumed
largely in the industrial and residential end-use sectors.
Emissions of CO2 from fossil fuel combustion in-
creased at an annualized rate of 1.4 percent from 1990 to
1996. The primary factors behind this trend were (1) a ro-
bust domestic economy, (2) relatively low energy prices,
and (3) fuel switching by electric utilities. After 1990, when
CO2 emissions from fossil fuel combustion were 1,331.4
MMTCE, there was a slight decline in emissions in 1991,
followed by a steady increase to 1,450.3 MMTCE in 1996.
Overall, CO2 emissions from fossil fuel combustion in-
creased by 9 percent over the seven year period and rose by
a dramatic 3.7 percent in the final year alone.
Of all fossil fuel combustion related emissions from
1995 to 1996, emissions from coal grew the most (an
increase of 25.5 MMTCE or 5 percent), while emissions
from natural gas changed the least (an increase of 3.8
MMTCE or 1 percent) as electric utilities increased their
consumption of coal, while shifting away from natural
gas because of higher gas prices. Alone, emissions from
coal combustion by electric utilities increased by over 6
percent from 1995 to 1996.
J996 U.S. Energy Consumption
*lLli:ltmr
U.S. Energy Consumption (Quadrillion Btu)
Source: DOE/EIA-0384(96), Annual Energy Review 1996,
Table 1.3, July 1997
Despite slightly higher prices, the consumption of
petroleum products in 1996 increased 3.5 percent from
the previous year, accounting for about 43 percent of the
increase in CO2 emissions from fossil fuel combustion.
More than half of the increase in emissions from petro-
leum was due to an increase in fuel consumption for trans-
portation activities.
From 1995 to 1996, emissions from natural gas rose
only 1.2 percent, largely due to higher natural gas prices in
1996 that reversed a 10 year long trend of declining prices.
The U.S. Department of Energy's Energy Information Ad-
ministration cited low levels of storage and unusually cold
weather as the two main reasons for this price increase (El A
1997). Natural gas related emissions from the residential
end-use sector rose by 7.9 percent while electric utilities
experienced a dramatic 14.5 percent decrease. This sharp
reduction in utilities' gas consumption can be explained, in
large part, by a 33 percent increase in the price of natural
gas for utilities (EIA 1997).
Industrial End- Use Sector. Industry accounted for
33 percent of U.S. emissions from fossil fuel consump-
tion (see Figure ES-5 and Table ES-6). About two-thirds
of these emissions result from producing steam and pro-
cess heat from fossil fuel combustion, while the remain-
ing third results from consuming electricity for such uses
as motors, electric furnaces, ovens, and lighting.
ES-8
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Figure ES-5
1996 CO2 Emissions from Fossil
Fuel Combustion by End-Use
Sector and Fuel Type
* Utilities also includes emissions of 0.04 MMTCE from
geothermal based electricity generation
Transportation End-Use Sector. Transportation
activities accounted for 31 percent of CO2 emissions from
fossil fuel combustion in 1996. Virtually all of the en-
ergy consumed in this sector came from petroleum prod-
ucts. Nearly two thirds of the emissions resulted from
gasoline consumption in mo tor vehicles. The remaining
emissions came from other transportation activities, in-
cluding the combustion of diesel fuel for heavy-duty ve-
hicles and jet fuel for aircraft.
Residential and Commercial End- Use Sectors. The
residential and commercial sectors accounted for 20 and
16 percent, respectively, of CO2 emissions from fossil
fuel consumption in 1996. Both sectors relied heavily
on electricity for meeting energy needs, with about two-
thirds and three-quarters of their emissions attributable
to electricity consumption, respectively, for lighting, heat-
ing, cooling, and operating appliances. The remaining
emissions were largely due to the consumption of natu-
ral gas and petroleum, primarily for meeting heating and
cooking needs.
Electric Utilities. The United States relies on elec-
tricity to meet a significant portion of its energy demands,
especially for lighting, electric motors, heating, and air
conditioning. Electric utilities are responsible for con-
suming 27 percent of U.S. energy and emitted 36 per-
cent of CO2 from fossil fuel consumption in 1996. The
type of fuel combusted by utilities has a significant ef-
fect on their emissions. For example, some electricity is
generated with low CO2 emitting energy technologies,
particularly non-fossil options such as nuclear, hydro-
electric, or geothermal energy. However, electric utili-
ties rely on coal for over half of their total energy re-
quirements and accounted for 88 percent of all coal con-
sumed in the United States in 1996. Consequently,
changes in electricity demand have a significant impact
on coal consumption and associated CO2 emissions.
Natural Gas Flaring
Carbon dioxide is produced when methane trapped
in natural gas systems or oil wells is flared (i.e., com-
busted) to relieve rising pressure or to dispose of small
quantities of gas that are not commercially marketable.
In 1996, flaring activities emitted approximately 3.5
MMTCE, or about 0.2 percent of U.S. CO2 emissions.
Biomass Combustion
Biomass, in the form of fuel wood and wood waste,
is used primarily by the industrial end-use sector, while
the transportation end-use sector dominates the use of
Table ES-6: CO Emissions from Fossil Fuel Combustion by End-Use Sector (MMTCE)*
End-Use Sector
1990
1991
1992
1993
1994
1995
1996
Residential
Commercial
Industrial
Transportation
U.S. Territories
Total
253.0
206.7
453.1
409.6
9.1
1331.4
257.0
206.4
441.6
400.8
10.7
1316.4
255.7
205.3
459.0
406.7
9.8
1336.6
271.6
212.2
459.0
414.1
10.6
1367.5
268.6
214.1
468.1
427.4
11.4
1389.6
269.7
219.2
465.7
432.8
11.2
1398.7
286.7
229.9
477.5
445.5
10.8
1450.3
* Emissions from fossil fuel combustion by electric utilities are allocated based on electricity consumption by each end-use sector.
Note: Totals may not sum due to independent rounding.
Executive Summary ES-9
-------
biomass-based fuels, such as ethanol from corn and
woody crops. Ethanol and ethanol blends, such as gaso-
hol, are typically used to fuel public transport vehicles.
Although these fuels do emit CO2, in the long run
the CO2 emitted frombiomass consumption does not in-
crease atmospheric CO2 concentrations, assuming 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 cre-
ating a net increase in total atmospheric carbon. Net car-
bon fluxes from changes in biogenic carbon reservoirs
in wooded or crop lands are accounted for under the Land-
Use Change and Forestry sector.
CO2 emissions frombiomass combustion were 54.6
MMTCE, with the industrial end-use sector accounting
for 71 percent of the emissions, and the residential end-
use sector, 24 percent. Ethanol consumption by the trans-
portation end-use sector accounted for only 3 percent of
CO2 emissions from biomass combustion.
Industrial Processes
Emissions are often produced as a by-product of
various non-energy-related activities. For example, in-
dustrial processes can chemically transform raw materi-
als from one state to another. This transformation often
releases greenhouse gases such as CO2. The production
processes that emit CO2 include cement manufacture,
lime manufacture, limestone and dolomite use (e.g., in
iron and steel making), soda ash manufacture and con-
sumption, and CO2 manufacture. Total carbon dioxide
emissions from these sources were approximately 17.3
MMTCE in 1996, accounting for about 1 percent of to-
tal CO2 emissions. Since 1990, emissions from each of
these sources increased, except for emissions from soda
ash manufacture and consumption, which remained rela-
tively constant.
Cement Manufacture (10.1 MMTCE)
Carbon dioxide is produced primarily during the
production of clinker, an intermediate product from which
finished Portland and masonry cement are made. Spe-
cifically, CO2 is created when calcium carbonate (CaCO3)
is heated in a cement kiln to form lime and CO0. This
lime combines with other materials to produce clinker,
while the CO2 is released into the atmosphere.
Lime Manufacture (3.8 MMTCE)
Lime is used in steel making, construction, pulp
and paper manufacturing, and water and sewage treat-
ment. It is manufactured by heating limestone (mostly
calcium carbonate, CaCO3) in a kiln, creating calcium
oxide (quicklime) and CO2, which is normally emitted
to the atmosphere.
Limestone and Dolomite Use (1.8 MTCE)
Limestone (CaCO3) and dolomite (CaCO3MgCO3)
are basic raw materials used by a wide variety of indus-
tries, including the construction, agriculture, chemical,
and metallurgical industries. 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 desulfur-
ization systems to remove sulfur dioxide from the ex-
haust gases.
Soda Ash Manufacture and
Consumption (1.2 MMTCE)
Commercial soda ash (sodium carbonate, Na2CO3) is
used in many consumer products, such as glass, soap and
detergents, paper, textiles, and food. During the manufac-
turing of these products, natural sources of sodium carbon-
ate 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.
Carbon Dioxide Manufacture (0.3 MMTCE)
Carbon dioxide is used directly in many segments
of the economy, including food processing, beverage
manufacturing, chemical processing, crude oil drilling,
and a host of industrial and other miscellaneous applica-
tions. For the most part, the CO2 used in these applica-
tions is eventually released to the atmosphere.
Land-Use Change and Forestry
When humans use and alter the biosphere through
changes in land-use and forest management practices,
ES-10
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
they alter the natural balance between carbon stored in
the atmosphere and in biomass and soils. These prac-
tices include forest clearing to create cropland or pas-
ture, timber re-growth on logged forest lands, wetland
draining, and reversion of pasture to grassland or forest.
Forests, which cover about 298 million hectares
(737 million acres) of U.S. land (Powell et al. 1993), can
be an important terrestrial sink for CO2. Because ap-
proximately half the dry weight of wood is carbon, tree
growth results in a net accumulation of carbon in rela-
tively long-lived biomass. Other types of vegetative
cover, as well as soils, can also act as sinks of carbon.
In the United States, improved forest management
practices and the regeneration of previously cleared for-
est areas have resulted in a net uptake (sequestration) of
carbon in U.S. forest lands. This uptake is an ongoing
result of land-use changes in previous decades. For ex-
ample, because of improved agricultural productivity and
the widespread use of tractors, the rate of clearing forest
land for crop cultivation and pasture slowed greatly 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 brought out of crop production, primarily between
1920 and 1950, and were allowed to revert to forest land
or were actively reforested.
Since the early 1950s, the managed growth of pri-
vate forest land in the East has nearly doubled the biom-
ass density there. The 1970s and 1980s saw a resurgence
of federally sponsored tree-planting programs (e.g., the
Forestry Incentive Program) and soil conservation pro-
grams (e.g., the Conservation Reserve Program), which
have focused on reforesting previously harvested lands,
improving timber-management, combating soil erosion,
and converting marginal cropland to forests.
As a result of these activities, the CO2 flux in 1996
was estimated to have been an net uptake of 208.6 MMTCE.
This net sequestration of carbon includes forest trees, un-
derstory, litter, soils, and carbon stored in the U.S. wood
product pools and landfills. This carbon uptake represents
an offset of about 14 percent of the CO2 emissions from
fossil fuel combustion in 1996. The amount of carbon se-
questered through changes in U.S. forestry and land-use
practices declined by 33 percent between 1990 and 1996
due to the maturation of existing U. S. forests and the slowed
expansion of Eastern forest cover.
Methane Emissions
Atmospheric methane (CH4) is an integral compo-
nent of the greenhouse effect, second only to CO2 as a
contributor to anthropogenic greenhouse gas emissions.
Methane's overall contribution to global warming is sig-
nificant because it is estimated to be 21 times more ef-
fective at trapping heat in the atmosphere than CO2. Over
the last two centuries, methane's concentration in the at-
mosphere has more than doubled (IPCC 1996). Scien-
tists believe these atmospheric increases were due largely
to increasing emissions from anthropogenic sources, such
as landfills, natural gas and petroleum systems, agricul-
tural activities, coal mining, fossil fuel combustion, waste-
water treatment, and certain industrial processes (see
Table ES-7).
Landfills
Landfills are the largest single anthropogenic
source of methane emissions in the United States. In an
environment where the oxygen content is low or nonex-
Figure ES-6
1996 Sources of CH.
Nituul Gai Syttami
Goal Mit"*in
Pelnitauni Syitvrni •'
Mubrt» Suun:u*
Wffviuwalvr TrHril-'im I
Pnerachemical Pradticbon
Ayrlci^lnr.1
Silken en-Mi
20
60
MMTCE
Executive Summary ES-11
-------
Table ES-7: U.S. Sources of Methane Emissions (MMTCE)
Source
1990
1991
1992
1993
1994
1995
1996
Stationary Sources
Mobile Sources
Coal Mining
Natural Gas Systems
Petroleum Systems
Petrochemical Production
Silicon Carbide Production
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Residue Burning
Landfills
Wastewater Treatment
2.3
1.5
24.0
32.9
1.6
0.3
+
32.7
14.9
2.5
0.2
56.2
0.9
Total 169.9
2
1
22
33,
1
0,
32
15,
2
0,
57,
0,
171,
.3
.4
.8
.3
.6
.3
i-
.8
.4
.5
.2
.6
.9
.1
2
1
22
33
1
0
33
16
2
0
57
0
172
.4
.4
.0
.9
.6
.3
f
.2
.0
.8
.2
.8
.9
.5
2
1
19,
34,
1
0,
33,
16,
2
0,
59,
0,
171,
.3
.4
.2
.1
.6
.4
i-
.6
.1
.5
.2
.7
.9
.9
2.3
1.4
19.4
33.9
1.6
0.4
+
34.5
16.7
3.0
0.2
61.6
0.9
175.9
2
1
20
33
1
0,
34
16
2
0,
63
0,
179,
.4
.4
.3
.8
.6
.4
i-
.9
.9
.8
.2
.6
.9
.2
2.5
1.4
18.9
34.1
1.5
0.4
+
34.5
16.6
2.5
0.2
65.1
0.9
178.6
+ Does not exceed 0.05 MMTCE
Note: Totals may not sum due to independent rounding.
istent, organic materials, such as yard waste, household
waste, food waste, and paper, are decomposed by bacte-
ria resulting in the generation of methane and biogenic
CO2. Methane emissions from landfills are affected by
site-specific factors such as waste composition, moisture,
and landfill size.
Methane emissions fromU.S. landfills in 1996 were
65.1 MMTCE, a 16 percent increase since 1990 due to
the steady accumulation of wastes in landfills. Emis-
sions from U.S. municipal solid waste landfills, which
received about 62 percent of the solid waste generated in
the United States, accounted for 93 percent of total land-
fill emissions, while industrial landfills accounted for the
remainder. Approximately 14 percent of the methane
generated in U.S. landfills in 1996 was recovered and
combusted, often for energy. EPA is currently reviewing
site specific information on landfill gas recovery and
anticipates that this new information will lead to an esti-
mate of greater higher national recovery total, and thus
lower net methane emissions. This new information will
be available in future inventories.
A regulation promulgated in March 1996 requires
the largest U.S. landfills to begin collecting and com-
busting their landfill gas to reduce emissions of
nonmethane volatile organic compounds (NMVOCs). It
is estimated that by the year 2000, this regulation will
have reduced landfill methane emissions by more than
50 percent.
Natural Gas and Petroleum Systems
Methane is the major component of natural gas.
During the production, processing, transmission, and dis-
tribution of natural gas, fugitive emissions of methane
often occur. Because natural gas is often found in con-
junction with petroleum deposits, leakage from petro-
leum systems is also a source of emissions. Emissions
vary greatly from facility to facility and are largely a func-
tion of operation and maintenance procedures and equip-
ment condition. In 1996, emissions from U.S. natural
gas systems were estimated to be 34.1 MMTCE, account-
ing for approximately 19 percent of U.S. methane emis-
sions.
Methane emissions from the components of petro-
leum systems-including crude oil production, crude oil
refining, transportation, and distribution-generally oc-
cur as a result of system leaks, disruptions, and routine
maintenance. In 1996, emissions from petroleum sys-
tems were estimated to be 1.5 MMTCE, or 1 percent of
U.S. methane emissions. EPA is reviewing new infor-
mation on methane emissions from petroleum systems
and anticipates that future emission estimates will be
higher for this source.
From 1990 to 1996, combined emissions from natu-
ral gas and petroleum systems increased by just over 3
percent as the number of gas producing wells and miles
of distribution pipeline rose.
ES-12
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Agriculture Sector
The Agricultural sector accounted for 30 percent
of U.S. methane emissions in 1996, with enteric fermen-
tation in domestic livestock and manure management
accounting for the majority. Other agricultural activities
contributing directly to methane emissions included rice
cultivation and agricultural waste burning. Between 1990
and 1996, methane emissions from domestic livestock
enteric fermentation and manure management increased
by about 6 percent and 11 percent, respectively. During
this same time period, methane emissions from rice cul-
tivation decreased slightly.
Enteric Fermentation in Domestic Livestock
(34.5 MMTCE)
During animal digestion, methane is produced
through the process of enteric fermentation, in which
microbes residing in animal digestive systems break down
the feed consumed by the animal. Ruminants, which
include cattle, buffalo, sheep, and goats, have the high-
est methane emissions among all animal types because
they have a rumen, or large fore-stomach, in which meth-
ane producing fermentation occurs. Non-ruminant do-
mestic animals, such as pigs and horses, have much lower
methane emissions. In 1996, enteric fermentation was
the source of about 19 percent of U.S. methane emis-
sions, and about 64 percent of methane emissions from
the Agricultural sector. From 1990 to 1996, emissions
from this source increased by almost 6 percent due mainly
to increased livestock populations.
Manure Management (16.6 MMTCE)
The decomposition of organic animal waste in an
anaerobic environment produces methane. The most
important factor affecting the amount of methane pro-
duced is how the manure is managed, because certain
types of storage and treatment systems promote an oxy-
gen-free environment. In particular, liquid systems tend
to encourage anaerobic conditions and produce signifi-
cant quantities of methane, whereas solid waste manage-
ment approaches produce little or no methane. Higher
temperatures and moist climatic conditions also promote
methane production.
Emissions from manure management were about 9
percent of U.S. methane emissions in 1996, and about 31
percent of methane emissions from the Agriculture sector.
From 1990 to 1996, emissions from this source increased
by 11 percent because of larger farm animal populations
and expanded use of liquid manure management systems.
Rice Cultivation (2.5 MMTCE)
Most of the world's rice, and all of the rice in the
United States, is grown on flooded fields. When fields
are flooded, anaerobic conditions develop and the organic
matter in the soil decomposes, releasing methane to the
atmosphere, primarily through the rice plants.
In 1996, rice cultivation was the source of just over
1 percent of total U.S. methane emissions, and about 5
percent of U.S. methane emissions from the Agricultural
sector. Emissions estimates from this source did not
change significantly from 1990 levels.
Agricultural Residue Burning (0.2 MMTCE)
Burning crop residue releases a number of green-
house gases, including methane. Agricultural residue
burning is considered to be a net source of methane emis-
sions because, unlike CO2, methane is released during
burning is not reabsorbed by crop regrowth during the
next growing season. Because field burning is not com-
mon in the United States, it was responsible for only 0.1
percent of U.S. methane emissions in 1996.
Coal Mining
Produced millions of years ago during the forma-
tion of coal, methane trapped within coal seams and sur-
rounding rock strata is released when the coal is mined.
The quantity of methane released to the atmosphere dur-
ing coal mining operations depends primarily upon the
depth and type of the coal that is mined.
Methane from surface mines is emitted directly to
the atmosphere as the rock strata overlying the coal seam
is removed. Because methane in underground mines is
explosive at concentrations of 5 to 15 percent in air, most
active underground mines are required to vent this meth-
ane, typically to the atmosphere. At some mines, meth-
ane-recovery systems may supplement these ventilation
Executive Summary ES-13
-------
systems. U.S. recovery of methane has been increasing
in recent years. During 1996, coal mining activities emit-
ted 18.9 MMTCE of methane, or 11 percent of U.S. meth-
ane emissions. From 1990 to 1996, emissions from this
source decreased by 21 percent due to increased use of
the methane collected by mine degasification systems.
Other Sources
Methane is also produced from several other
sources in the United States, including fossil fuel com-
bustion, wastewater treatment, and some industrial pro-
cesses. Fossil fuel combustion by stationary and mobile
sources was responsible for methane emissions of 2.5
and 1.4 MMTCE, respectively in 1996. Wastewater treat-
ment was a smaller source of methane, emitting 0.9
MMTCE in 1996. Methane emissions from two indus-
trial sources-petrochemical and silicon carbide produc-
tion-were also estimated, totaling 0.4 MMTCE.
Nitrous Oxide Emissions
Nitrous oxide (N2O) is a greenhouse gas that is pro-
duced naturally from a wide variety of biological sources
in soil and water. While N2O emissions are much lower
than CO2 emissions, N2O is approximately 310 times
more powerful than CO2 at trapping heat in the atmo-
sphere (IPCC 1996). During the past two centuries, at-
mospheric concentrations of N2O has risen by approxi-
mately 13 percent. The main anthropogenic activities
producing N2O in the United States were fossil fuel com-
bustion in motor vehicles, agricultural soil management,
and adipic and nitric acid production (see Table ES-8).
Fossil Fuel Combustion
Nitrous oxide is a product of the reaction that oc-
curs between nitrogen and oxygen during fossil fuel com-
bustion. Both mobile and stationary sources emit N2O,
and the volume emitted varies according to the type of
fuel, technology, and pollution control device used, as
well as maintenance and operating practices. For ex-
ample, catalytic converters installed to reduce mobile
source pollution can result in the formation of N2O.
In 1996, N2O emissions from mobile sources totaled
16.5 MMTCE, or 16 percent of U.S. N2O emissions. Emis-
sions of N2O from stationary sources were 4.0 MMTCE,
or 9 percent of U.S. N2O emissions. From 1990 to 1996,
combined N2O emissions from stationary and mobile
sources increased by 21 percent, primarily due to increased
rates of N2O generation in motor vehicles.
Agricultural Soil Management
Nitrous oxide (N2O) is produced naturally in soils
through microbial processes. A number of anthropogenic
activities add to the amount of nitrogen available to be
emitted as N2O by these microbial processes. Direct ad-
ditions of nitrogen occur through the application of syn-
thetic and organic fertilizers, cultivation of nitrogen-fix-
ing crops, cultivation of high organic content soils, and
the application of livestock manure on croplands and
pasture. Indirect emissions result from volatilization and
subsequent atmospheric deposition of ammonia (NH3)
and oxides of nitrogen (NOx) and from leaching and
surface run-off. These indirect emissions originate from
nitrogen applied to soils as fertilizer and from managed
and unmanaged livestock wastes.
Table ES-8: U.S. Sources of Nitrous Oxide Emissions (MMTCE)
Source
1990
1991
1992
1993
1994
1995
1996
Stationary Sources
Mobile Sources
Adipic Acid
Nitric Acid
Manure Management
Agricultural Soil Management
Agricultural Residue Burning
Human Sewage
Waste Combustion
Total
3.7
13.2
4.7
3.4
2.6
62.4
0.1
2.1
0.1
92.3
3.7
13.9
4.9
3.3
2.8
63.4
0.1
2.1
0.1
94.4
3.7
14.8
4.6
3.4
2.8
65.2
0.1
2.2
0.1
96.8
3.8
15.6
4.9
3.5
2.9
64.1
0.1
2.2
0.1
97.1
3.8
16.3
5.2
3.7
2.9
70.4
0.1
2.3
0.1
104.9
3.8
16.6
5.2
3.7
2.9
67.2
0.1
2.2
0.1
101.9
4.0
16.5
5.4
3.8
3.0
68.6
0.1
2.3
0.1
103.7
Note: Totals may not sum due to independent rounding.
ES-14
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Figure ES-7
1996 Sources of INLO
AgrlCHMiirni Bt:.: Hj-iH
Muhily
AdIpiC ALid
Sullofiary Eaurct* '
S inc Acid
|
J
Pj*udi» 6.irmng
Cnmtniyhiiii
r
2D «
fctfTCE
In 1996, agricultural soil management accounted
for 68.6 MMTCE, or approximately 66 percent of U.S.
N2O emissions. From 1990 to 1996, emissions from this
source increased by 10 percent as fertilizer consumption
and cultivation of nitrogen fixing crops rose.
Adipic Acid Production
The majority of the adipic acid produced in the
United States is used to manufacture nylon. Adipic acid
is also used to produce some low-temperature lubricants,
and to add a "tangy" flavor to foods.
In 1996, U.S. adipic acid production emitted 5.4
MMTCE of nitrous oxide, or 5 percent of U.S. N2O emis-
sions. By the end of 1997, all adipic acid production
plants in the United States are expected to have N2O con-
trols in place that will almost eliminate emissions. (Half
of the plants had these controls in place and operating in
1996.) From 1990 to 1996, emissions from this source
increased by 14 percent, as adipic acid production grew.
Nitric Acid Production
Nitric acid production is another industrial source
of N2O emissions. Used primarily to make synthetic com-
mercial fertilizer, this raw material is also a major com-
ponent 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 whichN2O is formed and emitted to the atmosphere.
In 1996, N2O emissions from nitric acid production were
3.8 MMTCE, or for 4 percent of U. S. N2O emissions. From
1990 to 1996, emissions from this source increased by 14
percent as nitric acid production grew.
Manure Management
Nitrous oxide is produced as part of microbial deni-
trification processes in managed and unmanaged manure,
the latter of which is addressed under agricultural soil
management. Total N2O emissions from managed ma-
nure systems in 1996 were 3.0 MMTCE, accounting for
3 percent of U.S. N2O emissions. Emission increased by
12 percent from 1990 to 1996, most of which can be
attributed to increased quantities of managed manure
from beef cattle in feedlots.
Other Sources
Other sources of N2O included agricultural reside
burning, waste combustion, and human sewage in waste-
water treatment systems. In 1996, agricultural residue
burning and municipal solid waste combustion each emit-
ted approximately 0.1 MMTCE of N2O. Although N2O
emissions from wastewater treatment were not fully es-
timated because insufficient data was available, the hu-
man sewage component of domestic wastewater resulted
in emission of 2.3 MMTCE in 1996.
MFCs, PFCs and SFC Emissions
b
Hydrofluorocarbons (HFCs) and perfluorocarbons
(PFCs) are man-made chemicals that have been intro-
duced as alternatives to the ozone depleting substances,
which are being phased out under the Montreal Protocol
and Clean Air Act Amendments of 1990. Because HFCs
and PFCs do not directly deplete to the stratospheric
ozone layer, they are not controlled by the Montreal Pro-
tocol.
However, many of these compounds, along with
sulfur hexafluoride (SF6), are potent greenhouse gases.
In addition to having high global warming potentials,
Executive Summary ES-15
-------
Figure ES-8
S jb&ll'L.tlOP .T Dl.lftL
dMCfiftfir Tf«l»i8»ie«i 1
Distribution I
Production I
i
1!
SF6 and most PFCs have extremely long atmospheric life-
times, resulting in their essentially irreversible accumu-
lation in the atmosphere. Sulfur hexafluoride, itself, is
the most potent greenhouse gas the IPCC has evaluated.
In addition to their use as substitutes for ozone de-
pleting substances, the other industrial sources of these
gases are aluminum production, HCFC-22 production,
semiconductor manufacturing, electrical transmission and
distribution, and magnesium production and processing.
Table ES-9 presents emission estimates for HFCs, PFCs,
and SF6, which totaled 34.7 MMTCE in 1996.
Substitution of Ozone Depleting
Substances
The use and subsequent emissions of HFCs and PFCs
as ODS substitutes increased dramatically from small
amounts in 1990 to 11.9 MMTCE in 1996. This increase
was the result of efforts to phase-out CFCs and other ODSs
in the United States, especially the introduction of HFC-
13 4a as a CFC substitute in refrigeration applications. This
trend is expected to continue for many years, and will ac-
celerate in the early part of the next century as HCFCs, which
are interim substitutes in many applications, are themselves
phased-out under the provisions of the CopenhagenAmend-
ments to the Montreal Protocol.
Other Industrial Sources
HFCs, PFCs, and SF6 are also emitted from a num-
ber of other industrial processes. During the production
of primary aluminum, two PFCs (CF4 and C2F6) are emit-
ted as intermittent by-products of the smelting process.
Emissions from aluminum production were estimated to
have decreased by 41 percent between 1990 and 1996
due to voluntary emission reductions efforts by the in-
dustry and falling domestic aluminum production.
HFC-23 is a by-product emitted during the pro-
duction of HCFC-22. Emissions from this source were
8.5 MMTCE in 1996, and have decreased by 11 percent
since 1990.
The semiconductor industry uses combinations of
HFCs, PFCs, and SF6 for plasma etching and chemical
vapor deposition processes. For 1996, it was estimated
that the U.S. semiconductor industry emitted a total of
1.4 MMTCE. These gases were not widely used in the
industry in 1990.
The primary use of SF6 is as a dielectric in electri-
cal transmission and distribution systems. Fugitive emis-
sions of SF6 occur from leaks in and servicing of substa-
tions and circuit breakers, especially from older equip-
ment. Estimated emissions from this source increased
by 25 percent from 1990, to 7.0 MMTCE in 1996.
SF6 is also used as a protective covergas for the cast-
ing of molten magnesium. Estimated emissions from pri-
mary magnesium production and magnesium casting were
3.0 MMTCE in 1996, and increased of percent since 1990.
Criteria Pollutant Emissions
In the United States, carbon monoxide (CO), ni-
trogen oxides (NOx), nonmethane volatile organic com-
pounds (NMVOCs), and sulfur dioxide (SO2) are com-
monly referred to as "criteria pollutants," as termed in
the Clean Air Act. Carbon monoxide is produced when
carbon containing fuels are combusted incompletely.
Nitrogen oxides (i.e., NO and NO2) are created by light-
ning, fires, fossil fuel combustion, and in the stratosphere
from nitrous oxide. NMVOCs-which include such com-
pounds as propane, butane, and ethane-are emitted pri-
marily from transportation, industrial processes, and non-
industrial consumption of organic solvents. In the United
States, SO2 is primarily emitted from the combustion of
fossil fuels and by the metals industry.
In part because of their contribution to the forma-
tion of urban smog (and acid rain in the case of SO2),
criteria pollutants are regulated under the Clean Air Act.
ES-16
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table ES-9: Emissions of MFCs, PFCs, and SF (MMTCE)
Source
1990
1991
1992
1993
1994
Note: Totals may not sum due to independent rounding.
1995
1996
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production
Semiconductor Manufacture
Electrical Transmission and Distribution
Magnesium Production and Processing
Total
0.3
4.9
9.5
0.2
5.6
1.7
22.2
0.3
4.7
8.4
0.4
5.9
2.0
21.6
0.4
4.1
9.5
0.6
6.2
2.2
23.0
1.4
3.5
8.7
0.8
6.4
2.5
23.4
4.0
2.8
8.6
1.0
6.7
2.7
25.9
9.5
2.7
7.4
1.2
7.0
3.0
30.8
11.9
2.9
8.5
1.4
7.0
3.0
34.7
These gases also indirectly affect the global climate by
reacting with other chemical compounds in the atmo-
sphere to form compounds that are greenhouse gases.
Unlike other criteria pollutants, SO2 emitted into the at-
mosphere is believed to affect the Earth's radiative bud-
get negatively; therefore, it is discussed separately.
The most important of the indirect climate change
effects of criteria pollutants is their role as precursors of
tropospheric ozone. In this role, they contribute to ozone
formation and alter the atmospheric lifetimes of other
greenhouse gases. For example, CO interacts with the
hydroxyl radical-the major atmospheric sink for meth-
ane emissions-to form CO Therefore, increased atmo-
spheric concentrations of CO limit the number of hy-
droxyl molecules (OH) available to destroy methane.
Since 1970, the United States has published esti-
mates of annual emissions of criteria pollutants (EPA
1997). Table ES-11 shows that fuel combustion accounts
for the majority of emissions of these gases. Fossil fuel
combustion by mobile sources emitted approximately 83
percent of U.S. CO emissions in 1996. Mobile sources
also emitted roughly half of U.S. NOx and NMVOC emis-
sions. Industrial processes-such as the manufacture of
chemical and allied products, metals processing, and in-
dustrial uses of solvents-were also significant sources
of CO, NO , and NMVOCs.
Executive Summary ES-17
-------
Emissions of Ozone Depleting Substances
Chlorofluorocarbons (CFCs) and other halogenated compounds were first emitted into the atmosphere this century. This family of
man-made compounds includes CFCs, halons, methyl chloroform, carbon tetrachloride, methyl bromide, and
hydrochlorofluorocarbons (HCFCs). These substances have been used in a variety of industrial applications, including refrigera-
tion, air conditioning, foam blowing, solvent cleaning, sterilization, fire extinguishing, coatings, paints, and aerosols.
Because these compounds have been shown to deplete stratospheric ozone, they are typically referred to as ozone depleting
substances (ODSs). In addition, they are potent greenhouse gases.
Recognizing the harmful effects of these compounds on the ozone layer, in 1987 many governments signed the Montreal Protocol
on Substances that Deplete the Ozone Layer to limit the production and importation of a number of CFCs and other halogenated
compounds. The United States furthered its commitment to phase-out ODSs by signing and ratifying the Copenhagen Amend-
ments to the Montreal Protocol in 1992. Under these amendments, the United States committed to ending the production and
importation of halons by 1994, and CFCs by 1996.
The IPCC Guidelines do not include reporting instructions for estimating emissions of ODSs because their use is being phased-out
under the Montreal Protocol. The United States believes, however, that a greenhouse gas emissions inventory is incomplete
without these emissions; therefore, estimates for several Class I and Class II ODSs are provided in Table ES-10. Compounds are
classified by class according to their ozone depleting potential. Class I compounds are the primary ODSs; Class II compounds
include partially halogenated chlorine compounds (HCFCs), some of which were developed as interim replacements for CFCs.
Because these HCFC compounds are only partially halogenated, their hydrogen-carbon bonds are more vulnerable to oxidation in
the troposphere and, therefore, pose only one-tenth to one-hundredth the threat to stratospheric ozone compared to CFCs.
It should be noted that the effects of these compounds on radiative forcing are not provided. Although many ODSs have relatively
high direct GWPs, their indirect effects from ozone-also a greenhouse gas-destruction are believed to have negative radiative
forcing effects, and therefore could significantly reduce the overall magnitude of their radiative forcing effects. Given the uncertain-
ties surrounding the net effect of these gases, emissions are reported on an unweighted basis.
Table ES-10: Emissions of Ozone Depleting Substances (Mg)
Compound
1990
1991
1992
1993
1994
1995
1996
Class I
CFC-11
CFC-12
CFC-113
CFC-114
CFC-115
Carbon Tetrachloride
Methyl Chloroform
Halon-1211
Halon-1301
Class II
HCFC-22
HCFC-123
HCFC-124
HCFC-141b
HCFC-142b
HCFC-225ca/cb
53,500
112,600
26,350
4,700
4,200
32,300
158,300
1,000
1,800
79,789
+
+
+
+
+
48,300
103,500
20,550
3,600
4,000
31,000
154,700
1,100
1,800
79,540
+
+
+
+
+
45,100
80,500
17,100
3,000
3,800
21,700
108,300
1,000
1,700
79,545
285
429
+
3,526
+
45,400
79,300
17,100
3,000
3,600
18,600
92,850
1,100
1,700
71,224
570
2,575
1,909
9,055
+
36,600
57,600
8,550
1,600
3,300
15,500
77,350
1,000
1,400
71,386
844
4,768
6,529
14,879
+
36,200
51,800
8,550
1,600
3,000
4,700
46,400
1,100
1,400
74,229
1,094
5,195
11,608
21,058
565
26,600
35,500
+
300
3,200
+
+
1,100
1,400
77,472
1,335
5,558
14,270
27,543
579
Source: EPA Office of Air and Radiation estimates
+ Does not exceed 10 Mg
ES-18
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table ES-11: Emissions of N0x, CO, NMVOCs, and S02 (Gg)
Gas/Activity 1990 1991 1992 1993 1994 1995 1996
N°x
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Industrial Processes
Solvent Use
Agricultural Burning
Waste
CO
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Industrial Processes
Solvent Use
Agricultural Burning
Waste
NMVOCs
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Industrial Processes
Solvent Use
Agricultural Burning
Waste
S02
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Industrial Processes
Solvent Use
Agricultural Burning
Waste
21,612
9,881
10,554
139
923
1
30
83
83,732
4,998
67,101
302
9,580
4
768
979
18,768
912
7,997
555
3,193
5,217
NA
895
21,379
18,407
1,237
390
1,306
+
NA
38
21,594
9,777
10,788
110
802
2
30
86
85,390
5,312
70,865
313
7,166
4
718
1,012
18,872
975
8,167
581
2,997
5,245
NA
907
20,752
17,959
1,222
343
1,187
+
NA
40
21,929
9,912
10,975
134
784
2
34
87
82,427
5,582
69,158
337
5,480
5
833
1,032
18,501
1,010
7,822
574
2,825
5,353
NA
916
20,554
17,684
1,267
377
1,186
+
NA
40
22,235
10,077
11,145
111
760
2
27
112
82,381
5,067
69,668
337
5,500
4
674
1,133
18,681
901
7,878
588
2,907
5,458
NA
949
20,196
17,459
1,166
347
1,159
1
NA
65
22,616
9,990
11,445
106
933
2
37
103
86,475
5,006
71,402
307
7,787
5
858
1,111
19,264
897
8,184
587
3,057
5,590
NA
949
19,633
17,134
965
344
1,135
1
NA
54
21,742
9,820
10,884
100
815
3
30
89
77,216
5,382
64,363
316
5,370
5
704
1,075
18,385
973
7,380
582
2,873
5,609
NA
968
17,165
14,724
947
334
1,116
1
NA
43
21,254
9,518
10,688
100
821
3
34
91
76,435
5,407
63,455
316
5,379
5
783
1,091
17,020
975
7,192
469
2,299
5,691
NA
393
17,673
15,228
946
334
1,122
1
NA
43
Source: (EPA 1997)
+ Does not exceed 0.5 Gg
NA (Not Available)
Note: Totals may not sum due to independent rounding.
Sources and Effects of Sulfur Dioxide
Sulfur dioxide (S02) emitted into the atmosphere through natural and anthropogenic processes affects the Earth's radiative budget
through its photochemical transformation into sulfate aerosols that can (1) scatter sunlight back to space, thereby reducing the
radiation reaching the Earth's surface; (2) affect cloud formation; and (3) affect atmospheric chemical composition (e.g., strato-
spheric ozone, by providing surfaces for heterogeneous chemical reactions). The overall effect of S02 derived aerosols on radiative
forcing is believed to be negative (IPCC 1996). However, because S02 is short-lived and unevenly distributed in the atmosphere,
its radiative forcing impacts are highly uncertain.
Sulfur dioxide is also a major contributor to the formation of urban smog, which can cause significant increases in acute and
chronic respiratory diseases. Once S02 is emitted, it is chemically transformed in the atmosphere and returns to the Earth as the
primary source of acid rain. Because of these harmful effects, the United States has regulated S02 emissions in the Clean Air Act.
Electric utilities are the largest source of S02 emissions in the United States, accounting for 66 percent in 1996. Coal combustion
contributes nearly all of those emissions (approximately 96 percent). S02 emissions have significantly decreased in recent years,
primarily as a result of electric utilities switching from high sulfur to low sulfur coal.
Executive Summary ES-19
-------
1. Introduction
his report presents estimates by the United States government of U.S. anthropogenic greenhouse gas emis
sions and sinks for the years 1990 through 1996.' A summary of these estimates is provided in Table 1-2
and Table 1-3 by gas and source category. The emission estimates in these tables are presented on both a full molecu-
lar 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.2-3 This report also discusses the methods and data used to calculate these
emission estimates.
In June of 1992, the United States signed the United Nations Framework Convention on Climate Change (FCCC).
The objective of the FCCC is "to achieve... stabilization of greenhouse gas concentrations in the atmosphere at a level
that would prevent dangerous anthropogenic interference with the climate system."4'5
Parties to the Convention, by signing, make commitments "to develop, periodically update, publish and make
available... national inventories of anthropogenic emissions by sources and removals by sinks of all greenhouse gases
not controlled by the Montreal Protocol, using comparable methodologies... "6 The United States views this report as
an opportunity to fulfill this commitment under FCCC.
In 1988, preceding the creation of the FCCC, the Intergovernmental Panel on Climate Change (IPCC) was
jointly established by the World Meteorological Organization (WMO) and the United Nations Environment Programme
(UNEP). The charter of the IPCC is to assess available scientific information on climate change, assess the environ-
mental and socio-economic impacts of climate change, and formulate response strategies (IPCC 1996). Underwork-
ing Group 1 of the IPCC, nearly 140 scientists and national experts from more than thirty countries corroborated 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 FCCC are consistent and comparable across
sectors and between nations. The Revised 1996 IPCC Guidelines were accepted by the IPCC at its Twelfth Session
(Mexico City, 11-13 September 1996). The information provided in this inventory is presented in accordance with
these guidelines, unless otherwise noted. Additionally, in order to fully comply with the Revised 1996 IPCC Guide-
lines, the United States has provided a copy of the IPCC reporting tables in Annex N and in Annex O estimates of
carbon dioxide emissions from fossil fuel combustion using the IPCC Reference Approach.
Preliminary U.S. greenhouse gas emission estimates for the year 1997 are also provided in Annex P.
See the section below entitled Global Warming Potential Concept for an explanation of GWP values.
See the section below entitled What is Climate Change? for an explanation of radiative forcing.
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).
Article 2 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change.
Article 4 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change (also
identified in Article 12).
Introduction 1-1
-------
Overall, the purpose of an inventory of anthropo-
genic greenhouse gas emissions is (1) to provide a basis
for the ongoing development of methodologies for esti-
mating sources and sinks of greenhouse gases; (2) to pro-
vide a common and consistent mechanism through which
Parties to the FCCC can estimate emissions and com-
pare the relative contribution of individual sources, gases,
and nations to climate change; and (3) as a prerequisite
for evaluating the cost-effectiveness and feasibility of pur-
suing possible mitigation strategies.
What is Climate Change?
The Earth naturally absorbs and reflects incoming
solar radiation and emits longer wavelength terrestrial
(thermal) radiation back into space. On average, the ab-
sorbed solar radiation is balanced by the outgoing ter-
restrial radiation emitted to space. A portion of this ter-
restrial radiation, though, is itself absorbed by gases in
the atmosphere. The energy from this absorbed terres-
trial radiation warms the Earth's surface and atmosphere,
creating what is known as the "natural greenhouse ef-
fect." Without the natural heat-trapping properties of
these atmospheric gases, the average surface tempera-
ture of the Earth would be about 34°C lower (IPCC 1996).
Although the Earth's atmosphere consists mainly
of oxygen and nitrogen, neither play a significant role in
this greenhouse effect because both are essentially trans-
parent to terrestrial radiation. The greenhouse effect is
primarily a function of the concentration of water vapor,
carbon dioxide, and other trace gases in the atmosphere
that absorb the terrestrial radiation leaving the surface of
the Earth (IPCC 1996). Changes in the atmospheric con-
centrations of these greenhouse gases can alter the bal-
ance of energy transfers between the atmosphere, space,
land, and the oceans. A gauge of these changes is called
radiative forcing, which is a simple measure of changes
in the energy available to the Earth-atmosphere system
(IPCC 1996). Holding everything else constant, increases
in greenhouse gas concentrations in the atmosphere will
produce positive radiative forcing (i.e., a net increase in
the absorption of energy by the Earth).
Under the United Nations FCCC, the definition of
climate change is "a change of climate which is attrib-
uted directly or indirectly to human activity that alters
the composition of the global atmosphere and which is
in addition to natural climate variability observed over
comparable time periods."7 Given that definition, in its
1995 assessment of the science of climate change, the
IPCC concluded that:
Human activities are changing the atmospheric
concentrations and distributions of greenhouse gases and
aerosols. These changes can produce a radiative forc-
ing by changing either the reflection or absorption of
solar radiation, or the emission and absorption of ter-
restrial radiation (IPCC 1996).
The IPCC went on to report in its assessment that
the "[g]lobal mean surface temperature [of the Earth] has
increased by between about 0.3 and 0.6 °C since the late
19th century..." (IPCC 1996) and finally concluded with
the following statement:
Our ability to quantify the human influence on glo-
bal climate is currently limited because the expected sig-
nal is still emerging from the noise of natural variability,
and because there are uncertainties in key factors. These
include the magnitude and patterns of long term natural
variability and the time-evolving pattern of forcing by,
and response to, changes in concentrations of greenhouse
gases and aerosols, and land surface changes. Never-
theless, the balance of the evidence suggests that there is
a discernable human influence on global climate (IPCC
1996).
Greenhouse Gases
Climate change can be driven by changes in the
atmospheric concentrations of a number of radiatively
active gases and aerosols. We have clear evidence that
human activities have affected concentrations, distribu-
tions and life cycles of these gases (IPCC 1996).
Naturally occurring greenhouse gases include wa-
ter vapor, carbon dioxide (CO2), methane (CH4), nitrous
oxide (N2O), and ozone (O3). Several classes of haloge-
Article 1 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change.
1-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
nated substances that contain fluorine, chlorine, or bro-
mine are also greenhouse gases, but they are, for the most
part, emitted solely by human activities. Chlorofluoro-
carbons (CFCs) and hydrochlorofluorocarbons (HCFCs)
are halocarbons that contain chlorine, while halocarbons
that contain bromine are referred to as halons. Other
fluorine containing halogenated substances include
hydrofluorocarbons (HFCs), perfluorocarbons (PFCs),
and sulfur hexafluoride (SF6). There are also several gases
that, although they do not have a direct radiative forcing
effect, do influence the formation and destruction of
ozone, which does have such a terrestrial radiation ab-
sorbing effect. These gases—referred to here as ozone
precursors—include carbon monoxide (CO), oxides of
nitrogen (NOx), and nonmethane volatile organic com-
pounds (NMVOCs).8 Aerosols—extremely small par-
ticles or liquid droplets often produced by emissions of
sulfur dioxide (SO2)—can also affect the absorptive char-
acteristics of the atmosphere.
Carbon dioxide, methane, and nitrous oxide are
continuously emitted to and removed from the atmo-
sphere by natural processes on Earth. Anthropogenic
activities, however, can cause additional quantities of
these and other greenhouse gases to be emitted or se-
questered, thereby changing their global average atmo-
spheric concentrations. Natural activities such as respi-
ration 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 anthropo-
genic activities—generally do not alter average atmo-
spheric greenhouse gas concentrations over decadal
timeframes. Climatic changes resulting from anthropo-
genic activities, however, could have positive or nega-
tive feedback effects on these natural systems.
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 Glo-
bal Warming Potentials (GWPs), which are assigned to
individual gases as a measure of their relative average
global radiative forcing effect.
Water Vapor (Hfl). Overall, the most abundant
and dominant greenhouse gas in the atmosphere is water
vapor. Water vapor is neither long-lived nor well-mixed
in the atmosphere, varying spatially from 0 to 2 percent
(IPCC 1996). In addition, atmospheric water can exist
in several physical states including gaseous, liquid, and
solid. Human activities are not believed to directly af-
fect the average global concentration of water vapor;
however, the radiative forcing produced by the increased
concentrations of other greenhouse gases may indirectly
affect the hydrologic cycle. A warmer atmosphere has
an increased water holding capacity; yet, increased con-
centrations of water vapor affects the formation of clouds,
which can both absorb and reflect solar and terrestrial
radiation.
Carbon Dioxide (CO.). In nature, carbon is cycled
between various atmospheric, oceanic, land biotic, ma-
rine biotic, and mineral reservoirs. The largest fluxes
occur between the atmosphere and terrestrial biota, and
between the atmosphere and surface water of the oceans.
In the atmosphere, carbon predominantly exists in its
oxidized form as CO2. Atmospheric carbon dioxide is
part of this global carbon cycle, and therefore its fate is a
complex function of geochemical and biological pro-
cesses. Carbon dioxide concentrations in the atmosphere,
as of 1994, increased from approximately 280 parts per
million by volume (ppmv) in pre-industrial9 times to 358
ppmv, a more than 25 percent increase (IPCC 1996).10
The IPCC has stated that "[t]here is no doubt that this
increase is largely due to human activities, in particular
fossil fuel combustion..." (IPCC 1996). Forest clearing,
other biomass burning, and some non-energy production
processes (e.g., cement production) also emit notable
quantities of carbon dioxide.
In its latest scientific 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
Also referred to in the U.S. Clean Air Act as "criteria pollutants."
The pre-industrial period is defined as the time preceding the year 1750 (IPCC 1996).
10
fluctuated by about ±10 ppmv around 280 ppmv (IPCC 1996).
Carbon dioxide concentrations during the last 1,000 years of the pre-industrial period (1650-1750), a time of relative climate stability,
Introduction
1-3
-------
surface because of its enhanced greenhouse effect—al-
though the magnitude and significance of the effects are
not fully resolved" (IPCC 1996).
Methane (CHJ. Methane is produced through
anaerobic decomposition of organic matter in biological
systems. Agricultural processes such as wetland rice
cultivation, enteric fermentation in animals, and the de-
composition of animal wastes emit CH4, as does the de-
composition 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. The
average global concentration of methane in the atmo-
sphere was 1,720 parts per billion by volume (ppbv) in
1994, a 145 percent increase from the pre-industrial con-
centration of 700 ppbv (IPCC 1996). It is estimated that
60 to 80 percent of current CH4 emissions are the result
of anthropogenic activities. Carbon isotope measure-
ments indicate that roughly 20 percent of methane emis-
sions are from fossil fuel consumption, and an equal per-
centage is produced by natural wetlands, which will likely
increase with rising temperatures and rising microbial
action (IPCC 1996).
Methane is removed from the atmosphere by re-
acting with the hydroxyl radical (OH) and is ultimately
converted to CO2. Increasing emissions of methane,
though, reduces the concentration of OH, and thereby
the rate of further methane removal (IPCC 1996).
Nitrous Oxide (Nf>). Anthropogenic sources of
N2O emissions include agricultural soils, especially the
use of synthetic and manure fertilizers; fossil fuel com-
bustion, especially from mobile sources; adipic (nylon)
and nitric acid production; wastewater treatment and
waste combustion; and biomass burning. The atmo-
spheric concentration of nitrous oxide (N2O) in 1994 was
about 312 parts per billion by volume (ppbv), while pre-
industrial concentrations were roughly 275 ppbv. The
majority of this 13 percent increase has occurred after
the pre-industrial period and is most likely due to an-
thropogenic activities (IPCC 1996). Nitrous oxide is re-
moved from the atmosphere primarily by the photolytic
action of sunlight in the stratosphere.
Ozone (OJ. Ozone is present in both the strato-
sphere,11 where it shields the Earth from harmful levels
of ultraviolet radiation, and at lower concentrations in
the troposphere12, where it is the main component of an-
thropogenic photochemical "smog". During the last two
decades, emissions of anthropogenic chlorine and bro-
mine-containing halocarbons, such as chlorofluorocar-
bons (CFCs), have depleted stratospheric ozone concen-
trations. This loss of ozone in the stratosphere has re-
sulted in negative radiative forcing, representing an in-
direct effect of anthropogenic emissions of chlorine and
bromine compounds (IPCC 1996).
Tropospheric ozone, which is also a greenhouse
gas, is produced from the oxidation of methane and from
reactions with precursor gases such as carbon monoxide
(CO), nitrogen oxides (NOx), and non-methane volatile
organic compounds (NMVOCs). This latter group of
ozone precursors are included in the category referred to
as "criteria pollutants" in the United States under the
Clean Air Act13 and its subsequent amendments. The
tropospheric concentrations of both ozone and these pre-
cursor gases are short-lived and, therefore, spatially vari-
able.
Halocarbons. Halocarbons are for the most part
man-made chemicals that have both direct and indirect
radiative forcing effects. Halocarbons that contain chlo-
rine—chlorofluorocarbons (CFCs), hydrochlorofluoro-
carbons (HCFCs), methyl chloroform, and carbon tetra-
chloride—and bromine—halons and methyl bromide—
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 be-
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.
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.
13 [42 U.S.C § 7408, CAA § 108]
1-4
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
cause they cause stratospheric ozone depletion, which is
itself an important greenhouse gas in addition to shield-
ing the Earth from harmful levels of ultraviolet radia-
tion. 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 514
countries beginning in 1996, and then followed by a com-
plete phase-out by the year 2030. The ozone depleting
gases covered under the Montreal Protocol and its
Amendments are not covered by the FCCC; however,
they are reported in this inventory under Annex K.
Perfluorocarbons (PFCs), hydrofluorocarbons
(HFCs), and sulfur hexafluoride (SF6) are not ozone de-
pleting substances, and therefore are not covered under
the Montreal Protocol. They are, however, powerful
greenhouse gases. HFCs—primarily used as replace-
ments for ozone depleting substances but also emitted as
a by-product of the HCFC-22 manufacturing process—
currently have a small aggregate radiative forcing im-
pact; however, it is anticipated that their contribution to
overall radiative forcing will increase (IPCC 1996). PFCs
and SF6 are predominantly emitted from various indus-
trial processes including aluminum smelting, semicon-
ductor manufacturing, electric power transmission and
distribution, and magnesium casting. Currently, the ra-
diative forcing impact of PFCs, and SF6 is also small;
however, because they have extremely long atmospheric
lifetimes, their concentrations tend to irreversibly accu-
mulate in the atmosphere.
Carbon Monoxide (CO). Carbon monoxide has
an indirect radiative forcing effect by elevating concen-
trations of CH4 and tropospheric ozone through chemi-
cal reactions with other atmospheric constituents (e.g.,
the hydroxyl radical) that would otherwise assist in de-
stroying CH4 and tropospheric ozone. Carbon monox-
ide is created when carbon-containing fuels are burned
incompletely. Through natural processes in the atmo-
sphere, it is eventually oxidized to CO2. Carbon mon-
oxide concentrations are both short-lived in the atmo-
sphere and spatially variable.
Nitrogen Oxides (NOJ. The primary climate
change effects of nitrogen oxides (i.e., NO and NO2) are
indirect and result from their role in promoting the for-
mation of tropospheric, and to a lesser degree, lower
stratospheric, ozone. (NOx emissions injected higher in
the stratosphere15 can lead to stratospheric ozone deple-
tion.). Nitrogen oxides are created from lightning, soil
microbial activity, biomass burning (both natural and
anthropogenic fires), fossil fuel combustion, and, in the
stratosphere, from nitrous oxide (N2O). Concentrations
of NOx are both relatively short-lived in the atmosphere
and spatially variable.
Nonmethane Volatile Organic Compounds
(NMVOCs). Nonmethane volatile organic compounds
include compounds such as propane, butane, and ethane.
These compounds participate, along with NOx, in the for-
mation of tropospheric ozone and other photochemical
oxidants. NMVOCs are emitted primarily from trans-
portation and industrial processes, as well as biomass
burning and non-industrial consumption of organic sol-
vents. 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 vol-
canic activity or by anthropogenic processes such as fuel
combustion. Their effect upon radiative forcing is to both
absorb radiation and to alter cloud formation, thereby
affecting the reflectivity (i.e., albedo) of the Earth. Aero-
sols are removed from the atmosphere primarily by pre-
cipitation, and generally have short atmospheric lifetimes.
Like ozone precursors, aerosol concentrations and com-
position vary by region (IPCC 1996).
Anthropogenic aerosols in the troposphere are pri-
marily the result of sulfur dioxide (SO2)16 emissions from
fossil fuel and biomass burning. Overall, aerosols tend
Article 5 of the Montreal Protocol covers several groups of countries, especially developing countries, with low consumption rates of
ozone depleting substances. Developing countries with per capita consumption of less than 0.3 kg receive financial assistance and a grace
period often additional years in the phase-out of ozone depleting substances.
Primarily from fuel combustion emissions from high altitude aircraft.
16
Sulfur dioxide is a primary anthropogenic contributor to the formation of "acid rain" and other forms of atmospheric acid deposition.
Introduction
1-5
-------
to produce a negative radiative forcing effect (i.e., net
cooling effect on the climate), although because they are
short-lived in the atmosphere—lasting days to weeks—
their concentrations respond rapidly to changes in emis-
sions.17 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). Emissions of sulfur diox-
ide are provided in Annex L of this report.
Global Warming Potentials
The Global Warming Potential (GWP) is intended
as a quantified measure of the relative radiative forcing
impacts of various greenhouse gases. It is defined as the
cumulative radiative forcing—both direct and indirect
effects—over a specified time horizon resulting from the
emission of a unit mass of gas relative to some reference
gas (IPCC 1996). Direct effects occur when the gas it-
self is a greenhouse gas. Indirect radiative forcing oc-
curs when chemical transformations involving the origi-
nal gas produces a gas or gases that are greenhouse gases,
or when a gas influences the atmospheric lifetimes of
other gases. The reference gas used is CO2, in which
case GWP weighted emissions are measured in million
metric tons of carbon equivalents (MMTCE). Carbon
comprises 12/44ths of carbon dioxide by weight. In or-
der to convert emissions reported in teragrams (Tg) of a
gas to MMTCE, the following equation is used:
(12
MMTCE = (Tgof gas)x(GWP)x —
i I 44
where, v
MMTCE = Million Metric Tons of Carbon Equivalents
Tg = Teragrams (equivalent to million metric tons)
GWP = Global Warming Potential
i "> \
12 = Carbon to CO2 molecular weight ratio.
44
GWP values allow policy makers to compare the im-
pacts of emissions and reductions of different gases. Ac-
cording to the IPCC, GWPs typically have an uncertainty
of ±35 percent. The parties to the FCCC have also agreed
to use GWPs based upon a 100 year time horizon although
other time horizon values are available (see Table 1-1).
In addition to communicating emissions in units of
mass, Parties may choose also to use global warming
potentials (GWPs) to reflect their inventories and pro-
jections in carbon dioxide-equivalent terms, using infor-
mation provided by the Intergovernmental Panel on Cli-
mate Change (IPCC) in its Second Assessment Report.
Any use of GWPs should be based on the effects of the
greenhouse gases over a 100-year time horizon. In ad-
dition, Parties may also use other time horizons.1*
Table 1-1: Global Warming Potentials and
Atmospheric Lifetimes (Years)
Gas
Atmospheric Lifetime
GWPa
Carbon dioxide (C02)
Methane (CH/
Nitrous oxide (N20)
HFC-23
HFC-125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
°F4
C F
C6F14
SF
6
50-200
12±3
120
264
32.6
14.6
48.3
1.5
36.5
209
17.1
50,000
10,000
2,600
3,200
3,200
1
21
310
11,700
2,800
1,300
3,800
140
2,900
6,300
1,300
6,500
9,200
7,000
7,400
23,900
Source: (IPCC 1996)
' 100 year time horizon
" The methane GWP includes the direct effects and those
indirect effects due to the production of tropospheric ozone
and stratospheric water vapor. The indirect effect due to the
production of C02 is not included.
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).
18 Framework Convention on Climate Change; FCCC/CP/1996/15/Add.l; 29 October 1996; Report of the Conference of the Parties on Its
Second Session; Held at Geneva from 8 To 19 July 1996; Addendum; Part Two: Action Taken By The Conference Of The Parties At Its Second
Session; Decision 9/CP.2; Communications from Parties included in Annex I to the Convention: guidelines, schedule and process for consid-
eration; Annex: Revised Guidelines for the Preparation of National Communications by Parties Included in Annex I to the Convention; p. 18.
1-6
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Greenhouse gases with long atmospheric lifetimes
(e.g., CO2, CH4, N2O, MFCs, PFCs, and SF6) tend to be
evenly distributed throughout the atmosphere, and conse-
quently global average concentrations can be determined.
The short-lived gases such as water vapor, tropospheric
ozone, ozone precursors (e.g., NOx, CO, and NMVOCs),
and tropospheric aerosols (e.g., SO2 products), however, vary
regionally, and consequently it is difficult to quantify their
global radiative forcing impacts. No GWP values are at-
tributed to gases that are short-lived and spatially inhomo-
geneous in the atmosphere. Other greenhouse gases not
yet listed by the Intergovernmental Panel on Climate Change
(IPCC), but are already or soon will be in commercial use
include: HFC-245fa, hydrofluoroethers (HFEs), and nitro-
gen trifluoride (NF3).
Organization of Report
In accordance with the IPCC guidelines for report-
ing contained in the Revised 1996 IPCC Guidelines for
National Greenhouse Gas Inventories (IPCC/UNEP/
OECD/IEA 1997), this U.S. inventory of greenhouse gas
emissions is segregated into six sector-specific chapters,
listed below:
Within each chapter, emissions are identified by
the anthropogenic activity that is the source of the green-
house gas emissions being estimated (e.g., coal mining).
Overall, the following organizational structure is consis-
tently applied throughout this report:
Chapter/Sector: Overview of emission trends
for sector
Source: Description of source pathway and emis-
sion trends from 1990 through 1996
— Methodology: Description of analytical meth-
ods employed to produce emission estimates
— Data Sources: Identification of primary data
references, primarily for activity data and emis-
sion factors
— Uncertainty: Discussion of relevant issues re-
lated to the uncertainty in the emission estimates
presented
Special attention is given to carbon dioxide from
fossil fuel combustion relative to other sources because
of its share of emissions relative to other sources. For it,
each energy consuming end-use is treated individually.
Additional information is also provided in the Annexes
(see box on following page).
Recent Trends in U.S.
Greenhouse Gas Emissions
Total U.S. greenhouse gas (GHG) emissions rose
in 1996 to 1,788.0 MMTCE (9.5 percent above 1990
baseline levels). The largest single year increase in emis-
sions over this time period was registered in 1996 (57.0
MMTCE or 3.3 percent) (see Figure 1-1).
Sectors
Activities Included
Energy
Industrial Processes
Solvent Use
Agriculture
Land-Use Change and Forestry
Waste
Emissions of all greenhouse gases resulting from stationary and mobile energy
activities including fuel combustion and fugitive fuel emissions.
By-product or fugitive emissions of greenhouse gases from industrial processes not
directly related to energy activities such as fossil fuel combustion.
Emissions, of primarily non-methane volatile organic compounds (NMVOCs),
resulting from the use of solvents.
Anthropogenic emissions from agricultural activities except fuel combustion and
sewage emissions, which are addressed under the Energy and Waste sectors,
respectively.
Emissions and removals from forest and land-use change activities, primarily carbon
dioxide.
Emissions from waste management activities.
Source: (IPCC/UNEP/OECD/IEA 1997)
Introduction
1-7
-------
ANNEX A Methodology for Estimating Emissions of C02 from Fossil Fuel Combustion
ANNEXE Methodology for Estimating Emissions of CH4, N20, and Criteria Pollutants from Stationary Combustion
ANNEX C Methodology for Estimating Emissions of CH4, N20, and Criteria Pollutants from Mobile Combustion
ANNEX D Methodology for Estimating Methane Emissions from Coal Production
ANNEXE Methodology for Estimating Methane Emissions from Natural Gas Systems
ANNEX F Methodology for Estimating Methane Emissions from Petroleum Systems
ANNEX G Methodology for Estimating Methane Emissions from Enteric Fermentation
ANNEX H Methodology for Estimating Methane Emissions from Manure Management
ANNEX I Methodology for Estimating Methane Emissions from Landfills
ANNEXJ Global Warming Potentials
ANNEX K Ozone Depleting Substance Emissions
ANNEX L Sulfur Dioxide Emissions
ANNEX M Complete List of Sources
ANNEX N IPCC Reporting Tables
ANNEX0 IPCC Reference Approach for Estimating C02 Emissions from Fossil Fuel Combustion
ANNEX P Preliminary 1997 Estimates of U.S. Greenhouse Gas Emissions and Sinks
ANNEX Q Sources of Greenhouse Gas Emissions Excluded
The largest source of U.S. GHG emissions was car-
bon dioxide (CO2) from fossil fuel combustion, which
accounted for 81 percent of weighted emissions in 1996.
Emissions from this source grew by 9 percent (118.9
MMTCE) over the seven year period and were respon-
sible for over two-thirds of the increase in national emis-
sions. The largest annual increase in emissions was reg-
istered in 1996, when increased fossil fuel consumption
drove up energy related CO emissions by 3.7 percent.
Figure 1-1
Recent Trends in U.S. GHG Emissions
LJrtmh Dlnxlrit
1.M*
1.VM
|lJWfl
= 1,000
750
•HFC*. ffCt, 4 9F,
• ,'1S J ".7J1 i \^j
mi mi 1*» iwi ms
The primary factors for this later single year increase
were (1) fuel switching by electric utilities from natural
gas to more carbon intensive coal as gas prices rose
sharply, (2) higher petroleum consumption in the trans-
portation end-use sector as travel increased and fuel effi-
ciency stagnated, (3) greater natural gas consumption for
heating in the residential end-use sector due to colder
weather, and (4) overall robust domestic economic
growth.
Other significant trends in emissions over the seven
year period of 1990 through 1996 included:
• Combined nitrous oxide (N2O) and methane (CH4)
emissions from mobile source fossil fuel combus-
tion rose 3.2 MMTCE (22 percent), primarily due
to increased rates of N2O generation in highway
vehicles.
• Aggregate hydrofluorocarbon (HFC) and
perfluorocarbon (PFC) emissions resulting from the
substitution of ozone depleting substances (e.g.,
CFCs) increased dramatically (by 11.6 MMTCE);
however PFC emissions from aluminum production
decreased significantly (41 percent) as a result of
both voluntary industry emission reduction efforts
and falling domestic aluminum production.
1-8
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Figure 1-2
Figure 1-3
U.S. GHG Emissions by Gas
1.9%HFCa.
6
6,8% N2
10.0-s; CH
CO.,
• Methane emissions from the decomposition of waste
in municipal and industrial landfills rose by 8.9
MMTCE (16 percent) as the amount of organic mat-
ter in landfills steadily accumulated.
• Emissions from coal mining dropped by 5.1
MMTCE (21 percent) as the use of methane from
degasification systems increased significantly.
• Nitrous oxide emissions from agricultural soil man-
agement increased by 6.2 MMTCE (10 percent) as
fertilizer consumption and cultivation of nitrogen
fixing crops rose.
Overall, from 1990 to 1996 total emissions of CO2,
CH4, and N2O increased by 122.8 (9 percent), 8.6 (5 per-
cent), and 11.4 MMTCE (12 percent), respectively. Dur-
ing the same period, weighted emissions of HFCs, PFCs,
and SF6 rose by 12.5 MMTCE (56 percent). Despite
being emitted in smaller quantities, emissions of HFCs,
PFCs, and SF are significant because of their extremely
Total U.S. GHG Emissions by Sector
Land-Llae Changn and FoTntry L»inh)
(4M)
1990 1991
1W4 tfl95
high global warming potentials and, in the cases of PFCs
and SF6, long atmospheric lifetimes. U.S. greenhouse
gas emissions were partly offset by carbon sequestration
in forests.
Alternatively, over the seven year period emissions
from the Energy, Industrial Processes, Agriculture, and
Waste sectors climbed by 120.2 (9 percent), 16.1 (35
percent), 9.9 (9 percent), and 9.1 MMTCE (15 percent),
respectively. Estimates of the quantity of carbon seques-
tered under the Land-Use Change and Forestry sector,
although based on projections, declined in absolute value
by 103.0 MMTCE (33 percent).
Table 1-2 summarizes emissions and sinks from
all U.S. anthropogenic sources weighted units of
MMTCE, while unweighted gas emissions and sinks
in teragrams (Tg) are provided in Table 1-3. Alterna-
tively, emissions and sinks are aggregated by sector in
Table 1-4 and Figure 1-3.
Introduction
1-9
-------
Table 1-2: U.S. Greenhouse Gas Emissions and Sinks (MMTCE)
Gas/Source
1990 1991
1992
1993
1994
1995
1996
CO,
Fossil Fuel Combustion
Natural Gas Flaring
Cement Manufacture
Lime Manufacture
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Carbon Dioxide Manufacture
Land-Use Change and Forestry (Sink)*
Stationary Sources
Mobile Sources
Coal Mining
Natural Gas Systems
Petroleum Systems
Petrochemical Production
Silicon Carbide Production
1,348.3 1,333.2 1,353.4 1,385.6 1,408.5 1,419.2 1,471.1
1,331.4 1,316.4 1,336.6 1,367.5 1,389.6 1,398.7 1,450.3
2.0
8.9
3.3
1.4
1.1
0.2
(311.5)
169.9
2.3
1.5
24.0
32.9
1.6
0.3
2.2
8.7
3.2
1.3
1.1
0.2
(311.5)
171.1
2.3
1.4
22.8
33.3
1.6
0.3
2.2
8.8
3.3
1.2
1.1
0.2
(311.5)
172.5
2.4
1.4
22.0
33.9
1.6
0.3
3.0
9.3
3.4
1.1
1.1
0.2
(208.6)
171.9
2.3
1.4
19.2
34.1
1.6
0.4
3.0
9.6
3.5
1.5
1.1
0.2
(208.6)
175.9
2.3
1.4
19.4
33.9
1.6
0.4
3.7
9.9
3.7
1.8
1.2
0.3
(208.6)
179.2
2.4
1.4
20.3
33.8
1.6
0.4
3.5
10.1
3.8
1.8
1.2
0.3
(208.6)
178.6
2.5
1.4
18.9
34.1
1.5
0.4
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Residue Burning
Landfills
Wastewater Treatment
N20
Stationary Sources
Mobile Sources
Adipic Acid
Nitric Acid
Manure Management
Agricultural Soil Management
Agricultural Residue Burning
Human Sewage
Waste Combustion
MFCs, PFCs, and SF6
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production
Semiconductor Manufacture
Electrical Transmission and Distribution
Magnesium Production and Processing
32.7
14.9
2.5
0.2
56.2
0.9
92.3
3.7
13.2
4.7
3.4
2.6
62.4
0.1
2.1
0.1
22.2
0.3
4.9
9.5
0.2
5.6
1.7
32.8
15.4
2.5
0.2
57.6
0.9
94.4
3.7
13.9
4.9
3.3
2.8
63.4
0.1
2.1
0.1
21.6
0.2
4.7
8.4
0.4
5.9
2.0
33.2
16.0
2.8
0.2
57.8
0.9
96.8
3.7
14.8
4.6
3.4
2.8
65.2
0.1
2.2
0.1
23.0
0.4
4.1
9.5
0.6
6.2
2.2
33.6
16.1
2.5
0.2
59.7
0.9
97.1
3.8
15.6
4.9
3.5
2.9
64.1
0.1
2.2
0.1
23.4
1.4
3.5
8.7
0.8
6.4
2.5
34.5
16.7
3.0
0.2
61.6
0.9
104.9
3.8
16.3
5.2
3.7
2.9
70.4
0.1
2.3
0.1
25.9
4.0
2.8
8.6
1.0
6.7
2.7
34.9
16.9
2.8
0.2
63.6
0.9
101.9
3.8
16.6
5.2
3.7
2.9
67.2
0.1
2.2
0.1
30.8
9.5
2.7
7.4
1.2
7.0
3.0
34.5
16.6
2.5
0.2
65.1
0.9
103.7
4.0
16.5
5.4
3.8
3.0
68.6
0.1
2.3
0.1
34.7
11.9
2.9
8.5
1.4
7.0
3.0
Total Emissions
Net Emission (Sources and Sinks)
1,632.7 1,620.2 1,645.7 1,678.0 1,715.3 1,731.1 1,788.0
1,321.2 1,308.7 1,334.2 1,469.4 1,506.7 1,522.5 1,579.5
+ Does not exceed 0.05 MMTCE
* Sinks are only included in net emissions total. Estimates of net carbon sequestration due to land-use change and forestry activities exclude
non-forest soils, and are based partially upon projections of forest carbon stocks.
Note: Totals may not sum due to independent rounding.
1-10
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 1-3: U.S. Greenhouse Gas Emissions and Sinks (Tg)
Gas/Source 1990 1991 1992 1993 1994 1995 1996
CO
2
Fossil Fuel Combustion
Natural Gas Flaring
Cement Manufacture
Lime Manufacture
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Carbon Dioxide Manufacture
Land-Use Change and Forestry (Sink)3
CH4
Stationary Sources
Mobile Sources
Coal Mining
Natural Gas Systems
Petroleum Systems
Petrochemical Production
Silicon Carbide Production
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Residue Burning
Landfills
Wastewater Treatment
N20
Stationary Source
Mobile Sources
Adipic Acid
4,943.7
4,881.9
7.3
32.6
11.9
5.1
4.1
0.8
(1,142.2)
29.7
0.4
0.3
4.2
5.7
0.3
0.1
+
5.7
2.6
0.4
+
9.8
0.2
1.1
+
0.2
0.1
4,888.5
4,826.9
8.2
31.9
11.7
4.9
4.0
0.8
(1,142.2)
29.9
0.4
0.2
4.0
5.8
0.3
0.1
+
5.7
2.7
0.4
+
10.0
0.2
1.1
+
0.2
0.1
4,962.5
4,900.7
8.1
32.1
12.1
4.5
4.1
0.9
(1,142.2)
30.1
0.4
0.2
3.8
5.9
0.3
0.1
+
5.8
2.8
0.5
+
10.1
0.2
1.1
+
0.2
0.1
5,080.4
5,014.1
11.0
33.9
12.4
4.1
4.0
0.9
(764.7)
30.0
0.4
0.2
3.4
5.9
0.3
0.1
+
5.9
2.8
0.4
+
10.4
0.2
1.1
+
0.2
0.1
5,164.7
5,095.2
11.1
35.4
12.8
5.3
4.0
0.9
(764.7)
30.7
0.4
0.2
3.4
5.9
0.3
0.1
+
6.0
2.9
0.5
+
10.8
0.2
1.2
+
0.2
0.1
5,203.7
5,128.5
13.7
36.1
13.6
6.5
4.3
1.0
(764.7)
31.3
0.4
0.2
3.6
5.9
0.3
0.1
+
6.1
2.9
0.5
+
11.1
0.2
1.2
+
0.2
0.1
5,393.9
5,317.8
12.7
37.1
14.1
6.7
4.3
1.1
(764.7)
31.2
0.4
0.2
3.3
5.9
0.3
0.1
+
6.0
2.9
0.4
+
11.4
0.2
1.2
+
0.2
0.1
Nitric Acid + + + + + + +
Manure Management + + + + + + +
Agricultural Soil Management 0.7 0.8 0.8 0.8 0.8 0.8 0.8
Agricultural Residue Burning + + + + + + +
Human Sewage + + + + + + +
Waste Combustion + + + + + + +
MFCs, PFCs, and SF6 M M M M M M M
Substitution of Ozone Depleting Substances M M M M M M M
Aluminum Production M M M M M M M
HCFC-22 Production" + + + + + + +
Semiconductor Manufacture M M M M M M M
Electrical Transmission and Distribution0 + + + + + + +
Magnesium Production and Processing0 + + + + + + +
NO,
CO
NMVOCs
21.6
83.7
18.8
21.6
85.4
18.9
21.9
82.4
18.5
22.2
82.4
18.7
22.6
86.5
19.3
21.7
77.2
18.4
21.3
76.4
17.0
+ Does not exceed 0.05 Tg
M Mixture of multiple gases
" Sinks are not included in C02 emissions total. Estimates of net carbon sequestration due to land-use change and forestry activities exclude
non-forest soils, and are based partially upon projections of forest carbon stocks.
" HFC-23 emitted
c SF6 emitted
Note: Totals may not sum due to independent rounding.
Introduction 1-11
-------
Table 1-4: U.S. Greenhouse Gas Emissions and Sinks by Sector (MMTCE)
Sector
1990
1991
1992
1993
1994
1995
1996
Energy
Industrial Processes
Agriculture
Land-Use Change and Forestry (Sink)*
Waste
Total Emissions
Net Emission (Sources and Sinks)
1
1
1
,412,
45,
115,
(311
59,
,632,
3?1
.5
.5
.5
.5)
.3
.7
?
1,397,
44
117
(311
60
1,620
1,308
.6
.7
.3
.5)
.6
.2
7
1,418.6
45.9
120.3
(311.5)
61.0
1,645.7
1,334.2
1,448.4
47.2
119.5
(208.6)
62.8
1,678.0
1,469.4
1,471.3
51.2
127.9
(208.6)
64.8
1,715.3
1,506.7
1,482.3
56.9
125.0
(208.6)
66.9
1,731.1
1,522.5
1
1
1
,532.7
61.5
125.4
(208.6)
68.4
,788.0
,579.5
* Sinks are only included in net emissions total. Estimates of net carbon sequestration due to land-use change and forestry activities exclude
non-forest soils, and are based partially upon projections of forest carbon stocks.
Note: Totals may not sum due to independent rounding.
Greenhouse Gas Emissions from Transportation Activities
Motor vehicle usage is increasing all over the world, including
in the United States. Since the 1970s, the number of highway
vehicles registered in the United States has increased faster
than the overall population, according to the Federal Highway
Administration. Likewise, the number of miles driven—up 15
percent since 1990—and gallons of gasoline consumed each
year in the United States has increased relatively steadily
since the 1980s, according to the Energy Information Adminis-
tration. These increases in motor vehicle usage are the result
of a confluence of factors including population growth, eco-
nomic growth, increasing urban sprawl, and low fuel prices.
One of the unintended consequences of these changes was a
slowing of progress toward cleaner air in both urban and rural
parts of the country. Passenger cars, trucks, motorcycles,
and buses emit significant quantities of air pollutants with local,
regional, and global effects. Motor vehicles were major sources
of carbon monoxide, carbon dioxide (C02), methane (CH4),
nonmethane volatile organic compounds, nitrogen oxides, ni-
trous oxide (N20), and hydrofluorocarbons (MFCs). Motor
vehicles were also important contributors to many serious air
pollution problems, including ground level ozone or smog, acid
rain, fine paniculate matter, and global warming. Within the
United States and abroad, government agencies have taken
strong actions to reduce these emissions. Since the 1970s,
the EPA has reduced lead in gasoline, developed strict emis-
sion standards for new passenger cars and trucks, directed
states to enact comprehensive motor vehicle emission control
programs, required inspection and maintenance programs, and
more recently, introduced the use of reformulated gasoline to
mitigate the air pollution impacts from motor vehicles. New
vehicles are now equipped with advanced emissions controls,
which are designed to reduce emissions of nitrogen oxides,
hydrocarbons, and carbon monoxide.
This report reflects new data on the role that automotive cata-
lytic converters play in emissions of N20, a powerful green-
house gas. The EPA's Office of Mobile Sources has recently
conducted a series of tests in order to measure the magnitude
of N20 emissions from gasoline-fueled passenger cars and
light-duty trucks equipped with catalytic converters. Results
show that N20 emissions are lower than the IPCC default
factors and the United States has shared this data with the
IPCC. Now, new emission factors developed from these
measurements and from previously published literature were
used to calculate emissions from mobile sources in the United
States (see Annex C).
Table 1 -5 summarizes greenhouse gas emissions from all trans-
portation related activities. Overall, transportation activities
accounted for an almost constant 26 percent of total U.S. green-
house gas emissions from 1990 to 1996. These emissions
were primarily C02 from fuel combustion, which increased by
8.8 percent from 1990 to 1996. However, because of larger
increases in N20 and HFC emissions during this period, over-
all emissions from transportation activities actually increased
by 10.1 percent.
1-12
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 1-5: Transportation Related Greenhouse Gas Emissions (MMTCE)
Gas/Vehicle Type 1990 1991 1992 1993 1994 1995 1996
C02
Passenger Cars3
Light-Duty Trucks3
Other Trucks
Buses
Aircraft
Boats and Vessels
Locomotives
Other"
CH
Passenger Cars
Light-Duty Trucks
Other Trucks and Buses
Aircraft
Boats and Vessels
Locomotives
Other0
N20
Passenger Cars
Light-Duty Trucks
Other Trucks and Buses
Aircraft"
Boats and Vessels
Locomotives
Other0
MFCs
Mobile Air Conditioners6
Total
409.6
169.3
77.5
56.8
2.7
55.9
16.3
7.4
23.7
1.5
0.8
0.4
0.1
+
0.1
+
0.1
13.2
8.7
3.4
0.7
+
0.2
0.1
0.2
+
+
424.3
400.8
167.8
77.2
54.7
2.9
53.8
15.0
6.9
22.4
1.4
0.7
0.4
0.1
+
0.1
+
0.1
13.9
9.1
3.7
0.7
+
0.2
0.1
0.2
+
+
416.1
406.7
172.0
77.2
56.6
2.9
53.0
15.3
7.4
22.4
1.4
0.7
0.4
0.1
+
0.1
+
0.1
14.8
9.7
3.9
0.7
+
0.2
0.1
0.2
0.2
0.2
423.2
414.1
173.5
80.5
59.7
3.0
53.5
13.4
6.7
23.7
1.4
0.7
0.4
0.2
+
+
+
0.1
15.6
10.1
4.2
0.7
+
0.2
0.1
0.2
0.7
0.7
431.7
427.4
172.5
87.2
62.4
3.3
55.6
13.7
8.0
24.8
1.4
0.7
0.4
0.2
+
+
+
0.1
16.3
10.0
5.1
0.8
+
0.2
0.1
0.2
1.3
1.3
446.4
432.8
160.0
104.9
64.0
3.5
55.0
12.5
8.1
24.9
1.4
0.7
0.4
0.2
+
+
+
0.1
16.6
10.1
5.2
0.8
+
0.2
0.1
0.2
2.5
2.5
453.3
445.5
163.2
107.1
67.0
3.7
57.4
13.2
8.5
25.5
1.4
0.6
0.4
0.2
+
+
+
0.1
16.5
10.1
5.1
0.9
+
0.2
0.1
0.2
3.6
3.6
467.0
+ Does not exceed 0.05 MMTCE
Note: Totals may not sum due to independent rounding.
' In 1995, the U.S. Federal Highway Administration modified the definition of light-duty trucks to include minivans and sport utility vehicles.
Previously, these vehicles were included under the passenger cars category. Hence the sharp drop in C02 emissions for passenger cars from
1994 to 1995 was observed. This gap, however, was offset by an equivalent rise in C02 emissions from light-duty trucks.
" "Other" C02 emissions includes motorcycles, construction equipment, agricultural machinery, pipelines, and lubricants.
c "Other" CH4 and N20 emissions includes motorcycles, construction equipment, agricultural machinery, gasoline-powered recreational,
industrial, lawn and garden, light commercial, logging, airport service, other equipment; and diesel-powered recreational, industrial, lawn and
garden, light construction, airport service.
d Aircraft N20 emissions include aviation gasoline combustion but exclude jet fuel combustion due to insufficient data availability.
e Includes primarily HFC-134a
Introduction 1-13
-------
Electric Utility Related Greenhouse Gas Emissions
Like transportation, activities related to the generation, transmission and distribution of electricity in the United States result in
greenhouse gas emissions. Table 1-6 presents greenhouse gas emissions from electric utility related activities. Overall emissions
from electric utilities increased by 8.6 percent from 1990 to 1996, and accounted for just under 30 percent of total U.S. green-
house emissions during the same period.
Table 1-6: Electric Utility Related Greenhouse Gas Emissions (MMTCE)
Gas/Fuel Type or Source
1990
1991
1992
1993
1994
+ Does not exceed 0.05 MMTCE
Note: Totals may not sum due to independent rounding.
1995 1996
C02
Coal
Natural Gas
Petroleum
Geothermal
CH4
Stationary Sources (Utilities)
N20
Stationary Sources (Utilities)
SF6
Electrical Transmission and Distribution
Total
476.8
409.0
41.2
26.6
0.1
0.1
0.1
2.0
2.0
5.6
5.6
484.6
473.4
407.2
41.1
25.1
0.1
0.1
0.1
2.0
2.0
5.9
5.9
481.4
472.5
411.8
40.7
19.9
0.1
0.1
0.1
2.0
2.0
6.2
6.2
480.8
490.7
428.7
39.5
22.5
0.1
0.1
0.1
2.1
2.1
6.4
6.4
499.3
494.8
430.2
44.0
20.6
+
0.1
0.1
2.1
2.1
6.7
6.7
503.7
493.8
432.7
47.2
14.0
+
0.1
0.1
2.1
2.1
7.0
7.0
503.1
516.8
460.9
40.3
15.6
+
0.1
0.1
2.2
2.2
7.0
7.0
526.2
Methodology and Data Sources
Emissions of greenhouse gases from various
sources have been estimated using methodologies that
are consistent with the Revised 1996IPCC Guidelines
for National Greenhouse Gas Inventories (IPCC/UNEP/
OECD/IEA 1997) except were noted otherwise. To the
extent possible, the present U.S. inventory relies on pub-
lished activity and emission factor data. Depending on
the emission source category, activity data can include
fuel consumption or deliveries, vehicle-miles traveled,
raw material processed, etc.; emission factors are factors
that relate quantities of emissions to an activity. For some
sources, IPCC default methodologies and emission fac-
tors have been employed. However, for emission sources
considered to be major sources in the United States, the
IPCC default methodologies were expanded and more
comprehensive methods were applied.
Inventory emission estimates from energy con-
sumption and production activities are based primarily
on the latest official fuel consumption data from the En-
ergy Information Administration of the Department of
Energy (EIA). Emission estimates for NOx, CO, and
NMVOCs were taken directly, except where noted, from
the United States Environmental Protection Agency's
(EPA) report, National Air Pollutant Emission Trends
1900 -1996 (EPA 1997), which is an annual EPA publi-
cation that provides the latest estimates of regional and
national emissions for ozone precursors (i.e., criteria
pollutants). Emissions of these pollutants are estimated
by the EPA based on statistical information about each
source category, emission factors, and control efficien-
cies. While the EPA's estimation methodologies for cri-
teria pollutants are conceptually similar to the IPCC rec-
ommended methodologies, the large number of sources
EPA used in developing its estimates makes it difficult to
reproduce the methodologies from EPA (1997) in this
inventory document. In these instances, the sources con-
taining detailed documentation of the methods used are
referenced for the interested reader. For agricultural
sources, the EPA criteria pollutant emission estimates
were supplemented using available activity data from
other agencies. Complete documentation of the meth-
odologies and data sources used is provided in conjunc-
tion with the discussion of each source and in the vari-
ous annexes.
Carbon dioxide emissions from fuel combusted in
ships or aircraft engaged in the international transport of
1-14
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
passengers or cargo are not included in U.S. totals, but
are reported separately as international bunkers in ac-
cordance with IPCC reporting guidelines (IPCC/UNEP/
OECD/IEA 1997). Carbon dioxide emissions from fuel
combusted within U.S. territories, however, are included
in U.S. totals.
Uncertainty in and
Limitations of Emission Estimates
While the current U.S. emissions inventory pro-
vides a solid foundation for the development of a more
detailed and comprehensive national inventory, it has
several strengths and weaknesses.
First, this inventory by itself does not provide a
complete picture of past or future emissions in the United
States; it only provides an inventory of U.S. emissions
for the years 1990 through 1996. However, the United
States believes that common and consistent inventories
taken over a period of time can and will contribute to
understanding future emission trends. The United States
produced its first comprehensive inventory of greenhouse
gas emissions and sinks in 1993, and intends to annually
update this inventory in conjunction with its commitments
under the FCCC. The methodologies used to estimate
emissions will be periodically updated as methods and
information improve, and as further guidance is received
from the IPCC.
Secondly, there are uncertainties associated with
the emissions estimates. Some of the current estimates,
such as those for CO2 emissions from energy-related ac-
tivities and cement processing, are considered to be fairly
accurate. For other categories of emissions, however, a
lack of data or an incomplete understanding of how emis-
sions are generated limit the scope or accuracy of the
estimates presented. Within the discussion of each emis-
sion source, specific factors affecting the accuracy of the
estimates are discussed.
Finally, while the IPCC methodologies provided
in the Revised 1996 IPCC Guidelines for National Green-
house Gas Inventories (IPCC/UNEP/OECD/IEA 1997)
represent baseline methodologies for a variety of source
categories, many of these methodologies continue to be
improved and refined as new research and data becomes
available. The current U.S. inventory uses the IPCC
methodologies where possible, and supplements them
with other available methodologies and data where pos-
sible. The United States realizes that additional efforts
are still needed to improve methodologies and data col-
lection procedures. Specific areas requiring further re-
search include:
Incorporating excluded emission sources. Quan-
titative estimates of some of the sources and sinks of
greenhouse gas emissions are not available at this time.
In particular, emissions from some land-use activities and
industrial processes are not included in the inventory ei-
ther because data are incomplete or because methodolo-
gies do not exist for estimating emissions from these
source categories. See Annex Q for a discussion of the
sources of greenhouse gas emissions excluded from this
report.
Improving the accuracy of emission factors. Fur-
ther research is needed in some cases to improve the ac-
curacy of emission factors used to calculate emissions
from a variety of sources. For example, the accuracy of
current emission factors applied to methane and nitrous
oxide emissions from stationary and mobile source fos-
sil fuel combustion are highly uncertain.
Collecting detailed activity data. Although meth-
odologies exist for estimating emissions for some sources,
problems arise in obtaining activity data at a level of de-
tail in which aggregate emission factors can be applied.
For example, the ability to estimate emissions of meth-
ane and nitrous oxide from jet aircraft is limited due to a
lack of activity data by aircraft type and number of land-
ing and take-off cycles.
Applying Global Warming Potentials. GWP val-
ues have several limitations including that they are not
applicable to unevenly distributed gases and aerosols such
as tropospheric ozone and its precursors. They are also
intended to reflect global averages and, therefore, do not
account for regional effects (IPCC 1996).
Emissions calculated for the U.S. inventory reflect
current best estimates; in some cases, however, estimates
are based on approximate methodologies, assumptions,
and incomplete data. As new information becomes avail-
able in the future, the United States will continue to im-
prove and revise its emission estimates.
Introduction
1-15
-------
Changes in the U.S.
Greenhouse Gas Inventory Report
In 1997, the Intergovernmental Panel on Climate
Change released the Revised 1996IPCC Guidelines for
National Greenhouse Gas Inventories (IPCC/UNEP/
OECD/IEA 1997) that included multiple methodologi-
cal changes and wholly new source categories. These
revised IPCC guidelines along with other unrelated ad-
ditions and methodological changes have been incorpo-
rated into this year's inventory of greenhouse gas emis-
sions and sinks which, depending on the source, improve
the accuracy, precision, or comprehensiveness of the es-
timates presented relative to previous U.S. inventories.
In particular, several new N2O sources have been included
for the first time and revisions have been made to some
existing sources that significantly increase overall N2O
emissions relative to previous U.S. inventories. A sum-
mary of the additions and changes made to this report is
provided below:
• An improved methodology for estimating methane
and nitrous oxide emissions from mobile sources was
employed that accounts for changes in emission con-
trol technologies over time and vehicle miles trav-
eled by model year. New N2O emission factors were
also used, based in part on new measurement data,
which had the primary result of revising N2O emis-
sion estimates from highway vehicles upward.
• An additional analysis of CO2 emissions from fossil
fuel combustion in the transportation end-use sector is
provided showing emissions by fuel and vehicle type.
• Carbon sequestration from non-fuel uses of fossil
fuels in U. S. territories was included for the first time
in emission estimates of CO2 from fossil fuel com-
bustion.
• Due to inconsistencies in natural gas production and
consumption data available from the Energy Infor-
mation Administration, CO2 emissions from
unmetered natural gas consumption were not in-
cluded. This exclusion had a insignificant effect on
reported emissions.
• Carbon dioxide emissions from geothermal steam
extraction for electric power generation were in-
cluded for the first time, although its contribution
to total emissions was less than 0.1 MMTCE.
• Improved emission factors and a more detailed
analysis of activities contributing to methane emis-
sions from natural gas systems were employed.
• Several new industrial processes were included for
the first time. Methane emissions from the produc-
tion of select petrochemicals and silicon carbide pro-
duction were added, although their contribution was
minor. Carbon dioxide emissions from ammonia,
iron and steel, and ferroalloy production were ex-
plicitly estimated, even though their emissions are
accounted for under the fossil fuel combustion of
industrial coking coal and natural gas.
• The discussion of HFC, PFC, and SF6 emissions has
been expanded to include multiple sources and im-
proved estimating methodologies.
• Estimates of nitrous oxide emissions from agricul-
tural soil management have been considerably ex-
panded to include direct and indirect emissions from
organic fertilizers, cropping practices, and livestock
manure management. Previous inventories simply
accounted for emissions resulting from the applica-
tion of synthetic fertilizers. As a result of this more
comprehensive methodology, estimates have roughly
tripled relative to previous years.
• Nitrous oxide emissions from manure management
have been estimated for the first time.
• Additional crop types have been included in the analy-
sis of emissions from agricultural residue burning.
• Carbon dioxide fluxes estimated from land-use
change and forestry have been revised to include
forest soils, forest understory, and non-forest soils.
Additionally, estimates for carbon stocks in forest
product pools now include wood harvested from
public lands, which were previously excluded. These
changes have more than doubled the flux estimates
relative to previous year's inventories.
• An improved methodology for estimating methane
emissions from landfills has been used, which tracks
explicitly the shift to fewer, larger landfills.
• Nitrous oxide emissions from human sewage and
waste combustion were estimated for the first time.
1-16
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
2. Energy
Er
I—of
1996 Energy Sector GHG Sources
-ilAiitt Put- C-jIMbulllli'l
Nature CM Syi
Coal Mir M
Sourav "i
Hiring
•
::• 40
MMTCF
|nergy-related activities were the primary source Figure 2-1
Df anthropogenic greenhouse gas emissions, ac-
counting for 86 percent of total U.S. emissions annually
on a carbon equivalent basis in 1996. This included 99,
33, and 20 percent of the nation's carbon dioxide (CO2),
methane (CH4), and nitrous oxide (N2O) emissions, respec-
tively. Energy-related CO2 emissions alone constituted 81
percent of national emissions from all sources on a carbon
equivalent basis (see Figure 2-1), while the non-CO2 emis-
sions from energy 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. Due to the relative importance
of fossil fuel combustion related CO2 emissions, they are considered separately from other emissions. Fossil fuel
combustion also emits CH4 and N2O, as well as criteria pollutants such as nitrogen oxides (NOx), carbon monoxide
(CO), and non-methane volatile organic compounds (NMVOCs). Fossil fuel combustion—from stationary and mo-
bile sources—was the second largest source N2O emissions in the United States, and overall energy related activities
are the largest sources of criteria pollutant emissions.
Energy-related activities other than fuel combustion, such as the production, transmission, storage, and distribution
of fossil fuels, also emit greenhouse gases. These emissions consist primarily of CH4 from natural gas systems, petroleum
systems, and coal mining. Smaller quantities of CO2, CO, NMVOCs, 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 under the Energy sector because biomass
fuels are of biogenic origin. It is assumed that the carbon released when biomass is consumed is recycled as U.S.
forests and crops regenerate, causing no net addition of CO2 to be added to the atmosphere. The net impacts of land-
use and forestry activities on the carbon cycle are accounted for under the Land-use change and Forestry sector.
Overall, emissions from the Energy sector have increased from 1990 to 1996 due, in part, to the strong perfor-
mance of the U.S. economy. Over this period, the U.S. Gross Domestic Product (GDP) grew approximately 13
percent, or at an annualized rate of about 2 percent. This robust economic activity increased the demand for fossil
fuels, with an associated increase in greenhouse gas emissions. Table 2-1 summarizes emissions from the Energy
sector in units of million metric tons of carbon equivalents (MMTCE), while unweighted gas emissions in teragrams
Energy 2-1
-------
Table 2-1: Emissions from the Energy Sector (MMTCE)
Gas/Source 1990 1991 1992 1993 1994 1995 1996
C02
Fossil Fuel Combustion
Natural Gas Flaring
Biomass-Ethanol*
Biomass-Wood*
International Bunker Fuels*
Non-fuel Use Carbon Stored*
CH4
Stationary Sources
Mobile Sources
Coal Mining
Natural Gas Systems
Petroleum Systems
N20
Stationary Sources
Mobile Sources
Total
1,333.4
1,331.4
2.0
1.6
47.0
22.7
(69.2)
62.2
2.3
1.5
24.0
32.9
1.6
16.9
3.7
13.2
1,412.5
1,318.7
1,316.4
2.2
1.2
46.9
24.0
(68.8)
61.4
2.3
1.4
22.8
33.3
1.6
17.6
3.7
13.9
1,397.6
1,338.8
1,336.6
2.2
1.5
49.0
24.9
(70.6)
61.3
2.4
1.4
22.0
33.9
1.6
18.5
3.7
14.8
1,418.6
1,370.5
1,367.5
3.0
1.7
47.6
22.9
(73.1)
58.5
2.3
1.4
19.2
34.1
1.6
19.3
3.8
15.6
1,448.4
1,392.6
1,389.6
3.0
1.8
48.4
22.3
(78.2)
58.6
2.3
1.4
19.4
33.9
1.6
20.1
3.8
16.3
1,471.3
1,402.4
1,398.7
3.7
2.0
50.2
23.6
(78.8)
59.5
2.4
1.4
20.3
33.8
1.6
20.4
3.8
16.6
1,482.3
1,453.8
1,450.3
3.5
1.4
53.2
22.5
(81.7)
58.4
2.5
1.4
18.9
34.1
1.5
20.5
4.0
16.5
1,532.7
+ Does not exceed 0.05 MMTCE
* These figures 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 2-2: Emissions from the Energy Sector (Tg)
Gas/Source 1990 1991 1992 1993 1994 1995 1996
C02
Fossil Fuel Combustion
Natural Gas Flaring
Biomass-Ethanol*
Biomass-Wood*
International Bunker Fuels*
Non-fuel Use Carbon Stored*
CH4
Stationary Sources
Mobile Sources
Coal Mining
Natural Gas Systems
Petroleum Systems
N20
Stationary Sources
Mobile Sources
4,889.2
4,881.9
7.3
5.7
172.2
83.4
(253.8)
10.9
0.4
0.3
4.2
5.7
0.3
0.2
+
0.2
4,835.2
4,826.9
8.2
4.5
171.9
87.8
(252.3)
10.7
0.4
0.2
4.0
5.8
0.3
0.2
+
0.2
4,908.8
4,900.7
8.1
5.5
179.7
91.3
(258.8)
10.7
0.4
0.2
3.8
5.9
0.3
0.2
+
0.2
5,025.1
5,014.1
11.0
6.1
174.5
83.8
(268.2)
10.2
0.4
0.2
3.4
5.9
0.3
0.2
+
0.2
5,106.3
5,095.2
11.1
6.7
177.5
81.7
(286.6)
10.2
0.4
0.2
3.4
5.9
0.3
0.2
+
0.2
5,142.2
5,128.5
13.7
7.2
184.2
86.7
(289.1)
10.4
0.4
0.2
3.6
5.9
0.3
0.2
+
0.2
5,330.6
5,317.8
12.7
5.1
195.0
82.4
(299.7)
10.2
0.4
0.2
3.3
5.9
0.3
0.2
+
0.2
+ Does not exceed 0.05 Tg
* These figures are presented for informational purposes only and are not included or are already accounted for in totals.
Note: Totals may not sum due to independent rounding.
2-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
(Tg) are provided in Table 2-2. Overall, emissions due
to energy-related activities increased by more than 9 per-
cent from 1990 to 1996, rising from 1,412.5 MMTCE in
1990 to 1,532.7 MMTCE in 1996. The growth in emis-
sions from 1995 to 1996 (3.4 percent) was the largest
percent increase over the seven year period. This growth
rate in emissions actually exceeded the overall growth
rate in the economy. Discussion of specific Energy sec-
tor trends is presented below.
Figure 2-2
1996 U.S. Energy Consumption
24.1%
Natural Gas
38.1%
PotrufoLim
Source: DOE/EIA-0384(96), Annual Energy Review 1996, Table
1.3, July 1997
Carbon Dioxide Emissions
from Fossil Fuel Combustion
The majority of energy consumed in the United
States, approximately 84.5 percent, was produced through
the combustion of fossil fuels such as coal, natural gas,
and petroleum in 1996 (see Figure 2-2). Of the remain-
ing, 7.6 percent was supplied by nuclear electric power
and 7.8 percent from renewable sources (EIA 1997a).
As fossil fuels are combusted, the carbon stored in
the fuels is emitted as CO2 and smaller amounts of other
gases, including methane (CH4), carbon monoxide (CO),
and non-methane volatile organic compounds
(NMVOCs). These other gases are emitted as a by-prod-
uct of incomplete fuel combustion. The amount of car-
bon in the fuel varies significantly by fuel type. For ex-
ample, coal contains the highest amount of carbon per
unit of useful energy. Petroleum has roughly 75 percent
of the carbon per unit of energy as coal, and natural gas
has only about 55 percent.1 Petroleum supplied the larg-
est share of U.S. energy demands, accounting for an av-
erage of 3 9 percent of total energy consumption over the
period of 1990 through 1996 (see Figure 2-2). Natural
gas and coal followed in order of importance, account-
ing for an average of 24 and 22 percent of total con-
sumption, respectively. Most petroleum was consumed
in the transportation end-use sector, while the vast ma-
jority of coal was used by electric utilities, with natural
gas consumed largely in the industrial and residential end-
use sectors.
Emissions of CO2 from fossil fuel combustion in-
creased at an annualized rate of 1.4 percent from 1990 to
1996. The major factor behind this trend was a robust
domestic economy, combined with relatively low energy
prices. For example, petroleum prices had changed little
in real terms since the 1970s, with coal prices actually
declining in real terms compared to prices in the 1970s
(EIA 1997a) (see Figure 2-3). After 1990, when carbon
dioxide emissions from fossil fuel combustion were
1,331.4 MMTCE (4,881.9 Tg), there was a slight decline
Figure 2-3
1*K ™tW 1BBE mBa 1*M Ittt 1th IfltfG
Source: DOE/EIA-0384(96), Annual Energy Review 1996,
July, 1997, Table 3.1
1
Based on national aggregate carbon content of all coal, natural gas, and petroleum fuels combusted in the United States.
Energy 2-3
-------
Table 2-3: CO Emissions from Fossil Fuel Combustion by Fuel Type and End-Use Sector (MMTCE)
Fuel/End-Use Sector
1990
1991
1992
1993
1994
1995
1996
Coal
Residential
Commercial
Industrial
Transportation
Utilities
U.S. Territories
Natural Gas
Residential
Commercial
Industrial
Transportation
Utilities
U.S. Territories
Petroleum
Residential
Commercial
Industrial
Transportation
Utilities
U.S. Territories
Geothermal*
Total
481.6
1.6
2.4
68.5
409.0
0.1
273.1
65.1
38.8
118.2
9.8
41.2
-
576.7
23.9
18.0
100.2
399.0
26.6
9.0
0.1
1,331.4
475.8
1.4
2.2
64.8
407.2
0.2
277.9
67.5
40.4
120.0
8.9
41.1
-
562.6
24.4
17.1
94.5
391.1
25.1
10.5
0.1
1,316.4
478.3
1.5
2.2
62.6
411.8
0.2
286.2
69.4
41.5
125.8
8.8
40.7
-
572.0
24.8
16.1
104.3
397.3
19.9
9.6
0.1
1,336.6
494.7
1.5
2.2
62.2
428.7
0.2
296.3
73.4
43.1
131.0
9.3
39.5
-
576.4
26.2
14.9
98.3
404.1
22.5
10.4
0.1
1,367.5
496.7
1.4
2.1
62.7
430.2
0.3
302.1
71.8
42.9
133.3
10.2
44.0
-
593.5
25.3
14.9
102.2
416.6
20.6
11.2
+
1,389.6
498.5
1.4
2.1
62.1
432.7
0.3
314.8
71.7
45.9
139.7
10.4
47.2
-
587.7
25.7
15.0
97.9
421.7
14.0
10.9
+
1,398.7
524.0
1.4
2.1
59.4
460.9
0.3
318.6
77.4
47.4
143.0
10.5
40.3
-
609.0
27.2
15.3
104.6
434.3
15.6
10.6
+
1,450.3
- Not applicable
+ Does not exceed 0.05 MMTCE
* Although not technically a fossil fuel, geothermal energy related C02 emissions are included for reporting purposes.
Note: Totals may not sum due to independent rounding.
of emissions in 1991, followed by an increase to 1,450.3
MMTCE (5,317.8 Tg) in 1996 (see Table 2-3 and Table
2-4). Overall, CO2 emissions from fossil fuel combus-
tion increased by 9 percent over the seven year period
and rose by a dramatic 3.7 percent in the final year alone.
Consumption of all fossil fuels increased, with
about 38 percent of the increase in CO2 emissions from
fossil fuel combustion since 1990 coming from natural
gas consumption, 36 percent from coal, and 26 percent
from petroleum. From 1995 to 1996, absolute emissions
from coal grew the most (an increase of 25.5 MMTCE
or 5 percent), while emissions from natural gas changed
the least (an increase of 3.8 MMTCE or 1 percent) as
electric utilities increased their consumption of coal while
shifting away from natural gas because of higher gas
prices. Alone, emissions from electric utility coal com-
bustion increased by 6.5 percent from 1995 to 1996.
In 1996, the U.S. coal industry produced the larg-
est amount of coal ever. Preliminary data (EIA 1997b)
show that annual U.S. coal consumption totaled 892
teragrams (Tg) in 1996, a 4.5 percent increase from 1995,
the combustion of which accounted for roughly half of
the total increase in emissions during the same period.
Despite slightly higher prices, the consumption of
petroleum products in 1996 increased 3.5 percent from the
previous year, accounting for about 43 percent of the increase
in CO2 emissions from fossil fuel combustion. More than
half of the increase in emissions from petroleum was due to
higher fuel consumption for transportation activities.
2-4
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 2-4: CO Emissions from Fossil Fuel Combustion by Fuel Type and End-Use Sector (Tg)
Fuel/End-Use Sector
1990
1991
1992
1993
1994
1995
- Not applicable
+ Does not exceed 0.05 Tg
* Although not technically a fossil fuel, geothermal energy related C02 emissions are included for reporting purposes.
Note: Totals may not sum due to independent rounding.
1996
Coal
Residential
Commercial
Industrial
Transportation
Utilities
U.S. Territories
Natural Gas
Residential
Commercial
Industrial
Transportation
Utilities
U.S. Territories
Petroleum
Residential
Commercial
Industrial
Transportation
Utilities
U.S. Territories
Geothermal*
Total
1,765.7
5.8
8.7
251.0
-
1,499.7
0.4
1,001.3
238.5
142.4
433.2
36.0
151.1
2,114.6
87.7
66.1
367.2
1,463.1
97.6
32.8
0.2
4,881.9
1,744.7
5.3
8.0
237.6
-
1,493.2
0.6
1,019.1
247.3
148.2
440.1
32.8
150.6
2,062.9
89.4
62.6
346.3
1,434.1
91.9
38.5
0.2
4,826.9
1,753.8
5.4
8.1
229.5
-
1,510.0
0.8
1,049.5
254.5
152.3
461.2
32.1
149.3
2,097.3
90.9
59.1
382.3
1,456.8
73.1
35.1
0.2
4,900.7
1,813.9
5.3
8.1
228.0
-
1,571.7
0.7
1,086.5
269.1
158.2
480.4
33.9
144.9
2,113.6
96.1
54.7
360.5
1,481.8
82.5
38.0
0.2
5,014.1
1,821.3
5.2
7.9
229.9
-
1,577.4
0.9
1,107.7
263.3
157.4
488.6
37.2
161.2
2,166.0
92.8
54.7
374.6
1,527.4
75.6
40.9
0.2
5,095.2
1,827.8
5.1
7.6
227.7
-
1,586.4
0.9
1,154.3
263.0
168.2
512.1
38.1
173.0
2,146.2
94.4
54.9
359.1
1,546.3
51.3
40.1
0.1
5,128.5
1,921.4
5.1
7.6
217.8
-
1,689.9
0.9
1,168.1
283.8
173.7
524.2
38.6
147.9
2,228.2
99.8
56.2
383.7
1,592.5
57.2
38.8
0.1
5,317.8
From 1995 to 1996, emissions from natural gas rose
only 1.2 percent, largely due to higher natural gas prices
in 1996 that reversed a 10 year long trend of declining
prices. The U.S. Department of Energy's Energy Infor-
mation Administration cited low levels of storage and
unusually cold weather as the two main reasons for this
price increase (EIA 1997e). Natural gas related emis-
sions from the residential sector rose by 7.9 percent while
the utility sector experienced a dramatic 14.6 percent
decrease. This sharp reduction can be explained by a 33
percent increase in the price of natural gas for utilities
(EIA 1997e). Increased consumption of natural gas ac-
counted for only 7.5 percent of the increase in fossil fuel
CO, emissions from 1995 to 1996.
End-Use Sector Contributions
The four end-use sectors contributing to CO2 emis-
sions from fossil fuel combustion include: industrial,
transportation, residential, and commercial. Electric utili-
ties also emit 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,
utility emissions have been distributed to each end-use
sector based upon their aggregate electricity consump-
tion. Emissions from utilities are addressed separately
after the end-use sectors have been discussed. Emissions
from U.S. territories are also calculated separately due
to a lack of end-use specific consumption data. Table
2-5 and Figure 2-4 summarize CO2 emissions from fos-
sil fuel combustion by end-use sector.
Energy 2-5
-------
Figure 2-4
1996 CO2 Emissions from Fossil Fuel
Combustion by End-Use Sector and Fuel Type
Natural Gm
Petroleum
»CMI
400
JUD
* Utilities also includes emissions of 0.04 MMTCE from
geothermal based electricity generation
Industrial End-Use Sector
The industrial end-use sector accounted for ap-
proximately one-third of CO2 emissions from fossil fuel
combustion. On average, nearly 64 percent of these emis-
sions resulted from the direct consumption of fossil fu-
els in order to meet industrial demand for steam and pro-
cess heat. The remaining 36 percent of industrial energy
needs was met by electricity for uses such as motors.
electric furnaces, ovens, and lighting.
Coal consumption by industry declined in 1996
from the previous year's levels. At coke plants, consump-
tion dropped by 3.9 percent. Consumption by other in-
dustries declined by 2.9 percent (EIA 1997b). Industrial
use of natural gas and petroleum were up in 1996 by 2.4
percent and 5.0 percent, respectively, from 1995 levels.
The industrial end-use sector was also the largest user
of fossil fuels for non-energy applications. Fossil fuels used
for producing fertilizers, plastics, asphalt, or lubricants can
sequester or store carbon in products for long periods of
time. Asphalt used in road construction, for example, stores
carbon essentially indefinitely. Similarly, fossil fuels used
in the manufacture of materials like plastics also store car-
bon, releasing it if the material is burned. Carbon stored by
industrial or transportation non-fuel uses of fossil fuels rose
18 percent between 1990 and 1996 (69.2 MMTCE and 81.7
MMTCE, respectively).
Transportation End-Use Sector
The transportation sector accounted for slightly
over 30 percent of U.S. CO2 emissions from fossil fuel
combustion. Virtually all of the energy consumed in this
sector came from petroleum-based products, with nearly
two-thirds resulting from gasoline consumption in auto-
mobiles and other on-road vehicles. Other uses, includ-
ing diesel fuel for the trucking industry and jet fuel for
aircraft, accounted for the remainder.
Following the overall trend in U. S. energy consump-
tion, fossil fuel combustion for transportation grew steadily
after declining in 1991, resulting in an increase in CO2 emis-
sions from 409.6 MMTCE (1,501.7 Tg) in 1990 to 445.5
MMTCE (1,633.5 Tg) in 1996. During this seven year pe-
riod, petroleum consumption—mainly motor gasoline, dis-
tillate fuel oil (e.g., diesel), and jet fuel—in the transporta-
tion end-use sector increased 8.5 percent. This increase
was slightly offset by decreases in the consumption of avia-
Table 2-5: CO Emissions from Fossil Fuel Combustion by End-Use Sector (MMTCE)*
End-Use Sector
1990
1991
1992
1993
1994
1995
1996
Residential
Commercial
Industrial
Transportation
U.S. Territories
Total
253.0
206.7
453.1
409.6
9.1
1331.4
257.0
206.4
441.6
400.8
10.7
1316.4
255.7
205.3
459.0
406.7
9.8
1336.6
271.6
212.2
459.0
414.1
10.6
1367.5
268.6
214.1
468.1
427.4
11.4
1389.6
269.7
219.2
465.7
432.8
11.2
1398.7
286.7
229.9
477.5
445.5
10.8
1450.3
* Emissions from fossil fuel combustion by electric utilities are allocated based on electricity consumption by each end-use sector.
Note: Totals may not sum due to independent rounding.
2-6
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Figure 2-5
32
m
it
= 14
• All
1194
Source: DOE/EIA-0384(96), Annual Energy Review 1996,
July, 1997, Table 3.13
tion gasoline and residual fuel. Overall, motor vehicle fuel
efficiency stabilized in the 1990s after increasing steadily
since 1977 (EIA 1997a). This trend is due, in part, to new
motor vehicle sales being increasingly dominated by less
fuel-efficient light-duty tracks and sport-utility vehicles (see
Figure 2-5). Moreover, declining petroleum prices during
these years—with the exception of 1996, when the average
price increased—combined with a stronger economy, were
Figure 2-6
1,600
1.IWI
1,200
1,000
Boa
tea
4O3
Clhcr V
19M
1891
1992
t»3
1*94
* "Other Vehicles" includes heavy duty gas vehicles, diesel passenger cars,
light duty diesel trucks, and motorcycles
Source: EPA/OAQPS
Important Note: There is a discontinuity in the VMT data starting in 1994.
Before 1994, vans, minivans, and sport utility vehicles were included in the
passenger car category. Beginning in 1994, all three vehicle types (passenger
or cargo) were included in the light duty truck category.
largely responsible for an overall increase in vehicle miles
traveled by on-road vehicles (see Figure 2-6).
Table 2-6 provides a detailed breakdown of CO2
emissions by fuel category and vehicle type for the trans-
portation end-use sector. On average 60 percent of the
emissions from this end-use sector 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, each accounting for, on av-
erage, 13 percent of CO2 emissions from the transporta-
tion end-use sector. It should be noted that the U.S. De-
partment of Transportation's Federal Highway Adminis-
tration altered its definition of light-duty trucks in 1995
to include sport utility vehicles and minivans; previously
these vehicles were included under the passenger cars
category. As a consequence of this reclassification, a
discontinuity exists in the time series in Table 2-6 for
both passenger cars and light-duty trucks.
Residential and Commercial End-Use Sectors
From 1990 to 1996, the residential and commer-
cial end-use sectors, on average, accounted for 19 and
16 percent, respectively, of CO2 emissions from fossil
fuel combustion. Unlike in other major end-use sectors,
emissions from the residential end-use sec-
tor did not decline in 1991, but they did de-
crease in 1992 and 1994, then grew steadily
through 1996. Both end-use sectors were
heavily reliant on electricity for meeting en-
ergy needs, with about two-thirds of their
emissions attributable to electricity consump-
tion for lighting, heating, cooling, and oper-
ating appliances. The remaining emissions
were largely due to the direct consumption
of natural gas and petroleum products, pri-
marily for heating and cooking needs.
Natural gas consumption in the resi-
dential and commercial end-use sectors in-
creased in 1996 by 7.6 and 3.3 percent, re-
spectively. This increase is attributed to
record low temperatures at the start of 1996
and new consumers in the natural gas mar-
ket (EIA 1997e). Petroleum consumption
increased about 6 and 2 percent from 1995
Energy 2-7
-------
Table 2-6: CO Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (MMTCE)
Fuel/Vehicle Type
1990
1991
1992
1993
1994
1995
1996
Motor Gasoline
Passenger Cars*
Light-Duty Trucks*
Other Trucks
Motorcycles
Buses
Construction Equipment
Agricultural Machinery
Boats (Recreational)
Distillate Fuel Oil (Diesel)
Passenger Cars*
Light-Duty Trucks*
Other Trucks
Buses
Construction Equipment
Agricultural Machinery
Boats (Freight)
Locomotives
Jet Fuel
General Aviation
Domestic Carriers
International Carriers
Military Aircraft
Aviation Gasoline
General Aviation
Residual Fuel Oil
Boats (Freight)
Natural Gas
Passenger Cars*
Light-Duty Trucks*
Buses
Pipeline
LPG
Light-Duty Trucks*
Other Trucks
Buses
Electricity
Buses
Locomotives
Pipeline
Lubricants
Total
260.9
167.3
74.9
11.3
0.4
0.6
0.6
1.2
4.6
73.4
2.0
2.5
45.3
2.2
2.9
6.4
5.0
7.3
55.0
1.7
32.0
5.1
16.3
0.8
0.8
6.7
6.7
9.8
+
+
+
9.8
0.4
0.1
0.2
+
0.7
+
0.1
0.6
1.8
409.6
259.5
165.9
74.7
11.2
0.4
0.6
0.6
1.2
4.8
70.5
1.9
2.4
43.3
2.2
2.9
6.3
4.8
6.7
53.0
1.5
29.6
5.1
16.9
0.8
0.8
5.5
5.5
8.9
+
+
+
8.9
0.3
0.1
0.2
+
0.7
+
0.1
0.5
1.6
400.8
263.4
170.0
74.6
11.2
0.4
0.6
0.6
1.2
4.7
73.4
2.0
2.5
45.1
2.3
2.9
6.4
5.1
7.3
52.3
1.3
30.5
5.3
15.2
0.8
0.8
5.5
5.5
8.8
+
+
+
8.8
0.3
0.1
0.2
+
0.7
+
0.1
0.5
1.6
406.7
269.3
171.5
77.8
11.7
0.5
0.7
0.6
2.0
4.6
75.2
2.0
2.6
47.7
2.3
2.9
6.4
4.6
6.6
52.7
1.3
30.9
5.3
15.2
0.7
0.7
4.2
4.2
9.3
+
+
+
9.2
0.3
0.1
0.2
+
0.7
+
0.1
0.5
1.6
414.1
273.7
170.5
84.2
10.4
0.5
0.9
0.6
2.1
4.5
80.4
2.0
2.8
51.7
2.3
2.9
6.3
4.6
7.8
54.9
1.2
32.0
5.5
16.1
0.7
0.7
4.6
4.6
10.2
+
+
+
10.1
0.5
0.2
0.3
+
0.7
+
0.1
0.5
1.7
427.4
279.9
158.1
101.3
10.9
0.5
0.8
0.7
2.2
5.3
81.8
1.8
3.3
52.7
2.7
2.8
6.2
4.3
8.0
54.2
1.4
32.8
5.7
14.3
0.7
0.7
2.9
2.9
10.4
+
+
+
10.4
0.5
0.3
0.3
+
0.7
+
0.1
0.5
1.7
432.8
285.5
161.3
103.4
11.2
0.5
0.8
0.7
2.2
5.4
86.1
1.9
3.4
55.5
2.8
3.0
6.5
4.6
8.4
56.7
1.5
34.2
6.0
15.0
0.7
0.7
3.1
3.1
10.5
+
+
+
10.5
0.6
0.3
0.3
+
0.7
+
0.1
0.5
1.6
445.5
Note: Totals may not sum due to independent rounding.
+ Does not exceed 0.05 MMTCE
In 1995, the U.S. Federal Highway Administration modified the definition of light-duty trucks to include minivans and sport utility vehicles.
Previously, these vehicles were included under the passenger cars category. Hence the sharp drop in emissions for passenger cars from
1994 to 1995 was observed. This gap, however, was offset by an equivalent rise in emissions from light-duty trucks.
to 1996 in the residential and commercial end-use sec-
tors, respectively. Coal consumption was a small com-
ponent of energy use in these end-use sectors.
Electric Utilities
As one of the largest consumers of fossil fuels in
the United States (averaging 28 percent of national fos-
sil fuel consumption and 88 percent of coal consump-
tion on an energy content basis), electric utilities were
collectively the largest producers of U.S. CO2 emissions,
accounting for 35 percent. The United States relies on
electricity to meet a significant portion of its energy re-
quirements for uses such as lighting, heating, electric
motors, and air conditioning. Because electric utilities
2-8
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
consume such a substantial portion of U.S. fossil fuels to
generate this electricity, the type of fuel they use has a
significant effect national CO2 emissions. Some of this
electricity was generated with the lowest CO2 emitting
energy technologies, particularly non-fossil options such
as hydropower or nuclear energy; however, electric utili-
ties still accounted for 88 percent of all coal consumed
in the United States in 1996. Consequently, changes in
electricity demand have a significant impact on coal con-
sumption and associated CO2 emissions.
The combustion of coal was used to generate 57
percent of the electricity consumed in the United States
in 1996, up from 55 percent in 1995 (EIA 1997f). From
1990 to 1996, coal emissions from utilities increased 12.7
percent. This increase in coal-related emissions from
utilities was alone responsible for 56 percent of the over-
all rise in CO2 emissions from fossil fuel combustion.
Balancing the increased consumption of coal by
utilities, their consumption of natural gas declined in 1996
due to rising gas prices relative to coal and petroleum
(EIA 1997a). Utility natural gas use increased signifi-
cantly in 1994 and 1995, as the natural gas industry sta-
bilized following a series of cold winters and a period of
industry restructuring. However, in 1996 utility gas prices
increased by a dramatic 33 percent (EIA 1997a), mak-
ing gas-based electricity generation less economical.
Consequently, natural gas consumption by electric utili-
ties declined by 15 percent in 1996. Utilities compen-
sated primarily by burning more coal, emissions from
which increased by 6.5 percent from 1995 to 1996. Pe-
troleum constitutes only a small portion of utility fossil
fuel consumption (3.4 percent in 1996, occurring mostly
in the eastern United States).
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. methodol-
ogy is presented in Annex A, and is characterized by the
following five steps:
1. Determine fuel consumption by fuel type and end-
use sector. By aggregating consumption data by end-
use sector (e.g., commercial, industrial, etc.), pri-
mary fuel type (e.g., coal, oil, gas), and secondary
fuel category (e.g., gasoline, distillate fuel, etc.), es-
timates of total U.S. energy consumption for a par-
ticular year were made.2
2. Determine the total carbon content of fuels con-
sumed. Total carbon was estimated by multiplying
the amount of fuel consumed by the amount of car-
bon in each fuel. This total carbon estimate defines
the maximum amount of carbon that could poten-
tially be released to the atmosphere if all of the car-
bon were converted to CO2. The carbon emission
coefficients used by the United States are presented
in Annex A.
3. Subtract the amount of carbon stored in products.
Non-fuel uses of fossil fuels can result in storage of
some or all of the carbon contained in the fuel for
some period of time, depending on the end-use. For
example, asphalt made from petroleum can seques-
ter up to 100 percent of the carbon for extended pe-
riods of time, while other products, such as lubri-
cants or plastics, lose or emit some carbon when they
are used and/or burned as waste. The amount of
carbon sequestered or stored in non-energy uses of
fossil fuels was based on the best available data on
the end-uses and ultimate fate of the various energy
products. These non-energy uses occurred in the
industrial and transportation end-use sectors. Car-
bon sequestered by these uses was 69 MMTCE in
1990, rising to 82 MMTCE in 1996.
4. Adjust for carbon that does not oxidize during com-
bustion. 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 or other by-products of inef-
ficient combustion. The estimated amount of carbon
not oxidized due to inefficiencies during the combus-
tion process ranged from 1 percent for petroleum and
coal to 0.5 percent for natural gas (see Annex A).
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 about 11 MMTCE of emissions in 1995 and 1996.
Energy 2-9
-------
5. Subtract emissions from international bunker fuels.
According to the IPCC guidelines (IPCC/UNEP/
OECD/IEA 1997) emissions from international
transport activities, or bunker fuels, should not be
included in national totals. Because U.S. energy con-
sumption statistics include these bunker fuels—pri-
marily residual oil—as part of consumption by the
transportation end-use sector, emissions from this
source were calculated separately and subtracted.
The calculations for emissions from bunker fuels
follows 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).
Carbon dioxide emissions from international bun-
kers were 22.7 MMTCE (83.4 Tg) in 1990, rising to
24.9 MMTCE (91.3 Tg) in 1992 and then declining
to 22.5 MMTCE (82.4 Tg) in 1996.
6. Allocate transportation emissions by vehicle type.
Because the transportation end-use sector was the
largest direct consumer of fossil fuels in the United
States, a more detailed accounting of carbon diox-
ide emissions is provided. Fuel consumption data
by vehicle type and transportation mode were used
to allocate emissions by fuel type calculated for the
transportation end-use sector. Specific data by ve-
hicle type were not available for 1996; therefore, the
1995 percentage allocations were applied to 1996
fuel consumption data in order to estimate emissions
in 1996. Military aircraft jet fuel consumption was
assumed to account for the difference between total
U. S. jet fuel consumption (as reported by DOE/EIA)
and civilian airline consumption (as reported by
DOT/BTS).
Data Sources
Fuel consumption, carbon content of fuels, and
percent of carbon sequestered in non-fuel uses data were
obtained directly from the Energy Information Adminis-
tration (EIA) of the U.S. Department of Energy (DOE).
Fuel consumption data were obtained primarily from the
Monthly Energy Review (EIA 1997d). IPCC (IPCC/
UNEP/OECD/IEA 1997) provided combustion efficiency
rates for petroleum and natural gas. Bechtel (1993) pro-
vided the combustion efficiency rates for coal. Vehicle
type fuel consumption data was taken from the Trans-
portation Energy Databook prepared by the Center for
Transportation Analysis at Oak Ridge National Labora-
tory (DOE 1993, 1994, 1995, 1996, 1997).
For consistency of reporting, the IPCC has recom-
mended that national inventories report energy data (and
emissions from energy) using the International Energy
Agency (IEA) reporting convention and/or IEA data.
Data in the IEA format are presented "top down"—that
is, energy consumption for fuel types and categories are
estimated from energy production data (accounting for
imports, exports, stock changes, and losses). The result-
ing 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 na-
tional totals.
Uncertainty
For estimates of CO2 from fossil fuel combustion,
the amount of CO2 emitted, in principle is directly re-
lated 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 consump-
tion by fuel type, average carbon contents of fossil fuels
consumed, and consumption of products with long-term
carbon storage should yield an accurate estimate of CO2
emissions.
There are uncertainties, however, concerning the
consumption data sources, carbon content of fuels and
products, and combustion efficiencies. For example,
given the same primary fuel type (e.g., coal), the amount
of carbon contained in the fuel per unit of useful energy
can vary. Non-energy uses of the fuel can also create
situations where the carbon is not emitted to the atmo-
sphere (e.g., plastics, asphalt, etc.) or is emitted at a much
delayed rate. The proportions of fuels used in these non-
fuel production processes that result in the sequestration
of carbon have been assumed. Additionally, inefficien-
cies in the combustion process, which can result in ash
2-10
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
or soot remaining unoxidized for long periods, were also
assumed. These factors all contribute to the uncertainty
in the CO2 estimates. For the United States, however,
these uncertainties are believed to be relatively small.
U.S. CO2 emission estimates from fossil fuel combus-
tion are considered accurate within one or two percent.
See, for example, Marland and Pippin (1990).
Stationary Source Fossil Fuel
Combustion (excluding C02)
Stationary sources encompass all fossil fuel com-
bustion activities except transportation (i.e., mobile com-
bustion). Other than carbon dioxide (CO2), which was
addressed in the previous section, gases from stationary
combustion include the greenhouse gases methane (CH4)
and nitrous oxide (N2O) and the criteria pollutants nitro-
gen oxides (NOx), carbon monoxide (CO), and non-meth-
ane volatile organic compounds (NMVOCs). Emissions
of these gases from stationary sources depend upon fuel
characteristics, technology type, usage of pollution con-
trol equipment, and ambient environmental conditions.
Emissions also vary with the size and vintage of the com-
bustion technology as well as maintenance and opera-
tional practices.
Stationary combustion is a small source of CH4 and
N2O in the United States. Methane emissions from sta-
tionary combustion in 1996 accounted for less than 2
percent of total U.S. CH4 emissions, while N2O emis-
sions from stationary combustion accounted for just un-
der 4 percent of all N2O emissions. Emissions of CH4
increased slightly (from 2.3 to 2.5 MMTCE) over the
period 1990 to 1996, due mainly to an increase in resi-
dential wood use. Nitrous oxide emissions rose 9 per-
cent from 3.7 MMTCE in 1990 to 4.0 MMTCE in 1996.
The largest source of N2O emissions was coal combus-
tion by electric utilities, which alone accounted for 55
percent of total N2O emissions from stationary combus-
tion in 1996.
Nitrous oxide and NOx emissions from stationary
combustion are closely related to air-fuel mixes and com-
bustion temperatures, as well as the characteristics of any
pollution control equipment that is employed. Carbon
monoxide emissions from stationary combustion are gen-
erally a function of the efficiency of combustion and the
use of emission controls; they are highest when less oxy-
gen is present in the air-fuel mixture than is necessary
for complete combustion. These conditions are most
likely to occur during start-up and shut-down 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 be-
lieved to be a function of the CH4 content of the fuel and
post-combustion controls.
In general, stationary combustion was a significant
source of NOx and CO emissions, and a smaller source
of NMVOCs. In 1996, emissions of NOx from station-
ary combustion represented 45 percent of national NOx
emissions, while CO and NMVOC emissions from sta-
tionary combustion contributed approximately 7 and 6
percent, respectively, to the national totals for the same
year. From 1990 to 1996, emissions of NOx decreased
by 4 percent, while emissions of CO and NMVOCs in-
creased by 8 and 7 percent, respectively.
The increase in CO and NMVOC emissions from
1990 to 1996 can largely be attributed to increased resi-
dential wood consumption, which is the most significant
source of these pollutants in the Energy sector. A com-
bination of technological advances and more stringent
emissions requirements dampened the rate of increase in
these emissions. Overall, NOx emissions from energy
varied due to fluctuations in emissions from electric utili-
ties, which constituted 58 percent of stationary NOx emis-
sions in 1996. Table 2-7, Table 2-8, Table 2-9, and Table
2-10 provide CH4 and N2O emission estimates from mo-
bile sources by vehicle type, fuel type, and transport ac-
tivity. Estimates of NO , CO, and NMVOC emissions in
•> x^ ?
1996 are given in Table 2-11.3
Methodology
Methane and nitrous oxide emissions were esti-
mated by multiplying emission factors (by sector and fuel
type) by fossil fuel and wood consumption data. Green-
house gas emissions from stationary combustion activi-
See Annex B for a complete time series of criteria pollutant emission estimates for 1990 through 1996.
Energy 2-11
-------
Table 2-7: CH Emissions from Stationary Sources (MMTCE)
Sector/Fuel Type
Electric Utilities
Coal
Fuel Oil
Natural gas
Wood
Industrial
Coal
Fuel Oil
Natural gas
Wood
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Residential
Coal
Fuel Oil
Natural Gas
Wood
Total
+ Does not exceed 0.05 MMTCE
Note: Totals may not sum due to
1990
0.1
0.1
+
+
+
0.7
0.2
0.1
0.2
0.3
0.2
+
0.1
0.1
+
1.3
0.1
0.1
0.1
0.9
2.3
independent
1991
0.1
0.1
+
+
+
0.7
0.1
0.1
0.2
0.2
0.2
+
+
0.1
+
1.3
0.1
0.1
0.1
1.0
2.3
rounding.
Table 2-8: N20 Emissions from Stationary Sources
Sector/Fuel Type
Electric Utilities
Coal
Fuel Oil
Natural gas
Wood
Industrial
Coal
Fuel Oil
Natural gas
Wood
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Residential
Coal
Fuel Oil
Natural Gas
Wood
Total
+ Does not exceed 0.05 MMTCE
Note: Totals may not sum due to
1990
2.0
1.9
0.1
+
+
1.3
0.3
0.4
0.1
0.5
0.1
+
+
+
+
0.3
+
0.1
+
0.2
3.7
independent
1991
2.0
1.9
0.1
+
+
1.3
0.3
0.4
0.1
0.5
0.1
+
+
+
+
0.3
+
0.1
+
0.2
3.7
rounding.
1992
0.1
0.1
+
+
+
0.7
0.1
0.1
0.2
0.3
0.2
+
+
0.1
+
1.4
0.1
0.1
0.1
1.1
2.4
(MMTCE)
1992
2.0
1.9
+
+
+
1.3
0.3
0.4
0.1
0.5
0.1
+
+
+
+
0.3
+
0.1
+
0.2
3.7
1993
0.1
0.1
+
+
+
0.8
0.1
0.1
0.3
0.3
0.2
+
+
0.1
0.1
1.2
0.1
0.1
0.1
0.9
2.3
1993
2.1
2.0
0.1
+
+
1.3
0.3
0.4
0.1
0.5
0.1
+
+
+
+
0.3
+
0.1
+
0.2
3.8
1994
0.1
0.1
+
+
+
0.8
0.1
0.1
0.3
0.3
0.2
+
+
0.1
0.1
1.2
0.1
0.1
0.1
0.9
2.3
1994
2.1
2.0
+
+
+
1.4
0.3
0.5
0.1
0.5
0.1
+
+
+
+
0.3
+
0.1
+
0.2
3.8
1995
0.1
0.1
+
+
+
0.8
0.1
0.1
0.3
0.3
0.2
+
+
0.1
0.1
1.3
0.1
0.1
0.1
1.0
2.4
1995
2.1
2.0
+
+
+
1.4
0.3
0.4
0.1
0.5
0.1
+
+
+
+
0.3
+
0.1
+
0.2
3.8
1996
0.1
0.1
+
+
+
0.8
0.1
0.1
0.3
0.3
0.2
+
+
0.1
0.1
1.3
0.1
0.1
0.1
1.0
2.5
1996
2.2
2.1
+
+
+
1.4
0.3
0.5
0.1
0.6
0.1
+
+
+
+
0.3
+
0.1
+
0.2
4.0
2-12
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 2-9: CH Emissions from Stationary Sources (Gg)
Sector/Fuel Type
1990
1991
1992
1993
1994
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding.
Table 2-10: NO Emissions from Stationary Sources (Gg)
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding.
1995
1996
Electric Utilities
Coal
Fuel Oil
Natural gas
Wood
Industrial
Coal
Fuel Oil
Natural gas
Wood
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Residential
Coal
Fuel Oil
Natural Gas
Wood
Total
23
16
4
3
+
129
27
17
40
44
31
1
9
13
9
218
19
13
21
166
401
23
16
4
3
+
126
26
16
41
44
31
1
9
13
9
227
17
13
22
175
407
22
16
3
3
+
130
25
17
43
45
31
1
8
14
9
237
17
13
23
184
420
23
17
3
3
+
132
25
17
45
46
35
1
8
14
13
211
17
14
24
156
402
23
17
3
3
+
136
25
18
46
48
35
1
8
14
13
207
17
13
24
153
401
22
17
2
3
+
138
24
17
48
48
36
1
8
15
13
223
16
14
24
170
420
23
18
2
3
+
142
23
18
49
51
38
1
8
16
14
226
16
14
26
170
429
Sector/Fuel Type
Electric Utilities
Coal
Fuel Oil
Natural gas
Wood
Industrial
Coal
Fuel Oil
Natural gas
Wood
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Residential
Coal
Fuel Oil
Natural Gas
Wood
Total
1990
24
23
1
+
+
16
4
5
1
6
1
+
1
+
+
3
+
1
+
2
44
1991
23
22
1
+
+
15
4
5
1
6
1
+
1
+
+
4
+
1
+
2
43
1992
24
23
1
+
+
16
3
5
1
6
1
+
+
+
+
4
+
1
+
2
44
1993
25
24
1
+
+
16
3
5
1
6
1
+
+
+
+
3
+
1
+
2
45
1994
25
24
1
+
+
16
3
5
1
6
1
+
+
+
+
3
+
1
+
2
45
1995
25
24
+
+
+
16
3
5
1
6
1
+
+
+
+
4
+
1
+
2
45
1996
26
25
+
+
+
17
3
6
1
7
1
+
+
+
+
4
+
1
1
2
47
Energy 2-13
-------
Table 2-11: 1996 Emissions of N0x, CO, and NMVOC from
Stationary Sources (Gg)
Sector/Fuel Type
NO
CO
NMVOCs
Electric Utilities
Coal
Fuel Oil
Natural gas
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Residential
Coal"
Fuel Oilb
Natural Gas"
Wood
Other Fuels3
Total
5,473
5,004
87
244
NA
137
2,875
543
223
1,212
NA
113
784
366
35
93
212
NA
26
804
NA
NA
NA
44
760
9,518
341
238
10
40
NA
53
972
90
65
316
NA
277
224
227
14
17
49
NA
148
3,866
NA
NA
NA
3,621
244
5,407
41
28
3
2
NA
9
188
5
11
66
NA
46
60
21
1
3
10
NA
8
724
NA
NA
NA
687
37
975
NA (Not Available)
Note: Totals may not sum due to independent rounding. See Annex B for
emissions in 1990 through 1995.
" "Other Fuels" include LPG, waste oil, coke oven gas, coke, and non-
residential wood (EPA 1997).
" Coal, fuel oil, and natural gas emissions are included in the "Other Fuels"
category (EPA 1997).
ties were grouped into four sectors: industrial, commer-
cial/institutional, residential, and electric utilities. For
CH4 and N2O, estimates were based on consumption of
coal, natural gas, fuel oil, and wood.
For NOx, CO, and NMVOCs, the major source cat-
egories included in this section are those used in EPA
(1997): coal, fuel oil, natural gas, wood, other fuels (in-
cluding LPG, coke, coke oven gas, and others), and sta-
tionary internal combustion. The EPA also 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 indi-
vidual 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 consump-
tion, fuel deliveries, tons of refuse burned, raw
material processed, etc.
The EPA derived the overall emission con-
trol efficiency of a source category from published
reports, the 1985 National Acid Precipitation and
Assessment Program (NAPAP) emissions inven-
tory, and other EPA databases. The U.S. approach
for estimating emissions of NOx, CO, and
NMVOCs from stationary source combustion, as
described above, is similar to the methodology
recommendedby the IPCC (IPCC/UNEP/OECD/
PEA 1997).
More detailed information on the meth-
odology for calculating emissions from station-
ary sources including emission factors and ac-
tivity data is provided in Annex B.
Data Sources
Emissions estimates for NOx, CO, and
NMVOCs in this section were taken directly
from the EPA's National Air Pollutant Emis-
sions Trends: 1900 - 1996 (EPA 1997). U.S.
energy data were provided by the U.S. Energy
Information Administration's Monthly Energy
Review (EIA 1997). Emission factors were pro-
vided by the Revised 1996 IPCC Guidelines
for National Greenhouse Gas Inventories
(IPCC/UNEP/OECD/IEA 1997).
Uncertainty
Methane emission estimates from stationary
sources are highly uncertain, primarily due to difficul-
ties in calculating emissions from wood combustion (i.e.,
fireplaces and wood stoves). The estimates of CH4 and
N2O emissions presented are based on broad indicators
of emissions (i.e., fuel use multiplied by an aggregate
emission factor for different sectors), rather than specific
emission processes (i.e., by combustion technology and
type of emission control). The uncertainties associated
with the emission estimates of these gases are greater
than with estimates of CO2 from fossil fuel combustion,
which are mainly a function of the carbon content of the
fuel combusted. Uncertainties in both CH4 and N2O es-
2-14
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
timates are due to the fact that emissions are estimated
based on emission factors representing only a limited
subset of combustion conditions. For the criteria pollut-
ants, uncertainties are partly due to assumptions concern-
ing combustion technology types, age of equipment,
emission factors used, and projections of growth.
Mobile Source Fossil Fuel
Combustion (excluding C02)
Mobile sources emit greenhouse gases other than
CO2, including methane (CH4), nitrous oxide (N2O), and
the criteria pollutants carbon monoxide (CO), nitrogen
oxides (NOx), and non-methane volatile organic com-
pounds (NMVOCs).
As with combustion in stationary sources, N2O and
NOx emissions are closely related to fuel characteristics,
air-fuel mixes, and 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 and CO emissions. Carbon monoxide
emissions from mobile source combustion are signifi-
cantly affected by combustion efficiency and presence
of post-combustion emission controls. Carbon monox-
ide emissions are highest when air-fuel mixtures have
less oxygen than required for complete combustion. This
occurs especially in idle, low speed and cold start condi-
tions. Methane and NMVOC emissions from motor ve-
hicles are a function of the CH4 content of the motor
fuel, the amount of hydrocarbons passing uncombusted
through the engine, and any post-combustion control of
hydrocarbon emissions, such as catalytic converters.
Emissions from mobile sources were estimated by
transport mode (e.g., road, air, rail, and water) and fuel
type—motor gasoline, diesel fuel, jet fuel, aviation gas,
natural gas, liquefied petroleum gas (LPG), and residual
fuel oil—and vehicle type. Road transport accounted for
the majority of mobile source fuel consumption, and hence,
the majority of mobile source emissions. Table 2-12, Table
2-13, Table 2-14, and Table 2-15 provide CH4 and N2O
emission estimates from mobile sources by vehicle type,
fuel type, and transport mode. Estimates of NOx, CO, and
NMVOC emissions in 1996 are given in Table 2-16.4
Mobile sources were responsible for a small por-
tion of national CH4 emissions but were the second larg-
est source of N2O in the United States. From 1990 to
1996, CH4 emissions declined by 7 percent, to 1.4
MMTCE. Nitrous oxide emissions, however, rose from
13.2 to 16.5 MMTCE (a 25 percent increase). The rea-
son for this conflicting trend was that the control tech-
nologies employed on highway vehicles in the United
States lowered CO, NO , NMVOC, and CH, emissions,
' x> > 4 '
but resulted in higher N2O emission rates. Fortunately,
since 1994 improvements in the emission control tech-
nologies installed on new vehicles have reduced emis-
sion rates of both NOx and N2O per vehicle mile trav-
eled. Overall, CH4 and N2O emissions were dominated
by gasoline-fueled passenger cars and light-duty gaso-
line trucks. From 1995 to 1996, both CH4 and N2O emis-
sions were almost constant (see Figure 2-7).
Emissions of criteria pollutants as a whole increased
from 1990 through 1994, after which there was a slight de-
crease through 1996. A drop in gasoline prices combined
with a strengthening U.S. economy caused the initial in-
crease. These factors pushed the vehicle miles traveled
(VMT) by road sources up, resulting in increased fuel con-
sumption and higher emissions. Some of this increased
activity was offset by an increasing portion of the U.S. ve-
hicle fleet meeting established emissions standards.
Figure 2-7
CH,
lift
See Annex C for a complete time series of criteria pollutant emission estimates for 1990 through 1996.
Energy 2-15
-------
Table 2-12: CH4 Emissions from Mobile Sources (MMTCE)
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Boats and Vessels
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
1990
1.3
0.8
0.4
0.1
+
0.1
+
+
0.1
0.1
0.1
+
+
+
+
+
1.5
1991
1.2
0.7
0.4
0.1
+
0.1
+
+
0.1
0.1
0.1
+
+
+
+
+
1.4
1992
1.2
0.7
0.4
0.1
+
0.1
+
+
0.1
0.1
0.1
+
+
+
+
+
1.4
1993
1.2
0.7
0.4
0.1
+
0.1
+
+
0.1
0.1
+
+
+
+
+
+
1.4
1994
1.2
0.7
0.4
0.1
+
0.1
+
+
0.1
0.1
+
+
+
+
+
+
1.4
1995
1.2
0.7
0.4
0.1
+
0.1
+
+
0.1
0.1
+
+
+
+
+
+
1.4
1996
1.2
0.6
0.4
0.1
+
0.1
+
+
0.1
0.1
+
+
+
+
+
+
1.4
+ Does not exceed 0.05 MMTCE
Note: Totals may not sum due to independent rounding.
* "Other" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty
diesel powered utility equipment.
Table 2-13: NO Emissions from Mobile Sources (MMTCE)
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Boats and Vessels
Locomotives
Farm Equipment
Construction Equipment
Aircraft3
Other"
Total
1990
12.3
8.6
3.4
0.2
+
0.5
+
+
0.5
0.5
0.2
0.1
0.1
+
+
+
13.2
1991
12.9
9.0
3.7
0.2
+
0.5
+
+
0.5
0.5
0.2
0.1
0.1
+
+
+
13.9
1992
13.8
9.7
3.9
0.2
+
0.5
+
+
0.5
0.5
0.2
0.1
0.1
+
+
+
14.8
1993
14.6
10.1
4.2
0.3
+
0.5
+
+
0.5
0.4
0.2
0.1
0.1
+
+
+
15.6
1994
15.3
9.9
5.1
0.3
+
0.6
+
+
0.5
0.4
0.2
0.1
0.1
+
+
+
16.3
1995
15.6
10.1
5.2
0.3
+
0.6
+
+
0.5
0.4
0.2
0.1
0.1
+
+
+
16.6
1996
15.5
10.0
5.1
0.3
+
0.6
+
+
0.5
0.4
0.2
0.1
0.1
+
+
+
16.5
+ Does not exceed 0.05 MMTCE
Note: Totals may not sum due to independent rounding.
' Aircraft emissions include aviation gasoline combustion and exclude jet fuel combustion due to insufficient data availability.
" "Other" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty
diesel powered utility equipment.
2-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 2-14: CH Emissions from Mobile Sources (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
Non-Highway
Boats and Vessels
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
1990
220
133
67
16
4
10
+
+
10
25
9
3
6
1
6
1
255
1991
214
128
66
16
4
10
+
+
10
25
10
2
5
1
6
1
250
1992
211
127
65
15
4
10
+
+
10
26
10
3
6
1
6
1
248
1993
209
123
66
16
4
11
+
+
10
23
8
2
5
1
5
1
244
1994
211
115
75
17
4
11
+
+
11
24
8
2
6
1
5
1
246
1995
209
114
74
17
4
11
+
+
11
24
9
3
6
1
5
1
244
1996
203
111
71
16
4
12
+
+
11
24
8
3
6
1
6
1
238
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding.
* "Other" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty
diesel powered utility equipment.
Table 2-15: N20 Emissions from Mobile Sources (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
Non-Highway
Boats and Vessels
Locomotives
Farm Equipment
Construction Equipment
Aircraft3
Other"
Total
1990
145
102
41
2
+
6
+
+
5
5
3
1
1
+
+
1
157
1991
153
107
44
3
+
6
+
+
5
6
3
1
1
+
+
+
165
1992
164
115
46
3
+
6
+
+
6
6
3
1
1
+
+
+
175
1993
173
120
50
3
+
6
+
+
6
5
2
1
1
+
+
+
184
1994
181
117
60
3
+
7
+
+
6
5
2
1
1
+
+
1
193
1995
184
119
61
4
+
7
+
+
6
5
3
1
1
+
+
+
196
1996
183
119
61
4
+
7
+
+
6
5
2
1
1
+
+
+
195
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding.
' Aircraft emissions includes aviation gasoline combustion and excludes jet fuel combustion due to insufficient data availability.
" "Other" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty
diesel powered utility equipment.
Energy 2-17
-------
Table 2-16: 1996 Emissions of N0x, CO, and NMVOC from
Mobile Sources (Gg)
Fuel Type/Vehicle Type
NO
CO
NMVOCs
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Boats and Vessels
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
4,752
3,075
1,370
295
12
1,753
35
9
1,709
4,183
244
836
1,012
1,262
151
678
10,688
46,712
29,883
13,377
3,267
185
1,318
30
7
1,280
15,424
1,684
102
901
1,066
861
10,810
63,455
4,709
2,979
1,435
259
35
283
12
4
267
2,201
460
44
207
184
161
1,144
7,192
Note: Totals may not sum due to independent rounding. See Annex C for
emissions in 1990 through 1995.
* "Other" includes gasoline powered recreational, industrial, lawn and garden,
light commercial, logging, airport service, other equipment; and diesel powered
recreational, industrial, lawn and garden, light construction, airport service.
Fossil-fueled motor vehicles comprise the single
largest source of CO emissions in the United States and
are a significant contributor to NOx and NMVOC emis-
sions. In 1996, CO emissions from mobile sources con-
tributed 83 percent of all U.S. CO emissions and 50 and
42 percent of NOx and NMVOC emissions, respectively.
Since 1990, emissions of CO and NMVOCs from mo-
bile sources decreased by 5 and 10 percent, respectively,
while emissions of NOx increased by 1 percent.
Methodology
Estimates for CH4 and N2O emissions from mobile
combustion were calculated by multiplying emission fac-
tors by measures of activity for each category. Depending
upon the category, activity data included such information
as fuel consumption, fuel deliveries, and vehicle miles trav-
eled (VMT). Emission estimates from highway vehicles
were based on VMT and emission factors by
vehicle type, fuel type, model year, and con-
trol technology. Fuel consumption data was
employed as a measure of activity for non-
highway vehicles and then fuel-specific emis-
sion factors were applied. A complete dis-
cussion of the methodology used to estimate
emissions from mobile sources is provided
in Annex C.
The EPA provided emissions esti-
mates of NOx, CO, and NMVOCs for eight
categories of highway vehicles5, aircraft,
and seven categories of off-highway ve-
hicles6.
Data Sources
Emission factors used in the calcula-
tions of CH4 and N2O emissions are pre-
sented in Annex C. TbsRevised 1996IPCC
Guidelines (IPCC/UNEP/OECD/IEA
1997) provided emission factors for CH4,
and were developed using MOBILESa, a
model used by the Environmental Protection Agency
(EPA) to estimate exhaust and running loss emissions
from highway vehicles. The MOBILESa model uses in-
formation on ambient temperature, vehicle speeds, na-
tional vehicle registration distributions, gasoline volatil-
ity, and other variables in order to produce these factors
(EPA 1997b).
Emission factors for N2O from gasoline highway
vehicles came from a recent EPA report (1998). This
report developed emission factors for older passenger cars
(roughly pre-1992 in California and pre-1994 in the rest
of the United States), from published references, and for
newer cars from a recent testing program at EPA's Na-
tional Vehicle and Fuel Emissions Laboratory (NVFEL).
These emission factors for gasoline highway vehicles are
lower than the U.S. default values in the Revised 1996
IPCC Guidelines, but are higher than the European de-
These categories included: gasoline passenger cars, diesel passenger cars, light-duty gasoline trucks less than 6,000 pounds in weight, light-
duty gasoline trucks between 6,000 and 8,500 pounds in weight, light-duty diesel trucks, heavy-duty gasoline trucks and buses, heavy-duty
diesel trucks and buses, and motorcycles.
These categories included: gasoline and diesel farm tractors, other gasoline and diesel farm machinery, gasoline and diesel construction
equipment, snowmobiles, small gasoline utility engines, and heavy-duty gasoline and diesel general utility engines.
2-18
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
fault values, both of which were published before the
more recent tests and literature review conducted by the
NVFEL. The U.S. default values in the Revised 1996
IPCC Guidelines were based on three studies that tested
a total of five cars using European rather than U.S. test
protocols. More details may be found in EPA (1998).
Emission factors for gasoline vehicles other than
passenger cars were scaled from those for passenger cars
with the same control technology, based on their relative
fuel economy. This scaling was supported by limited
data showing that light-duty trucks emit more N2O than
passenger cars with equivalent control technology. The
use of fuel-consumption ratios to determine emission
factors is considered a temporary measure only, to be
replaced as soon as additional testing data are available.
For more details, see U.S. EPA (1998). Nitrous oxide
emission factors for diesel highway vehicles were taken
from the European default values found in the Revised
1996IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).
There is little data addressing N2O emissions from U.S.
diesel-fueled vehicles, and in general, European coun-
tries have had more experience with diesel-fueled ve-
hicles. U.S. default values in the Revised 1996 IPCC
Guidelines were used for non-highway vehicles.
Activity data were gathered from several U.S. gov-
ernment sources including EIA (1997), FHWA (1997),
and FAA (1997). Control technology data for highway
vehicles were obtained from the EPA's Office of Mobile
Sources. Annual VMT data for 1990 through 1996 were
obtained from the Federal Highway Administration's
(FHWA) Highway Performance Monitoring System da-
tabase, as noted in EPA (1997a).
Emissions estimates for NO , CO, NMVOCs were
x? ^
taken directly from the EPA's National Air Pollutant
Emissions Trends, 1900 - 1996 (EPA 1997a).
Uncertainty
Mobile source emission estimates can vary signifi-
cantly due to assumptions concerning fuel type and com-
position, technology type, average speeds, type of emis-
sion control equipment, equipment age, and operating
and maintenance practices. Fortunately, detailed activ-
ity data for mobile sources were available, including VMT
by vehicle type for highway vehicles. The allocation of
this VMT to individual model years was done using the
profile of U.S. vehicle usage by vehicle age in 1990 as
specified in MOBILE 5a. Data to develop a temporally
variable profile of vehicle usage by model year instead
of age was not available.
Average emission factors were developed based on
numerous assumptions concerning the age and model of
vehicle; percent driving in cold start, warm start, and
cruise conditions; average driving speed; ambient tem-
perature; and maintenance practices. The factors for regu-
lated emissions from mobile sources—CO, NOx, and
hydrocarbons—have been extensively researched, and so
involve lower uncertainty than emissions of unregulated
gases. Although methane has not been singled out for
regulation in the United States, overall hydrocarbon emis-
sions from mobile sources—a component of which is
methane—are regulated.
Compared to methane, CO, NOx, and NMVOCs,
there is relatively little data available to estimate emis-
sion factors for nitrous oxide. Nitrous oxide is not a cri-
teria pollutant, and measurements of it in automobile ex-
haust have not been routinely collected. Research data
has shown that N2O emissions from vehicles with cata-
lytic converters are greater than those without emission
controls, and that vehicles with aged catalysts emit more
than new ones. The emission factors used were, there-
fore, derived from aged cars (EPA 1998). The emission
factors used for Tier 0 and older cars were based on tests
of 28 vehicles; those for newer vehicles were based on
tests of 22 vehicles. This sample is small considering
that it is being used to characterize the entire U.S. fleet,
and the associated uncertainty is therefore large. Cur-
rently, N2O gasoline highway emission factors for ve-
hicles other than passenger cars are scaled based on those
for passenger cars and their relative fuel economy. Ac-
tual measurements should be substituted for this proce-
dure when they become available. Further testing is
needed to reduce the uncertainty in emission factors for
all classes of vehicles, using realistic driving regimes,
environmental conditions, and fuels.
Emissions of N2O from the combustion of jet fuel
in aircraft were not estimated due to insufficient data
availability on the number of landing and take-off cycles
executed and cruising fuel consumption by specific type
Energy 2-19
-------
of aircraft. The estimates presented for N2O emissions
from aircraft include only the combustion of aviation
gasoline. Complete N2O emission estimates from air-
craft will be included in future inventories.
Overall, uncertainty for N2O emissions estimates is
considerably higher than for CH4, CO, NOx, or NMVOC;
however, all these gases involve far more uncertainty than
CO0 emissions from fossil fuel combustion.
Coal Mining
All underground and surface coal mining liberates
(i.e., releases) methane as part of normal operations. The
amount of methane liberated during mining is primarily
dependent upon the amount of methane stored in the coal
and the surrounding strata. This in situ methane content
is a function of the quantity of methane generated dur-
ing the coal formation process and its ability to migrate
through the surrounding strata over time. The degree of
coalification—defined by the rank or quality of the coal
formed—determines the amount of methane generated
during the coal formation process; higher ranked coals
generate more methane. The amount of methane that
remains in the coal and surrounding strata also depends
upon geologic characteristics such as pressure and tem-
perature within a coal seam. Deeper coal deposits tend
to retain more of the methane generated during coalifi-
cation. Accordingly, deep underground coal seams gen-
erally have higher methane contents than shallow coal
seams or surface deposits.
Underground, versus surface, coal mines contrib-
ute the largest share of methane emissions. All under-
ground coal mines employ ventilation systems to ensure
that methane levels remain within safe concentrations.
These systems exhaust significant amounts of methane
to the atmosphere in low concentrations. Additionally,
over twenty gassy U.S. coal mines supplement ventila-
tion with degasification systems. Degasification systems
are wells drilled from the surface or boreholes drilled
inside the mine that remove large volumes of methane
before or after mining. Currently, twelve coal mines col-
lect methane from degasification systems and sell this
gas to a pipeline, thus reducing emissions to the atmo-
sphere. Surface coal mines also release methane as the
overburden is removed and the coal is exposed. Addi-
tionally, after coal has been mined, small amounts of
methane retained in the coal are released during process-
ing, storage, and transport.
Total methane emissions in 1996 were estimated
to be 18.9 MMTCE (3.3 Tg), declining from 24.0
MMTCE (4.2 Tg) in 1990 (see Table 2-17 and Table 2-
18). Of this amount, underground mines accounted for
67 percent, surface mines accounted for 13 percent, and
post-mining emissions accounted for 20 percent. With
the exception of 1995, total methane emissions declined
every year during this period. In 1993, emissions from
underground mining dropped to a low of 2.8 Tg, prima-
rily due to labor strikes at many of the large underground
mines. In 1995, there was an increase in methane emis-
sions from underground mining (3.1 Tg) due to particu-
larly high emissions at the gassiest coal mine in the coun-
try. While methane liberated from underground mines
fluctuated from 1990 to 1996, the amount of methane
recovered and used increased. As a result, with the ex-
ception of 1995, total methane emitted from underground
mines declined in each year. Surface mine emissions
Table 2-17: Methane Emissions from Coal Mining (MMTCE)
Activity
1990
1991
1992
1993
1994
Note: Totals may not sum due to independent rounding.
1995
1996
Underground Mining
Liberated
Recovered & Used
Surface Mining
Post- Mining (Underground)
Post-Mining (Surface)
Total
17.1
18.8
(1.6)
2.8
3.6
0.5
24.0
16.4
18.1
(1.7)
2.6
3.4
0.4
22.8
15.6
17.8
(2.1)
2.6
3.3
0.4
22.0
13.3
16.0
(2.7)
2.5
3.0
0.4
19.2
13.1
16.3
(3.2)
2.6
3.3
0.4
19.4
14.2
17.7
(3.4)
2.4
3.3
0.4
20.3
12.6
16.5
(3.8)
2.5
3.4
0.4
18.9
2-20
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 2-18: Methane Emissions from Coal Mining (Tg)
Activity
1990
1991
1992
1993
1994
Note: Totals may not sum due to independent rounding.
1995
1996
Underground Mining
Liberated
Recovered & Used
Surface Mining
Post- Mining (Underground)
Post-Mining (Surface)
Total
3.0
3.3
(0.3)
0.5
0.6
0.1
4.2
2.9
3.2
(0.3)
0.4
0.6
0.1
4.0
2.7
3.1
(0.4)
0.4
0.6
0.1
3.8
2.3
2.8
(0.5)
0.4
0.5
0.1
3.4
2.3
2.8
(0.6)
0.5
0.6
0.1
3.4
2.5
3.1
(0.6)
0.4
0.6
0.1
3.6
2.2
2.9
(0.7)
0.4
0.6
0.1
3.3
and post-mining emissions remained relatively constant
from 1990 to 1996.
In 1994, EPA's Coalbed Methane Outreach Program
(CMOP) began working with the coal industry and other
stakeholders to identify and remove obstacles to investments
in coal mine methane recovery and use projects. Reduc-
tions attributed to CMOP were estimated to be 0.7,0.8, and
1.0 MMTCE in 1994, 1995, and 1996, respectively.
Methodology
The methodology for estimating methane emissions
from coal mining consists of two main steps. The first
step involved estimating methane emissions from under-
ground 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 involved
estimating emissions from surface mines and post-min-
ing activities by multiplying basin-specific coal produc-
tion by basin specific emissions factors.
Underground mines. Total methane emitted from un-
derground mines was estimated as the quantity of methane
liberated from ventilation systems, plus methane liberated
from degasification systems, minus methane recovered and
used. The Mine Safety and Heath Administration (MSHA)
measures methane emissions from ventilation systems for
all mines with detectable7 methane concentrations. These
mine-by-mine measurements were used to estimate meth-
ane emissions from ventilation systems.
Some of the gassier underground mines also use
degasification systems (e.g., wells or boreholes) that re-
move methane before or after mining . This methane
can then be collected for use orventedto the atmosphere.
Various approaches were employed to estimate the quan-
tity of methane collected by each of the more than twenty
mines using these systems, depending on available data.
For example, some mines have reported to EPA the
amounts of methane liberated from their degasification
systems. For mines that sell recovered methane to a pipe-
line, pipeline sales data was used to estimate
degasification emissions. Finally, for those mines for
which no other data was available, default recovery effi-
ciency values were developed, depending on the type of
degasification system employed.
Finally, the amount of methane recovered by
degasification systems and then used (i.e., not vented) was
estimated. This calculation was complicated by the fact
that methane is rarely recovered and used during the same
year in which the particular coal seam is mined. In 1996,
twelve coal mines sold recovered methane to a pipeline
operator. Emissions avoided for these projects were esti-
mated using gas sales data reported by various state agen-
cies, and information supplied by coal mine operators re-
garding the number of years in advance of mining that gas
recovery occurred. Additionally, some of the state agen-
cies provided individual well production information, which
was used to assign gas sales to a particular year.
Surface Mines and Post-Mining Emissions. Surface
mining and post-mining methane emissions were estimated
by multiply ing basin-specific coal production by basin-spe-
cific emissions factors. For surface mining, emissions fac-
tors were developed by assuming that surface mines emit
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.
Energy 2-21
-------
from one to three times as much methane as the average in
situ methane content of the coal. This accounts for meth-
ane released from the strata surrounding the coal seam. For
post-mining emissions, the emission factor was assumed to
be from 25 to 40 percent of the average in situ methane
content of coals mined in the basin.
Data Sources
The Mine Safety and Health Administration pro-
vided mine-specific information on methane liberated
from ventilation systems at underground mines. EPA
developed estimates of methane liberated from
degasification systems at underground mines based on
available data for each of the mines employing these sys-
tems. The primary sources of data for estimating emis-
sions avoided at underground mines were gas sales data
published by state petroleum and natural gas agencies
and information supplied by mine operators regarding
the number of years in advance of mining that gas recov-
ery occurred. Annual coal production data was taken
from the Energy Information Agency's Coal Industry
Annual (see Table 2-19) (EIA 1991, 1992, 1993, 1994,
1995, 1996, 1997). Data on in situ methane content and
emissions factors were taken from EPA (1993).
Uncertainty
Table 2-19: Coal Production (Thousand Metric Tons)
Year Underground Surface Total
1990
1991
1992
1993
1994
1995
1996
384,247
368,633
368,625
318,476
362,063
359,475
371,813
546,814
532,653
534,286
539,211
575,525
577,634
593,311
931,061
901,285
902,911
857,687
937,588
937,109
965,125
The emission estimates from underground venti-
lation systems were based upon actual measurement data
for mines with detectable methane emissions. Accord-
ingly, the uncertainty associated with these measurements
is estimated to be low. Estimates of methane liberated
from degasification systems are less certain because EPA
assigns default recovery efficiencies for a subset of U.S.
mines. Compared to underground mines, there is con-
siderably more uncertainty associated with surface min-
ing and post-mining emissions because of the difficulty
in developing accurate emissions factors from field mea-
surements. Because underground emissions comprise
the majority of total coal mining emissions, the overall
uncertainty is estimated to be only ±15 percent.8
Natural Gas Systems
Methane emissions from natural gas systems are
generally process related, with normal operations, rou-
tine maintenance, and system upsets being the primary
contributors. Emissions from normal operations include:
natural gas combusting engine and turbine exhaust, bleed
and discharge emissions from pneumatic devices, and
fugitive emissions from system components. Routine
maintenance emissions originate from pipelines, equip-
ment, and wells during repair and maintenance activi-
ties. Pressure surge relief systems and accidents can lead
to system upset emissions.
The U.S. natural gas system encompasses hundreds
of thousands of wells, hundreds of processing facilities,
hundreds of thousands of miles of transmission pipelines,
and over a million miles of distribution pipeline. The
system, though, canbe divided into four stages, each with
different factors affecting methane emissions, as follows:
Field Production. In this initial stage, wells are
used to withdraw raw gas from underground formations.
Emissions arise from the wells themselves, treatment fa-
cilities, gathering pipelines, and process units such as
dehydrators and separators. Fugitive emissions and emis-
sions from pneumatic devices accounted for the major-
ity of emissions. Emissions from field production have
increased absolutely and as a proportion of total emis-
sions from natural gas systems—approximately 27 per-
cent between 1990 and 1996—due to an increased num-
ber of producing gas wells and related equipment.
o
Preliminary estimate
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Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Processing. In this stage, processing plants remove
various constituents from the raw gas before it is injected
into the transmission system. Fugitive emissions from
compressors, including compressor seals, were the pri-
mary contributor from this stage. Processing plants ac-
counted for about 12 percent of methane emissions from
natural gas systems during the period of 1990 through
1996.
Transmission and Storage. Natural gas transmis-
sion involves high pressure, large diameter pipelines that
transport gas long distances from field production areas
to distribution centers or large volume customers. From
1990 to 1996, the reported length of the gas utility trans-
mission pipeline varied, with an overall decline from
about 280,000 miles to about 265,000 miles. Through-
out the transmission system, compressor stations pres-
surize the gas to move it through the pipeline. Fugitive
emissions from compressor stations and metering and
regulating stations accounted for the majority of the emis-
sions from transmission. Pneumatic devices and engine
exhaust were smaller sources of emissions from trans-
mission facilities. Methane emissions from the trans-
mission stage accounted for approximately 35 percent
of the emissions from natural gas systems. Natural gas
is also injected and stored in underground formations
during periods of low demand, and withdrawn, processed,
and distributed during periods of high demand. Com-
pressors and dehydrators were the primary contributors
from these storage facilities. Less than one percent of
total emissions from natural gas systems can be attrib-
uted to these facilities.
Distribution. The distribution of natural gas re-
quires the use of low-pressure pipelines to deliver gas to
customers. The distribution network consisted of nearly
1.5 million miles of pipeline in 1996, increasing from a
1990 figure of just over 1.3 million miles (AGA 1996).
Distribution system emissions, which accounted for ap-
proximately 27 percent of emissions from natural gas
systems, resulted mainly from fugitive emissions from
gate stations and non-plastic piping. An increased use
of plastic piping, which has lower emissions than other
pipe materials, has reduced the growth in emissions from
this stage.
Overall, natural gas systems emitted 34.1 MMTCE
(6.0 Tg) of methane in 1996 or 19 percent of total methane
emissions (see Table 2-20 and Table 2-21). Emissions rose
slightly from 1990 to 1996, reflecting an increase in the
number of producing gas wells and miles of distribution
pipeline. Initiated in 1993, EPA's Natural Gas STAR pro-
gram is working with the gas industry to promote profitable
Table 2-20: Methane Emissions from Natural Gas Systems (MMTCE)
Stage 1990 1991 1992 1993
1994
1995
1996
Field Production
Processing
Transmission and Storage
Distribution
Total
8.0
4.0
12.6
8.3
32.9
8.1
4.0
12.7
8.4
33.3
8.5
4.0
12.9
8.6
33.9
8.7
4.0
12.6
8.8
34.1
8.8
4.2
12.5
8.7
33.9
9.1
4.1
13.2
8.7
34.6
9.5
4.1
12.4
9.1
34.1
Note: 1994 through 1996 totals include reductions from Natural Gas STAR program. Totals may not sum due to independent rounding.
Table 2-21: Methane Emissions from Natural Gas Systems (Tg)
Stage 1990 1991 1992 1993
1994
1995
1996
Field Production
Processing
Transmission and Storage
Distribution
Total
1.4
0.7
2.2
1.4
5.7
1.4
0.7
2.2
1.5
5.8
1.5
0.7
2.3
1.5
5.9
1.5
0.7
2.2
1.5
5.9
1.5
0.7
2.2
1.5
5.9
1.5
0.7
2.3
1.5
6.0
1.5
0.7
2.2
1.6
6.0
Note: 1994 through 1996 totals include reductions from Natural Gas STAR program. Totals may not sum due to independent rounding.
Energy 2-23
-------
practices that reduce methane emissions. The program was
estimated to have reduced emissions by 0.3, 0.5, and 0.9
MMTCE in 1994, 1995, and 1996, respectively.
Methodology
The foundation for the estimate of methane emis-
sions from the U.S. natural gas industry is a detailed study
by the Gas Research Institute and EPA (GRI/EPA 1995).
The GRI/EPA study developed over 100 detailed emis-
sion factors and activity levels through site visits to se-
lected gas facilities, and arrived at a national point esti-
mate for 1992. Since publication of this study, EPA con-
ducted additional analysis to update the activity data for
some of the components of the system, particularly field
production equipment. Summing emissions across indi-
vidual sources in the natural gas system provided a 1992
baseline emissions estimate from which the emissions
for the period 1990 through 1996 were derived.
Apart from the year 1992, detailed statistics on each
of the over 100 activity levels were not available for the
time series 1990 through 1996. To estimate these activ-
ity levels, aggregate annual statistics were obtained on
the main driving variables, including: number of pro-
ducing wells, number of gas plants, miles of transmis-
sion pipeline, miles of distribution pipeline, and miles of
distribution services. By assuming that the relationships
among these variables remained constant (e.g., the num-
ber of heaters per well remained the same), the statistics
on these variables formed the basis for estimating other
activity levels.
For the period 1990 through 1995, the emission
factors were held constant. A gradual improvement in
technology and practices is expected to reduce the emis-
sion factors slightly over time. To reflect this trend, the
emission factors for 1996 were reduced by about 0.2 per-
cent, a rate that, if continued, would lower the emission
factors by 5 percent in 2020. See Annex E for more
detailed information on the methodology and data used
to calculate methane emissions from natural gas systems.
Data Sources
Activity data were taken from the American Gas
Association (AGA 1991, 1992, 1993, 1994, 1995, 1996,
1997), the Energy Information Administration's Annual
Energy Outlook (EIA 1997a) and Natural Gas Annual
(EIA 1997b), and the Independent Petroleum Associa-
tion of America (IPAA 1997). The U.S. Department of
Interior (DOI1997) supplied offshore platform data. All
emission factors were taken from GRI/EPA (1995).
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, scal-
ing up from model facilities introduces a degree of uncer-
tainty. Additionally, highly variable emission rates were
measured among many system components, making the
calculated average emission rates uncertain. Despite the
difficulties associated with estimating emissions from this
source, the uncertainty in the total estimated emissions are
believed to be on the order of ±40 percent.
Petroleum Systems
One of the gases emitted from the production and
refining of petroleum products is methane. The activi-
ties that lead to methane emissions include: production
field treatment and separation, routine maintenance of
production field equipment, crude oil storage, refinery
processes, crude oil tanker loading and unloading, and
venting and flaring. Each stage is described below:
Production Field Operations. Fugitive emissions
from oil wells and related production field treatment and
separation equipment are the primary source of emis-
sions from production fields. From 1990 to 1996, these
emissions accounted for about 10 percent of total emis-
sions from petroleum systems. Routine maintenance,
which includes the repair and maintenance of valves,
piping, and other equipment, accounted for less than 1
percent of total emissions from petroleum systems.
Emissions from production fields are expected to decline
in the future as the number of oil wells decreases.
Crude Oil Storage. Crude oil storage tanks emit
methane during two processes. "Breathing losses" from
roof seals and joints occur when the tank is in use, and
while tanks are being drained or filled, "working losses"
occur as the methane in the air space above the liquid is
displaced. Piping and other equipment at storage facilities
2-24
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
can also produce fugitive emissions. Between 1990 and
1996, crude oil storage emissions accounted for less than
1 percent of total emissions from petroleum systems.
Refining. Waste gas streams from refineries are a
source of methane emissions. Based on Tilkicioglu and
Winters (1989), who extrapolated waste gas stream emis-
sions to national refinery capacity, emissions estimates
from this source accounted for approximately 4 percent
of total methane emissions from the production and re-
fining of petroleum.
Tanker Operations. The loading and unloading of
crude oil tankers releases methane. From 1990 to 1996,
emissions from crude oil transportation on tankers ac-
counted for roughly 2 percent of total emissions from
petroleum systems.
Venting and Flaring. Gas produced during oil pro-
duction that cannot be contained or otherwise used is
released into the atmosphere or flared. Vented gas typi-
cally has a high methane content; however, it is assumed
that flaring destroys the majority of the methane in the
gas (about 98 percent depending upon the moisture con-
tent of the gas). Venting and flaring may account for up
to 85 percent of emissions from petroleum systems.
There is considerable uncertainty in the estimate of emis-
sions from this activity.
From 1990 to 1996, methane emissions from petro-
leum systems remained relatively constant at approximately
1.6 MMTCE (0.3 Tg), accounting for about 1 percent of
total methane emissions in 1996. Emission estimates are
provided below in Table 2-22 and Table 2-23.
Methodology
The methodology used for estimating emissions
from each activity is described below:
Production Field Operations. Emission estimates
were calculated by multiplying emission factors (i.e.,
emissions per oil well) with their corresponding activity
data (i.e., number of oil wells). To estimate emissions
for 1990 to 1996, emission factors developed to estimate
1990 emissions were multiplied by updated activity data
for 1990 through 1996. Emissions estimates from pe-
troleum systems excluded associated natural gas wells
to prevent double counting with the estimates for natural
gas systems.
Crude Oil Storage. Tilkicioglu and Winters (1989)
estimated crude oil storage emissions on a model tank farm
facility with fixed and floating roof tanks. Emission factors
developed for the model facility were applied to published
crude oil storage data to estimate emissions.
Table 2-22: Methane Emissions from Petroleum Systems (MMTCE)
Stage 1990 1991 1992 1993
1994
1995
1996
Production Field Operations
Crude Oil Storage
Refining
Tanker Operations
Venting and Flaring
Total
0.1
+
0.1
+
1.3
1.6
0.1
+
0.1
+
1.3
1.6
0.1
+
0.1
+
1.3
1.6
0.1
+
0.1
+
1.3
1.6
0.1
+
0.1
+
1.3
1.6
0.1
+
0.1
+
1.3
1.6
0.1
+
0.1
+
1.3
1.5
+ Does not exceed 0.05 MMTCE
Note: Totals may not sum due to independent rounding.
Table 2-23: Methane Emissions from Petroleum Systems (Gg)
Stage
Production Field Operations
Crude Oil Storage
Refining
Tanker Operations
Venting and Flaring
Total
1990
24
2
10
6
231
272
1991
25
2
10
6
231
273
1992
24
2
10
5
231
272
1993
24
2
10
5
231
272
1994
24
2
10
5
231
272
1995
23
2
10
5
231
271
1996
23
2
9
5
231
271
Note: Totals may not sum due to independent rounding.
Energy 2-25
-------
Refining. Tilkicioglu and Winters (1989) also es-
timated methane emissions from waste gas streams based
on measurements at ten refineries. These data were ex-
trapolated to total U.S. refinery capacity to estimate emis-
sions from refinery waste gas streams for 1990. To esti-
mate emissions for 1991 through 1996, the emissions
estimates for 1990 were scaled using updated data on
U.S. refinery capacity.
Tanker Operations. Methane emissions from
tanker operations are associated with the loading and
unloading of domestically-produced crude oil transported
by tanker, and the unloading of foreign-produced crude
transported by tanker. The quantity of domestic crude
transported by tanker was estimated as Alaskan crude oil
production less Alaskan refinery crude utilization, plus
10 percent of non-Alaskan crude oil production. Crude
oil imports by tanker were estimated as total imports less
imports from Canada. An emission factor based on the
methane content of hydrocarbon vapors emitted from
crude oil was employed (Tilkicioglu and Winters 1989).
This emission factor was multiplied by updated activity
data to estimate total emissions for 1990 through 1996.
Venting and Flaring. Although venting and flar-
ing data indicate that the amount of venting and flaring
activity has changed over time, there is currently insuffi-
cient data to assess the change in methane emissions as-
sociated with these changes. Given the considerable un-
certainty in the emissions estimate for this stage, and the
inability to discern a trend in actual emissions, the 1990
emissions estimate was held constant for the years 1991
through 1996.
See Annex F for more detailed information on the
methodology and data used to calculate methane emis-
sions from petroleum systems.
Data Sources
Data on the number of oil wells in production fields
were taken from the American Petroleum Institute (API
1997) as were the number of oil wells that do not pro-
duce natural gas. Crude oil storage, U.S. refinery capac-
ity, crude oil stocks, crude oil production, utilization, and
import data were obtained from the U.S. Department of
Energy (EIA 1991,1992,1993, 1994, 1995,1996,1997).
Emission factors were taken from Tilkicioglu and Win-
ters (1989) and EPA (1993).
Uncertainty
There are significant uncertainties associated with
all aspects of the methane emissions estimates from pe-
troleum systems. Published statistics are inadequate for
estimating activity data at the level of detail required.
Similarly, emission factors for each stage remain uncer-
tain. In particular, there is insufficient information to
estimate annual venting and flaring emissions using pub-
lished statistics. EPA is currently undertaking more de-
tailed analyses of emissions from this source and antici-
pates that new information will be available for the 1997
inventory. Preliminary work suggests that emissions will
increase. Table 2-24 provides emission estimate ranges
given the uncertainty in the venting and flaring estimates.
Natural Gas Flaring and
Criteria Pollutant Emissions
from Oil and Gas Activities
The flaring of natural gas from petroleum wells is
a small source of carbon dioxide (CO2). In addition, oil
and gas activities also release small amounts of nitrogen
oxides (NO ), carbon monoxide (CO), and nonmethane
Table 2-24: Uncertainty in Methane Emissions from Petroleum Systems (Gg)
Stage 1990 1991 1992 1993
1994
1995
1996
Venting and Flaring (point estimate)
Low
High
Total (point estimate)
Low
High
231
93
462
272
103
627
231
93
462
273
103
631
231
93
462
272
103
628
231
93
462
272
103
627
231
93
462
272
103
625
231
93
462
271
102
621
231
93
462
271
102
620
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Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
volatile organic compounds (NMVOCs). Each of these
sources is a small portion of overall emissions. Emis-
sions of CO2, NOx, and CO from petroleum and natural
gas production activities are all less than 1 percent of
national totals, while NMVOC emissions are roughly 3
percent of national totals.
Carbon dioxide emissions from petroleum produc-
tion result from natural gas that is flared (i.e., combusted)
at the production site. Barns and Edmonds (1990) noted
that of total reported U.S. venting and flaring, approxi-
mately 20 percent is actually vented, with the remaining
80 percent flared. For 1996, these emissions were esti-
mated to be approximately 3.5 MMTCE (12.7 Tg), an
increase of 75 percent from 1990 (see Table 2-25).
Criteria pollutant emissions from oil and gas pro-
duction, transportation, and storage, constitute a relatively
small and stable portion of the total emissions of these
gases for the 1990 to 1996 period (see Table 2-26).
Methodology
The estimates for CO2 emissions were prepared
using an emission factor of 14.92 MMTCE/QBtu of flared
gas, and an assumed flaring efficiency of 100 percent.
The quantity of flared gas (i.e., 80 percent of total vented
and flared gas) for each year was multiplied by this fac-
tor to calculate emissions.
Criteria pollutant emission estimates for NOx, CO,
and NMVOCs were determined using industry-published
production data and applying average emission factors.
Data Sources
Activity data for estimating CO2 emissions from
natural gas flaring were provided in EIA's Natural Gas
Annual (EIA 1997). The emission factor was also pro-
vided by EIA.
EPA (1997) provided emission estimates for NOx,
CO, and NMVOCs from petroleum refining, petroleum
product storage and transfer, and petroleum marketing
operations. Included are gasoline, crude oil and distil-
late fuel oil storage and transfer operations, gasoline bulk
terminal and bulk plants operations, and retail gasoline
service stations operations.
Table 2-25: C02 Emissions from Natural Gas Flaring
Year MMTCE Tg
1990
1991
1992
1993
1994
1995
1996
2.0
2.2
2.2
3.0
3.0
3.7
3.5
7.3
8.2
8.1
11.0
11.1
13.7
12.7
Table 2-26: N0x, NMVOCs, and CO Emissions from
Oil and Gas Activities (Gg)
Year
NO
CO
NMVOCs
1990
1991
1992
1993
1994
1995
1996
139
110
134
111
106
100
100
302
313
337
337
307
316
316
555
581
574
588
587
582
469
Uncertainty
Uncertainties in CO2 emission estimates primarily
arise from assumptions concerning what proportion of
natural gas is flared and the flaring efficiency. The 20
percent vented as methane is accounted for in the sec-
tion on methane emissions from petroleum production,
refining, transportation, and storage activities. Uncer-
tainties in criteria pollutant emission estimates are partly
due to the accuracy of the emission factors used and pro-
jections of growth.
Wood Biomass and
Ethanol Consumption
The combustion of biomass fuels—such as wood,
charcoal, and wood waste—and biomass-based fuels—
such as ethanol from corn and woody crops—generates
carbon dioxide (CO2). However, in the long run the car-
bon dioxide emitted from biomass consumption does not
increase atmospheric carbon dioxide concentrations, as-
suming the biogenic carbon emitted is offset by 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
Energy 2-27
-------
Table 2-27: C02 Emissions from Wood Consumption by End-Use Sector (MMTCE)
End-Use Sector
Electric Utility
Industrial
Residential
Commercial
Total
1990
0.3
34.0
12.7
0.7
47.6
1991
0.2
33.3
13.4
0.7
47.5
1992
0.2
34.7
14.1
0.7
49.7
1993
0.2
35.4
11.9
1.0
48.6
1994
0.2
36.5
11.7
1.0
49.4
1995
0.2
37.0
13.0
1.0
51.2
1996
0.3
38.9
13.0
1.1
53.2
Note: Totals may not sum due to independent rounding.
Table 2-28: CO Emissions from Wood Consumption by End-Use Sector (Tg)
End-Use Sector
Electric Utility
Industrial
Residential
Commercial
Total
1990
1.0
124.8
46.4
2.4
174.6
1991
0.8
122.1
49.0
2.4
174.3
1992
0.9
127.3
51.5
2.4
182.1
1993
0.9
129.8
43.8
3.5
178.0
1994
0.9
133.7
42.9
3.6
181.1
1995
0.9
135.7
47.6
3.6
187.8
1996
1.0
142.6
47.5
3.9
195.0
Note: Totals may not sum due to independent rounding.
U.S. totals. Net carbon fluxes from changes in biogenic
carbon reservoirs in wooded or crop lands are accounted
for under the Land-Use Change and Forestry sector.
In 1996, CO2 emissions due to burning of woody
biomass within the industrial, residential and commer-
cial end-use sectors and by electric utilities were about
53.2 MMTCE (195.0 Tg) (see Table 2-27 and Table 2-
28). As the largest consumer of biomass fuels, the in-
dustrial end-use sector was responsible for 73 percent of
the CO2 emissions from biomass-based fuels. The resi-
dential end-use sector was the second largest emitter,
making up 24 percent of total emissions from woody bio-
mass. The commercial end-use sector and electric utili-
ties accounted for the remainder.
Between 1990 and 1996, total emissions of CO2
from biomass burning increased 12 percent. This increase
in emissions was mainly due to a 14 percent rise in in-
dustrial biomass fuel consumption between 1990 and
1996. Consumption of biomass fuels within the com-
mercial end-use sector and by electric utilities remained
relatively stable and thus had little impact on changes in
overall CO2 emissions from biomass combustion.
Biomass-derived fuel consumption in the United
States consisted mainly of ethanol use in the transporta-
tion end-use sector. Ethanol is primarily produced from
corn grown in the Midwest, and was used primarily in
the Midwest and South. Pure ethanol can be combusted,
or it can be mixed with gasoline as a supplement or oc-
tane-enhancing agent. The most common mixture is a
90 percent gasoline, 10 percent ethanol blend known as
gasohol. Ethanol and ethanol blends are often used to
fuel public transport vehicles such as buses, or centrally
fueled fleet vehicles. Ethanol and ethanol blends are be-
lieved to 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 1996, the United States consumed an estimated
74 trillionBtus of ethanol (1.0 billion gallons), mostly in
the transportation end-use sector. Emissions of CO2 in
1996 due to ethanol fuel burning were estimated to be
approximately 1.4 MMTCE (5.1 Tg) (see Table 2-29).
Between 1990 and 1991, emissions of CO2 due to etha-
nol fuel consumption fell by 21 percent. Since this de-
Table 2-29: C02 Emissions from Ethanol
Consumption
Year
MMTCE
1990
1991
1992
1993
1994
1995
1996
1.6
1.2
1.5
1.7
1.8
2.0
1.4
5.7
4.5
5.5
6.1
6.7
7.2
5.1
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Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
cline, emissions from ethanol have steadily increased
through 1995. From 1995 to 1996, however, ethanol
consumption declined by 29 percent. Overall, from 1990
to 1996, emissions of CO2 decreased by 9.8 percent.
Again, emissions from ethanol consumption are not in-
cluded under the Energy sector because the corn from
which ethanol is derived is of biogenic origin.9
Ethanol production dropped sharply in the middle
of 1996 because of short corn supplies and high prices.
Plant output began to increase toward the end of the grow-
ing season, reaching close to normal levels at the end of
the year. However, total 1996 ethanol production fell far
short of the 1995 level (EIA 1997b).
Methodology
Woody biomass emissions were estimated by con-
verting U.S. consumption data in energy units (17.2 mil-
lion Btu per short ton) to megagrams (Mg) of dry matter
using EIA assumptions. Once consumption data for each
sector were converted to megagrams of dry matter, the
carbon content of the dry fuel was estimated based on
default values of 45 to 50 percent carbon in dry biomass.
The amount of carbon released from combustion was
estimated using 87 percent for the fraction oxidized (i.e.,
combustion efficiency). Ethanol consumption data in
energy units were also multiplied by a carbon coefficient
(18.96 mg C/Btu) to produce carbon emission estimates.
Data Sources
Woody biomass consumption data were provided
by EIA (1997a) (see Table 2-30). The factor for con-
verting energy units to mass was supplied by EIA (1994).
Carbon content and combustion efficiency values were
taken from the Revised 1996IPCC Guidelines (IPCC/
UNEP/OECD/IEA 1997).
Uncertainty
The combustion efficiency factor used is believed
to under estimate the efficiency of wood combustion pro-
cesses in the United States. The IPCC emission factor
has been used because better data are not yet available.
Increasing the combustion efficiency would increase
emission estimates. In addition, according to EIA (1994)
commercial wood energy use is typically not reported
because there are no accurate data sources to provide
reliable estimates. Emission estimates from ethanol pro-
duction are more certain than estimates from woody bio-
mass consumption due to better activity data collection
methods and uniform combustion techniques.
Emissions from ethanol were estimated using con-
sumption data from EIA (1997a) (see Table 2-31). The
carbon coefficient used was provided by OTA (1991).
Table 2-30: Residential and Industrial Biomass
Consumption (Trillion Btu)
Year Industrial Residential
1990
1991
1992
1993
1994
1995
1996
1,562
1,528
1,593
1,625
1,673
1,698
1,784
581
613
645
548
537
596
595
Table 2-31: Ethanol Consumption
Year Trillion Btu
1990
1991
1992
1993
1994
1995
1996
82
65
79
88
97
104
74
Emissions and sinks of biogenic carbon are accounted for under the Land-Use Change and Forestry sector.
Energy 2-29
-------
3. Industrial
Processes
Gsenhouse gas emissions are produced as a by-product of various non-energy related industrial activities.
hat is, these emissions are produced directly 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 often results in the release of greenhouse gases such as carbon dioxide (CO2), methane
(CH4), and nitrous oxide (N2O). The processes addressed in this chapter include cement production, lime manufac-
ture, limestone and dolomite use (e.g., flux stone, flue gas desulfurization, and glass manufacturing), soda ash pro-
duction and use, CO2 manufacture, iron and steel production, ammonia manufacture, ferroalloy production, alumi-
num production, petrochemical production (including carbon black, ethylene, dicholoroethylene, styrene, andmetha-
nol), silicon carbide production, adipic acid production, and nitric acid production (see Figure 3-1).'
In addition to the three greenhouse gases listed above, there are also industrial sources of several classes of
man-made fluorinated compounds called hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride
(SF6). The present contribution of these gases to the radiative forcing effect of all anthropogenic greenhouse gases is
Figure 3-1
1996 Industrial Processes Sector GHG Sources
S*lMltMticH-i a QtaHv DtipMlnp 5ub«.l«n:™«
Cftrtwlll MunufMKhity
HCFC-3J ProdifdlWl
Dlnrt,lu.r1lciii
N 1iic
Proauciinn and
*lLnnmiB»i Production
Sodo
•SerntcflnduGtar Manufacture
i Worm* DC turn antf CEKiBLpTiptoon
ftrtW if M En|H««
l Prcdiiclicm
inirfictiira
Silicon Carbide Production
L
* i
HNTTCE
19
12
i
included under the Energy sector as part of fossil fuel combustion of industrial coking coal, natural gas, and petroleum coke.
Carbon dioxide emissions from iron and steel production, ammonia manufacture, ferroalloy production, and aluminum production are
Industrial Processes
3-1
-------
small; however, because of their extremely long lifetimes,
they will continue to accumulate in the atmosphere as
long as emissions continue. Sulfur hexafluoride, itself,
is the most potent greenhouse gas the IPCC has ever
evaluated. Usage of these gases, especially HFCs, is
growing rapidly as they are the primary substitutes for
ozone depleting substances (ODS), which are being
phased-out under the Montreal Protocol on Substances
that Deplete the Ozone Layer. In addition to ODS sub-
stitutes, HFCs, PFCs, and other fluorinated compounds
are employed and emitted by a number of other indus-
trial sources in the United States. These industries in-
clude aluminum production, HCFC-22 production, semi-
conductor manufacture, electric power transmission and
distribution, and magnesium metal production and pro-
cessing.
Total CO2 emissions from industrial processes were
approximately 17.3 MMTCE (63.3 Tg) in 1996. This
amount accounted for only 1 percent of total U.S. CO2
emissions. Methane emissions from petrochemical and
silicon carbide production resulted in emissions of ap-
proximately 0.4 MMTCE (0.1 Tg) in 1996, which was
less than 1 percent of U.S. CH4 emissions. Nitrous ox-
ide emissions from adipic acid and nitric acid produc-
tion were 9.2 MMTCE (0.1 Tg) in 1996, or 9 percent of
total U.S. N2O emissions. In the same year, combined
emissions of HFCs, PFCs and SF6 totaled 34.7 MMTCE.
Overall, emissions from the Industrial Processes sector
increased by 35 percent from 1990 to 1996, and 8 per-
cent in the last year alone.
Emission estimates are presented under this sector
for several industrial processes that are actually accounted
for within the Energy sector. Although CO2 emissions
from iron and steel production, ammonia manufacture,
ferroalloy production, and aluminum production are not
the result of the combustion of fossil fuels for energy,
their associated emissions are captured in the fuel data
for industrial coking coal, natural gas, industrial coking
coal, and petroleum coke, respectively. Consequently, if
all emissions were attributed to their appropriate sector,
then emissions from energy would decrease by roughly
30 MMTCE in 1996, and industrial process emissions
would increase by the same amount.
Greenhouse gases are also emitted from a number
of industrial processes not addressed in this section. For
example, caprolactam—a chemical feedstock for the
manufacture of nylon 6,6—and urea production are be-
lieved to be industrial sources of N2O emissions. How-
ever, emissions for these and other sources have not been
estimated at this time due to a lack of information on the
emission processes, manufacturing data, or both. As more
information becomes available, emission estimates for
these processes will be calculated and included in future
greenhouse gas emission inventories, although their con-
tribution is expected to be small.2
The general method employed to estimate emis-
sions for industrial processes, as recommended by the
Intergovernmental Panel on Climate Change (IPCC), gen-
erally involved multiplying production data for each pro-
cess by an emission factor per unit of production. The
emission factors used were either derived using calcula-
tions that assume precise and efficient chemical reactions
or were based upon empirical data in published refer-
ences. As a result, uncertainties in the emission coeffi-
cients can be attributed to, among other things, ineffi-
ciencies in the chemical reactions associated with each
production process or to the use of empirically derived
emission factors that are biased and, therefore, may not
represent U.S. national averages. Additional sources of
uncertainty specific to an individual source category are
discussed in each section.
Table 3-1 summarizes emissions from the Indus-
trial Processes sector in units of million metric tons of
carbon equivalents (MMTCE), while unweighted gas
emissions in teragrams (Tg) are provided in Table 3-2.
Cement Manufacture
Cement production is an energy and raw material
intensive process resulting in the generation of substan-
tial amounts of carbon dioxide (CO2) from both the en-
ergy consumed in making the cement and the chemical
process itself. Cement production accounts for about
2.4 percent of total global industrial and energy related
CO2 emissions (IPCC 1996). The United States is the
world's third largest cement producer. Cement is pro-
3-2
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 3-1: Emissions from Industrial Processes (MMTCE)
Gas/Source
1990 1991 1992 1993 1994 1995
1996
C02
Cement Manufacture
Lime Manufacture
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Carbon Dioxide Manufacture
Iron and Steel Production*
Ammonia Manufacture*
Ferroalloy Production*
Aluminum Production*
CH
Petrochemical Production
Silicon Carbide Production
N20
Adipic Acid Production
Nitric Acid Production
MFCs, PFCs, and SF6
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production
Semiconductor Manufacture
Electrical Transmission and Distribution
Magnesium Production and Processing
Total
14.9
8.9
3.3
1.4
1.1
0.2
23.9
6.3
0.5
1.6
0.3
0.3
+
8.1
4.7
3.4
22.2
0.3
4.9
9.5
0.2
5.6
1.7
45.5
14.5
8.7
3.2
1.3
1.1
0.2
19.2
6.4
0.4
1.7
0.3
0.3
+
8.3
4.9
3.3
21.6
0.2
4.7
8.4
0.4
5.9
2.0
44.7
14.6
8.8
3.3
1.2
1.1
0.2
20.7
6.7
0.4
1.6
0.3
0.3
+
8.0
4.6
3.4
23.0
0.4
4.1
9.5
0.6
6.2
2.2
45.9
15.1
9.3
3.4
1.1
1.1
0.2
21.0
6.4
0.4
1.5
0.4
0.4
+
8.4
4.9
3.5
23.4
1.4
3.5
8.7
0.8
6.4
2.5
47.2
15.9
9.6
3.5
1.5
1.1
0.2
21.6
6.6
0.4
1.3
0.4
0.4
+
8.9
5.2
3.7
25.9
4.0
2.8
8.6
1.0
6.7
2.7
51.2
16.8
9.9
3.7
1.8
1.2
0.3
22.2
6.5
0.4
1.4
0.4
0.4
+
9.0
5.2
3.7
30.8
9.5
2.7
7.4
1.2
7.0
3.0
56.9
17.3
10.1
3.8
1.8
1.2
0.3
21.6
6.6
0.5
1.4
0.4
0.4
+
9.2
5.4
3.8
34.7
11.9
2.9
8.5
1.4
7.0
3.0
61.5
+ Does not exceed 0.05 MMTCE
* Emissions from these sources are accounted for in the Energy sector and are not included in the Industrial Processes totals.
Note: Totals may not sum due to independent rounding.
duced in almost every state and is used in all of them.
Carbon dioxide, emitted from the chemical process of
cement production, represents one of the most signifi-
cant sources of industrial CO2 emissions in the United
States.
During cement production, calcium carbonate
(CaCO3) is heated in a cement kiln at a temperature of
1,930°C (3,500°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-con-
taining materials to produce clinker (an intermediate
product), with the 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 Port-
land and masonry cement. The production of masonry
cement requires additional lime and, thus, results in ad-
ditional CO2 emissions. However, this additional lime is
already accounted for in the Lime Manufacture section
of this chapter; therefore, the additional emission from
making masonry cement from clinker are not counted in
this source's total. They are presented here for informa-
tional purposes only.
In 1996, U.S. clinker production—including Puerto
Rico—totaled 73.1 teragrams (Tg), and U.S. masonry
cement production reached 3.4 Tg (USGS 1997). The
resulting emissions of CO2 from clinker production were
estimated to be 10.1 MMTCE (37.1 Tg), or less than 1
percent of total U.S. CO2 emissions (Table 3-3). Emis-
sions from masonry production from clinker raw mate-
rial were estimated to be 0.02 MMTCE (0.08 Tg) in 1996,
but are accounted for under Lime Manufacture.
After falling in 1991 by 2 percent from 1990 lev-
els, cement production emissions have grown every year
since. Overall, from 1990 to 1996 emissions increased
by 14 percent. In 1996, output by cement plants increased
3 percent over 1995, to 73 Tg. In both the near and in-
See Annex Q for a discussion of emission sources excluded.
Industrial Processes
3-3
-------
Table 3-2: Emissions from Industrial Processes (Tg)
Gas/Source
1990 1991 1992 1993 1994 1995
+ Does not exceed 0.05 Tg
M (Mixture of gases)
" Emissions from these sources are accounted for in the Energy sector and are not included in the Industrial Processes totals.
" HFC-23 emitted
c SF6 emitted
Note: Totals may not sum due to independent rounding.
1996
C02
Cement Manufacture
Lime Manufacture
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Carbon Dioxide Manufacture
Iron and Steel Production3
Ammonia Manufacture3
Ferroalloy Production3
Aluminum Production3
CH4
Petrochemical Production
Silicon Carbide Production
N20
Adipic Acid Production
Nitric Acid Production
MFCs, PFCs, and SF6
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production"
Semiconductor Manufacture
Electrical Transmission and Distribution0
Magnesium Production and Processing0
54.6
32.6
11.9
5.1
4.1
0.8
87.6
23.1
1.8
6.0
0.1
0.1
+
0.1
0.1
M
M
M
+
M
+
+
53.3
31.9
11.7
4.9
4.0
0.8
70.6
23.4
1.6
6.1
0.1
0.1
+
0.1
0.1
M
M
M
+
M
+
+
53.7
32.1
12.1
4.5
4.1
0.9
75.8
24.4
1.6
5.9
0.1
0.1
+
0.1
0.1
M
M
M
+
M
+
+
55.3
33.9
12.4
4.1
4.0
0.9
77.1
23.4
1.5
5.4
0.1
0.1
+
0.1
0.1
M
M
M
+
M
+
+
58.4
35.4
12.8
5.3
4.0
0.9
79.0
24.3
1.6
4.9
0.1
0.1
+
0.1
0.1
M
M
M
+
M
+
+
61.5
36.1
13.6
6.5
4.3
1.0
81.4
23.7
1.6
5.0
0.1
0.1
+
0.1
0.1
M
M
M
+
M
+
+
63.3
37.1
14.1
6.7
4.3
1.1
79.0
24.2
1.7
5.3
0.1
0.1
+
0.1
0.1
M
M
M
+
M
+
+
Table 3-3: CCL Emissions from Cement Production*
Year
1990
1991
1992
1993
1994
1995
1996
MMTCE
8.9
8.7
8.8
9.3
9.7
9.9
10.1
Tg
32.6
31.9
32.1
33.9
35.4
36.1
37.1
* Totals exclude C02 emissions from making masonry cement
from clinker, which are accounted for under Lime Manufacture.
termediate terms, cement production in the United States
is anticipated to grow only modestly (USGS 1996). Ce-
ment is a critical component of the construction indus-
try; therefore, the availability of public construction fund-
ing, as well as overall economic growth, will have con-
siderable influence on cement production in the future.
Methodology
Carbon dioxide emissions from cement production
are created by the chemical reaction of carbon-containing
minerals (i.e., calcining limestone). While in the kiln, lime-
stone is broken down into CO2 and lime with the CO2 re-
leased 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 ap-
plying 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
3-4
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
64.6 percent (IPCC/UNEP/OECD/IEA 1997) and a con-
stant reflecting the mass of CO2 released per unit of lime.
This yields an emission factor of 0.507 metric tons of
CO2 per metric ton of clinker produced. The emission
factor was calculated as follows:
EF,,.. . = 0.646 fcaO x 44.01 g/mole CO "1 = 0.507 tons/ CO./ton clinker
umker I z I z
|_ 56.08 g/mole CaO J
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 approxi-
mately 5 percent. Lime accounts for approximately 60
percent of this added weight. Thus, the additional lime
is equivalent to roughly 2.86 percent of the starting
amount of the product, since:
0.6 x 0.057(1 + 0.05) = 2.86%
An emission factor for this added lime can then be
calculated by multiplying this percentage (2.86 percent)
by the molecular weight ratio of CO2 to CaO (0.785) to
yield 0.0224 metric tons of additional CO2 emitted for
every metric ton of masonry cement produced.
As previously mentioned, the CO2 emissions from
the additional lime added during masonry cement pro-
duction were accounted for in the section on CO2 emis-
sions from Lime Manufacture. Thus, these emissions
were estimated in this chapter for informational purposes
only, and are not included in the cement emission totals.
Data Sources
The activity data for cement and clinker produc-
tion (see Table 3-4) were taken from U.S. Geological
Survey (USGS 1992, 1995, 1996,1997); the 1996 figure
was adjusted, as stated below, from USGS, Mineral In-
dustry Surveys: Cement in December 1996. The data
Table 3-4: Cement Production (Thousand
Metric Tons)
Year
Clinker
Masonry
1990
1991
1992
1993
1994
1995
1996
64,355
62,918
63,415
66,957
69,786
71,257
73,103
3,209
2,856
3,093
2,975
3,283
3,603
3,420
were compiled by USGS through questionnaires sent to
domestic clinker and cement manufacturing plants. For
1996, clinker figures were not yet available. Thus, as
recommended by the USGS, clinker production was es-
timated for 1996 by subtracting 5 percent from Portland
cement production (Portland cement is a mixture of clin-
ker and approximately 5 percent gypsum).
Uncertainty
The uncertainties contained in these estimates are
primarily due to uncertainties in the lime content of clin-
ker and in the amount of lime added to masonry cement.
For example, the lime content of clinker varies from 64
to 66 percent. Also, 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 cre-
ate calcium carbonate. This reaction only occurs in
roughly the outer 0.2 inches of surface area. Since the
amount of CO2 reabsorbed is thought to be minimal, it is
not considered in this analysis. In addition, estimating
emissions based on finished cement production for 1996
ignores the consideration that some domestic cement may
be made from imported clinker.
Lime Manufacture
Lime, or calcium oxide (CaO), is an important
manufactured product with many industrial, chemical,
and environmental applications. Lime has historically
ranked fifth in total production of all chemicals in the
United States. Its major uses are in steel making, flue
gas desulfurization (FGD), construction, pulp and paper
manufacturing, and water purification. Lime production
involves three main processes: stone preparation, calci-
nation, and hydration. Carbon dioxide is generated dur-
ing the calcination stage, when limestone—mostly cal-
cium carbonate (CaCO3)—is roasted at high temperatures
in a kiln to produce CaO and CO2. Some of the CO2
generated during the production process, however, is re-
covered for use in sugar refining and precipitated cal-
cium carbonate (PCC) production. The CO2 is driven
off as a gas and is normally emitted to the atmosphere.
Industrial Processes
3-5
-------
Table 3-5: Net C02 Emissions from Lime
Manufacture
Year
MMTCE
1990
1991
1992
1993
1994
1995
1996
3.3
3.2
3.3
3.4
3.5
3.7
3.8
Table 3-6: C02 Emissions from Lime
Manufacture (Tg)
Year
Production Recovered* Net Emissions
1990
1991
1992
1993
1994
1995
1996
12.5
12.3
12.7
13.2
13.7
14.5
15.0
(0.5)
(0.6)
(0.6)
(0.8)
(0.9)
(0.9)
(0.9)
11.9
11.7
12.1
12.4
12.8
13.6
14.1
* For sugar refining and precipitated calcium carbonate
production
Note: Totals may not sum due to independent rounding.
Lime production in the United States—including
Puerto Rico—was reported to be 19.1 teragrams (Tg) in
1996 (USGS 1997). This resulted in CO2 emissions of
3.8 MMTCE (14.1 Tg), or 0.2 percent of U.S. CO2 emis-
sions (see Table 3-5 and Table 3-6).
Domestic lime manufacture has increased every
year since 1991, when it declined by 1 percent from 1990
levels. Production in 1996 increased 3 percent over that
in 1995 to about 19 Tg. Commercial sales increased by
500,000 metric tons to a record high of 16.9 Tg (USGS
1997).
Overall, from 1990 to 1996, CO2 emissions in-
creased by 18 percent. This incresase is attributed in
part to growth in demand for environmental applications.
In 1993, the U.S. Environmental Protection Agency
(EPA) completed regulations under the Clean Air Act
capping sulfur dioxide (SO2) emissions from electric utili-
ties. This action resulted in greater lime consumption
for flue gas desulfurization systems, which increased by
16 percent in 1993 (USGS 1994b). At the turn of the
century, over 80 percent of lime consumed in the United
States went for construction uses, but currently over 90
percent is consumed for chemical and industrial purposes,
of which 28 percent are environmental uses (USGS 1997).
Methodology
During the calcination stage of lime manufacture,
CO2 is driven off as a gas and normally exits the system
with the stack gas. The mass of CO2 released per unit of
lime produced can be calculated based on stoichiometry:
(44.01g/moleCO) - (56.08 g/mole CaO) = 0.785 g
C02/g CaO 2
Lime production in the United States was 19,100
thousand metric tons in 1996 (USGS 1997), resulting in
potential CO2 emissions of 15.0 Tg. Some of the CO2
generated during the production process, however, was
recovered for use in sugar refining and precipitated cal-
cium carbonate (PCC) production. Combined lime manu-
facture by these producers was 1,428 thousand metric
tons in 1996, generating 1.1 Tg of CO2. Approximately
80 percent of this CO2 was recovered.
Table 3-7: Lime Manufacture and Lime Use for
Sugar Refining and PCC (Thousand Metric Tons)
Year Production Use
1990
1991
1992
1993
1994
1995
1996
15,859
15,694
16,227
16,800
17,400
18,500
19,100
826
964
1,023
1,310
1,377
1,504
1,428
Data Sources
The activity data for lime manufacture and lime
consumption by sugar refining and precipitated calcium
carbonate (PCC) for 1990 through 1992 (see Table 3-7)
were taken from USGS (1991, 1992); for 1993 through
1994 from Michael Miller (1995); and for 1995 through
1996 from USGS (1997).
Uncertainty
The term "lime" is actually a general term that in-
cludes various chemical and physical forms of this com-
modity. Uncertainties in the emission estimate can be at-
tributed to slight differences in the chemical composition
of these products. For example, although much care is taken
3-6
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
to avoid contamination during the production process, lime
typically contains trace amounts of impurities such as iron
oxide, alumina and silica. Due to differences in the lime-
stone 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. In most processes that use lime (e.g., water soft-
ening), CO2 reacts with the lime to create calcium carbon-
ate. This is not necessarily true about lime consumption in
the steel industry, however, which is the largest consumer
of lime. 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.
As more information becomes available, this emission esti-
mate will be adjusted accordingly.
In some cases, lime is generated from calcium car-
bonate by-products at paper mills and water treatment
plants.3 The lime generated by these processes is not
included in the USGS data for commercial lime consump-
tion. In the paper industry, mills which employ the sul-
fate process (i.e., Kraft) consume lime in order to
causticize a waste sodium carbonate solution (i.e., black
liquor). Most sulfate mills recover the waste calcium
carbonate after the causticizing operation and calcine it
back into lime—thereby generating CO2—for reuse in
the pulping process. However, some of these mills cap-
ture the CO2 released in this process to be used as pre-
cipitated calcium carbonate (PCC). Further research is
necessary to determine to what extent CO2 is released to
the atmosphere through generation of lime by paper mills.
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 pro-
cess. Further research is necessary to determine the de-
gree to which lime recycling is practiced by water treat-
ment plants in the United States.
Limestone and Dolomite Use
Limestone (CaCO3) and dolomite (CaCO3MgCO3)4
are basic raw materials used by a wide variety of indus-
tries, including construction, agriculture, chemical, met-
allurgy, 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 ex-
tracted for commercial use. For example, limestone can
be used as a flux or purifier in metallurgical furnaces, as
a sorbent in flue gas desulfurization (FGD) systems for
utility and industrial plants, or as a raw material in glass
manufacturing. Limestone is heated during these pro-
cesses, generating CO2 as a by-product.
In 1996, approximately 11.8 Tg of limestone and
3.2 Tg of dolomite were used as flux stone in the chemi-
cal and metallurgical industries, in FGD systems, and
for glass manufacturing (see Table 3-10). Overall, both
limestone and dolomite usage resulted in aggregate CO2
emissions of 1.8 MMTCE (6.7 Tg), orO. 1 percent of U.S.
CO2 emissions (see Table 3-8 and Table 3-9).
Emissions in 1996 increased 4 percent from the
previous year. Though slightly decreasing in 1991,1992,
and 1993, CO2 emissions from this source have since
increased 33 percent from the 1990 baseline. In the near
future, gradual increases in demand for crushed stone
are anticipated based on the volume of work on highway
and other infrastructure projects that are being financed
by the Intermodal Surface Transportation Efficiency Act
of 1991, the National Highway System Designation Act
of 1995, and the overall growth in the U.S. economy
(USGS 1996). The increases will be influenced, how-
ever, by construction activity for both publicly and pri-
vately funded projects.
Some carbide producers may also regenerate lime from their calcium hydroxide by-products, nevertheless this process is not a source 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)J, not calcium carbonate [CaCOJ. Thus, the calcium
hydroxide is heated in the kiln to simply expel the water [Ca(OH)2 + heat ® CaO + H2O] and no CO2 is released to the atmosphere.
Limestone and dolomite are collectively referred to as limestone by the industry, and intermediate varieties are seldom distinguished.
Industrial Processes
3-7
-------
Table 3-8: C02 Emissions from Limestone & Dolomite Use (MMTCE)
Activity 1990 1991 1992 1993
1994
Total
1.4
1.3
1.2
1.1
1.5
1995
1.8
1996
Flux Stone
Glass Making
FGD
0.8
0.1
0.5
0.7
+
0.6
0.6
0.1
0.5
0.5
0.1
0.5
0.8
0.1
0.6
1.1
0.1
0.6
1.1
0.2
0.6
1.8
+ Does not exceed 0.05 MMTCE
Note: Totals may not sum due to independent rounding.
Table 3-9: CO Emissions from Limestone & Dolomite Use (Tg)
Activity
Flux Stone
Limestone
Dolomite
Glass Making
Limestone
Dolomite
FGD
Total
1990
2.6
0.4
0.2
NA
1.9
5.1
1991
2.3
0.4
0.2
NA
2.0
4.9
1992
2.0
0.3
0.2
NA
2.0
4.5
1993
1.6
0.3
0.3
NA
1.9
4.1
1994
2.1
0.8
0.4
NA
2.0
5.3
1995
2.5
1.4
0.4
0.1
2.0
6.5
1996
2.7
1.5
0.4
0.1
2.1
6.7
NA (Not Available)
Note: Totals may not sum due to independent rounding.
Table 3-10: Limestone & Dolomite Consumption (Thousand Metric Tons)
Activity
1990
1991
1992
1993
1994
NA (Not Available)
1995
1996
Flux Stone
Limestone
Dolomite
Glass Making
Limestone
Dolomite
FGD
5,797
932
430
NA
4,369
5,213
838
386
NA
4,606
4,447
737
495
NA
4,479
3,631
632
622
NA
4,274
4,792
1,739
809
NA
4,639
5,734
2,852
958
216
4,650
6,052
3,010
1,011
228
4,700
Methodology
Carbon dioxide emissions were calculated by mul-
tiplying the amount of limestone consumed by an aver-
age carbon content for limestone, approximately 12.0
percent for limestone and 13.2 percent for dolomite
(based on stoichiometry). Assuming that all of the car-
bon was released into the atmosphere, the appropriate
emission factor was multiplied by the annual level of
consumption for flux stone, glass manufacturing, and
FGD systems to determine emissions.
Data Sources
Consumption data for 1990 through 1995 of lime-
stone and dolomite used as flux stone and in glass manu-
facturing (see Table 3-10) were obtained from the USGS
(1991,1993,1996). Data for 1996 were taken from USGS
(1997). Consumption data for limestone used in FGD were
taken from unpublished survey data in the Energy Informa-
tion Administration's Form EI-767, "Steam Electric Plant
Operation and Design Report," (EIA 1997).
The USGS reports production of total crushed stone
annually, however, the breakdown of limestone and dolo-
3-8
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
mite production is only provided for odd years. Consump-
tion figures for even years were estimated by assuming that
limestone and dolomite account for the same percentage of
total crushed stone for the given even year as the average of
the percentages for the years before and after (exception:
1990 and 1996 consumption were estimated using the per-
centages for only 1991 and 1995, respectively).
It should be noted that there is a large quantity of
crushed stone reported to the USGS under the category
"unspecified uses". A portion of this consumption is
believed to be limestone or dolomite used as flux stone
and for glass manufacture. The quantity listed for "un-
specified uses" was, therefore, allocated to each reported
end-use according to each end-uses fraction of total con-
sumption in that year.5
Uncertainty
Uncertainties in this estimate are due to variations in
the chemical composition of limestone. In addition to cal-
cite, 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 manu-
factured. 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 accu-
rately allocate this unspecified quantity to the correct end-
uses. Furthermore, some of the limestone reported as "lime-
stone" is believed to be dolomite, which has a higher car-
bon content than limestone.
Soda Ash Manufacture
and Consumption
Soda ash (sodium carbonate, Na2CO3) is a white
crystalline solid that is readily soluble in water and
strongly alkaline. Commercial soda ash is used as a raw
material in a variety of industrial processes and in many
familiar consumer products such as glass, soap and de-
tergents, 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 pro-
duces only natural soda ash and is the largest soda ash-
producing country in the world. Trona is the principal
ore from which natural soda ash is made.
Only two states produce natural soda ash: Wyoming
and California. Of these two states, only Wyoming has net
emissions of CO2. This difference is a result of the produc-
tion processes employed in each state.6 During the produc-
tion process used in Wyoming, natural sources of sodium
carbonate are heated and transformed into a crude soda ash
that requires further refining. Carbon dioxide (CO2) is gen-
erated as a by-product of this reaction, and is eventually
emitted into the atmosphere. In addition, CO2 is also re-
leased when soda ash is consumed.
In 1996, CO2 emissions from trona production were
approximately 0.4 MMTCE (1.6 Tg). Soda ash consump-
tion in the United States also generated about 0.7
MMTCE (2.7 Tg) of CO2 in 1996. Total emissions from
this source in 1996 were 1.2 MMTCE (4.3 Tg), or less
than 0.1 percent of U.S. CO2 emissions (see Table 3-11
and Table 3-12). Emissions have fluctuated since 1990.
These fluctuations were strongly related to the behavior
of the export market and the U.S. economy. Emissions
in 1996 decreased by 1 percent from the previous year,
but have increased 3 percent since 1990.
The United States has the world's largest deposits of
trona and represents about one-third of total world soda ash
output. The distribution of soda ash by end-use in 1996
was glass making, 48 percent; chemical production, 27 per-
cent; soap and detergent manufacturing, 12 percent; dis-
tributors, 5 percent; pulp and paper production, 3 percent;
This approach was recommended by USGS.
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 will precipi-
tate under these conditions. 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 never actually released.
Industrial Processes
3-9
-------
Table 3-11: C02 Emissions from Soda Ash Manu-
facture and Consumption
2(Na3H(C03)2 2H20) ®
CO,
Year
MMTCE
1990
1991
1992
1993
1994
1995
1996
1.1
1.1
1.1
1.1
1.1
1.2
1.2
Table 3-12: C02 Emissions from Soda Ash Manu-
facture and Consumption (Tg)
Year
Trona
Production
Soda Ash
Consumption
Total
1990
1991
1992
1993
1994
1995
1996
1.4
1.4
1.5
1.4
1.4
1.6
1.6
2.7
2.6
2.6
2.6
2.6
2.7
2.7
4.1
4.0
4.1
4.1
4.0
4.3
4.3
Note: Totals may not sum due to independent rounding.
flue gas desulfurization and miscellaneous, 2 percent each;
and water treatment, 1 percent (USGS 1997).
Exports are a driving force behind increasing U.S.
soda ash production capacity (USGS 1997). For ex-
ample, the automotive manufacturing industry in South
America is expanding considerably. This expansion will
require additional quantities of flat glass for automotive
windows in the estimated 2 million vehicles that are
planned to be built by the end of the century (USGS
1997). Domestic soda ash consumption is also expected
to rise in 1997.
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 diox-
ide and water are generated as a by-product of the calci-
nation process. Carbon dioxide emissions from the cal-
cination of trona can be estimated based on the follow-
ing chemical reaction:
[trona] [soda ash]
Based on this formula, approximately 10.27 met-
ric tons of trona are required to generate one metric ton
of CO2. Thus, the 16.3 million metric tons of trona mined
in 1996 for soda ash production (USGS 1997) resulted
in CO2 emissions of approximately 0.4 MMTCE (1.6 Tg).
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 processed for these pur-
poses, additional CO2 is usually emitted. In these applica-
Table 3-13: Soda Ash Manufacture and Consump-
tion (Thousand Metric Tons)
Year
1990
1991
1992
1993
1994
1995
1996
Trona
Production
14,734
14,674
14,900
14,500
14,600
16,500
16,300
Soda Ash
Consumption
6,527
6,287
6,360
6,350
6,240
6,510
6,410
tions, 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 re-
leased for every metric ton of soda ash consumed.
Data Sources
The activity data for trona production and soda ash
consumption (see Table 3-13) were taken from USGS
(1993, 1994, 1995, 1997). Soda ash production and in-
ventory data were collected by the USGS from volun-
tary surveys of the U.S. soda ash industry. All six of the
soda ash operations in the United States completed sur-
veys to provide production and consumption data to the
USGS.
It is unclear to what extent the CO2 used for EOR will be re-released. For example, the CO2 used for EOR is likely to show up at the wellhead
after a few years of injection (Hangebrauk et al. 1992). This CO2, however, is typically recovered and re-injected into the well. More research
is required to determine the amount of CO2 that in fact escapes. For the purposes of this analysis, it is assumed that all of the CO2 remains
sequestered.
3-10
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Uncertainty
Emissions from soda ash consumption are dependent
upon the type of processing employed by each end-use;
however, specific information characterizing the emissions
from each end-use is limited. Therefore, uncertainty exists
as to the accuracy of the emission factors.
Carbon Dioxide Manufacture
Carbon dioxide (CO2) is used for a variety of ap-
plications, including food processing, chemical produc-
tion, carbonated beverages, and enhanced oil recovery
(EOR). Carbon dioxide used for EOR is injected into
the ground to increase reservoir pressure, and is there-
fore considered sequestered.7 For the most part, how-
ever, CO2 used in non-EOR applications will eventually
enter the atmosphere.
Carbon dioxide is produced from a small number
of natural wells, as a by-product from the production of
chemicals (e.g., ammonia), or separated from crude oil
and natural gas. Depending on the raw materials that are
used, the by-product CO2 generated during these pro-
duction processes may already be accounted for in the
CO2 emission estimates from fossil fuel consumption
(either during combustion or from non-fuel uses). For
example, ammonia is manufactured using primarily natu-
ral gas as a feedstock. Carbon dioxide emissions from
this process are accounted for in the Energy sector under
Fossil Fuel Combustion and therefore are not included
here.
In 1996, CO2 emissions from this source were ap-
proximately 0.3 MMTCE (1.1 Tg), or less than 0.1 per-
cent ofU.S. CO2 emissions (see Table 3-14). This amount
represents an increase of 18 percent from the previous
year and is 43 percent higher than CO2 emissions in 1990,
which totaled 0.2 MMTCE. Carbon dioxide demand in
the merchant market is expected to expand 4.2 percent
annually through 1998 (Freedonia Group 1994).
Methodology
Carbon dioxide emission estimates were based on CO2
consumption with the assumption that the end-use applica-
tions, except enhanced oil recovery, eventually release 100
percent of the CO into the atmosphere. Carbon dioxide
Table 3-14: CCL Emissions from Carbon Dioxide
Manufacture
Year
1990
1991
1992
1993
1994
1995
1996
MMTCE
0.2
0.2
0.2
0.2
0.2
0.3
0.3
Tg
0.8
0.8
0.9
0.9
0.9
1.0
1.1
consumption for uses other than enhanced oil recovery was
about 5.7 teragrams in 1996 (Ita 1997). The Freedonia
Group estimates that, in the United States, there is a 80 to
20 percent split between CO2 produced as a by-product and
CO2 produced from natural wells. Thus, emissions are equal
to 20 percent of CO2 consumption. The remaining 80 per-
cent was assumed to already be accounted for in the CO2
emission estimates from other categories (the most impor-
tant being Fossil Fuel Combustion).
Data Sources
Carbon dioxide consumption data (see Table 3-15)
were obtained from Freedonia Group Inc. (1994, 1996).
Data for 1996 were obtained by personal communica-
tion with Paul Ita of the Freedonia Group Inc. (1997).
Percent of carbon dioxide produced from natural wells
was obtained from Freedonia Group Inc. (1991).
Table 3-15: Carbon Dioxide Consumption
Year
1990
1991
1992
1993
1994
1995
1996
Thousand
Metric Tons
4,000
4,200
4,410
4,559
4,488
4,842
5,702
Uncertainty
Uncertainty exists in the assumed allocation of car-
bon dioxide manufactured from fossil fuel by-products
(80 percent) and carbon dioxide produced from wells
(20 percent). In addition, it is possible that CO2 recov-
ery exists in particular end-use sectors. Contact with
Industrial Processes
3-11
-------
several organizations did not provide any information
regarding recovery. More research is required to deter-
mine the quantity, if any, that may be recovered.
Iron and Steel Production
The production of iron and steel emits CO2. Iron is
produced by first reducing iron oxide (ore) with metallurgi-
cal coke in a blast furnace to produce pig iron (impure iron
of about 4 to 4.5 percent carbon by weight). Carbon diox-
ide is produced as the coke used in the process is oxidized.
Steel (less than 2 percent carbon by weight) is produced
from pig iron in a variety of specialized steel furnaces. The
majority of CO2 emissions come from the production of
iron, with smaller amounts evolving from the removal of
carbon from pig iron to produce steel.
Additional CO2 emissions also occur from the use
of limestone or dolomite flux; however, these emissions
are accounted for under Limestone and Dolomite Use.
Emissions of CO2 from iron and steel production
in 1996 were 21.6 MMTCE (79.0 Tg), falling from a
high of 23.9 MMTCE (87.6 Tg) in 1990. Emissions fluc-
tuated significantly in this period. CO2 emissions from
this source are not included in totals for the Industrial
Processes sector because these emissions are accounted
for with Fossil Fuel Combustion emissions from indus-
trial coking coal in the Energy sector.8 Emissions esti-
mates are presented here for informational purposes only
(see Table 3-16).
Table 3-16: CCL Emissions from Iron and Steel
Production
Year
1990
1991
1992
1993
1994
1995
1996
MMTCE
23.9
19.2
20.6
21.0
21.6
22.2
21.6
Tg
87.6
70.6
75.8
77.1
79.0
81.4
79.0
Methodology
Carbon dioxide emissions were calculated by multi-
plying annual estimates of pig iron production by the ratio
of CO2 emitted per unit of iron produced (1.6 metric ton
CO2/ton iron). The emission factor employed was applied
to both pig iron production and integrated pig iron plus steel
production; therefore, emissions were estimated using total
U.S. pig iron production for all uses including making steel.
Data Sources
The emission factor was taken from the Revised 1996
IPCC Guidelines QPCC/UNEP/OBCD/mA 1997). Produc-
tion datafor 1990 through 1996 (see Table 3-17) came from
the U.S. Geological Survey's (USGS) Minerals Yearbook-
Volume I-Metals and Minerals (USGS 1994, 1996).
Table 3-17: Pig Iron Production
Year Thousand Metric Tons
1990
1991
1992
1993
1994
1995
1996
54,750
44,100
47,400
48,200
49,400
50,900
49,400
Uncertainty
The emission factor employed was assumed to be
applicable to both pig iron production and integrated pig
iron plus steel production. This assumption was made
because the uncertainty in the factor is greater than the
additional emissions generated when steel is produced
from pig iron. Using plant-specific emission factors
would yield a more accurate estimate, but these factors
were not available. The most accurate alternative would
be to calculate emissions based on the amount of reduc-
ing agent used, rather than on the amount of iron or steel
produced; however, these data were also not available.
Although the CO emissions from the use of industrial coking coal as a reducing agent should be included in the Industrial Processes sector,
information to distinguish individual non-fuel uses of fossil fuels is unfortunately not available in DOE/EIA fuel statistics.
3-12
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Ammonia Manufacture
Emissions of CO2 occur during the production of
ammonia. In the United States, roughly 98 percent of
synthetic ammonia is produced by catalytic steam reform-
ing of natural gas, and the remainder is produced using
naphtha (a petroleum fraction) or the electrolysis of brine
at chlorine plants (EPA 1997). The former two fossil
fuel-based reactions produce carbon monoxide and hy-
drogen gas. (The latter reaction does not lead to CO2
emissions.) Carbon monoxide (CO) is transformed into
CO2 in the presence of a catalyst (usually a metallic ox-
ide) during the process. The hydrogen gas is diverted
and combined with nitrogen gas to produce ammonia.
The CO2, included in a gas stream with other process
impurities, is absorbed by a scrubber solution. In regen-
erating the scrubber solution, CO2 is released.
(catalyst)
4H2 + CO2
2NH
CH4 + H2O
3H + N
Emissions of CO2 from ammonia production in 1 996
were 6.6 MMTCE (24.2 Tg). For the 1990 through 1996
period, emissions fluctuated within a range of 6.3 to 6.7
MMTCE (23 . 1 to 24.4 Tg). Carbon dioxide emissions from
this source are not included in totals for the Industrial Pro-
cesses sector because these emissions are accounted for with
Fossil Fuel Combustion of natural gas in the Energy sec-
tor.9 Emissions estimates are presented here for informa-
tional purposes only (see Table 3-18).
Table 3-18: C02 Emissions from Ammonia
Manufacture
Year
1990
1991
1992
1993
1994
1995
1996
MMTCE
6.3
6.4
6.7
6.4
6.6
6.5
6.6
Tg
23.1
23.4
24.4
23.4
24.3
23.7
24.2
Methodology
Emissions of CO2 were calculated by multiplying an-
nual estimates of ammonia production by an emission fac-
tor (1.5 ton CO2/ton ammonia). It was assumed that all
ammonia was produced using catalytic steam reformation,
although small amounts may have been produced using
chlorine brines. The actual amount produced using this lat-
ter method is not known, but assumed to be small.
Data Sources
The emission factor was taken from the Revised
1996IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).
Production data (see Table 3-19) came from the Census
Bureau of the U.S. Department of Commerce (Census
Bureau 1997).
Table 3-19: Ammonia Manufacture
Year
Metric tons
1990
1991
1992
1993
1994
1995
1996
15,425,394
15,573,812
16,260,834
15,599,485
16,210,848
15,787,276
16,113,777
Uncertainty
It is uncertain how accurately the emission factor
used represents an average across all ammonia plants.
By using an alternative method of estimating emissions
from ammonia production that requires data on the con-
sumption of natural gas at each ammonia plant, more
accurate estimates could be calculated. However, these
consumption data are often considered confidential and
are difficult to acquire. All ammonia production in this
analysis was assumed to be from the same process; how-
ever, actual emissions could differ because processes
other than catalytic steam reformation may have been
used.
Although the CO emissions from the use of natural gas as a feedstock should be included in the Industrial Processes sector, information to
distinguish individual non-fuel uses of fossil fuels is unfortunately not available in DOE/EIA fuel statistics.
Industrial Processes
3-13
-------
Ferroalloy Production
Carbon dioxide is emitted from the production of
several ferroalloys. Ferroalloys are composites of iron
and other elements often including silicon, manganese,
and chromium. When incorporated in alloy steels,
ferroalloys are used to alter the material properties of the
steel. Estimates from two types of ferrosilicon (50 and
75 percent silicon) and silicon metal (about 98 percent
silicon) have been calculated. Emissions from the pro-
duction of ferrochromium and ferromanganese are not
included here because of the small number of manufac-
turers of these materials. As a result, government infor-
mation disclosure rules prevent the publication of pro-
duction data for them. Similar to emissions from the
production of iron and steel, CO2 is emitted when coke is
oxidized during a high-temperature reaction with iron
and the selected alloying element. Due to the strong re-
ducing environment, CO is initially produced. The CO
is eventually oxidized, becoming CO2. A representative
reaction equation for the production of 50 percent
ferrosilicon is given below:
2SiO2 + 7C® 2FeSi + 7CO
Emissions of CO2 from ferroalloy production in 1996
were 0.5 MMTCE (1.7 Tg). From 1990 through 1996,
emissions fluctuated within a range of 0.4 to 0.5 MMTCE
(1.5 to 1.8 Tg). Carbon dioxide emissions from this source
are not included totals for the Industrial Processes sector
because these emissions are accounted for in the calcula-
tions of industrial coking coal combustion under the En-
ergy sector.10 Emission estimates are presented here for
informational purposes only (see Table 3-20).
Methodology
Emissions of CO2 were calculated by multiplying
annual estimates of ferroalloy production by material-
specific emission factors. Emission factors were applied
to production data for ferrosilicon 50 and 75 percent (2.35
and 3.9 metric ton CO2/metric ton, respectively) and sili-
con metal (4.3 metric ton CO2/metric ton). It was as-
sumed that all ferroalloy production was produced using
coking coal, although some ferroalloys may have been
produced with wood, biomass, or graphite carbon inputs.
Data Sources
Emission factors were taken from the Revised 1996
IPCC Guidelines QPCC/WEP/OECD/IEA1997). Produc-
tion datafor 1990 through 1996 (see Table 3-21) came from
the Minerals Yearbook: Volume I—Metals and Minerals
published in USGS (1991, 1992, 1993, 1994, 1995, 1996,
1997).
Table 3-21: Production of Ferroalloys (Metric Tons)
Fe2O3
Ferrosilicon
Year
1990
1991
1992
1993
1994
1995
1996
50%
321,385
230,019
238,562
199,275
198,000
181,000
182,000
75%
109,566
101,549
79,976
94,437
112,000
128,000
132,000
Silicon
Metal
145,744
149,570
164,326
158,000
164,000
163,000
175,000
Table 3-20: C02 Emissions from Ferroalloy
Production
Year
MMTCE
10
Uncertainty
Although some ferroalloys may be produced us-
ing wood or biomass as a carbon source, information
and data regarding these practices were not available.
Emissions from ferroalloys produced with wood would
not be counted under this source because wood-based
carbon is of bio genie origin.u Emissions from ferroalloys
produced with graphite inputs would be counted in na-
tional totals, but may generate differing amounts of CO2
per unit of ferroalloy produced compared to the use of
coking coal. As with emissions from iron and steel pro-
duction, the most accurate method for these estimates
would be basing calculations on the amount of reducing
Although the CO emissions from the use of industrial coking coal as a reducing agent should be included in the Industrial Processes
1990
1991
1992
1993
1994
1995
1996
0.5
0.4
0.4
0.4
0.4
0.4
0.5
1.8
1.6
1.6
1.5
1.6
1.6
1.7
sector, information to distinguish individual non-fuel uses of fossil fuels is unfortunately not available in DOE/EIA fuel statistics.
Emissions and sinks of biogenic carbon are accounted for under the Land-Use Change and Forestry sector.
3-14
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
agent used in the process, rather than on the amount of
ferroalloys produced. Again, these data were unavail-
able.
Petrochemical Production
Small amounts of methane (CH4) are released dur-
ing the production of petrochemicals. Emissions are cal-
culated here from the production of five chemicals: car-
bon black, ethylene, ethylene dichloride, styrene, and
methanol. Emissions of CH4 from petrochemical pro-
duction in 1996 were 0.4 MMTCE (73 Gg), or 0.2 per-
cent of U.S. CH4 emissions (see Table 3-22). Production
levels of all five chemicals increased from 1990 to 1996.
Table 3-22: CH4 Emissions from Petrochemical
Production
Year
1990
1991
1992
1993
1994
1995
1996
MMTCE
0.3
0.3
0.3
0.4
0.4
0.4
0.4
Gg
55
57
60
65
70
70
73
Methodology
Emissions of CH4 were calculated by multiplying
annual estimates of chemical production by an emission
factor. The following factors were used: 11 kg CH4/
metric ton carbon black, 1 kg CH4/metric ton ethylene,
0.4 kg CH4/metric ton ethylene dichloride, 4 kg CH4/met-
ric ton styrene, and 2 kg CH4/metric ton methanol. These
emission factors were based upon measured material bal-
ances. Although the production of other chemicals may
also result in methane emissions, there were not suffi-
cient data to estimate their emissions.
Data Sources
Emission factors were taken from the Revised 1996
IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). An-
nual production data (see Table 3-23) came from the
Chemical Manufacturers Association Statistical Hand-
book (CMA 1997).
Uncertainty
The emission factors used here were based on a
limited number of studies. Using plant-specific factors
instead of average factors would increase the accuracy
of the emissions estimates, however, such data were not
available. There may also be other significant sources of
methane arising from chemical production activities
which have not been included in these estimates.
Silicon Carbide Production
Methane is emitted from the production of silicon
carbide, a material used as an industrial abrasive. To
make silicon carbide (SiC), quartz (SiO2) is reacted with
carbon in the form of petroleum coke. Methane is pro-
duced during this reaction from volatile compounds in
the petroleum coke. Although CO2 is also emitted from
this production process, the requisite data were unavail-
able for these calculations. Regardless, they are already
accounted for under CO2 from Fossil Fuel Combustion
in the Energy sector. Emissions of CH4 from silicon car-
bide production in 1996 (see Table 3-24) were less than
0.1 MMTCE (1 Gg).
Methodology
Emissions of CH4 were calculated by multiplying
annual estimates of silicon carbide productionby an emis-
sion factor (11.6 kg CH4/metric ton silicon carbide). This
emission factor was derived empirically from measure-
Table 3-23: Production of Selected Petrochemicals (Metric Tons)
Chemical
Carbon Black
Ethylene
Ethylene Dichloride
Styrene
Methanol
1990
1,306,368
16,541,885
6,282,360
3,636,965
3,784,838
1991
1,224,720
18,124,042
6,220,670
3,680,510
3,948,134
1992
1,365,336
18,563,126
6,872,040
4,082,400
3,665,995
1993
1,451,520
18,382,594
8,141,213
4,565,030
4,781,851
1994
1,492,344
20,200,622
8,482,320
5,112,072
4,904,323
1995
1,524,096
19,470,326
7,830,950
5,166,504
5,122,958
1996
1,560,384
20,343,960
8,595,720
5,386,954
5,261,760
Industrial Processes
3-15
-------
Table 3-24: CH4 Emissions from Silicon Carbide
Production
Year
1990
1991
1992
1993
1994
1995
1996
MMTCE Gg
+ 1
+ 1
+ 1
+ 1
+ 1
+ 1
+ 1
+ Does not exceed 0.05 MMTCE
ments taken at Norwegian silicon carbide plants (IPCC/
UNEP/OECD/IEA 1997).
Data Sources
The emission factor was taken from the Revised
1996IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).
Production data for 1990 through 1996 (see Table 3-25)
came from the Minerals Yearbook: Volume I-Metals and
Minerals published in USGS (1991, 1992, 1993, 1994,
1995, 1996, 1997).
Table 3-25: Production of Silicon Carbide
Year Metric Tons
1990
1991
1992
1993
1994
1995
1996
105,000
78,900
84,300
74,900
84,700
75,400
73,600
Uncertainty
The emission factor used here was based on one
study of Norwegian plants. The applicability of this fac-
tor to average U.S. practices at silicon carbide plants is
uncertain. The most accurate 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. Again, these
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 poly-
esters. Ninety percent of all adipic acid produced in the
United States is used in the production of nylon 6,6. It is
also used to provide some foods with a "tangy" flavor.
Adipic acid is produced through a two-stage pro-
cess during which N2O is generated in the second stage.
This second stage involves the oxidation of ketone-alco-
hol with nitric acid. Nitrous oxide is generated as a by-
product of this reaction and is emitted in the waste gas
stream. In the United States, this waste gas is treated to
remove nitrogen oxides (NOx), other regulated pollut-
ants, and in some cases N2O. There are currently four
plants in the United States that produce adipic acid. Since
1990, two of these plants have employed emission con-
trol measures destroying roughly 98 percent of the N2O
in their waste gas stream before it is released to the at-
mosphere (Radian 1992). It is expected that all adipic
acid production plants will have N2O emission controls
in place and operating by the end of 1997, as a result of
a voluntary agreement among producers.
Adipic acid production for 1996 was estimated to be
835 thousand metric tons. Nitrous oxide emissions from
this source were estimated to be 5.4 MMTCE for 1996, or 5
percent of U.S. N2O emissions (see Table 3-26).
Adipic acid production reached its highest level in
twelve years in 1996, growing about 2 percent from the
previous year. Though production may continue to in-
crease in the future, emissions should follow a signifi-
cantly different path by the end of 1997, due to the wide-
spread installation of pollution control measures men-
tioned above.
Table 3-26: N20 Emissions from Adipic Acid
Manufacture
Year
MMTCE
UclUl WC1C UllclVcUlclUlC.
Adipic Acid Production
Adipic acid production has been identified as a sig-
nificant anthropogenic source of nitrous oxide (N?O)
emissions. Adipic acid is a white crystalline solid used
1990
1991
1992
1993
1994
1995
1996
4.7
4.9
4.6
4.9
5.2
5.2
5.4
56
58
54
58
62
62
63
3-16
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Methodology
Nitrous oxide emissions were calculated by multi-
plying adipic acid production by the ratio of N2O emit-
ted per unit of adipic acid produced and adjusting for the
actual percentage of N2O released as a result of plant
specific emission controls. Because emissions of N2O in
the United States are not regulated, emissions have not
been well characterized. However, on the basis of ex-
periments (Thiemens and Trogler 1991), the overall re-
action stoichiometry for N2O production in the prepara-
tion of adipic acid was estimated at approximately 0.3
kg of N2O per kilogram of product.
Data Sources
Adipic acid production data for 1990 through 1995
(see Table 3-27) were obtained from Chemical and En-
gineering News, "Facts and Figures" and "Production of
Top 50 Chemicals" (C&EN 1992, 1993, 1994, 1995,
1996). The 1996 data were projected from the 1995
manufactured total based upon suggestions of industry
contacts. The emission factor was taken from Thiemens,
M.H. and W.C. Trogler (1991).
Table 3-27: Adipic Acid Manufacture
Year Thousand Metric Tons
1990
1991
1992
1993
1994
1995
1996
735
771
708
765
815
816
835
adipic acid production data used to derive the emission
estimates as it is necessary to assume that all plants op-
erate at equivalent utilization levels.
The emission factor 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.
Nitric Acid Production
Nitric acid (HNO3) is an inorganic compound used
primarily to make synthetic commercial fertilizer. 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 manufac-
tured 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. While
the waste gas stream may be cleaned of other pollutants
such as nitrogen dioxide, there are currently no control
measures aimed at eliminating N2O.
Nitric acid production reached 8,252 thousand
metric tons in 1996 (C&EN 1997). Nitrous oxide emis-
sions from this source were estimated at 3.8 MMTCE,
accounting for approximately 4 percent of U.S. N2O emis-
sions (see Table 3-28). Nitric acid production for 1996
increased 3 percent from the previous year, or 12 per-
cent since 1990.
Uncertainty
Because N2O emissions are controlled in some adi-
pic acid production facilities, the amount of N2O that is
actually released will depend on the level of controls in
place at a specific production plant. Thus, in order to
calculate accurate emission estimates, it is necessary to
have production data on a plant-specific basis. In most
cases, however, these data are confidential. As a result,
plant-specific production figures were estimated by al-
locating total adipic acid production using existing plant
capacities. This creates a degree of uncertainty in the
Table 3-28: N20 Emissions from Nitric Acid
Manufacture
Year
1990
1991
1992
1993
1994
1995
1996
MMTCE
3.4
3.3
3.4
3.5
3.7
3.7
3.8
Gg
40
40
40
41
44
44
45
Industrial Processes
3-17
-------
Methodology
Nitrous oxide emissions were calculated by multi-
plying nitric acid production by the amount of N2O emit-
ted per unit of nitric acid produced. Off-gas measure-
ments at one nitric acid production facility showed N2O
emission rates to be approximately 2 to 9 g N2O per kg
of nitric acid produced (Reimeretal. 1992). In calculat-
ing emissions, the midpoint of this range was used (5.5
kg N2O/metric ton HNO3).
Data Sources
Nitric acid production data for 1990 through 1996
(see Table 3-29) were obtained from Chemical and En-
gineering News, "Facts and Figures" and "Production of
Top 50 Chemicals" (C&EN 1992, 1993, 1994, 1995,
1996). The emission factor range was taken from Reimer,
R.A., Parrett, R.A., and Slaten, C.S. (1992).
Table 3-29: Nitric Acid Manufacture
Year Thousand Metric Tons
1990
1991
1992
1993
1994
1995
1996
7,257
7,189
7,298
7,488
8,005
8,023
8,252
Uncertainty
These emission estimates are highly uncertain due
to a lack of information on manufacturing processes and
emission controls. Although no abatement techniques
are specifically directed at removing N2O at nitric acid
plants, existing control measures for other pollutants may
have some impact upon N2O emissions. The emission
factor range of 2 to 9 g N2O per kg of nitric acid pro-
duced is significant, leading to further uncertainty when
applying the midpoint value.
Substitution of Ozone
Depleting Substances
Hydrofluorocarbons (HFCs) and perfluorocarbons
(PFCs) are used primarily 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 199012. Ozone depleting
substances—chlorofluorocarbons (CFCs), halons, carbon
tetrachloride, methyl chloroform, and hydrochloro-
fluorocarbons (HCFCs)—are used in a variety of industrial
applications including refrigeration and air conditioning
equipment, solvent cleaning, foam production, sterilization,
fire extinguishing, and aerosols. AlthoughHFCs andPFCs,
unlike ODSs, are not harmful to the stratospheric ozone
layer, they are powerful greenhouse gases. Emission
estimates for HFCs and PFCs used as substitutes for ODSs
are provided in Table 3-30 and Table 3-31.
In 1990 and 1991, the only significant emissions
of HFCs and PFCs as substitutes to ODS were relatively
small amounts of HFC-152a—a component of the re-
frigerant 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-40413. In 1993, use of HFCs in foams and aerosols
began, and in 1994 these compounds also found appli-
cations as solvents and sterilants. In 1995, ODS substi-
tutes 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 increased dramatically, from
small amounts in 1990, to 11.9 MMTCE in 1996. This
increase was the result of efforts to phase-out CFCs and
other ODSs in the United States. This trend is expected
to continue for many years, and will accelerate in the
early part of the next century as HCFCs, which are in-
terim substitutes in many applications, are themselves
phased-out under the provisions of the Copenhagen
Amendments to the Montreal Protocol.
12 [42 U.S.C § 7671, CAA § 601]
13
R-404 contains HFC-125, HFC-143a, and HFC-134a.
3-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 3-30: Emissions of MFCs and PFCs from ODS Substitution (MMTCE)
Gas
HFC-23
HFC-125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
C4F10
PFC/PFPEs*
Total
1990 1991 1992 1993 1994
+ + + + +
+ + 0.2 0.4 1.2
0.2 0.2 0.2 1.0 1.9
+ + + + +
0.1 + + + +
+ + + + 0.7
+ + + + +
+ + + + +
+ + + + +
+ + + + 0.1
0.3 0.2 0.4 1.4 4.0
1995
+
2.2
3.4
0.1
+
1.5
+
0.2
+
2.0
9.5
1996
0.1
2.4
4.8
0.2
+
1.6
0.1
0.4
0.1
2.0
11.9
+ Does not exceed 0.05 MMTCE
* PFC/PFPEs are a proxy for a diverse collection of PFCs and perfluoropolyethers (PFPEs) employed for solventapplications. For estimating
purposes, the GWP value used was based upon C6F14.
Note: Totals may not sum due to independent rounding.
Table 3-31: Emissions of MFCs and PFCs from ODS Substitution (Mg)
Gas
1990
1991
1992
1993
1994
1995
1996
HFC-23
HFC-125
HFC-134a
HFC-1433
HFC-1523
HFC-22763
HFC-236f3
HFC-4310mee
C F
C6F"
PFC/PFPEs*
+ + + +
+ + 236 481
564 564 626 2,885
+ + + 12
1,500 750 313 694
+ + + +
+ + + +
+ + + +
+ + + +
+ + + +
+ + + +
+
1,628
5,410
43
833
894
+
+
+
+
33
9
2,823
9,553
94
981
1,895
+
611
22
2
990
26
3,172
13,605
226
1,085
2,063
79
1,030
64
6
990
+ Does not exceed 0.5 Mg
* PFC/PFPEs are a proxy for a diverse collection of PFCs and perfluoropolyethers (PFPEs) employed for solvent
applications.
Methodology and Data Sources
The EPA used a detailed vintaging model of ODS-
containing equipment and products to estimate the use
and 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 vari-
ous compounds for the annual "vintages" of new equip-
ment 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. By
aggregating the data for more than 40 different end-uses,
the model produces estimates of annual use and emis-
sions of each compound.
The major end-use categories defined in the
vintaging model to characterize ODS use in the United
States were: refrigeration and air conditioning, aerosols,
solvent cleaning, fire extinguishing equipment, steriliza-
tion, and foams.
Industrial Processes
3-19
-------
The vintaging model estimates HFC and PFC use
and emissions resulting from their use as replacements
for ODS by undertaking the following steps:
Step 1: Estimate ODS Use in the United States
Prior to Phase-out Regulations
The model begins by estimating chlorofluorocar-
bon (CFC), halon, methyl chloroform, and carbon tetra-
chloride use prior to the restrictions on the production of
these compounds in the United States. For modeling
purposes, total ODS use was divided into more than 40
separate end-uses. The methodology used to estimate
baseline ODS use varied depending on the end-use un-
der consideration. The next section describes the meth-
odology used for estimating baseline ODS use in the re-
frigeration, air conditioning, and fire extinguishing
(halon) sectors. The subsequent section details the meth-
odology used for all other end-uses.
Step 1.1: Estimate Baseline ODS Use for
Refrigeration, Air Conditioning, and Fire
Extinguishing
For each equipment type, the model estimates the
total stock of ODS-containing equipment during the pe-
riod 1985 to 1996. The key data required to develop
stock estimates for each end-use were as follows:
• Total stock of ODS-containing equipment in use in
the United States in 1985
• The annual rate of growth in equipment consump-
tion in each end-use
• The retirement function for equipment in each
end-use
Historical production and consumption data were
collected for each equipment type to develop estimates
of total equipment stock in 1985. For some end-uses,
the only data available were estimates of ODS usage. In
these cases, the total 1985 stock was estimated by divid-
ing total ODS use by the average charge of ODS in a
typical piece of equipment.
Stocks of ODS-containing equipment change over
time. In the vintaging model, the growth in equipment
stocks in each end-use was simulated after 1985 using
growth rates that define the total number of pieces of
new equipment added to the stock each year. The model
also uses a retirement function to calculate the length of
time each piece of equipment is expected to remain in
service. These retirement functions are a critical part of
the vintaging model because they determine the speed at
which the stock of equipment turns over and is replaced
by new equipment. In this analysis, point estimates of
the average lifetime of equipment in each end-use were
used to develop retirement functions. These retirement
functions assume 100 percent survival of equipment up
to this average age and zero percent survival thereafter.
Given these data, the total equipment stock in ser-
vice in a given year / was estimated as the equipment
stock in the year (M), plus new equipment added to the
stock in year /, minus retirements in year t.
Annual ODS use was then estimated for each equip-
ment type during the period 1985 through 1996. Be-
cause control technologies can reduce particular kinds
of ODS use, use estimates were broken down by type of
use (e.g., use in new equipment at manufacture and use
required to maintain existing equipment). Baseline esti-
mates of ODS use were based on the following data col-
lected for each equipment type:
• ODS charge size (Refers to the number of kilograms
of ODS installed in new equipment during manu-
facture)
• ODS required to maintain existing equipment (In
many end-uses, ODS must be regularly added to
equipment to replace chemical emitted from the
equipment. Such emissions result from normal leak-
age and from loss during servicing of the equipment.)
With these data, ODS usage for each refrigeration,
air conditioning, and fire extinguishing end-use was cal-
culated using the following equation:
(Total stock of existing equipment in use) X (ODS
required to maintain each unit of existing equipment) +
(New equipment additions) X (ODS charge size)
Step 1.2: Estimate Baseline ODS Use in Foams,
Solvents, Sterilization, and Aerosol End-Uses
For end-uses other than refrigeration, air condition-
ing, and fire extinguishing, a simpler approach was used
because these end-uses do not require partial re-filling
of existing equipment each year. Instead, such equip-
ment either does not require any ODS after initial pro-
duction (e.g., foams and aerosols), or requires complete
3-20
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
re-filling or re-manufacturing of the equipment eachyear
(e.g., solvents and sterilants). ODS use does not need to
be differentiated between new and existing equipment
for these end-uses. Thus, it is not necessary to track the
stocks of new and existing equipment separately over
time.
The approach used for these end-uses was to esti-
mate total ODS use in 1985 based on available industry
data. Future OD S use was estimated using growth rates
that predict ODS consumption growth in these end-uses
over time, based upon input from industry.
Step 2: Specification and Implementation of
Control Technologies
Having established a baseline for ODS equipment
in 1985, the vintaging model next defines controls that
may be undertaken for purposes of reducing ODS use
and emissions within each end-use. The following con-
trols are implemented in the model:
• Replacement of ODS used in the manufacturing of
new equipment or in the operation of existing equip-
ment (i.e., retrofits) with alternative chemicals, such
as HFCs and PFCs
• Replacement of ODS-based processes or products
with alternative processes or products (e.g., the use
of aqueous cleaning to replace solvent cleaning with
CFC-113)
• Modification of the operation and servicing of
equipment to reduce use and emission rates through
the application of engineering and recycling con-
trols
Assumptions addressing these types of controls in
each end-use were used to develop "substitution sce-
narios" that simulate the phase-out of ODSs in the United
States by end-use. These scenarios represent EPA's best
estimates of the use of control technologies towards the
phase-out ODS in the United States, and are periodically
reviewed by industry experts.
In addition to the chemical substitution scenarios, the
model also assumes that a portion of ODS substitutes are
recycled during servicing and retirement of the equipment.
Recycling is assumed to occur in the refrigeration and air
conditioning, fire extinguishing, and solvent end-uses.
The substitution scenarios defined for each equip-
ment type were applied to the relevant equipment stocks.
The equipment life-cycle was then simulated after the
imposition of controls. Substitute chemical use and emis-
sions—including HFCs and PFCs—were calculated for
each scenario using the methods described below.
Step 3: Estimate ODS Substitute Use and
Emissions (HFCs and PFCs)
ODS substitute use (i.e., HFC and PFC use) was
calculated using the same routine described above for
refrigeration, air conditioning, and fire extinguishing
equipment. In terms of chemical usage, a key question
was whether implementation of a given ODS substitute
in an end-use changed the quantity of chemical required
to manufacture new equipment or service existing equip-
ment. In this analysis, it was assumed that the use of
ODS alternatives in new equipment—including HFCs and
PFCs—did not change the total charge of initial chemi-
cal used in the equipment in each end-use. For certain
refrigeration and air conditioning end-uses, however, it
was assumed that new equipment manufactured with
HFCs and PFCs would have lower leak rates than older
equipment. Existing ODS-containing equipment that was
retrofitted with HFCs or PFCs was assumed to have a
higher leak rate than new HFC/PFC equipment.
The use of HFCs and PFCs in all other sectors was
calculated by simply replacing OD S use with the chemi-
cal alternatives defined in the substitution scenarios. The
use of HFCs and PFCs was not assumed to change the
quantity of chemical used in new or existing equipment
for these sectors.
The vintaging model estimates HFC and PFC emis-
sions over the lifetime of equipment in each end-use.
Emissions may occur at the following points in the life-
time of the equipment:
• Emissions upon manufacture of equipment
• Annual emissions from equipment (due to normal leak-
age, and if applicable, servicing of equipment)
• Emissions upon retirement of equipment
The emissions that occur upon manufacture of re-
frigeration and air conditioning equipment were assumed
to be less than 0.1 percent. Annual emissions of HFCs and
Industrial Processes
3-21
-------
PFCs from equipment—due to normal leakage and servic-
ing—were assumed to be constant each year over the life of
the equipment. The quantity of emissions at disposal is a
function of the prevalence of recycling at disposal.
Emissions for open cell foam were assumed to be
100 percent in the year of manufacture. Closed cell foams
were assumed to emit a portion of total HFC/PFC use upon
manufacture, a portion at a constant rate over the lifetime of
the foam, and the rest at disposal. There were no foam
recycling technologies in use in the United States; there-
fore, HFCs and PFCs remaining in closed cell foam were
assumed to be emitted by the end of the product lifetime.
Emissions were assumed to occur at manufacture,
during normal operation, and upon retirement of fire ex-
tinguishing systems. Emissions at manufacture were as-
sumed to be negligible and emissions upon disposal were
assumed to be minimal because of the use of recovery
technologies.
For solvent applications, 15 percent of the chemi-
cal used in equipment was assumed to be emitted in that
year. The remainder of the used solvent was assumed to
be disposed rather than emitted or recycled.
For sterilization applications, all chemicals that
were used in the equipment were assumed to be emitted
in that year.
All HFCs and PFCs used in aerosols were assumed
to be emitted in the same year. No technologies were
known to exist that recycle or recover aerosols.
Uncertainty
Given that emissions of ODS substitutes occur from
thousands of different kinds of equipment and from mil-
lions of point and mobile sources throughout the United
States, emission estimates must be made using analyti-
cal tools such as the EPA vintaging model or the meth-
ods outlined in IPCC/UNEP/OECD/IEA (1997). Though
EPA's model is more comprehensive than the IPCC meth-
odology, significant uncertainties still exist with regard
to the levels of equipment sales, equipment characteris-
tics, and end-use emissions profiles that were used to
estimate annual emissions for the various compounds.
Aluminum Production
Aluminum is a light-weight, malleable, and corro-
sion resistant metal that is used in many manufactured
products including aircraft, automobiles, bicycles, and
kitchen utensils. The United States was the largest pro-
ducer with 17 percent of the world total in 1996 (USGS
1997). The United States was also a major importer. The
production of aluminum—in addition to consuming large
quantities of electricity—results in emissions of several
greenhouse gases including carbon dioxide (CO2) and
two perfluorocarbons (PFCs): perfluoromethane (CF4)
and perfluoroethane (C2F6).
Occasionally, sulfur hexafluoride (SF6) is also used
by the aluminum industry as a degassing agent in spe-
cialized applications. In these cases it is mixed with ar-
gon and nitrogen and blown through molten aluminum
as it cools; however, this practice is not know to be used
by firms in the United States. Where it does occur in
other countries, the concentration of SF6 in the mixture
is small and it is believed that nearly all the SF6 is de-
stroyed in the process.
Carbon dioxide is emitted during the aluminum
smelting process when alumina (aluminum oxide, A12O3)
is reduced to aluminum using the Hall-Heroult reduc-
tion process. The reduction of the alumina occurs through
electrolysis in a molten bath of natural or synthetic cryo-
lite (Na3AlF6). The reduction cells contain a carbon lin-
ing that serves as the cathode. Carbon is also contained
in the anode, which can be a carbon mass of paste, coke
briquettes, or prebaked carbon blocks from petroleum
coke. During reduction, some of this carbon is oxidized
and released to the atmosphere as CO2.
Process emissions of CO2 from aluminum produc-
tion were estimated at 1.4 MMTCE (5.3 Tg) in 1996 (see
Table 3-32). The CO2 emissions from this source, how-
ever, are accounted for under the non-fuel use portion of
CO2 from Fossil Fuel Combustion of petroleum coke and
tar pitch in the Energy sector. Thus, to avoid double
counting, CO2 emissions from aluminum production are
not included in totals for the Industrial Processes sector.
They are described here for informational purposes only.
3-22
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 3-32:
Production
Year
1990
1991
1992
1993
1994
1995
1996
C02 Emissions from Aluminum
MMTCE
1.6
1.7
1.6
1.5
1.3
1.4
1.4
Tg
6.0
6.1
5.9
5.4
4.8
5.0
5.3
Table 3-34: RFC Emissions from Aluminum
Production (Mg)
In addition to CO2 emissions, the aluminum pro-
duction industry was also the largest source of PFC emis-
sions in the United States. During the smelting process,
when the alumina ore content of the electrolytic bath falls
below critical levels required for electrolysis, rapid volt-
age increases occur, termed "anode effects". These an-
ode 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. The more frequent and long-lasting
the anode effects, the greater the emissions.
Primary aluminum production related emissions of
PFCs are estimated to have declined from 4.3 MMTCE
of CF4 (2,430 Mg) and 0.6 MMTCE of C2F6 (240 Mg) in
1990 to 2.5 MMTCE of CF4 (1,430 Mg) and 0.4 MMTCE
of C2F6 (140 Mg) in 1996, as shown in Table 3-33 and
Table 3-34. The overall decline in PFC emissions is es-
timated to have been 40 percent. This decline was both
due to reductions in domestic aluminum production and
actions taken by aluminum smelting companies to re-
duce the frequency and duration of anode effects under
EPA's Voluntary Aluminum Industrial Partnership
Table 3-33: PFC Emissions from Aluminum
Production (MMTCE)
Year
1990
1991
1992
1993
1994
1995
1996
CF
4
2,430
2,330
2,020
1,750
1,400
1,330
1,430
CF
2 6
240
230
200
170
140
130
140
(VAIP).
U.S. primary aluminum production for 1996, to-
taling 3,577 thousand metric tons, increased by 6 per-
cent from 1995 to 1996. Production fell to a seven-year
low in 1994, continuing a decline which started in 1991.
These declines were due in part to a continued increase
in imports, primarily from the former Soviet Union. For
example, in 1994 these countries exported 60 percent
more ingots (metal cast for easy transformation) to the
United States than in 1993. However, the U.S. Geologi-
cal Survey (USGS) reported that this supply surplus
would be temporary and that a more normal global sup-
ply and demand equilibrium should return beginning in
1995. Data for 1995 and 1996 appear to support this
assessment. U.S. imports for consumption of aluminum
materials decreased in 1996 compared with those of the
previous year. Although imports from Russia continued
to decline from their peak level in 1994, Russia remained
the second largest source of imports (USGS 1997).
The transportation industry remained the largest
domestic consumer of aluminum, accounting for about
28 percent (USGS 1997). The "big three" automakers
have announced new automotive designs that will ex-
pand the use of aluminum materials in the near future.
USGS believes that demand for and production of alu-
minum should continue to increase.
Year
1990
1991
1992
1993
1994
1995
1996
Note:
CF
4
4.3
4.1
3.6
3.1
2.5
2.4
2.5
Totals may not sum due to
CF
2 6
0.6
0.6
0.5
0.4
0.4
0.3
0.4
independent rounding.
Total
4.9
4.7
4.1
3.5
2.8
2.7
2.9
Methodology
Carbon dioxide is released to the atmosphere dur-
ing alumina reduction to aluminum metal following the
reaction below:
2A12O3 + 3C ® 4A1 + 3CO2
The quantity of CO2 released was estimated from
Industrial Processes
3-23
-------
the production volume of primary aluminum metal and
the carbon consumed by the process. During alumina
reduction, approximately 1.5 to 2.2 metric tons of CO2
are emitted for each metric ton of aluminum produced
(Abrahamson 1992). In previous inventories, the mid-
point (1.85) of this range was used for the emission fac-
tor. However, for this year's report—and adjusting ear-
lier years—the emission factor was revised to 1.5 metric
tons CO2 per metric ton of aluminum smelted based on a
mass balance for a "typical" aluminum smelter (Drexel
University Project Team 1996). This value is at the low
end of the Abrahamson (1992) range.
The CO2 emissions from this source are already
accounted for under CO2 Emissions from Fossil Fuel
Combustion in the Energy sector.14 Thus, to avoid double
counting, CO2 emissions from aluminum production are
not included in totals for the Industrial Processes sector.
PFC emissions from aluminum production were
estimated using a per unit production emission factor for
the base year 1990. The emission factor used is a func-
tion of several operating variables including average an-
ode effect frequency and duration. Total annual emis-
sions for 1990 were then calculated based on reported
annual production levels. The five components of the
per unit production emission factor are:
• Amount of CF4 and C2F6 emitted during every minute
of an anode effect, per ampere of current
Average duration of anode effects
Average frequency of anode effects
Current efficiency for aluminum smelting
Current required to produce a metric ton of alumi-
num, assuming 100 percent efficiency
Using available data for the United States, this meth-
odology yields a range in the emission factor of 0.01 to 1.2
kg CF4 per metric ton of aluminum produced in 1990 (Jacobs
1994). The emission factor for C2F6 was estimated to be
approximately an order of magnitude lower. Emissions for
1991 through 1996 were estimated with emission factors
that incorporated data on reductions in anode effects re-
ported to the VAIP by aluminum companies.
Data Sources
Production data for 1990 through 1996 (see
Table 3-35) were obtained from USGS, Mineral Indus-
try Surveys: Aluminum Annual Report (USGS 1997,
1995). The USGS requested data from the 13 domestic
producers, all of whom responded. The CO2 emission
factor range was taken from Abrahamson (1992). The
mass balance for a "typical" aluminum smelter was taken
from Drexel University Project Team (1996).
PFC emission estimates were provided by the EPA's
Atmospheric Pollution Prevention Division in coopera-
Table 3-35: Production of Primary Aluminum
Year Thousand Metric Tons
1990
1991
1992
1993
1994
1995
1996
4,048
4,121
4,042
3,695
3,299
3,375
3,577
tion with participants in the Voluntary Aluminum Indus-
trial Partnership.
Uncertainty
Uncertainty exists as to the most accurate CO2
emission factor for aluminum production. Emissions vary
depending on the specific technology used by each plant.
However, evidence suggests that there is little variation
in CO2 emissions from plants utilizing similar technolo-
gies (IPCC/UNEP/OECD/IEA 1997). A less uncertain
method would be to calculate emissions based upon the
amount of carbon—in the form of petroleum coke or tar
pitch—consumed by the process; however, this type of
information was not available.
Although the carbon contained in the anode is considered a non-fuel use of petroleum coke or tar pitch and should be included in the
Industrial Processes sector, information to distinguish individual non-fuel uses of fossil fuels is unfortunately not available in DOE/EIA fuel
statistics.
3-24
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
For PFC emission estimates, the value for emis-
sions per anode effect minute per ampere was based on a
limited number of measurements that may not be repre-
sentative of the industry as a whole (EPA 1993). For
example, the emission factor may vary by smelter tech-
nology type, among other factors. The average frequency
of anode effects and the current efficiency are well docu-
mented; however, insufficient measurement data existed
to quantify a relationship between PFC emissions and
anode effect minutes. Future inventories will incorpo-
rate additional data reported to VAIP by aluminum com-
panies and ongoing research into PFC emissions from
aluminum production.
HCFC-22 Production
Trifluoromethane (HFC-23 or CHF3) is generated
as a by-product during the manufacturing of chloro-
difluoromethane (HCFC-22), which is currently used
both as a substitute for ozone depleting substances—
mainly in refrigeration and air conditioning systems—
and as a chemical feedstock for manufacturing synthetic
polymers. Although HCFC-22 production is scheduled
to be phased out by 2020 under the U.S. Clean Air Act15
because of its stratospheric ozone depleting properties,
feedstock production is permitted to continue indefinitely.
Emissions of HFC-23 in 1996 were estimated to
be 8.5 MMTCE (2,660 Mg). This represents over a 10
percent decline from emissions in 1990 (see Table 3-36).
In the future, production of HCFC-22 is expected
Table 36: HFC-23 Emissions from HCFC-22
Production
Year
MMTCE
Mg
1990
1991
1992
1993
1994
1995
1996
9.5
8.4
9.5
8.7
8.6
7.4
8.5
2,980
2,630
2,980
2,730
2,700
2,320
2,660
to initially increase in the United States and then decline
as non-feedstock HCFCs production is phased-out; feed-
stock production is anticipated to continue growing
steadily, mainly for manufacturing Teflon0 and other
chemical products. All U.S. producers of HCFC-22 are
participating in a voluntary program with the EPA to re-
duce HFC-23 emissions.
Methodology
EPA studied the conditions of HFC-23 generation,
methods for measuring emissions, and technologies for
emissions control. This effort was undertaken in coop-
eration with the manufacturers of HCFC-22.
Previous emission estimates assumed that HFC-23
emissions were between 2 and 4 percent of HCFC-22
production on a mass ratio basis. The methodology em-
ployed for this year's inventory was based upon mea-
surements of critical feed components at individual
HCFC-22 production plants. Individual producers also
measured HFC-23 concentrations in the process stream
by gas chromatography. Using measurements of feed
components and HFC-23 concentrations in process
streams, the amount of HFC-23 generated was estimated.
HFC-23 concentrations were determined at the point the
gas leaves the chemical reactor; therefore, estimates also
include fugitive emissions.
Data Sources
Emission estimates were provided by the EPA's
Atmospheric Pollution Prevention Division in coopera-
tion with the U.S. manufacturers of HCFC-22.
Uncertainty
A high level of confidence has been attributed to
the HFC-23 concentration data employed because mea-
surements were conducted frequently and accounted for
day-to-day and process variability. It is estimated that
the emissions reported are within 20 percent of the true
value. This methodology allowed for determination of
reductions in HFC-23 emissions during a period of in-
creasing HCFC-22 production. (Use of emission factors
would not have allowed for such an assessment.) By
15
As construed, interpreted and applied in the terms and conditions of the Montreal Protocol on Substances that Deplete the Ozone Layer.
[42 U.S.C. §7671m(b), CAA §614]
Industrial Processes
3-25
-------
1996, the rate of HFC-23 generated as a percent of HCFC-
22 produced dropped, on average, below 2 percent in the
United States.
Semiconductor Manufacture
The semiconductor industry uses multiple long-
lived fluorinated gases in plasma etching and chemical
vapor deposition (CVD) processes. The gases most com-
monly employed are trifluoromethane (HFC-23),
perfluoromethane (CF4), perfluoroethane (C2F6), and sul-
fur hexafluoride (SF6), although other compounds such
as nitrogen trifluoride (NF3) andperfluoropropane (C3F8)
are also used. The exact combination of compounds is
specific to the process employed.
For 1996, it was estimated that total weighted emis-
sions of all greenhouse gases by the U.S. semiconductor
industry was 1.3 MMTCE. These gases were not widely
used in 1990, hence, emissions in 1990 were estimated to
Table 3-37: RFC Emissions from Semiconductor
Manufacture
Year
MMTCE*
1990
1991
1992
1993
1994
1995
1996
0.2
0.4
0.6
0.8
1.0
1.2
1.4
* Combined radiative forcing effect of all gases
be only 0.2 MMTCE. Combined emissions of all gases are
presented in Table 3-37 below. It is expected that the rapid
growth of this industry and the increasing complexity of
microchips will increase emissions in the future.
Methodology
An estimate of emissions was developed based on
the approximate sales of the four main gases (HFC-23,
CF4, C2F6, and SF6) to semiconductor firms. Estimates
were confirmed with data reported to the EPA by a sub-
set of firms in the industry who have engaged in volun-
tary monitoring efforts. Further study of gas emission
rates is also underway.
Data Sources
Emission estimates were provided by the EPA's
Atmospheric Pollution Prevention Division in coopera-
tion with the U.S. semiconductor industry.
Uncertainty
Emission estimates for this source are believed to
be highly uncertain due to the lack of detailed gas con-
sumption data and the complex chemical reactions in-
volved in the processes used. For example, in the etch-
ing process the gas molecules are disrupted by a plasma
into varied recombinant formulations specific to each tool
and operation.
Because of the uncertainties surrounding its con-
tribution to the greenhouse gas effect, NF3 is not included
in this inventory of greenhouse gas emissions. It has
been estimated that the atmospheric lifetime of NF3, be-
fore it undergoes photodissociation in the stratosphere,
is about 700 years, resulting in a 100 year global warm-
ing potential (GWP) value of approximately 8,000
(Molina, Wooldridge, and Molina 1995). As the under-
standing of the emission characteristics of this gas im-
proves, NF3 will be included in future inventories.
Electrical Transmission and
Distribution
The largest use for sulfur hexafluoride (SF6), both
domestically and internationally, is as an electrical insu-
lator in equipment that transmits and distributes electric-
ity. It has been estimated that eighty percent of the world-
wide use of SF6 is in electrical transmission and distribu-
tion systems (Ko et al. 1993). The gas has been em-
ployed by the electric power industry in the United States
since the 1950s because of its dielectric strength and arc-
quenching characteristics. It is used in gas-insulated sub-
stations, circuit breakers, and other switchgear. Sulfur
hexafluoride has replaced flammable insulating oils in
many applications and allows for more compact substa-
tions in dense urban areas.
Fugitive emissions of SF6 can escape from gas-in-
sulated substations and gas-insulated circuit breakers
through seals, especially from older equipment. It can
also be released when equipment is opened for servic-
3-26
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 3-38: SFB Emissions from Electrical
b
Transmission and Distribution
Year
MMTCE
Mg
1990
1991
1992
1993
1994
1995
1996
5.6
5.9
6.2
6.4
6.7
7.0
7.0
859
902
945
988
1,031
1,074
1,074
ing, which typically occurs every few years. In the past,
some utilities vented SF6 to the atmosphere during ser-
vicing; however, it is believed that increased awareness
and the relatively high cost of the gas have reduced this
practice.
Emissions of SF6 from electrical transmission and dis-
tribution systems was estimated to be 7.0 MMTCE (1,020
Mg) in 1996. This quantity amounts to a 25 percent in-
crease over the estimate for 1990 (see Table 3-38).
Methodology
Manufacturers of circuit breakers and gas-insulated
substations have claimed that new equipment leaks at
rates of less than 1 percent annually. To explore emis-
sion rates from electrical equipment, the EPA examined
atmospheric concentrations of SF6. Assumptions were
made to estimate historical worldwide SF6 production.
Based on measured concentrations, an atmospheric mass
balance was then calculated. This mass balance provided
an indication that most of the SF6 produced worldwide
since the early 1950s must have been emitted. Thus, it
was concluded that emission rates from equipment must
be higher than had been claimed. It was assumed that
roughly three-quarters of SF6production was used in elec-
trical equipment and that equipment leaked at a rate much
higher than proposed by industry.
Data Sources
Emission estimates were provided by the EPA's
Atmospheric Pollution Prevention Division in coopera-
tion with the U.S. electric utilities.
Uncertainty
There is little verifiable data existing for estimat-
ing SF6 emissions from electrical transmission and dis-
tribution systems. Neither gas consumption nor leakage
monitoring data were available. An accurate inventory
of the stock of SF6 in existing equipment, in addition to
improved assumptions of the leak rates from both new
and old equipment, will be required to develop improved
emission estimates.
Magnesium Production and
Processing
The magnesium metal production and casting in-
dustries use sulfur hexafluoride (SF6) as a covergas to
prevent the violent oxidation of molten magnesium in
the presence of air. Small concentrations of SF6 in com-
binations with carbon dioxide and air are blown over the
molten magnesium metal to induce the formation of a
protective crust. The industry adopted the use of SF6 to
replace sulfur dioxide (SO2). The SF6 technique is used
by producers of primary magnesium metal and most mag-
nesium part casters. The recycling industry, for the most
part, continues to employ sulfur dioxide as a covergas.
For 1996, a total of 3.0 MMTCE (460 Mg) of SF6
was estimated to have been emitted by the magnesium
industry, 76 percent more than was estimated for 1990
(see Table 3-39). There are no significant plans for ex-
pansion of primary production in the United States, but
demand for magnesium metal for die casting has the po-
tential to expand if auto manufacturers begin designing
more magnesium parts into future vehicle models.
Methodology
Emissions were estimated based upon usage infor-
Table 3-39: SF6 Emissions from Magnesium
Production and Processing
Year
1990
1991
1992
1993
1994
1995
1996
MMTCE
1.7
2.0
2.2
2.5
2.7
3.0
3.0
Mg
260
300
340
380
420
460
460
Industrial Processes
3-27
-------
mation supplied to the EPA by primary magnesium pro-
ducers. Consumption was assumed to equal emissions
in the same year. Although not directly employed, the
Norwegian Institute for Air Research (NIAR 1993) has
reported a range of emission factors for primary magne-
sium production as being from 1 to 5 kg of SF6 per met-
ric ton of magnesium. A survey of magnesium die cast-
ers has also reported an average emission factor of 4.1
kg of SF6 per metric ton of magnesium parts die cast
(Gjestland and Magers 1996).
Data Sources
Emission estimates were provided by the EPA's
Atmospheric Pollution Prevention Division in coopera-
tion with the U.S. primary magnesium metal producers
and casting firms.
Uncertainty
There are a number of uncertainties in these esti-
mates, including the assumption that SF6 does not react
nor decompose during use. In reality, it is possible that
the high temperatures associated with molten magnesium
would cause some gas degradation. Like other sources
of SF6 emissions, verifiable SF6 consumption data were
not available.
Industrial Sources of Criteria
Pollutants
In addition to the main greenhouse gases addressed
above, many industrial processes generate emissions of
criteria air pollutants. Total emissions of nitrogen ox-
ides (NOx), carbon monoxide (CO), and nonmethane
volatile organic compounds (NMVOCs) from non-en-
ergy industrial processes from 1990 to 1996 are reported
by detailed source category in Table 3-40.
Methodology and Data Sources
The emission estimates for this source were taken di-
rectly from the EPA's National Air Pollutant Emissions
Trends, 1900-1996 (EPA 1997a). Emissions were calcu-
lated either for individual sources or for many sources com-
bined, 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 emis-
sion factors, which together relate the quantity of emis-
sions to the activity. Emission factors are generally avail-
able from the EPA's Compilation of Air Pollutant Emis-
sion Factors, AP-42 (EPA 1997b). The EPA currently
derives the overall emission control efficiency of a source
category from a variety of information sources, includ-
ing published reports, the 1985 National Acid Precipita-
tion and Assessment Program emissions inventory, and
other EPA databases.
Uncertainty
Uncertainties in these estimates are partly due to
the accuracy of the emission factors used and accurate
estimates of activity data.
3-28
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 3-40: Emissions of N0x, CO, and NMVOC from Industrial Processes (Gg)
Gas/Source 1990 1991 1992 1993 1994 1995 1996
NO
X
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*
NMVOCs
Chemical & Allied Product
Manufacturing
Metals Processing
Storage and Transport
Other Industrial Processes
Miscellaneous*
923
152
88
3
343
337
9,580
1,074
2,395
69
487
5,556
3,193
575
111
1,356
364
787
802
149
69
5
319
259
7,166
1,022
2,333
25
497
3,288
2,997
644
112
1,390
355
496
784
148
74
4
328
230
5,480
1,009
2,264
15
494
1,697
2,825
649
113
1,436
376
252
760
141
75
4
336
204
5,500
992
2,301
46
538
1,623
2,907
636
112
1,451
401
306
933
145
82
5
353
347
7,787
1,063
2,245
22
544
3,912
3,057
627
114
1,478
397
441
815
144
89
5
362
215
5,370
1,109
2,159
22
566
1,514
2,873
599
113
1,499
409
253
821
144
89
5
366
217
5,379
1,109
2,157
22
576
1,514
2,299
396
64
1,190
398
251
* Miscellaneous includes the following categories: catastrophic/accidental release, other combustion, health services, TSDFs (Transport,
Storage, and Disposal Facilities under the Resource Conservation and Recovery Act), cooling towers, and fugitive dust. It does not include
agricultural fires or slash/prescribed burning, which are accounted for under the Agricultural Burning source.
Note: Totals may not sum due to independent rounding.
Industrial Processes 3-29
-------
4. Solvent Use
T
I he use of solvents and other chemical products can result in emissions of various ozone precursors (i.e.,
criteria pollutants).1 Nonmethane volatile organic compounds (NMVOCs), commonly referred to as "hy-
drocarbons," are the primary gases emitted from most processes employing organic or petroleum based solvents,
along with small amounts of carbon monoxide (CO) and oxides of nitrogen (NOx) whose emissions are associated
with control devices used to reduce NMVOC emissions. NMVOC emissions from solvent use increased 9 percent
from 1990 to 1996. Surface coatings accounted for just under a majority of NMVOC emissions from solvent use (46
percent), while "non-industrial" uses accounted for about 33 percent and dry cleaning for 3 percent of NMVOC
emissions in 1996. Overall, solvent use accounted for approximately 33 percent of total U.S. 1996 emissions of
NMVOCs.
Although NMVOCs are not considered primary 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 recom-
mended 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 solvents use include: degreasing,
graphic arts, surface coating, other industrial uses of solvents (i.e., electronics, etc.), dry cleaning, and non-industrial
uses (i.e., uses of paint thinner, etc.). Because many of these sources employ thermal incineration as a control
technology, CO and NOx combustion by-products are also reported with this source category.
Total emissions of nitrogen oxides (NOx), nonmethane volatile organic compounds (NMVOCs), and carbon
monoxide (CO) from non-energy industrial processes from 1990 to 1996 are reported by detailed source category in
Table 4-1.
Methodology
Emissions were calculated by aggregating solvent use data based on information relating to solvent uses from
different sectors such as degreasing, graphic arts, etc. Emission factors for each consumption category were then
applied to the data to estimate emissions. For example, emissions from surface coatings were mostly due to solvent
evaporation as the coatings solidify. By applying the appropriate solvent emission factors to the type of solvents used
for surface coatings, an estimate of emissions was obtained. Emissions of CO and NOx result primarily from thermal
and catalytic incineration of solvent laden gas streams from painting booths, printing operations, and oven exhaust.
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 sector.
Solvent Use 4-1
-------
Table 4-1: Emissions of NO , CO, and NMVOC from Solvent Use (Gg)
Activity
1990
1991
1992
1993
1994
1995
1996
N°x
Degreasing
Graphic Arts
Dry Cleaning
Surface Coating
Other Industrial Processes
Non-Industrial Processes
CO
Degreasing
Graphic Arts
Dry Cleaning
Surface Coating
Other Industrial Processes
Non-Industrial Processes
NMVOCs
Degreasing
Graphic Arts
Dry Cleaning
Surface Coating
Other Industrial Processes
Non-Industrial Processes
1
+
+
+
1
+
+
4
+
+
+
+
4
+
5,217
675
249
195
2,289
85
1,724
2
+
+
+
1
+
+
4
+
+
+
1
3
+
5,245
651
273
198
2,287
89
1,746
2
+
1
+
2
+
+
4
+
+
+
1
3
+
5,353
669
280
203
2,338
93
1,771
2
+
1
+
2
+
+
4
+
+
+
1
3
+
5,458
683
292
204
2,387
93
1,798
2
+
1
+
2
+
+
5
+
+
1
1
3
+
5,590
703
302
207
2,464
90
1,825
3
+
1
+
2
+
+
5
+
+
1
1
3
+
5,609
716
307
209
2,432
87
1,858
3
+
1
+
2
+
+
5
+
+
1
1
3
+
5,691
599
353
172
2,613
48
1,905
Note: Totals may not sum due to independent rounding.
+ Does not exceed 0.5 Gg
Data Sources
The emission estimates for this source were taken
directly from the EPA's National Air Pollutant Emissions
Trends, 1900-1996 (EPA 1997a). Emissions were cal-
culated either for individual sources or for many sources
combined, using basic activity data (e.g., the amount of
solvent purchased) as an indicator of emissions. National
activity data were collected for individual source catego-
ries from various agencies.
Activity data were used in conjunction with emis-
sion factors, which together relate the quantity of emis-
sions to the activity. Emission factors are generally avail-
able from the EPA's Compilation of Air Pollutant Emis-
sion Factors, AP-42 (EPA 1997b). The EPA currently
derives the overall emission control efficiency of a source
category from a variety of information sources, includ-
ing published reports, the 1985 National Acid Precipita-
tion 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 reli-
ability of correlations between activity data and actual
emissions.
4-2
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
5. Agriculture
Figure 5-1
Agricultural activities contribute directly to emissions of greenhouse gases through a variety of processes.
The Agriculture sector includes the following sources: enteric fermentation in domestic livestock, live-
stock manure management, rice cultivation, agricultural soil activities, and agricultural residue burning. Several
other agricultural activities, such as irrigation and tillage practices, may also generate anthropogenic greenhouse gas
emissions; however, the impacts of these practices are too uncertain to estimate emissions.' Agriculture related land-
use activities, such as conversion of grassland to cultivated land, are discussed under the Land-Use Change and
Forestry sector.
In 1996, agricultural activities were responsible for
emissions of 125.4 MMTCE, or approximately 7 percent
of total U.S. greenhouse gas emissions. Methane (CH4)
and nitrous oxide (N2O) were the primary greenhouse gases
emitted by agricultural activities. Methane emissions from
enteric fermentation and manure management represent
about 19 and 9 percent of total CH4 emissions from an-
thropogenic activities, respectively. Of all domestic ani-
mal types, beef and dairy cattle were by far the largest
emitters of methane. Rice cultivation and agricultural crop
waste burning were minor sources of methane. Agricul-
tural soil management activities such as fertilizer applica-
tion and other cropping practices were the largest source of nitrous oxide emissions, accounting for 66 percent of total
U.S. N2O emissions. Manure management and agricultural residue burning were also smaller sources of N2O emis-
sions (see Figure 5-1).
Table 5-1 and Table 5-2 present emission estimates for the Agriculture sector. Between 1990 and 1996, CH4
emissions from the sector increased by 7 percent while N2O emissions increased by 10 percent. In addition to CH4
and N2O, agricultural residue burning was also a minor source of the criteria pollutants carbon monoxide (CO) and
nitrogen oxides (NOx).
Enteric Fermentation
Methane (CH4) is produced as part of the 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,
Burning
10 m- .»& JO 60
MMTCE
1
Irrigation associated with rice cultivation is included in this inventory.
Agriculture 5-1
-------
Table 5-1: Emissions from the Agriculture Sector (MMTCE)
Gas/Source
1990
1991
1992
1993
1994
Note: Totals may not sum due to independent rounding.
Table 5-2: Emissions from the Agriculture Sector (Tg)
1995
1996
CH4
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Residue Burning
N20
Manure Management
Agricultural Soil Management
Agricultural Residue Burning
Total
50.3
32.7
14.9
2.5
0.2
65.2
2.6
62.4
0.1
115.5
50.9
32.8
15.4
2.5
0.2
66.3
2.8
63.4
0.1
117.3
52.2
33.2
16.0
2.8
0.2
68.1
2.8
65.2
0.1
120.3
52.5
33.6
16.1
2.5
0.2
67.1
2.9
64.1
0.1
119.5
54.4
34.5
16.7
3.0
0.2
73.5
2.9
70.4
0.1
127.9
54.8
34.9
16.9
2.8
0.2
70.2
2.9
67.2
0.1
125.0
53.7
34.5
16.6
2.5
0.2
71.7
3.0
68.6
0.1
125.4
Gas/Source
CH4
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Residue Burning
N20
Manure Management
Agricultural Soil Management
Agricultural Residue Burning
+ Does not exceed 0.05 Tg
1990
8.8
5.7
2.6
0.4
+
0.8
+
0.7
+
Note: Totals may not sum due to independent
1991
8.9
5.7
2.7
0.4
+
0.8
+
0.8
+
rounding.
1992
9.1
5.8
2.8
0.5
+
0.8
+
0.8
+
1993
9.2
5.9
2.8
0.4
+
0.8
+
0.8
+
1994
9.5
6.0
2.9
0.5
+
0.9
+
0.8
+
1995
9.6
6.1
2.9
0.5
+
0.8
+
0.8
+
1996
9.4
6.0
2.9
0.4
+
0.8
+
0.8
+
referred to as enteric fermentation, produces methane as
a by-product, which can be exhaled, or eructated, by the
animal. The amount of methane produced and excreted
by an individual animal depends primarily upon the
animal's digestive system, and the amount and type of
feed it consumes.
Among domestic animal types, the ruminant ani-
mals (e.g., cattle, buffalo, sheep, goats, and camels) are
the major emitters of methane because of their unique
digestive system. Ruminants possess a rumen, or large
"fore-stomach," in which microbial fermentation breaks
down the feed they consume into soluble products that
can be utilized by the animal. The microbial fermenta-
tion that occurs in the rumen enables ruminants to digest
coarse plant material that non-ruminant animals cannot.
Ruminant animals, consequently, have the highest meth-
ane emissions among all animal types.
Non-ruminant domestic animals (e.g., pigs, horses,
mules, rabbits, and guinea pigs) also produce methane
through enteric fermentation, although this microbial fer-
mentation occurs in the large intestine. These non-rumi-
nants have significantly lower methane emissions than
ruminants because the capacity of the large intestine to
produce methane is lower.
In addition to the type of digestive system, an
animal's feed intake also affects methane excretion. In
general, a higher feed intake leads to higher methane
emissions. Feed intake is positively related to animal
size, growth rate, and production (e.g., milk production,
wool growth, pregnancy, or work). Therefore, feed in-
take varies among animal types as well as among differ-
ent management practices for individual animal types.
Methane emissions estimates for livestock are
shown in Table 5-3 and Table 5-4. Total livestock emis-
sions in 1996 were 34.5 MMTCE (6.0 Tg), or 19 percent
of total U.S. methane emissions. Emissions from dairy
cattle remained relatively constant from 1990 to 1996
despite a steady increase in milk production. During this
time, emissions per cow increased due to a rise in milk
production per dairy cow (see Table 5-5); however, this
5-2
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 5-3: Methane Emissions from Enteric Fermentation (MMTCE)
Animal Type
1990
1991
1992
1993
1994
Note: Totals may not sum due to independent rounding.
Table 5-4: Methane Emissions from Enteric Fermentation (Tg)
Animal Type
1990
1991
1992
1993
1994
+ Does not exceed 0.05 Tg
Note: Totals may not sum due to independent rounding.
1995
1995
1996
Dairy Cattle
Beef Cattle
Other
Sheep
Goats
Horses
Hogs
Total
8.4
22.6
1.6
0.5
0.1
0.5
0.5
32.7
8.4
22.8
1.7
0.5
0.1
0.6
0.5
32.8
8.4
23.1
1.7
0.5
0.1
0.6
0.5
33.2
8.4
23.6
1.6
0.5
0.1
0.6
0.5
33.6
8.4
24.5
1.6
0.4
0.1
0.6
0.5
34.5
8.4
24.9
1.6
0.4
0.1
0.6
0.5
34.9
8.3
24.6
1.6
0.4
0.1
0.6
0.5
34.5
1996
Dairy Cattle
Beef Cattle
Other
Sheep
Goats
Horses
Hogs
Total
1.5
4.0
0.3
0.1
+
0.1
0.1
5.7
1.5
4.0
0.3
0.1
+
0.1
0.1
5.7
1.5
4.0
0.3
0.1
+
0.1
0.1
5.8
1.5
4.1
0.3
0.1
+
0.1
0.1
5.9
1.5
4.3
0.3
0.1
+
0.1
0.1
6.0
1.5
4.3
0.3
0.1
+
0.1
0.1
6.1
1.5
4.3
0.3
0.1
+
0.1
0.1
6.0
trend was offset by a decline in the dairy cow popula-
tion. Beef cattle emissions increased, reflecting the rise
in the beef cow population, although, in 1996 the num-
ber of beef cows declined for the first time since 1990.
Methane emissions from other animals have remained
relatively constant during the period 1990 through 1996.
Methodology
Livestock emission estimates fall into two catego-
ries: cattle and other domesticated animals. Cattle, due
to their large population, large size, and particular diges-
tive characteristics, account for the majority of methane
emissions from livestock in the United States and are
handled separately. Also, cattle production systems in
the United States are well characterized in comparison
with other livestock management systems. Overall, emis-
sions estimates were derived using emission factors,
which were multiplied by the appropriate animal popu-
lation data.
While the large diversity of animal management
practices cannot be precisely characterized and evalu-
ated, significant scientific literature exists that describes
the quantity of methane produced by individual rumi-
nant animals, particularly cattle. A detailed model that
incorporates this information and other analyses of feed-
ing practices and production characteristics was used to
estimate emissions from cattle populations.
To derive emission factors for the various types of
cattle found in the United States, a mechanistic model of
rumen digestion and animal production was applied to
data on thirty-two different diets and nine different cattle
types (Baldwin et al. 1987a and b).2 The cattle types
were defined to represent the different sizes, ages, feed-
ing systems, and management systems that are typically
found in the United States. Representative diets were
defined for each category of animal, reflecting the feeds
and forages consumed by cattle type and region. Using
this model, emission factors were derived for each com-
The basic model of Baldwin et al. (1987a and b) was revised somewhat to allow for evaluations of a greater range of animal types and diets.
See EPA (1993).
Agriculture 5-3
-------
bination of animal type and representative diet. Based
upon the level of use of each diet in the five regions,
average regional emission factors for each of the nine
cattle types were derived.3 These emission factors were
then multiplied by the applicable animal populations from
each region.
For dairy cows and beef cows and replacements,
emission estimates for 1990 to 1996 were developed us-
ing regional emission factors. Dairy cow emission fac-
tors were modified to reflect changing (primarily increas-
ing) milk production per cow over time in each region.
All other emission factors were held constant over time.
Emissions from other cattle types were estimated using
national average emission factors.
Emissions estimates for other animal types were
based upon average emission factors representative of
entire populations of each animal type. Methane emis-
sions from these animals accounted for a minor portion
of total methane emissions from livestock in the United
States. Also, the variability in emission factors for each
of these other animal types (e.g., variability by age, pro-
duction system, and feeding practice within each animal
type) is smaller than for cattle.
See Annex G for more detailed information on the
methodology and data used to calculate methane emis-
sions from enteric fermentation.
Data Sources
The emission estimates for all domestic livestock
were determined using a mechanistic model of rumen
digestion and emission factors
developed in EPA (1993). For
dairy cows and beef cows and
replacements, regional emis-
sion factors were used from
EPA (1993). Emissions from
other cattle types were esti-
mated using national average
emission factors from EPA
(1993). Methane emissions
from sheep, goats, pigs, and
horses were estimated by using emission factors utilized
in Crutzen et al. (1986) and annual population data from
USDA statistical reports. These emission factors are rep-
resentative of typical animal sizes, feed intakes, and feed
characteristics in developed countries. The methodol-
ogy employed in EPA (1993) is the same as those rec-
ommended in IPCC (1997). All livestock population data
were taken from USDA statistical reports. See the fol-
lowing section on manure management for a complete
listing of reports cited. Table 5-5 below provides a sum-
mary of cattle population and milk production data.
Uncertainty
The diets analyzed using the rumen digestion model
include broad representations of the types of feed con-
sumed within each region. Therefore, the full diversity
of feeding strategies employed in the United States is
not represented and the emission factors used may be
biased. The rumen digestion model, however, has been
validated by experimental data. Animal population and
production statistics, particularly for beef cows and other
grazing cattle, are also uncertain. Overall, the uncer-
tainty in the emission estimate is estimated to be roughly
20 percent (EPA 1993).
Manure Management
The management of livestock manure produces
methane (CH4) and nitrous oxide (N2O) emissions. Meth-
ane is produced by the anaerobic decomposition of ma-
nure. Nitrous oxide is produced as part of the agricul-
Table 5-5: Cow Populations (thousands) and Milk
Production (million kilograms)
Year
Milk Production Dairy Cow Population Beef Cow Population
1990
1991
1992
1993
1994
1995
1996
67,006
66,995
68,441
68,304
69,702
70,500
69,976
10,007
9,883
9,714
9,679
9,514
9,494
9,409
32,677
32,960
33,453
34,132
35,325
35,628
35,414
Feed intake of bulls does not vary significantly by region, so only a national emission factor was derived for this cattle type.
5-4
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
tural nitrogen cycle through the denitrification of the or-
ganic nitrogen in livestock manure and urine.
When livestock and poultry manure is stored or
treated in systems that promote anaerobic conditions (e.g.,
as a liquid in lagoons, ponds, tanks, or pits), the decom-
position of materials in manure tends to produce meth-
ane. When manure is handled as a solid (e.g., in stacks
or pits) or deposited on pastures and range lands, it tends
to decompose aerobically and produce little or no meth-
ane. Air temperature and moisture also affect the amount
of methane produced because they influence the growth
of the bacteria responsible for methane formation. Meth-
ane production generally increases with rising tempera-
ture. Also, for non-liquid based manure systems, moist
conditions (which are a function of rainfall and humid-
ity) favor methane production. Although the majority of
manure is handled as a solid, producing little methane,
the general trend in manure management, particularly
for dairy and swine producers, is one of increasing us-
age of liquid systems.
The composition of the manure also affects the
amount of methane produced. Manure composition de-
pends upon the diet of the animals. The greater the en-
ergy content and digestibility of the feed, the greater the
potential for methane emissions. For example, feedlot
cattle fed a high energy grain diet generate manure with
a high methane-producing capacity. Range cattle feed-
ing on a low energy diet of forage material produce ma-
nure with only half the methane-producing capacity of
feedlot cattle manure.
The amount of N2O produced can also vary de-
pending on the manure and urine composition, the type
of bacteria involved in the process, and the amount of
oxygen and liquid in the manure system. Nitrous oxide
emissions result from livestock manure and urine that is
managed using liquid and slurry systems, as well as ma-
nure and urine that is collected and stored. Nitrous ox-
ide emissions from unmanaged livestock manure and
urine on pastures, ranges, and paddocks, as well as from
manure and urine that is spread daily onto fields is dis-
cussed under Agricultural Soil Management.
Table 5-6, Table 5-7, and Table 5-8 (note, Table
5-8 is in units of gigagrams) provide estimates of meth-
ane and nitrous oxide emissions from manure manage-
ment. Emission quantities are broken down by animal
categories representing the major methane producing
groups. Estimates for methane emissions in 1996 were
16.6 MMTCE (2.9 Tg). Emissions have increased each
year from 1990 through 1995; however, emissions de-
creased slightly in 1996 with a decline in animal popula-
Table 5-6: CH and NO Emissions from Manure Management (MMTCE)
Animal Type
CH4
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
N20
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
Total
1990
14.9
4.3
1.1
7.8
+
1.5
0.2
2.6
0.1
1.1
0.1
+
1.3
17.6
1991
15.4
4.3
1.2
8.2
+
1.5
0.2
2.8
0.1
1.2
0.1
+
1.3
18.2
1992
16.0
4.4
1.2
8.6
+
1.6
0.2
2.8
0.1
1.2
0.1
+
1.4
18.7
1993
16.1
4.4
1.2
8.6
+
1.6
0.2
2.9
0.1
1.2
0.1
+
1.4
19.0
1994
16.7
4.5
1.2
9.1
+
1.7
0.2
2.9
0.1
1.2
0.1
+
1.5
0.1
19.7
1995
16.9
4.5
1.3
9.2
+
1.7
0.2
2.9
0.1
1.2
0.1
+
1.5
0.1
19.8
1996
16.6
4.5
1.3
8.8
+
1.7
0.2
3.0
0.1
1.2
0.1
+
1.5
0.1
19.5
+ Does not exceed 0.05 MMTCE
Note: Totals may not sum due to independent rounding.
Agriculture 5-5
-------
Table 5-7: Methane Emissions from Manure Management (Tg)
Animal Type
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
Total
1990
0.7
0.2
1.4
+
0.3
2.6
1991
0.8
0.2
1.4
+
0.3
2.7
1992
0.8
0.2
1.5
+
0.3
2.8
1993
0.8
0.2
1.5
+
0.3
2.8
1994
0.8
0.2
1.6
+
0.3
2.9
1995
0.8
0.2
1.6
+
0.3
2.9
1996
0.8
0.2
1.5
+
0.3
2.9
+ Does not exceed 0.05 Tg
Note: Totals may not sum due to independent rounding.
Table 5-8: NO Emissions from Manure Management (Gg)
Animal Type
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
Total
1990
1
13
1
+
+
15
1
31
1991
1
15
1
+
+
16
1
33
1992
1
14
1
+
+
16
1
33
1993
1
15
1
+
+
17
1
34
1994
1
15
1
+
+
17
1
35
1995
1
14
1
+
+
18
1
34
1996
1
14
1
+
+
18
1
35
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding.
tions, including swine. Under the AgSTAR Program of
the U.S. Climate Change Action Plan, methane emissions
from manure have been reduced through methane recov-
ery efforts. The AgSTAR Program reported a reduction
of 0.1 MMTCE of methane in 1996.
Total N2O emissions from managed manure sys-
tems in 1996 were estimated to be 3.0 MMTCE (35 Gg).
The 12 percent increase in emissions from 1990 to 1996
can be attributed to an increase in the proportion of beef
cattle in feedlots, which are assumed to use managed
manure management systems. Methane emissions were
mostly unaffected by this shift in the beef cattle popula-
tion because feedlot cattle use solid storage systems,
which produce little methane.
In general, changes in the emission estimates over
time reflect variations in animal populations. The esti-
mates also reflect a regional redistribution of dairies to
the southwestern states, which have larger average farm
sizes, and an increase in feed consumption by dairy cows
to accommodate increased milk production per cow.
Regional shifts in the hog population were also addressed.
Methodology
The methods presented in EPA (1993) form the
basis of the methane emissions estimates for each ani-
mal type. The calculation of emissions requires the fol-
lowing information:
• Amount of manure produced (amount per head times
number of head)
• Portion of the manure that is volatile solids (by ani-
mal type)
• Methane producing potential of the volatile solids
(by animal type)
• Extent to which the methane producing potential is
realized for each type of manure management sys-
tem (by state and manure management system)
• Portion of manure managed in each manure man-
agement system (by state and animal type)
For dairy cattle and swine—the two largest emit-
ters of methane—estimates were developed using state-
level animal population data. For other animal types,
1990 emission estimates from the detailed analysis pre-
sented in EPA (1993) were scaled at the national level
5-6
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
using the population of each livestock type. Nitrous ox-
ide emissions were estimated by first determining ma-
nure management system usage. Manure system usage
for dairy cows and swine were based on the farm size
distribution. Total Kjeldahl nitrogen4 production was
calculated for all livestock using livestock population data
and nitrogen excretion rates. The total amount of nitro-
gen from manure was reduced by 20 percent to account
for the portion that volatilizes to NH3 and NOx (IPCC/
UNEP/OECD/IEA 1997). Nitrous oxide emission fac-
tors were then applied to total nitrogen production to es-
timate N2O emissions. Throughout the time series the
estimates of the portion of manure and urine which is
managed in each of the manure management systems in
each state remained fixed.
See Annex H for more detailed information on the
methodology and data used to calculate methane emis-
sions from enteric fermentation. The same activity data
was also used to calculate N2O emissions.
Data Sources
Annual livestock population data for all livestock
types except horses were obtained from the U.S. Depart-
ment of Agriculture's National Agricultural Statistics
Service (USDA 1994a, b; 1995a-j; 1996a-f; 1997a-f).
Horse population data were obtained from the FAOSTAT
database (FAO 1997). Data on farm size distribution for
dairy cows and swine were taken from the U.S. Depart-
ment of Commerce (DOC 1995, 1987). Manure man-
agement system usage data for other livestock were taken
from EPA (1992). Nitrogen excretion rate data were de-
veloped by the American Society of Agricultural Engi-
neers (ASAE 1995). Nitrous oxide emission factors were
taken from IPCC/UNEP/OECD/IEA (1997). Manure
management systems characterized as "Other" generally
refers to deep pit and litter systems. The IPCC N2O emis-
sion factor for "other" systems (0.005 kg N2O/kg N ex-
creted), was determined to be inconsistent with the char-
acteristics of these management systems. Therefore, in
its place the solid storage/dry lot emission factor was used.
Uncertainty
The primary factors contributing to the uncertainty
in emission estimates are a lack of information on the
usage of various manure management systems in each
state and the exact methane generating characteristics of
each type of manure management system. Because of
significant shifts in the dairy and swine sectors toward
larger farms, it is believed that increasing amounts of
manure are being managed in liquid manure manage-
ment systems. The existing estimates capture a portion
of these shifts as the dairy and swine populations move
regionally toward states with larger average farm sizes.
However, changes in farm size distribution within states
since 1992 are not captured by the method. The meth-
ane generating characteristics of each manure manage-
ment system type are based on relatively few laboratory
and field measurements, and may not match the diver-
sity of conditions under which manure is managed na-
tionally.
The N2O emission factors published in IPCC/
UNEP/OECD/IEA (1997) were also derived using lim-
ited information. The IPCC factors are global averages;
U.S.-specific emission factors may be significantly dif-
ferent. Manure and urine in anaerobic lagoons and liq-
uid/slurry management systems produce methane at dif-
ferent rates, and would in all likelihood produce N2O at
different rates, although a single emission factor was used.
Rice Cultivation
Most of the world's rice, and all rice in the United
States, is grown on flooded fields. When fields are flooded,
aerobic decomposition of organic material gradually de-
pletes the oxygen present in the soil and floodwater causing
anaerobic conditions in the soil to develop. Under such
conditions, methane is produced through anaerobic decom-
position of soil organic matter by methanogenic bacteria.
However, not all of the methane that is produced is released
into the atmosphere. As much as 60 to 90 percent of the
methane produced is oxidized by aerobic methanotrophic
Total Kjeldahl nitrogen is a measure of organically bound nitrogen and ammonia nitrogen.
Agriculture 5-7
-------
bacteria in the soil (Holzapfel-Pschorn et al. 1985, Sass et
al. 1990). Some of the methane is also leached away as
dissolved methane in floodwater that percolates from the
field. The remaining non-oxidized methane is transported
from the submerged soil to the atmosphere primarily by
diffusive transport through the rice plants. Some methane
also escapes 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
methane emissions. Upland rice fields are not flooded,
and therefore are not believed to produce methane. In
deepwater rice fields (i.e., fields with flooding depths
greater than one meter), lower stems and roots of the
rice plants are dead, and thus effectively block the pri-
mary methane transport pathway to the atmosphere.
Therefore, while deepwater rice growing areas are be-
lieved to emit methane, the quantities released are likely
to be significantly less than the quantities released from
areas with more shallow flooding depths. Also, some
flooded fields are drained periodically during the grow-
ing season, either intentionally or accidentally. If water
is drained and soils are allowed to dry sufficiently, meth-
ane emissions decrease or stop entirely. This is due to
soil aeration, which not only causes existing soil meth-
ane to oxidize but also inhibits further methane produc-
tion in soils. All rice in the United States is grown under
continuously flooded conditions; none is grown under
deepwater conditions.
Other factors that influence methane emissions
from flooded rice fields include soil temperature, soil
type, fertilization practices, cultivar selection, and other
cultivation practices (e.g., tillage, seeding and weeding
practices). Many studies have found, for example, that
methane emissions increase as soil temperature increases.
Several studies have also indicated that some types of
synthetic nitrogen fertilizer inhibit methane generation,
while organic fertilizers enhance methane emissions.
However, while it is generally acknowledged that these
factors influence methane emissions, the extent of their
influence, individually or in combination, has not been
well quantified.
Rice cultivation is a small source of methane in the
United States. Only seven states grow rice: Arkansas,
California, Florida, Louisiana, Mississippi, Missouri, and
Texas. Methane emissions from rice cultivation in 1996
were estimated to have been 2.5 MMTCE (431 Gg), ac-
counting for just over 1 percent of total methane emis-
sions from U.S. anthropogenic sources. Table 5-9 and
Table 5-10 present annual emission estimates for each
state. There was no apparent trend over the seven year
period. Between 1994 and 1996, rice areas declined fairly
steadily in almost all states, and the national total de-
clined by about 8 percent each year (see Table 5-11).
The factors that affect the rice area harvested vary
from state to state. In Florida, the state having the small-
est harvested rice area, rice acreage is driven by sugar-
cane acreage. Sugarcane fields are flooded each year to
control pests, and on this flooded land a rice crop is grown
along with a ratoon crop of sugarcane (Schudeman
1997a). In Missouri, rice acreage is affected by weather
(rain during the planting season may prevent the plant-
ing of rice), prices of soybeans relative to rice (if soy-
bean prices are higher, then soybeans may be planted on
Table 5-9: Methane Emissions from Rice Cultivation (MMTCE)
State
1990
1991
1992
1993
1994
+ Does not exceed 0.05 MMTCE
Note: Totals may not sum due to independent rounding.
1995
1996
Arkansas
California
Florida
Louisiana
Mississippi
Missouri
Texas
Total
0.9
0.5
+
0.6
0.2
0.1
0.3
2.5
0.9
0.4
+
0.6
0.1
0.1
0.3
2.5
1.0
0.5
+
0.7
0.2
0.1
0.3
2.8
0.9
0.5
+
0.6
0.2
0.1
0.2
2.5
1.1
0.6
+
0.7
0.2
0.1
0.3
3.0
1.0
0.5
+
0.7
0.2
0.1
0.3
2.8
0.9
0.6
+
0.6
0.1
0.1
0.2
2.5
5-8
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 5-10: Methane Emissions from Rice Cultivation (Gg)
State
1990
1991
1992
1993
1994
1995
Note: Totals may not sum due to independent rounding.
Table 5-11: Area Harvested for Rice-Producing States (hectares)
Note: Totals may not sum due to independent rounding.
1996
Arkansas
California
Florida
Louisiana
Mississippi
Missouri
Texas
Total
156
79
3
111
27
11
52
439
164
70
5
104
24
12
50
429
180
79
5
126
30
15
51
486
160
88
5
108
27
12
43
443
185
98
5
126
34
16
52
516
175
94
5
116
32
15
46
482
152
101
4
99
23
12
40
431
State/Crop
Arkansas
California
Florida
Primary
Ratoon
Louisiana
Primary
Ratoon
Mississippi
Missouri
Texas
Primary
Ratoon
Total
1990
485,633
159,854
4,978
2,489
220,558
66,168
101,174
32,376
142,857
57,143
1,273,229
1991
509,915
141,643
8,580
4,290
206,394
61,918
89,033
37,232
138,810
55,524
1,253,339
1992
558,478
159,450
8,944
4,472
250,911
75,273
111,291
45,326
142,048
56,819
1,413,011
1993
497,774
176,851
8,449
4,225
214,488
64,346
99,150
37,637
120,599
48,240
1,271,759
1994
574,666
196,277
8,902
4,451
250,911
75,273
126,669
50,182
143,262
57,305
1,487,897
1995
542,291
188,183
8,903
4,452
230,676
69,203
116,552
45,326
128,693
51,477
1,385,755
1996
473,493
202,347
8,903
4,452
215,702
64,711
84,176
36,423
120,599
48,240
1,259,045
some of the land which would otherwise have been
planted in rice), and government support programs
(which, beginning in 1996, were being phased-out)
(Stevens 1997). In Mississippi, rice acreage is driven by
both the price of rice and the price of soybeans. Rice in
Mississippi is usually rotated with soybeans, but if soy-
bean prices increase relative to rice prices, then some of
the acreage that would have been planted in rice, is in-
stead planted in soybeans (Street 1997). In Texas, rice
production, and thus, harvested area, are driven by both
government programs and the cost of production
(Klosterboer 1997). California rice area is influenced
by water availability as well as government programs and
commodity prices. In recent years, California was able
to grow more rice due to recovery from a drought, as
well as price increases associated with gaining access to
the Japanese market (Scardaci 1997). In Louisiana, rice
area is influenced by government programs (which had
less of an effect in 1996 than in other years because of
the beginning of aphase-out of these programs), weather
conditions (such as rainfall during the planting season),
as well as the price of rice relative to that of corn and
other crops (Saichuk 1997). Arkansas rice area has been
influenced in the past by government programs. The
phase-out of these programs began in 1996, and com-
modity prices in the spring had a greater effect on the
amount of land planted in rice (Mayhew 1997).
Methodology
The Revised 1996IPCC Guidelines (IPCC/UNEP/
OECD/IEA 1997) recommend applying a seasonal emis-
sion factor to the annual harvested rice area to estimate
annual CH4 emissions. This methodology assumes that
a seasonal emission factor is available for all growing
conditions, including season lengths. Because season
lengths are variable both within and among states in the
United States, and because flux measurements have not
been taken under all growing conditions in the United
Agriculture 5-9
-------
States, the previous IPCC methodology (IPCC/UNEP/
OECD/IEA 1995) has been applied here, using season
lengths that vary slightly from the recommended ap-
proach. The 1995 IPCC Guidelines recommend multi-
plying a daily average emission factor by growing sea-
son length and annual harvested area. The IPCC Guide-
lines suggest that the "growing" season be used to calcu-
late emissions based on the assumption that emission
factors are derived from measurements over the whole
growing season rather than just the flooding season.
Applying this assumption to the United States, however,
would result in an overestimate of emissions because the
emission factors developed for the United States are based
on measurements over the flooding, rather than the grow-
ing, season. Therefore, the method used here is based
on the number of days of flooding during the growing
season and a daily average emission factor, which is
multiplied by the harvested area. Agricultural statisti-
cians in each of the seven states in the United States that
produce rice were contacted to determine water manage-
ment practices and flooding season lengths in each state.
Although all contacts reported that rice growing areas
were continually flooded, flooding season lengths var-
ied considerably among states; therefore, emissions were
calculated separately for each state.
The climatic conditions of southwest Louisiana,
Texas, and Florida also allow for a second, or ratoon,
rice crop. This second rice crop is produced from re-
growth on the stubble after the first crop has been har-
vested. The emission estimates presented here account
for this additional harvested area.
Because the number of days that the rice fields re-
main permanently flooded varies considerably with plant-
ing system and cultivar type, a range for the flooding
season length was adopted for each state. The harvested
areas and flooding season lengths for each state are pre-
sented in Table 5-11 and Table 5-12, respectively.
Data Sources
Data on harvested rice area for all states except
Florida were taken from U. S. Department of Agriculture's
Crop Production 1996 Summary (USDA 1997). Har-
vested rice areas in Florida were obtained from Tom
Schudeman (1997b), a Florida Agricultural Extension
Agent. Acreages for the ratoon crops were estimated to
account for about 30 percent of the primary crop in Loui-
siana, 40 percent in Texas (Lindau and Bollich 1993)
and 50 percent in Florida (Schudeman 1995). Daily
methane emission factors were taken from results of field
studies performed in California (Cicerone et al. 1983),
Texas (Sass et al. 1990,1991a, 1991b, 1992) and Louisi-
ana (Lindau et al. 1991,LindauandBollich 1993). Based
on the maximal and minimal estimates of the emission
rates measured in these studies, a range of 0.1065 to
0.5639 g/m2/day was applied to the harvested areas and
flooding season lengths in each state.5 Since these mea-
surements were taken in rice growing areas, they are
representative of soil temperatures, and water and fertil-
izer management practices typical of the United States.
Uncertainty
There are three sources of uncertainty in the cal-
culation of CH4 emissions from rice cultivation. The larg-
est uncertainty is associated with the emission factor.
Daily average emissions, derived from field measure-
ments in the United States, vary from state to state by as
much as two orders of magnitude (IPCC/UNEP/OECD/
IEA 1997). This variability is due to differences in cul-
tivation practices, such as ratooning and fertilizer use, as
well as differences in soil and climatic conditions. A
range (0.3352 g/m2/day ±68 percent) has been used in
these calculations to reflect this variability. Based on
this range, methane emissions from rice cultivation in
1996 were estimated to have been approximately 0.6 to
4.3 MMTCE (111 to 752 Gg).
Two measurements from these studies were excluded when determining the emission coefficient range. A low seasonal average flux of
0.0595 g/m /day in Sass et al. (1990) was excluded because this site experienced a mid-season accidental drainage of floodwater, after which
methane emissions declined substantially and did not recover for about two weeks. Also, the high seasonal average flux of 2.041 g/m /day in
Lindau and Bollich (1993) was excluded since this emission rate is unusually high, compared to other flux measurements in the United States,
as well as in Europe and Asia (see IPCC/UNEP/OECD/IEA 1997).
5-10
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 5-12: Primary Cropping Flooding Season
Length (days)
State
Arkansas
California
Florida*
Louisiana*
Mississippi
Missouri
Texas*
Low
75
123
90
90
75
80
60
High
100
153
120
120
82
100
80
* These states have a second, or "ratoon", cropping cycle
which may have a shorter flooding season than the one listed
in the table.
Another source of uncertainty is in the flooding
season lengths used for each state. Flooding seasons in
each state may fluctuate from year to year and thus a
range has been used to reflect this uncertainty (see Table
5-13).
The last source of uncertainty centers around the
ratoon, or second crop. Rice fields for the ratoon crop
typically remain flooded for a shorter period of time than
for the first crop. Studies indicate, however, that the
methane emission rate of the ratoon crop may be signifi-
cantly higher than that of the first crop. The rice straw
produced during the first harvest has been shown to dra-
matically increase methane emissions during the ratoon
cropping season (Lindau and Bollich 1993). It is not
clear to what extent the shorter season length and higher
emission rates offset each other. As scientific understand-
ing improves, these emission estimates can be adjusted
to better reflect these variables.
Agricultural Soil Management
Nitrous oxide (N2O) is produced naturally in soils
through the microbial processes of nitrification and denitri-
fication.6 A number of agricultural activities add nitrogen
to soils, thereby increasing the amount of nitrogen avail-
able for nitrification and denitrification, and ultimately the
amount of N2O emitted. These activities may add nitrogen
to soils either directly or indirectly. Direct additions occur
through various cropping practices (i.e., application of syn-
thetic and organic fertilizers, daily spread of animal wastes,
production of nitrogen-fixing crops, incorporation of crop
residues, and cultivation of high organic content soils, called
histosols), and through animal grazing (i.e., direct deposi-
tion of animal wastes on pastures, range, and paddocks by
grazing animals7). Indirect additions occur through two
mechanisms: 1) volatilization of applied nitrogen (i.e., fer-
tilizer and animal waste) and subsequent atmospheric depo-
sition of that nitrogen as ammonia (NH3) and oxides of ni-
trogen (NOx); and 2) surface runoff and leaching of applied
nitrogen. Other agricultural soil management practices, such
as irrigation, drainage, tillage practices, and fallowing of
land, can affect fluxes of N2O, as well as other greenhouse
gases, to and from soils. However, because there are sig-
nificant uncertainties as to the effects of these other prac-
tices, they have not been estimated.
Estimates of annual N2O emissions from agricul-
tural soils in previous U.S. inventories included only those
that result directly from the application of commercial
synthetic and organic fertilizer nitrogen, as was consis-
Table 5-13: NO Emissions from Agricultural Soil Management (MMTCE)
Activity
1990
1991
1992
1993
1994
Note: Totals may not sum do to independent rounding.
1995
1996
Direct
Cropping Practices
Animal Production
Indirect
Total
33.5
10.1
18.8
62.4
34.0
10.1
19.3
63.4
35.4
10.4
19.4
65.2
33.6
10.5
20.0
64.1
39.0
10.8
20.6
70.4
35.9
11.0
20.3
67.2
37.4
10.8
20.4
68.6
Nitrification is the aerobic microbial oxidation of ammonium to nitrate, and denitrification is the anaerobic microbial reduction of nitrate to
dinitrogen gas (IPCC/UNEP/OECD/IEA 1997). Nitrous oxide is a gaseous intermediate product in the reaction sequences of both processes,
which leaks from microbial cells into the soil atmosphere.
Nitrous oxide emissions from animal wastes that are managed in animal waste management systems are covered under Manure Management
in the Agriculture sector.
Agriculture 5-11
-------
Table 5-14: N20 Emissions from Agricultural Soil Management (Gg N20)
Activity 1990 1991 1992 1993 1994
Note: Totals may not sum do to independent rounding.
1995
1996
Direct Cropping Practices
Animal Production
Indirect
Total
396
119
223
738
403
120
228
750
418
123
230
771
398
125
236
758
461
128
244
833
424
131
240
795
442
128
241
812
tent with earlier versions of the IPCC Guidelines (IPCC/
OECD Joint Programme 1994, IPCC/UNEP/OECD/IEA
1995). The Revised 1996IPCC Guidelines (WCCIUNEPI
OECD/IEA 1997) includes additional anthropogenic
sources of soil nitrogen, and emissions from both direct
and indirect pathways. As a consequence, the emission
estimates provided below are significantly higher (by
about 300 percent) than previous estimates.
The revised estimates of annual N2O emissions
from agricultural soil management range from 62.4 to
70.4MMTCE(738to 833 Gg N2O) for the years 1990 to
1996 (Table 5-13 and Table 5-14). Emission levels in-
creased fairly steadily from 1990 to 1996 except for the
year 1993, when emissions declined slightly, and the year
1994, when emissions increased sharply. These fluctua-
tions are largely a reflection of annual variations in syn-
thetic nitrogen fertilizer consumption and crop produc-
tion. The other agricultural sources of nitrogen (animal
wastes, and histosol cultivation) generally increased
steadily, or stayed flat, from year to year. Synthetic ni-
trogen fertilizer consumption, and production of corn and
most beans and pulses, peaked in 1994 due to the 1993
flooding of the North Central region and the intensive
cultivation that followed. Over the seven-year period,
total emissions of N2O increased by 10 percent.
Methodology and Data Sources
This N2O source category is divided into three com-
ponents: (1) direct emissions from agricultural soils due
to cropping practices; (2) direct emissions from agricul-
tural soils due to animal production; and (3) emissions
from soils indirectly induced by agricultural applications
of nitrogen. The emission estimates for all three compo-
nents follow the methodologies in the Revised 1996 IPCC
Guidelines (IPCC/UNEP/OECD/IEA 1997).
Direct N20 Emissions from Agricultural Cropping
Practices
Estimates of N2O emissions from this component
are based on the total amount of nitrogen that is applied
to soils through cropping practices. These practices are
(1) the application of synthetic and organic fertilizers,
(2) the application of animal waste through daily spread
operations, (3) the production of nitrogen-fixing crops,
(4) the incorporation of crop residues into the soil, and
(5) the cultivation of histosols.
Annual fertilizer consumption data for the U.S.
were taken from annual publications on commercial fer-
tilizer statistics (AAPFCO 1995, 1996; TVA 1990,1992a
andb, 1994). These data are recorded in "fertilizeryear"
totals (July to June) which were converted to calendar
year totals by assuming that approximately 35 percent
of fertilizer usage occurred from July to December (TVA
1992b). Datafor July to December of calendar year 1996
were based on preliminary estimates (Terry 1998). Data
on the nitrogen content of synthetic fertilizers were avail-
able in published consumption reports; however, data on
manure used as commercial fertilizer and other organic
fertilizer consumption8 did not include nitrogen content
information. To convert to units of nitrogen, it was as-
sumed that 1 percent of manure and 4.1 percent of other
organic fertilizers (on a mass basis) was nitrogen (Terry
1997). Annual consumption of commercial fertilizers
Organic fertilizers included in these publications are manure, compost, dried blood, sewage sludge, tankage, and other organics. Tankage is
dried animal residue, usually freed from fat and gelatin.
5-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
(synthetic, manure, and other organics) in units of nitro-
gen are presented in Table 5-15. The total amount of
nitrogen consumed from synthetic and organic fertiliz-
ers was reduced by 10 percent and 20 percent, respec-
tively, to account for the portion that volatilizes to NH3
and NOx (IPCC/UNEP/OECD/IEA 1997).
To estimate the amount of animal waste applied
annually through daily spread operations, it was assumed
that only the wastes from dairy cattle on small farms were
managed as daily spread (Safely et al. 1992). Dairy cow
population data were obtained from the USDA National
Agricultural Statistics Service (USDA 1995a,b,c,d,
1996a,b, 1997a,b). Farm size was reported by the De-
partment of Commerce (DOC 1995). Population data
for dairy cattle on small farms were multiplied by an av-
erage animal mass constant (ASAE 1995). Total Kjeldahl
nitrogen9 excreted per year (manure and urine) was then
calculated using daily rates of N excretion per unit of
animal mass (ASAE 1995) (Table 5-16). The total amount
of nitrogen from manure was reduced by 20 percent to
account for the portion that volatilizes to NH3 and NOx
(IPCC/UNEP/OECD/IEA 1997).
Annual production statistics for nitrogen-fixing
crops (beans, pulses, and alfalfa) were taken from U.S.
Department of Agriculture reports (USDA 1994a, 1997c,
1998). These statistics are presentedinTable 5-17. Crop
product values for beans and pulses were expanded to
total crop dry biomass, in mass units of dry matter, by
applying residue to crop ratios and dry matter fractions
for residue from Strehler and Stutzle (1987). Crop prod-
uct values for the alfalfa were converted to dry matter
mass units by applying a dry matter fraction value esti-
mated at 80 percent (Mosier 1998). To convert to units
of nitrogen, it was assumed that 3 percent of the total
crop dry mass for all crops was nitrogen (IPCC/UNEP/
OECD/IEA 1997).
To estimate the amount of nitrogen applied to soils
through crop residue incorporation, it was assumed that
all residues from corn, wheat, bean, and pulse produc-
tion, except the fractions that are burned in the field after
harvest, are plowed under. Annual production statistics
were taken from U.S. Department of Agriculture (USDA
1994a, 1997c, 1998). These statistics are presented in
Table 5-17 and Table 5-18. Crop residue biomass, in dry
matter mass units, was calculated from the production
statistics by applying residue to crop mass ratios and dry
matter fractions for residue from Strehler and Stutzle
(1987). For wheat and corn, nitrogen contents were taken
from Barnard and Kristoferson (1985). For beans and
pulses, it was assumed that 3 percent of the total crop
residue was nitrogen (IPCC/UNEP/OECD/IEA 1997).
The crops whose residues were burned in the field are
corn, wheat, soybeans, and peanuts. For these crop types,
the total residue nitrogen was reduced by 3 percent to
subtract the fractions burned in the field (see the Agri-
cultural Residue Burning section of this chapter).
Total crop nitrogen in the residues returned to soils
was then added to the unvolatilized applied nitrogen from
commercial fertilizers and animal wastes, and the nitro-
gen fixation from bean, pulse, and alfalfa cultivation. The
sum was multiplied by the IPCC default emission factor
(0.0125 kg N2O-N/kg N applied) to estimate annual N2O
emissions from nitrogen applied to soils.
Statistics on the area of histosols cultivated annu-
ally were not available, so an estimate for the year 1982
(Mausbach and Spivey 1993) was used for all years in
the 1990 to 1996 series (Table 5-19). The area estimate
was derived from USDA land-use statistics. The histosol
area cultivated was multiplied by the IPCC default emis-
sion factor (5 kg N2O-N/ha cultivated) to estimate an-
nual N2O emissions from histosol cultivation.
Annual N2O emissions from nitrogen applied to soils
were then added to annual N2O emissions from histosol
cultivation to estimate total direct annual N2O emissions
from agricultural cropping practices (Table 5-20).
Direct N20 Emissions from Animal Production
Estimates of N2O emissions from this component
were based on animal wastes that are not used as com-
mercial fertilizers, or applied in daily spread applications,
or managed in manure management systems, but instead
are deposited directly on soils by animals in pastures,
range, and paddocks.10 It was assumed that all
unmanaged wastes, except for dairy cow wastes, fall into
1 Total Kjeldahl nitrogen is a measure of organically bound nitrogen and ammonia nitrogen.
Agriculture 5-13
-------
this category (Safely etal. 1992). Estimates of nitrogen
excretion by these animals were derived from animal
population and weight statistics, information on manure
management system usage in the United States, and ni-
trogen excretion values for each animal type.
Annual animal population data for all livestock types,
except horses, were obtained from the USDA National Ag-
ricultural Statistics Service (USDA 1994b, c, 1995a-j, 1996a-
i, 1997a, b, d-h). Horse population data were taken from
U.S. Department of Commerce's Bureau of Census (DOC
1987) and FAO (1996). Manure management system us-
age for all livestock types, except swine, was taken from
Safely et al. (1992). Because these data were not available
for swine, the swine population values were allocated to
manure management system types using information on
farm size distribution reported by the U.S. Department of
Commerce (DOC 1995). Swine populations in the larger
farm categories were assumed to utilize manure collection
and storage management systems; all the wastes from
smaller farms were assumed to be managed as pasture, range,
and paddock. Population data for animals whose wastes
were managed in pasture, range, and paddock were multi-
plied by an average animal mass constant (ASAE 1995) to
derive total animal mass for each animal type. Total Kjeldahl
nitrogen excreted peryear was then calculated for each ani-
mal type using daily rates of N excretion per unit of animal
mass (ASAE 1995). Annual nitrogen excretion was then
summed overall animal types (Table 5-16), and reduced by
20 percent to account for the portion that volatilizes to NH3
and NOx. The remainder was multiplied by the IPCC de-
fault emission factor (0.02 kg N2O-N/kg N excreted) to es-
timate NO emissions (Table 5-21).
Indirect N20 Emissions from Nitrogen Applied to
Agricultural Soils
This component accounts for N2O that is emitted
indirectly from nitrogen applied as fertilizer and excreted
by livestock. Through volatilization, some of this nitro-
gen enters the atmosphere as NH3 and NOx, and subse-
quently returns to soils through atmospheric deposition,
thereby enhancing N2O production. Additional nitrogen
is lost from soils through leaching and runoff, and enters
groundwater and surface water systems, from which a
portion is emitted as N2O. These two indirect emission
pathways are treated separately, although the activity data
used are identical.
Estimates of total nitrogen applied as fertilizer and
excreted by all livestock (i.e., wastes from all unmanaged
and managed systems) were derived using the same ap-
proach as was employed to estimate the direct soil emis-
sions. Annual application rates for synthetic and non-
manure organic fertilizer nitrogen11 were derived as de-
scribed above from commercial fertilizer statistics for
the United States (AAPFCO 1995, 1996; TVA 1990,
1992aandb, 1994). Annual total nitrogen excretion data
(by animal type) were derived, also as described above,
using animal population statistics (USDA 1994b, c,
1995a-j, 1996a-i, 1997a, b, d-h; DOC 1987; and FAO
1996), average animal mass constants (ASAE 1995), and
daily rates of N excretion per unit of animal mass (ASAE
1995). Annual nitrogen excretion was then summed over
all animal types.
To estimate N2O emissions from volatilization and
subsequent atmospheric deposition, it was assumed that
10 percent of the synthetic fertilizer nitrogen applied, 20
percent of the non-manure organic fertilizer nitrogen ap-
10 The Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) indicate that emissions from animal wastes managed in solid storage
and drylot should also be included in the emissions from soils (see footnote "c" in Table 4-22 in the Reference Manual); however, this
instruction appeared to be an error (and footnote "b" should have been listed next to "Solid storage and drylot" in Table 4-22). Therefore, N2O
emissions from livestock wastes managed in solid storage and drylot are reported under manure management, rather than here, under agricul-
tural soil management. (See Annex H for a discussion of the activity data used to calculate emissions from the manure management source
category.)
The activity data for livestock nitrogen excretion include nitrogen excreted by all livestock, so manure used as fertilizer is excluded to
avoid double counting the nitrogen contained in manure used as commercial fertilizer.
5-14
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
plied, and 20 percent of the total livestock nitrogen ex-
cretion were volatilized to NH3 and NOx, and 1 percent
of the total volatilized nitrogen returned to the soils and
was emitted as N2O (IPCC/UNEP/OECD/IEA 1997).
These emission levels are presented in Table 5-22.
To estimate N2O emissions from leaching and run-
off, it was assumed that 30 percent of the non-volatilized
nitrogen applied or excreted (i.e., 30 percent of the sum
of 90 percent of synthetic fertilizer nitrogen plus 80 per-
cent of non-manure organic fertilizer nitrogen plus 80
percent of total livestock nitrogen) was lost to leaching
and surface runoff, and 2.5 percent of the lost nitrogen
was emitted as N2O (IPCC/UNEP/OECD/IEA 1997).
These emission levels are also presented in Table 5-22.
Table 5-15: Commercial Fertilizer Consumption (Metric Tons of Nitrogen)
Fertilizer Type 1990 1991 1992 1993 1994
1995
1996
Synthetic
Manure
Other Organics
Table 5-16: Animal
Activity
Daily Spread
Pasture, Range, &
Paddock
All Management
Systems
Table 5-17: Bean,
Product Type
Soybeans
Peanuts
Dry Edible Beans
Dry Edible Peas
Austrian Winter Peas
Lentils
Wrinkled Seed Peas
Alfalfa
10,110,726
976
763
Excretion
1990
816,082
4,742,247
7,931,542
Pulse, and
1990
52,415,690
1,634,590
1,468,690
107,590
5,760
66,459
41,820
75,671,002
10,271,698
332
1,210
(Metric Tons of
1991
883,915
4,761,332
8,177,248
10,335,778
597
1,256
Nitrogen)
1992
867,342
4,881,526
8,283,417
Alfalfa Production (Metric
1991
54,064,730
2,234,650
1,531,550
168,510
6,300
104,090
41,960
75,585,727
1992
59,611,670
1,943,380
1,025,800
114,990
4,490
71,030
24,360
71,794,602
Table 5-18: Corn and Wheat Production (Metric Tons of
Product Type
Corn for Grain
Wheat
1990
201,533,597
74,292,383
1991
189,867,775
53,890,553
1992
240,719,220
67,135,240
10,727,695
1,056
1,121
1993
853,218
4,952,799
8,379,216
11,171,243
1,206
1,101
1994
839,146
5,095,815
8,581,138
10,794,578
1,339
1,374
1995
838,323
5,192,152
8,645,896
10,996,568
1,099
1,544
1996
819,968
5,099,242
8,518,518
Tons of Product)
1993
50,919,130
1,538,770
993,960
149,320
7,030
90,990
38,510
72,851,472
Product)
1993
160,953,750
65,220,410
1994
69,625,980
1,934,370
1,323,900
102,290
2,310
84,190
34,200
73,786,780
1994
256,621,290
63,166,750
1995
59,243,170
1,570,100
1,397,610
209,060
5,400
97,300
47,540
76,670,720
1995
187,305,080
59,400,390
1996
64,837,320
1,660,690
1,268,240
121,150
4,670
60,460
24,860
72,136,611
1996
236,064,120
62,191,130
Agriculture 5-15
-------
Table 5-19: Histosol Area Cultivated
Year
1990
1991
1992
1993
1994
1995
1996
Hectares
843,386
843,386
843,386
843,386
843,386
843,386
843,386
Table 5-20: Direct N20 Emissions from Agricultural Cropping Practices (MMTCE)
Activity 1990 1991 1992 1993 1994 1995 1996
Commercial Fertilizers
Manure Managed as
Daily Spread
N Fixation
Crop Residue
Histosol Cultivation
Total
15.1
1.1
10.3
6.4
0.6
33.5
15.4
1.2
10.6
6.3
0.6
34.0
15.5
1.2
11.1
7.1
0.6
35.4
16.0
1.1
9.9
6.0
0.6
33.6
16.7
1.1
12.5
8.0
0.6
39.0
16.1
1.1
11.3
6.8
0.6
35.9
16.4
1.1
11.8
7.5
0.6
37.4
Table 5-21: Direct N20 Emissions from Pasture, Range, and Paddock Animals (MMTCE)
Animal Type 1990 1991 1992 1993 1994 1995 1996
Beef Cattle
Horses
Swine
Sheep
Goats
Poultry
Total
9.0
0.5
0.2
0.2
0.1
+
10.1
9.1
0.5
0.2
0.2
0.1
+
10.1
9.3
0.6
0.2
0.2
0.1
+
10.4
9.5
0.6
0.2
0.2
0.1
+
10.5
9.8
0.6
0.2
0.2
0.1
+
10.8
10.0
0.6
0.2
0.2
0.1
+
11.0
9.8
0.6
0.2
0.2
0.1
+
10.8
+ Does not exceed 0.05 MMTCE
Table 5-22: Indirect N20 Emissions (MMTCE)
Activity 1990 1991 1992 1993 1994 1995 1996
Volatilization &
Atmospheric Deposition
Synthetic Fertilizer
Animal Waste
Surface Run-off &
Leaching
Synthetic Fertilizer
Animal Waste
Total
3.5
1.3
2.1
15.4
9.1
6.3
18.8
3,
1
2
15
9
6
19
.5
.4
.2
.7
.2
.5
.3
3.
1
2
15,
9,
6,
19,
,6
.4
.2
.9
.3
.6
.4
3,
1
2
16
9
6
.7
.4
.2
.3
.6
.7
20
3.8
1.5
2.3
16.9
10
6.8
20.6
3,
1
2
16
9
6
20
.7
.4
.3
.6
.7
.9
.3
3.7
1.5
2.3
16.7
9.9
6.8
20.4
Note: Totals may not sum do to independent rounding.
5-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Uncertainty
A number of conditions can affect nitrification and
denitrification rates in soils, including: water content,
which regulates oxygen supply; temperature, which con-
trols rates of microbial activity; nitrate or ammonium
concentration, which regulate reaction rates; available
organic carbon, which is required for microbial activity;
and soil pH, which is a controller of both nitrification
and denitrification rates and the ratio of N2O/N2 from
denitrification. These conditions vary greatly by soil type,
climate, cropping system, and soil management regime.
Although numerous emissions measurement data have
been collected under a wide variety of controlled condi-
tions, the interaction of these conditions and their com-
bined effect on the processes leading to N2O emissions
are not fully understood. Moreover, the amount of added
nitrogen from each source (fertilizers, animal wastes, ni-
trogen fixation, crop residues, cultivation of histosols,
atmospheric deposition, or leaching and runoff) that is
not absorbed by crops or wild vegetation, but remains in
the soil and is available for production of N2O, is uncer-
tain. Therefore, it is not yet possible to develop statisti-
cally valid estimates of emission factors for all possible
combinations of soil, climate, and management condi-
tions. The emission factors used were midpoint estimates
based on measurements described in the scientific litera-
ture, and as such, are representative of current scientific
understanding. Nevertheless, estimated ranges around
each midpoint estimate are wide; most are an order of
magnitude or larger (IPCC/UNEP/OECD/IEA 1997).
Uncertainties also exist in the activity data used to
derive emission estimates. In particular, the fertilizer statis-
tics include only those organic fertilizers that enter the com-
mercial market, so any non-commercial fertilizer use (other
than daily spread livestock waste and incorporation of crop
residues) has not been captured. Also, the nitrogen content
of organic fertilizers varies by type, as well as within indi-
vidual types; however, average values were used to esti-
mate total organic fertilizer nitrogen consumed. Conver-
sion factors for the bean, pulse, and alfalfa production sta-
tistics were based on a limited number of studies, and may
not be representative of all conditions in the United States.
It was assumed that the entire crop residue for corn, wheat,
beans, and pulses was returned to the soils, with the excep-
tion of the fraction burned. A portion of this residue may be
disposed of through other practices, such as composting or
landfilling; however, data on these practices are not avail-
able. Statistics on the histosol area cultivated annually were
not available either; the point estimate reported should be
considered highly uncertain. Lastly, the livestock excretion
values, while based on detailed population and weight sta-
tistics, were derived using simplifying assumptions concern-
ing the types of management systems employed.
Agricultural Residue Burning
Large quantities of agricultural crop residues are
produced by farming activities. There are a variety of
ways to dispose of these residues. For example, agricul-
tural residues can be plowed back into the field,
composted, landfilled, or burned in the field. Alterna-
tively, they can be collected and used as a fuel or sold in
supplemental feed markets. Field burning of crop resi-
dues is not considered a net source of carbon dioxide
(CO2) because the carbon released to the atmosphere as
CO2 during burning is assumed to be reabsorbed during
the next growing season. Crop residue burning is, how-
ever, a net source of methane (CH4), nitrous oxide (N2O),
carbon monoxide (CO), and nitrogen oxide (NOx), which
are released during combustion. In addition, field burn-
ing may result in enhanced emissions of N2O and NOx
many days after burning (Anderson et al. 1988, Levine
et al. 1988), although this process is highly uncertain
and was not addressed.
Field burning is not a common method of agricul-
tural 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, peanut, soybeans, bar-
ley, and corn, and of these residues, generally less than 5
percent is burned each year.12 Annual emissions from
this source over the period 1990 through 1996 averaged
approximately 0.21 MMTCE (36 Gg) of CH4, 0.11
MMTCE (1 Gg ) of NO, 783 Gg of CO, and 32 Gg of
The fraction of rice straw burned each year is thought to be significantly higher (see "Data Sources" discussion below).
Agriculture 5-17
-------
NOx (see Table 5-23 and Table 5-24). These estimates
are significantly higher than those in the previous U.S.
inventories as a result of new research indicating that resi-
dues from a greater number of crop types are typically
burned. The average annual emission estimates for field
burning of crop residues from 1990 through 1996 repre-
sent 1 percent of total U.S. CO emissions.
Methodology
The methodology for estimating greenhouse gas
emissions from field burning of agricultural residues is
consistent with the Revised 1996IPCC Guidelines (IPCC/
UNEP/OECD/IEA 1997). In order to estimate the
amounts of carbon and nitrogen released during burn-
ing, the following equations were used:
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)13
Nitrogen Released = (Annual Crop Production) x
(Residue/Crop Product Ratio) x (Fraction of Residues
Burned in situ) x (Dry Matter Content of the Residue) '
(Burning Efficiency) ' (Nitrogen Content of the Resi-
due) x (Combustion Efficiency)
Emissions of CH4 and CO were calculated by mul-
tiplying the amount of carbon released by the appropri-
ate emission ratio (i.e., CH/C or CO/C). Similarly, N2O
and NOx emissions were calculated by multiplying the
amount of nitrogen released by the appropriate emission
ratio (i.e., N2O/N or NOx/N).
Data Sources
The crop residues burned in the United States were
determined from various state level greenhouse gas emis-
sion inventories (ILENR 1993, Oregon Department of
Energy 1995, Wisconsin Department of Natural Re-
sources 1993) and publications on agricultural burning
in the United States (Jenkins etal. 1992, Turn etal. 1997,
EPA 1992). Crop production data were taken from the
Table 5-23: Emissions from Agricultural Residue Burning (MMTCE)
Gas/Crop Type
CH4
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
N20
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
Total
+ Does not exceed 0.05
1990
0.2
+
+
0.1
+
0.1
+
+
0.1
0.3
MMTCE
Note: Totals may not sum due to independent
1991 1992
0.2 0.2
+ +
+ +
0.1 0.1
+ +
0.1 0.1
+ +
+ +
0.1 0.1
0.3 0.3
rounding.
1993 1994 1995 1996
0.2 0.2 0.2 0.2
+ + + +
+ + + +
0.1 0.1 0.1 0.1
+ + + +
0.1 0.1 0.1 0.1
+ + + +
+ + + +
+ 0.1 0.1 0.1
0.3 0.4 0.3 0.3
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.
5-18
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 5-24: Emissions from Agricultural Residue Burning (Gg)
Gas/Crop Type
CH4
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
N20
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
N0x
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
CO
Wheat
Rice
Sugarcane
Corn
Barley
Soybeans
Peanuts
1990
37
7
4
1
17
1
7
+
1
+
+
+
+
+
1
+
30
1
3
+
11
+
14
+
768
137
93
18
354
15
148
2
1991
34
5
4
1
16
1
7
+
1
+
+
+
+
+
1
+
30
1
3
+
11
+
14
+
718
99
94
20
333
16
153
3
1992
40
6
5
1
19
1
8
+
1
+
+
+
1
+
1
+
34
1
3
+
13
+
16
+
833
124
98
20
404
16
168
3
1993
32
6
4
1
14
1
7
+
1
+
+
+
+
+
1
+
27
1
2
+
9
+
14
+
674
120
77
20
296
14
144
2
1994
41
6
4
1
20
1
9
+
2
+
+
+
1
+
1
+
37
1
3
+
14
+
18
+
858
116
87
20
425
13
194
3
1995
34
5
3
1
16
1
8
+
1
+
+
+
+
+
1
+
30
1
2
+
10
+
16
+
704
109
67
20
326
13
167
2
1996
37
5
3
1
19
1
9
+
1
+
+
+
1
+
1
+
34
1
2
+
13
+
17
+
783
114
57
19
393
14
183
2
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding.
USDA's Crop Production Summaries (USDA 1993,1994,
1995, 1996, 1997). The percentage of crop residue
burned was assumed to be 3 percent for all crops, except
rice, based on state inventory data (ILENR 1993, Or-
egon Department of Energy 1995, Noller 1996, Wiscon-
sin Department of Natural Resources 1993, and
Cibrowski 1996). For rice, the only data that were avail-
able were for California (Jenkins 1997), which was re-
sponsible for about 21 percent of the annual U.S. rice
production. Until 1991, 99 percent of California's rice
area was burned each year after harvest. Since then,
California has tightened restrictions on burning, such that
today, only about half of its rice area is burned each year.
Therefore, a weighted average fraction burned was cal-
culated for rice for each year assuming that the fraction
of rice residue burned in California declined linearly from
99 to 50 percent between 1991 and 1996, while the frac-
tion burned in the rest of the country stayed constant at 3
percent.
Residue/crop product ratios, residue dry matter
contents, residue carbon contents, and residue nitrogen
contents for all crops except sugarcane, peanuts, and soy-
beans were taken from Strehler and Stiitzle (1987). These
data for sugarcane were taken from University of Cali-
fornia (1977) and Turn et al. (1997). Residue/crop prod-
uct ratios and residue dry matter contents for peanuts
and soybeans were taken from Strehler and Sttitzle
(1987); residue carbon contents for these crops were set
at 0.45 and residue nitrogen contents were taken from
Barnard and Kristoferson (1985) (the value for peanuts
Agriculture 5-19
-------
was set equal to the soybean value). The burning effi-
ciency was assumed to be 93 percent, and the combus-
tion efficiency was assumed to be 88 percent for all crop
types (EPA 1994). Emission ratios for all gases were
taken from the Revised 1996IPCC Guidelines (IPCC/
UNEP/OECD/IEA 1997).
Uncertainty
The largest source of uncertainty in the calculation of
non-CO2 emissions from field burning of agricultural resi-
dues is in the estimates of the fraction of residue of each
crop type burned each year. Data on the fraction burned, or
even the gross amount of residue burned each year, are not
collected at either the national or state level. In addition,
burning practices are highly variable among crops, as well
as among states. The fractions of residue burned used in
these calculations were based upon information collected
by state agencies and in published literature. It is likely that
these emission estimates will continue to change as more
information becomes available.
Other sources of uncertainty include the residue/
crop product ratios, residue dry matter contents, burning
and combustion efficiencies, and emission ratios. A resi-
due/crop product ratio fora specific crop can vary among
cultivars, and for all crops except sugarcane, generic resi-
due/crop product ratios, rather than ratios specific to the
United States, have been used. Residue dry matter con-
tents, burning and combustion efficiencies, and emission
ratios, all can vary due to weather and other combustion
conditions, such as fuel geometry. Values for these vari-
ables were taken from literature on agricultural biomass
burning.
5-20
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Land-Use Change
Forestry
This chapter provides an assessment of the net carbon dioxide (CO2) flux caused by changes in forest carbon
stocks (trees, understory, forest floor, forest soil, wood products, and landfilled wood), and a preliminary
assessment of the net CO2 flux caused by changes in non-forest soil carbon stocks (see Table 6-1 and 6-2). Unlike the
assessments for other sectors, which are based on annual activity data, estimates for the Land-Use Change and For-
estry sector are based on periodic activity data in the form of forest, wood product, and landfilled wood surveys. As
a result, the CO2 flux from forest carbon stocks was calculated on an average annual basis. This annual average value
was then applied to the years between surveys. In addition, because the most recent national compilation of state
forest surveys was completed for the year 1992, and the most recent wood product and landfilled wood surveys were
completed for the year 1990, the estimates of the CO2 flux from forest carbon stocks are based in part on modeled
projections of stock estimates for the year 2000.
Carbon dioxide fluxes caused by changes in forest floor, forest soil, and non-forest soil carbon stocks were not
assessed in previous U.S. greenhouse gas inventories due to insufficient data and lack of accepted guidelines. The
assessment of CO2 flux from forest floor and forest soil carbon stocks in this inventory was based on stock estimates
developed by the U.S. Forest Service, and is consistent with the Revised 1996IPCC Guidelines (IPCC/UNEP/OECD/
IEA 1997). The assessment of CO2 flux from non-forest soils was based on the Revised 1996 IPCC Guidelines,
which includes methodologies for calculating non-forest soil carbon flux from three land-use practices: (1) cultiva-
tion of mineral soils, (2) cultivation of organic soils, and (3) liming of agricultural soils. However, due to insufficient
data about these land-use activities in the United States, this chapter provides only a preliminary assessment of CO2
Table 6-1: Net C02 Flux from Land-Use Change and Forestry (MMTCE)
Description 1990 1991 1992 1993 1994 1995 1996
Forests
Trees
Understory
Forest Floor
Soil
Harvested Wood
Wood Products
Landfilled Wood
Total Net Flux*
(274.2)
(95.6)
(2.4)
(20.8)
(155.2)
(37.3)
(17.9)
(19.4)
(311.5)
(274.2)
(95.6)
(2.4)
(20.8)
(155.2)
(37.3)
(17.9)
(19.4)
(311.5)
(274.2)
(95.6)
(2.4)
(20.8)
(155.2)
(37.3)
(17.9)
(19.4)
(311.5)
(171.3)
(74.0)
(1.3)
(9.8)
(86.3)
(37.3)
(17.9)
(19.4)
(208.6)
(171.3)
(74.0)
(1.3)
(9.8)
(86.3)
(37.3)
(17.9)
(19.4)
(208.6)
(171.3)
(74.0)
(1.3)
(9.8)
(86.3)
(37.3)
(17.9)
(19.4)
(208.6)
(171.3)
(74.0)
(1.3)
(9.8)
(86.3)
(37.3)
(17.9)
(19.4)
(208.6)
Note: Parentheses indicate sequestration. Totals may not sum due to independent rounding. Shaded areas indicate values based on a combination
of historical data and projections. All other values are based on historical data only.
'The total net flux excludes preliminary flux estimates for non-forest soils due to the high level of uncertainty of these estimates.
Land-Use Change and Forestry 6-1
-------
Table 6-2: Net CO Flux from Land-Use Change and Forestry (Tg CO
Description
1990
1991
1992
1993
1994
1995
1996
Forests
Trees
Understory
Forest Floor
Soil
Harvested Wood
Wood Products
Landfilled Wood
Total Net Flux*
(1,005.4)
(350.5)
(8.8)
(76.3)
(569.1)
(136.8)
(65.5)
(71.2)
(1,142.2)
(1,005.4)
(350.5)
(8.8)
(76.3)
(569.1)
(136.8)
(65.5)
(71.2)
(1,142.2)
(1,005.4)
(350.5)
(8.8)
(76.3)
(569.1)
(136.8)
(65.5)
(71.2)
(1,142.2)
(627.9)
(271.3)
(4.6)
(35.8)
(316.3)
(136.8)
(65.5)
(71.2)
(764.7)
(627.9)
(271.3)
(4.6)
(35.8)
(316.3)
(136.8)
(65.5)
(71.2)
(764.7)
(627.9)
(271.3)
(4.6)
(35.8)
(316.3)
(136.8)
(65.5)
(71.2)
(764.7)
(627.9)
(271.3)
(4.6)
(35.8)
(316.3)
(136.8)
(65.5)
(71.2)
(764.7)
Note: Parentheses indicate sequestration. Totals may not sum due to independent rounding. Shaded areas indicate values based on a
combination of historical data and projections. All other values are based on historical data only.
"The total net flux excludes preliminary flux estimates for non-forest soils due to the high level of uncertainty of these estimates.
fluxes from two of the three land-use practices: cultiva-
tion of organic soils and liming of agricultural soils.
Because of the high level of uncertainty associated with
these two flux estimates, and the lack of a flux estimate
for the third activity, the non-forest soil flux estimates
have not been incorporated into the total fluxes reported
for the Land-Use Change and Forestry sector.
Changes in Forest Carbon Stocks
Globally, the most important human activity that
affects forest carbon fluxes is deforestation, particularly
the clearing of tropical forests for agricultural use. Tropi-
cal deforestation is estimated to have released nearly 6
billion metric tons of CO2 per year during the 1980s, or
about 23 percent of global CO2 emissions from anthro-
pogenic activities. Conversely, during this period about
7 percent of global CO2 emissions were offset by CO2
uptake due to forest regrowth in the Northern Hemisphere
(Houghton et al. 1995).
In the United States, the amount of forest land has
remained fairly constant during the last several decades.
The United States covers roughly 2,263 million acres, of
which 3 3 percent (737 million acres) is forest land (Powell
et al. 1993). The amount of forest land declined by ap-
proximately 5.2 million acres between 1977 and 1987
(USFS 1990,Waddelletal. 1989), and increased by about
5.3 million acres between 1987 and 1992 (Powell et al.
1993). These changes represent average fluctuations of
only about 0.1 percent per year. Other major land-use
categories in the United States include range and pasture
lands (29 percent), cropland (17 percent), urban areas (3
percent), and other lands (18 percent) (Daugherty 1995).
Given the low rate of change in U.S. forest land
area, the major influences on the current net carbon flux
from forest land are management activities and ongoing
impacts of previous land-use changes. These activities
affect the net flux of carbon by altering the amount of
carbon stored in forest ecosystems. For example, inten-
sified management of forests can increase both the rate
of growth and the eventual biomass density of the forest,
thereby increasing the uptake of carbon. The reversion
of cropland to forest land through natural regeneration
also will, over decades, result in increased carbon stor-
age in biomass and soils.
Forests are complex ecosystems with several in-
terrelated components, each of which acts as a carbon
storage pool, including:
• Trees (i.e., living trees, standing dead trees, roots,
stems, branches, and foliage)
• Understory vegetation (i.e., shrubs and bushes)
• The forest floor (i.e., woody debris, tree litter, and
humus)
• Soil
As a result of biological processes in forests (e.g.,
growth and mortality) and anthropogenic activities (e.g.,
harvesting, thinning, and replanting), carbon is continu-
ously cycled through these ecosystem components, as
well as between the forest ecosystem and the atmosphere.
For example, the growth of trees results in the uptake of
carbon from the atmosphere and storage of carbon in
living biomass. As trees age, they continue to accumu-
6-2
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
late carbon until they reach maturity, at which point they
are relatively constant carbon stores. As trees die and
otherwise deposit litter and debris on the forest floor,
decay processes release carbon to the atmosphere and
also increase soil carbon. The net change in forest car-
bon is the sum of the net changes in the total amount of
carbon stored in each of the forest carbon pools overtime.
The net change in forest carbon, however, may not
be equivalent to the net flux between forests and the at-
mosphere because timber harvests may not always re-
sult in an immediate flux of carbon to the atmosphere.'
Harvesting in effect transfers carbon from one of the "for-
est pools" to a "product pool." Once in a product pool,
the carbon is emitted over time as CO2 if the wood prod-
uct combusts or decays. The rate of emission varies con-
siderably among different product pools. For example,
if timber is harvested for energy use, combustion results
in an immediate release of carbon. Conversely, if timber
is harvested and subsequently used as lumber in a house,
it may be many decades or even centuries before the lum-
ber is allowed to decay and carbon is released to the at-
mosphere. If wood products are disposed of in land-
fills, the carbon contained in the wood may be released
years or decades later, or may even be stored permanently
in the landfill.
In the United States, improved forest management
practices, the regeneration of previously cleared forest
areas, and timber harvesting and use have resulted in an
annual net uptake (i.e., sequestration) of carbon. Also
due to improvements in U.S. agricultural productivity,
the rate of forest land 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 brought out of crop production,
primarily between 1920 and 1950, and were allowed to
revert to forest land or were actively reforested. The
impacts of these land-use changes are still affecting
carbon fluxes from forests in the East. In addition to
land-use changes in the early part of this century, in recent
decades carbon fluxes from Eastern forests were affected
by a trend toward managed growth on private land,
resulting in a near doubling of the biomass density in
eastern forests since the early 1950s. More recently, the
1970s and 1980s saw a resurgence of federally sponsored
tree-planting programs (e.g., the Forestry Incentive
Program) and soil conservation programs (e.g., the
Conservation Reserve Program), which have focused on
reforesting previously harvested lands, improving timber
management activities, combating soil erosion, and
converting marginal cropland to forests. In addition to
forest regeneration and management, forest harvests have
also affected net carbon fluxes. Because most of the
timber that is harvested from U.S. forests is used in wood
products and much of the discarded wood products are
disposed of by landfilling—rather than incineration—
significant quantities of this harvested carbon are
transferred to long-term storage pools rather than being
released to the atmosphere. The size of these long-term
carbon storage pools has also increased steadily over the
last century.
As shown in Table 6-3, U.S. forest components,
wood product pools, and landfill wood were estimated
to account for an average annual net sequestration of
311.5 MMTCE from 1990 through 1992, and 208.6
MMTCE from 1993 through 1996. The net carbon se-
questration reported for 1996 represents an offset of about
14 percent of the 1996 CO2 emissions from fossil fuel
combustion. The average annual net carbon sequestra-
tion reported for 1993 through 1996 represents a 33 per-
cent decrease relative to the average annual net carbon
sequestration reported for 1990 through 1992. The over-
all decrease in annual net sequestration between 1990
and 1992 and between 1993 and 1996 is due to changes
in the aggregate age structure of U.S. forests caused by
the maturation of existing forests and the slowed expan-
sion of Eastern forest cover. The abrupt shift in annual
net sequestration from 1992 to 1993 is the result of cal-
culating average annual fluxes using periodic activity data
as well as models that project decadal rather than annual
sequestration estimates.
The estimates of total net flux in Table 6-3 are sig-
nificantly higher than those provided in previous inven-
tories (EPA 1995, 1997). These earlier inventories in-
i
For this reason, the term "apparent flux" is used in this chapter.
Land-Use Change and Forestry 6-3
-------
Table 6-3: Net CO, Flux from U.S. Forests (MMTCE)
Description
1990
1991
1992
1993
1994
1995
1996
Apparent Forest Flux
Trees
Understory
Forest Floor
Forest Soils
Apparent Harvested Wood Flux
Apparent Wood Product Flux
Apparent Landfilled Wood Flux
Total Net Flux
(274.2)
(95.6)
(2.4)
(20.8)
(155.2)
(37.3)
(17.9)
(19.4)
(311.5)
(274.2)
(95.6)
(2.4)
(20.8)
(155.2)
(37.3)
(17.9)
(19.4)
(311.5)
(274.2)
(95.6)
(2.4)
(20.8)
(155.2)
(37.3)
(17.9)
(19.4)
(311.5)
(171.3)
(74.0)
(1.3)
(9.8)
(86.3)
(37.3)
(17.9)
(19.4)
(208.6)
(171.3)
(74.0)
(1.3)
(9.8)
(86.3)
(37.3)
(17.9)
(19.4)
(208.6)
(171.3)
(74.0)
(1.3)
(9.8)
(86.3)
(37.3)
(17.9)
(19.4)
(208.6)
(171.3)
(74.0)
(1.3)
(9.8)
(86.3)
(37.3)
(17.9)
(19.4)
(208.6)
Note: Parentheses indicate net carbon "sequestration" (i.e., sequestration or accumulation into the carbon pool minus emissions or harvest
from the carbon pool). The word "apparent" is used to indicate that an estimated flux is a measure of net change in carbon stocks, rather than
an actual flux to or from the atmosphere. The sum of the apparent fluxes in this table (i.e., total flux) is an estimate of the actual flux. Shaded
areas indicate values based on a combination of historical data and projections. All other values are based on historical data only. Totals may
not sum due to independent rounding.
eluded only tree and understory fluxes, whereas the esti-
mates in this inventory account for changes in all four
forest carbon storage components: (1) trees, (2) under-
story, (3) forest floor, and (4) soil. In addition, the ear-
lier inventories accounted for wood products and
landfilled wood associated with harvests from private tim-
berland only, whereas the revised estimates presented here
account for wood products and landfilled wood associ-
ated with harvests from both private and public timber-
land.
Methodology
The methodology for estimating annual forest car-
bon flux in the United States differs from the method-
ologies employed for other sources because the forest
carbon flux estimates for the Land-Use Change and For-
estry sector were derived from periodic surveys of forest
carbon stocks rather than annual activity data. Three sur-
veys of forest carbon stocks were used: (1) timber stocks,
(2) wood products, and (3) landfilled wood. In addition,
because national compilations of state forest surveys have
not been completed for 1997, projections of forest car-
bon stocks, rather than complete historical data, were used
to derive some of the annual flux estimates.
Timber stock data from forest surveys were used
to derive estimates of carbon contained in the four forest
ecosystem components (trees, understory, forest floor,
and soil) for the survey years. The apparent annual for-
est carbon flux for a specific year was estimated as the
average annual change in the total forest carbon stocks
between the preceding and succeeding timber survey
years. The most recent national compilations of state
forest surveys were conducted for the years 1987 and
1992, and a projection has been prepared for the year
2000. Therefore, the apparent annual forest carbon flux
estimate for the years 1990 through 1992 was calculated
from forest carbon stocks reported for 1987 and 1992,
and the apparent annual forest carbon flux estimate for
the years 1993 through 1996 was calculated from forest
carbon stocks for 1992 and projected forest carbon stocks
for the year 2000.
Carbon stocks contained in the wood product and
landfilled wood pools were estimated for 1990 using his-
torical forest harvest data, and were estimated for 2000
using projections of forest harvest. Therefore, apparent
annual wood product and landfilled wood fluxes for the
years 1990 through 1996 were calculated from a 1990
historical estimate and a 2000 projection.
The total annual net carbon flux from forests was
obtained by summing the apparent carbon fluxes associ-
ated with changes in forest stocks, wood product pools,
and landfilled wood pools.
The inventory methodology described above is
consistent with the Revised 1996IPCC Guidelines (IPCC/
UNEP/OECD/IEA 1997). The IPCC identifies two ap-
proaches to developing an emissions inventory for the
Land-Use Change and Forestry sector: (1) using aver-
age annual statistics on land-use change and forest man-
agement activities, and applying carbon density and flux
rate data to these activity estimates to derive total flux
6-4
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
values; or (2) using carbon stock estimates derived from
periodic inventories of forest stocks, and measuring net
changes in carbon stocks over time. The latter approach
was employed because the United States conducts peri-
odic surveys of national forest stocks. In addition, the
IPCC identifies two approaches to accounting for car-
bon emissions from harvested wood: (1) assuming that
all of the harvested wood replaces wood products that
decay in the inventory year so that the amount of carbon
in annual harvests equals annual emissions from harvests;
or (2) accounting for the variable rate of decay of har-
vested wood according to its disposition (e.g., product
pool, landfill, combustion). The latter approach was ap-
plied for this inventory using estimates of carbon stored
in wood products and landfilled wood.2 Although there
are large uncertainties associated with the data used to
develop the flux estimates presented here, the use of di-
rect measurements from forest surveys and associated
estimates of product and landfilled wood pools is likely
to result in more accurate flux estimates than the alterna-
tive IPCC methodology.
Data Sources
The estimates of forest, product, and landfill car-
bon stocks used in this inventory to derive carbon fluxes
were obtained from Birdsey and Heath (1995), Heath et
al. (1996), and Heath (1997). The amount of carbon in
trees, understory vegetation, the forest floor, and forest
soil in 1987 and 1992 was estimated using timber vol-
ume data collected by the U.S. Forest Service (USFS)
for those years (Waddell et al. 1989, Powell et al. 1993).
The timber volume data include timber stocks on forest
land classified as timberland, reserved forest land, or other
forest land3 in the contiguous United States, but do not
include stocks on forest land in Alaska or Hawaii or trees
on non-forest land (e.g., urban trees).4 The timber vol-
ume data include estimates by tree species, size class,
and other categories.
The amount of carbon in trees, understory vegeta-
tion, the forest floor, and forest soil in 2000 was esti-
mated by Birdsey and Heath (1995) using the FORCARB
forest carbon model (Plantinga and Birdsey 1993) linked
to the TAMM/ATLAS forest sector model (Adams and
Haynes 1980, Alig 1985, Haynes and Adams 1985, Mills
andKincaid 1992). The forest stock projections for 2000,
therefore, are based on multiple variables, including pro-
jections of prices, consumption, and production of tim-
ber and wood products; and projections of forest area,
forest inventory volume, growth, and removals.
The amount of carbon in aboveground and
belowground tree biomass in forests was calculated by
multiplying timber volume by conversion factors derived
from studies in the United States (Cost et al. 1990, Koch
1989). Carbon stocks in the forest floor and understory
vegetation were estimated based on simple models (Vogt
et al. 1986) and review of numerous intensive ecosystem
studies (Birdsey 1992). Soil carbon stocks were calcu-
lated using a model similar to Burke et al. (1989) based
on data from Post et al. (1982).
Carbon stocks in wood products in use and in wood
stored in landfills were estimated by applying the
HARVCARB model (Row and Phelps 1991) to histori-
cal harvest data from the USFS (Powell et al. 1993) and
harvest projections for 2000 (Adams and Haynes 1980,
Mills andKincaid 1992). The HARVCARB model allo-
cates harvested carbon to disposition categories (prod-
ucts, landfills, energy use, and emissions), and tracks the
accumulation of carbon in different disposition catego-
ries over time.
This calculation does not account for carbon stored in imported wood products. It does include carbon stored in exports, even if the logs
are processed in other countries (Heath et al. 1996).
Forest land in the U.S. includes all land that is at least 10 percent stocked with trees of any size. Timberland is the most productive type of
forest land, growing at a rate of 20 cubic feet per acre per year or more. In 1992, there were about 490 million acres of Timberlands, which
represented 66 percent of all forest lands (Powell et al. 1993). Forest land classified as Timberland is unreserved forest land that is producing
or is capable of producing crops of industrial wood. The remaining 34 percent of forest land is classified as Productive Reserved Forest Land,
which is withdrawn from timber use by statute or regulation, or Other Forest Land, which includes unreserved and reserved unproductive forest
land.
Although forest carbon stocks in Alaska and Hawaii are large compared to the U.S. total, net carbon fluxes from forest stocks in Alaska and
Hawaii are believed to be minor. Net carbon fluxes from urban tree growth are also believed to be minor.
Land-Use Change and Forestry 6-5
-------
Table 6-4: U.S. Forest Carbon Stock Estimates5 (Tg of Carbon)
Description
1987
1990
1992
2000
Forests
Trees
Understory
Forest Floor
Forest Soil
Harvested Wood
Wood Products
Landfilled Wood
36,353
13,009
558
2,778
20,009
NA
NA
NA
NA
NA
NA
NA
NA
3,739
2,061
1,678
37,724
13,487
570
2,882
20,785
NA
NA
NA
39,094
14,079
580
2,960
21,475
4,112
2,240
1,872
NA (Not Available)
Note: Forest carbon stocks do not include forest stocks in Alaska or Hawaii, 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. Shaded areas indicate values based on a
combination of historical data and projections. All other values are based on historical data only. Totals may not sum due to independent
rounding.
Table 6-4 presents the carbon stock estimates for
forests (including trees, understory, forest floor, and for-
est soil), wood products, and landfilled wood used in this
inventory. The increase in all of these stocks over time
indicates that, during the examined periods, forests, for-
est product pools, and landfilled wood all accumulated
carbon (i.e., carbon sequestration by forests was greater
than carbon removed in wood harvests and released
through decay; and carbon accumulation in product pools
and landfills was greater than carbon emissions from these
pools by decay and burning).
Uncertainty
There are considerable uncertainties associated
with the estimates of the net carbon flux from U.S. for-
ests. The first source of uncertainty stems from the un-
derlying forest survey data. These surveys are based on
a statistical sample designed to represent a wide variety
of growth conditions present over large territories. There-
fore, the actual timber volumes contained in forests are
represented by average values that are subject to sam-
pling and estimation errors. In addition, the forest sur-
vey data that are currently available exclude timber stocks
on forest land in Alaska or Hawaii, and trees on non-
forest land (e.g., urban trees); however, net carbon fluxes
from these stocks are believed to be minor.
The second source of uncertainty results from de-
riving carbon storage estimates for the forest floor, un-
derstory vegetation, and soil from models that are based
on data from forest ecosystem studies. In order to ex-
trapolate results of these studies to all forest lands, it was
assumed that they adequately describe regional or na-
tional averages. This assumption can potentially intro-
duce the following errors: (1) bias from applying data
from studies that inadequately represent average forest
conditions, (2) modeling errors (erroneous assumptions),
and (3) errors in converting estimates from one report-
ing unit to another (Birdsey and Heath 1995). In par-
ticular, the impacts of forest management activities, in-
cluding harvest, on soil carbon are not well understood.
Moore et al. (1981) found that harvest may lead to a 20
percent loss of soil carbon, while little or no net change
in soil carbon following harvest was reported in another
study (Johnson 1992). Since forest soils contain over 50
percent of the total stored forest carbon in the United
States, this difference can have a large impact on flux
estimates.
The third source of uncertainty results from the use
of projections of forest carbon stocks for the year 2000
(Birdsey and Heath 1995) to estimate annual net carbon
sequestration from 1993 to 1996. These projections are
the product of two linked models (FORCARB and
TAMM/ATLAS) that integrate multiple uncertain vari-
ables related to future forest growth and economic fore-
casts. Because these models project decadal rather than
annual carbon fluxes, estimates of annual net carbon se-
questration from 1993 to 1996 are calculated as average
annual estimates based on projected long-term changes
in U.S. forest stocks.
5 Sources: Heath (1997), Heath et al. (1996), and Birdsey and Heath (1995).
6-6
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
The fourth source of uncertainty results from in-
complete accounting of wood products. Because the
wood product stocks were estimated using U.S. harvest
statistics, these stocks include exports, even if the logs
were processed in other countries, and exclude imports.
Haynes (1990) estimates that imported timber accounts
for about 12 percent of the timber consumed in the United
States, and that exports of roundwood and primary prod-
ucts account for about 5 percent of harvested timber.
Changes in Non-Forest
Soil Carbon Stocks
The amount of organic carbon contained in soils
depends on the balance between inputs of photosyntheti-
cally fixed carbon (i.e., organic matter such as decayed
detritus and roots) and loss of carbon through decompo-
sition. The quantity and quality of organic matter in-
puts, and the rate of decomposition, are determined by
the combined interaction of climate, soil properties, and
land-use. Agricultural practices and other land-use ac-
tivities, such as clearing, drainage, tillage, planting, crop
residue management, fertilization, and flooding, can
modify both organic matter inputs and decomposition,
and thereby result in a net flux of carbon dioxide (CO2)
to or from soils. The addition of carbonate minerals to
soils through liming operations also results in net emis-
sions of CO2. Changes in non-forest soil carbon stocks
include net fluxes of CO2 from three categories of land-
use/land-management activities: (1) activities on organic
soils, especially cultivation and conversion to pasture and
forest; (2) activities on mineral soils, especially land-use
change activities; and (3) liming of soils.6 Organic soils
and mineral soils are treated separately because each re-
sponds differently to land-use practices.
Organic soils contain extremely deep and rich lay-
ers of organic matter. When these soils are cultivated,
tilling or mixing of the soil brings buried organic matter
to the soil surface, thereby accelerating the rate of de-
composition and CO2 generation. Because of the depth
and richness of the organic layer, carbon loss from culti-
vated organic soils can be sustained over long periods of
time (IPCC/UNEP/OECD/IEA 1997). Conversion of
organic soils to agricultural uses typically involves drain-
age as well, which also exacerbates soil carbon oxida-
tion. When organic soils are disturbed, through cultiva-
tion and/or drainage, the rate at which organic matter
decomposes, and therefore the rate at which CO2 emis-
sions are generated, is determined primarily by climate,
the composition (decomposability) of the organic mat-
ter, and the specific land-use practices undertaken. The
use of organic soils for upland crops results in greater
carbon loss than conversion to pasture or forests, due to
deeper drainage and/or more intensive management prac-
tices (Armentano and Verhoeven 1990, as cited in IPCC/
UNEP/OECD/IEA 1997).
Mineral soils generally have fairly shallow organic
layers and therefore have low organic carbon contents
relative to organic soils. Consequently, it is possible to
entirely deplete the carbon stock of a mineral soil within
the first 10 to 20 years of disturbance, depending on the
type of disturbance, climate, and soil type. Once the
majority of the native carbon stock has been depleted, an
equilibrium is reached that reflects a balance between
accumulation from plant residues and loss of carbon
through decomposition. Various land-use practices, such
as incorporation of crop residues and cultivation of cer-
tain crops, can result in a net accumulation of carbon
stocks in mineral soils.
Lime in the form of crushed limestone (CaCO3)
and dolomite (CaMg(CO3)2) is commonly added to agri-
cultural soils to ameliorate acidification. When these
compounds come in contact with acid soils, they degrade,
thereby generating CO2. The rate of degradation is de-
termined by soil conditions and the type of mineral ap-
plied; it can take several years for agriculturally-applied
lime to degrade completely.
Fluxes of CC>2 from forest soils are excluded from this section because they are included in the previous section (Changes in Forest Carbon
Stocks).
Land-Use Change and Forestry 6-7
-------
Table 6-5:
(MMTCE)
Year
1990
1991
1992
1993
1994
1995
1996
C02 Flux From
Mineral
Soils
NA
NA
NA
NA
NA
NA
NA
Non-Forest Soils
Organic
Soils
5.9
5.9
5.9
5.9
5.9
5.9
5.9
Liming
of Soils
2.3
2.8
2.2
2.1
2.3
2.2
2.8
NA (Not Available)
Note: The C02 flux from non-forest soils has been excluded from
the total flux reported for the land-use change and forestry sector
due to the high level of uncertainty associated with these
estimates.
Table 6-6:
(Tg C02)
Year
1990
1991
1992
1993
1994
1995
1996
C02 Flux From
Nuberak
Soils
NA
NA
NA
NA
NA
NA
NA
Non-Forest Soils
Organic
Soils
21.8
21.8
21.8
21.8
21.8
21.8
21.8
Liming
of Soils
8.4
10.2
8.0
7.7
8.5
7.9
10.1
NA (Not Available)
Note: The C02 flux from non-forest soils has been excluded from
the total flux reported for the land-use change and forestry sector
due to the high level of uncertainty associated with these
estimates.
Only two categories of land-use/land-management
activities—agricultural use of organic soils and liming—
are included in the estimates of CO2 emissions presented
here, because insufficient activity data are available to
estimate fluxes from mineral soils. Net annual emissions
of CO2 from organic soils and liming of soils in the United
States over the period 1990 through 1996 totaled approxi-
mately 8 to 9 MMTCE (30 to 32 Tg) (see Table 6-5 and
Table 6-6).
Annual CO2 emissions from agricultural use of or-
ganic soils were estimated to be 5.9 MMTCE (21.8 Tg)
over the 1990 through 1996 period. Organic soil data
were available for only 1982; therefore, emissions from
organic soils were assumed to stay constant at the 1982
level for the years 1990 to 1996. Liming accounted for
net annual CO2 emissions of approximately 2.1 to 2.8
MMTCE (8 to 10 Tg). There was no apparent trend over
the seven year period.
The emission estimates and analysis in this section
are restricted to CO2 fluxes associated with the manage-
ment of non-forest organic soils and liming of soils.
However, it is important to note that land-use and land-
use change activities may also result in fluxes of non-
CO2 greenhouse gases, such as methane (CH4), nitrous
oxide (N2O), and carbon monoxide (CO), to and from
soils. For example, when lands are flooded with fresh-
water, such as during hydroelectric dam construction, CH4
is produced and emitted to the atmosphere due to anaero-
bic decomposition of organic material in the soil and
water column. Conversely, when flooded lands, such as
lakes and wetlands, are drained, anaerobic decomposi-
tion and associated CH4 emissions will be reduced. Dry
soils are a sink of CH4, so eventually, drainage may re-
sult in soils that were once a source of CH4 becoming a
sink of CH4. However, once the soils become aerobic,
oxidation of soil carbon and other organic material will
result in elevated emissions of CO2. Moreover, flooding
and drainage may also affect net soil fluxes of N2O and
CO, although these fluxes are highly uncertain. The
fluxes of CH4, and other gases, due to flooding and drain-
age are not assessed in this inventory due to a lack of
activity data on the extent of these practices in the United
States as well as scientific uncertainties about the vari-
ables that control fluxes.7
Methodology and Data Sources
The methodologies used to calculate CO2 emissions
from cultivation of organic soils and liming follow the
Revised 1996IPCC Guidelines (IPCC/UNEP/OECD/IEA
1997).
To estimate annual CO2 emissions from organic
soils, the area under agricultural usage was divided into
broad climatic regions, and the area in each climatic re-
gion was multiplied by an emission factor. (All areas
were cropped rather than utilized for pasture or forestry,
However, methane emissions due to flooding of rice fields are included. These are addressed under Rice Cultivation in the Agriculture
sector.
6-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
so there was no need to further divide areas into general
land-use types). Annual statistics on the area of organic
soils under agricultural usage were not available for the
years 1990 through 1996; therefore, an estimate for the
area cultivated in 1982 (Mausbach and Spivey 1993) was
used for all years in the 1990 to 1996 series. The area
estimate was derived from USDA land-use statistics. Of
the 850,000 hectares of organic soils under cultivation
in 1982, Mausbach and Spivey (1993) estimated that two-
thirds were located in warm, temperate regions and one-
third was located in cool, temperate regions (Table 6-7).
The IPCC default emission factors (10 metric tons C/
hectare/year for warm, temperate regions, 1.0 metric tons
C/hectare/yearfor cool, temperate regions) were applied
to these areas to estimate annual CO2 emissions result-
ing from cultivation of organic soils.
Carbon dioxide emissions from degradation of
limestone and dolomite applied to agricultural soils were
calculated by multiplying the annual amounts of lime-
stone and dolomite applied, by CO2 emission factors
(0.120 metric ton C/metric ton limestone, 0.130 metric
ton C/metric ton dolomite).8 These emission factors are
based on the assumption that all of the carbon in these
materials evolves as CO2. The annual application rates
of limestone and dolomite were derived from estimates
and industry statistics provided in the U.S. Geological
Survey's Mineral Resources Program crushed stone re-
ports (USGS 1997a, 1997b, 1996, 1995, 1993). To de-
velop these data, the Mineral Resources Program 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 are
divided into three components: (1) production by end-
use, as reported by manufacturers (i.e., "specified" pro-
duction); (2) production reported by manufacturers with-
out end-uses specified (i.e., "unspecified" production);
and (3) estimated additional production by manufactur-
ers who did not respond to the survey (i.e., "estimated"
production). To estimate the total amounts of crushed
limestone and dolomite applied to agricultural soils, it
was assumed that the fractions of "unspecified" and "es-
timated" production that were applied to agricultural soils
were equal to the fraction of "specified" production that
was applied to agricultural soils. In addition, the total
crushed limestone and dolomite production figures for
1991, 1993, and 1994 were revised by the Mineral Re-
sources Program in later reports, but end uses were not
specified. To estimate the amounts applied to agricul-
tural soils, it was assumed that the fractions estimated
using the previously published data did not change.
Uncertainty
Uncertainties in the emission estimates presented
result primarily from the underlying activity data used
in the calculations. In particular, statistics on the areas
of organic soil cultivated or managed as pasture or forest
were not available, and the point estimate of total or-
ganic soil cultivated is highly uncertain. In addition, the
breakdown of the cultivated organic soil area by climate
region was based upon a qualitative assessment of the
location of cultivated organic soils. Furthermore, there
Table 6-7: Areas of Cultivated Organic Soils and Quantities of Applied Minerals
Description 1990 1991 1992 1993 1994
1995
1996
Organic Soils Area Cultivated (hectares)
Warm Temperate Regions
Cool Temperate Regions
Applied Minerals (Gg)
Limestone
Dolomite
566,000
284,000
16,385
2,543
566,000
284,000
19,820
3,154
566,000
284,000
15,574
2,417
566,000
284,000
15,340
2,040
566,000
284,000
16,730
2,294
566,000
284,000
15,050
2,770
566,000
284,000
19,657
3,051
8 Note: the default emission factor for dolomite provided in the Workbook volume of the Revised 1996 IPCC Guidelines (IPCC/UNEP/
OECD/IEA 1997) is incorrect. The value provided is 0.122 metric ton carbon/ metric ton of dolomite; the correct value is 0.130 metric ton
carbon/ metric ton of dolomite.
Land-Use Change and Forestry 6-9
-------
are uncertainties in the estimates of total limestone and
dolomite applied to agricultural soils, which are based
on estimates as well as reported quantities.
The emission factors used in the calculations are
an additional source of uncertainty. As discussed above,
CO2 emissions from cultivation of organic soils are con-
trolled by climate, the composition of the soil organic
matter, and cultivation practices. Only the first variable
is taken into account, and only in a general way, in deriv-
ing the emission factors. Moreover, measured carbon
loss rates from cultivated organic soils vary by as much
as an order of magnitude.
The rate of degradation of applied limestone and
dolomite is determined by soil conditions and the type
of mineral applied. It can take several years for agricul-
turally-applied lime to degrade completely. The approach
used to estimate CO2 emissions from liming assumed that
the amount of mineral applied in any year was equal to
the amount that degrades in that year, so annual applica-
tion rates could be used to derive annual emissions.; how-
ever, this assumption may be incorrect. Moreover, soil
conditions were not taken into account in the calcula-
tions.
Because the estimates of CO2 fluxes from non-for-
est soils are based on limited and highly uncertain activ-
ity data and cover only a subset of the CO2 fluxes associ-
ated with this source, the estimate of CO2 flux from non-
forest soils has been excluded from the total flux reported
for the Land-Use Change and Forestry sector.
6-10
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
7. Waste
Figure 7-1
1996 Waste Sector GHG Sources
Landfill*
;r i
Certain waste management and treatment activities
are sources of greenhouse gas emissions.
Particularly the anaerobic decomposition of organic wastes
by bacteria can result in the generation of methane (C.
Currently, anaerobic decomposition processes in landfills are
estimated to be the largest anthropogenic source of methane
emissions in the United States, accounting for just over 36
percent of the total (see Figure 7-1). Smaller amounts of
methane are emitted from wastewater systems by bacteria
used in various treatment processes. Wastewater treatment
systems are also a potentially significant source of nitrous
oxide (N2O) emissions; however, methodologies are not
currently available to develop a complete estimate. Emissions
from the treatment of the human sewage component of wastewater were estimated, however, using a simplified methodology.
Waste combustion, both in incinerators and through open burning, is a small source of N2O. Nitrogen oxide (NOx), carbon
monoxide (CO), and non-methane volatile organic compounds (NMVOCs) are emitted by each of these sources, but are
addressed separately at the end of this chapter. A summary of greenhouse gas emissions from the Waste sector is presented
in Table 7-1 and Table 7-2.
Landfills
Troatmont
Watt*
-MI> I .r-l:.ii i
I
MWTCE
Landfills are the largest anthropogenic source of methane (CH4) emissions in the United States. In 1996,
emissions were approximately 65.1 MMTCE (11.4 Tg), or just over 36 percent of U.S. methane emissions (see Table
7-3 and Table 7-4). Emissions from municipal solid waste (MSW) landfills, which received about 62 percent of the
total solid waste generated in the United States, accounted for about 93 percent of total landfill emissions, while
industrial landfills accounted for the remaining. There are over 6,000 landfills in the United States, with 1,300 of the
largest landfills receiving almost all the waste and generating the vast majority of the emissions.
Methane emissions result from the decomposition of organic landfill materials such as yard waste, household
garbage, food waste, and paper. This decomposition process is a natural mechanism through which microorganisms
derive energy. After being placed in a landfill, organic waste first decomposes aerobically (in the presence of oxygen)
and is then attacked by anaerobic bacteria, which convert organic matter to substances such as cellulose, amino acids,
and sugars. These simple substances are further broken down through fermentation into gases and short-chain or-
ganic compounds that form the substrates for the growth of methanogenic bacteria. Methane producing anaerobic
Waste
7-1
-------
Table 7-1: Emissions from the Waste Sector (MMTCE)
Gas/Source
1990
1991
1992
1993
1994
1995
1996
CH4
Landfills
Wastewater Treatment
N20
Human Sewage
Waste Combustion
Total
57.1
56.2
0.9
1.4
2.1
0.1
59.3
58.4
57.6
0.9
1.4
2.1
0.1
60.6
58.7
57.8
0.9
1.5
2.2
0.1
61.0
60.6
59.7
0.9
1.5
2.2
0.1
62.8
62.5
61.6
0.9
1.5
2.3
0.1
64.8
64.5
63.6
0.9
1.5
2.2
0.1
66.9
66.0
65.1
0.9
1.5
2.3
0.1
68.4
Note: Totals may not sum due to independent rounding.
Table 7-2: Emissions from the Waste Sector (Tg)
Gas/Source
1990
1991
1992
1993
1994
1995
1996
CH4
Landfills
Wastewater Treatment
N20
Human Sewage
Waste Combustion
10.0
9.8
0.2
;
10.2
10.0
0.2
;
10.3
10.1
0.2
;
10.6
10.4
0.2
;
10.9
10.8
0.2
;
11.3
11.1
0.2
;
11.5
11.4
0.2
;
+ Does not exceed 0.05 Tg
Note: Totals may not sum due to independent rounding.
bacteria then convert these fermentation products into
stabilized organic materials and a biogas consisting of
approximately 50 percent carbon dioxide and 50 percent
methane by volume. In general, the CO2 emitted is of
biogenic origin and primarily results from the decompo-
sition—either aerobic or anaerobic—of organic matter
such as food or yard wastes.' The percentage of carbon
dioxide in the biogas released from a landfill may be
smaller because some CO2 dissolves in landfill water
(Bingemerand Crutzen 1987). Methane production typi-
cally begins one or two years after waste placement in a
landfill and may last from 10 to 60 years.
Between 1990 and 1996, estimates of methane
emissions from landfills have increased slightly. The rela-
tively constant emissions estimates are a result of two
counter-acting factors: (1) the amount of MSW in land-
fills contributing to methane emissions has increased
(thereby increasing the potential for emissions), and (2)
the amount of landfill gas collected and combusted by
landfill operators has also increased (thereby reducing
emissions).
Methane emissions from landfills are a function of
several factors, including: the total amount of MSW
landfilled over the last 30 years, which is related to total
MSW landfilled per year; composition of the waste in
place; the amount of methane that is recovered and ei-
ther flared or used for energy purposes; and the amount
of methane oxidized in landfills before being released
into the atmosphere. The estimated total quantity of waste
in place contributing to emissions increased from about
4,926 teragrams in 1990 to 5,676 teragrams in 1996, an
increase of 15 percent (see Annex I). During this same
period, the estimated methane recovered and flared from
landfills increased as well. In 1990, for example, ap-
proximately 1.5 teragrams (Tg) of methane were recov-
ered and combusted (i.e., used for energy orflared) from
landfills. In 1992, the estimated quantity of methane re-
covered and combusted increased to 1.8 Tg.2
Over the next several years, the total amount of
MSW generated is expected to continue increasing. The
percentage of waste landfilled, however, may decline due
to increased recycling and composting practices. In ad-
Emissions and sinks of biogenic carbon are accounted for under the Land-Use Change and Forestry sector.
EPA is presently reviewing new data on landfill gas recovery and flaring. It is anticipated that the national total for methane recovery and
flaring will be significantly larger based on this new information.
7-2
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 7-3: CH Emissions from Landfills (MMTCE)
Activity
MSW Landfills
Industrial Landfills
Recovered
Net Emissions
1990
60.6
4.2
(8.6)
56.2
1991
61.9
4.3
(8.6)
57.6
1992
63.8
4.4
(10.3)
57.8
1993
65.5
4.5
(10.3)
59.7
1994
67.3
4.6
(10.3)
61.6
1995
69.2
4.8
(10.3)
63.6
1996
70.6
4.9
(10.3)
65.1
Note: Totals may not sum due to independent rounding.
Table 7-4: CH Emissions from Landfills (Tg)
Activity
MSW Landfills
Industrial Landfills
Recovered
Net Emissions
1990
10.6
0.7
(1.5)
9.8
1991
10.8
0.7
(1.5)
10.0
1992
11.1
0.8
(1.8)
10.1
1993
11.4
0.8
(1.8)
10.4
1994
11.7
0.8
(1.8)
10.8
1995
12.1
0.8
(1.8)
11.1
1996
12.3
0.8
(1.8)
11.4
Note: Totals may not sum due to independent rounding.
dition, the quantity of methane that is recovered and ei-
ther flared or used for energy purposes is expected to
increase, partially as a result of a new regulation that will
require large landfills to collect and combust landfill gas.
The impact of such shifts in activity on emissions cannot
be fully assessed at this time.
Methodology
Based on the available information, methane emis-
sions from landfills were estimated to equal methane pro-
duction from municipal landfills, plus methane produced
by industrial landfills, minus methane recovered and com-
busted, and minus the methane oxidized before being
released into the atmosphere.
The methodology for estimating CH4 emissions
from municipal landfills is based on an updated model
that tracks changes in the population of landfills in the
United States over time. This model is based on the pat-
tern of actual waste disposal by each individual landfill
surveyed by the EPA's Office of Solid Waste in 1987. A
second model was employed to estimate emissions from
the landfill population data (EPA 1993). For each land-
fill in the data set, the amount of waste in place contrib-
uting to methane generation was estimated using its year
of opening, its waste acceptance rate, and total waste dis-
posed in landfills. Data on national waste disposed in
landfills each year was apportioned by landfill. Emis-
sions from municipal landfills were then estimated by
multiplying the quantity of waste contributing to emis-
sions by emission factors (EPA 1993). For further infor-
mation see Annex I.
To estimate landfill gas recovered per year, data on
current and planned landfill gas recovery projects in the
United States were obtained from Governmental Advi-
sory Associates (GAA 1994). The GAA report, consid-
ered to be the most comprehensive source of informa-
tion on gas recovery in the United States, has estimates
for gas recovery in 1990 and 1992. In addition, a num-
ber of landfills were believed to recover and flare meth-
ane without energy recovery and were not included in
the GAA database. To account for the amount of meth-
ane flared without energy recovery, the estimate of gas
recovered was increased by 25 percent (EPA 1993).
The amount of methane oxidized was assumed to
be 10 percent of the methane generated. Methane re-
covered and oxidized was subtracted from the methane
generated from municipal and industrial landfills to ar-
rive at net methane emissions. Emissions from indus-
trial sites were assumed to be a fixed percentage of total
emissions from municipal landfills.
Data Sources
The model, including actual waste disposal data
from individual landfills, was developed from a survey
performed by the EPA Office of Solid Waste (EPA 1988).
National landfill waste disposal data for 1988 through
1996 were obtained from Biocycle (1997). Documenta-
tion on the landfill methane emissions methodology em-
Waste
7-3
-------
ployed is available in EPA's "Anthropogenic Methane
Emissions in the United States, Estimates for 1990: Re-
port to Congress" (EPA 1993). Emission factors were
taken from Bingemer and Crutzen (1987) and the Gov-
ernmental Advisory Associates (GAA 1994).
Table 7-5: CH4 Emissions from Domestic
Wastewater Treatment
Uncertainty
There are several uncertainties associated with the
estimates of methane emissions from landfills. The pri-
mary one concerns the characterization of landfills. There
is a lack of information on the area landfilled and total waste
in place (the fundamental factors that affect methane pro-
duction). In addition, little information is available on the
quantity of methane flared at non-energy related projects
and the number of landfill closures. Finally, the statistical
model used to estimate emissions is based upon methane
generation at landfills that currently have developed energy
recovery projects, and may not precisely capture the rela-
tionship between emissions and various physical character-
istics of individual landfills. Overall, uncertainty is esti-
mated to be roughly ±30 percent.
Wastewater Treatment
The breakdown of organic material in wastewater
treatment systems produces methane when it occurs un-
der anaerobic conditions. During collection and treat-
ment, wastewater may be incidentally as well as deliber-
ately maintained under anaerobic conditions. The meth-
ane produced during deliberate anaerobic treatment is
typically collected and flared or combusted for energy.
However, whenever anaerobic conditions develop, some
of the methane generated is incidentally released to the
atmosphere. Untreated wastewater may also produce
methane if held under anaerobic conditions.
Organic content, expressed in terms of biochemical
oxygen demand (BOD), 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. Under
Year
1990
1991
1992
1993
1994
1995
1996
MMTCE
0.9
0.9
0.9
0.9
0.9
0.9
0.9
Tg
0.2
0.2
0.2
0.2
0.2
0.2
0.2
anaerobic conditions, however, wastewater with higher
BOD concentrations will produce more methane than
wastewater with lower BOD. The amount of methane
produced is driven by the extent to which the organic
material is broken down under anaerobic versus aerobic
conditions.
In 1996, methane emissions from municipal waste-
water were 0.9 MMTCE (0.2 Tg), or less than one per-
cent of total U.S. methane emissions. Emissions have
increased slightly since 1990 reflecting the increase in
the U.S. human population. No estimates have been de-
veloped to indicate any changes in the manner in which
wastewater is managed in the United States during this
period. Table 7-5 provides emission estimates from do-
mestic wastewater treatment.
At this time, data are not sufficient to estimate meth-
ane emissions from industrial wastewater sources. Fur-
ther research is ongoing at the EPA to better quantify
emissions from this source.
Methodology
Wastewater methane emissions are estimated us-
ing the default IPCC methodology (IPCC/UNEP/OECD/
IEA 1997). The total population for each year was mul-
tiplied by a wastewater BOD production rate to deter-
mine total wastewater BOD produced. It was assumed
that, per capita, 0.05 kilograms of wastewater BOD53 is
produced per day and that 15 percent of wastewater
BOD5 is anaerobically digested. This proportion of BOD
was then multiplied by an emission factor of 0.22 Gg of
CH4perGgofBOD5.
The 5 day biochemical oxygen demand (BOD) measurement (Metcalf and Eddy 1972).
7-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 7-6: U.S. Population (millions) and
Wastewater BOD Produced (Gg)
Year
Population
BODS*
1990
1991
1992
1993
1994
1995
1996
250.7
253.6
256.5
259.2
261.7
264.2
266.5
4,578
4,631
4,685
4,733
4,779
4,824
4,867
* The 5 day biochemical oxygen demand (BOD) measurement
(Metcalf and Eddy 1972)
Data Sources
Human population data for 1990 to 1996 were sup-
plied by the U.S. Census Bureau (1997). The emission
factor employed was taken from Metcalf & Eddy (1972).
Table 7-6 provides U.S. population and wastewater BOD
data.
Uncertainty
Domestic wastewater emissions estimates are
highly uncertain due to the lack of data on the occur-
rence of anaerobic conditions in treatment systems, es-
pecially incidental occurrences. It is also believed that
industrial wastewater is responsible for significantly more
methane emissions than domestic wastewater treatment.
Human Sewage
Human sewage is transported for treatment in the
form of domestic wastewater. Nitrous oxide (N2O) is
emitted from both domestic and industrial wastewater
containing nitrogen-based organic matter and is produced
through natural processes known as nitrification and deni-
trification. Nitrification occurs aerobically and converts
ammonia into nitrate, while denitrification occurs anaero-
bically, and converts nitrate to N2O. It is estimated that
the amount of N2O emitted from wastewater treatment
plants accounts for approximately 5 to 10 percent of an-
nual global discharge (Spector 1997, McElroy et al.
1978). Human sewage is believed to constitute a signifi-
cant portion of the material responsible for N2O emis-
sions from wastewater (Spector 1997). There is insuffi-
cient information available at this time to estimate emis-
sions from industrial wastewater and the other compo-
nents of domestic wastewater. In general, N2O genera-
tion in wastewater systems is affected by temperature,
pH, biochemical oxygen demand (BOD), and nitrogen
concentration. BOD is the amount of dissolved oxygen
used by aerobic microorganisms to completely consume
the available organic matter (Metcalf and Eddy 1972).
Emissions of N2O from human sewage treated in
wastewater systems was estimated to be 2.3 MMTCE (27
Gg) in 1996. An increase in the U.S. population and the
per capita protein intake resulted in an overall increase
of 8 percent in N2O emissions from human sewage be-
tween 1990 and 1996 (see Table 7-7).
Table 7-7: NO Emissions from Human Sewage
Year
MMTCE
1990
1991
1992
1993
1994
1995
1996
2.1
2.1
2.2
2.2
2.3
2.2
2.3
25
25
26
26
27
26
27
Methodology
Nitrous oxide emissions from human sewage were
estimated using the IPCC default methodology (IPCC/
UNEP/OECD/IEA 1997). The equation in IPCC was
modified slightly to convert N2O-N to N2O by using a
conversion factor of the atomic weight of N2O to that of
N2 (44/28). This is illustrated below:
N20(s)=(Protein)x(FracNpR)x(NRPeople)x(EF)x(44/28)
where,
N2O(s) = N2O emissions from human sewage
Protein = Annual, per capita protein consumption
FracNpR = fraction of nitrogen in protein
NR People = U.S. population
EF = Emission factor
(44/28) = The atomic weight ratio of N2O to N2
Waste
7-5
-------
Data Sources
U.S. population data were taken from the U.S. Cen-
sus Bureau (1997). Data on the annual per capita pro-
tein consumption were provided by the United Nations
Food and Agriculture Organization (FAO 1997). Because
data on protein intake were unavailable for 1996, the
average value of per capita protein consumption over the
years 1990 through 1995 was used (see Table 7-8). An
emission factor has not been specifically estimated for
the United States. As a result, the default IPCC value
(0.01 kg N2O-N/kg sewage-N produced) was applied.
Similarly, the fraction of nitrogen in protein (0.16 kg N/
kg protein) was also obtained from IPCC/UNEP/OECD/
IEA (1997).
Table 7-8: U.S. Population (millions) and Average
Protein Intake (kg/person/year)
Year
Population
Protein
1990
1991
1992
1993
1994
1995
1996
250.7
253.6
256.5
259.2
261.7
264.2
266.5
39.06
39.42
39.79
40.15
40.88
39.79
39.79
Uncertainty
The U.S. population (NR people) and per capita
protein intake data (Protein) are believed to be highly
certain. There is significant uncertainty, however, in the
emission factor (EF) due to regional differences that
would likely affect N2O emissions but are not accounted
for in the default IPCC factor. In contrast, the fraction of
nitrogen in protein (FracNPR) is believed to be quite accu-
rate. Despite the increase in N2O emissions from 1990
through 1996, these estimates from human sewage are
significantly lower than other more recent estimates
(Spector 1997) of total N2O emissions fromboth domes-
tic and industrial wastewater treatment. EPA is currently
supporting further research to develop a comprehensive
estimate of emissions from this source.
Waste Combustion
Waste combustion involves the burning of garbage
and non-hazardous solids, called municipal solid waste
(MSW), and has been identified as a source of nitrous
oxide (N2O) emissions.4 In 1992, there were over 160
municipal waste combustion plants in the United States
(EPA 1997b). Emissions from this source are dependent
on the types of waste burned and combustion tempera-
tures (De Soete 1993). Nitrous oxide emissions from
MSW combustion were estimated to be 0.1 MMTCE (1
Gg) in 1996, and have fluctuated only slightly since 1990
(see Table 7-9).
Table 7-9: N20 Emissions from Waste Combustion
Year
MMTCE
1990
1991
1992
1993
1994
1995
1996
0.1
0.1
0.1
0.1
0.1
0.1
0.1
1
1
1
1
1
1
1
Methodology
Estimates of nitrous oxide emissions from MSW
combustion in the United States are based on the meth-
odology outlined in the EPA's Compilation of Air Pol-
lutant Emission Factors (EPA 1997a). It is based upon
the quantity of MSW combusted at waste combustion
facilities and an emission factor of N2O emission per unit
mass of waste combusted (30 g N2O/metric ton MSW).
Data Sources
Data on the quantity of MSW generated and com-
busted was taken from the April 1997 issue ofBioCycle
(Goldstein 1997). Table 7-10 provides MSW generation
and percentage combustion data. The emission factor of
N2O emissions per quantity of MSW combusted was
taken from De Soete (1993).
Emissions of carbon dioxide from the combustion of petroleum-based plastics are accounted for under CO from fossil fuel combustion as
a non-fuel use of petroleum.
7-6
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 7-10: Municipal Solid Waste Generation
(Metric Tons) and Percent Incinerated
Year
Waste Generation
Combusted (%)
1990
1991
1992
1993
1994
1995
1996
266,541,881
254,796,765
264,843,388
278,572,955
293,109,556
296,586,430
297,268,188
11.5
10.0
11.0
10.0
10.0
10.0
10.0
Table 7-11: U.S. Municipal Solid Waste Com-
busted by Data Source (Metric Tons)
Year
1990
1991
1992
1993
1994
1995
1996
BioCycle
30,652,316
25,479,677
29,132,773
27,857,295
29,310,956
29,658,643
29,726,819
EPA
28,958,820
30,256,974
29,675,982
29,884,776
29,494,422
30,384,066
NA
NA (Not Available)
Uncertainty
As with other combustion related sources of nitrous
oxide, emissions are affected by combustion conditions. In
part, because insufficient data exists to provide detailed es-
timates of N2O emissions for individual combustion facili-
ties, the estimates presented are highly uncertain. MSW
combustion data published in BioCycle were compared with
data published by the EPA's Office of Solid Waste (EPA
1997b) and were found to be relatively consistent (see Table
7-11). The emission factor for N2O from MSW combus-
tion facilities has also been found to vary by an order of
magnitude (between 25 and 293 g N2O/metric ton MSW
combusted) (Watanabe, et al. 1992).
Waste Sources of Criteria
Pollutants
In addition to the main greenhouse gases addressed
above, waste generating and handling processes are
sources of criteria air pollutant emissions. Total emis-
sions of nitrogen oxides (NOx), carbon monoxide (CO),
and nonmethane volatile organic compounds (NMVOCs)
from the Waste sector for the years 1990 through 1996
are provided in Table 7-12.
Table 7-12: Emissions of NO , CO, and NMVOC from Waste (Gg)
Gas/Source
1990
1991
1992
1993
1994
1995
1996
NO
X
Landfills
Wastewater Treatment
Waste Combustion3
Miscellaneous"
CO
Landfills
Wastewater Treatment
Waste Combustion3
Miscellaneous11
NMVOCs
Landfills
Wastewater Treatment
Waste Combustion3
Miscellaneous"
83
+
+
82
+
979
1
+
978
+
895
58
57
222
558
86
+
+
85
1
1,012
1
+
1,011
+
907
60
58
227
562
87
+
+
86
1
1,032
2
+
1,030
+
916
63
61
230
563
112
1
+
107
4
1,133
2
+
1,130
1
949
67
63
256
563
103
1
+
99
3
1,111
2
+
1,108
1
949
73
64
248
564
89
1
+
88
1
1,075
2
+
1,073
1
968
68
61
237
602
91
1
+
89
1
1,091
2
+
1,089
1
393
20
58
240
75
a Includes waste incineration and open burning (EPA 1997)
" Miscellaneous includes TSDFs (Treatment, Storage, and Disposal Facilities under the Resource Conservation and Recovery Act [42 U.S.C. §
6924, SWDA § 3004]) and other waste categories.
Note: Totals may not sum due to independent rounding.
+ Does not exceed 0.5 Gg
Waste
7-7
-------
Methodology and Data Sources
These emission estimates were taken directly from
the EPA's National Air Pollutant Emissions Trends, 1900-
1996 (EPA 1997b). This EPA report provides emission
estimates of these gases by sector, using a "top down"
estimating procedure3/4emissions were calculated either
for individual sources or for many sources combined,
using basic activity data (e.g., the amount of raw mate-
rial processed) as an indicator of emissions. National
activity data were collected for individual source catego-
ries 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 emis-
sion 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 1997a). The EPA currently derives
the overall emission control efficiency of a source cat-
egory from a variety of information sources, including
published reports, the 1985 National Acid Precipitation
and Assessment Program emissions inventory, and other
EPA data bases.
Uncertainty
Uncertainties in these estimates are primarily due
to the accuracy of the emission factors used and accurate
estimates of activity data.
7-8
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
8.
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Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
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8-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Annexes
The following seventeen annexes provide additional information to the material presented in the main body of
this report. Annexes A through I discuss methodologies for individual source categories in greater detail than was
presented in the main body of the report and include explicit activity data and emission factor tables. Annex J lists
the Global Warming Potential (GWP) values used in this report as provided in IPCC (1996). Annexes K and J
summarize U.S. emissions of ozone depleting substances (e.g., CFCs and HCFCs) and sulfur dioxide (SO2),
respectively. Annex M provides a complete list of emission sources assessed in this report. Annexes N and O present
U.S. greenhouse gas emission estimates in the reporting format recommended in the Revised 1996IPCC Guidelines
for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997) and the IPCC reference approach for
estimating CO2 emissions from fossil fuel combustion, respectively.
Preliminary greenhouse gas emission estimates for 1997 are provided in Annex P, which will be revised in future
reports. Finally, Annex Q addresses the criteria for the inclusion of an emission source category and some of the
sources which meet the criteria but are nonetheless excluded from U.S. estimates.
List of Annexes
• Annex A Methodology for Estimating Emissions of CO2 from Fossil Fuel Combustion
• Annex B Methodology for Estimating Emissions of CH4, N2O, and Criteria Pollutants from
Stationary Combustion
• Annex C Methodology for Estimating Emissions of CH4, N2O, and Criteria Pollutants from
Mobile Combustion
• Annex D Methodology for Estimating Methane Emissions from Coal Production
• Annex E Methodology for Estimating Methane Emissions from Natural Gas Systems
• Annex F Methodology for Estimating Methane Emissions from Petroleum Systems
• Annex G Methodology for Estimating Methane Emissions from Enteric Fermentation
• Annex H Methodology for Estimating Methane Emissions from Manure Management
• Annex I Methodology for Estimating Methane Emissions from Landfills
• Annex J Global Warming Potentials
• Annex K Ozone Depleting Substance Emissions
• Annex L Sulfur Dioxide Emissions
• Annex M Complete List of Sources
• Annex N IPCC Reporting Tables
• Annex O IPCC Reference Approach for Estimating CO2 Emissions from Fossil Fuel Combustion
• Annex P Preliminary 1997 Estimates of U.S. Greenhouse Gas Emissions and Sinks
• Annex Q Sources of Greenhouse Gas Emissions Excluded
-------
Annex A
Methodology for Estimating Emissions of CO2 from Fossil Fuel
Combustion
Carbon dioxide (CO2) emissions from fossil fuel combustion were estimated using a "bottom-up" methodology
characterized by six steps. These steps are described below. Methodological and data changes from previous
inventories are outlined at the end of this discussion.
Step 1: Determine Energy Consumption by Fuel Type and End-Use Sector
The bottom-up methodology used by the United States for estimating CO2 emissions from fossil fuel combustion
is conceptually similar to the approach recommended by the Intergovernmental Panel on Climate Change (IPCC) for
countries that intend to develop detailed, sectoral-based emission estimates (IPCC/UNEP/OECD/IEA 1997). Basic
consumption data are presented in Columns 2-8 of Table A-l through Table A-7, with totals by fuel type in Column
8 and totals by end-use sector in the last rows. Fuel consumption data for the bottom-up approach were obtained
directly from the Energy Information Administration (EIA) of the U.S. Department of Energy. The EIA data were
collected through surveys at the point of delivery or use; therefore, they reflect the reported consumption of fuel by
end-use sector and fuel type. Individual data elements were supplied by a variety of sources within EIA. Most
information was taken from published reports, although some data were drawn from unpublished energy studies and
databases maintained by EIA.
Energy consumption data were aggregated by end-use sector (i.e., residential, commercial, industrial,
transportation, electric utilities, and U.S. territories), primary fuel type (e.g., coal, natural gas, and petroleum), and
secondary fuel type (e.g., motor gasoline, distillate fuel, etc.). The 1996 total energy consumption across all sectors,
including territories, and energy types was 79,419 trillion Btu, as indicated in the last entry of Column 8 in Table A-1.
This total includes fuel used for non-fuel purposes and fuel consumed as international bunkers, both of which are
deducted in later steps.
There are two modifications made in this report that may cause consumption information herein to differ from
figures given in the cited literature. These are the consideration of synthetic natural gas production and ethanol added
to motor gasoline.
First, a portion of industrial coal accounted for in EIA combustion figures is actually used to make "synthetic
natural gas" via coal gasification. The energy in this gas enters the natural gas stream, and is accounted for in natural
gas consumption statistics. Because this energy is already accounted for as natural gas, it is deducted from industrial
coal consumption to avoid double counting. This makes the figure for other industrial coal consumption in this report
slightly lower than most EIA sources.
Second, ethanol has been added to the motor gasoline stream for several years, but prior to 1993 this addition
was not captured in EIA motor gasoline statistics. Starting in 1993, ethanol was included in gasoline statistics.
However, because ethanol is a biofuel, which is assumed to result in no net CO2 emissions, the amount of ethanol
added is subtracted from total gasoline consumption. Thus, motor gasoline consumption statistics given in this report
may be slightly lower than in EIA sources.
There are also three basic differences between the consumption figures presented in Table A-l and those
recommended in the IPCC emission inventory methodology.
First, consumption data in the U.S. inventory are presented using higher heating values (HHV)1 rather than the
lower heating values (LHV)2 reflected in the IPCC emission inventory methodology. This convention is followed
because data obtained from EIA are based on HHV.
1 Also referred to as Gross Calorific Values (GCV).
2 Also referred to as Net Calorific Values (NCV).
A-1
-------
Second, while EIA's energy use data for the United States includes only the 50 U.S. states and the District of
Columbia, the data reported to the Framework Convention on Climate Change are to include energy consumption
within territories. Therefore, consumption estimates for U.S. territories were added to domestic consumption of fossil
fuels. Energy consumption data from U.S. territories are presented in Column 7 of Table A-l. It is reported separately
from domestic sectoral consumption, because it is collected separately by EIA with no sectoral disaggregation.
Third, the domestic sectoral consumption figures in Table A-l include bunkerfuels and non-fuel uses of energy.
The IPCC recommends that countries estimate emissions from bunker fuels separately and exclude these emissions
from national totals, so bunker fuel emissions have been estimated in Table A-8 and deducted from national estimates
(see Step 4). Similarly, fossil fuels used to produce non-energy products that store carbon rather than release it to the
atmosphere are provided in Table A-9 and deducted from national emission estimates (see Step 3).
Step 2: Determine the Carbon Content of All Fuels
The carbon content of combusted fossil fuels was estimated by multiplying energy consumption (Columns 2
through 8 of Table A-l) by fuel specific carbon content coefficients (Table A-10 and Table A-l 1) that reflected the
amount of carbon per unit of energy inherent in each fuel. The resulting carbon contents are sometimes referred to
as potential emissions, or the maximum amount of carbon that could potentially be released to the atmosphere if all
carbon in the fuels were converted to CO2. The carbon content coefficients used in the U.S. inventory were derived
by EIA from detailed fuel information and are similar to the carbon content coefficients contained in the IPCC's
default methodology (IPCC/UNEP/OECD/IEA 1997), with modifications reflecting fuel qualities specific to the
United States.
Step 3: Adjust for the amount of Carbon Stored in Products
Depending on the end-use, non-fuel uses of fossil fuels can result in long term storage of some or all of the
carbon contained in the fuel. For example, asphalt made from petroleum can sequester up to 100 percent of the carbon
contained in the petroleum feedstock for extended periods of time. Other non-fuel products, such as lubricants or
plastics also store carbon, but can lose or emit some of this carbon when they are used and/or burned as waste.
The amount of carbon sequestered or stored by non-fuel uses of fossil fuel products was based upon data that
addressed the ultimate fate of various energy products, with all non-fuel use attributed to the industrial, transportation,
and territories end-use sectors. This non-fuel consumption is presented in Table A-9. Non-fuel consumption was then
multiplied by fuel specific carbon content coefficients (Table A-10 and Table A-l 1) to obtain the carbon content of
the fuel, or the maximum amount of carbon that could be sequestered if all the carbon in the fuel were stored in non-
fuel products (Columns 5 and 6 of Table A-9). This carbon content was then multiplied by the fraction of carbon
assumed to actually have been sequestered in products (Column 7 of Table A-9), resulting in the final estimates of
carbon stored by sector and fuel type, which are presented in Columns 8 through 10 of Table A-3. The portions of
carbon sequestered were based on EIA data.
Step 4: Subtract Carbon from Bunker Fuels.
Emissions from international transport activities, or bunker fuel consumption, were not included in national
totals. There is currently disagreement internationally as to which countries are responsible for these emissions, and
until this issue is resolved, countries are asked to report these emissions separately. However, EIA data includes
bunkerfuels—primarily residual oil—as part of fuel consumptionby the transportation end-use sector. To compensate
for this inclusion, bunker fuel emissions were calculated separately (Table A-8) and the carbon content of these fuels
was subtracted from the transportation end-use sector. The calculations of bunker fuel emissions followed the same
procedures used for other fuel emissions (i.e., estimation of consumption, determination of carbon content, and
adjustment for the fraction of carbon not oxidized).
Step 5: Account for Carbon that Does Not Oxidize During Combustion
Because combustion processes are not 100 percent efficient, some of the carbon contained in fuels is not emitted
to the atmosphere. Rather, it remains behind as soot, paniculate matter, or other by-products of inefficient
A-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
combustion. The estimated fraction of carbon not oxidized in U. S. energy conversion processes due to inefficiencies
during combustion ranges from 0.5 percent for natural gas to 1 percent for petroleum and coal. Except for coal these
assumptions are consistent with the default values recommended by the IPCC (IPCC/UNEP/OECD/IEA 1997). In
the U.S. unoxidized carbon from coal combustion was estimated to be no more than one percent (Bechtel 1993).
Table A-10 presents fractions oxidized by fuel type, which are multiplied by the net carbon content of the combusted
energy to give final emissions estimates.
Step 6: Summarize Emission Estimates
Actual CO2 emissions in the United States were summarized by major fuel (i.e., coal, petroleum, natural gas,
geothermal) and consuming sector (i.e., residential, commercial, industrial, transportation, electric utilities, and
territories). Adjustments for bunker fuels and carbon sequestered in products were made. Emission estimates are
expressed in terms of million metric tons of carbon equivalents (MMTCE).
To determine total emissions by final end-use sector, emissions from electric utilities were distributed over the
five end-use sectors according to their share of electricity consumed (see Table A-12).
Differences with Previous Years' Inventories
Two minor changes were made to the estimates of CO2 emissions from energy consumption in this year's report.
The first change concerns how emissions from unmetered natural gas consumption were handled. The second change
pertains to accounting for non-fuel uses of fossil fuels in U.S. territories.
Previous inventories included calculations of emissions from unmetered natural gas consumption. Previously,
the EIA provided this consumption data, which was calculated as the difference between reported gas production and
reported consumption. For many years, the reported amount of gas produced was greater than the amount of gas
consumed. EIA assumed that this difference was due to leakage and measurement errors and unmetered consumption.
However, during the past two years, the reported amount of gas consumed was higher than the quantity of gas reported
to have been produced. This occurrence casts doubt on what composes this difference. Therefore, this year
calculations of emissions from unmetered natural gas consumption were not included in the emission estimates.
Thisyear's estimates accountforthe non-fuel use inU.S. territories. Previous inventories overlooked this small
source (0.17 MMTCE in 1996) of carbon sequestration.
A-3
-------
Table A-1: 1996 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type
1
8
10
11
12
13
14
15
Fuel Type
Residential Coal
Commercial Coal
Industrial Coking Coal
Industrial Other Coal
Coke Imports
Transportation Coal
Utility Coal
US Territory Coal (bit)
Total Coal
Natural Gas
Asphalt & Road Oil
Aviation Gasoline
Distillate Fuel Oil
Jet Fuel
Kerosene
LPG
Lubricants
Motor Gasoline
Residual Fuel
Other Petroleum
AvGas Blend Components
Crude Oil
MoGas Blend Components
Misc. Products
Naphtha (<401 deg. F)
Other Oil (>401 deg. F)
Pentanes Plus
Petrochemical Feedstocks
Petroleum Coke
Still Gas
Special Naphtha
Unfinished Oils
Waxes
Other Wax & Misc.
Total Petroleum
Geothermal
TOTAL (All Fuels)
Res.
53.7
53.7
5,375.8
0.0
0.0
937.5
0.0
82.1
422.0
0.0
0.0
0.0
1,441.6
6,871.0
Comm.
81.0
81.0
3,289.9
0.0
0.0
493.7
0.0
24.6
74.5
0.0
26.2
156.8
775.8
4,146.7
Consumption (TBtu)
Ind. Trans. Utility
849.7
1,489.3
(0.3)
0.0
18,086.4
2,338.7 0.0 18,086.4
10,311.3 730.6 2,800.8
1,175.9 0.0 0.0
0.0 37.4 0.0
1,166.3 4,468.0 109.0
0.0 3,274.2 0.0
21.4 0.0 0.0
2,130.4 34.3 0.0
172.5 163.0 0.0
199.8 14,879.2 0.0
376.0 813.0 605.9
7.0
13.7
0.0
89.0
479.3
729.6
355.0
0.0
816.0 20.5
1,437.1
74.5
(112.8)
48.7
0.0
9,179.5 23,669.1 735.5
0.018
21,829.5 24,399.7 21,622.7
Terr. Total
53.7
81.0
849.7
1,489.3
(0.3)
0.0
18,086.4
10.3 10.3
10.3 20,570.0
NA 22,508.4
1,175.9
37.4
130.7 7,305.2
79.1 3,353.4
128.1
5.6 2,666.7
1.3 336.8
93.7 15,198.9
151.7 2,103.4
76.7 76.7
7.0
13.7
0.0
89.0
479.3
729.6
355.0
0.0
836.5
1,437.1
74.5
(112.8)
48.7
0.0
538.8 36,340.2
0.018
549.1 79,418.7
Emissions (MMTCE)
Res. Comm.
1.4
1.4
77.4
0.0
0.0
18.5
0.0
1.6
7.1
0.0
0.0
0.0
27.2
106.0
2.1
2.1
47.4
0.0
0.0
9.8
0.0
0.5
1.3
0.0
0.5
3.3
15.3
64.8
including Adjustments* and Fraction Oxidized
Ind. Trans. Utility Terr. Total
20.9
38.5
(0.0)
59.4
143.0
(0.0)
0.0
23.0
0.0
0.4
13.0
1.7
3.8
8.0
0.1
0.3
0.0
1.8
8.6
14.4
1.8
(13.7)
19.6
24.9
1.5
(2.3)
1.0
(3.4)
104.6
307.0
0.0
0.0
10.5
0.0
0.7
86.1
56.7
0.0
0.6
1.6
285.5
3.1
434.3
444.8
460.9
460.9
40.3
0.0
0.0
2.2
0.0
0.0
0.0
0.0
0.0
12.9
0.6
15.6
0.0369
516.9
0.255
0.3
NA
0.000
0.000
2.581
1.514
0.000
0.094
0.013
1.783
3.227
1.367
10.580
10.835
1.4
2.1
20.9
38.5
(0.0)
0.0
460.9
0.3
524.0
318.6
(0.0)
0.7
142.1
58.2
2.5
22.0
3.4
291.6
30.6
1.4
0.1
0.3
0.0
1.8
8.6
14.4
1.8
(13.7)
20.2
24.9
1.5
(2.3)
1.0
(3.4)
607.7
0.0369
1,450.3
"Adjustments include: international bunker fuel consumption (see Table A-8) and carbon stored in products (see Table A-9)
NA (Not Available)
A-4 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table A-2: 1995 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type
1
8
10
11
12
13
14
15
Fuel Type
Residential Coal
Commercial Coal
Industrial Coking Coal
Industrial Other Coal
Coke Imports
Transportation Coal
Utility Coal
US Territory Coal (bit)
Total Coal
Natural Gas
Asphalt & Road Oil
Aviation Gasoline
Distillate Fuel Oil
Jet Fuel
Kerosene
LPG
Lubricants
Motor Gasoline
Residual Fuel
Other Petroleum
AvGas Blend Components
Crude Oil
MoGas Blend Components
Misc. Products
Naphtha (<401 deg. F)
Other Oil (>401 deg. F)
Pentanes Plus
Petrochemical Feedstocks
Petroleum Coke
Still Gas
Special Naphtha
Unfinished Oils
Waxes
Other Wax & Misc.
Total Petroleum
Geothermal
TOTAL (All Fuels)
Res.
53.7
53.7
4,981.3
0.0
0.0
893.1
0.0
71.7
398.3
0.0
0.0
0.0
1,363.0
6,398.0
Comm.
81.0
81.0
3,185.2
0.0
0.0
470.3
0.0
21.5
70.3
0.0
25.8
168.9
756.8
4,023.0
Consumption (TBtu)
Ind. Trans. Utility
884.7
1,530.7
26.4
0.0
16,978.9
2,441.9 0.0 16,978.9
10,064.3 722.0 3,276.4
1,178.2 0.0 0.0
0.0 39.6 0.0
1,118.7 4,244.4 90.7
0.0 3,132.2 0.0
18.7 0.0 0.0
2,010.8 32.4 0.0
177.8 167.9 0.0
196.7 14,586.4 0.0
371.5 870.0 544.4
5.3
14.5
0.0
97.1
373.0
801.0
337.9
0.0
779.0 22.9
1,417.5
70.8
(320.9)
40.6
0.0
8,688.1 23,072.9 658.0
0.016
21,194.3 23,794.8 20,913.3
Terr. Total
53.7
81.0
884.7
1,530.7
26.4
0.0
16,978.9
10.2 10.2
10.2 19,565.7
NA 22,229.3
1,178.2
39.6
135.5 6,952.5
81.6 3,213.8
111.8
5.6 2,517.3
1.4 347.1
97.9 14,906.8
156.2 2,110.9
79.3 79.3
5.3
14.5
0.0
97.1
373.0
801.0
337.9
0.0
802.0
1,417.5
70.8
(320.9)
40.6
0.0
557.5 35,096.2
0.016
567.7 76,891.1
Emissions (MMTCE)
Res. Comm.
1.4
1.4
71.7
0.0
0.0
17.6
0.0
1.4
6.7
0.0
0.0
0.0
25.7
98.8
2.1
2.1
45.9
0.0
0.0
9.3
0.0
0.4
1.2
0.0
0.5
3.6
15.0
62.9
including
Ind.
21.8
39.6
0.7
62.1
139.7
0.0
0.0
22.1
0.0
0.4
12.5
1.8
3.8
7.9
0.1
0.3
0.0
1.9
6.7
15.8
1.7
(12.9)
18.9
24.6
1.4
(6.4)
0.8
(3.3)
97.9
299.7
Adjustments* and Fraction Oxidized
Trans. Utility Terr. Total
0.0
0.0
10.4
0.0
0.7
81.8
54.2
0.0
0.5
1.7
279.9
2.9
421.7
432.1
432.7
432.7
47.2
0.0
0.0
1.8
0.0
0.0
0.0
0.0
0.0
11.6
0.6
14.0
0.0328
493.9
0.255
0.3
NA
0.000
0.000
2.675
1.562
0.000
0.095
0.014
1.863
3.323
1.414
10.946
11.201
1.4
2.1
21.8
39.6
0.7
0.0
432.7
0.3
498.5
314.8
0.0
0.7
135.3
55.8
2.2
21.0
3.5
286.0
29.3
1.4
0.1
0.3
0.0
1.9
6.7
15.8
1.7
(12.9)
19.5
24.6
1.4
(6.4)
0.8
(3.3)
585.3
0.0328
1,398.7
"Adjustments include: international bunker fuel consumption (see Table A-8) and carbon stored in products (see Table A-9)
NA (Not Available)
A-5
-------
Table A-3: 1994 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type
1
8
10
11
12
13
14
15
Fuel Type
Residential Coal
Commercial Coal
Industrial Coking Coal
Industrial Other Coal
Coke Imports
Transportation Coal
Utility Coal
US Territory Coal (bit)
Total Coal
Natural Gas
Asphalt & Road Oil
Aviation Gasoline
Distillate Fuel Oil
Jet Fuel
Kerosene
LPG
Lubricants
Motor Gasoline
Residual Fuel
Other Petroleum
AvGas Blend Components
Crude Oil
MoGas Blend Components
Misc. Products
Naphtha (<401 deg. F)
Other Oil (>401 deg. F)
Pentanes Plus
Petrochemical Feedstocks
Petroleum Coke
Still Gas
Special Naphtha
Unfinished Oils
Waxes
Other Wax & Misc.
Total Petroleum
Geothermal
TOTAL (All Fuels)
Res.
55.5
55.5
4,988.3
0.0
0.0
880.0
0.0
64.9
395.5
0.0
0.0
0.0
1,340.4
6,384.2
Comm.
83.5
83.5
2,980.8
0.0
0.0
464.3
0.0
19.5
69.8
0.0
25.2
174.6
753.3
3,817.6
Consumption (TBtu)
Ind. Trans. Utility
850.6
1,589.4
23.6
0.0
16,895.2
2,463.7 0.0 16,895.2
9,609.3 705.2 3,052.9
1,172.9 0.0 0.0
0.0 38.1 0.0
1,108.8 4,175.0 95.2
0.0 3,154.5 0.0
16.9 0.0 0.0
1,996.5 32.2 0.0
180.9 170.8 0.0
191.9 14,214.1 0.0
417.6 896.0 846.6
6.1
18.7
0.0
105.9
398.3
838.6
338.7
0.0
793.0 26.3
1,439.4
81.1
(279.2)
40.6
0.0
8,866.8 22,680.7 968.2
0.024
20,939.8 23,385.9 20,916.2
Terr. Total
55.5
83.5
850.6
1,589.4
23.6
0.0
16,895.2
10.2 10.2
10.2 19,508.1
NA 21,336.5
1,172.9
38.1
101.3 6,824.6
80.7 3,235.2
101.3
9.2 2,503.1
2.1 353.8
131.4 14,562.7
171.1 2,505.9
72.6 72.6
6.1
18.7
0.0
105.9
398.3
838.6
338.7
0.0
819.4
1,439.4
81.1
(279.2)
40.6
0.0
568.5 35,177.9
0.024
578.7 76,022.4
Emissions (MMTCE)
Res. Comm.
1.4
1.4
71.8
0.0
0.0
17.4
0.0
1.3
6.7
0.0
0.0
0.0
25.3
98.6
2.1
2.1
42.9
0.0
0.0
9.2
0.0
0.4
1.2
0.0
0.5
3.7
14.9
60.0
including
Ind.
21.0
41.1
0.7
62.7
133.3
(0.0)
0.0
21.9
0.0
0.3
12.8
1.8
3.7
8.9
0.1
0.4
0.0
2.1
7.2
16.6
2.4
(13.6)
19.4
25.0
1.6
(5.6)
0.8
(3.5)
102.2
298.1
Adjustments* and Fraction Oxidized
Trans. Utility Terr. Total
0.0
0.0
10.2
0.0
0.7
80.4
54.9
0.0
0.5
1.7
273.7
4.6
416.6
426.7
430.2
430.2
44.0
0.0
0.0
1.9
0.0
0.0
0.0
0.0
0.0
18.0
0.7
20.6
0.0492
494.8
0.255
0.3
NA
0.000
0.000
2.001
1.546
0.000
0.156
0.021
2.500
3.641
1.294
11.159
11.414
1.4
2.1
21.0
41.1
0.7
0.0
430.2
0.3
496.7
302.1
(0.0)
0.7
132.7
56.4
2.0
21.3
3.5
280.4
38.8
1.3
0.1
0.4
0.0
2.1
7.2
16.6
2.4
(13.6)
20.1
25.0
1.6
(5.6)
0.8
(3.5)
590.7
0.0492
1,389.6
"Adjustments include: international bunker fuel consumption (see Table A-8) and carbon stored in products (see Table A-9)
NA (Not Available)
A-6 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table A-4: 1993 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type
10
11
12
13
14
15
Fuel Type
Residential Coal
Commercial Coal
Industrial Coking Coal
Industrial Other Coal
Coke Imports
Transportation Coal
Utility Coal
US Territory Coal (bit)
Total Coal
Natural Gas
Asphalt & Road Oil
Aviation Gasoline
Distillate Fuel Oil
Jet Fuel
Kerosene
LPG
Lubricants
Motor Gasoline
Residual Fuel
Other Petroleum
AvGas Blend Components
Crude Oil
MoGas Blend Components
Misc. Products
Naphtha (<401 deg. F)
Other Oil (>401 deg. F)
Pentanes Plus
Petrochemical Feedstocks
Petroleum Coke
Still Gas
Special Naphtha
Unfinished Oils
Waxes
Other Wax & Misc.
Total Petroleum
Geothermal
TOTAL (All Fuels)
Res.
56.6
56.6
5,097.5
0.0
0.0
912.9
0.0
75.6
398.6
0.0
0.0
0.0
1,387.0
6,541.1
Comm.
85.5
85.5
2,995.8
0.0
0.0
463.9
0.0
14.0
70.3
0.0
29.6
175.0
752.8
3,834.2
Consumption (TBtu)
Ind. Trans. Utility
839.5
1,588.0
17.3
0.0
16,841.1
2,444.8 0.0 16,841.1
9,387.4 643.1 2,744.1
1,149.0 0.0 0.0
0.0 38.4 0.0
1,099.7 3,912.9 76.7
0.0 3,028.0 0.0
13.1 0.0 0.0
1,794.4 18.9 0.0
173.1 163.5 0.0
179.4 14,000.5 0.0
451.8 913.4 938.6
0.1
21.2
0.0
94.7
350.6
844.1
332.3
0.0
767.3 36.8
1,430.2
104.6
(396.0)
40.0
0.0
8,449.6 22,075.5 1,052.0
0.026
20,281.8 22,718.6 20,637.3
Terr. Total
56.6
85.5
839.5
1,588.0
17.3
0.0
16,841.1
8.1 8.1
8.1 19,436.1
NA 20,867.9
1,149.0
38.4
92.3 6,558.3
71.4 3,099.4
102.7
12.8 2,295.1
0.2 336.7
115.9 14,325.5
153.6 2,632.4
83.2 83.2
0.1
21.2
0.0
94.7
350.6
844.1
332.3
0.0
804.1
1,430.2
104.6
(396.0)
40.0
0.0
529.5 34,246.5
0.026
537.5 74,550.5
Emissions (MMTCE) including Adjustments* and Fraction Oxidizec
Res. Comm. Ind. Trans. Utility Terr.
1.5
1.5
73.4
0.0
0.0
18.0
0.0
1.5
6.7
0.0
0.0
0.0
26.2
101.0
2.2
2.2
43.1
0.0
0.0
9.2
0.0
0.3
1.2
0.0
0.6
3.7
14.9
60.2
20.7
41.1
0.5
62.2
131.0
0.0
0.0
21.7
0.0
0.3
12.0
1.7
3.5
9.6
0.0
0.4
0.0
1.9
6.3
16.7
2.0
(13.1)
18.9
24.8
2.1
(7.9)
0.8
(3.3)
98.3
291.5
0.0
0.0
9.3
0.0
0.7
75.2
52.7
0.0
0.3
1.6
269.3
4.2
404.1
413.4
428.7
428.7
39.5
0.0
0.0
1.5
0.0
0.0
0.0
0.0
0.0
20.0
1.0
22.5
0.0533
490.7
0.201
0.2
NA
0.000
0.000
1.823
1.369
0.000
0.217
0.002
2.206
3.269
1.482
10.368
10.569
Total
1.5
2.2
20.7
41.1
0.5
0.0
428.7
0.2
494.7
296.3
0.0
0.7
127.5
54.1
2.0
20.4
3.4
275.5
40.7
1.5
0.0
0.4
0.0
1.9
6.3
16.7
2.0
(13.1)
19.9
24.8
2.1
(7.9)
0.8
(3.3)
576.4
0.0533
,367.5
"Adjustments include: international bunker fuel consumption (see Table A-8) and carbon stored in products (see Table A-9)
NA (Not Available)
A-7
-------
Table A-5: 1992 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type
10
11
12
13
14
15
Fuel Type
Residential Coal
Commercial Coal
Industrial Coking Coal
Industrial Other Coal
Coke Imports
Transportation Coal
Utility Coal
US Territory Coal (bit)
Total Coal
Natural Gas
Asphalt & Road Oil
Aviation Gasoline
Distillate Fuel Oil
Jet Fuel
Kerosene
LPG
Lubricants
Motor Gasoline
Residual Fuel
Other Petroleum
AvGas Blend Components
Crude Oil
MoGas Blend Components
Misc. Products
Naphtha (<401 deg. F)
Other Oil (>401 deg. F)
Pentanes Plus
Petrochemical Feedstocks
Petroleum Coke
Still Gas
Special Naphtha
Unfinished Oils
Waxes
Other Wax & Misc.
Total Petroleum
Geothermal
TOTAL (All Fuels)
Res.
56.7
56.7
4,821.1
0.0
0.0
864.9
0.0
65.0
382.5
0.0
0.0
0.0
1,312.4
6,190.2
Comm.
85.7
85.7
2,884.2
0.0
0.0
464.0
0.0
11.1
67.5
0.0
79.5
191.2
813.3
3,783.2
Consumption (TBtu)
Ind. Trans. Utility
867.4
1,573.1
27.2
0.0
16,192.0
2,467.7 0.0 16,192.0
8,996.4 608.4 2,828.5
1,102.2 0.0 0.0
0.0 41.1 0.0
1,144.5 3,810.2 67.3
0.0 3,001.3 0.0
9.8 0.0 0.0
1,859.8 18.4 0.0
170.0 160.5 0.0
194.3 13,698.8 0.0
391.3 1,082.0 835.6
0.2
27.4
75.7
100.1
377.3
814.9
322.7
0.0
813.1 30.1
1,447.6
104.6
(355.0)
37.3
0.0
8,637.7 21,812.3 933.0
0.028
20,101.8 22,420.7 19,953.5
Terr. Total
56.7
85.7
867.4
1,573.1
27.2
0.0
16,192.0
8.8 8.8
8.8 18,810.9
NA 20,138.6
1,102.2
41.1
78.7 6,429.6
65.8 3,067.1
85.9
11.8 2,340.0
0.0 330.5
114.4 14,087.0
154.5 2,654.6
61.4 61.4
0.2
27.4
75.7
100.1
377.3
814.9
322.7
0.0
843.2
1,447.6
104.6
(355.0)
37.3
0.0
486.6 33,995.3
0.028
495.5 72,944.8
Emissions (MMTCE) including Adjustments* and Fraction Oxidized
Res. Comm. Ind. Trans. Utility Terr. Total
1.5
1.5
69.4
0.0
0.0
17.1
0.0
1.3
6.4
0.0
0.0
0.0
24.8
95.7
2.2
2.2
41.5
0.0
0.0
9.2
0.0
0.2
1.1
0.0
1.5
4.1
16.1
59.9
21.2
40.7
0.7
62.6
125.8
(0.0)
0.0
22.6
0.0
0.2
12.6
1.7
3.7
8.3
0.0
0.5
1.5
2.0
6.8
16.1
4.9
(13.1)
19.0
25.1
2.1
(7.1)
0.7
(3.3)
104.3
292.6
0.0
0.0
8.8
0.0
0.8
73.4
52.3
0.0
0.3
1.6
263.4
5.5
397.3
406.1
411.8
411.8
40.7
0.0
0.0
1.3
0.0
0.0
0.0
0.0
0.0
17.8
0.8
19.9
0.0574
472.5
0.220
0.2
NA
0.000
0.000
1.554
1.264
0.000
0.199
0.000
2.176
3.288
1.095
9.575
9.795
1.5
2.2
21.2
40.7
0.7
0.0
411.8
0.2
478.3
286.2
(0.0)
0.8
125.2
53.5
1.7
20.6
3.3
270.8
39.0
1.1
0.0
0.5
1.5
2.0
6.8
16.1
4.9
(13.1)
19.9
25.1
2.1
(7.1)
0.7
(3.3)
572.0
0.0574
1,336.6
"Adjustments include: international bunker fuel consumption (see Table A-8) and carbon stored in products (see Table A-9)
NA (Not Available)
A-8 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table A-6: 1991 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type
10
11
12
13
14
15
Fuel Type
Residential Coal
Commercial Coal
Industrial Coking Coal
Industrial Other Coal
Coke Imports
Transportation Coal
Utility Coal
US Territory Coal (bit)
Total Coal
Natural Gas
Asphalt & Road Oil
Aviation Gasoline
Distillate Fuel Oil
Jet Fuel
Kerosene
LPG
Lubricants
Motor Gasoline
Residual Fuel
Other Petroleum
AvGas Blend Components
Crude Oil
MoGas Blend Components
Misc. Products
Naphtha (<401 deg. F)
Other Oil (>401 deg. F)
Pentanes Plus
Petrochemical Feedstocks
Petroleum Coke
Still Gas
Special Naphtha
Unfinished Oils
Waxes
Other Wax & Misc.
Total Petroleum
Geothermal
TOTAL (All Fuels)
Res.
56.3
56.3
4,685.0
0.0
0.0
831.5
0.0
72.3
389.5
0.0
0.0
0.0
1,293.3
6,034.6
Comm.
84.5
84.5
2,807.7
0.0
0.0
481.6
0.0
12.1
68.7
0.0
85.0
213.2
860.6
3,752.8
Consumption (TBtu)
Ind. Trans. Utility
907.3
1,629.2
8.9
0.0
16,012.4
2,545.4 0.0 16,012.4
8,637.2 621.5 2,853.6
1,076.5 0.0 0.0
0.0 41.7 0.0
1,139.2 3,677.6 80.0
0.0 3,025.0 0.0
11.4 0.0 0.0
1,749.3 19.9 0.0
166.7 157.5 0.0
193.3 13,502.6 0.0
335.9 1,031.9 1,076.1
(0.1)
38.9
(25.9)
152.6
298.9
827.3
294.0
0.0
700.2 21.7
1,426.6
88.0
(450.2)
35.1
0.0
8,057.8 21,456.2 1,177.8
0.028
19,240.4 22,077.7 20,043.8
Terr. Total
56.3
84.5
907.3
1,629.2
8.9
0.0
16,012.4
7.0 7.0
7.0 18,705.6
NA 19,605.0
1,076.5
41.7
72.2 6,282.1
80.8 3,105.8
95.8
13.7 2,241.1
0.0 324.2
117.3 13,898.2
135.0 2,792.1
122.7 122.7
(0.1)
38.9
(25.9)
152.6
298.9
827.3
294.0
0.0
722.0
1,426.6
88.0
(450.2)
35.1
0.0
541.7 33,387.5
0.028
548.7 71,698.1
Emissions (MMTCE) including Adjustments* and Fraction Oxidized
Res. Comm. Ind. Trans. Utility Terr. Total
1.4
1.4
67.5
0.0
0.0
16.4
0.0
1.4
6.5
0.0
0.0
0.0
24.4
93.3
2.2
2.2
40.4
0.0
0.0
9.5
0.0
0.2
1.2
0.0
1.6
4.5
17.1
59.7
22.6
42.0
0.2
64.8
120.0
(0.0)
0.0
22.5
0.0
0.2
10.9
1.7
3.7
7.1
(0.0)
0.8
(0.5)
3.1
5.4
16.3
4.7
(12.2)
17.1
24.7
1.7
(9.0)
0.7
(4.4)
94.5
279.3
0.0
0.0
8.9
0.0
0.8
70.5
53.0
0.0
0.3
1.6
259.5
5.5
391.1
400.1
407.2
407.2
41.1
0.0
0.0
1.6
0.0
0.0
0.0
0.0
0.0
22.9
0.6
25.1
0.0574
473.5
0.175
0.2
NA
0.000
0.000
1.426
1.551
0.000
0.233
0.000
2.232
2.872
2.186
10.500
10.675
1.4
2.2
22.6
42.0
0.2
0.0
407.2
0.2
475.8
277.9
(0.0)
0.8
121.9
54.6
1.9
19.1
3.2
267.0
42.9
2.2
(0.0)
0.8
(0.5)
3.1
5.4
16.3
4.7
(12.2)
17.7
24.7
1.7
(9.0)
0.7
(4.4)
562.6
0.0574
1,316.4
"Adjustments include: international bunker fuel consumption (see Table A-8) and carbon stored in products (see Table A-9)
NA (Not Available)
A-9
-------
Table A-7: 1990 Energy Consumption Data and CO2 Emissions from Fossil Fuel Combustion by Fuel Type
10
11
12
13
14
15
Fuel Type
Residential Coal
Commercial Coal
Industrial Coking Coal
Industrial Other Coal
Coke Imports
Transportation Coal
Utility Coal
US Territory Coal (bit)
Total Coal
Natural Gas
Asphalt & Road Oil
Aviation Gasoline
Distillate Fuel Oil
Jet Fuel
Kerosene
LPG
Lubricants
Motor Gasoline
Residual Fuel
Other Petroleum
AvGas Blend Components
Crude Oil
MoGas Blend Components
Misc. Products
Naphtha (<401 deg. F)
Other Oil (>401 deg. F)
Pentanes Plus
Petrochemical Feedstocks
Petroleum Coke
Still Gas
Special Naphtha
Unfinished Oils
Waxes
Other Wax & Misc.
Total Petroleum
Geothermal
TOTAL (All Fuels)
Res.
61.9
61.9
4,518.7
0.0
0.0
837.4
0.0
63.9
365.0
0.0
0.0
0.0
1,266.3
5,846.9
Comm.
92.9
92.9
2,698.1
0.0
0.0
487.0
0.0
11.8
64.4
0.0
110.6
233.1
906.9
3,697.9
Consumption (TBtu)
Ind. Trans.
1,041.8
1,646.1
4.8
0.0
16
2,692.7 0.0 16
8,519.7 682.4 2
1,170.2 0.0
0.0 45.0
1,180.9 3,830.5
0.0 3,129.5
12.3 0.0
1,607.7 21.8
186.3 176.0
184.1 13,577.1
417.2 1,030.2 1
0.2
50.9
53.7
137.8
347.8
753.9
250.3
0.0
719.9
1,473.2
107.1
(369.0)
33.3
0.0
8,317.9 21,810.1 1
19,530.3 22,492.5 20
Utility
087.8
087.8
861.4
0.0
0.0
86.3
0.0
0.0
0.0
0.0
0.0
139.4
24.7
250.4
0.029
199.6
Terr. Total
61.9
92.9
1,041.8
1,646.1
4.8
0.0
16,087.8
4.9 4.9
4.9 18,940.2
NA 19,280.3
1,170.2
45.0
73.9 6,496.0
63.5 3,193.0
88.0
14.4 2,073.3
0.8 363.1
100.8 13,972.6
121.8 2,941.7
85.2 85.2
0.2
50.9
53.7
137.8
347.8
753.9
250.3
0.0
744.6
1,473.2
107.1
(369.0)
33.3
0.0
460.3 34,011.9
0.029
465.2 72,232.4
Emissions (MMTCE) including Adjustments* and Fraction Oxidized
Res. Comm. Ind. Trans. Utility Terr. Total
1.6
1.6
65.1
0.0
0.0
16.5
0.0
1.2
6.1
0.0
0.0
0.0
23.9
90.6
2.4
2.4
38.8
0.0
0.0
9.6
0.0
0.2
1.1
0.0
2.1
5.0
18.0
59.2
25.9
42.4
0.1
68.5
118.2
0.0
0.0
23.3
0.0
0.2
10.9
1.9
3.5
8.9
0.0
1.0
1.0
2.8
6.2
14.9
3.3
(12.1)
17.3
25.5
2.1
(7.4)
0.7
(3.9)
100.2
286.8
0.0
0.0
9.8
0.0
0.8
73.4
55.0
0.0
0.4
1.8
260.9
6.7
399.0
408.9
409.0
409.0
41.2
0.0
0.0
1.7
0.0
0.0
0.0
0.0
0.0
24.2
0.7
26.6
0.0595
476.9
1.6
2.4
25.9
42.4
0.1
0.0
409.0
0.122 0.1
0.1 481.6
NA 273.1
0.000 0.0
0.000 0.8
1.459 126.1
1.220 56.3
0.000 1.7
0.244 18.7
0.008 3.6
1.918 268.5
2.590 47.4
1.518 1.5
0.0
1.0
1.0
2.8
6.2
14.9
3.3
(12.1)
18.0
25.5
2.1
(7.4)
0.7
(3.9)
8.957 576.7
0.0595
9.079 1,331.4
"Adjustments include: international bunker fuel consumption (see Table A-8) and carbon stored in products (see Table A-9)
NA (Not Available)
A-10U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table A-8: 1996 Emissions From International Bunker Fuel Consumption
12 3 456
Fuel Type
Distillate Fuel
Jet Fuel
Residual Fuel
Total
Bunker Fuel Carbon Content Carbon Content
Consumption Coefficient (MMTCE)
(TBtu) (MMTCE/QBtu)3
109
312
665
1,085
19.95
19.33
21.49
2
6
14
22.5
Fraction Emissions
Oxidized (MMTCE)
0.99
0.99
0.99
2
6
14
22.3
Table A-9: 1996 Carbon Stored In Products
1
Fuel Type
Industrial Coking Coal
Natural Gas
Asphalt & Road Oil
Distillate Fuel Oil
LPG
Lubricants
Residual Fuel
Naphtha (<401 deg. F)
Other Oil (>401 deg. F)
Pentanes Plus
Petrochemical Feedstocks
Petroleum Coke
Special Naphtha
Other Wax & Misc.
Total
2 3
Non-Fuel Use
(TBtu)
Ind. Trans.
28
381
1,176
[a]
1,699
173 163
[a]
[b]
[b]
319
1,204
208
75
192
5,453 163
4
Carbon Content
Coefficient
(MMTCE/QBtu)
25.53
14.47
20.62
19.95
16.99
20.24
21.49
18.14
19.95
18.24
19.37
27.85
19.86
19.81
5 6
Carbon Content
(MMTCE)
Ind. Trans.
0.7
6
24
0
29
3 3
0
0
0
6
21
6
1
4
101 3
7
Fraction
Sequestered
0.75
1.00
1.00
[a]
0.80
0.50
[a]
[b]
[b]
0.80
0.75
0.50
0.00
1.00
8
Carbon
Ind.
0.532
5.520
24.248
[a]
23.088
1.746
[a]
[b]
[b]
4.651
13.812
2.897
0.000
3.417
79.9
9 10
Stored (MMTCE)
Trans. Total
0.532
5.520
24.248
[a]
23.088
1.649 3.395
[a]
[b]
[b]
4.651
13.812
2.897
0.000
3.417
1.6 81.6
[aj Non-fuel use values of distillate fuel and residual fuel were relatively small and included in the
[b] Non-fuel use values of Naphtha (<401 deg. F) and Other Oil (>401 deg. F) are reported in the
'Other Waxes and Misc." category.
'Petrochemical Feedstocks" category.
3 One QBtu is one quadrillion Btu, or 1015 Btu. This unit is commonly referred to as a "Quad."
A-11
-------
Table A-10: Key Assumptions for Estimating Carbon Dioxide Emissions
Carbon Content Coefficient
Fuel Type (MMTCE/QBtu)
Coal
Residential Coal
Commercial Coal
Industrial Coking Coal
Industrial Other Coal
Coke Imports
Transportation Coal
Utility Coal
U.S. Territory Coal (bit)
Natural Gas
Petroleum
Asphalt & Road Oil
Aviation Gasoline
Distillate Fuel Oil
Jet Fuel
Kerosene
LPG
Lubricants
Motor Gasoline
Residual Fuel
Other Petroleum
AvGas Blend Components
Crude Oil
MoGas Blend Components
Misc. Products
Naphtha (<401 deg. F)
Other Oil (>401 deg. F)
Pentanes Plus
Petrochemical Feedstocks
Petroleum Coke
Still Gas
Special Naphtha
Unfinished Oils
Waxes
Other Wax & Misc.
Geothermal
[a]
[a]
[a]
[a]
27.85
NC
[a]
25.14
14.47
20.62
18.87
19.95
[a]
19.72
[a]
20.24
[a]
21.49
18.87
[a]
19.39
20.23
18.14
19.95
18.24
19.37
27.85
17.51
19.86
20.23
19.81
19.81
2.05
Fraction
Oxidized
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.995
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
0.99
NA
Sources: Carbon Coefficients and stored carbon from EIA. Combustion efficiency for coal from Bechtel (1993) and for petroleum and natural gas from IPCC
(IPCC/UNEP/OECD/IEA 1997, vol. 2).
NA (Not Applicable)
NC (Not Calculated)
[a] These coefficients vary annually due to fluctuations in fuel quality (see Table A-11).
A-12U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table A-11: Annually Variable Carbon Content Coefficients by Year (MMTCE/QBtu)
Fuel Type
Residential Coal
Commercial Coal
Industrial Coking Coal
Industrial Other Coal
Utility Coal
LPG
Motor Gasoline
Jet Fuel
Crude Oil
1990
25.92
25.92
25.51
25.58
25.68
16.99
19.41
19.40
20.14
1991
26.00
26.00
25.51
25.59
25.69
16.98
19.41
19.40
20.16
1992
26.13
26.13
25.51
25.62
25.69
16.99
19.42
19.39
20.20
1993
25.97
25.97
25.51
25.61
25.71
16.97
19.43
19.37
20.20
1994
25.95
25.95
25.52
25.63
25.72
17.01
19.45
19.35
20.19
1995
26.00
26.00
25.53
25.63
25.74
17.00
19.38
19.34
20.21
1996
26.00
26.00
25.53
25.63
25.74
16.99
19.38
19.33
20.23
Source: EIA
Table A-12: Electricity Consumption by End-Use Sector (Billion Kilowatt-hours)
End-Use Sector
Residential
Commercial
Industrial
Transportation
U.S. Territories*
Total
1990
924
839
946
4
2,713
1991
955
856
947
4
2,762
1992
936
851
973
4
2,764
1993
995
886
977
4
2,862
1994
1,008
914
1,008
4
2,934
1995
1,043
954
1,013
4
3,014
1996
1,078
985
1,017
4
3,084
*EIA electric utility fuel consumption data does not include the U.S. territories.
- Not applicable
Source: EIA
A-13
-------
Annex B
Methodology for Estimating Emissions of CH4, N2O, and Criteria
Pollutants from Stationary Sources
Estimates of CH4 and N2O Emissions from Stationary Combustion
Methane (CH4) and nitrous oxide (N2O) emissions from stationary source fossil fuel combustion were estimated
using IPCC emission factors and methods. Estimates were obtained by multiplying emission factors (by sector and
fuel type) by fossil fuel and wood consumption data. This "top-down" methodology is characterized by two basic
steps, described below. Data are presented in Table B-l through Table B-9. Changes in the methodology for this
source are outlined at the end of this discussion.
Step 1: Determine Energy Consumption by Sector and Fuel Type
Greenhouse gas emissions from stationary combustion activities were grouped into four sectors: industrial,
commercial/institutional, residential, and electric utilities. For CH4 and N2O, estimates were based upon consumption
of coal, gas, oil, and wood. Energy consumption data were obtained from EIA's Monthly Energy Review (1997), and
adjusted to lower heating values assuming a 10 percent reduction for natural gas and a 5 percent reduction for coal
and petroleum fuels. Table B-l provides annual energy consumption data for the years 1990 through 1996.
Step 2: Determine the Amount of CH4 and N O Emitted
Activity data for each sector and fuel type were multiplied by emission factors to obtain emissions estimates.
Emission factors were taken from the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). Table B-2
provides emission factors used for each sector and fuel type.
Estimates of NO , CO, and NMVOC Emissions from Stationary Combustion
For criteria pollutants, the major source categories included were those identified in EPA (1997): coal, fuel oil,
natural gas, wood, other fuels (including bagasse, liquefied petroleum gases, coke, coke oven gas, and others), and
stationary internal combustion (which includes emissions from internal combustion engines not used in transportation).
EPA (1997) periodically estimates emissions of NOX, CO, and NMVOCs by sector and fuel type using a "bottom-up"
estimating procedure. In other words, the emissions were calculated either for individual sources (e.g., industrial
boilers) or for many sources combined, using basic activity data (e.g., fuel consumption or deliveries, etc.) as
indicators of emissions. EPA (1997) projected emissions for years subsequent to their bottom-up estimates. The
national activity data used to calculate the individual categories were obtained from various sources. Depending upon
the category, these activity data may include fuel consumption or deliveries of fuel, tons of refuse burned, raw material
processed, etc. Activity data were used in conjunction with emission factors that relate the quantity of emissions to
the activity. Table B-3 through Table B-9 present criteria pollutant emission estimates for 1990 through 1996.
The basic calculation procedure for most source categories presented in EPA (1997) is represented by the
following equation:
ERS = As x EfRS x (1 - (y 100)
where,
E = emissions
p = pollutant
s = source category
A = activity level
EF = emission factor
C = percent control efficiency
B-1
-------
The EPA currently derives the overall emission control efficiency of a category from a variety of sources,
including published reports, the 1985 National Acid Precipitation and Assessment Program (NAPAP) emissions
inventory, and other EPA databases. The U.S. approach for estimating emissions of NOX, CO, and NMVOCs from
stationary combustion as described above is similar to the methodology recommended by the IPCC
(IPCC/UNEP/OECD/IEA 1997).
Differences with Previous Years' Inventories
In previous editions of the Inventory, methane emissions from stationary sources were calculated using a
different methodology. Rather than using activity data and emission factors, CH4 emissions were calculated as a ratio
of NMVOC emissions. The accuracy of stationary source methane emissions have been improved in this year's
inventory with the use of fuel type and end-use specific emission factors in place of the previous NMVOC ratio.
B-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table B-1: Fuel Consumption by Stationary Sources for Calculating CH4 and N2O
Emissions (TBtu)
Fuel/End-Use Sector
Coal
Residential
Commercial/Institutional
Industry
Utilities
Petroleum
Residential
Commercial/Institutional
Industry
Utilities
Natural Gas
Residential
Commercial/Institutional
Industry
Utilities
Wood
Residential
Commercial/Institutional
Industrial
Utilities
Table B-2: CH4 and N2O
Fuel/End-Use Sector
Coal
Residential
Commercial/Institutional
Industry
Utilities
Petroleum
Residential
Commercial/Institutional
Industry
Utilities
Natural Gas
Residential
Commercial/Institutional
Industry
Utilities
Wood
Residential
Commercial/Institutional
Industrial
Utilities
1990
18,935.3
61.9
92.9
2,692.7
16,087.8
11,741.5
1,266.3
906.9
8,317.9
1,250.4
18,597.9
4,518.7
2,698.1
8,519.7
2,861.4
2,185.0
581.0
30.0
1,562.0
12.0
Emission Factors
CH,
300
10
10
1
10
10
2
3
5
5
5
1
300
300
30
30
1991
18,698.6
56.3
84.5
2,545.4
16,012.4
11,389.6
1,293.3
860.6
8,057.8
1,177.8
18,983.5
4,685.0
2,807.7
8,637.2
2,853.6
2,181.0
613.0
30.0
1,528.0
10.0
by Fuel
N,0
1.4
1.4
1.4
1.4
0.6
0.6
0.6
0.6
0.1
0.1
0.1
0.1
4.0
4.0
4.0
4.0
1992
18,802.1
56.7
85.7
2,467.7
16,192.0
11,696.4
1,312.4
813.3
8,637.7
933.0
19,530.2
4,821.1
2,884.2
8,996.4
2,828.5
2,279.0
645.0
30.0
1,593.0
11.0
Type and
1993
19,428.0
56.6
85.5
2,444.8
16,841.1
11,641.5
1,387.0
752.8
8,449.6
1,052.0
20,224.9
5,097.5
2,995.8
9,387.4
2,744.1
2,228.0
548.0
44.0
1,625.0
11.0
Sector (g/GJ)
1994
19,497.8
55.5
83.5
2,463.7
16,895.2
11,928.7
1,340.4
753.3
8,866.8
968.2
20,631.3
4,988.3
2,980.8
9,609.3
3,052.9
2,266.0
537.0
45.0
1,673.0
11.0
4
1995
19,555.4
53.7
81.0
2,441.9
16,978.9
11,465.9
1,363.0
756.8
8,688.1
658.0
21,507.3
4,981.3
3,185.2
10,064.3
3,276.4
2,350.0
596.0
45.0
1,698.0
11.0
1996
20,559.8
53.7
81.0
2,338.7
18,086.4
12,132.3
1,441.6
775.8
9,179.5
735.5
21,777.8
5,375.8
3,289.9
10,311.3
2,800.8
2,440
595.0
49.0
1,784.0
12.0
4 GJ (Gigajoule) = 109 joules. One joule = 9.486x1CT4 Btu
B-3
-------
Table B-3: 1996 NOX, NMVOC, and CO Emissions from Stationary
Sources (Gg)
Table B-4: 1995 NOX, NMVOC, and CO Emissions from Stationary
Sources (Gg)
Sector/Fuel Type
Electric Utilities
Coal
Fuel Oil
Natural gas
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Residential
Coalb
Fuel Oilb
Natural Gasb
Wood
Other Fuels3
Total
NO,
5,473
5,004
87
244
NA
137
2,875
543
223
1,212
NA
113
784
366
35
93
212
NA
26
804
NA
NA
NA
44
760
9,518
NMVOC
341
238
10
40
NA
53
972
90
65
316
NA
277
224
227
14
17
49
NA
148
3,866
NA
NA
NA
3,621
244
5,407
CO
41
28
3
2
NA
9
188
5
11
66
NA
46
60
21
1
3
10
NA
8
724
NA
NA
NA
687
37
975
NA (Not Available)
a "Other Fuels" include LPG, waste oil, coke oven gas, coke
b Coal, fuel oil, and natural gas emissions are included in the
Note: Totals may not sum due to independent rounding.
and non-residential wood (EPA 1997).
Other Fuels" category (EPA 1997).
Sector/Fuel Type
Electric Utilities
Coal
Fuel Oil
Natural gas
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Residential
Coalb
Fuel Oilb
Natural Gasb
Wood
Other Fuels3
Total
NO,
5,791
5,060
87
510
NA
134
2,852
541
224
1,201
NA
111
774
365
35
94
210
NA
27
812
NA
NA
NA
44
768
9,820
NMVOC
40
26
2
2
NA
9
187
5
11
66
NA
45
59
21
1
3
10
NA
8
725
NA
NA
NA
688
37
973
CO
338
227
9
49
NA
52
958
88
64
313
NA
270
222
211
14
17
49
NA
132
3,876
NA
NA
NA
3,628
248
5,382
NA (Not Available)
a "Other Fuels" include LPG, waste oil, coke oven gas, coke,
b Coal, fuel oil, and natural gas emissions are included in the
Note: Totals may not sum due to independent rounding.
and non-residential wood (EPA 1997).
'Other Fuels" category (EPA 1997).
B-4 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table B-5: 1994 NOX, NMVOC, and CO Emissions from Stationary
Sources (Gg)
Table B-6: 1993 NOX, NMVOC, and CO Emissions from Stationary
Sources (Gg)
Sector/Fuel Type
Electric Utilities
Coal
Fuel Oil
Natural gas
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Residential
Coalb
Fuel Oilb
Natural Gasb
Wood
Other Fuels3
Total
NO,
5,955
5,112
148
536
NA
159
2,854
546
219
1,209
NA
113
767
365
36
86
215
NA
28
817
NA
NA
NA
40
111
9,990
NMVOC
41
26
4
2
NA
9
178
7
11
57
NA
45
58
21
1
3
10
NA
8
657
NA
NA
NA
621
36
897
CO
335
224
13
48
NA
50
944
91
60
306
NA
260
228
212
13
16
49
NA
134
3,514
NA
NA
NA
3,271
243
5,006
NA (Not Available)
a "Other Fuels" include LPG, waste oil, coke oven gas, coke
b Coal, fuel oil, and natural gas emissions are included in the
Note: Totals may not sum due to independent rounding.
Sector/Fuel Type
Electric Utilities
Coal
Fuel Oil
Natural gas
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Residential
Coalb
Fuel Oilb
Natural Gasb
Wood
Other Fuels3
Total
NO,
6,033
5,210
163
500
NA
160
2,858
534
222
1,206
NA
113
782
360
37
84
211
NA
28
827
NA
NA
NA
40
786
10,077
NMVOC
41
26
4
2
NA
9
169
5
11
46
NA
46
60
22
1
3
10
NA
8
670
NA
NA
NA
633
36
901
CO
329
223
15
45
NA
46
946
92
60
292
NA
259
243
207
14
16
48
NA
129
3,585
NA
NA
NA
3,337
248
5,067
and non-residential wood (EPA 1997).
Other Fuels" category (EPA 1997).
NA (Not Available)
a "Other Fuels" include LPG, waste oil, coke oven gas, coke, and non-residential wood (EPA 1997).
b Coal, fuel oil, and natural gas emissions are included in the "Other Fuels" category (EPA 1997).
Note: Totals may not sum due to independent rounding.
B-5
-------
Table B-7: 1992 NOX, NMVOC, and CO Emissions from Stationary
Sources (Gg)
Table B-8: 1991 NOX, NMVOC, and CO Emissions from Stationary
Sources (Gg)
Sector/Fuel Type
Electric Utilities
Coal
Fuel Oil
Natural gas
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Residential
Coalb
Fuel Oilb
Natural Gasb
Wood
Other Fuels3
Total
NOx
5,899
5,060
154
526
NA
159
2,785
521
222
1,180
NA
115
748
348
35
84
204
NA
25
879
NA
NA
NA
48
831
9,912
NMVOC
40
25
4
2
NA
9
169
7
11
47
NA
45
60
20
1
3
9
NA
7
782
NA
NA
NA
746
36
1,010
CO
318
214
14
47
NA
43
866
92
58
272
NA
239
205
204
13
16
46
NA
128
4,194
NA
NA
NA
3,929
265
5,582
NA (Not Available)
a "Other Fuels" include LPG, waste oil, coke oven gas, coke
b Coal, fuel oil, and natural gas emissions are included in the
Note: Totals may not sum due to independent rounding.
and non-residential wood (EPA 1997).
Other Fuels" category (EPA 1997).
Sector/Fuel Type
Electric Utilities
Coal
Fuel Oil
Natural gas
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Residential
Coalb
Fuel Oilb
Natural Gasb
Wood
Other Fuels3
Total
NOx
5,913
5,042
192
526
NA
152
2,702
517
215
1,134
NA
117
720
333
33
80
191
NA
29
829
NA
NA
NA
45
784
9,777
NMVOC
40
25
5
2
NA
9
177
5
10
54
NA
47
61
18
1
2
8
NA
7
739
NA
NA
NA
704
35
975
CO
317
212
17
46
NA
41
834
92
54
257
NA
242
189
196
13
16
40
NA
128
3,964
NA
NA
NA
3,710
254
5,312
NA (Not Available)
° "Other Fuels" include LPG, waste oil, coke oven gas, coke,
b Coal, fuel oil, and natural gas emissions are included in the
Note: Totals may not sum due to independent rounding.
and non-residential wood (EPA 1997).
'Other Fuels" category (EPA 1997).
B-6 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table B-9: 1990 NOX, NMVOC, and CO
Emissions from Stationary Sources (Gg)
Sector/Fuel Type
Electric Utilities
Coal
Fuel Oil
Natural gas
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Internal Combustion
Commercial/Institutional
Coal
Fuel Oil
Natural gas
Wood
Other Fuels3
Residential
Coalb
Fuel Oilb
Natural Gasb
Wood
Other Fuels3
Total
NOx
6,043
5,117
200
513
NA
213
2,753
530
240
1,072
NA
119
792
336
36
88
181
NA
31
749
NA
NA
NA
42
707
9,881
NMVOC
43
25
5
2
NA
11
165
7
11
52
NA
46
49
18
1
3
7
NA
8
686
NA
NA
NA
651
35
912
CO
329
213
18
46
NA
52
797
95
67
205
NA
253
177
205
13
16
40
NA
136
3,667
NA
NA
NA
3,429
238
4,998
NA (Not Available)
a "Other Fuels" include LPG, waste oil, coke oven gas, coke, and non-
residential wood (EPA 1997).
b Coal, fuel oil, and natural gas emissions are included in the "Other Fuels"
category (EPA 1997).
Note: Totals may not sum due to independent rounding.
B-7
-------
Annex C
Methodology for Estimating Emissions of CH4, N2O, and Criteria
Pollutants from Mobile Sources
Estimates of CH4 and N2O Emissions from Mobile Combustion
Greenhouse gas emissions from mobile sources are reported by transport mode (e.g., road, rail, air, and water),
vehicle type, and fuel. EPA does not systematically track emissions of CH4 and N2O; therefore, estimates of these
gases were developed using a methodology similar to that outlined in the Revised 1996 IPCC Guidelines
(IPCC/UNEP/OECD/IEA 1997).
Step 1: Determine Vehicle Miles Traveled or Fuel Consumption by Vehicle Type,
Fuel Type, and Model Year
Activity data were obtained from a number of U.S. government agency publications. Depending on the
category, these basic activity data included such information as fuel consumption, fuel deliveries, and vehicle miles
traveled (VMT). The activity data for highway vehicles included estimates of VMT by vehicle type and model year
from EPA (1997a) and the MOBILESa emissions model (EPA 1997b).
National VMT data for gasoline and diesel highway vehicles are presented in Table C-l and Table C-2,
respectively. Total VMT for each highway category (i.e., gasoline passenger cars, light-duty gasoline trucks, heavy-
duty gasoline vehicles, diesel passenger cars, light-duty diesel trucks, heavy-duty diesel vehicles, and motorcycles)
were distributed across 25 model years based on the temporally fixed age distribution of VMT by the U.S. vehicle fleet
in 1990 (see Table C-3) as specified in MOBILESa. Activity data for gasoline passenger cars and light-duty trucks
in California were developed separately due to the different emission control technologies deployed in that state
relative to the rest of the country. Unlike the rest of the United States, beginning in model year 1994, a fraction of
the California VMT for gasoline passenger cars and light-duty trucks was attributed to for low emission vehicles
(LEVs). LEVs have not yet been widely deployed in other states. Based upon U.S. Department of Transportation
statistics for 1994, it was assumed that 8.7 percent of national VMT occurred in California.
Activity data for non-highway vehicles were based on annual fuel consumption statistics by transportation mode
and fuel type. Consumption data for distillate and residual fuel oil by ocean-going ships (i.e., marine bunkers), boats,
construction equipment, farm equipment, and locomotives were obtained from EIA (1997). Data on the consumption
of jet fuel and aviation gasoline in aircraft were obtained from FAA (1997). Consumption of motor gasoline by boats,
construction equipment, farm equipment, and locomotives data were drawn from FHWA (1997). The activity data
used for non-highway vehicles are included in Table C-4.
Step 2: Allocate VMT Data to Control Technology Type for Highway Vehicles
For highway sources, VMT by vehicle type for each model year were distributed across various control
technologies as shown in Table C-5, Table C-6, Table C-7, Table C-8, and Table C-9. Again, California gasoline-
fueled passenger cars and light-duty trucks were treated separately due to that state's distinct mobile source emission
standards—including the introduction of LEVs in 1994—compared with the rest of the United States. The categories
"Tier 0" and "Tier 1" have been substituted for the early three-way catalyst and advanced three-way catalyst
categories, respectively, as defined in the Revised 1996IPCC Guidelines. Tier 0, Tier 1, and LEV are actually U.S.
emission regulations, rather than control technologies; however, each does correspond to particular combinations of
control technologies and engine design. Tier 1 and its predecessor Tier 0 both apply to vehicles equipped with three-
way catalysts. The introduction of "early three-way catalysts," and "advance three-way catalysts" as described in the
Revised 1996 IPCC Guidelines, roughly correspond to the introduction of Tier 0 and Tier 1 regulations (EPA 1998).
C-1
-------
Step 3: Determine the Amount of CH4 and N2O Emitted by Vehicle, Fuel, and Control
Technology Type
Emissions of CH4 from mobile source combustion were calculated by multiplying emission factors in
IPCC/UNEP/OECD/IEA (1997) by activity data for each vehicle type as described in Step 1 (see Table C-10 and
Table C-ll). The CH4 emission factors for highway sources were derived from EPA's MOBILESa mobile source
emissions model (EPA 1997b). The MOBILESa model uses information on ambient temperature, diurnal temperature
range, altitude, vehicle speeds, national vehicle registration distributions, gasoline volatility, emission control
technologies, fuel composition, and the presence or absence of vehicle inspection/maintenance programs in order to
produce these factors.
Emissions of N2O—in contrast to CH4, CO, NOX, and NMVOCs—have not been extensively studied and are
currently not well characterized. The limited number of studies that have been done on highway vehicle emissions
of N2O have shown that emissions are generally greater from vehicles with catalytic converter systems than those
without such controls, and greater from aged than from new catalysts. These systems control tailpipe emissions of
NOX (i.e., NO and NO2) by catalytically reducing NOX to N2. Suboptimal catalyst performance, caused by as yet
poorly understood factors, results in incomplete reduction and the conversion of some NOX to N2O rather than to N2.
Fortunately, newer vehicles with catalyst and engine designs meeting the more recent Tier 1 and LEV standards have
shown reduced emission rates of both NOX and N2O.
In order to better characterize the process by which N2O is formed by catalytic controls and to develop a more
accurate national emission estimate, the EPA's Office of Mobile Sources—at its National Vehicle and Fuel Emissions
Laboratory (NVFEL)—recently conducted a series of tests in order to measure emission rates of N2O from used Tier
1 and LEV gasoline-fueled passenger cars and light-duty trucks equipped with catalytic converters. These tests and
a review of the literature were used to develop the emission factors for nitrous oxide used in this inventory (EPA
1998). The following references were used in developing the N2O emission factors for gasoline-fueled highway
passenger cars presented in Table C-10:
LEVs. Tests performed at NVFEL (EPA 1998)5
Tier 1. Tests performed at NVFEL (EPA 1988)
Tier 0. Smith and Carey (1982), Barton and Simpson (1994), and one car tested at NVFEL (EPA 1998)
Oxidation Catalyst. Smith and Carey (1982), Urban and Garbe (1979)
Non-Catalyst. Prigent and de Soete (1989), Dasch (1992), and Urban and Garbe (1979)
Nitrous oxide emission factors for other types of gasoline-fueled vehicles—light-duty trucks, heavy-duty
vehicles, and motorcycles—were estimated by adjusting the factors for gasoline passenger cars, as described above,
by their relative fuel economies. This adjustment was performed using the carbon dioxide emission rates in the
Revised 1996IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) as a proxy for fuel economy (see Table C-10). Data
from the literature and tests performed at NVFEL support the conclusion that light-duty trucks have higher emission
rates than passenger cars. However, the use of fuel-consumption ratios to determine emission factors is considered
a temporary measure only, to be replaced as soon as real data are available.
The resulting N2O emission factors employed for gasoline highway vehicles are lower than the U.S. default
values presented in the Revised 1996 IPCC Guidelines, but are higher than the European default values, both of which
were published before the more recent tests and literature review conducted by the NVFEL. The U.S. defaults in the
Guidelines were based on three studies that tested a total of five cars using European rather than U. S. test procedures.
Nitrous oxide emission factors for diesel highway vehicles were taken from the European default values found in the
Revised 1996IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). There is little data addressing N2O emissions from
U.S. diesel-fueled vehicles, and in general, European countries have had more experience with diesel-fueled vehicles.
U.S. default values in the Revised 1996IPCC Guidelines were used for non-highway vehicles.
5 It was assumed that LEVs would be operated using low-sulfur fuel (i.e., Indolene at 24 ppm sulfur). All other NVFEL tests
were performed using a standard commercial fuel (CAAB at 285 ppm sulfur). Emission tests by NVFEL have consistently
exhibited higher N2O emission rates from higher sulfur fuels on Tier 1 and LEV vehicles.
C-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Compared to regulated tailpipe emissions, there is relatively little data available to estimate emission factors
for nitrous oxide. Nitrous oxide is not a criteria pollutant, and measurements of it in automobile exhaust have not been
routinely collected. Further testing is needed to reduce the uncertainty in nitrous oxide emission factors for all classes
of vehicles, using realistic driving regimes, environmental conditions, and fuels.
Estimates of NOX, CO, and NMVOC Emissions From Mobile Combustion
The emission estimates of NOX, CO, and NMVOCs for mobile sources were taken directly from the EPA's
National Air Pollutant Emissions Trends, 1900 -1996 (EPA 1997a). This EPA report provides emission estimates
for these gases by sector and fuel type using a "top down" estimating procedure whereby emissions were calculated
using basic activity data, such as amount of fuel delivered or miles traveled, as indicators of emissions. Table C-12
through Table C-18 provide complete emissions estimates for 1990 through 1996.
Table C-1: Vehicle Miles Traveled for Gasoline Highway Vehicles (109 Miles)
Passenger Light-Duty Heavy-Duty Passenger Cars Light-Duty
Year Carsa Trucksa Vehicles Motorcycles (CA)b Trucks (CA)b
1990
1991
1992
1993
1994
1995
1996
1362.75
1381.11
1437.57
1462.88
1426.55
1466.04
1492.35
422.09
428.12
431.76
450.30
531.21
545.90
555.84
43.32
43.60
43.39
45.96
49.67
51.04
52.00
9.57
9.20
9.55
9.89
10.25
10.52
10.73
129.86
131.61
136.99
139.40
135.94
139.70
142.21
40.22
40.80
41.14
42.91
50.62
52.02
52.97
3 Excludes California
b California VMT for passenger cars and light-duty trucks was treated separately and estimated as 8.7 percent of national total.
Source: VMT data are the same as those used in EPA (1997a).
Table C-2: Vehicle Miles Traveled for Diesel Highway Vehicles (109 Miles)
Year Passenger Light-Duty Heavy-Duty
Cars Trucks Vehicles
1990
1991
1992
1993
1994
1995
1996
20.59
20.87
21.72
22.09
21.55
22.14
22.55
3.77
3.84
3.92
4.08
4.82
4.95
5.05
112.20
112.91
114.95
119.61
126.99
130.50
132.95
Source: VMT data are the same as those used in EPA (1997a).
C-3
-------
Table C-3: VMT Profile by Vehicle Age (years) and Vehicle/Fuel Type for Highway Vehicles
(percent of VMT)
Vehicle Age
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
LDGV
4.9%
7.9%
8.3%
8.2%
8.4%
8.1%
7.7%
5.6%
5.0%
5.1%
5.0%
5.4%
4.7%
3.7%
2.4%
1.9%
1 .4%
1 .5%
1.1%
0.8%
0.6%
0.5%
0.4%
0.3%
1.0%
LDGT
6.3%
8.4%
8.4%
8.4%
8.4%
6.9%
5.9%
4.4%
3.6%
3.1%
3.0%
5.3%
4.7%
4.6%
3.6%
2.8%
1.7%
2.2%
1.7%
1 .4%
0.9%
0.8%
0.8%
0.5%
2.5%
HDGV
2.3%
4.7%
4.7%
4.7%
4.7%
3.8%
3.3%
2.1%
2.6%
2.9%
3.4%
6.4%
5.4%
5.8%
5.1%
3.8%
4.3%
4.1%
3.5%
2.9%
2.1%
2.2%
2.2%
1 .4%
1 1 .7%
LDDV
4.9%
7.9%
8.3%
8.2%
8.4%
8.1%
7.7%
5.6%
5.0%
5.1%
5.0%
5.4%
4.7%
3.7%
2.4%
1.9%
1 .4%
1 .5%
1.1%
0.8%
0.6%
0.5%
0.4%
0.3%
1.0%
LDDT
6.3%
8.4%
8.4%
8.4%
8.4%
6.9%
5.9%
4.4%
3.6%
3.1%
3.0%
5.3%
4.7%
4.6%
3.6%
2.8%
1.7%
2.2%
1.7%
1 .4%
0.9%
0.8%
0.8%
0.5%
2.5%
HDDV
3.4%
6.7%
6.7%
6.7%
6.7%
7.3%
6.1%
4.0%
4.1%
5.1%
5.3%
6.6%
5.5%
5.7%
4.5%
1.9%
2.3%
2.8%
2.4%
1.6%
1.1%
0.9%
0.7%
0.5%
1.6%
MC
14.4%
16.8%
13.5%
10.9%
8.8%
7.0%
5.6%
4.5%
3.6%
2.9%
2.3%
9.7%
0%
0%
0%
0%
0%
0%
0%
0%
0%
0%
0%
0%
0%
LDGV (gasoline passenger cars, also referred to as light-duty gas vehicles)
LDGT (light-duty gas trucks)
HDGV (heavy-duty gas vehicles)
LDDV (diesei passenger cars, also referred to as light-duty diesel vehicles)
LDDT (light-duty diesel trucks)
HDDV (heavy-duty diesel vehicles)
MC (motorcycles)
C-4 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table C-4: Fuel Consumption for Non-Highway Vehicles by Fuel Type (U.S. Gallons)
Vehicle Type/Year
Aircraft3
1990
1991
1992
1993
1994
1995
1996
Marine Bunkers
1990
1991
1992
1993
1994
1995
1996
Boats"
1990
1991
1992
1993
1994
1995
1996
Construction Equipment0
1990
1991
1992
1993
1994
1995
1996
Farm Equipment
1990
1991
1992
1993
1994
1995
1996
Locomotives
1990
1991
1992
1993
1994
1995
1996
Residual
-
-
-
-
-
-
-
4,686,071,250
5,089,541,250
5,399,308,500
4,702,411,500
4,458,628,500
4,823,428,500
4,353,732,750
1,562,023,750
1,696,513,750
1,799,769,500
1,567,470,500
1,486,209,500
1,607,809,500
1,451,244,250
-
-
-
-
-
-
-
-
-
-
-
-
-
-
25,422
6,845
8,343
4,065
5,956
6,498
6,498
Diesel
-
-
-
-
-
-
-
549,251,000
541,910,000
560,042,500
510,936,250
506,724,750
494,526,250
544,402,000
1,647,753,000
1,625,730,000
1,680,127,500
1,532,808,750
1,520,174,250
1,483,578,750
1,633,206,000
2,508,300,000
2,447,400,000
2,287,642,000
2,323,183,000
2,437,142,000
2,273,162,000
2,386,973,000
3,164,200,000
3,144,200,000
3,274,811,000
3,077,122,000
3,062,436,000
3,093,224,000
3,225,029,000
3,210,111,000
3,026,292,000
3,217,231,000
2,906,998,000
3,063,441,000
3,191,023,000
3,266,861,000
Jet Fuel Other
12,986,111,661 353,100,000
11,995,880,426 353,600,000
12,279,912,686 314,000,000
12,326,549,428 268,400,000
12,855,125,825 264,100,000
13,140,841,990 258,100,000
13,677,564,463 275,800,000
-
-
-
-
-
-
-
- 1,300,400,000
- 1,709,700,000
- 1,316,170,000
873,687,000
896,700,000
- 1,060,394,000
- 1,060,394,000
- 1,523,600,000
- 1,384,900,000
- 1,492,200,000
- 1,464,599,000
- 1,492,152,000
- 1,499,346,000
- 1,499,346,000
812,800,000
776,200,000
805,500,000
845,320,000
911,996,000
926,732,000
926,732,000
-
-
-
-
-
-
-
- Not applicable
Sources: FWHA 1997, EIA 1997, and FAA 1997.
a Other Fuel = Aviation Gasoline.
b Other Fuel = Motor Gasoline
0 Construction Equipment includes snowmobiles. Other Fuel = Motor Gasoline
C-5
-------
Table C-5: Control Technology Assignments for Gasoline Passenger Cars (percentage of
VMT)*
Model Years
<1972
1973-1974
1975
1976-1977
1978-1979
1980
1981
1982
1983
1984-1993
1994
1995
1996
Uncontrolled Non-catalyst
100%
100%
20%
15%
10%
5%
Oxidation
80%
85%
90%
88%
15%
14%
12%
TierO
7%
85%
86%
88%
100%
60%
20%
TieM
40%
80%
100%
* Excluding California VMT
Table C-6:
VMT)*
Model Years
<1972
1973-1974
1975
1976
1977-1978
1979-1980
1981
1982
1983
1984
1985
1986
1987-1993
1994
1995
1996
Control Technology Assignments for Gasoline
Uncontrolled Non-catalyst
100%
100%
30%
20%
25%
20%
Oxidation
70%
80%
75%
80%
95%
90%
80%
70%
60%
50%
5%
Light-Duty Trucks (percentage of
TierO
5%
10%
20%
30%
40%
50%
95%
60%
20%
TieM
40%
80%
100%
* Excluding California VMT
Table C-7:
Control Technology Assignments for California
Gasoline
Passenger Cars and
Light-Duty Trucks (percentage of VMT)
Model Years
<1972
1973-1974
1975-1979
1980-1981
1982
1983
1984-1991
1992
1993
1994
1995
1996
Uncontrolled Non-catalyst
100%
100%
Oxidation
100%
15%
14%
12%
TierO
85%
86%
88%
100%
60%
20%
Tier 1 LEV
40%
80%
90% 10%
85% 15%
80% 20%
C-6 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table C-8: Control Technology Assignments for Gasoline Heavy-Duty Vehicles
(percentage of VMT)
Model Years
<1981
1982-1984
1985-1986
1987
1988-1989
1990-2003
2004
Uncontrolled
100%
95%
Non-catalyst
95%
70%
60%
45%
Oxidation
5%
5%
15%
25%
30%
TierO
15%
15%
25%
100%
Table C-9: Control Technology Assignments for Diesel Highway VMT
Vehicle Type/Control Technology Model Years
Diesel Passenger Cars and Light-Duty Trucks
Uncontrolled 1966-1982
Moderate control 1983-1995
Advanced control 1996
Heavy-Duty Diesel Vehicles
Uncontrolled 1966-1972
Moderate control 1983-1995
Advanced control 1996
Motorcycles
Uncontrolled 1966-1995
Non-catalyst controls 1996
* California VMT only
C-7
-------
Table C-10: Emission Factors (g/km) for CH4 and N2O and "Fuel Economy" (g CO2/km)c for
Highway Mobile Sources
Vehicle Type/Control Technology
Gasoline Passenger Cars
Low Emission Vehicles3
TieM
TierO
Oxidation Catalyst
Non-Catalyst
Uncontrolled
Gasoline Light-Duty Trucks
Low Emission Vehicles3
Tier!
TierO
Oxidation Catalyst
Non-Catalyst
Uncontrolled
Gasoline Heavy-Duty Vehicles
TierO
Oxidation Catalyst"
Non-Catalyst Control
Uncontrolled
Diesel Passenger Cars
Advanced
Moderate
Uncontrolled
Diesel Light Trucks
Advanced
Moderate
Uncontrolled
Diesel Heavy-Duty Vehicles
Advanced
Moderate
Uncontrolled
Motorcycles
Non-Catalyst Control
Uncontrolled
N20
0 0176
0^0288
0.0507
0.0322
0.0103
0.0103
0 0249
0^0400
0.0846
0.0418
0.0117
0.0118
0.1729
00870
0^0256
0.0269
0.0100
0.0100
0.0100
0.0200
0.0200
0.0200
0.0300
0.0300
0.0300
0.0042
0.0054
CH4
0.025
0.030
0.040
0.070
0.120
0.135
0.030
0.035
0.070
0.090
0.140
0.135
0.075
0.090
0.125
0.270
0.01
0.01
0.01
0.01
0.01
0.01
0.04
0.05
0.06
0.26
0.13
g C02/km
280
285
298
383
531
506
396
396
498
498
601
579
1,017
1,036
1,320
1,320
237
248
319
330
331
415
987
1,011
1,097
219
266
a Applied to California VMT only
b Methane emission factor assumed based on light-duty trucks oxidation catalyst value
0 The carbon emission factor (g C02/km) was used as a proxy for fuel economy because of the greater number of significant figures compared to the km/L
values presented in (IPCC/UNEP/OECD/IEA 1997).
NA (Not Available)
C-8 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table C-11: Emission Factors for CH4 and N2O Emissions from Non-Highway Mobile
Sources (g/kg fuel)
Vehicle Type/Fuel Type
Marine Bunkers (Ocean-Going Ships)
Residual*
Distillate*
Boats
Residual
Distillate
Gasoline
Locomotives
Residual
Diesel
Coal
Farm Equipment
Gas/Tractor
Other Gas
Diesel/Tractor
Other Diesel
Construction
Gas Construction
Diesel Construction
Other Non-Highway
Gas Snowmobile
Gas Small Utility
Gas HD Utility
Diesel HD Utility
Aircraft
Jet Fuel
Av. Gas
N20
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
NA
0.04
CH4
0.3
0.3
0.23
0.23
0.23
0.25
0.25
0.25
0.45
0.45
0.45
0.45
0.18
0.18
0.18
0.18
0.18
0.18
0.087
2.64
* Methane emission factor value assumed based on value of diesel heavy oil in (IPCC/UNEP/OECD/IEA 1997)
NA (Not Available)
C-9
-------
Table C-12: 1996 Emissions of NOX, CO, and NMVOC from Mobile
Sources (Gg)
Table C-13: 1995 Emissions of NOX, CO, and NMVOC from Mobile
Sources (Gg)
Fuel Type/Vehicle Type NOx
Gasoline Highway 4,752
Passenger Cars 3,075
Light-Duty Trucks 1,370
Heavy-Duty Vehicles 295
Motorcycles 12
Diesel Highway 1,753
Passenger Cars 35
Light-Duty Trucks 9
Heavy-Duty Vehicles 1 ,709
Non-Highway 4,183
Boats and Vessels 244
Locomotives 836
Farm Equipment 1,012
Construction Equipment 1 ,262
Aircraft 151
Other* 678
Total 10,688
CO NMVOCs
46,712 4,709
29,883 2,979
13,377 1,435
3,267 259
185 35
1,318 283
30 12
7 4
1,280 267
15,424 2,201
1,684 460
102 44
901 207
1,066 184
861 161
10,810 1,144
63,455 7,192
* "Other" includes gasoline powered recreational, industrial, lawn and garden, light commercial, logging,
airport service, other equipment; and diesel powered recreational,
construction, airport service.
Note: Totals may not sum due to independent rounding.
industrial, lawn and garden, light
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Boats and Vessels
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
NOx
4,804
3,112
1,378
301
12
1,839
35
9
1,795
4,241
244
898
1,007
1,265
150
678
10,884
CO
47,767
30,391
13,453
3,741
182
1,318
30
7
1,281
15,278
1,674
103
885
1,053
855
10,709
64,363
NMVOCs
4,883
3,071
1,478
297
37
290
12
4
274
2,207
436
45
207
184
161
1,175
7,380
* "Other" includes gasoline powered recreational, industrial, lawn and garden, light commercial, logging,
airport service, other equipment; and diesel powered recreational, industrial, lawn and garden, light
construction, airport service.
Note: Totals may not sum due to independent rounding.
C-10 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table C-14: 1994 Emissions of NOX, CO, and NMVOC from Mobile
Sources (Gg)
Table C-15: 1993 Emissions of NOX, CO, and NMVOC from Mobile
Sources (Gg)
Fuel Type/Vehicle Type NOx
Gasoline Highway 5,063
Passenger Cars 3,230
Light-Duty Trucks 1,503
Heavy-Duty Vehicles 318
Motorcycles 1 1
Diesel Highway 1,897
Passenger Cars 35
Light-Duty Trucks 9
Heavy-Duty Vehicles 1 ,854
Non-Highway 4,485
Boats and Vessels 233
Locomotives 859
Farm Equipment 1,113
Construction Equipment 1 ,443
Aircraft 146
Other* 692
Total 11,445
CO NMVOCs
54,778 5,507
33,850 3,367
15,739 1,731
5,013 375
177 33
1,316 300
29 12
7 4
1,280 284
15,308 2,376
1,663 575
104 45
998 229
1,146 204
830 159
10,566 1,164
71,402 8,184
* "Other" includes gasoline powered recreational, industrial, lawn and garden, light commercial, logging,
airport service, other equipment; and diesel powered recreational,
construction, airport service.
Note: Totals may not sum due to independent rounding.
industrial, lawn and garden, light
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Boats and Vessels
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
NOx
4,913
3,327
1,289
286
11
1,900
36
7
1,857
4,332
230
857
1,090
1,344
142
669
11,145
CO
53,375
35,357
13,786
4,061
172
1,240
30
6
1,205
15,053
1,651
108
1,011
1,061
821
10,400
69,668
NMVOCs
5,248
3,427
1,494
296
31
288
12
3
273
2,341
571
47
226
190
160
1,148
7,878
* "Other" includes gasoline powered recreational, industrial, lawn and garden, light commercial, logging,
airport service, other equipment; and diesel powered recreational, industrial, lawn and garden, light
construction, airport service.
Note: Totals may not sum due to independent rounding.
C-11
-------
Table C-16: 1992 Emissions of NOX, CO, and NMVOC from Mobile
Sources (Gg)
Table C-17: 1991 Emissions of NOX, CO, and NMVOC from Mobile
Sources (Gg)
Fuel Type/Vehicle Type NOx
Gasoline Highway 4,788
Passenger Cars 3,268
Light-Duty Trucks 1,230
Heavy-Duty Vehicles 280
Motorcycles 1 1
Diesel Highway 1,962
Passenger Cars 35
Light-Duty Trucks 7
Heavy-Duty Vehicles 1 ,920
Non-Highway 4,226
Boats and Vessels 239
Locomotives 858
Farm Equipment 1 ,078
Construction Equipment 1 ,256
Aircraft 142
Other* 653
Total 10,975
CO NMVOCs
53,077 5,220
35,554 3,447
13,215 1,440
4,145 303
163 30
1,227 288
28 12
6 3
1,193 274
14,855 2,314
1,639 568
113 49
993 223
999 178
818 162
10,293 1,134
69,158 7,822
* "Other" includes gasoline powered recreational, industrial, lawn and garden, light commercial, logging,
airport service, other equipment; and diesel powered recreational,
construction, airport service.
Note: Totals may not sum due to independent rounding.
industrial, lawn and garden, light
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Boats and Vessels
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
NOx
4,654
3,133
1,215
296
10
2,035
34
7
1,995
4,099
246
842
1,035
1,197
141
638
10,788
CO
55,104
36,369
13,621
4,953
161
1,210
27
5
1,177
14,551
1,624
109
935
961
806
10,116
70,865
NMVOCs
5,607
3,658
1,531
384
33
290
11
3
276
2,271
563
47
213
171
161
1,116
8,167
* "Other" includes gasoline powered recreational, industrial, lawn and garden, light commercial, logging,
airport service, other equipment; and diesel powered recreational, industrial, lawn and garden, light
construction, airport service.
Note: Totals may not sum due to independent rounding.
C-12 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table C-18: 1990 Emissions of NOX, CO, and NMVOC from Mobile
Sources (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
Non-Highway
Boats and Vessels
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
NOx
4,356
2,910
1,140
296
11
2,031
35
6
1,989
4,167
235
843
1,028
1,268
143
650
10,554
CO
51,332
33,746
12,534
4,863
190
1,147
28
5
1,115
14,622
1,600
110
969
1,023
820
10,099
67,101
NMVOCs
5,444
3,524
1,471
392
56
283
11
2
269
2,270
555
48
214
181
163
1,109
7,997
* "Other" includes gasoline powered recreational, industrial, lawn and garden, light commercial, logging,
airport service, other equipment; and diesel powered recreational, industrial, lawn and garden, light
construction, airport service.
Note: Totals may not sum due to independent rounding.
C-13
-------
Annex D
Methodology for Estimating Methane Emissions from Coal Mining
The methodology for estimating methane emissions from coal mining consists of two distinct steps. The first
step addresses emissions from underground mines. For these mines, emissions were estimated on a mine-by-mine
basis and then are summed to determine total emissions. The second step of the analysis involved estimating methane
emissions for surface mines and post-mining activities. In contrast to the methodology for underground mines, which
used mine-specific data, the methodology for estimating emissions from surface mines and post-mining activities
consists of multiplying basin-specific coal production by basin specific emissions factors.
Step 1: Estimate Methane Liberated and Methane Emitted from Underground Mines
Underground mines liberate methane from ventilation systems and from degasification systems. Some mines
recover and use methane liberated from degasification systems, thereby reducing methane emissions to the
atmosphere. Total methane emitted from underground mines equals methane liberated from ventilation systems, plus
methane liberated from degasification systems, minus methane recovered and used.
Step 1.1 Estimate Methane Liberated from Ventilation Systems
All coal mines use ventilation systems for several air quality purposes and to ensure that methane levels remain
within safe concentrations. Many coal mines do not have detectable methane emissions, while others emit several
million cubic feet per day (MMCFD) from their ventilation systems. On a quarterly basis, the U.S. Mine Safety and
Health Administration (MSHA) measures methane emissions levels at underground mines. MSHA maintains a
database of measurement data from all underground mines with detectable levels of methane in their ventilation air.6
Based on the four quarterly measurements, MSHA estimates average daily methane liberated at each of the
underground mines with detectable emissions.
For the years 1990 through 1996, EPA obtained MSHA emissions data for a large but incomplete subset all
mines with detectable emissions. This subset includes mines emitting at least 0.1 MMCFD for some years and at least
0.5 MMCFD for other years, as shown in Table D-l. Well over 90 percent of all ventilation emissions are
concentrated in these subsets. For 1997, EPA obtained the complete MSHA database for all 586 mines with detectable
methane emissions. These mines were assumed to account for 100 percent of methane liberated from underground
mines.
Using this complete 1997 database, the portion of total emissions accounted for by mines emitting more and less
than 0.1 MMCFD or 0.5 MMCFD was estimated, (see Table D-l). These proportions were then applied to the years
1990 through 1996 to account for the less than 10 percent of mines without MSHA data.
Average daily methane emissions were multiplied by 365 days per year to determine annual emissions for each
mine. Total ventilation emissions for these mines were estimated by summing emissions from individual mines.
6 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.
D-1
-------
Table D-1: Mine-Specific Data Used to Estimate Ventilation Emissions
Year Individual Mine Data Used
1990 All Mines Emitting at Least 0.1 MMCFD (Assumed to Account for 97.8% of Total)*
1991 1990 Emissions Factors Used Instead of Mine Specific Data
1992 1990 Emissions Factors Used Instead of Mine Specific Data
1993 All Mines Emitting at Least 0.1 MMCFD (Assumed to Account for 97.8% of Total)*
1994 All Mines Emitting at Least 0.1 MMCFD (Assumed to Account for 97.8% of Total)*
1995 All Mines Emitting at Least 0.5 MMCFD (Assumed to Account for 94.1% of Total)*
1996 All Mines Emitting at Least 0.5 MMCFD (Assumed to Account for 94.1% of Total)*
1997 All Mines with Detectable Emissions (Assumed to Account for 100% of Total)
"Assumption based on complete set of individual mine data collected for 1997.
Step 1.2 Estimate Methane Liberated from Degasification Systems
Over 20 U. S. coal mines use degasification systems in addition to their ventilation systems for methane control.
Coal mines use several different types of degasification systems to remove methane, including vertical wells and
horizontal boreholes recover methane prior to mining of the coal seam. Gob wells and cross-measure boreholes
recover methane from the overburden (i.e., GOB area) after mining of the seam (primarily in longwall mines).
MSHA collects information about the presence and type of degasification systems in some mines, but does not
collect quantitative data on the amount of methane liberated. Thus, the methodology estimated degasification
emissions on a mine-by-mine basis based on other sources of available data. Many of the coal mines employing
degasification systems have provided EPA with information regarding methane liberated from their degasification
systems. For these mines, this reported information was used as the estimate. In other cases in which mines sell
methane recovered from degasification systems to a pipeline, gas sales were used to estimate methane liberated from
degasification systems (see Step 1.3). Finally, for those mines that do not sell methane to a pipeline and have not
provided information to EPA, methane liberated from degasification systems was estimated based on the type of
system employed. For example, for coal mines employing gob wells and horizontal boreholes, the methodology
assumes that degasification emissions account for 40 percent of total methane liberated from the mine.
Step 1.3: Estimate Methane Recovered from Degasification Systems and Used
(Emissions Avoided)
In 1996, all 12 active U.S. coal mines that had developed methane recovery and use projects sold the recovered
methane to a pipeline. One coal mine also used some recovered methane in a thermal dryer in addition to selling gas
to a pipeline. Where available, state agency gas sales data were used to estimate emissions avoided for these projects.
Emissions avoided were attributed to the year in which the coal seam was mined. For example, if a coal mine
recovered and sold methane using a vertical well drilled five years in advance of mining, the emissions avoided
associated with those gas sales were attributed to the year during which the well was mined-through (five years after
the gas was sold). In order to estimate emissions avoided for those coal mines using degasification methods that
recover methane in advance of mining, information was needed regarding the amountof gas recovered and the number
of years in advance of mining that wells were drilled. In most cases, coal mine operators provided EPA with this
information, which was then used to estimate emissions avoided for a particular year. Additionally, several state
agencies made production data available for individual wells. For some mines, this individual well data were used
to assign gas sales from individual wells to the appropriate emissions avoided year.
Step 2: Estimate Methane Emitted from Surface Mines and Post-Mining Activities
Mine-specific data was not available for estimating methane emissions from surface coal mines or for post-
mining activities. For surface mines and post-mining activities, basin-specific coal production was multiplied by a
basin-specific emission factors to determine methane emissions.
D-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Step 2.1: Define the Geographic Resolution of the Analysis and Collect Coal
Production Data
The first step in estimating methane emissions from surface mining and post-mining activities was to define the
geographic resolution of the analysis and to collect coal production data at that level of resolution. The U.S. analysis
was conducted by coal basin as defined in Table D-2.
The Energy Information Agency (EIA) Coal Industry Annual reports state- and county-specific underground
and surface coal production by year. To calculate production by basin, the state level data were grouped into coal
basins using the basin definitions listed in Table D-2. For two states—West Virginia and Kentucky—county-level
production data was used for the basin assignments because coal production occurred from geologically distinct coal
basins within these states. Table D-2 presents coal basin definitions by basin and by state. Table D-3 presents the
coal production data aggregated by basin.
Step 2.2: Estimate Emissions Factors for Each Emissions Type
Emission factors for surface mined coal were developed from the in situ methane content of the surface coal in
each basin. Based on an analysis presented in EPA (1993), the surface mining emission factors used were from 1 to
3 times the average in situ content in the basin. Furthermore, the post-mining emission factors used were assumed
to be 25 to 40 percent of the average in situ content in the basin. Table D-4 presents the average in situ content for
each basin, along with the resulting emission factor estimates.
Step 2.3: Estimate Methane Emitted
The total amount of methane emitted was calculated by multiplying the coal production in each basin by the
appropriate emission factors.
Total annual methane emissions is equal to the sum of underground mine emissions plus surface mine emissions
plus post-mining emissions. Table D-5 and Table D-6 present estimates of methane liberated, methane used, and
methane emissions for 1990 through 1997 (1997 is a preliminary estimate).
D-3
-------
Table D-2: Coal Basin Definitions by Basin and by State
Basin
States
Northern Appalachian Basin
Central Appalachian Basin
Warrior Basin
Illinois Basin
South West and Rockies Basin
North Great Plains Basin
West Interior Basin
Northwest Basin
Maryland, Ohio, Pennsylvania, West VA North
Kentucky East, Tennessee, Virginia, West VA South
Alabama
Illinois, Indiana, Kentucky West
Arizona, California, Colorado, New Mexico, Utah
Montana, North Dakota, Wyoming
Arkansas, Iowa, Kansas, Louisiana, Missouri, Oklahoma, Texas
Alaska, Washington
State
Basin
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Illinois
Indiana
Iowa
Kansas
Kentucky East
Kentucky West
Louisiana
Maryland
Missouri
Montana
New Mexico
North Dakota
Ohio
Oklahoma
Pennsylvania.
Tennessee
Texas
Utah
Virginia
Washington
West Virginia South
West Virginia North
Wyoming
Warrior Basin
Northwest Basin
South West And Rockies Basin
West Interior Basin
South West And Rockies Basin
South West And Rockies Basin
Illinois Basin
Illinois Basin
West Interior Basin
West Interior Basin
Central Appalachian Basin
Illinois Basin
West Interior Basin
Northern Appalachian Basin
West Interior Basin
North Great Plains Basin
South West And Rockies Basin
North Great Plains Basin
Northern Appalachian Basin
West Interior Basin
Northern Appalachian Basin
Central Appalachian Basin
West Interior Basin
South West And Rockies Basin
Central Appalachian Basin
Northwest Basin
Central Appalachian Basin
Northern Appalachian Basin
North Great Plains Basin
D-4 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table D-3: Annual Underground Coal Production (thousand short tons)
Underground Coal Production
Basin
Northern Appalachia
Central Appalachia
Warrior
Illinois
S. West/Rockies
N. Great Plains
West Interior
Northwest
Total
1990
103,865
198,412
17,531
69,167
32,754
1,722
105
0
423,556
1991
103,450
181,873
17,062
69,947
31,568
2,418
26
0
406,344
1992
105,220
177,777
15,944
73,154
31,670
2,511
59
0
406,335
1993
77,032
164,845
15,557
55,967
35,409
2,146
100
0
351,056
1994
100,122
170,893
14,471
69,050
41,681
2,738
147
0
399,102
1995
98,103
166,495
17,605
69,009
42,994
2,018
25
0
396,249
1996
106,729
171,845
18,217
67,046
43,088
2,788
137
0
409,850
Surface Coal Production
Basin
Northern Appalachia
Central Appalachia
Warrior
Illinois
S. West/Rockies
N. Great Plains
West Interior
Northwest
Total
1990
60,761
94,343
11,413
72,000
43,863
249,356
64,310
6,707
602,753
1991
51,124
91,785
10,104
63,483
42,985
259,194
61,889
6,579
587,143
1992
50,512
95,163
9,775
58,814
46,052
258,281
63,562
6,785
588,944
1993
48,641
94,433
9,211
50,535
48,765
275,873
60,574
6,340
594,372
1994
44,960
106,129
8,795
51,868
49,119
308,279
58,791
6,460
634,401
1995
39,372
106,250
7,036
40,376
46,643
331,367
59,116
6,566
636,726
1996
39,788
108,869
6,420
44,754
43,814
343,404
60,912
6,046
654,007
Total Coal Production
Basin
Northern Appalachia
Central Appalachia
Warrior
Illinois
S. West/Rockies
N. Great Plains
West Interior
Northwest
Total
1990
164,626
292,755
28,944
141,167
76,617
251,078
64,415
6,707
1,026,309
1991
154,574
273,658
27,166
133,430
74,553
261,612
61,915
6,579
993,487
1992
155,732
272,940
25,719
131,968
77,722
260,792
63,621
6,785
995,279
1993
125,673
259,278
24,768
106,502
84,174
278,019
60,674
6,340
945,428
1994
145,082
277,022
23,266
120,918
90,800
311,017
58,938
6,460
1,033,503
1995
137,475
272,745
24,641
109,385
89,637
333,385
59,141
6,566
1,032,975
1996
146,517
280,714
24,637
111,800
86,902
346,192
61,049
6,046
1,063,857
Source: EIA (1990-96), Coal Industry Annual. U.S. Department of Energy, Washington, D.C., Table 3.
Note: Totals may not sum due to independent rounding.
Table D-4: Surface and Post-Mining Coal Emission Factors (ft3 per short ton)
Basin
Northern Appalachia
Central Appalachia
Warrior
Illinois
S. West/Rockies
N. Great Plains
West Interior
Northwest
Surface Underground
Average Average
in situ in situ
Content Content
49.3
49.3
49.3
39.0
15.3
3.2
3.2
3.2
49.3
49.3
49.3
39.0
15.3
3.2
3.2
3.2
Surface
Low
49.3
49.3
49.3
39.0
15.3
3.2
3.2
3.2
Mine Factors
Mid High
98.6
98.6
98.6
78.0
30.6
6.4
6.4
6.4
147.9
147.9
147.9
117.0
45.9
9.6
9.6
9.6
Post-Mining Surface
Factors
Low Mid High
12.3
12.3
12.3
9.8
3.8
0.8
0.8
0.8
16.0
16.0
16.0
12.7
5.0
1.0
1.0
1.0
19.7
19.7
19.7
15.6
6.1
1.3
1.3
1.3
Post Mining
Underground
Low Mid High
12.3
12.3
12.3
9.8
3.8
0.8
0.8
0.8
16.0
16.0
16.0
12.7
5.0
1.0
1.0
1.0
19.7
19.7
19.7
15.6
6.1
1.3
1.3
1.3
Source: EPA (1993), Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to Congress, U.S. Environmental Protection Agency,
Air and Radiation, April.
D-5
-------
Table D-5: Underground Coal Mining Methane Emissions (billion cubic feet)
Activity
Ventilation Output
Adjustment Factor for Mine Data3
Ventilation Liberated
Degasification System Liberated
Total Underground Liberated
Recovered & Used
Total
1990
112
97.8%
114
57
171
(15)
156
1991
NA
NA
NA
NA
164
(15)
149
1992
NA
NA
NA
NA
162
(19)
142
1993
95
97.8%
97
49
146
(24)
121
1994
96
97.8%
98
50
149
(29)
119
1995
102
91.4%
111
50
161
(31)
130
1996
90
91.4%
99
51
150
(35)
115
1997b
96
100.0%
96
57
153
(42)
112
3 Refer to Table D-1
b Preliminary estimate.
Note: Totals may not sum due to independent rounding.
Table D-6: Total Coal Mining Methane Emissions (billion cubic feet)
Activity 1990
Underground Mining 156
Surface Mining 25
Post-Mining (Underground) 33
Post-Mining (Surface) 4
Total 218
1991
149
23
31
4
207
1992
142
23
30
4
200
1993
121
23
27
4
175
1994
119
24
30
4
177
1995
130
22
30
4
185
1996
115
23
31
4
172
1997*
112
24
30
4
170
* Preliminary estimate
Note: Totals may not sum due to independent rounding.
D-6 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Annex E
Methodology for Estimating Methane Emissions from Natural Gas
Systems
Step 1: Calculate Emission Estimates for Base Year 1992 Using GRI/EPA Study
The first step in estimating methane emissions from natural gas systems was to develop a detailed base year
estimate of emissions. The study by GRI/EPA (1995) divides the industry into four stages to construct a detailed
emissions inventory for the year 1992. These stages include: field production, processing, transmission and storage
(both underground and liquefied gas storage), and distribution. This study produced emission factors and activity data
for over 100 different emission sources within the natural gas system. Emissions for 1992 were estimated by
multiplying activity levels by emission factors for each system component and then summing by stage. Since
publication, EPA has updated activity data for some of the components in the system. Table E-l displays the 1992
GRI/EPA activity levels and emission factors for venting and flaring from the field production stage, and the current
EPA activity levels and emission factors. The data in Table E-l is a representative sample of data used to calculate
emission from all stages.
Step 2: Collect Aggregate Statistics on Main Driver Variables
As detailed data on each of the over 100 sources were not available for the period 1990 through 1996, activity
levels were estimated using aggregate statistics on key drivers, including: number of producing wells (IPAA 1997),
number of gas plants (AGA 1990, 1991, 1992, 1993, 1994, 1995,1996, 1997), miles of transmission pipeline (AGA,
1990,1991,1992,1993,1994,1995,1996,1997), miles of distribution pipeline (AGA 1990,1991,1992,1993,1994,
1995,1996,1997), miles of distribution services (AGA 1990,1991,1992,1993,1994,1995,1996,1997), and energy
consumption (EIA 1996a). Data on the distribution of gas mains by material type was not available for certain years
from AGA. Forthose years, the average distribution by type was held constant. Table E-2 provides the activity levels
of some of the key drivers in the natural gas analysis.
Step 3: Estimate Emission Factor Changes Over Time
For the period 1990 through 1995, the emission factors were held constant, based on 1992 values. An assumed
improvement in technology and practices was estimated to reduce emission factors by 5 percent by the year 2020.
This assumption, annualized, amounts to a 0.2 percent decline in the 1996 emission factors.
Step 4: Estimate Emissions for Each Source
Emissions were estimated by multiplying the activity levels by emission factors. Table E-3 provides emission
estimates for venting and flaring emissions from the field production stage.
E-1
-------
Table E-1: 1992 Data and Emissions (Mg) for Venting and Flaring from Natural Gas Field Production Stage
Activity
Drilling and Well Completion
Completion Flaring
Normal Operations
Pneumatic Device Vents
Chemical Injection Pumps
Kimray Pumps
Dehydrator Vents
Compressor Exhaust Vented
Gas Engines
Routine Maintenance
Well Workovers
Gas Wells
Well Clean Ups(LP Gas Wells)
Blowdowns
Vessel BD
Pipeline BD
Compressor BD
Compressor Starts
Upsets
Pressure Relief Valves
ESD
Mishaps
GRI/EPA Values
Activity Data
844 compl/yr
249,111 controllers
16,971 active pumps
11, 050,000 MMscf/yr
12,400,000 MMscf/yr
27,460 MMHPhr
9,392 w.o/yr
114,139 LP gas wells
255,996 vessels
340,000 miles (gath)
17,112 compressors
17,112 compressors
529,440 PRV
1,1 15 platforms
340,000 miles
Emission Factor
733 scf/comp
345 scfd/device
248 scfd/pump
368 scf/MMscf
276 scf/MMscf
0.24 scf/HPhr
2,454 scfy/w.o.
49,570 scfy/LP well
78 scfy/vessel
309 scfy/mile
3,774 scfy/comp
8,443 scfy/comp
34.0 scfy/PRV
256,888 scfy/plat
669 scfy/mile
Emissions
11.9
602,291
29,501
78,024
65,608
126,536
443
108,631
383
2,017
1,240
2,774
346
5,499
4,367
EPA Adjusted Values
Activity Data
400 compl/yr
249,111 controllers
16,971 active pumps
7,380,194 MMscf/yr
8,200,21 5 MMscf/yr
27,460 MMHPhr
9,392 w.o/yr
1 1 4,1 39 LP gas wells
242,306 vessels
340,200 miles (gath)
17,1 12 compressors
17,1 12 compressors
529,440 PRV
1 ,372 platforms
340,200 miles
Emission Factor
733 scf/comp
345 scfd/device
248 scfd/pump
992 scf/MMscf
276 scf/MMscf
0.24 scf/HPhr
2,454 scfy/w.o.
49,570 scfy/LP well
78 scfy/vessel
309 scfy/mile
3,774 scfy/comp
8,443 scfy/comp
34.0 scfy/PRV
256,888 scfy/plat
669 scfy/mile
Emissions
5.63
602,291
29,502
140,566
43,387
126,535
443
108,631
363
2,018
1,240
2,774
346
6,767
4,370
E-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table E-2: Activity Factors for Key Drivers
Variable
Transmission Pipelines Length
Wells
GSAM Appalachia Wells a
GSAM N Central Associated Wells a
GSAM N Central Non-Associated Wells a
GSAM Rest of US Wells a
GSAM Rest of US Associated Wells a
Appalch. + N. Central Non-Assoc. + Rest of US
Platforms
Gulf of Mexico Off-shore Platforms
Rest of U.S. (offshore platforms)
N. Central Non-Assoc. + Rest of US Wells
Gas Plants
Number of Gas Plants
Distribution Services
Steel - Unprotected
Steel - Protected
Plastic
Copper
Total
Distribution Mains
Steel - Unprotected
Steel - Protected
Cast Iron
Plastic
Total
Unit
miles
# wells
# wells
# wells
# wells
# wells
# wells
# platforms
# platforms
# platforms
# gas plants
# of services
# of services
# of services
# of services
# of services
miles
miles
miles
miles
miles
1990
280,100
120,162
3,862
3,105
145,100
256,918
268,367
3,798
24
148,205
761
5,500,993
19,916,202
16,269,414
228,240
41,914,849
491,120
91,267
52,644
202,269
837,300
1991
281,600
121,586
3,890
3,684
147,271
262,441
272,541
3,834
24
150,955
734
5,473,625
20,352,983
17,654,006
233,246
43,713,860
492,887
90,813
52,100
221,600
857,400
1992
284,500
123,685
3,852
4,317
152,897
253,587
280,899
3,800
24
157,214
732
5,446,393
20,352,983
17,681,238
233,246
43,713,860
496,839
90,361
51,800
244,300
883,300
1993
269,600
124,708
3,771
4,885
156,568
249,265
286,161
3,731
24
161,453
726
5,419,161
20,512,366
18,231,903
235,073
44,398,503
501,480
89,909
50,086
266,826
908,300
1994
268,300
122,021
3,708
5,813
160,011
248,582
287,845
3,806
23
165,824
725
5,392,065
20,968,447
19,772,041
240,299
46,372,852
497,051
89,460
48,542
284,247
919,300
1995
264,900
123,092
3,694
6,323
164,750
245,338
294,165
3,868
23
171,073
675
5,365,105
21,106,562
20,270,203
241,882
46,983,752
499,488
89,012
48,100
294,400
931,000
1996
257,000
122,700
3,459
7,073
173,928
246,598
303,701
3,846
24
181,001
623
5,388,279
21,302,429
20,970,924
244,127
47,905,759
468,833
88,567
47,100
329,700
934,200
a GSAM is the Gas Systems Analysis Model (GSAM 1997) of the Federal Energy Technology Center of the U.S. Department of Energy. It is a supply, demand and transportation model.
E-3
-------
Table E-3: Emission Estimates for Venting and Flaring from the Field Production Stage (Mg)
Activity 1990 1991 1992 1993 1994 1995 1996
Drilling and Well Completion
Completion Flaring
Normal Operations
Pneumatic Device Vents
Chemical Injection Pumps
Kimray Pumps
Dehydrator Vents
Compressor Exhaust Vented
Gas Engines
Routine Maintenance
Well Workovers
Gas Wells
Well Clean Ups(LP Gas Wells)
Blowdowns
5.4
5.5
5.6
5.7
5.8
5.9
6.1
567,778
36,449
134,247
41,436
578,313
37,323
136,380
42,095
602,291
39,053
140,566
43,387
618,531
40,277
143,211
44,203
635,276
41,668
144,040
44,459
655,386
43,111
147,191
45,432
691,999
45,664
151,565
46,782
119,284 121,498 126,535 129,947 133,465 137,690 145,382
531 540 556 567 570 582 600
101,118 102,725 105,878 107,870 108,494 110,868 114,162
Vessel BD
Pipeline BD
Compressor BD
Compressor Starts
Upsets
Pressure Relief Valves
ESD
Mishaps
256
1,710
1,548
3,462
326
6,764
925
261
1,729
1,573
3,518
332
6,827
936
271
1,772
1,627
3,640
346
6,767
959
278
1,772
1,662
3,718
355
6,646
974
284
1,818
1,687
3,773
365
6,773
984
292
1,852
1,730
3,871
376
6,882
1,003
306
1,908
1,802
4,031
397
6,834
1,033
E-4 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Annex F
Methodology for Estimating Methane Emissions from Petroleum
Systems
The methodology for estimating methane emissions from petroleum systems is being updated. EPA anticipates
that current methodology understates emissions, and that the new methodology will be incorporated into future
inventories.
Step 1: Production Field Operations
The American Petroleum Institute (API) publishes active oil well data in reports such as the API Basic
Petroleum Data Book. To estimate activity data, the percentage of oil wells that were not associated with natural gas
production, averaging approximately 56.4 percent over the period 1990 through 1996, was multiplied by the total
number of wells in the United States. This number was then multiplied by per well emission factors for fugitive
emissions and routine maintenance from Tilkicioglu & Winters (1989). Table F-l displays the activity data, emission
factors, and emissions estimates used.
Step 2: Crude Oil Storage
Methane emissions from storage were calculated as a function of annual U.S. crude stocks less strategic
petroleum stocks for each year, obtained from annual editions of the Petroleum Supply Annual (ElA 1991,1992,1993,
1994, 1995, 1996, 1997). These stocks were multiplied by emission factors from Tilkicioglu & Winters (1989) to
estimate emissions. Table F-2 displays the activity data, emission factors, and emissions estimates used.
Step 3: Refining
Methane emissions from refinery operations were based on U.S. refinery working storage capacity, found in
annual editions of the Petroleum Supply Annual (ElA 1991,1992,1993, 1994,1995,1996, 1997). This capacity was
multiplied by an emission factor from Tilkicioglu & Winters (1989) to estimate emissions. Table F-3 provides the
activity data, emission factors, and emissions estimates used.
Step 4: Tanker Operations
Methane emissions from the transportation of petroleum on marine vessels were estimated using activity data
on crude oil imports, U.S. crude oil production, Alaskan crude oil production, and Alaskan refinery crude oil capacity.
All activity data were taken from annual editions of the Petroleum Supply Annual (EIA 1991,1992,1993,1994,1995,
1996, 1997).
Tilkicioglu & Winters (1989) identified three sources of emissions in the transportation of petroleum. These
are emissions from loading Alaskan crude oil onto tankers, emissions from crude oil transfers to terminals, and ballast
emissions.
Step 4.1: Loading Alaskan Crude Oil onto Tankers
The net amount of crude oil transported by tankers was determined by subtracting Alaskan refinery capacity
from Alaskan crude oil production. This net amount was multiplied by an emission factor from Tilkicioglu & Winters
(1989) to estimate emissions. The activity data and emissions estimates are shown in Table F-4.
Step 4.2: Crude Oil Transfers to Terminals
Methane emissions from crude oil transfers were taken from the total domestic crude oil transferred to terminals.
This amount was assumed to be 10 percent of total domestic crude oil production less Alaskan crude oil production.
F-1
-------
To estimate emissions, this transferred amount was multiplied by an emission factor from Tilkicioglu & Winters
(1989). The activity data and emissions estimates are shown in Table F-5.
Step 4.3: Ballast Emissions
Ballast emissions are emitted from crude oil transported on marine vessels. This amount was calculated from
the sum of Alaskan crude oil on tankers, the amount of crude oil transferred to terminals, and all crude oil imports less
Canadian imports. Ballast volume was assumed to be 17 percent of this sum (Tilkicioglu & Winters 1989). This
amount was then multiplied by an emission factor to estimate emissions. The activity data and emissions estimates
are shown in Table F-6.
Total emissions from tanker operations are shown in Table F-7.
Step 5: Venting and Flaring
Methane emissions from venting and flaring were based on 1990 emissions estimates from EPA (1993) and were
held constant through 1996 due to the lack of data available to assess the change in emissions.
Table F-1: Emissions from Petroleum Production Field Operations
Activity Units 1990 1991 1992 1993 1994 1995 1996
Total Oil Wells
% Not Assoc. w/ Natural Gas
Oil Wells in Analysis
587,762 610,204 594,189 583,879 581,657
55.6% 56.4% 56.7% 56.7% 56.6%
326,982 343,873 336,749 330,843 329,366
574,483 574,419
56.7% 56.5%
325,451 324,362
Emission Factors
Fugitive
Routine Maintenance
kg/well/yr
kg/well/yr
72
0.15
Emissions
Fugitive
Routine Maintenance
mill kg/yr
mill kg/yr
23.5
0.05
24.8
0.05
24.3
0.05
23.9
0.05
23.7
0.05
23.4
0.05
23.4
0.05
Table F-2: Emissions from Petroleum Storage
Activity
Total Crude Stocks
Strategic Petroleum Stocks
Crude Oil Storage
Units
1000barrels/yr
1000barrels/yr
1000barrels/yr
1990
908,387
585,692
322,695
1991
893,102
568,508
324,594
1992
892,864
574,724
318,140
1993
922,465
587,080
335,385
1994
928,915
591,670
337,245
1995
894,968
591,640
303,328
1996
849,669
566,000
283,669
Emission Factors
Breathing
Working
Fugitive
kg CH4/brl/yr
kg CH4/brl/yr
kg CH4/brl/yr
0.002612
0.002912
4.99x1 0'5
Emissions
Breathing
Working
Fugitive
Total Emissions
kg/yr
kg/yr
kg/yr
mill, kg/yr
842,892
939,602
16,118
1.80
847,853
945,131
16,213
1.81
830,994
926,339
15,891
1.77
876,039
976,552
16,752
1.87
880,897
981,968
16,845
1.88
792,305
883,210
15,151
1.69
740,955
825,969
14,169
1.58
Table F-3: Emissions from Petroleum Refining
Activity (Jan 1)
Total Refinery Storage Capacity
Storage Emission Factor
Emissions
Units
1000barrels/yr
Mg CH4/brl/yr
mill, kg/yr
1990
174,490
5.9 x10'5
10.29
1991
171,366
10.10
1992
167,736
9.89
1993
170,823
10.07
1994
164,364
9.69
1995
161,305
9.51
1996
158,435
9.34
Table F-4: Emissions from Petroleum Transportation: Loading Alaskan Crude Oil onto
Tankers (Barrels/day*)
F-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Activity
Alaskan Crude
Alaskan Refinery Crude Capacity
Net Tankered
Conversion Factor (gal oil/ barrel oil)
Emission factor (Ibs/gallon)
Emissions @ Loading AK (Ibs/day)
Methane Content of Gas (%)
Emissions @ Loading AK (mill kg/yr)
1990
1991
1992
1993
1994
1995
1996
1,773,452 1,798,216 1,718,690 1,582,175 1,558,762 1,484,000 1,393,000
229,850 239,540 222,500
1,543,602 1,558,676 1,496,190
42
0.001
256,300 261,000
1,325,875 1,297,762
275,152 283,350
1,208,848 1,109,650
64,831
20.80%
2.23
65,464 62,840 55,687 54,506
2.26
2.17
1.92
50,772
1.75
46,605
1.61
* Unless otherwise noted
Table F-5: Emissions from Petroleum Transportation: Crude Oil Transfers to Terminals
(Barrels/day*)
Activity
US Crude Production
AK Crude Production
US Crude - AK Crude
10% transported to terminals
Conversion Factor (gal oil/ barrel oil)
Emission factor (Ibs/gallon)
Emissions from Transfers (Ibs/day)
Methane Content of Gas (%)
Emissions from Transfers (mill kg/yr)
* Unless otherwise noted
Table F-6: Emissions from
Activity
1990
7,355,307
1,773,452
5,581,855
558,185
42
0.001
23,444
20.80%
0.81
1991
7,416,545
1,798,216
5,618,329
561,833
23,597
0.81
1992
7,190,773
1,718,690
5,472,082
547,208
22,983
0.79
1993
6,846,666
1,582,175
5,264,490
526,449
22,111
0.76
1994
6,661,578
1,558,762
5,102,816
510,282
21,432
0.74
1995
6,560,000
1,484,000
5,076,000
507,600
21,319
0.73
1996
6,465,000
1,393,000
5,072,000
507,200
21,302
0.73
Petroleum Transportation: Ballast Emissions (Barrels/day*)
1990
1991
1992
1993
1994
1995
1996
Crude Imports (less Canadian)
Alaskan Crude (Net Tankered)
10% Crude Prod. Transported to terminals
Conversion Factor (gal oil/ barrel oil)
Emission factor (lbs/1000 gallons)
Crude Oil Unloaded
Ballast Volume
(17% of Crude Unloaded)
Ballast Emissions (Ibs/day)
Methane Content of Gas (%)
Ballast Emissions (mill kg/yr)
5,251,701 5,038,786 5,300,616 5,886,921 6,079,773 6,125,482 6,909,429
1,543,602 1,558,676 1,496,190 1,325,875 1,297,762 1,208,848 1,109,650
558,185 561,833 547,208 526,449 510,282 507,600 507,200
42
1.4
7,353,489 7,159,296 7,344,015 7,739,245 7,887,816 7,841,930 8,526,279
1,250,093 1,217,080 1,248,483 1,315,672 1,340,929 1,333,128 1,449,467
73,505 71,564 73,411 77,361 78,847 78,388 85,229
20.80%
2.53 2.47 2.53 2.67 2.72 2.70 2.94
* Unless otherwise noted
Table F-7: Total Methane Emissions from Petroleum Transportation
Year
1990
1991
1992
1993
1994
1995
1996
Million kg/yr
5.6
5.5
5.5
5.4
5.3
5.2
5.3
F-3
-------
Annex G
Methodology for Estimating Methane Emissions from Enteric
Fermentation
Step 1: Collect Livestock Population Data
All livestock population data, except for horses, was taken from U.S. Department of Agriculture (USDA)
statistical reports. For each animal category, the USDA publishes monthly, annual, and multi-year livestock
population and production estimates. Multi-year reports include revision to earlier published data. Recent reports
were obtained from the USDA Economics and Statistics System website, at ,
while historical data were downloaded from the USDA-National Agricultural Statistics Service (NASS) website at
.
The Food and Agriculture Organization (FAO) publish horse population data. These data were accessed from
the FAOSTAT database at . Table G-l summarizes the published population data by animal
type.
Step 2: Estimate Emission Factors for Dairy Cows
Regional dairy cow emission factors from the 1993 Report to Congress (EPA 1993) were used as the starting
point for the analysis. These emission factors were used to calibrate a model of methane emissions from dairy cows.
The model applies revised regional emission factors that reflect changes in milk production per cow over time.
Increases in milk production per cow, in theory, require increases in feed intake, which lead to higher methane
emissions per cow. Table G-2 presents the emission factors per head by region used for dairy cows and milk
production. The regional definitions are from EPA (1993).
Step 3: Estimate Methane Emissions from Dairy Cattle
Dairy cow emissions for each state were estimated by multiplying the published state populations by the regional
emission factors, as calculated in Step 2. Dairy replacement emissions were estimated by multiplying national
replacement populations by a national emission factor. The USDA reported the number of replacements 12 to 24
months old as "milk heifers." It is assumed that the number of dairy cow replacements 0 to 12 months old was
equivalent to the number 12 to 24 months old replacements.
Step 4: Estimate Methane Emissions from Beef Cattle
Beef cattle methane emissions were estimated by multiplying published cattle populations by emission factors.
Emissions from beef cows and replacements were estimated using state population data and regional emission
developed in EPA (1993), as shown in Table G-3. Emissions from slaughter cattle and bulls were estimated using
national data and emission factors. The emission factors for slaughter animals represent their entire life, from birth
to slaughter. Consequently, the emission factors were multiplied by the national data on total steer and heifer
slaughters rather than live populations of calves, heifers, and steers grownfor slaughter. Slaughterpopulationnumbers
were taken from and USDA datasets. The Weanling and Yearling mix was unchanged from earlier estimates derived
from discussions with industry representatives.
Step 5: Estimate Methane Emissions from Other Livestock
Methane emissions from sheep, goats, swine, and horses were estimated by multiplying published national
population estimates by the national emission factor for each year.
A summary of emissions is provided in Table G-4. Emission factors, national average or regional, are shown
by animal type in Table G-5.
G-1
-------
G-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table G-1: Livestock Population (thousand head)
Animal Type
Dairy
Cows
Replacements 0-1 2
Replacements 12-24
Beef
Cows
Replacements 0-1 2
Replacements 12-24
Slaughter-Weanlings
Slaughter-Yearlings
Bulls
Other
Sheep
Goats
Horses
Hogs
1990
10,007
4,135
4,135
32,677
5,141
5,141
5,199
20,794
2,180
11,356
2,545
5215
54,014
1991
9,883
4,097
4,097
32,960
5,321
5,321
5,160
20,639
2,198
11,174
2,475
5650
56,478
1992
9,714
4,116
4,116
33,453
5,621
5,621
5,150
20,600
2,220
10,797
2,645
5650
58,532
1993
9,679
4,088
4,088
34,132
5,896
5,896
5,198
20,794
2,239
10,201
2,605
5850
57,999
1994
9,514
4,072
4,072
35,325
6,133
6,133
5,408
21,632
2,304
9,742
2,595
5900
60,018
1995
9,494
4,021
4,021
35,628
6,087
6,087
5,612
22,450
2,395
8,886
2,495
6000
59,792
1996
9,409
3,902
3,902
35,414
5,839
5,839
5,580
22,322
2,346
8,454
2,495
6,000
56,716
Table G-2: Dairy Cow Emission Factors and Milk Production Per Cow
Region
Dairy Cow Emission Factors (kg/head)
North Atlantic
South Atlantic
North Central
South Central
West
Milk Production (kg/year)
North Atlantic
South Atlantic
North Central
South Central
West
1990
116.2
127.7
105.0
116.2
130.4
6,574
6,214
6,334
5,696
8,339
1991
118.8
128.7
105.7
116.1
129.4
6,811
6,300
6,413
5,687
8,255
1992
121.3
132.3
107.8
117.9
132.7
7,090
6,622
6,640
5,849
8,573
1993
121.0
132.2
107.6
119.2
132.3
7,055
6,608
6,627
5,971
8,530
1994
122.3
134.5
109.8
121.1
135.6
7,185
6,813
6,862
6,148
8,874
1995
124.7
134.4
111.2
122.2
134.8
7,424
6,792
6,987
6,248
8,789
1996
124.8
132.9
110.0
120.9
137.3
7,440
6,673
6,881
6,128
9,047
Table G-3: Emission factors Beef Cows and Replacements (kg/head/yr)
Region
Replacements (0-12) Replacements (12-24) Mature Cows
North Atlantic
South Atlantic
North Central
South Central
West
19.2
22.7
20.4
23.6
22.7
63.8
67.5
60.8
67.7
64.8
61.5
70.0
59.5
70.9
69.1
G-3
-------
Table G-4: Emissions from Livestock Enteric Fermentation (Tg)
Animal Type
Dairy
Cows
Replacements 0-1 2
Replacements 12-24
Beef
Cows
Replacements 0-1 2
Replacements 12-24
Slaughter-Weanlings
Slaughter-Yearlings
Bulls
Other
Sheep
Goats
Horses
Hogs
Total
Table G-5: Enteric
Animal Type
Dairy
Cows
Replacements 0-1 2
Replacements 12-24
Beef
Cows
Replacements 0-1 2
Replacements 12-24
Slaughter-Weanlings
Slaughter-Yearlings
Bulls
Other
Sheep
Goats
Horses
Hogs
1990 1991
1.47
1.15
0.08
0.24
3.95
2.18
0.11
0.33
0.12
0.98
0.22
0.28
0.09
0.01
0.09
0.08
5.70
1.46
1.14
0.08
0.24
3.98
2.20
0.12
0.35
0.12
0.98
0.22
0.29
0.09
0.01
0.10
0.08
5.73
1992
1.47
1.15
0.08
0.24
4.04
2.23
0.13
0.37
0.12
0.97
0.22
0.29
0.09
0.01
0.10
0.09
5.80
1993
1.47
1.15
0.08
0.24
4.12
2.28
0.13
0.38
0.12
0.98
0.22
0.29
0.08
0.01
0.11
0.09
5.88
1994
1.47
1.15
0.08
0.24
4.27
2.36
0.14
0.40
0.12
1.02
0.23
0.29
0.08
0.01
0.11
0.09
6.03
1995
1.47
1.16
0.08
0.24
4.34
2.38
0.14
0.40
0.13
1.06
0.24
0.28
0.07
0.01
0.11
0.09
6.10
1996
1.46
1.15
0.08
0.23
4.29
2.36
0.13
0.38
0.13
1.06
0.23
0.27
0.07
0.01
0.11
0.09
6.02
Fermentation Emission Factors
kg/head/year
regional
19.6
58.8
regional
regional
regional
23.1
47.3
100.0
8.0
5.0
18.0
1.5
G-4 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Annex H
Methodology for Estimating Methane Emissions from Manure
Management
Step 1: Collect Livestock Population Data
All livestock population data, except for horses, were taken from U.S. Department of Agriculture (USDA)
statistical reports. For each animal category, the USDA publishes monthly, annual, and multi-year livestock
population and production estimates. Multi-year reports include revisions to earlier published data. Recent reports
were obtained from the USDA Economics and Statistics System website, at ,
while historical data were downloaded from the USDA National Agricultural Statistics Service (NASS) website at
.
Dairy cow and swine population data by farm size for each state, used in Step 2, were found in the 1992 Census
of Agriculture published by the U.S. Department of Commerce (DOC). This census is conducted every five years.
Data from the census were obtained from the USDA NASS website at .
The Food and Agriculture Organization (FAO) publishes horse population data. These data weree accessed from
the FAOSTAT database at . Table H-l summarizes the published population data by animal
type.
Step 2: Estimate State Methane Conversion Factors for Dairy Cows and Swine
Data from EPA (1993) were used for assessing dairy and swine manure management practices by farm size.
Based on this assessment, an average methane conversion factor (MCF) was assigned to each farm size category for
dairy and swine farms, indicating the portion of the methane producing potential realized. Because larger farms tend
to use liquid manure management systems, which produce more methane, the MCFs applied to them were higher for
smaller farm sizes.
Using the dairy cow and swine populations by farm size in the DOC Census of Agriculture for each state,
weighted average dairy and swine MCFs were calculated for each state. The MCF value for each state reflected the
distribution of animals among farm sizes within the state. Table H-2 provides estimated MCF values.
Step 3: Estimate Methane Emissions from Swine
For each state, the total swine population was multiplied by volatile solids (VS) production rates to determine
total VS production. Estimated state level emissions were calculated as the product of total VS production multiplied
by the maximum methane production potential for swine manure (B0), and the state MCF. Total U.S. emissions are
the sum of the state level emissions. The VS production rate and maximum methane production potential are shown
in Table H-3.
Step 4: Estimate Methane Emissions from Dairy Cattle
Methane emissions from dairy cow manure were estimated using the same method as emissions from swine
(Step 3), but with an added analysis to estimate changes in manure production associated with changes in feed intake,
or dry matter intake (DMi). It is assumed that manure and VS production will change linearly with changes in dry
matter intake (DMi).
Changes in DMi were calculated reflecting changes in feed intake associated with changes in milk production
per cow per year. To estimate the changes in feed intake, a simplified emission factor model was used for dairy cow
enteric fermentation emissions (see Annex G). This model estimates the change in DMi over time relative to 1990,
which was used to calculate VS production by dairy cows by state, as summarized in the following equation: (Dairy
cow population) x (VS produced per cow) x (DMi scaling factor). Methane emissions were then calculated as follows:
H-1
-------
(VS produced) x (Maximum methane production potential for dairy cow manure) x (State-specific MCF). Total
emissions were finally calculated as the sum of the state level emissions. The 1990 VS production rate and maximum
methane production potential are shown in Table H-3.
Step 5: Estimate Methane Emissions for Other Animals
The 1990 methane emissions for the other animal types were estimated using the detailed method described
above for dairy cows and swine (EPA 1993). This process was not repeated for subsequent years for these other
animal types. Instead, national populations of each of the animal types were used to scale the 1990 emissions
estimates to the period 1991 through 1996.
Emission estimates are summarized in Table H-4.
Table H-1: Livestock Population (1000 head)
Dairy Cattle
Dairy Cows
Swine
Beef Cattle
Feedlot Heifers
Feedlot Cow/Other
NOF Calves
NOF Heifers
NOF Cows
Sheep
Rams/Weth>1yr
Ewes<1yr
Sheep on Feed
Goats
Hens>1yr
Pullets laying
PulletsOmo
Chickens
Other (Lost)
Other (Sold)
Horses
1990
10,007
4,135
86,065
7,252
88
2,180
8,740
7,554
11,356
7,961
1,491
381
2,545
1,703,037
153,916
34,222
6,546
1,172,830
41,672
128,384
1991
13,980
4,097
56,478
7,927
4,144
2,198
23,854
7,356
32,860
7,799
361
373
1,177
1,767,513
117,178
34,272
42,344
1,227,430
7,278
129,505
5,650
13,830
9,714
58,532
88,546
3,884
92
24,118
9,261
33,359
10,797
350
1,432
1,093
2,645
121,103
163,397
45,160
7,113
7,025
41,538
5,850
1993
9,679
4,088
90,317
7,838
95
2,239
9,727
8,081
10,201
7,140
1,349
348
2,605
1,895,851
158,938
33,833
7,240
1,338,862
39,606
130,750
1994
13,686
4,072
60,018
8,063
4,088
2,304
24,692
8,108
35,227
6,775
314
332
1,044
1,971,404
134,876
32,808
44,875
1,403,508
12,744
131,375
6,000
13,514
9,493
59,792
94,364
3,934
97
25,184
10,790
35,531
8,886
282
1,167
957
2,495
133,767
164,526
45,494
7,641
8,152
40,917
6,000
1996
9,408
3,902
93,683
7,822
96
2,346
10,800
8,594
8,454
5,875
1,107
282
2,495
2,091,364
165,304
31,316
7,243
1,519,640
39,588
137,595
H-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table H-2: Dairy Cow and Swine Methane Conversion Factors
State Dairy Cow Swine
AK 0.35
AL 0.23
AR 0.45
AZ 0.09
CA 0.44
CO 0.31
CT 0.19
DE 0.21
FL 0.41
GA 0.27
HI 0.40
IA 0.04
ID 0.23
IL 0.07
IN 0.06
KS 0.09
KY 0.06
LA 0.19
MA 0.13
MD 0.15
ME 0.10
Ml 0.12
MN 0.04
MO 0.07
MS 0.17
Table H-3: Dairy Cow
Description
Typical Animal Mass (kg)
kg VS/day per 1000 kg mass
Maximum methane generation
m3 methane/kg VS
0.35
0.28
0.59
0.68
0.44
0.46
0.01
0.29
0.23
0.35
0.40
0.38
0.27
0.42
0.43
0.33
0.30
0.30
0.40
0.42
0.01
0.42
0.38
0.33
0.35
and Swine
potential (B0)
State Dairy Cow Swine
MT
NC
ND
NE
NH
NJ
NM
NV
NY
OH
OK
OR
PA
Rl
SC
SD
TN
TX
UT
VA
VT
WA
Wl
VW
WY
Constants
Dairy Cow
640
10
0.24
0.16
0.20
0.05
0.08
0.12
0.13
0.42
0.36
0.11
0.07
0.13
0.25
0.06
0.07
0.29
0.06
0.14
0.31
0.21
0.17
0.11
0.29
0.05
0.11
0.12
Swine
150
8.5
0.47
0.39
0.65
0.22
0.34
0.36
0.26
0.47
0.50
0.22
0.30
0.31
0.35
0.35
0.59
0.40
0.26
0.28
0.30
0.34
0.34
0.09
0.29
0.27
0.11
0.20
Source
ASAE 1995
ASAE 1995
EPA 1992
H-3
-------
Animal Type
Dairy Cattle
Dairy Cows
Dairy Heifers
Swine
Beef Cattle
Feedlot Steers
Feedlot Heifers
Feedlot Cow/Other
NOF Bulls
NOF Calves
NOF Heifers
NOF Steers
NOF Cows
Sheep
Ewes > 1 yr
Rams/Weth > 1 yr
Ewes < 1 yr
Rams/Weth < 1 yr
Sheep on Feed
Goats
Poultry
Hens > 1 yr
Pullets laying
Pullets > 3 mo
Pullets < 3 mo
Chickens
Broilers
Other (Lost)
Other (Sold)
Turkeys
Horses
1990
0.75
0.59
0.16
1.44
0.20
0.03
0.02
0.00
0.01
0.02
0.02
0.01
0.10
0.004
0.003
0.000
0.000
0.000
0.000
0.001
0.27
0.05
0.06
0.01
0.01
0.00
0.10
0.00
0.01
0.03
0.03
1992 1993
0.77
0.61
0.16
1.51
0.21
0.03
0.02
0.00
0.01
0.02
0.02
0.02
0.10
0.003
0.003
0.000
0.000
0.000
0.000
0.001
0.28
0.06
0.06
0.01
0.01
0.00
0.11
0.00
0.01
0.03
0.03
1995
0.79
0.63
0.16
1.60
0.22
0.03
0.02
0.00
0.01
0.02
0.02
0.02
0.11
0.003
0.002
0.000
0.000
0.000
0.000
0.001
0.30
0.06
0.06
0.01
0.01
0.00
0.12
0.00
0.01
0.03
0.03
H-4 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Annex I
Methodology for Estimating Methane Emissions from Landfills
Landfill methane is produced from a complex process of waste decomposition and subsequent fermentation
under anaerobic conditions. The total amount of methane produced in a landfill from a given amount of waste and
the rate at which it is produced depends upon the characteristics of the waste, the climate, and operating practices at
the landfill. To estimate the amount of methane produced in a landfill in given year the following information is
needed: quantity of waste in the landfill, the waste characteristics, the residence time of the waste in the landfill, and
landfill management practices.
The amount of methane emitted from a landfill is less than the amount of methane produced in a landfill. If no
measures are taken to extract the methane, a portion of the methane will oxidize as it travels through the top layer of
the landfill cover. The portion of the methane that oxidizes turns primarily to carbon dioxide (CO2). If the methane
is extracted and combusted (e.g., flared or used for energy), then that portion of the methane produced in the landfill
will not be emitted as methane, but again would be converted to CO2. In general, the CO2 emitted is of biogenic origin
and primarily results from the decomposition—either aerobic or anaerobic—of organic matter such as food or yard
wastes.7
To take into account the inter-related processes of methane production in the landfill and methane emission, this
analysis relied on a simulation of the population of landfills and waste disposal. A starting population of landfills was
initialized with characteristics from the latest survey of municipal solid waste (MSW) landfills (EPA 1988). Using
actual national waste disposal data, waste was simulated to be placed in these landfills each year from 1990 to 1996.
If landfills reach their design capacity, they were simulated to have closed. New landfills were simulated to open only
if annual disposal capacity was less than total waste disposal. Of note is that closed landfills continue to produce and
emit methane for many years. This analysis tracks these closed landfills throughout the analysis period, and includes
their estimated methane production and emissions.
Using this approach, the age of the waste in each landfill was tracked explicitly. This tracking allowed the
annual methane production in each landfill to be estimated. Methane produced in industrial landfills was also
estimated. It was assumed to be 7 percent of the total methane produced in MSW landfills. Finally, methane
recovered and combusted and methane oxidized were subtracted to estimate final methane emissions.
Using this approach, landfill population and waste disposal characteristics were simulated over time explicitly,
thereby allowing the time-dependent nature of methane production to be modeled. However, the characteristics used
to initialize the landfill population in the model were relatively old and may not represent the current set of operating
landfills adequately. There is also uncertainty in the methane production equation developed in EPA (1993), as well
as in the estimate of methane oxidation (10 percent).
Step 1: Estimate Municipal Solid Waste in Place Contributing to Methane Emissions
The landfill population model was initialized to define the population of landfills at the beginning of 1990.
Waste was simulated to be placed into these landfills for the years 1990 through 1996 using data on the total waste
landfilled from Biocycle (1997). The annual acceptance rates of the landfills were used to apportion the total waste
by landfill. More waste was preferentially disposed in "Large" landfills (see Table 1-3), reflecting the trend toward
fewer and more centralized disposal facilities. The model updates the landfill characteristics each year, calculating
the total waste in place and the full time profile of waste disposal. This time profile was used to estimate the portion
of the waste that contributes to methane emissions. Table 1-1 shows the amount of waste landfilled each year and the
total estimated waste in place contributing to methane emissions.
7 Emissions and sinks of biogenic carbon are accounted for under the Land-Use Change and Forestry sector.
1-1
-------
Step 2: Estimate Landfill Methane Production
Emissions for each landfill were estimated by applying the emissions model (EPA 1993) to the landfill waste
in place contributing to methane production. Total emission were then calculated as the sum of emissions from all
landfills.
Step 3: Estimate Industrial Landfill Methane Production
Industrial landfills receive waste from factories, processing plants, and other manufacturing activities. Because
there were no data available on methane generation at industrial landfills, the approach used was to assume that
industrial methane production equaled about 7 percent of MSW landfill methane production (EPA 1993), as shown
below in Table 1-2.
Step 4: Estimate Methane Recovery
To estimate landfill gas (LFG) recovered per year, data on current and planned LFG recovery projects in the
United States were obtained from Governmental Advisory Associates (GAA 1994). The GAA report, considered to
be the most comprehensive source of information on gas recovery in the United States, has estimates for gas recovery
in 1990 and 1992. Their data set showed that 1.20 and 1.44 teragrams (Tg) of methane were recovered nationally by
municipal solid waste landfills in 1990 and 1992, respectively. In addition, a number of landfills were believed to
recover and flare methane without energy recovery and were not included in the GAA database. To account for the
amount of methane flared without energy recovery, the estimate of gas recovered was increased by 25 percent (EPA
1993). Therefore, net methane recovery from landfills was assumed to equal 1.50 Tg in 1990, and 1.80 Tg in 1992.
The 1990 estimate of methane recovered was used for 1991 and the 1992 estimate was used for the period 1992 to
1996. EPA is currently reviewing more detailed information on LFG recovery projects and expects that the total
recovery figure could be significantly higher.
Step 5: Estimate Methane Oxidation
As discussed above, a portion of the methane escaping from a landfill through its cover oxidizes in the top layer
of the soil. The amount of oxidation that occurs is uncertain and depends upon the characteristics of the soil and the
environment. For purposes of this analysis, it was assumed that 10 percent of the methane produced was oxidized in
the soil.
Step 6: Estimate Total Methane Emissions
Total methane emissions were calculated by adding emissions from MSW and industrial waste, and subtracting
methane recovered and oxidized, as shown in Table 1-2.
Table 1-1: Municipal Solid Waste (MSW) Contributing to Methane Emissions (Tg)
Description
Total MSW Generated3
Percent of MSW Landfilled3
Total MSW Landfilled
MSW Contributing to Emissions"
1990
264
71%
189
4,926
1991
255
76%
194
5,027
1992
265
72%
190
5,162
1993
278
71%
197
5,292
1994
293
67%
196
5,428
1995
296
63%
187
5,559
1996
297
62%
184
5,676
3 Source: Biocycle (1997). The data, originally reported in short tons, are converted to metric tons.
b The EPA emissions model (EPA 1993) defines all waste younger than 30 years as contributing to methane emissions.
I-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table 1-2: Methane Emissions from Landfills (Tg)
Activity
MSW Generation
Large Landfills
Medium Landfills
Small Landfills
Industrial Generation
Potential Emissions
Recovery
Oxidation
Net Emissions
1990
11.6
4.53
5.79
1.27
0.73
12.3
(1.50)
(1.09)
9.82
1991
11.8
4.62
5.91
1.30
0.75
12.6
(1.50)
(1.12)
10.0
1992
12.2
4.76
6.07
1.33
0.77
12.9
(1.80)
(1.12)
10.1
1993
12.5
4.91
6.23
1.36
0.79
13.3
(1.80)
(1.16)
10.4
1994
12.8
5.11
6.36
1.39
0.81
13.7
(1.80)
(1.19)
10.8
1995
13.2
5.29
6.53
1.41
0.83
14.1
(1.80)
(1.23)
11.1
1996
13.5
5.45
6.62
1.42
0.85
14.3
(1.80)
(1.26)
11.4
Note: Totals may not sum due to independent rounding.
Table I-3: Municipal Solid Waste Landfill Size Definitions (Tg)
Description Waste in Place
Small Landfills < 0.4
Medium Landfills 0.4 - 2.0
Large Landfills >2.0
I-3
-------
Annex J
Global Warming Potentials
Table J-1: Global Warming Potentials and Atmospheric Lifetimes (years)
Gas
Carbon dioxide (C02)
Methane (CH4)b
Nitrous oxide (N20)
HFC-23
HFC-125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
CF4
C2F6
C4F10
C6F14
SFfi
Atmospheric Lifetime
50-200
12±3
120
264
32.6
14.6
48.3
1.5
36.5
209
17.1
50,000
10,000
2,600
3,200
3,200
GWPa
1
21
310
11,700
2,800
1,300
3,800
140
2,900
6,300
1,300
6,500
9,200
7,000
7,400
23,900
Source: (IPCC 1996)
° 100 year time horizon
b The methane GWP includes the direct effects and those indirect effects due to the
production of tropospheric ozone and stratospheric water vapor. The indirect effect due to
the production of C02 is not included.
J-1
-------
Annex K
Ozone Depleting Substance Emissions
Ozone is present in both the stratosphere8, where it shields the Earth from harmful levels of ultraviolet radiation,
and at lower concentrations in the troposphere9, where it is the main component of anthropogenic photochemical
"smog". Chlorofluorocarbons (CFCs) and other compounds that contain chlorine or bromine have been found to
destroy ozone in the stratosphere, and are commonly referred to as ozone-depleting substances (ODSs). If left
unchecked, ozone depletion could result in a dangerous increase of ultraviolet radiation reaching the earth's surface.
In 1987, nations around the world signed the Montreal Protocol on Substances that Deplete the Ozone Layer. This
landmark agreement created an international framework for limiting, and ultimately eliminating, the use and emission
of most ozone depleting substances, which are used in a variety of industrial applications, including refrigeration and
air conditioning, foam blowing, fire extinguishing, aerosol propellants, sterilization, and solvent cleaning.
In the United States, the Clean Air Act Amendments of 1990 provide the legal instrument for implementation
of the Montreal Protocol controls. The Clean Air Act classifies ozone depleting substances as either Class I or Class
II, depending upon the ozone depletion potential (ODP) of the compound.10 The production of CFCs, halons, carbon
tetrachloride, and methyl chloroform, all Class I substances, has already ended in the United States. However, because
stocks of these chemicals remain available and in use, they will continue to be emitted for many years from
applications such as refrigeration and air conditioning equipment, fire extinguishing systems, and metered dose
inhalers. As a result, emissions of Class I compounds will continue, in ever decreasing amounts, into the early part
of the next century. Class II substances, which are comprised of hydrochlorofluorocarbons (HCFCs), are being
phased-out at a later date because of their lower ozone depletion potentials. These compounds are serving as interim
replacements for Class I compounds in many industrial applications. The use and emissions of HCFCs in the United
States is anticipated to increase over the next several years. Under current controls, the production of all HCFCs in
the United States will end by the year 2030.
In addition to contributing to ozone depletion, CFCs, halons, carbon tetrachloride, methyl chloroform, and
HCFCs are also significant greenhouse gases. The total impact of ozone depleting substances on global warming is
not clear, however, because ozone is also a greenhouse gas. The depletion of ozone in the stratosphere by ODSs has
an indirect negative radiative forcing, while most ODSs have a positive direct radiative forcing effect. The IPCC has
prepared both direct GWPs and net (i.e., combined direct and indirect effects) GWP ranges for some of the most
common ozone depleting substances (IPCC 1996). Direct GWPs account for the direct global warming impact of the
emitted gas. Net GWP ranges account for both the direct impact of the emitted gas and the indirect effects resulting
from the destruction of ozone.
Although the IPCC emission inventory guidelines do not include reporting emissions of ozone depleting
substances, the United States believes that no inventory is complete without the inclusion of these emissions.
Emission estimates for several ozone depleting substances are provided in Table K-l.
8 The stratosphere is the layer from the top of the troposphere up to about 50 kilometers. Approximately 90 percent of
atmospheric ozone lies within the stratosphere. The greatest concentration of ozone occurs in the middle of the stratosphere,
in a region commonly called the ozone-layer.
9 The troposphere is the layer from the ground up to about 11 kilometers near the poles and 16 kilometers in equatorial
regions (i.e., the lowest layer of the atmosphere, where humans live). It contains roughly 80 percent of the mass of all gases
in the atmosphere and is the site for weather processes including most of the water vapor and clouds.
10 Substances with an ozone depletion potential of 0.2 or greater are classified as Class I. All other substances that may
deplete stratospheric ozone but which do not have an ODP of 0.2 or greater, are classified as Class II.
K-1
-------
Table K-1: Emissions of Ozone Depleting Substances (Mg)
Compound
Class I
CFC-11
CFC-12
CFC-11 3
CFC-114
CFC-11 5
Carbon Tetrachloride
Methyl Chloroform
Halon-1211
Halon-1301
Class II
HCFC-22
HCFC-123
HCFC-124
HCFC-141b
HCFC-142b
HCFC-225ca/cb
1990
53,500
112,600
26,350
4,700
4,200
32,300
158,300
1,000
1,800
79,789
+
+
+
+
+
1991
48,300
103,500
20,550
3,600
4,000
31,000
154,700
1,100
1,800
79,540
+
+
+
+
+
1992
45,100
80,500
17,100
3,000
3,800
21,700
108,300
1,000
1,700
79,545
285
429
+
3,526
+
1993
45,400
79,300
17,100
3,000
3,600
18,600
92,850
1,100
1,700
71,224
570
2,575
1,909
9,055
+
1994
36,600
57,600
8,550
1,600
3,300
15,500
77,350
1,000
1,400
71,386
844
4,768
6,529
14,879
+
1995
36,200
51,800
8,550
1,600
3,000
4,700
46,400
1,100
1,400
74,229
1,094
5,195
11,608
21,058
565
1996
26,600
35,500
+
300
3,200
+
+
1,100
1,400
77,472
1,335
5,558
14,270
27,543
579
Source: EPA estimates
+ Does not exceed 10 Mg
Methodology and Data Sources
Emissions of ozone depleting substances were estimated using two simulation models: the Atmospheric and
Health Effects Framework (AHEF) and EPA's Vintaging Model.
The Atmospheric and Health Effects Framework model contains estimates of U. S. domestic use of each of the
ozone depleting substances. These estimates were based upon data that industry reports to EPA and other published
material. The annual consumption of each compound was divided into various end-uses based upon historical trends
and research into specific industrial applications. These end-uses include refrigerants, foam blowing agents, solvents,
aerosol propellants, sterilants, and fire extinguishing agents.
With the exception of aerosols, solvents, and certain foam blowing agents, emissions of ozone depleting
substances are not instantaneous, but instead occur gradually over time (i.e., emissions in a given year are the result
of both ODS use in that year and use in previous years). Each end-use has a certain release profile, which gives the
percentage of the compound that is released to the atmosphere each year until all releases have occurred. In
refrigeration equipment, for example, the initial charge is released slowly over the lifetime of the equipment, which
could be 20 or more years. In addition, not all of the refrigerant is ultimately emitted—some will be recovered when
the equipment is retired from operation.
The AHEF model was used to estimate emissions of ODSs that were in use prior to the controls implemented
under the Montreal Protocol. This included CFCs, halons, carbon tetrachloride, methyl chloroform, and HCFC-22.
CertainHCFCs, such as HCFC-123, HCFC-124,HCFC-141b, HCFC-142b, HCFC-225caandHCFC-225cb, have also
entered the market as interim substitutes for ODSs. Emissions estimates for these compounds were taken from EPA's
Vintaging Model.
K-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
The Vintaging Model was used to estimate the use and emissions of various ODS substitutes, including HCFCs.
The name refers to the fact that the model tracks the use and emissions of various compounds by the annual "vintages"
of new equipment that enter service in each end-use. The Vintaging Model is a "bottom-up" model. Information was
collected regarding the sales of equipment that use ODS substitutes and the amount of the chemical required by each
unit of equipment. Emissions for each end-use were estimated by applying annual leak rates and release profiles, as
in the AHEF. By aggregating the data for more than 40 different end-uses, the model produces estimates of annual
use and emissions of each compound.
Uncertainties
Uncertainties exist with regard to the levels of chemical production, equipment sales, equipment characteristics,
and end-use emissions profiles that are used by these models.
K-3
-------
Annex L
Sulfur Dioxide Emissions
Sulfur dioxide (SO2) emitted into the atmosphere through natural and anthropogenic processes affects the Earth's
radiative budget through photochemical transformation into sulfate aerosols that can(l) scatter sunlight back to space,
thereby reducing the radiation reaching the Earth's surface; (2) affect cloud formation; and (3) affect atmospheric
chemical composition (e.g., stratospheric ozone, by providing surfaces for heterogeneous chemical reactions). The
overall effect of SO2 derived aerosols on radiative forcing is believed to be negative (IPCC 1996). However, because
SO2 is short-lived and unevenly distributed through the atmosphere, its radiative forcing impacts are highly uncertain.
Sulfur dioxide emissions have been provided below in Table L-l.
The major source of SO2 emissions in the United States was the burning of sulfur containing fuels, mainly coal.
Metal smelting and other industrial processes also released significant quantities of SO2. As a result, the largest
contributors to overall U.S. emissions of SO2 were electric utilities, accounting for 66 percent in 1996 (see Table L-2).
Coal combustion accounted for approximately 96 percent of SO2 emissions from electric utilities in the same year.
The second largest source was industrial fuel combustion, which produced 18 percent of 1996 SO2 emissions. Overall,
sulfur dioxide emissions in the United States decreased by 19percentfrom 1990 to 1996. Eighty-two percent of this
decline came from reductions from electric utilities, primarily due to increased consumption of low sulfur coal from
surface mines in western states.
Sulfur dioxide is important for reasons other than its effect on radiative forcing. It is a major contributor to the
formation of urban smog and acid rain. As a contributor to urban smog, high concentrations of SO2 can cause
significant increases in acute and chronic respiratory diseases. In addition, once SO2 is emitted, it is chemically
transformed in the atmosphere and returns to earth as the primary contributor to acid deposition, or acid rain. Acid
rain has been found to accelerate the decay of building materials and paints, as well as cause the acidification of lakes
and streams and damage trees. As a result of these harmful effects, the United States has regulated the emissions of
SO2 under the Clean Air Act. The EPA has also developed a strategy to control these emissions via four programs:
(1) the National Ambient Air Quality Standards program,11 (2) New Source Performance Standards,12 (3) the New
Source Review/Prevention of Significant Deterioration Program,13 and (4) the sulfur dioxide allowance program.14
11 [42 U.S.C § 7409, CAA § 109]
12[42U.S.C § 7411, CAA § 111]
13 [42 U.S.C § 7473, CAA § 163]
14 [42 U.S.C § 7651, CAA § 401]
L-1
-------
Table L-1: Emissions of SO2 (Gg)
Sector/Source
Energy
Stationary Sources
Mobile Sources
Oil and Gas Activities
Industrial Processes
Chemical Manufacturing
Metals Processing
Storage and Transport
Other Industrial Processes
Miscellaneous*
Solvent Use
Degreasing
Graphic Arts
Dry Cleaning
Surface Coating
Other Industrial
Non-industrial
Agriculture
Agricultural Burning
Waste
Waste Combustion
Landfills
Wastewater Treatment
Miscellaneous Waste
Total
1990
20,034
18,407
1,237
390
1,306
269
658
6
362
11
+
+
+
NA
+
+
NA
NA
NA
38
38
+
+
+
21,379
1991
19,524
17,959
1,222
343
1,187
254
555
9
360
10
+
+
+
NA
+
+
NA
NA
NA
40
39
+
+
1
20,752
1992
19,327
17,684
1,267
377
1,186
252
558
8
360
9
+
+
+
+
+
+
NA
NA
NA
40
39
+
+
1
20,554
1993
18,973
17,459
1,166
347
1,159
244
547
4
355
8
1
+
+
NA
+
+
NA
NA
NA
65
56
+
+
8
20,196
1994
18,444
17,134
965
344
1,135
249
510
1
361
13
1
+
+
+
+
+
NA
NA
NA
54
48
+
+
5
19,633
1995
16,006
14,724
947
334
1,116
260
481
2
365
8
1
+
+
+
+
+
NA
NA
NA
43
42
+
1
+
17,165
1996
16,174
15,228
612
334
1,122
260
481
2
371
8
1
+
+
+
+
+
NA
NA
NA
43
42
+
1
+
17,339
Source: (EPA 1997)
* Miscellaneous includes other combustion and fugitive dust categories
+ Does not exceed 0.5 Gg
NA (Not Available)
Note: Totals may not sum due to independent rounding.
Table L-2: Emissions of SO2 from Electric Utilities (Gg)
Fuel Type 1990 1991 1992 1993 1994 1995 1996~
Coal
Oil
Gas
Misc. Internal Combustion
13,807 13,687 13,448 13,179 12,985 10,526 10,990
580 591 495 555 474 375 373
1 1 1 1 1 8 19
45 41 42 45 48 50 52
Total
14,432 14,320 13,986 13,779 13,507 10,959 11,434
Source: (EPA 1997)
Note: Totals may not sum due to independent rounding.
L-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Annex M
Complete List of Sources
Sector/Source Gas(es)
Energy
Carbon Dioxide Emissions from Fossil Fuel Combustion C02
Stationary Source Fossil Fuel Combustion (excluding C02) CH4, N20, CO, NOX, NMVOC
Mobile Source Fossil Fuel Combustion (excluding C02) CH4, N20, CO, NOX, NMVOC
Coal Mining CH4
Natural Gas Systems CH4
Petroleum Systems CH4
Natural Gas Flaring and Criteria Pollutant Emissions from Oil and Gas Activities C02, CO, NOX, NMVOC
Wood Biomass and Ethanol Consumption CO,
Industrial Processes
Cement Manufactur
Lime Manufacture CO
Cement Manufacture C02
'2
Limestone and Dolomite Use C02
Soda Ash Manufacture and Consumption C02
Carbon Dioxide Manufacture C02
Iron and Steel Production C02
Ammonia Manufacture C02
Ferroalloy Production C02
Petrochemical Production CH4
Silicon Carbide Production CH4
Adipic Acid Production N20
Nitric Acid Production N20
Substitution of Ozone Depleting Substances MFCs, PFCsa
Aluminum Production CF4, C2F6
HCFC-22 Production HFC-23
Semiconductor Manufacture MFCs, PFCs, SF6b
Electrical Transmission and Distribution SF6
Magnesium Production and Processing SF6
Industrial Sources of Criteria Pollutants CO, NOX, NMVOC
Solvent Use CO, NOX, NMVOC
Agriculture
Enteric Fermentation CH4
Manure Management CH4, N20
Rice Cultivation CH4
Agricultural Soil Management N20
Agricultural Residue Burning CH4, N,0, CO, NOX
Land-Use Change and Forestry
Changes in Forest Carbon Stocks C02
Changes in Non-Forest Soil Carbon Stocks CO,
Waste
Landfills CH4
Wastewater Treatment CH
'4
Human Sewage N20
Waste Combustion N20
Waste Sources of Criteria Pollutants CO, NOX, NMVOC
8 In 1996, included HFC-23, HFC-125, HFC-134a, HFC-143a, HFC-152a, HFC-227ea, HFC-236fa, HFC-4310mee, C4F10, C6F14, PFC/PFPEs
b Included such gases as HFC-23, CF4, C2F6, SF6
M-1
-------
Annex N
IPCC Reporting Tables
This annex contains a series of tables which summarize the emissions and activity data discussed in the body of
this report. The data in these tables conform with guidelines established by the IPCC (IPCC/UNEP/OECD/IEA 1997;
vol. 1) for consistent international reporting of greenhouse gas emissions inventories. The format of these tables does not
always correspond directly with the calculations discussed in the body of the report. In these instances, the data have
been reorganized to conform to IPCC reporting guidelines. As a result, slight differences may exist between the figures
presented in the IPCC tables and those in the body of the report. These differences are merely an artifact of variations in
reporting structures; total U.S. emissions are unaffected.
Title of Inventory
Contact Name
Title
Organisation
Address
Phone
Fax
E-Mail
Is uncertainty addressed?
Related documents filed with IPCC
inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
Wiley Barbour
U.S. Environmental Protection Agency
Climate Policy and Programs Division (2175)
401 M Street, SW
Washington, DC 20460
(202) 260-6972
(202) 260-6405
barbour.wiley@epamail.epa.gov
Yes
Yes
N-1
-------
IPCC Table 1: Sectoral Report for Energy (1996)
Sectoral Report for National Greenhouse Gas Inventories
(Gg)
Greenhouse Gas Source and Sink Categories
Total Energy
A Fuel Combustion Activities (Reference)
A Fuel Combustion Activities (Sectoral)
1 Electric Utilities
Petroleum
Gas
Coal
Geothermal
2 Industry
Petroleum
Gas
Coal
3 Transport
Petroleum
Gas
Coal
4 Commercial
Petroleum
Gas
Coal
5 Residential
Petroleum
Gas
Coal
6 Agriculture / Forestry
Petroleum
Gas
Coal
7 Territories
Petroleum
Gas
Coal
B Fugitive Emissions from Fuels
1 Solid Fuels
a Coal Mining
2 Petroleum and Natural Gas
a Petroleum
b Natural Gas
c Venting and Flaring
Memo Items*:
International Bunkers
Aviation
Marine
CO2 Emissions from Biomass [b]
Wood
Ethanol
C02[a]
5,330,574
5,317,701
5,317,843
1,895,156
57,236
147,859
1,689,925
135
1,125,708
383,708
524,213
217,787
1,631,090
1,592,519
38,570
0
237,504
56,184
173,678
7,642
388,656
99,796
283,795
5,065
IE
39,730
38,794
936
12,730
NE
12,730
12,730
82,443
22,096
60,346
200,108
194,963
5,145
CH4
10,188.5
667.1
23.3
-
-
-
-
141.6
-
-
-
238.4
-
-
-
38.2
-
-
-
225.6
-
-
-
IE
NE
9,521.3
3,301.0
3,301.0
6,220.3
270.6
5,949.7
NE
IE
N20
242.92
242.92
26.13
-
-
-
-
16.56
-
-
-
195.44
-
-
-
1.08
-
-
-
3.71
-
-
-
IE
NE
NE
NE
NE
NE
IE
NOx
20,123
20,024
5,991
-
-
-
-
2,794
-
-
-
10,656
-
-
-
336
-
-
-
654
-
-
-
IE
NE
100
NE
100
-
-
-
IE
IE
CO
67,596
67,280
341
-
-
-
-
972
-
-
-
61,931
-
-
-
219
-
-
-
3,817
-
-
-
IE
NE
316
NE
316
-
-
-
IE
IE
NMVOC
8,470
8,014
41
-
-
-
-
188
-
-
-
7,048
-
-
-
21
-
-
-
715
-
-
-
IE
NE
456
NE
456
-
-
-
IE
IE
S02
16,173
15,839
1 1 ,434
-
-
-
-
3,084
-
-
-
612
-
-
-
IE
164
-
-
-
IE
NE
334
NE
334
-
-
-
IE
IE
*Not included in energy totals
Note: Totals may not equal sum of components due to independent rounding.
"-" = Value is not estimated separately, but included in an aggregate figure.
NE = Not estimated
IE = Estimated but included elsewhere
[a] For CO2 calculations a detailed bottom-up approach was implemented using activity data disaggregated by sector and fuel type.
[b] CO2 emissions estimates from biomass consumption are from commercial, industrial, residential, transportation, and electric power production
applications. Estimates of non-CO2 emissions from these sources were calculated via U.S. EPA methodologies and are incorporated in sectoral
estimates in section A.
N-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
IPCC Table 2a: Sectoral Report for Industrial Processes (1996)
Sectoral Report for National Greenhouse Gas Inventories (Gg
Greenhouse Gas Source and Sink Categories
Total Industrial Processes
A Mineral Products
1 Cement Production
2 Lime Production
3 Limestone and Dolomite Use
4 Soda Ash Production and Use
5 Asphalt Roofing
6 Other
B Chemical Industry
1 Ammonia Production
2 Nitric Acid Production
3 Adipic Acid Production
4 Silicon Carbide Production
5 Carbon Dioxide Production
6 Petrochemical Production
C Metal Production
1 Iron and Steel Production
2 Ferroalloys Production
3 Aluminum Production
4 SF6 Used in Aluminum and Magnesium Foundries
D Other Production
E Production of Halocarbons and SF6
1 Byproduct Emissions
2 Fugitive Emissions
3 Other
F Consumption of Halocarbons and SF6
1 Refrigeration and Air Conditioning Equipment
2 Foam Blowing
3 Fire Extinguishers
4 Aerosols
5 Solvents
6 Electrical Transmission and Distribution
G Other
1 Storage and Transport
2 Other Industrial Processes
3 Miscellaneous
C02
63,309
62,169
37,061
1 4,092
6,743
4,273
NE
NA
1,140
23, 138 [a]
1,140
IE
79,040 [a]
1 ,695 [a]
5258 [a]
NA
NE
NE
IE
CH4
73.9
NE
NA
73.9
0.9
73.0
NE
NA
NE
NE
IE
N20
108.71
NE
NA
108.71
45.38
63.32
NE
NA
NE
NE
IE
NOx
820
IE
IE
NA
144
-
-
-
-
-
-
89
-
-
-
-
NA
NE
NE
587
5
366
216
CO
5,338
IE
IE
NA
1,110
-
-
-
-
-
-
2,157
-
-
-
-
NA
NE
NE
2,071
23
576
1,472
NMVOC
1,970
IE
IE
NA
377
-
-
-
-
-
-
64
-
-
-
-
NA
NE
NE
1,529
889
391
249
S02
1,122
IE
IE
NA
260
-
-
-
-
-
-
481
-
-
-
-
NA
NE
NE
381
2
371
8
MFCs [b
[b
NE
NA
IE
NE
NA
IE b
IE b
lEfbl
-
-
-
-
-
NO
PFCs [b
[b
NE
NA
IE
fbl
fbl
NA
IE fbl
IE fbl
-
-
-
-
-
NO
SF6
1 .5342
NE
NA
IE
0.4603
0.4603
NA
IE
1 .0739
1 .0739
NO
Note: Totals may not equal sum of components due to independent rounding.
"-" = Value is not estimated separately, but included in an aggregate figure.
NE = Not estimated
IE = Estimated but included elsewhere
NO = Not known to be occurring
NA = Not applicable
[aj CO2 emissions from aluminum, ammonia, ferroalloy, and iron & steel production are included
in this table for informational purposes, but are not included in the national total in order to
prevent double counting these emissions, which are included under non-fuel industrial uses under
the Energy sector.
[b] Emissions of MFCs and PFCs are documented by gas in Table 2b.
[c] Includes cooling towers, fugitive dust, health services
N-3
-------
IPCC Table 2b: Detailed Emissions of MFCs (1996)
Greenhouse Gas Source and Sink Categories
Total MFCs and PFCs
A Substitution of Ozone Depleting Substances
B Aluminum Production
C HCFC-22 Production
D Semiconductor Manufacture
(MMTCE)
Unspecified*
1.4
1.4
Sectoral Report for National Greenhouse Gas Inventories(Gg)
HFC-23
2.690
0.026
NO
2.664
IE
HFC-125
3.172
3.172
NO
NO
NO
HFC-134a
13.605
13.605
NO
NO
NO
HFC-143a
0.226
0.226
NO
NO
NO
HFC-152a
1.08
1.08
NO
NO
NO
HFC-227ea
2.063
2.063
NO
NO
NO
HFC-236fa
0.079
0.079
NO
NO
NO
HFC-4310mee
1.030
1.030
NO
NO
NO
"Includes gases such as HFC-23, CF4, C2F6, SF6, and C3FS
IE = Estimated but included elsewhere
NO = Not known to be occurring
IPCC Table 2c: Detailed Emissions of PFCs (1996)
Sectoral Report for National Greenhouse Gas Inventories
(Gg)
Greenhouse Gas Source and Sink Categories
Total MFCs and PFCs
A Substitution of Ozone Depleting Substances
B Aluminum Production
C HCFC-22 Production
D Semiconductor Manufacture
CF4
1.434
NO
1.434
NO
IE
C2F6
0.143
NO
0.143
NO
IE
C4P10
0.064
0.064
NO
NO
NO
C6F14
0.006
0.006
NO
NO
NO
PFC/PFPEs [a]
0.990
0.990
NO
NO
NO
IE = Estimated but included elsewhere
NO = Not known to be occurring
[a] PFC/PFPEs are a proxy for many diverse PFCs and perfluoropolyethers (PFPEs) that are employed in solvent applications. The GWP and atmospheric lifetime of this aggregate category is based upon
that of C6F14
IPCC Table 3: Sectoral Report for Solvent and Other Product Use (1996)
Sectoral Report for National Greenhouse Gas Inventories
(Gg)
Greenhouse Gas Source and Sink Categories
Total Solvent and Other Product Use
A Degreasing
B Dry Cleaning
C Graphic Arts
D Surface Coating (including paint)
E Other Industrial
F Non-Industrial
NOx
3
a
a
1
2
a
a
CO
5
a]
al
1
3
al
NMVOC
5,691
599
172
353
2,613
48
1,905
S02
1
a
a
a
[al
fa
NO
IP1
[a] Less than 0.5 Gg
CC Table 4: Sectoral Report for Agriculture (1996)
Sectoral Report for National Greenhouse Gas Inventories
(Gg)
Greenhouse Gas Source and Sink Categories
Total Agriculture
A Enteric Fermentation
1 Dairy Cattle
2 Beef Cattle
3 Sheep
C02
NE
NE
CH4
9,381.5
6,023.0
1,456.0
4,294.0
68.0
N20
847.94
NE
NOx
34
NE
CO
783
NE
NMVOC
NE
S02
NE
N-4 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
4 Goats
5 Horses, Mules and Asses
6 Swine
B Manure Management
1 Dairy Cattle
2 Beef Cattle
3 Sheep
4 Goats
5 Horses, Mules and Asses
6 Swine
7 Poultry
C Rice Cultivation
1 Irrigated
2 Rainfed
3 Deepwater
D Agricultural Soils
1 Direct Emission from Agricultural Cropping Practices
2 Direct Emissions from Animal Production
3 Indirect Emissions from Nitrogen Applied to Agricultural Soils
E Prescribed Burning of Savannas
F Field Burning of Agricultural Residues
1 Cereals
2 Pulse
3 Tuber and Root
4 Sugar Cane
NE
NE
NE
NE
NE
12.0
108.0
85.0
2,889.9
786.6
226.1
2.8
0.9
30.8
1,541.3
301.5
431.3
431.3
NE
NE
37.3
27.5
8.7
0.1
0.9
34.95
0.84
14.46
0.27
0.05
0.59
0.76
17.97
NE
811.56
442.32
128.21
241 .03
NE
1.42
0.67
0.74
0.01
0.01
NE
NE
NE
NE
34
16
17
0
0
NE
NE
NE
NE
783
578
183
2
19
Note: Totals may not equal sum of components due to independent rounding.
NE = Not estimated
N-5
-------
IPCC Table 5: Sectoral Report for Land-Use Change and Forestry (1996)
Sectoral Report for National Greenhouse Gas Inventories (Gg)
Greenhouse Gas Source and Sink Categories
Total Land-Use Change and Forestry
A Changes in Forest and Other Woody Biomass Stocks
1 Forest Trees, Understory, Floor
B Forest and Grassland Conversion
C Abandonment of Managed Lands
D CO2 Emissions and Removals from Soil
1 Forest Soils
2 Non-Forest Soils
E Other
1 Landfilled Wood Carbon Flux
2 Wood Product Flux
CO2 Emissions
CO2 Removals
-764,683
-31 1 ,667
-31 1 ,667
NO
NO
-316,250
-316,250
NE
-136,767
-71 ,243
-65,523
CH4
NE
N20
NE
NOx
NE
CO
NE
NE = Not estimated
NO = Not known to be occurring
IPCC Table 6: Sectoral Report for Waste (1996)
Sectoral Report for National Greenhouse Gas Inventories (Gg)
Greenhouse Gas Source and Sink Categories
Total Waste
A Solid Waste Disposal on Land
1 Managed Waste Disposal
B Wastewater Handling
1 Domestic
2 Industrial
3 Human Sewage
C Waste Incineration
1 Waste Incineration
2 Open Burning
D Other
1 Treatment Storage and Disposal Facility
2 Scrap and Waste Materials/Leaking Underground Storage Tanks
C02
IE
IE
NE
IE
NE
CH4
11,532
1 1 ,372
1 1 ,372
161
161
NE
-
NE
NE
N20
28
NE
27
NE
NE
27
1
1
NE
NOx
87
1
1
a
a
a
-
85
49
36
1
1
CO
1,019
2
2
a
a
a
1,016
402
614
1
1
NMVOC
368
19
19
58
47
11
218
50
169
73
41
32
S02
43
a
a
1
-
-
42
32
10
fa
-
"-" = Value is not estimated separately, but included in an aggregate figure.
[a] Less than 0.5 Gg
NE = Not estimated
IE = Estimated but included elsewhere
IPCC Table 7 A: Summary Report for National Greenhouse Gas Inventories (1996)
Summary Report for National Greenhouse Gas Inventories
(Gg)
Greenhouse Gas Source and Sink Categories
Total National Emissions and Removals
1 Energy
A Fuel Combustion Activities (Sectoral)
1 Electric Utilities
2 Industry
CO2
Emissions
5,393,883
5,330,574
5,317,843
1,895,156
1,125,708
CO2
Removals
-764,683
CH4
31,176.1
10,188.5
667.1
23.3
141.6
N2O
1,227.11
242.92
242.92
26.13
16.56
NOX
21,067
20,123
20,024
5,473
2,875
CO
74,741
67,596
67,280
341
972
NMVOC
16,499
8,470
8,014
41
188
SO2
17,339
16,173
15,839
1 1 ,434
3,084
MFCs
[b]
NO
PFCs
[b]
NO
SF6
1.5342
NO
N-6 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
3 Transport
4 Commercial
5 Residential
6 Agriculture / Forestry
7 Territories
B Fugitive Emissions from Fuels
1 Solid Fuels
2 Petroleum and Natural Gas
2 Industrial Processes
A Mineral Products
B Chemical Industry
C Metal Production
D Other Production
E Production of Halocarbons and SF6
F Consumption of Halocarbons and SF6
G Other
3 Solvent and Other Product Use
1,631,090
237,504
388,656
IE
39,730
12,730
NE
12,730
63,309
62,169
1,140
IE
NA
NE
NE
IE
NE
238.4
38.2
225.6
IE
NE
9,521.3
3,301.0
6,220.3
73.9
NE
73.9
NE
NA
NE
NE
IE
NE
195.44
1.08
3.71
IE
NE
NE
NE
108.71
NE
108.71
NE
NA
NE
NE
IE
NE
10,656
336
654
IE
NE
100
NE
100
820
IE
144
89
NA
NE
NE
587
3
61,931
219
3,817
IE
NE
316
NE
316
5,338
IE
1,110
2,157
NA
NE
NE
2,071
5
7,048
21
715
IE
NE
456
NE
456
1,970
IE
377
64
NA
NE
NE
1,529
5,691
612
546
164
IE
NE
334
NE
334
1,122
IE
260
481
NA
NE
NE
381
1
fbl
NE
IE
NE
NA
IE b
IE b
NO
NO
fbl
NE
IE
fbl
NA
IE b
IE b
NO
NO
1 .5342
NE
IE
0.4603
NA
IE
1 .0739
NO
NO
*Not included in energy totals
Note: Totals may not sum due to independent rounding.
NE = Not estimated
IE = Estimated but included elsewhere
NO = Not known to be occurring
[a] CO2 emissions estimates from biomass consumption are from commercial, industrial, residential, transportation, and electric power production applications. They are provided for informational
purposes only and are not included in national totals. Estimates of non-CO2 emissions from these sources were calculated via U.S. EPA methodologies and are incorporated in sectoral estimates in
section 1A.
[b] Totaled by gas in Table 2b
N-7
-------
IPCC Table 7 A (continued): Summary Report for National Greenhouse Gas Inventories (1996)
Summary Report for National Greenhouse Gas Inventories
(Gg)
Greenhouse Gas Source and Sink Categories
4 Agriculture
A Enteric Fermentation
B Manure Management
C Rice Cultivation
D Agricultural Soils
E Prescribed Burning of Savannas
F Field Burning of Agricultural Residues
5 Land-Use Change & Forestry
A Changes in Forest and Other Woody Biomass Stocks
B Forest and Grassland Conversion
C Abandonment of Managed Lands
D CO2 Emissions and Removals from Soil
E Other
6 Waste
A Solid Waste Disposal on Land
B Wastewater Handling
C Waste Incineration
D Other
Memo Items*:
International Bunkers
Aviation
Marine
CO2 Emissions from Biomass [a]
C02
Emissions
NE
NE
NE
NE
NE
NO
NE
IE
IE
NE
IE
NE
82,443
22,096
60,346
200,108
C02
Removals
-764,683
-31 1 ,667
NO
NO
-316,250
-136,767
CH4
9,381.5
6,023.0
2,889.9
431.3
NE
NO
37.3
NE
11,532.3
11,371.7
160.6
NE
NE
NE
IE
N20
847.94
NE
34.95
NE
811.56
NO
1.42
NE
27.55
NE
26.66
0.89
NE
NE
IE
NOX
34
NE
NE
NE
NE
NO
34
NE
87
1
0
85
1
IE
IE
CO
783
NE
NE
NE
NE
NO
783
NE
1,019
2
0
1,016
1
IE
IE
NMVOC
NE
NE
368
19
58
218
73
IE
IE
S02
NE
NE
43
0
1
42
0
IE
IE
MFCs
NO
NO
NO
NO
NO
PFCs
NO
NO
NO
NO
NO
SF6
NO
NO
NO
NO
NO
*Not included in energy totals
Note: Totals may not sum due to independent rounding.
NE = Not estimated
IE = Estimated but included elsewhere
NO = Not known to be occurring
[a] CO2 emissions estimates from biomass consumption are from commercial, industrial, residential, transportation, and electric power production applications. They are provided for informational
purposes only and are not included in national totals. Estimates of non-CO2 emissions from these sources were calculated via U.S. EPA methodologies and are incorporated in sectoral estimates in
section 1A.
[b] Totaled by gas in Table 2b
N-8 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
IPCC Table 7B: Short Summary Report for National Greenhouse Gas Inventories (1996)
Summary Report for National Greenhouse Gas Inventories
(Gg)
Greenhouse Gas Source and Sink Categories
Total National Emissions and Removals
1 Energy (Reference Approach)
1 Energy (Sectoral Approach)
A Fuel Combustion Activities
B Fugitive Emissions from Fuels
2 Industrial Processes
3 Solvent and Other Product Use
4 Agriculture
5 Land-Use Change & Forestry
6 Waste
Memo Items*:
International Bunkers
Aviation
Marine
CO2 Emissions from Biomass
a
C02
Emissions
5,393,883
5,317,701
5,330,574
5,317,843
12,730
63,309
NE
NE
IE
82,443
22,096
60,346
200,108
C02
Removals
-764,683
-764,683
CH4
31,176.1
10,188.5
667.1
9,521.3
73.9
NE
9,381.5
NE
11,532.3
NE
IE
N20
1,227.11
242.92
242.92
NE
108.71
NE
847.94
NE
27.55
NE
IE
NOx
21,067
20,123
20,024
100
820
3
34
NE
87
IE
IE
CO
74,741
67,596
67,280
316
5,338
5
783
NE
1,019
IE
IE
NMVOC
16,499
8,470
8,014
456
1,970
5,691
NE
NE
368
IE
IE
S02
17,339
16,173
15,839
334
1,122
1
NE
NE
43
IE
IE
MFCs
[b]
NO
[b]
NO
NO
NO
NO
NO
NO
PFCs
[b]
NO
[b]
NO
NO
NO
NO
NO
NO
SF6
1.5342
NO
1 .5342
NO
NO
NO
NO
NO
NO
*Not included in energy totals
Note: Totals may not sum due to independent rounding.
NE = Not estimated
IE = Estimated but included elsewhere
NO = Not known to be occurring
[a] CO2 emissions estimates from biomass consumption are from commercial, industrial, residential, transportation, and electric power production applications. They are provided for informational
purposes only and are not included in national totals. Estimates of non-CO2 emissions from these sources were calculated via U.S. EPA methodologies and are incorporated in sectoral estimates in
section 1A.
[b] Totaled by gas in Table 2b
N-9
-------
IPCC Table 8A (part I): Overview Table for National Greenhouse Gas Inventories (1996)
Greenhouse Gas Source and Sink Categories
Total National Emissions and Removals
1 Energy
A Fuel Combustion Activities (Reference)
A Fuel Combustion Activities (Sectoral)
1 Electric Utilities
2 Industry
3 Transport
4 Commercial
5 Residential
6 Agriculture / Forestry
7 Territories
B Fugitive Emissions from Fuels
1 Solid Fuels
2 Petroleum and Natural Gas
2 Industrial Processes
A Mineral Products
B Chemical Industry
C Metal Production
D Other Production
E Production of Halocarbons and SF6
F Consumption of Halocarbons and SF6
G Other [f]
3 Solvent and Other Product Use
CO2
Estimate
ALL
ALL
ALL
ALL
ALL
ALL
IE
ALL
NE
PART [c]
ALL
ALL
IE
NA
NO
NO
IE
NE
Quality
H
H
H
H
H
H
H
M
H
M
CH4
Estimate
NE
ALL
ALL
ALL
ALL
ALL
IE
NE
ALL
ALL
NE
ALL
NE
NA
NO
NO
IE
NE
Quality
M
M
M
M
M
M
M
M
N2O
Estimate
NE
ALL
ALL
PART [b]
ALL
ALL
IE
NE
NE
NE
NE
ALL
NE
NA
NO
NO
IE
NE
Quality
M
M
M
M
M
H
NOx
Estimate
NE
ALL
ALL
ALL
ALL
ALL
IE
NE
NE
ALL
IE
ALL
ALL
NA
NO
NO
ALL
ALL
Quality
H
H
H
H
H
H
H
H
H
H
CO
Estimate
NE
ALL
ALL
ALL
ALL
ALL
IE
NE
NE
ALL
IE
ALL
ALL
NA
NO
NO
ALL
ALL
Quality
H
H
H
H
H
H
H
H
H
H
NMVOC
Estimate
NE
ALL
ALL
ALL
ALL
ALL
IE
NE
NE
ALL
IE
ALL
ALL
NA
NO
NO
ALL
ALL
Quality
H
H
H
H
H
H
H
H
H
H
Quality:
H = High Confidence in Estimation
M = Medium Confidence in Estimation
L = Low Confidence in Estimation
NE = Not estimated
IE = Estimated but included elsewhere
NO = Not known to be occurring
NA = Not applicable
PART = Partly estimated
ALL = Full estimate of all possible sources
[a] Non-forest soils are not included in this estimate.
[b] Estimate does not include nitrous oxide emissions from jet aircraft.
[c] Estimate excludes geologic carbon dioxide deposits released during petroleum and natural gas production.
[d] Estimate does not include emissions from industrial wastewater.
[e] Includes emissions from human sewage only
[f] From storage and transport; other industrial processes; and cooling towers, fugitive dust, and health services
[g] From landfilled wood and wood product flux
[h] From treatment, storage and disposal facilities: scrap and waste materials; and underground storage tanks
IPCC Table 8A (part II): Overview Table for National Greenhouse Gas Inventories (1996)
Documentation:
H = High (all background information included)
M = Medium (some background information included)
L = Low (only emission estimates included)
Disaggregation:
1 = Total emissions estimated
2 = Sectoral split
3 = Subsectoral split
Greenhouse Gas Source and Sink Categories
4 Agriculture
A Enteric Fermentation
B Manure Management
C Rice Cultivation
D Agricultural Soils
E Prescribed Burning of Savannas
F Field Burning of Agricultural Residues
5 Land-Use Change & Forestry
CO2
Estimate
NE
NE
NE
NE
NE
NE
Quality
CH4
Estimate
ALL
ALL
ALL
NE
NE
ALL
Quality
M
M
M
M
N2O
Estimate
NE
ALL
NE
ALL
NE
ALL
Quality
M
M
M
NOx
Estimate
NE
NE
NE
NE
NE
ALL
Quality
M
CO
Estimate
NE
NE
NE
NE
NE
ALL
Quality
M
NMVOC
Estimate
NE
NE
NE
NE
NE
NE
Quality
N-10 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
A Changes in Forest and Other Woody Biomass Stocks
B Forest and Grassland Conversion
C Abandonment of Managed Lands
D CO2 Emissions and Removals from Soil
E Other [g]
6 Waste
A Solid Waste Disposal on Land
B Wastewater Handling
C Waste Incineration
D Other [h]
Memo Items:
International Bunkers
Aviation
Marine
CO2 Emissions from Biomass [a]
ALL
NO
NO
PART [a]
ALL
IE
NE
IE
NE
ALL
ALL
ALL
M
L
M
M
M
M
NE
NE
NE
NE
NE
ALL
PART [d]
NE
NE
NE
NE
IE
H
M
NE
NE
NE
NE
NE
NE
PART [e]
ALL
NE
NE
NE
IE
M
M
NE
NE
NE
NE
NE
ALL
ALL
ALL
ALL
IE
IE
IE
H
H
H
H
NE
NE
NE
NE
NE
ALL
ALL
ALL
ALL
IE
IE
IE
H
H
H
H
NE
NE
NE
NE
NE
ALL
ALL
ALL
ALL
IE
IE
IE
H
H
H
H
Quality:
H = High Confidence in Estimation
M = Medium Confidence in Estimation
L = Low Confidence in Estimation
NE = Not estimated
IE = Estimated but included elsewhere
NO = Not known to be occurring
NA = Not applicable
PART = Partly estimated
ALL = Full estimate of all possible sources
[a] Non-forest soils are not included in this estimate.
[b] Estimate does not include nitrous oxide emissions from jet aircraft.
[c] Estimate excludes geologic carbon dioxide deposits released during petroleum and natural gas production.
[d] Estimate does not include emissions from industrial wastewater.
[e] Includes emissions from human sewage only
[f] From storage and transport; other industrial processes; and cooling towers, fugitive dust, and health services
[g] From landfilled wood and wood product flux
[h] From treatment, storage and disposal facilities: scrap and waste materials; and underground storage tanks
Documentation:
H = High (all background information included)
M = Medium (some background information included)
L = Low (only emission estimates included)
Disaggregation:
1 = Total emissions estimated
2 = Sectoral split
3 = Subsectoral split
N-11
-------
IPCC Table 8A (part III): Overview Table for National Greenhouse Gas Inventories (1996)
Greenhouse Gas Source and Sink Categories
Total National Emissions and Removals
1 Energy
A Fuel Combustion Activities (Reference)
A Fuel Combustion Activities (Sectoral)
1 Electric Utilities
2 Industry
3 Transport
4 Commercial
5 Residential
6 Agriculture / Forestry
7 Territories
B Fugitive Emissions from Fuels
1 Solid Fuels
2 Petroleum and Natural Gas
2 Industrial Processes
A Mineral Products
B Chemical Industry
C Metal Production
D Other Production
E Production of Halocarbons and SF6
F Consumption of Halocarbons and SF6
G Other [f]
3 Solvent and Other Product Use
SO2
Estimate
NE
ALL
ALL
ALL
IE
IE
NE
NE
NE
ALL
IE
ALL
ALL
NA
NO
NO
ALL
ALL
Quality
H
H
H
H
H
H
H
H
MFCs
Estimate
NE
NO
NO
NO
NO
NO
NO
NO
NO
NO
NE
IE
NE
NA
ALL
ALL
NO
NO
Quality
M
M
PFCs
Estimate
NE
NO
NO
NO
NO
NO
NO
NO
NO
NO
NE
IE
ALL
NA
ALL
ALL
NO
NO
Quality
M
M
M
SF6
Estimate
NE
NO
NO
NO
NO
NO
NO
NO
NO
NO
NE
IE
ALL
NA
IE
ALL
NO
NO
Quality
M
M
Documentation
H
H
H
H
H
H
M
M
M
M
M
Disaggregation
3
3
3
3
3
3
3
2
2
2
3
Footnotes
Quality:
H = High Confidence in Estimation
M = Medium Confidence in Estimation
L = Low Confidence in Estimation
NE = Not estimated
IE = Estimated but included elsewhere
NO = Not known to be occurring
NA = Not applicable
PART = Partly estimated
ALL = Full estimate of all possible sources
[a] Non-forest soils are not included in this estimate.
[b] Estimate does not include nitrous oxide emissions from jet aircraft.
[c] Estimate excludes geologic carbon dioxide deposits released during petroleum and natural gas production.
[d] Estimate does not include emissions from industrial wastewater.
[e] Includes emissions from human sewage only
[f] From storage and transport; other industrial processes; and cooling towers, fugitive dust, and health services
[g] From landfilled wood and wood product flux
[h] From treatment, storage and disposal facilities: scrap and waste materials; and underground storage tanks
Documentation:
H = High (all background information included)
M = Medium (some background information included)
L = Low (only emission estimates included)
Disaggregation:
1 = Total emissions estimated
2 = Sectoral split
3 = Subsectoral split
N-12 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
IPCC Table 8A (part IV): Overview Table for National Greenhouse Gas Inventories (1996)
Greenhouse Gas Source and Sink Categories
4 Agriculture
A Enteric Fermentation
B Manure Management
C Rice Cultivation
D Agricultural Soils
E Prescribed Burning of Savannas
F Field Burning of Agricultural Residues
5 Land-Use Change & Forestry
A Changes in Forest and Other Woody Biomass Stocks
B Forest and Grassland Conversion
C Abandonment of Managed Lands
D CO2 Emissions and Removals from Soil
E Other [g]
6 Waste
A Solid Waste Disposal on Land
B Wastewater Handling
C Waste Incineration
D Other [h]
Memo Items:
International Bunkers
Aviation
Marine
CO2 Emissions from Biomass [a]
SO2
Estimate
NE
NE
NE
NE
NE
NE
NE
NE
NE
NE
NE
ALL
ALL
ALL
ALL
IE
IE
IE
Quality
H
H
H
H
MFCs
Estimate
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
Quality
PFCs
Estimate
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
Quality
SF6
Estimate
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
Quality
Documentation
H
H
H
H
H
M
M
M
H
H
H
H
H
H
Disaggregation
3
3
3
3
3
2
2
2
3
2
2
1
1
2
Footnotes
Quality:
H = High Confidence in Estimation
M = Medium Confidence in Estimation
L = Low Confidence in Estimation
NE = Not estimated
IE = Estimated but included elsewhere
NO = Not known to be occurring
NA = Not applicable
PART = Partly estimated
ALL = Full estimate of all possible sources
[a] Non-forest soils are not included in this estimate.
[b] Estimate does not include nitrous oxide emissions from jet aircraft.
[c] Estimate excludes geologic carbon dioxide deposits released during petroleum and natural gas production.
[d] Estimate does not include emissions from industrial wastewater.
[e] Includes emissions from human sewage only
[f] From storage and transport; other industrial processes; and cooling towers, fugitive dust, and health services
[g] From landfilled wood and wood product flux
[h] From treatment, storage and disposal facilities: scrap and waste materials; and underground storage tanks
Documentation:
H = High (all background information included)
M = Medium (some background information included)
L = Low (only emission estimates included)
Disaggregation:
1 = Total emissions estimated
2 = Sectoral split
3 = Subsectoral split
N-13
-------
Annex O
IPCC Reference Approach for Estimating CO2 Emissions from Fossil
Fuel Combustion
It is possible to estimate carbon emissions from fossil fuel consumption using alternative methodologies and
different data sources than those described in Annex A. For example, the IPCC requires countries in addition to their
"bottom-up" sectoral methodology to complete a "top-down" Reference Approach for estimating carbon dioxide
emissions from fossil fuel combustion. Section 1.3 of the Revised 1996 IPCC Guidelines for National Greenhouse
Gas Inventories: Reporting Instructions states, "If a detailed, Sectoral Approach for energy has been used for the
estimation of CO2 from fuel combustion you are still asked to complete.. .the Reference Approach.. .for verification
purposes" (IPCC/UNEP/OECD/IEA 1997). This reference method estimates fossil fuel consumption by adjusting
national aggregate fuel production data for imports, exports, and stock changes rather than relying on end-user
consumption surveys. The basic principle is that once carbon-based fuels are brought into a national economy, they
are either saved in some way (e.g., stored in products, kept in fuel stocks, or left unoxidized in ash) or combusted, and
therefore the carbon in them is oxidized and released into the atmosphere. Accounting for actual consumption of fuels
at the sectoral or sub-national level is not required. The following discussion provides the detailed calculations for
estimating CO2 emissions from fossil fuel combustion from the United States using the IPCC-recommended Reference
Approach.
Step 1: Collect and Assemble Data in Proper Format
To ensure the comparability of national inventories, the IPCC has recommended that countries report energy
data using the International Energy Agency (TEA) reporting convention. National energy statistics were collected in
physical units from several DOE/EIA documents in order to obtain the necessary data on production, imports, exports,
and stock changes.15 These data are presented in Table O-l.
The carbon content of fuel varies with the fuel's heat content. Therefore, for an accurate estimation of CO2
emissions, fuel statistics should be provided on an energy content basis (e.g., BTU's or joules). Because detailed fuel
production statistics are typically provided in physical units (as in Table O-l), they were converted to units of energy
before carbon emissions can be calculated. Fuel statistics were converted to their energy equivalents by using
conversion factors provided by DOE/EIA. These factors and their data sources are displayed in Table O-2. The
resulting fuel data are provided in Table O-3.
Step 2: Estimate Apparent Fuel Consumption
The next step of the IPCC method is to estimate "apparent consumption" of fuels within the country. This
requires a balance of primary fuels produced, plus imports, minus exports, and adjusting for stock changes. In this
way, carbon enters an economy through energy production and imports (and decreases in fuel stocks) and is transferred
out of the country through exports (and increases in fuel stocks). Thus, apparent consumption of primary fuels
(including crude oil, natural gas liquids, anthracite, bituminous, subbituminous and lignite coal, and natural gas) can
be calculated as follows:
Production + Imports - Exports - Stock Change
Flows of secondary fuels (e.g., gasoline, residual fuel, coke) should be added to primary apparent consumption.
The production of secondary fuels, however, should be ignored in the calculations of apparent consumption since the
carbon contained in these fuels is already accounted for in the supply of primary fuels from which they were derived
15 For the United States, national aggregate energy statistics typically exclude data on the U.S. territories. As a result, national
statistics were adjusted to include production, imports, exports, and stock changes within the United States territories. The
territories include Puerto Rico, U.S. Virgin Islands, Guam, American Samoa, Wake Island, and U.S. Pacific Islands.
O-1
-------
(e.g., the estimate for apparent consumption of crude oil already contains the carbon from which gasoline would be
refined). Flows of secondary fuels should therefore be calculated as follows:
Imports - Exports - Stock Change
Note that this calculation can result in negative numbers for apparent consumption. This is a perfectly
acceptable result since it merely indicates a net export or stock increase in the country of that fuel when domestic
production is not considered.
The IPCC Reference Approach calls for estimating apparent fuel consumption before converting to a common
energy unit. However, certain primary fuels in the United States (e.g., natural gas and steam coal) have separate
conversion factors for production, imports, exports, and stock changes. In these cases, it is not appropriate to multiply
apparent consumption by a single conversion factor since each of its components have different heat contents.
Therefore, United States fuel statistics were converted to their heat equivalents before estimating apparent
consumption. The energy value of bunker fuels was subtracted before computing energy totals.16 Results are provided
in Table O-3.
Step 3: Estimate Carbon Emissions
Once apparent consumption is estimated, the remaining calculations are virtually identical to those for the
"bottom-up" Sectoral Approach (see Annex A). That is:
Potential carbon emissions were estimated using fuel-specific carbon coefficients (see Table O-4).17
The carbon sequestered in non-fuel uses of fossil fuels (e.g., plastics or asphalt) was then estimated and
subtracted from the total amount of carbon (see Table O-5).
Finally, to obtain actual carbon emissions, net carbon emissions were adjusted for any carbon that remained
unoxidized as a result of incomplete combustion (e.g., carbon contained in ash or soot).18
Step 4: Convert to CO2 Emissions
Because the IPCC reporting guidelines recommend that countries report greenhouse gas emissions on a full
molecular weight basis, the final step in estimating CO2 emissions from fossil fuel consumption was converting from
units of carbon to units of CO2. Actual carbon emissions were multiplied by the molecular to atomic weight ratio of
CO2 to carbon (44/12) to obtain total carbon dioxide emitted from fossil fuel combustion in teragrams (Tg). The
results are contained in Table O-6.
Comparison Between Sectoral and Reference Approaches
These two alternative approaches can both produce reliable estimates that are comparable within a few percent.
The major difference between methodologies employed by each approach lies in the energy data used to derive carbon
emissions (i.e., the actual reported consumption for the Sectoral Approach versus apparent consumption derived for
the Reference Approach). In theory, both approaches should yield identical results. In practice, however, slight
discrepancies occur. For the United States, these differences are discussed below.
16 Bunker fuels refer to quantities of fuels used for international transportation. The IPCC methodology accounts for these
fuels as part of the energy balance of the country in which they were delivered to end-users. Carbon dioxide emissions from
the combustion of these fuels were estimated separately and were not included in U.S. national totals. This is done to ensure
that all fuel is accounted for in the methodology and so that the IPCC is able to prepare global emission estimates.
17 Carbon coefficients from EIA were used wherever possible. Because EIA did not provide coefficients for coal, the IPCC-
recommended emission factors were used in the top-down calculations for these fuels. See notes in Table O-4 for more
specific source information.
18 For the portion of carbon that is unoxidized during coal combustion, the IPCC suggests a global average value of 2 percent.
However, because combustion technologies in the United States are more efficient, the United States inventory uses one
percent in its calculations for petroleum and coal and 0.5 percent for natural gas.
O-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Differences in Total Amount of Energy Consumed
Table O-7 summarizes the differences between the two methods in estimating total energy consumption in the
United States. Although theoretically the two methods should arrive at the same estimate for U.S. energy
consumption, the Sectoral Approach provides an energy total that is about 2.2 percent higher than the Reference
Approach. The greatest difference lies in the higher estimate of petroleum consumption with the Sectoral Approach.
There are several potential sources for these discrepancies:
Product Definitions. The fuel categories in the Reference Approach are different from those used in the
Sectoral Approach, particularly for petroleum. For example, the Reference Approach estimates apparent
consumption for crude oil. Crude oil is not typically consumed directly, but refined into other products. As
a result, the United States does not focus on estimating the energy content of crude oil, but rather estimating
the energy content of the various products resulting from crude oil refining. The United States does not
believe that estimating apparent consumption for crude oil, and the resulting energy content of the crude oil,
is the most reliable method for the United States to estimate its energy consumption. Other differences in
product definitions include using sector-specific coal statistics in the Sectoral Approach (i.e., residential,
commercial, industrial coking, industrial other, and transportation coal), while the Reference Approach
characterizes coal by rank (i.e. anthracite, bituminous, etc.). Also, the liquefied petroleum gas (LPG)
statistics used in the bottom-up calculations are actually a composite category composed of natural gas
liquids (NGL) and LPG.
Heat Equivalents. It can be difficult to obtain heat equivalents for certain fuel types, particularly for
categories such as "crude oil" where the key statistics are derived from thousands of producers in the United
States and abroad. For heat equivalents by coal rank, it was necessary to refer back to EIA's State Energy
Data Report 1992 (1994) because this information is no longer published.
Possible inconsistencies in U.S. Energy Data. The United States has not focused its energy data collection
efforts on obtaining the type of aggregated information used in the Reference Approach. Rather, the United
States believes that its emphasis on collection of detailed energy consumption data is a more accurate
methodology for the United States to obtain reliable energy data. Therefore, top-down statistics used in the
Reference Approach may not be as accurately collected as bottom-up statistics applied to the Sectoral
Approach.
Balancing Item. The Reference Approach uses apparent consumption estimates while the Sectoral Approach
uses reported consumption estimates. While these numbers should be equal, there always seems to be a
slight difference that is often accounted for in energy statistics as a "balancing item."
Differences in Estimated CO2 Emissions
Given these differences in energy consumption data, the next step for each methodology involved estimating
emissions of CO2. Table O-8 summarizes the differences between the two methods in estimated carbon emissions.
As previously shown, the Sectoral Approach resulted in a 2.2 percent higher estimate of energy consumption
in the United States than the Reference Approach, but the resulting estimates of carbon emissions are almost exactly
the same. While the Reference Approach estimates of coal and gas emissions were slightly higher than the bottom-up
numbers, top-down oil emission estimates were lower than the Sectoral Approach. Overall emissions balance out
because of these differences. Potential reasons for these patterns may include:
Product Definitions. Coal data is aggregated differently in each methodology, as noted above, with United
States coal data typically collected in the format used the Sectoral Approach. This results in more accurate
estimates than in the Reference Approach. Also, the Reference Approach relies on a "crude oil" category
for determining petroleum-related emissions. Given the many sources of crude oil in the United States, it
is not an easy matter to track potential differences in carbon content between different sources of crude,
particularly since information on the carbon content of crude oil is not regularly collected.
O-3
-------
Carbon Coefficients. The Reference Approach relies on several default carbon coefficients providedby IPCC
(IPCC/UNEP/OECD/IEA 1997), while the Sectoral Approach uses category-specific coefficients that are
likely to be more accurate. Also, as noted above, the carbon coefficient for crude oil is not an easy value to
obtain given the many sources and grades of crude oil consumed in the United States.
Although the two approaches produce similar results, the United States believes that the "bottom-up" Sectoral
Approach provides a more accurate assessment of CO2 emissions at the fuel level. This improvement in accuracy is
largely a result of the data collection techniques used in the United States, where there has been more emphasis on
obtaining the detailed products-based information used in the Sectoral Approach than obtaining the aggregated energy
flow data used in the Reference Approach. However, the United States also believes that it is valuable to understand
fully the reasons for the differences between the two methods.
References
EIA (1998) Monthly Energy Review, DOE/EIA 0035(98)-monthly, Energy Information Administration, U.S.
Department of Energy, Washington, DC. April.
EIA (1997a) Annual Energy Review 1996, DOE/EIA- 0384(96)-annual, Energy Information Administration, U.S.
Department of Energy, Washington, DC.
EIA (1997b) Coal Industry Annual - 1996, DOE/EIA 0584(96)-annual, Energy Information Administration, U.S.
Department of Energy, Washington, DC.
EIA (1997c) Emissions of Greenhouse Gases in the United States 1996, DOE/EIA 0573(97)-annual, Energy
Information Administration, U.S. Department of Energy, Washington, DC. April.
EIA (1997d) Petroleum Supply Annual -1996, DOE/EIA 03 40(96)-annual, Energy Information Administration, U.S.
Department of Energy, Washington, DC, Volume I.
EIA (1994; State Energy Data Report 1992, DOE/EIA 0214(92)-annual, Energy Information Administration, U.S.
Department of Energy, Washington, DC.
IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Paris:
Intergovernmental Panel on Climate Change, United Nations Environment Programme, Organization for
Economic Co-Operation and Development, International Energy Agency.
O-4 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table O-1: 1996 U.S. Energy Statistics (physical units)
Fuel Category (Units)
Solid Fuels (1000 Short Tons)
Gas Fuels (Million Cubic Feet)
Liquid Fuels (Thousand Barrels)
Fuel Type
Anthracite Coal
Bituminous Coal
Sub-bituminous Coal
Lignite
Coke
Unspecified Coal
Natural Gas
Crude Oil
Nat Gas Liquids and LRGs
Other Liquids
Motor Gasoline
Aviation Gasoline
Kerosene
Jet Fuel
Distillate Fuel
Residual Fuel
Naptha for Petrofeed
Petroleum Coke
Other Oil for Petrofeed
Special Napthas
Lubricants
Waxes
Asphalt/Road Oil
Still Gas
Misc. Products
Production
4,768
630,741
340,291
88,056
19,289,254
2,366,017
669,820
84,349
Imports
[1]
[1]
[1]
[1]
1,111
6,476
2,844,207
2,747,839
77,286
213,934
123,099
49
452
40,561
84,234
90,854
20,231
510
52,030
3,457
4,185
468
9,833
-
106
Exports
[1]
[1]
[1]
[1]
1,121
90,473
151,262
40,211
19,459
7,869
38,127
-
793
17,673
69,603
37,165
-
104,359
-
7,598
12,506
1,002
2,448
-
84
Stock
Change Bunkers
[1]
[1]
[1]
[1]
21
(17,411)
(11,000)
(45,299)
(7,620)
(7)
(4,287)
(72)
(178)
(146) 54,983
(3,485) 18,657
8,732 104,370
(1,041)
272
(8)
(139)
(291)
57
(1,997)
-
73
U.S.
Territories
460
1,450
17,853
13,967
22,452
24,143
219
13,240
[1] Included in Unspecified Coal
Data Sources: Solid Fuels - EIA Coal Industry Annual 1996; Gas Fuels - EIA Annual Energy Review 1996; Liquid Fuels - EIA Petroleum Supply Annual 1996
O-5
-------
Table O-2: Conversion Factors to Energy Units (heat equivalents)
Fuel Category (Units)
Solid Fuels (Million BTU/Short Ton)
Natural Gas (BTU/Cubic Foot)
Liquid Fuels (Million Btu/Barrel)
Fuel Type
Anthracite Coal
Bituminous Coal
Sub-bituminous Coal
Lignite
Coke
Unspecified
Crude Oil
Nat Gas Liquids and LRGs
Other Liquids
Motor Gasoline
Aviation Gasoline
Kerosene
Jet Fuel
Distillate Fuel
Residual Oil
Naptha for Petrofeed
Petroleum Coke
Other Oil for Petrofeed
Special Napthas
Lubricants
Waxes
Asphalt/Road Oil
Still Gas
Misc. Products
Production
22.573
23.89
17.14
12.866
1,027
5.800
3.777
5.825
Imports
24.8
25.000
1,022
5.935
3.777
5.825
5.253
5.048
5.67
5.67
5.825
6.287
5.248
6.024
5.825
5.248
6.065
5.537
6.636
6.000
5.796
Exports
24.8
26.174
1,011
5.800
3.777
5.825
5.253
5.048
5.67
5.67
5.825
6.287
5.248
6.024
5.825
5.248
6.065
5.537
6.636
6.000
5.796
Stock
Change
24.8
21.287
1,027
5.800
3.777
5.825
5.253
5.048
5.67
5.67
5.825
6.287
5.248
6.024
5.825
5.248
6.065
5.537
6.636
6.000
5.796
Bunkers
5.800
3.777
5.825
5.253
5.048
5.67
5.67
5.825
6.287
5.248
6.024
5.825
5.248
6.065
5.537
6.636
6.000
5.796
U.S.
Territories
21.287
5.800
3.777
5.825
5.253
5.048
5.67
5.67
5.825
6.287
5.248
6.024
5.825
5.248
6.065
5.537
6.636
6.000
5.796
Data Sources: Coal and lignite production - EIA State Energy Data Report 1992; Coke - EIA Annual Energy Review 1996; Unspecified Solid Fuels - EIA Monthly Energy Review, April 1998; Natural Gas - EIA Monthly
Energy Review, April 1998; Crude Oil - EIA Monthly Energy Review, April 1998; Natural Gas Liquids and LRGs - EIA Petroleum Supply Annual 1996; all other Liquid Fuels - EIA Monthly Energy Review, April 1998
O-6 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table O-3: 1996 Apparent Consumption of Fossil Fuels (trillion Btu)
Fuel Category
Solid Fuels
Gas Fuels
Liquid Fuels
Total
Fuel Type
Anthracite Coal
Bituminous Coal
Sub-bituminous Coal
Lignite
Coke
Unspecified
Natural Gas
Crude Oil
Nat Gas Liquids and LRGs
Other Liquids
Motor Gasoline
Aviation Gasoline
Kerosene
Jet Fuel
Distillate Fuel
Residual Oil
Naptha for Petrofeed
Petroleum Coke
Other Oil for Petrofeed
Special Napthas
Lubricants
Waxes
Asphalt/Road Oil
Still Gas
Misc. Products
Production
107.6
15,068.4
5,832.6
1,132.9
-
-
19,810.1
13,722.9
2,529.9
491.3
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
58,695.8
Imports
27.6
161.9
2,906.8
16,308.4
291.9
1,246.2
646.6
0.2
2.6
230.0
490.7
571.2
106.2
3.1
303.1
18.1
25.4
2.6
65.3
-
0.6
23,408.3
Exports
27.8
2,368.0
152.9
233.2
73.5
45.8
200.3
-
4.5
100.2
405.4
233.7
-
628.7
-
39.9
75.8
5.5
16.2
-
0.5
4,612.1
Stock
Change
0.5
(370.6)
(11.3)
(262.7)
(28.8)
(0.0)
(22.5)
(0.4)
(1.0)
(0.8)
(20.3)
54.9
(5.5)
1.6
(0.0)
(0.7)
(1.8)
0.3
(13.3)
-
0.4
(682.0)
U.S.
Bunkers Territories
-
-
-
-
-
9.8
-
-
5.5
-
93.8
-
79.2
311.8
108.7 130.8
656.2 151.8
-
-
-
-
1.3
-
-
-
76.7
1,076.6 548.9
Apparent
Consumption
107.6
15,068.4
5,832.6
1,132.9
(0.8)
(1,825.7)
22,575.2
30,060.8
2,782.6
1,691.7
562.7
0.6
78.3
(181.2)
127.6
(221.7)
111.6
(627.2)
303.1
(21.0)
(47.4)
(3.3)
62.3
-
76.4
77,646.3
Note: Totals may not sum due to independent rounding.
O-7
-------
Table O-4: 1996 Potential Carbon Emissions
Apparent Consumption (QBTU) Carbon Coefficients Potential Carbon Emissions
Fuel Category Fuel Type (MMTCE/QBTU) (MMTCE)
Solid Fuels
Gas Fuels
Liquid Fuels
Total
Anthracite Coal
Bituminous Coal
Sub-bituminous Coal
Lignite
Coke
Unspecified
Natural Gas
Crude Oil
Nat Gas Liquids and LRGs
Other Liquids
Motor Gasoline
Aviation Gasoline
Kerosene
Jet Fuel
Distillate Fuel
Residual Oil
Naptha for Petrofeed
Petroleum Coke
Other Oil for Petrofeed
Special Napthas
Lubricants
Waxes
Asphalt/Road Oil
Still Gas
Misc. Products
0.11
15.07
5.83
1.13
(0.00)
(1.83)
22.58
30.06
2.78
1.69
0.56
0.00
0.08
(0.18)
0.13
(0.22)
0.11
(0.63)
0.30
(0.02)
(0.05)
(0.00)
0.06
0.00
0.08
26.86
25.86
26.26
27.66
25.56
25.74
14.47
20.23
16.99
20.23
19.38
18.87
19.72
19.33
19.95
21.49
18.14
27.85
19.95
19.86
20.24
19.81
20.62
17.51
19.81
2.9
389.7
153.2
31.3
(0.0)
(47.0)
326.7
608.1
47.3
34.2
10.9
0.0
1.5
(3.5)
2.5
(4.8)
2.0
(17.5)
6.0
(0.4)
(1.0)
(0.1)
1.3
0.0
1.5
1545.0
Data Sources: Coal and Lignite - Revised 1996IPCC Guidelines Reference Manual, Table 1-1; Coke- EIA Monthly Energy Review, April 1998 Tabled; Unspecified Solid Fuels - EIA Monthly Energy Review, April 1998
Table C1 (U.S. Average); Natural Gas and Liquid Fuels - EIA Emissions of Greenhouse Gases in the United States 1996.
Note: Totals may not sum due to independent rounding.
O-8 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Table O-5: 1996 Carbon Stored in Products
Consumption for Non-
Fuel Use (Trillion BTU)
27.8
381.4
1175.9
1698.7
335.5
319.0
[1]
208.0
74.5
[1]
Ml
Carbon
(MMTCE/QBTU) (MMTCE)
25.53
14.47
20.62
16.99
20.24
18.24
[1]
27.85
19.86
[1]
Ml
Fraction
0.75
1.00
1.00
0.80
0.50
0.80
[1]
0.50
0
[1]
Ml
Carbon Sequestered
(MMTCE)
0.5
5.5
24.2
23.1
3.4
4.7
13.8
2.9
0.0
3.4
0.2
81.7
Values for Misc. U.S. Territories Petroleum, Petrochemical Feedstocks and Waxes/Misc. are not shown because these categories are aggregates of numerous smaller components.
Table O-6: Reference Approach CO2 Emissions from Fossil Fuel Consumption (MMTCE unless otherwise noted)
Fuel Category
Coal
Petroleum
Natural Gas
Total
Potential
Carbon
Emissions
530.0
688.3
326.7
1,545.0
Carbon
Sequestered
0.5
75.7
5.5
81.7
Net Carbon
Emissions
529.5
612.7
321.1
1463.3
Fraction
Oxidized
(percent)
99.0%
99.0%
99.5%
-
C02 Emissions
(MMTCE)
524.2
606.5
319.5
1450.3
C02 Emissions (Tg)
1922.1
2223.9
1171.6
5317.7
Note: Totals may not sum due to independent rounding.
O-9
-------
Table O-7: 1996 Energy Consumption in the United States: Sectoral vs. Reference Approaches (trillion BTU)
Approach
Sectoral3
Reference (Apparent)3
Difference
Coal
20,570
on ^-it;
-1.2%
Natural Gas
22,508
22,575
0.3%
Petroleum
36,340
34,756
-4.4%
Total
79,419
77,646
-2.2%
a Includes U.S. territories
Note: Totals may not sum due to independent rounding.
Table O-8: 1996 CO2 Emissions from Fossil Fuel Combustion by Estimating Approach (MMTCE)
Approach
Sectoral3
Reference3
Difference
Coal
524.0
594 9
0.0%
Natural Gas
318.6
319.5
0.3%
Petroleum
607.7
606.5
-0.2%
Total
1450.3
1450.3
0.0%
a Includes U.S. territories
Note: Totals may not sum due to independent rounding.
O-10U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
-------
Annex P
Preliminary 1997 Estimates of U.S. Greenhouse Gas Emissions and Sinks
This annex provides preliminary 1997 estimates of greenhouse gas emissions and sinks. Although these
calculations are not final, large changes are not expected, and therefore, this annex allows the reader to evaluate the
trend in U.S. emissions.
The following trends are evident based on a comparison of these preliminary 1997 estimates and 1990 through
1996 estimates found in the body of this report. In 1997, total U.S. emissions appear to have grown by 180 MMTCE
(11.0 percent) since 1990. Froml996to 1997, emissions rose by 1.4 percent, or 25 MMTCE. Tab leP-1 below shows
preliminary estimates in teragrams (Tg) of gas and MMTCE.
Specifically, emissions of CO2 increased by 10.6 percent over the 8 year period, and by 1.4 percent in the last
year. Increases in emissions from coal and natural gas combustionby utilities and petroleum consumption by industry
were responsible for the majority of this increase in emissions.
Methane emissions grew by 5.5 percent over the 1990 to 1997 period, and by 0.4 percent in the last year. From
1996 to 1997, most CH4 sources experienced small increases or decreases. Emissions from rice cultivation grew the
most in terms of percentage (10.1 percent), while landfill emissions grew the most absolutely (1.6 MMTCE).
Nitrous oxide emissions rose 13.8 percent over the 1990 to 1997 period. However, from 1996 to 1997, N2O
emissions increased by only 1.2 percent or 1.3 MMTCE. In the last year, emissions from adipic acid production
dropped by 37 percent due to improved industrial controls. As a percentage increase, emissions from manure
management rose the most (25.7 percent). The source contributing the most to the total N2O increase was agricultural
soil management (1.6 MMTCE).
Emissions of HFCs, PFCs, and SF6 showed a 6.4 percent increase from 1996 to 1997. Over the 1990 to 1997
period, emissions from this sector increased by 66.4 percent or 14.7 MMTCE. In the last year, emissions from HCFC-
22 production and semiconductor manufacture showed a slight decrease. However, increased emissions of 2.6
MMTCE from the substitution of ozone depleting substances offset this trend.
P-1
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Table P-1: Preliminary 1997 Estimates of U.S. Greenhouse Gas Emissions and Sinks
Gas/Source
C02
Fossil Fuel Combustion
Natural Gas Flaring
Cement Manufacture
Lime Manufacture
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Carbon Dioxide Manufacture
Land-Use Change and Forestry (Sink)3
CH4
Stationary Sources
Mobile Sources
Coal Mining
Natural Gas Systems
Petroleum Systems
Petrochemical Production
Silicon Carbide Production
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Residue Burning
Landfills
Wastewater Treatment
N20
Stationary Sources
Mobile Sources
Adipic Acid
Nitric Acid
Manure Management
Agricultural Soil Management
Agricultural Residue Burning
Human Sewage
Waste Combustion
MFCs, PFCs, and SFs
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production"
Semiconductor Manufacture
Electrical Transmission and Distribution0
Magnesium Production and Processing0
Total Emissions
Net Emissions
Note: Totals may not sum due to independent rounding.
+ Does not exceed 0.05 Tg or 0.05 MMTCE
M (Mixture of multiple gases)
NA (Not Applicable)
a Sinks are not included in C02 emissions total.
bHFC-23 emitted
°SF6 emitted
Tg
5,469.3
5,391.4
12.4
38.8
14.2
7.0
4.4
1.1
(764.7)
31.3
0.39
0.2
3.3
5.9
0.3
0.1
+
6.0
3.0
0.5
+
11.7
0.2
876.7
+
0.2
+
0.1
43.9
830.8
1.6
+
+
M
M
M
+
M
+
+
NA
NA
MMTCE
1,491.6
1,470.4
3.4
10.6
3.9
1.9
1.2
0.3
(208.6)
179.3
2.24
1.2
18.7
33.5
1.6
0.4
+
34.2
17.0
2.7
0.2
66.7
0.9
105.0
4.13
16.9
3.4
4.2
3.7
70.2
0.1
2.3
0.1
36.9
14.5
2.9
8.2
1.3
7.0
3.0
1812.9
1604.4
P-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
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Annex Q
Sources of Greenhouse Gas Emissions Excluded
Although this report is intended to be a comprehensive assessment of anthropogenic sources and sinks of
greenhouse gas emissions for the United States, certain sources have been identified yet excluded from the estimates
presented for various reasons. Before discussing these sources, however, it is important to note that processes or
activities that are not anthropogenic in origin or do not result in a net source or sink of greenhouse gas emissions are
intentionally excluded from a national inventory of greenhouse gas emissions. In general, processes or activities that
are not anthropogenic are considered natural (i.e., not directly influenced by human activity) in origin and, as an
example, would include the following:
Volcanic eruptions
CO2 exchange (i.e., uptake or release) by oceans
Natural forest fires19
CH4 emissions from wetlands not affected by human induced land-use changes
Some activities or process may be anthropogenic in origin but do not result in net emissions of greenhouse gases,
such as the respiration of CO2 by living organisms. Given a source category that is both anthropogenic and results
in net greenhouse gas emissions, reasons for excluding a source related to an anthropogenic activity include one or
more of the following:
There is currently insufficient scientific understanding to develop a reliable method for estimating emissions
at a national level.
Although an estimating method has been developed, data was not adequately available to calculate emissions.
Emissions were implicitly accounted for within another source category (e. g., CO2 from fossil fuel combustion).
It is also important to note that the United States believes the exclusion of the sources discussed below
introduces only a minor bias in its overall estimate of U.S. greenhouse gas emissions.
N2O from the Combustion of Jet Fuel
The combustion of jet fuel by aircraft results in N2O emissions. The N2O emissions per mass of fuel combusted
during landing/take-off (LTO) operations differ significantly from those during aircraft cruising. Accurate estimation
of these N2O emissions requires a detailed accounting of LTO cycles and fuel consumption during cruising by aircraft
model (e.g., Boeing 747-400). Sufficient data for calculating such N2O emissions were not available for this report.
(SQQ Revised 1996IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual, pp. 1.93 - 1.96)
Emissions from Bunker Fuels and Fossil Fuels Combusted Abroad by the U.S. Military
Emissions from fossil fuels combusted in military vehicles (i.e., ships, aircraft, and ground vehicles) may or may
not be included in U.S. energy statistics. Domestic fuel sales to the military are captured in U.S. energy statistics;
however, fuels purchased abroad for base operations and refueling of vehicles are not. It is not clear to what degree
fuels purchased domestically are exported by the military to bases abroad.
19 In some cases forest fires that are started either intentionally or unintentionally are viewed as mimicking natural burning
processes which have been suppressed by other human forest management activities. The United States does not consider
forest fires within its national boundaries to be a net source of greenhouse emissions.
Q-1
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Fuels combusted by military ships and aircraft while engaged in international transport or operations in
international waters or airspace (i.e., flying or cruising in international airspace or waters) that is purchased
domestically is included in U.S. energy statistics. Therefore, the United States currently under reports its emissions
of CO2 from international bunker fuels, and most likely over reports its CO2 emissions from transportation related
fossil fuel combustion by the same amount. At this time, fuel consumption statistics from the Department of Defense
are not adequately detailed to correct for this bias.20
CO2 from Burning in Coal Deposits and Waste Piles
Coal is periodically burned in deposits and waste piles. It has been estimated that the burning of coal in deposits
and waste piles would represent less than 1.3 percent of total U.S. coal consumption (averaged over ten-years).
Because there is currently no known source of data on the quantity of coal burned in waste piles and there is
uncertainty as to the fraction of coal which is oxidized during such burnings, these CO2 emissions are not currently
estimated. Further research would be required to develop accurate emission factors and activity data for these
emissions to be estimated, (see Revised 1996 IP CC Guidelines for National Greenhouse Gas Inventories: Reference
Manual, P- 1.112-1.113)
Fossil CO2from Petroleum and Natural Gas Wells, CO2 Separated from Natural Gas, and
CO2 from Enhanced Oil Recovery (EOR)
Petroleum and natural gas well drilling, petroleum and natural gas production, and natural gas
processing—including removal of CO2—may result in emissions of CO2 that was at one time stored in underground
formations. Sufficient methodologies for estimating emissions of this "fossil" CO2 at the national level have not been
adequately developed.
Carbon dioxide is also injected into underground deposits to increase crude oil reservoir pressure in a field
technique known as enhanced oil recovery (EOR). It is thought that much of the injected CO2 may be effectively and
permanently sequestered, but the fraction of injected CO2 which is re-released remains uncertain. The fraction re-
released varies from well to well depending upon the field geology and the gas capture/re-injection technology
employed at the wellhead. Further research into EOR is required before the resulting CO2 emissions canbe adequately
quantified, (see the discussion of the Carbon Dioxide Manufacture source category in the Industrial Processes sector)
Carbon Sequestration in Underground Injection Wells
Organic hazardous wastes are injected into underground wells. Depending on the source of these organic
substances (e.g., derived from fossil fuels) the carbon in them may or may not be included in U.S. CO2 emission
estimates. Sequestration of carbon containing substances in underground injection wells may be an unidentified sink.
Further research is required to if this potential sink is to be quantified.
CH4 from Abandoned Coal Mines
Abandoned coal mines are a source of CH4 emissions. In general, many of the same factors that affect emissions
from operating coal mines will affect emissions from abandoned mines such as the permeability and gassiness of the
coal, the mine's depth, geologic characteristics, and whether it has been flooded. A few gas developers have
recovered methane from abandoned mine workings; therefore, emissions from this source may not be insignificant.
Further research and methodological development is needed if these emissions are to be estimated.
CO2 from Unaccounted for Natural Gas
There is a discrepancy between the amount of natural gas sold by producers and that reported as purchased by
consumers. This discrepancy, known as unaccounted for or unmetered natural gas, was assumed to be the sum of
20 See the Defense Energy Support Center (formerly the Defense Fuel Supply Center), Fact Book 1997.
[http://www.desc.dla.mil/main/pulicati.htm]
Q-2 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
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leakage, measurement errors, data collection problems, undetected non-reporting, undetected overreporting, and
undetected underreporting. Historically, the amount of gas sold by producers has always exceeded that reportedly
purchased by consumers; therefore, some portion of unaccounted for natural gas was assumed to be a source of CO2
emissions. (It was assumed that consumers were underreporting their usage of natural gas.) In DOE/EIA's energy
statistics for 1996, however, reported consumption of natural gas exceeded the amount sold by producers. Therefore,
the historical explanation given for this discrepancy has lost credibility and unaccounted for natural gas is no longer
used to calculate CO2 emissions, (see section on Changes in the U.S. Greenhouse Gas Inventory Report)
CO2 from Shale Oil Production
Oil shale is shale saturated with kerogen.21 It can be thought of as the geological predecessor to crude oil.
Carbon dioxide is released as a by-product of the process of producing petroleum products from shale oil. As of now,
it is not cost-effective to mine and process shale oil into usable petroleum products. The only identified large-scale
oil shale processing facility in the U.S. was operated by Unocal during the year of 1985 to 1990. There have been
no known emissions from shale oil processing in the United States since 1990 when the Unocal facility closed.
CH4 from the Production of Carbides other than Silicon Carbide
Methane may be emitted from the production of carbides because the petroleum coke used in the process
contains volatile organic compounds which form methane during thermal decomposition. Methane emissions from
the production of silicon carbide were estimated and accounted for, but emissions from the production of calcium
carbide and other carbides were not. Further research is needed to estimate CH4 emissions from the production of
calcium carbide and other carbides other than silicon carbide, (see Revised 1996IPCC Guidelines for National
Greenhouse Gas Inventories: Reference Manual, pp. 2.20 - 2.21)
CO2 from Calcium Carbide and Silicon Carbide Production
Carbon dioxide is formed by the oxidation of petroleum coke in the production of both calcium carbide and
silicon carbide. These CO2 emissions are implicitly accounted for with emissions from the combustion of petroleum
coke under the Energy sector. There is currently not sufficient data on coke consumption to estimate emissions from
these sources explicitly. (see Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference
Manual, pp. 2.20-2.21)
CO2 from Graphite Consumption in Ferroalloy and Steel Production
The CO2 emissions from the three reducing agents used in ferroalloy and steel production—coke, wood (or
biomass), and graphite—are accounted for as follows:
Emissions resulting from the use of coke are accounted for in the Energy sector under fossil fuel combustion.
Estimating emissions from the use of wood or other biomass materials is unnecessary because these emissions
should be accounted for under Land-Use Change and Forestry sector if the biomass is harvested on an
unsustainable basis.
The CO2 emissions from the use of graphite, which is produced from petroleum by-products, may be accounted
for in the Energy sector (further analysis is required to determine if these emissions are being properly
estimated). The CO2 emissions from the use of natural graphite, however, have not been accounted for in the
estimate.
Emissions from graphite electrode consumption—versus its use as a reducing agent—in ferroalloy and steel
production may at present only be accounted for in part under fossil fuel combustion if the graphite used was derived
from a fossil fuel substrate (versus natural graphite ore). Further research into the source and total consumption of
21 Kerogen is fossilized insoluble organic material found in sedimentary rocks, usually shales, which can be converted to
petroleum products by distillation.
Q-3
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graphite for these purposes is required to explicitly estimate emissions, (see Iron and Steel Production and Ferroalloy
Production in the Industrial Processes sector)
N2O from Caprolactam Production
Caprolactam is a widely used chemical intermediate, primarily to produce nylon-6. All processes forproducing
caprolactam involve the catalytic oxidation of ammonia, with N2O being produced as a by-product. Caprolactam
production could be a significant source of N2O—it has been identified as such in the Netherlands. More research
is required to determine this source's significance because there is currently insufficient information available on
caprolactam production to estimate emissions in the United States, (see Revised 1996IPCC Guidelines for National
Greenhouse Gas Inventories: Reference Manual, pp. 2.22 - 2.23)
N2O from Cracking of Certain Oil Fractions
In order to improve the gasoline yield in crude oil refining, certain oil fractions are processed in a catcracker.
Because crude oil contains some nitrogen, N2O emissions may result from this cracking process. There is currently
insufficient data to develop a methodology for estimating these emissions, (see Revised 1996 IPCC Guidelines for
National Greenhouse Gas Inventories: Reference Manual, p. 2.23)
CH4 from Coke Production
Coke production may result in CH4 emissions. Detailed coke production statistics were not available for the
purposes of estimating CH4 emissions from this minor source, (see Petrochemical Production under the Industrial
Processes sector and the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual,
p. 2.23)
CO2 from Metal Production
Coke is used as a reducing agent in the production of some metals from their ores, including magnesium,
chromium, lead, nickel, silicon, tin, titanium, and zinc. Carbon dioxide may be emitted during the metal's production
from the oxidization of the coke used as a reducing agent and, in some cases, from the carbonate ores themselves (e.g.,
some magnesium ores contain carbonate). The CO2 emissions from coke oxidation are accounted for in the Energy
sector under Fossil Fuel Combustion. The CO2 emissions from the carbonate ores are not presently accounted for,
but their quantities are thought to be minor, (see Revised 1996 IPCC Guidelines for National Greenhouse Gas
Inventories: Reference Manual, p. 2.37 - 2.38)
N2O from Acrylonitrile Production
Nitrous oxide may be emitted during acrylonitrile production. No methodology was available for estimating
these emissions, and therefore further research is needed if these emissions are to be included, (see Revised 1996
IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual, p. 2.22)
Miscellaneous SF6 Uses
Sulfur hexafluoridemay be used in gas-filled athletic shoes, in foam insulation, for dry etching, in laser systems,
as an atmospheric tracer gas, for indoor air quality testing, for laboratory hood testing, for chromatography, in tandem
accelerators, in sound-insulating windows, in tennis balls, in loudspeakers, in shock absorbers, and for certain
biomedical applications. Data need to be gathered and methodologies developed if these emissions are to be
estimated.
CO2 from Solvent Incineration
CO2 may be released during the incineration of solvents. Although emissions from this source are believed to
be minor, data need to be gathered and methodologies developed if these emissions are to be estimated.
Q-4 U.S. Greenhouse Gas Emissions and Sinks: 1990-1996
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CO2 from Non-Forest Soils
Non-forest soils emit CO2 from decaying organic matter and carbonate minerals—the latter may be naturally
present or mined and later applied to soils as a means to adjust their acidity. Soil conditions, climate, and land-use
practices interact to affect the CO2 emission rates from non-forest soils. The U.S. Forest Service has developed a
model to estimate CO2 emissions from forest soils, but no such model has been adequately developed for non-forest
soils. Further research and methodological development is needed if these emissions are to be accurately estimated.
(see Changes in Non-Forest Carbon Stocks under the Land-Use Change and Forestry sector)
CH4 from Land-Use Changes Including Wetlands Creation or Destruction
Wetlands are a known source of CH4 emissions. When wetlands are destroyed, CH4 emissions may be reduced.
Conversely, when wetlands are created (e.g., during the construction of hydroelectric plants), CH4 emissions may
increase. Grasslands and forest lands may also be weak sinks for CH4 due to the presence of methanotrophic bacteria
that use CH4 as an energy source (i.e., they oxidize CH4 to CO2). Currently, an adequate scientific basis for estimating
these emissions and sinks does not exist, and therefore further research and methodological development is required.
CH4 from Septic Tanks and Drainfields
Methane is produced during the biodegradation of organics in septic tanks if other suitable electron-acceptors
(i.e., oxygen, nitrate, or sulfate) besides CO2 are unavailable. Such conditions are called methanogenic. There were
insufficient data and methodological developments available to estimate emissions from this source.
N2O from Wastewater Treatment
As a result of nitrification and denitrification processes, N2O may be produced and emitted from wastewater
treatment plants. Nitrogen-containing compounds are found in wastewater due to the presence of both human
excrement and other nitrogen-containing constituents (e.g. garbage, industrial wastes, dead animals, etc.). The portion
of emitted N2O which originates from human excrement is currently estimated under the Human Sewage source
category—based upon average dietary assumptions. The portion of emitted N2O which originates from other nitrogen-
containing constituents is not currently estimated. Further research and methodological development is needed if these
emissions are to be accurately estimated.
CH4 from Industrial Wastewater
Methane may be produced during the biodegradation of organics in wastewater treatment if other suitable
electron-acceptors (i.e. oxygen, nitrate, or sulfate) besides CO2 are unavailable. Such conditions are called
methanogenic. Methaneproduced from domestic wastewater treatment plants is accounted for under the Waste sector.
These emissions are estimated by assuming an average 5-day biological oxygen demand (BOD5) per capita
contribution in conjunction with the approximation that 15 percent of wastewater's BOD5 is removed under
methanogenic conditions. This method itself needs refinement. It is not clear if industrial wastewater sent to domestic
wastewater treatment plants, which may contain biodegradable material, would be accounted for in the average BOD5
per capita number. Additionally, CH4 emissions from methanogenic processes at industrial wastewater treatment
plants are not currently estimated. Further research and methodological development is needed if these emissions are
to be accurately estimated, (see Wastewater Treatment under the Waste sector)
Q-5
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United States
Enviromental Protection Agency
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Washington, DC 20460
Official Business
Penalty for Private Use
$300
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