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How to Obtain Copies
You may electronically download this document on the U.S. EPA's homepage at
http://www.epa.gov/globalwanning/emissions/national. To obtain additional copies of this report, call the National Service Center for
Environmental Publications (NSCEP) at (800) 490-9198.
For Further Information
Contact Mr. Wiley Barbour, Environmental Protection Agency, (202) 564-3999, barbour.wiley@epa.gov, or
Mr. Michael Gillenwater, Envirormental Protection Agency, (202) 564-4092.
For more information regarding climate change and greenhouse gas emissions, see EPA web site at http://www.epa.gov/globalwarming.
Released for printing: April 15,2001
Non-Energy Uses of Fossil Fuels
The products and production processes pictured on the front and back cover of this report depict non-energy uses of fossil fuels.
Rather than being combusted for energy, fuels consumed for non-energy purposes act as building blocks or reagents in fabricating
other materials. These fossil fuel-derived materials are important from an emissions perspective since they often provide long-term
storage of a portion of the fuel's carbon.
Refinery: Crude oil is a mixture of many hydrocarbon chains of various lengths. Refineries process crude
oil by distillation, separating the fuel into its hydrocarbon components according to their boiling points
and molecular weights. The oil "fractions" are further reacted through such processes as catalytic cracking
and hydroprocessing to form the petrochemical feedstocks that serve as the building blocks of synthetic
products.
gpspp P"f€%:
Plastics: Monomers derived from oil and natural gas are reacted to form polymeric resins for use
as plastics. Plastics store this fossil fuel carbon during their lifetime and, if recycled or landfilled, they
can continue to act to store carbon.
Asphalt: Asphalt is a product of the crude oil fractions with high boiling points and molecular weights.
These "heavy" fractions are mixed with rock aggregate when laid on roads and highways, storing the fossil
fuel carbon.
Textiles: Like plastics, synthetic fibers such as polyester, nylon, and acrylic are made from polymeric
resins derived from fossil fuels. The resins are spun into fibers that can be used in clothing, furniture,
safety equipment, and building materials. These products can also act to store their fossil fuel carbon.
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UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
OFFICE OF
AIR AND RADIATION
April 2001
The U.S. Environmental Protection Agency, in cooperation with other federal agencies,
has prepared the Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999. The
estimates of emissions and sequestration contained in this report, along with future updates, will
be used to monitor and track the progress of the United States in meeting our commitments under
the United Nations Framework Convention on Climate Change (UNFCCC).
In accordance with a decision of the Conference of Parties to the UNFCCC (Decision
3/CP.5), this inventory complies with the UNFCCC Reporting Guidelines on Annual Inventories
(FCCC/CP/1999/7). Adherence to these guidelines ensures that national inventories are well
documented, consistently prepared, and as accurate and complete as possible. The assumptions
and methodologies used in this report have been clearly explained, and are based on the Revised
1996IPCC Guidelines for National Greenhouse Gas Inventories and the IPCC Report on Good
Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories.
Each year, advances in scientific understanding and availability of underlying data allow
us to improve the quality and comprehensiveness of the inventory. A section entitled "Changes
in this Year's U.S. Greenhouse Gas Inventory Report," guides readers to specific areas where the
EPA has expanded coverage, improved methods, or added additional data since the previous
inventory publication.
Some of this year's advances include improved estimates for carbon stored in products
from non-energy uses of fossil fuels, non-CO2 emissions from mobile combustion, SF6 emissions
from magnesium production and processing, and new data on emissions from semiconductor
manufacturing. Also included for the first time this year are new data on Land-Use Change and
Forestry.
We hope that these improvements make this document more useful, and appreciate the
comments and suggestions we have received from numerous reviewers in both the scientific
community and the general public.
Robert J3renner
Assistant Administrator (acting)
Office of Air and Radiation
Internet Address (URL) • http://www.epa.gov
Recycled/Recyclable . Printed with Vegetable Oil Based Inks on Recycled Paper (Minimum 25% Postconsumer)
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Inventory of U.S. Greenhouse
Gas Emissions and Sinks:
April 15,2001
U.S. Environmental Protection Agency
Office of Atmospheric Programs (6202N)
1200 Pennsylvania Avenue, NW
Washington, DC 20460
USA
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Acknowledgments
"R^he Environmental Protection Agency would like to acknowledge the many individual and organizational
1 contributors to this document, without whose efforts this report would not be complete. Although the
complete list of researchers, government employees, and consultants who have provided technical and editorial
support is too long to list here, we would like to thank some key contributors and reviewers whose work has signifi-
cantly improved this year's report.
In particular, we wish to acknowledge the efforts of the Energy Information Administration and the Department
of Energy for providing detailed statistics and insightful analysis on numerous energy-related topics; the U.S. Forest
Service for preparing the forest carbon inventory, and the Department of Agriculture's Agricultural Research Service
for their work on nitrous oxide emissions from soils; and to the Department of Agriculture's Agriculture Research
Service and the Natural Resource Ecology Laboratory at Colorado State University for their work on carbon in agricul-
tural soils.
Within the EPA, many Offices contributed data, analysis and technical review for this report. The EPA Office of
Atmospheric Programs developed methodologies and provided detailed emission estimates for numerous source
categories, particularly for methane, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. The Office of
Transportation and Air Quality and the Office of Air Quality Planning and Standards provided analysis and review for
several of the source categories addressed in this report. The Office of Solid Waste and the Office of Research and
Development also contributed analysis and research.
Other government agencies have contributed data as well, including the U.S. Geological Survey, the Federal
Highway Administration, the Department of Transportation, the Bureau of Transportation Statistics, the Department of
Commerce, the National Agricultural Statistics Service, the Federal Aviation Administration, and the Department of
Defense.
Wiley Barbour and Michael Gillenwater directed the analytical development and writing of this report. Work on
fuel combustion and industrial process emissions was directed by Michael Gillenwater. Work on energy and waste
sector methane emissions was directed by Elizabeth Scheehle, while work on agriculture sector emissions was directed
by Tom Wirth. Work on emissions of HFCs, PFCs, and SF6 was directed by Reynaldo Forte and Sally Rand.
We would especially like to thank the staff of the Climate and Atmospheric Policy Practice at ICF Consulting,
especially Marian Martin, John Venezia, Kim Raby, Katrin Peterson, Barbara Braatz, Payton Decks, Susan Brown,
Randy Freed, Joe Casola, Diana Pape, Anne Choate, Noam Glick, Leonard Crook, Carrie Smith, Jeffrey King, and Heike
Mainhardt for synthesizing this report and preparing many of the individual analyses. Eastern Research Group also
provided significant analytical support.
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The United States Environmental Protection Agency (EPA) prepares the official U.S. Inventory of Greenhouse
Gas Emissions and Sinks to comply with existing commitments under the United Nations Framework Convention on
Climate Change (UNFCCC).1 Under a decision of the UNFCCC Conference of the Parties, national inventories for most
UNFCCC Annex I parties should be provided to the UNFCCC Secretariat each year by April 15.
In an effort to engage the public and researchers across the country, the EPA has instituted an annual public
review and comment process for this document. The availability of the draft document is announced via Federal
Register Notice and is posted on the EPA web page.2 Copies are also mailed upon request. The public comment period
is generally limited to 30 days; however, comments received after the closure of the public comment period are accepted
and considered for the next edition of this annual report. The EPA's policy is to allow at least 60 days for public review
and comment when proposing new regulations or documents supporting regulatory development—unless statutory
or judicial deadlines make a shorter time necessary—and 30 days for non-regulatory documents of. an informational
nature such as the Inventory document.
1 See http://www.unfccc.de
2 See http://www.epa.gov/globalwarming/emissions/national
ii Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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Table of Contents
Acknowledgments i
Preface ii
Table of Contents iii
List of Tables, Figures, and Boxes vi
Tables vi
Figures ix
Boxes x
Changes in This Year's Inventory Report xi
Changes in Historical Data xii
Methodological Changes xvii
Executive Summary ES-1
Recent Trends in U.S. Greenhouse Gas Emissions ES-2
Global Warming Potentials ES-12
Carbon Dioxide Emissions ES-13
Methane Emissions ES-18
Nitrous Oxide Emissions ES-21
HFC, PFC, and SF6 Emissions ES-22
Criteria Pollutant Emissions ES-25
1. Introduction 1-1
What is Climate Change? 1-2
Greenhouse Gases 1-2
Global Warming Potentials 1-6
Recent Trends in U.S. Greenhouse Gas Emissions 1-8
Uncertainty in and Limitations of Emission Estimates 1-18
Organization of Report 1-19
2. Energy 2-1
Carbon Dioxide Emissions from Fossil Fuel Combustion 2-2
Carbon Stored in Products from Non-Energy Uses of Fossil Fuels 2-20
Stationary Combustion (excluding CO2) 2-22
Mobile Combustion (excluding CO2) 2-26
Coal Mining 2-31
Natural Gas Systems 2-34
Petroleum Systems 2-36
Natural Gas Flaring and Criteria Pollutant Emissions from Oil and Gas Activities 2-38
International Bunker Fuels 2-40
Wood Biomass and Ethanol Consumption 2-45
3. Industrial Processes 3-1
Cement Manufacture 3-3
Lime Manufacture 3-6
Limestone and Dolomite Use 3-8
Soda Ash Manufacture and Consumption 3-10
Carbon Dioxide Consumption 3-12
Iron and Steel Production , 3-13
iii
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Ammonia Manufacture 3-14
Ferroalloy Production 3-15
Petrochemical Production 3-16
Silicon Carbide Production 3-18
Adipic Acid Production 3-18
Nitric Acid Production 3-20
Substitution of Ozone Depleting Substances ! 3-21
Aluminum Production 3-23
HCFC-22 Production 3-26
Semiconductor Manufacture 3-27
Electrical Transmission and Distribution 3-29
Magnesium Production and Processing 3-30
Industrial Sources of Criteria Pollutants 3-32
4. Solvent Use 4-1
5. Agriculture 5-1
Enteric Fermentation 5-2
Manure Management 5-5
Rice Cultivation 5-10
Agricultural Soil Management 5-15
Agricultural Residue Burning 5-20
6. Land-Use Change and Forestry 6-1
Changes hi Forest Carbon Stocks 6-2
Changes hi Agricultural Soil Carbon Stocks 6-8
Changes in Yard Trimming Carbon Stocks in Landfills .' 6-12
7. Waste : 7-1
Landfills 7-1
Waste Combustion 7-5
Wastewater Treatment 7-12
Human Sewage 7-15
Waste Sources of Criteria Pollutants 7-16
8. References 8-1
Changes in this Year's Inventory 8-1
Executive Summary 8-4
Introduction 8-4
Energy 8-5
Industrial Processes 8-11
Solvent Use 8-15
Agriculture 8-15
Land-Use Change and Forestry 8-25
Waste 8-28
Annexes
ANNEX A Methodology for Estimating Emissions of CO2 from Fossil Fuel Combustion A-l
ANNEXE Methodology for Estimating Carbon Stored in Products from Non-Energy Uses
of Fossil Fuels B-l
ANNEXC Methodology for Estimating Emissions of CH4, N2O, and Criteria Pollutants from
Stationary Combustion ; C-l
ANNEX D Methodology for Estimating Emissions of CH4, N2O, and Criteria Pollutants from
Mobile Combustion D-l
ANNEXE Methodology for Estimating CH4 Emissions from Coal Mining E-l
iv Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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ANNEXF Methodology for Estimating CH4 Emissions from Natural Gas Systems F-l
ANNEXG Methodology for Estimating CH4 Emissions from Petroleum Systems G-l
ANNEXH Methodology for Estimating Emissions from International Bunker Fuels Used
bytheU.S.MUitary H-l
ANNEXI Methodology for Estimating HFC, PFC, and SF6 Emissions from Substitution
of Ozone Depleting Substances 1-1
ANNEX! Methodology for Estimating CH4 Emissions from Enteric Fermentation J-l
ANNEXK Methodology for Estimating CH4 and N2O Emissions from Manure Management K-l
ANNEXL Methodology for Estimating N2O Emissions from Agricultural Soil Management L-l
ANNEXM Methodology for Estimating CH4 Emissions from Landfills M-l
ANNEXN Global Warming Potential Values N-l
ANNEXO Ozone Depleting Substance Emissions O-l
ANNEXP Sulfur Dioxide Emissions P-l
ANNEXQ Complete List of Source Categories Q-l
ANNEXR IPCC Reference Approach for Estimating CO2 Emissions from Fossil Fuel Combustion R-l
ANNEX S Sources of Greenhouse Gas Emissions Excluded S-l
ANNEXT Constants, Units, and Conversions T-l
ANNEXU Abbreviations U-l
ANNEXV Chemical Symbols V-l
ANNEX W Glossary W-l
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List of Tables,
Figures, and
Tables
Table ES-1: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (TgCO2Eq.)
Table ES-2: Annual Change in CO2 Emissions from Fossil Fuel Combustion for Selected Fuels
and Sectors (Tg CO2 Eq. and Percent) i. ES-5
Table ES-3: Recent Trends in Various U.S.Data (Index 1990= 100) ES-7
Table ES-4: Transportation-Related Greenhouse Gas Emissions (Tg CO2 Eq.) ES-11
Table ES-5: Electric Utility-Related Greenhouse Gas Emissions (TgCO2Eq.) ES-12
TableES-6: Global Warming Potentials (100 Year Time Horizon) ES-13
Table ES-7: U.S. Sources of CO2 Emissions and Sinks (TgCO2Eq.) ES-14
Table ES-8: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.) ES-15
Table ES-9: U.S. Sources of Methane Emissions (TgCO2Eq.) ES-19
Table ES-10: U.S. Sources of Nitrous Oxide Emissions (TgCO2Eq.) ES-21
TableES-11: Emissions of HFCs,PFCs, and SF6(TgCO2Eq.) ES-23
Table ES-12: Emissions of Ozone Depleting Substances (Gg) ES-24
Table ES-13: Emissions of NOX, CO, NMVOCs, and SO2 (Gg) ES-26
Table 1-1: Global Warmhig Potentials and Atmospheric Lifetimes (Years) 1-7
Table 1-2: Annual Change in CO2 Emissions from Fossil Fuel Combustion for Selected Fuels and
Sectors (Tg CO2 Eq. and Percent) .., 1-10
Table 1-3: Recent Trends in Various U.S. Data (Index 1990 = 100) 1-11
Table 1-4: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq.) ', 1-13
Table 1-5: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg) 1-14
Table 1-6: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector
(TgC02Eq.) 1-15
Table 1-7: Transportation-Related Greenhouse Gas Emissions (Tg CO2 Eq.) 1-16
Table 1-8: Electric Utility-Related Greenhouse Gas Emissions (Tg CO2 Eq.) 1-17
Table 1-9: IPCC Sector Descriptions 1-19
Table 1-10: List of Annexes 1-20
Table 2-1: Emissions from Energy (TgCO2Eq.) 2-2
Table 2-2: Emissions from Energy (Gg) 2-3
Table 2-3: CO2 Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg CO2 Eq.) 2-4
Table 2-4: Fossil Fuel Carbon in Products (Tg CO2 Eq.)* 2-8
Table 2-5: CO2 Emissions from International Bunker Fuels (TgCO2Eq.)* :. 2-8
Table 2-6: Fossil Fuel Carbon in Products and CO2 Emissions from International Bunker Fuel
Combustion (TgCO2Eq.) 2-9
Table 2-7: CO2 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg CO2 Eq.) .... 2-12
Table 2-8: Carbon Intensity from Direct Fossil Fuel Combustion by Sector (Tg CO2 Eq./EJ) 2-15
Table 2-9: Carbon Intensity from Energy Consumption by Sector (Tg CO2 Eq./EJ) 2-17
Table2-10: Change in CO2 Emissions from Direct Fossil Fuel Combustion Since 1990(TgCO2Eq.) 2-17
Table 2-11:1999 Non-Energy Fossil Fuel Consumption, Storage, and Emissions (Tg CO2 Eq. ;
unless otherwise noted) 2-21
Table 2-12: Storage and Emissions from Non-Energy Fossil Fuel Consumption (Tg CO2 Eq.) 2-21
Table 2-13: CH4 Emissions from Stationary Combustion (TgCO2Eq.) 2-23
Table 2-14: N2O Emissions from Stationary Combustion (Tg CO2 Eq.) 2-24
Table 2-15: CH4 Emissions from Stationary Combustion (Gg) 2-24
vi Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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Table 2-16: N2O Emissions from Stationary Combustion (Gg) 2-25
Table 2-17: NOX, CO, and NMVOC Emissions from Stationary Combustion in 1999 (Gg) 2-26
Table 2-18: CH4 Emissions from Mobile Combustion (TgCO2Eq.) 2-27
Table 2-19: N2O Emissions from Mobile Combustion (TgCO2Eq.) 2-27
Table 2-20: CH4 Emissions from Mobile Combustion (Gg) 2-28
Table 2-21: N2O Emissions from Mobile Combustion (Gg) 2-28
Table 2-22: NOX, CO, and NMVOC Emissions from Mobile Combustion in 1999 (Gg) 2-29
Table 2-23: CH4 Emissions from Coal Mining (TgCO2Eq.) 2-32
Table 2-24: CH4 Emissions from Coal Mining (Gg) 2-32
Table 2-25: Coal Production (Thousand Metric Tons) 2-34
Table 2-26: CH4 Emissions from Natural Gas Systems (TgCO2Eq.) 2-35
Table 2-27: CH4 Emissions from Natural Gas Systems (Gg) 2-35
Table 2-28: CH4 Emissions from Petroleum Systems (Tg CO2Eq.) 2-37
Table 2-29: CH4 Emissions from Petroleum Systems (Gg) 2-37
Table 2-30: Uncertainty in CH4 Emissions from Production Field Operations (Gg) 2-39
Table 2-31: CO2 Emissions from Natural Gas Flaring 2-39
Table 2-32: NOX, NMVOCs, and CO Emissions from Oil and Gas Activities (Gg) 2-39
Table 2-33: Total Natural Gas Reported Vented and Flared (Million Ft3) and Thermal Conversion
Factor (B to/Ft3) 2-40
Table 2-34: Emissions from International Bunker Fuels (TgCO2Eq.) 2-42
Table 2-35: Emissions from International Bunker Fuels (Gg) 2-42
Table 2-36: Aviation Jet Fuel Consumption for International Transport (Million Gallons) 2-43
Table 2-37: Marine Fuel Consumption for International Transport (Million Gallons) 2-44
Table 2-38: CO2 Emissions from Wood Consumption by End-Use Sector (Tg CO2 Eq.) 2-45
Table 2-39: CO2 Emissions from Wood Consumption by End-Use Sector (Gg) 2-45
Table 2-40 :CO2 Emissions from Ethanol Consumption 2-46
Table 2-41: Woody Biomass Consumption by Sector (Trillion Btu) 2-46
Table 2-42: Ethanol Consumption 2-46
Table 3-1: Emissions from Industrial Processes (TgCO2Eq.) 3-3
Table 3-2: Emissions from Industrial Processes (Gg) 3-4
Table 3-3: CO2 Emissions from Cement Production 34
Table 3-4: Cement Production (Gg) 3-5
Table 3-5: Net CO2 Emissions from Lime Manufacture 3-6
Table 3-6: CO2 Emissions from Lime Manufacture (Gg) 3-6
Table 3-7: Lime Production and Lime Use for Sugar Refining and PCC (Thousand Metric Tons) 3-7
Table 3-8: Hydrated Lime Production (Thousand Metric Tons) 3-7
Table 3-9: CO2 Emissions from Limestone & Dolomite Use (TgCO2Eq.) 3-9
Table 3-10: CO2 Emissions from Limestone & Dolomite Use (Gg) 3-9
Table 3-11: Limestone and Dolomite Consumption (Thousand Metric Tons) 3-9
Table 3-12: CO2 Emissions from Soda Ash Manufacture and Consumption 3-11
Table 3-13: CO2 Emissions from Soda Ash Manufacture and Consumption (Gg) 3-11
Table 3-14: Soda Ash Manufacture and Consumption (Thousand Metric Tons) 3-12
Table 3-15: CO2 Emissions from Carbon Dioxide Consumption 3-12
Table 3-16: Carbon Dioxide Consumption 3-13
Table 3-17: CO2 Emissions from Iron and Steel Production 3-14
Table 3-18: Pig Iron Production 3-14
Table 3-19: CO2 Emissions from Ammonia Manufacture 3-15
Table 3-20: Ammonia Manufacture 3-15
Table 3-21:CO2 Emissions from Ferroalloy Production 3-16
Table 3-22: Production of Ferroalloys (Metric Tons) 3-16
Table 3-23: CH4 Emissions from Petrochemical Production 3-17
Table 3-24: Production of Selected Petrochemicals (Thousand Metric Tons) 3-17
Table 3-25: CH4 Emissions from Silicon Carbide Production 3-18
Table 3-26: Production of Silicon Carbide 3-18
VII
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Table 3-27: N2O Emissions from Adipic Acid Production 3-19
Table 3-28: Adipic Acid Production 3-20
Table 3-29: N2O Emissions from Nitric Acid Production 3-21
Table 3-30: Nitric Acid Production 3-21
Table 3-31: Emissions of HFCs andPFCs fromODS Substitution (Tg CO2Eq.) 3-22
Table 3-32: Emissions of HFCs and PFCs from CDS Substitution (Mg) .' 3-23
Table 3-33: CO2 Emissions from Aluminum Production 3-24
Table3-34: PFC Emissions from Aluminum Production (TgCO2Eq.) 3-24
Table3-35: PFC Emissions from Aluminum Production (Gg) 3-24
Table3-36: Production of Primary Aluminum 3-25
Table3-37: HFC-23 Emissions fromHCFC-22 Production 3-26
Table 3-38: Emissions of Fluorinated Greenhouse Gases from Semiconductor Manufacture 3-27
Table 3-39: SF6 Emissions from Electrical Transmission and Distribution 3-29
Table 3-40: SF6 Emissions from Magnesium Production and Processing 3-30
Table 3-41: 1999 Potential and Actual Emissions of HFCs, PFCs, and SF6 from Selected Sources
(TgC02Eq.) '. 3-31
Table 3-42: NOX, CO, and NMVOC Emissions from Industrial Processes (Gg) 3-32
Table4-l: Emissions of NOX, CO, andNMVOC from Solvent Use(Gg) 4-2
Table 5-1: Emissions from Agriculture (TgCO2Eq.) i 5-2
Table 5-2: Emissions from Agriculture (Gg) 5-2
Table 5-3: CH4 Emissions from Enteric Fermentation (TgCO2Eq.) 5-3
Table 5-4: CH4 Emissions from Enteric Fermentation (Gg) 5-3
Table 5-5: CH4 and N2O Emissions from Manure Management (TgCO2Eq.) 5-7
Table 5-6: CH4 Emissions from Manure Management (Gg) 5-7
Table 5-7: N2O Emissions from Manure Management (Gg) 5-7
Table 5-8: CH4 Emissions from Rice Cultivation (TgCO2Eq.) 5-12
Table 5-9: CH4 Emissions from Rice Cultivation (Gg) 5-12
Table 5-10: Rice Areas Harvested (Hectares) - 5-14
Table 5-11: Rice Hooding Season Lengths (Days) 5-14
Table 5-12: N2O Emissions from Agricultural Soil Management (TgCO2Eq.) 5-17
Table5-13:N2O Emissions from Agricultural Soil Management (Gg) 5-17
Table 5-14: Direct N2O Emissions from Managed Soils (TgCO2Eq.) 5-17
Table 5-15: Direct N2O Emissions from Pasture, Range, and Paddock Livestock Manure (Tg CO2 Eq.) 5-17
TableS-16:IndirectN2O.Emissions (TgCO2Eq.) 5-18
Table 5-17: Emissions from Agricultural Residue Burning (TgCO2Eq.) 5-21
Table 5-18: Emissions from Agricultural Residue Burning (Gg) 5-22
Table 5-19: Agricultural Crop Production (Thousand Metric Tons of Product) 5-23
Table 5-20: Percentage of Rice Area Burned by State , 5-23
Table 5-21: Percentage of Rice Area Burned 5-23
Table 5-22: Key Assumptions for Estimating Emissions from Agricultural Residue Burning 5-24
Table 5-23: Greenhouse Gas Emission Ratios 5-24
Table 6-1: Net CO2 Flux from Land-Use Change and Forestry (TgCO2Eq.) • 6-2
Table 6-2: Net CO2 Flux from Land-Use Change and Forestry (TgC) : 6-2
Table 6-3: Net CO2 Flux from U.S. Forests (TgCO2Eq.) , 64
Table 6-4: Net CO2 Flux from U.S. Forests (TgC) 64
Table 6-5: U.S. Forest Carbon Stock Estimates (Tg C) 64
Table 6-6: Net CO2 Flux From Agricultural Soils (TgCO2Eq.) 6-9
Table 6-7: Quantities of Applied Minerals (Thousand Metric Tons) 6-11
Table 6-8: Net CO2 from Landfilled Yard Trimmings 6-12
Table 6-9: Composition of Yard Trimmings in MSW and Carbon Storage Factor (Gg C/Gg yard trimmings). 6-13
Table 6-10: Yard Trimmings Disposal to Landfills 6-13
viii Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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Table 7-1: Emissions from Waste (TgCO2Eq.) 7-2
Table 7-2: Emissions from Waste (Gg) 7-2
Table 7-3 :CH4 Emissions from Landfills (TgCO2Eq.) 7-3
Table 7-4: CH4 Emissions from Landfills (Gg) 7-3
Table 7-5: CO2 and N2O Emissions from Municipal Solid Waste Combustion (Tg CO2 Eq.) 7-6
Table 7-6: CO2 and N2O Emissions from Municipal Solid Waste Combustion (Gg) 7-6
Table 7-7: CO2 Emissions from Hazardous Waste Combustion 7-7
Table 7-8:1998 Plastics in the Municipal Solid Waste Stream by Resin (Gg) 7-7
Table 7-9:1998 Plastics Combusted (Gg), Carbon Content (%), and Carbon Combusted (Gg) 7-7
Table 7-10: Elastomers Consumed in 1998 (Gg) 7-8
Table 7-11: Scrap Tire Constituents and CO2 Emissions from Scrap Tke Combustion in 1998 7-9
Table 7-12: Rubber and Leather in Municipal Solid Waste in 1998 7-9
Table 7-13: Textiles in MSW(Gg) 7-9
Table 7-14: Synthetic Fiber Production in 1998 7-10
Table 7-15: Assumed Composition of Combusted Hazardous Waste by Weight (Percent) 7-10
Table 7-16: Municipal Solid Waste Generation (Metric Tons) and Percent Combusted 7-11
Table 7-17: U.S. Municipal Solid Waste Combusted by Data Source (Metric Tons) 7-12
Table 7-18: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Tg CO2 Eq.) 7-13
Table 7-19: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Gg) 7-13
Table 7-20: U.S. Population (Millions) and Wastewater BOD Produced (Gg) 7-14
Table 7-21: U.S. Pulp and Paper Production (Million Metric Tons) and Wastewater BOD Removed (Gg) 7-15
Table 7-22: N2O Emissions from Human Sewage 7-15
Table 7-23: U.S. Population (Millions) and Average Protein Intake (kg/Person/Year) 7-16
Table 7-24: Emissions of NOX, CO, and NMVOC from Waste (Gg) 7-17
Figures
Figure ES-l: U.S. GHG Emissions by Gas ES-3
Figure ES-2: Annual Percent Change in U.S. GHGEmissions ES-3
Figure ES-3: Absolute Change in U.S. GHG Emissions Since 1990 ES-3
Figure ES-4:1999 GHG Emissions by Gas ES-3
Figure ES-5: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product ES-7
Figure ES-6: Percent Difference in Adjusted and Actual Energy-Related CO2 Emissions ES-8
Figure ES-7: Recent Trends in Adjusted and Actual Energy-Related CO2 Emissions ES-8
Figure ES-8: Annual Deviations from Normal Heating Degree Days for the United States (1949-1999) ES-9
Figure ES-9: Annual Deviations from Normal Cooling Degree Days for the United States (1949-1999) ES-9
Figure ES-10: Nuclear and Hydroelectric Power Plant Capacity Factors in the United States (1973-1999) ..ES-10
Figure ES-l 1:1999 Sources of CO2 ES-13
Figure ES-12:1999 U.S. Energy Consumption by Energy Source ES-14
Figure ES-13: U.S. Energy Consumption (Quadrillion Btu) ES-14
Figure ES-14:1999 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type ES-16
Figure ES-15:1999 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion ES-16
Figure ES-16:1999 Sources of CH4 ES-18
Figure ES-17:1999 Sources of N2O ES-21
Figure ES-18:1999 Sources of HFCs,PFCs, and SF6 ES-23
Figure 1-1: U.S. GHG Emissions by Gas 1-8
Figure 1-2: Annual Percent Change in U.S. GHG Emissions 1-8
Figure 1-3: Absolute Change in U.S. GHG Emissions Since 1990 1-9
Figure 1-4: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product 1-11
Figure 1-5: U.S. GHG Emissions by Chapter/IPCC Sector 1-12
IX
-------
Figure 2-1: 1999 Energy Chapter GHG Sources 2-1
Figure 2-2: 1999 U.S. Energy Consumption by Energy Source 2-3
Figure 2-3: U.S. Energy Consumption (Quadrillion Btu) 2-3
Figure 2-4: 1999 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type 2-4
Figure 2-5: Percent Difference in Adjusted and Actual Energy-Related CO2 Emissions 2-5
Figure 2-6: Recent Trends in Adjusted and Actual Energy-Related CO2 Emissions ; 2-5
Figure 2-7: Annual Deviations from Normal Heating Degree Days for the United States (1949-1999) 2-6
Figure 2-8: Annual Deviations fromNormal Cooling Degree Days for the United States (1949-1999) 2-6
Figure 2-9: Nuclear and Hydroelectric Power Plant Capacity Factors in the United States (1973-1999) 2-7
Figure 2-10:1999 End-Use Sector Emissions of CO2 from Fossil Fuel Combustion 2-8
Figure 2-11: Industrial Production Indexes (Index 1992=100) 2-10
Figure 2-12: Motor Gasoline Retail Prices (Real) 2-11
Figure 2-13: Motor Vehicle Fuel Efficiency • 2-11
Figure 2-14: Heating Degree Days 2-13
Figure 2-15: Cooling Degree Days 2-13
Figure 2-16: Electric Utility Retail Sales by End-Use Sector 2-14
Figure 2-17: Net Generation by Electric Utilities and Nonutilities 2-14
Figure 2-18: U.S. Energy Consumption and Energy-Related CO2 Emissions Per Capita and Per Dollar GDP 2-16
Figure 2-19: Change in CO2 Emissions from Fossil Fuel Combustion Since 1990 by End-Use Sector 2-16
Figure 2-20: Mobile Source CH4 and N2O Emissions • 2-30
Figure 3-1:1999 Industrial Processes Chapter GHG Sources 3-1
FigureS-1:1999 Agriculture Chapter GHG Sources • 5-1
Figure 5-2: Sources of N2O Emissions from Agricultural Soils 5-15
Figure 7-1:1999 Waste Chapter GHG Sources • 7-1
Boxes
Box ES-l: Emission Reporting Nomenclature • ES-2
Box ES-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data ES-7
Box ES-3: Weather and Non-Fossil Energy Adjustments to CO2 from Fossil Fuel Combustion Trends ES-8
Box ES-4: Greenhouse Gas Emissions from Transportation Activities < ES-10
Box ES- 5: Greenhouse Gas Emissions from Electric Utilities ES-12
Box ES-6: Emissions of Ozone Depleting Substances ES-24
Box ES-7: Sources and Effects of Sulfur Dioxide ES-25
Box 1-1: Emission Reporting Nomenclature r 1-7
Box 1-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data 1-11
Box 1-3: Greenhouse Gas Emissions from Transportation Activities 1-15
Box 1-4: Greenhouse Gas Emissions from Electric Utilities 1-16
Box 1-5: IPCC Good Practice Guidance • 1-17
Box 2-1: Weather and Non-Fossil Energy Adjustments to CO2 from Fossil Fuel Combustion Trends 2-5
Box 2-2: Sectoral Carbon Intensity Trends Related to Fossil Fuel and Overall Energy Consumption 2-15
Box 3-1: Potential Emission Estimates of HFCs, PFCs, and SF6 3-31
Box 6-1: Comparison to forest carbon stock and flux estimates in the United States Submission on Land Use,
Land-Use Change, and Forestry 6-7
Box 7-1: Biogenic Emissions and Sinks of Carbon 7-3
Box 7-2: Recycling and Greenhouse Gas Emissions and Sinks 7-4
x Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Changes in This Year's
Inventory Report
Each year the EPA not only recalculates and revises the emission and sink estimates for all years that are
presented in the Inventory of U.S. Greenhouse Gas Emissions and Sinks but also attempts to improve the
analyses themselves through the use of better methods or data as well as the overall usefulness of the report. A
summary of this year's changes is presented in the following sections and includes updates to historical data in
addition to changes in methodology. The magnitude of each change is also described. Table Changes-1 summarizes the
quantitative effect of these changes on U.S. greenhouse gas emissions and Table Changes-2 summarizes the quantita-
tive effect on U.S. sinks, both relative to the previously published U.S. Inventory (i.e., 1990-1998 report). These tables
present the magnitude of these changes in units of teragrams of carbon dioxide (CO2) equivalents (Tg CO2 Eq.). (See
Box Changes-1.)
Changes in historical data are generally the result of changes in statistical data supplied by other agencies. Data
sources are provided for further reference.
For methodological changes, differences between the previous Inventory report and this report are explained. In
general, when methodological changes have been implemented, the entire time series (i.e., 1990 through 1998) has been
recalculated to reflect the change.
Box Changes -1: Emission Reporting Nomenclature
The Global Warming Potential (GWP) weighted emissions of all direct greenhouse gases in this report are presented in terms of
equivalent emissions of carbon dioxide (C02), using units of teragrams of carbon dioxide equivalents (Tg C02 Eq.). In previous year's
inventories emissions were reported in terms of carbon—versus carbon dioxide—equivalent emissions, using units of million metric
tons of carbon equivalents (MMTCE). This change of units for reporting was implemented so that the U.S. Inventory would be more
consistent with international practices, which are to report emissions in carbon dioxide equivalent units.
In order to convert the emission estimates presented in this report to those provided previously, the following equation can be
employed:
Tg C02 Eq. = MMTCE x (44/12)
There are two elements to the conversion. The first element is simply nomenclature, since one teragram is equal to one million
metric ton:
Tg = 109 kg = 106 metric tons = megaton = 1 million metric tons
The second element is the conversion, by weight, from carbon to carbon dioxide. The molecular weight of carbon is 12, and the
molecular weight of oxygen is 16; therefore, the molecular weight of C02 is 44 (i.e., 12+[16x2]), as compared to 12 for carbon alone.
Thus, carbon comprises 12/44ths of carbon dioxide by weight.
xi
-------
Table Changes -1: Revisions to U.S. Greenhouse Gas Emissions (Tg C02 Eq.)
Gas/Source
C02
Waste Combustion
Fossil Fuel Combustion
Natural Gas Raring
Other3
CH4
Manure Management
Wastewater Treatment
Enteric Fermentation
Landfills
Other3
N20
Manure Management
Mobile Sources
Agricultural Soil Management
Other3
HFCs, PFCs, and SF6
Magnesium Production
and Processing
Substitution of Ozone
- Depleting Substances
Other3
Net Change in Total Emissions"
Percent Change
1990
(1.4)
7.2
(4.8)
(4.0)
0.1
(7.7)
(28.5)
8.0
9.5
3.7
(0.4)
+
3.7
3.9
(7.2)
(0.4)
(1.5)
(0.7)
NC
(0.8)
(10.6)
-0.2%
1991
(1.1)
8.3
(5.5)
(4.0)
0.1
(8.7)
(29.4)
8.1
8.6
4.3
(0.4)
(0.8)
3.5
4.1
(8.1)
(0.4)
(1.8)
(1.7)
NC
(0.1)
(12.5)
-0.2%
1992
9.4
8.9
4.2
(3.9)
0.1
(9.4)
(31.0)
8.2
10.2
3.5
(0.4)
0.1
3.4
4.2
(7.1)
(0.4)
(2.7)
(2.6)
NC
(0.1)
(2.6)
+%
1993
0.7
9.7
(5.4)
(3.7)
0.1
(17.1)
(34.7)
8.3
6.0
3.9
(0.6)
(1.3)
3.3
4.1
(8.3)
(0.4)
(3.6)
(3.7)
NC
0.1
(21.3)
-0.3%
1994
18.0
10.7
11.2
(3.6)
(0.2)
(19.5)
(38.6)
8.4
9.1
3.3
(1.8)
(2.4)
3.0
3.6
(8.7)
(0.3)
(5.1)
(4.9)
(0.1)
(0.1)
(8.9)
-0.1%
1995
26.0
12.0
17.4
(3.6)
0.2
(24.6)
(41.4)
8.5
8.3
1.0
(1.2)
(3.8)
2.7
2.9
(9.6)
0.2
(7.3)
(5.5)
(1.6)
(0.3)
(9.7)
-0.2%
1996
27.1
12.5
18.1
(3.5)
0.1
(33.5)
(44.2)
8.5
5.5
(1.5)
(1.8)
(4.0)
2.8
1.2
(7.6)
(0.4)
(7.8)
(5.4)
(2.4)
+
(18.2)
-0.3%
1997
28.7
13.1
19.0
(3.5)
+
(41.7)
(48.5)
8.6
4.2
(2.9)
(3.2)
(4.8)
2.8
1.8
(9.0)
(0.3)
(6.3)
(3.5)
(2.9)
0.1
(24.2)
-0.4%
1998
11.7
12.3
3.3
(3.4)
(0.5)
(38.6)
(48.6)
8.7
3.9
(2.0)
(0-7)
(4.0)
2.5
1.2
(7.2)
(0.5)
(9.2)
(4.7)
(3.5)
(1.0)
(40.2)
-0.6%
+ Does not exceed 0.05 TO C02 Eq.
"Includes other source categories with only minor or no versions made to emission estimates.
1 b Excludes emissions from international bunker fuels and carbon sinks.
NC (No Change)
'-. Note: Totals may not sum due to independent rounding.
Changes in Historical Data
In the CO2 Emissions from Fossil Fuel Combustion
section of the Energy chapter, energy consumption
data have been updated by the Energy Information
Administration (EIA 2000a, 2000b, 2000c) for selected
years (see below for detail on methodological
changes). For example, the amount of coal com-
busted in the industrial end-use sector by nonutility
generators of electricity was reused upward, result-
ing in an average 31.1 Tg CO2 Eq. increase in emis-
sions. In addition, the carbon content coefficients
for motor gasoline blend components, unfinished
oils, and miscellaneous petroleum products were re-
vised from static to annually variable coefficients,
based on EIA (2000b). The annually variable carbon
content coefficients for coal (i.e., residential, com-
mercial, industrial coking, industrial other, and utility
coal) were expanded to include more significant dig-
its, also based on EIA (2000b). These data changes,
combined with the methodological changes de-
scribed below, resulted in an average increase of 6.4
Tg of CO2Eq. (0.1 percent) in annual CO2 emissions
from fossil fuel combustion for 1990 through 1998.
In the Stationary Combustion (excluding CO2) sec-
tion of the Energy chapter, two revisions to the en-
ergy consumption data were made. First, the EIA has
provided estimates for commercial wood energy con-
sumption for 1990 through 1992, which were previ-
ously not provided, and has revised the wood en-
ergy consumption data for the remaining years. Sec-
ond, wood biomass has been reported separately
x!i Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table Changes-2: Revisions to Net C02 Sequestration from Land-Use Change and Forestry (Tg C02 Eq.)
I Component
1990 1991
1992 1993 1994 1995 1996 1997 1998
tforest^
I Agricultural Soils
if Landfilled Yard Trimmings
f Total Change in Land-Use
L Change and Forestry
r Sequestration
Percent Change
140.5
(40.4)
NC
152.6
(39.7)
NC
204.3
(40.9)
NC
(174.3)
(70.0)
NC
(180.9)
(69.3)
NC
(173.6)
(68.8)
NC
(178.0)
(68.9)
NC
(138.8)
(69.0)
NC
(132.5)
(77.3)
(0.5)
100.1 112.9
-8.6% -11.2%
163.4
-15.6%
(244.3)
29.4%
(250.2) (242.4)
30.4% 31.2%
(246.9)
31.9%
(207.8)
26.8%
(210.3)
27.2%
JC (No Change)
Jjote: Numbers in parentheses indicate an increase in estimated net sequestration, or a decrease in net flux of C02 to the atmosphere. In the
''"percent change" row, negative numbers indicate that the sequestration estimate has decreased, and positive numbers indicate that the
-sequestration estimate has increased. These percents are based on sequestration estimates that were rounded to the nearest 102 gigagram
IC02. The previously published U.S. Inventory did not include agricultural soils in the total flux estimates for land-use change and forestry, so
|jhe data in the "agricultural soils" row are equal to the agricultural soil sequestration estimates presented in this Inventory. Totals may not
ivSum due to independent rounding.
from wood wastes, liquors, municipal solid waste,
tires, etc., in EIA's estimates of consumption for fuel
combustion (EIA 2000a). Only estimates of wood
consumption were used to calculate non-CO2 emis-
sions from stationary combustion. These revisions
resulted in average decrease of 0.2 Tg CO2 Eq. (2.8
percent) in annual stationary combustion methane
emissions for 1990 through 1998. The average de-
crease in N2O emissions was 0.4 Tg CO2 Eq. (2.9
percent) for 1990 through 1998.
In the Mobile Combustion (excluding CO2) section
of the Energy Chapter, estimates of 1996 to 1998 ve-
hicle miles traveled were revised by the Federal High-
way Administration (FHWA1999). This data change,
combined with the methodological changes de-
scribed below, resulted in an average decrease of 0.4
Tg CO2 Eq. (7.1 percent) in annual methane emis-
sions for 1990 through 1998. Average N2O emissions
increased by 3.0 Tg CO2 Eq. (5.2 percent) annually
for 1990 through 1998.
In the Coal Mining section of the Energy chapter,
data on underground emissions have been revised
and State gas sales data and coal production totals
have been updated by DOE's Energy Information
Administration (EIA 2000e). Due to improvements in
the data, this year's inventory includes 5 additional
coal mines for the 1998 data. Each year, States pro-
vide gas sales data, which are used to estimate emis-
sions avoided from gas recovery projects. Previously,
gas sales data for 1998 were not available, but this
inventory reflects the final data from the States. Fi-
nally, DOE's EIA reports surface and underground
production in the Coal Industry Annual (EIA 1999a).
Although total production was available for 1998,
the apportionment to surface and underground min-
ing was not available. The total coal production val-
ues remain unchanged. These revisions result hi an
annual increase in CH4 emissions of 1.3 Tg CO2 Eq.
(2.0 percent) for 1998.
In the Natural Gas Systems section of the Energy
chapter, methane emission estimates have been re-
vised to incorporate new activity driver data on gas
wells for 1997 and 1998 (AGA 1998,1999a, 1999b,
2000, IPAA 1999). These data changes, combined
with the methodological changes described below,
resulted in an average decrease of 0.6 Tg CO2 Eq.
(0.5 percent) in annual methane emissions from natu-
ral gas systems from 1990 through 1998.
In the Natural Gas Flaring and Criteria Pollutant Emis-
sions in the Oil and Gas Activities section of the
Energy chapter, a conversion factor accounting for
the vented gas from petroleum systems has been
corrected from previous reports. The amount of natu-
ral gas flared is calculated by subtracting the vented
gas emissions from the total gas reported by EIA as
combined vented and flared gas (EIA 2000d). Previ-
xiii
-------
ously, the conversion value for vented gas was mis-
calculated, causing the amount of gas vented to ap-
pear negligible. Correction of the conversion factor
caused the estimate of natural gas vented to increase
to between 20 and 40 percent of the total gas vented
and flared. This caused an associated average de-
crease in annual CO2 emissions from natural gas flar-
ing of 3.7 Tg CO2Eq. (29 percent) from 1990 through
1998. The EPA (2000b) has also revised estimates for
criteria pollutants from oil and gas activities for 1990
through 1998. These revisions resulted in average
increases of 3.5 percent in annual NOX emissions,
and 3.1 percent hi annual CO emissions, and an aver-
age annual decrease of 0.1 percent in NMVOC emis-
sions from 1990 through 1998.
• In the International Bunker Fuels section of the En-
ergy chapter, civil marine bunker fuel data for 1990
were revised with previously unavailable data pro-
vided by DOC (2000). In addition, activity data for
foreign airlines at U.S. airports in 1998 have been
adjusted (BEA 2000). Lastly, DESC (2000) revised their
estimates of jet fuel and aviation gasoline consump-
tion by the military for international bunkers for 1990
to 1994. These revisions resulted hi a decrease in
CO2emissions of 4.0 Tg CO2 Eq. (3.4 percent) in 1990
and a decrease of 1.9 Tg CO2 Eq. (1.7 percent) in
1998. The new civil marine bunker fuel data ac-
counted for almost all of the decrease in CO2 emis-
sions for 1990. Methane emissions have decreased
by less than 0.1 Tg CO2 Eq. (1.9 percent) in 1990 and
less than 0.1 Tg CO2 Eq. (2.5 percent) in 1998. Ni-
trous oxide emissions have decreased by less than
0.1 Tg CO2 Eq. (3.0 percent) hi 1990 and less than 0.1
Tg CO2 Eq. (1.9 percent) in 1998.
• In the Limestone and Dolomite Use section of the
Industrial Processes chapter, the activity data used
to calculate CO2 emissions for have been revised to
incorporate published 1994 limestone and dolomite
consumption (USGS 1995). Previously, limestone and
dolomite consumption for 1994 was interpolated us-
ing 1993 and 1995 data. Additionally, estimates of the
amount of limestone used in glassmaking have been
revised for 1996 through 1998. In previous invento-
ries, milestone used hi glass making for 1996 through
1998 was assumed to account for the same propor-
tion of total crashed stone consumption as in 1995.
However, the USGS published new data (USGS 1999)
for 1998 limestone consumption. Now, milestone con-
sumed for glass making in 1996 and 1997 is interpo-
lated, using both the 1995 and 1998 data, and the
1998 data have been updated. Finally, the amount of
limestone consumed in 1998 for flue gas desulfuriza-
tion has been updated to reflect new data (EIA 1999b).
These updates resulted in a decrease in annual CO2
emissions from limestone and dolomite use in 1994
and 1996 through 1998. On average, emissions de-
creased by 0.4 Tg CO2 Eq. (2.2 percent).
• In the Nitric Acid Production section of the Industrial
Processes chapter, 1998 production data were revised
using data from Chemical and Engineering News
(C&EN 2000). The revision resulted in a decrease of
0.2 Tg CO2 Eq. (1.0 percent) in annual nitrous oxide
emissions from nitric acid production in 1998.
• In the Substitution of Ozone Depleting Substances
section of the Industrial Processes chapter, a review
of the current chemical substitution trends, together
with input from industry representatives, resulted in
updated assumptions for the Vintaging Model, par-
ticularly in the precision cleaning solvents, station-
ary refrigeration, and fire extinguishing sectors.
These revisions resulted in an average decrease of
2.1 Tg CO2 Eq. (19 percent) in HFC, PFC, and SF6
emissions from substitution of ozone depleting sub-
stances for 1994 through 1998.
• In the Aluminum Production section of the Indus-
trial Processes chapter, the smelter-specific emission
factors used for estimating PFC emissions from alu-
minum production were revised to reflect recently
reported data concerning smelter operating param-
eters and smelter emission measurements. These data
were provided by the EPA's Climate Protection Divi-
sion in cooperation with participants in the Volun-
tary Aluminum Industrial Partnership (VAIP) program.
The revisions resulted in an average decrease of 0.2
Tg CO2 Eq. (4.0 percent) in PFC emissions from alu-
minum production for 1990 through 1998.
xiv Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
In the Manure Management section of the Agricul-
ture chapter, two major data revisions occurred. Ma-
nure management system data were revised and up-
dated for the entire time series based on data that
has been gathered by various sources. These sources
include EPA's Office of Water (ERG 2000, UEP1999),
USDA's Animal and Plant Health Inspection Service
(USDA 1996b, 1998b, 2000d, 2000e), as well as per-
sonal communications with USDA and other experts
(Deal 2000, Johnson 2000, Miller 2000, Stettler 2000,
Sweeten 2000, Wright 2000). Contacts at Cornell Uni-
versity provided survey data on dairy manure man-
agement practices in New York (Poe et al., 1999). The
revisions made to the manure management system
data account for changes that have occurred in the
industry, including more dairies moving away from
daily spread systems and installing on-site manure
storage systems and layer operations moving from
flush systems to high rise housing. The revised data
also account for dairies, beef feedlots, swine, and
poultry operations handling portions of their manure
as a dry waste, either as separated solids or manure
collected from scrape systems. In particular, the new
data revised the previous assumptions of the num-
ber of dairy cattle housed on pasture, range, or pad-
dock, and the amount of manure managed in daily
spread systems. Previously, general assumptions had
been made that all large dairies and swine operations
handle their manure in a liquid system, and all dairies
with less than 100 head and swine operations with
less than 200 head were managed in pasture, range,
or paddock systems. These revised data result in
lower CH4 emissions and higher N2O emissions.
Secondly, Census of Agriculture data, which are used
to determine the distribution of animals by farm size,
were updated for 1992 and 1997. These distributions
were then combined with manure management sys-
tem data to determine State-specific weighted emis-
sion factors. The revised data, made available to the
public in June 1999, revised the swine farm distribu-
tion, which resulted in a decrease in CH4 emissions,
and an increase in N2O emissions.
These data changes, together with the methodologi-
cal changes described below, resulted in annual CH4
emission estimates from manure management de-
creasing by an average of 38.3 Tg CO2 Eq. (56 per-
cent). Additionally, average annual N2O emission
estimates increased by 3.1 Tg CO2 Eq. (23 percent),
due to significant increases in the dairy estimates.
The estimates of nitrous oxide (N2O) emissions from
agricultural soil management have been updated for
a variety of reasons, as described below: Two
changes were made to the commercial fertilizer sta-
tistics. First, the fertilizer consumption data for 1998
were updated based on revised values published by
the Association of American Plant Food Control Of-
ficials (AAPFCO 1999). The updated data were less
than 1 percent lower than the original data. Second,
the nitrogen content of commercial organic fertilizers
(4.1 percent in the previous Inventory) was revised
to reflect the annual weighted average nitrogen con-
tents published in annual reports of commercial fer-
tilizer statistics (TVA1991-1994, AAPFCO 1995-1999).
These new nitrogen contents varied from 2.3 to 3.9
percent (by mass).
The annual estimates of livestock manure produc-
tion were refined through personal communications
with livestock experts (Anderson 2000, Deal 2000,
Johnson 2000, Lange 2000, Miller 2000, Milton 2000,
Safley 2000, Stettler 2000, Sweeten 2000, and Wright
2000). These refinements resulted in a decrease of
about 30 percent in the estimates of manure nitrogen
applied to soils, a decrease of about 13 percent in the
estimates of manure deposited by pasture, range,
and paddock animals, and a decrease of about 20
percent in total livestock manure. The fraction of
poultry manure assumed to be used as a livestock
feed supplement was reduced from 10 percent to 4.2
percent (Carpenter 1992).
In the calculations of both nitrogen-fixing crop pro-
duction and crop residue application, the 1998 crop
production data for small grains and beans and pulses
were changed based upon updated values from
USDA (2000b). The updated data for all crops except
XV
-------
peanuts were lower than the USDA estimates used
in the previous Inventory; the updated production
statistics for peanuts were higher. All changes were
less than 1 percent of the original data.
In the calculations of nitrogen-fixing crop produc-
tion, the crop production data for forage legumes
(i.e., alfalfa, red clover, white clover, birdsfoot trefoil,
arrowleaf clover, crimson clover, and hairy vetch) were
revised to include more detailed crop information,
especially about biomass densities and grass/legume
mixtures. Hairy vetch was dropped from the calcula-
tions because the data used in the previous Inven-
tory were found to be too uncertain. These revisions
resulted in a 6 percent decrease in the annual total
forage legume production estimates.
The calculation of crop residue applications was re-
vised in several ways. First, the following grains were
included in the calculations, in addition to those con-
sidered previously: rice, barley, sorghum, oats, rye,
and millet. Second, instead of assuming that 100 per-
cent of the residue was left on the field, it was as-
sumed that 90 percent of the residues of all crop
types, except rice, were left on the field. For rice resi-
due, it was assumed that all of the unburned residue
was left on the field. Third, the conversion factors
used in calculating the amount of crop residue ap-
plied to soils were revised to more recent, and in
many cases, U.S.-based, data. New values for resi-
due dry matter content and residue nitrogen content
for wheat, rice, corn, and barley were obtained from
Turn et al. (1997), and new values for residue dry
matter content and residue nitrogen content for pea-
nuts, sorghum, oats, and rye were obtained from a
computer model at Cornell University's Animal Sci-
ence Department—the Cornell Net Carbohydrate and
Protein System (Ketzis 1999). The new values for
residue dry matter content and residue nitrogen con-
tent for millet, and residue dry matter content for
soybeans, were obtained from Strehler and Stiitzle
(1987). The new value for residue nitrogen content
for soybeans was obtained from Barnard and
Kristoferson (1985). Together, these changes resulted
in a 2 to 3 percent decrease in the total annual crop
residue nitrogen application estimates.
These revisions, together with the methodologi-
cal modification described below, resulted in an av-
erage decrease of 8.1 Tg CO2 Eq. (2.8 percent) in
estimated annual N2O emissions from agricultural
soil management for 1990 through 1998.
The estimates of emissions from agricultural residue
burning include three changes, as described below:
Revised USDA crop production data for 1998 from
USDA (2000b) have been incorporated. For all crops
except sugarcane and peanuts, production estimates
were lower than previously reported; the updated
production statistics for sugarcane and peanuts were
higher. All changes were less than 1 percent of the
original estimate.
Data on the percentage of rice burned in California
were updated as a result of conversations with an air
pollution specialist with the California Air Resources
Board (Najita 2000). More accurate estimates of rice
acreage burned in Sacramento Valley were obtained
from data collected by the Air Resources Board. These
estimates are about 75 to 130 percent higher than the
estimates used in the previous Inventory.
The crop conversion factors, which served as key
assumptions for estimating emissions, were revised
in this report to reflect data from recent, U.S.-based
sources. Updated values for dry matter content, car-
bon content, and nitrogen content of wheat, rice,
corn, and barley were obtained from Turn et al. (1997),
and revised values for dry matter content, carbon
content, and nitrogen content of peanuts were ob-
tained from a computer model at Cornell University's
Animal Science Department—the Cornell Net Car-
bohydrate and Protein System (Ketzis 1999).
These revisions, in combination with the method-
ological revision described below, resulted in an av-
erage decrease in agricultural residue burning CH4
emissions of 0.1 Tg CO2 Eq. (14 percent), and an
average increase in N2O emissions of less than 0.1
Tg CO2 Eq. (4.9 percent), for 1990 through 1998.
xvi Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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In the Land-Use Change and Forestry chapter, the
following changes were made to the Forests, Agricul-
tural Soils, and Landfilled Yard Trimmings sections:
In the Forests section of the Land-Use Change and
Forestry chapter, new data from a U.S. forest survey
for 1997 (Smith and Sheffield 2000) were utilized.
These 1997 data were used to estimate 1997 carbon
stocks for forests and harvested wood, which were
combined with the 1992 and 2000 carbon stock esti-
mates to derive carbon flux estimates for intervening
years. The flux estimates for 1993 through 1998 in
last year's Inventory were derived using a 1992 stock
and a projected stock for 2000, since the 1997 forest
survey was not yet available.
The Agricultural Soils section of the Land-Use
Change and Forestry chapter includes two changes,
as described below:
New data from a preliminary version of USDA's 1997
National Resources Inventory (NRI) (USDA 2000a)
were used to derive mineral and organic soil carbon
flux estimates for 1993 through 1999. The previous
Inventory included only a partial time series of agri-
cultural soil carbon flux estimates, and these esti-
mates were not included in the total net flux esti-
mates presented in the chapter because USDA's 1997
NRI had not yet been completed. This Inventory in-
cludes a complete time series of agricultural soil car-
bon flux estimates, and these estimates are included
in the total net flux estimates for land use, land-use
change, and forestry.
The carbon dioxide emission estimates for lim-
ing were also changed. The input data for these cal-
culations were revised based on the latest updates
from publications of the Bureau of Mines and the
U.S. Geological Survey.
In the Landfilled Yard Trimmings section of the Land-
Use Change and Forestry chapter, the 1998 estimate
for yard trimmings disposed in landfills was revised
using new data found in EPA (1999). Previously, the
1998 value had been projected.
These changes, combined with the methodologi-
cal changes described below, resulted in an average
decrease of 125.5 Tg CO2 Eq. (11.8 percent) in annual
carbon sequestration from land-use change and for-
estry for 1990 through 1992, and an average increase
of 233.2 Tg CO2 Eq. (29.4 percent) in annual carbon
sequestration from land-use change and forestry for
1993 through 1998.
• In the Human Sewage section of the Waste chapter,
revisions have been made to U.S. Census Bureau
population data (2000). Additionally, this report re-
flects an updated 1998 per capita protein consump-
tion estimate published by the Food and Agriculture
Organization (FAO 2000). These revisions resulted
in an average increase of 0.1 Tg CO2 Eq. (1.4 percent)
in annual N2O emissions from human sewage, from
1990 through 1998.
• In the Wastewater Treatment section of the Waste
chapter, revisions have been made to national popu-
lation data for 1990 through 1998 that were supplied
by the U.S. Census Bureau (2000). This change, com-
bined with the methodological changes described
below, resulted in an average increase of 8.4 Tg CO2
Eq. (255 percent) in annual CH4 emissions from waste-
water treatment.
Methodological Changes
Carbon Dioxide Emissions from Fossil
Fuel Combustion [and] Carbon Stored
in Products from Non-Energy Uses
of Fossil Fuels
The carbon storage factors used to estimate the
carbon stored by the non-energy use of asphalt and road
oil, liquefied petroleum gases (LPG), petrochemical feed-
stocks, pentanes plus, natural gas for other uses (i.e., not
used for fertilizers), and lubricants were revised. The role
of carbon storage in estimating emissions from the com-
bustion of fossil fuels was explained in previous invento-
ries only in Step 3 in the Methodology for the Carbon
xvii
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Dioxide Emissions from Fossil Fuel Combustion section
of the Energy chapter. For this inventory, the complete
list of storage factors, the methods and data used to de-
rive the factors, and the uncertainty involved with their
estimation are discussed hi a new source category sec-
tion of the Energy chapter entitled, "Carbon Stored in
Products from Non-Energy Uses of Fossil Fuels."
The storage factor revisions were made by examin-
ing the lifecycle of the various fuel products. The storage
factor for asphalt and road oil remained 100 percent; LPG
and pentanes plus were raised to 91 from 80 percent;
naphtha petrochemical feedstocks were raised to 91 from
75 percent; other oil feedstocks were raised to 91 from 50
percent; natural gas for other uses was lowered to 91
percent from 100 percent; and lubricants were lowered to
9 percent from 50 percent. Details of the storage factor
revisions can be found in Annex B, which has been added
to document this new storage factor methodology.
Updated storage factors were developed for fuels
according to the following three criteria:
• Relative size of non-energy fuel consumption. Nearly
two-thirds of the carbon consumed for non-energy
uses come from LPG (26 percent), petrochemical feed-
stocks (19 percent), and asphalt and road oil (19 per-
cent). Combined, the fuels that have been selected
represent approximately 305 Tg CO2 Eq., nearly 64
percent of the total consumed for non-energy uses
in 1999.
• Ability to identify data for fuel products. Data gath-
ering is made efficient and the uncertainty is reduced
when a fuel's uses are limited (i.e., there are only a
few important end uses) or well characterized. As-
phalt and road oil is a good example of a limited end
use fuel, having only two major uses, asphalt paving
and roofing. Lubricants are an example of a well-char-
acterized non-energy use of fossil fuel—by virtue of
analyses conducted to support rulemakings on used
oils, the EPA maintains some data on their fate.
• Uncertainty in previously used storage factor. The
previous storage factors for certain fuel types or prod-
ucts, and the assumptions upon which they are
based, are not expected to be significantly altered
through additional research. For example, special
naphthas—a generic fuel category which covers
highly purified organic compounds, usually contain-
ing 4 to 12 carbon atoms—are almost entirely used
as solvents. Due to their volatility, they are generally
emitted during use and are subsequently photo-oxi-
dized to CO2 in the atmosphere. Similarly, natural gas
used in fertilizer is consumed for ammonia produc-
tion, and nearly all the carbon is oxidized. The petro-
chemical feedstocks, on the other hand, lead to many
products via a myriad of reaction pathways. In this
case, the uncertainty hi the storage factor could be
reduced significantly by investigating the fuel's pro-
cessing losses and end uses.
Overall, the storage factor revisions increased the
carbon stored from non-energy uses of fossil fuels by an
average of 26.9 Tg CO2 Eq. for 1990 through 1998. These
methodological changes, combined with the data changes
described above, resulted in an average increase of 6.4
Tg CO2 Eq. (0.1 percent) of CO2 annual emissions from
fossil fuel combustion for 1990 through 1998.
Mobile Combustion (excluding C02)
Annual vehicle mileage accumulation by vehicle
age, provided by EPA (2000a), has been incorporated for
this report. Previously, only the age distribution of high-
way vehicle registrations was accounted for when allo-
cating vehicle miles traveled (VMT) to different model
years. This change accounts for the fact that newer ve-
hicles are generally driven more than older vehicles. This
methodological change, combined with the data changes
described above, resulted hi an average decrease of 0.4
Tg CO2 Eq. (7.1 percent) in annual CH4 emissions from
mobile combustion for 1990 through 1998. Average N2O
emissions increased by 3.0 Tg CO2 Eq. (5.2 percent) an-
nually for 1990 through 1998.
xviii Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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Natural Gas Systems
In the Natural Gas Systems section of the Energy
chapter, a new source was added into the estimation of
emissions from natural gas production for 1990 through
1999. Coalbed methane wells draw natural gas from deep
deposits of coal, and in the course of producing gas,
these wells can also produce large amounts of water, which
has methane in solution. When the water reaches the
surface, the dissolved methane volatilizes. Estimates of
these emissions are small, and add approximately 0.15 Tg
CO2 Eq. per year to the total. This change, combined with
the data changes mentioned above, resulted in an aver-
age decrease of 0.6 Tg CO2 Eq. (0.5 percent) in annual
CH4 emissions from natural gas systems from 1990
through 1998.
Lime Manufacture
The method for estimating CO2 emissions from lime
manufacture was updated to adhere to IPCC Good Prac-
tice Guidance (IPCC 2000). Previously, gross emissions
were calculated by multiplying total lime production by
an emission factor of 0.73 metric ton CO2/metric ton of
lime. This emission factor was the product of the average
CaO/CaOMgO content of lime, 93 percent, and the sto-
ichiometric ratio of CO2 to CaO (0.785 metric ton CO2/
metric ton CaO). In this report, lime production was split
into high-calcium lime and dolomitic lime, and the emis-
sion factors (0.75 and 0.86 metric ton CO2/metric ton lime,
respectively) were updated. Additionally, corrections were
made for the amount of hydrated lime produced. These
methodological revisions led to an average increase of
0.2 Tg CO2 Eq. (1.6 percent) in annual CO2 emissions from
lime manufacture for 1990 through 1998.
Semiconductor Manufacturing
The estimates presented in the Semiconductor
Manufacturing section of the Industrial Processes chap-
ter in previous Inventories were estimated based on gas
sales data from 1994, emission factors for the most com-
monly used gases, and projections—both backward and
forward—regarding the growth of semiconductor sales
and the effectiveness of emission reduction efforts. The
methodology has been updated to use production data
for 1990 through 1994, and reported data from semicon-
ductor manufacturers for other years. These changes re-
sulted in an average decrease of 0.1 Tg CO2 Eq. (5.0 per-
cent) in annual HFC, PFC, and SF6 emissions from semi-
conductor manufacturing for 1990 through 1998.
Magnesium Production and Processing
Emission estimates for the magnesium production
and processing industry have been revised to incorpo-
rate information provided by EPA's SF6 Emission Reduc-
tion Partnership for the Magnesium Industry. These revi-
sions resulted in an average decrease of 3.6 Tg CO2 Eq.
(37 percent) in annual SF6 emissions from magnesium pro-
duction and processing from 1990 through 1998.
Enteric Fermentation
Four major changes to the methodology used in
estimating enteric fermentation emissions from cattle were
completed in this report: 1) an enhanced population char-
acterization method (i.e., IPCC Tier 2) was adopted for
cattle only; 2) diet characterizations were expanded to
apply to development of emission factors for the new
population modeling structure; 3) certain DE and Ym val-
ues were evaluated using a physiological model; and 4)
new equations were implemented based on IPCC Good
Practice Guidance (IPCC 2000).
For cattle, all historical emission estimates have
been updated using the IPCC Good Practice Guidance
Tier 2 approach. These methods for estimating methane
emissions from enteric fermentation resulted in increased
levels of detail, such as definitions of livestock sub-cat-
egories, livestock populations by sub-category, and feed
intake estimates for the typical animal in each sub-cat-
egory. Cattle populations were categorized in much more
depth through the modeling of the populations by month.
Factors such as weight gain, birth, pregnancy, feedlot
placements, and slaughter were tracked to characterize
the U.S. cattle population in greater detail than in previ-
ous inventories, in which only end of year population
data were used.
Diets of beef, dairy, and feedlot animals were up-
dated from the values presented in EPA (1993) by research-
XIX
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ing regional diets throughout the United States. A rumi-
nant digestion model (Donovan and Baldwin 1999) and
expert opinion (Johnson 1999) were used to derive DE
and Ym values for the selected animal categories using
the results of the diet research. These estimates were
used to develop new emission factors for all animal cat-
egories studied, with the exception of bulls.
The net energy and methane emission equations
presented in D?CC (2000) were incorporated into a com-
puter model that contains the population characteriza-
tion to estimate emissions for each of the selected cattle
population categories, both regionally and temporally. In
previous Inventories, national emission factors recom-
mended by IPCC/UNEP/OECD/BEA (1997) were used with
static information relevant to broader classifications of
the cattle industry to estimate total emissions. These
methodological changes resulted in an average increase
in annual CH4 emissions from enteric fermentation of 7.3
Tg CO2Eq. (5.9 percent) from 1990 through 1998.
Manure Management
Several changes have been incorporated into the
manure management emission estimates that affect esti-
mates for all years. The major changes affecting the esti-
mates are described below:
• Swine Population Characterization Revisions. His-
torically, swine population was broken into two
groups: breeding swine (i.e., gestating sows, farrow-
ing sows, and boars) and all market swine. For this
report, the entire time series has been revised to ac-
count for different weight groups of market swine.
Specifically, the market swine population was bro-
ken into four groups: swine less than 60 pounds (<27
kg), swine 60 to 119 pounds (27 to 54 kg), swine 120
to 179 pounds (54 to 81kg), and swine greater than
180 pounds (>82 kg). The population estimates for
each size group were based on quarterly and annual
population data available from USDA's National
Agricultural Statistics Service (USDA 1998a, 2000c).
The representative weight for each size group was
set at the mid-point of the weight range, with the
exception of the swine less than 60 pounds and swine
greater than 180 pounds. The representative weight
for these two size groups were based on expert judg-
ment (Safley 2000).
Waste Characteristics Data Revisions. Other animal
waste characteristics were also revised to match data
found in USDA's Agricultural Waste Management
Field Handbook (USDA 1996a), in order to distin-
guish waste characteristics between various animal
subgroups. For example, distinctions were made in
the amount of volatile solids and nitrogen excreted
by market swine in various stages of growth, beef
cattle that are grazed versus beef cattle on high en-
ergy feed, and between lactating and dry dairy cows.
The data source for waste characteristics for all live-
stock except sheep, goats, and horses was changed
to the Agricultural Waste Management Field Hand-
book (USDA 1996a). The volatile solids and nitrogen
excretion data for breeding swine are a combination
of the types of animals that make up this animal
group, namely gestating and farrowing swine and
boars. It was assumed that a group of breeding swine
is typically broken out as 80 percent gestating sows,
15 percent farrowing swine, and 5 percent boars
(Safley 2000). In addition, B0 values used in previous
estimates were reviewed and updated for dairy and
beef cattle, swine, and poultry.
Most significantly, volatile solids and nitrogen ex-
cretion data for immature swine were accessed from
USDA's Agricultural Waste Management Field Hand-
book (USDA 1996a), and coupled with revised ani-
mal masses for the new population groups. Previ-
ously, the methodology for estimating these emis-
sions assumed that all market swine generate vola-
tile solids and nitrogen at a rate equal to a 255-pound
(116 kg) swine. That methodology overestimated the
amount of volatile solids and nitrogen generated, as
well as the subsequent emissions of methane and
nitrous oxide. These changes resulted hi a roughly
70 percent drop in both volatile solids production
and nitrogen excretion for swine operations.
Dairy Cow Volatile Solids Production Revisions.
The method for calculating volatile solids produc-
tion from dairy cows was revised to better address
xx Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
the relationship between milk production and vola-
tile solids production. Cows that produce more milk
per year also produce more volatile solids in their
manure due to their increased feed. Data from the
Agriculture Waste Management Field Handbook
were used to determine the mathematical relation-
ship between volatile solids production and milk pro-
duction for a 1,400-pound dairy cow (USDA 1996a).
Annual milk production data, published by USDA's
National Agricultural Statistics Service (USDA 2000f),
was accessed for each State and for each year 1990
through 1999. State-specific volatile solids produc-
tion rates were then calculated and used instead of a
national volatile solids constant.
• Methane Conversion Factor (MCF) Revisions. His-
torically, for the calculation of methane emissions,
default MCFs from IPCC were used for all manure
management systems. However, the IPCC Good Prac-
tice report (IPCC 2000) now provides a range of 0 to
100 percent as the MCF for anaerobic lagoons. Rather
than choosing an MCF for all U.S. systems based
solely on judgement, a methodology was developed
to reflect the range in performance that is achieved
by lagoon systems, and other liquid-based systems.
Therefore, the entire time series was revised to in-
corporate a new method of calculating MCFs for liq-
uid/slurry, deep pit, and anaerobic lagoon systems.
The new calculation method is based on the mean
ambient temperature of the location of the manure
management system (Safley and Westerman 1990),
represented by the State and the counties hi which
specific animal populations reside (USDA 1999). The
calculation of the anaerobic lagoon MCF includes
an additional approach to account for the timing and
length of storage exhibited by these systems, which
allows the organic matter to continue to break down
over time, increasing the potential for methane pro-
duction. This approach assesses the production of
methane on a monthly basis, and accounts for re-
sidual volatile solids that are retained in the lagoon
from previous months. In addition, the calculation
includes an adjustment for the effect of management
and design practices. This factor accounts for other
mechanisms by which volatile solids are removed
from the management system prior to conversion to
methane, such as solids being removed from the la-
goon for application to cropland. This factor, equal
to 0.8, has been estimated using currently available
methane measurement data from anaerobic lagoon
systems in the United States (Safley and Westerman
1998 and 1992; Martin 2000). This methodology can
be refined over time as new measurements and tem-
perature data are gathered to reflect lagoon perfor-
mance in the United States.
Nationally, the CH4 emission estimates for the en-
tire time series dropped between 50 to 60 percent. Swine
estimates dropped most significantly (62 percent to 72
percent), followed by poultry (52 percent to 60 percent),
dairy (38 percent to 44 percent), and beef (25 percent to
31 percent). Sheep emission estimates dropped by 19 per-
cent across all years of the inventory due to a correction
hi animal weight and the related correction to volatile
solids production. The combined effect of these changes,
together with the data changes described above, resulted
in a decrease hi CH4 emission estimates from manure man-
agement of 38.3 Tg CO2 Eq. (56 percent) on average from
1990 through 1998.
The N2O emission estimates for the entire time se-
ries increased between 17 to 27 percent primarily due to
significant increases in the dairy estimates. Swine N2O
estimates for the time series dropped by 40 percent, while
beef dropped about 5 percent. The combined effect of
these changes, together with the data changes described
above, resulted hi an increase in the average annual N2O
emission estimates from manure management of 3.1 Tg
CO2Eq. (23 percent).
Rice Cultivation
There was a calculation error in the rice cultivation
spreadsheets used in the previous Inventory. This has
been identified and corrected, resulting hi a slightly lower
emission estimate for 1996, and higher emission estimates
for 1992 through 1995 and 1997 and 1998. This correction
XXI
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resulted in an average increase of 0.1 Tg CO2 Eq. (0.9
percent) in annual methane emissions from rice cultiva-
tion for 1992 through 1998.
Agricultural Soil Management
The estimates of nitrous oxide (N2O) emissions from
the pasture, range, and paddock manure sub-source were
derived by applying the emission factor to total pasture,
range, and paddock manure nitrogen, rather than just the
unvolatilized portion. In the previous Inventory, the emis-
sion factor was applied to the unvolatilized portion of
pasture, range, and paddock manure.
This methodological change, in combination with
the revisions to historical data, resulted in an average
decrease of 8.1 Tg CO2Eq. (2.8 percent) in estimated an-
nual N2O emissions from agricultural soil management
for 1990 through 1998.
Agricultural Residue Burning
The emission factor for methane from agricultural
residue burning was revised to reflect the default value in
the Revised 1996IPCC Guidelines (IPCC/UNEP/OECD/
EEA1997). The default emission factor from the previous
version of the IPCC Guidelines was used in the previous
Inventory. This methodological change, in combination
with the revisions to historical data described above, re-
sulted in an average decrease in agricultural residue burn-
ing CH4 emissions of 0.1 Tg CO2 Eq. (14 percent), and an
average increase in N2O emissions of less than 0.1 Tg
CO2Eq. (4.9 percent), for 1990 through 1998.
Land-Use Change and Forestry
The Land-Use Change and Forestry chapter com-
prises three sections: 1) Forests; 2) Agricultural Soils;
and 3) Landfilled Yard Trimmings. The methodologies
used in the first two sections have changed relative to
the previous Inventory. The changes to each section are
described below.
* Forests. First, the treatment of specific portions of the
forest land base (i.e., Timberland, Reserved Forest
Land, and Other Forest Land27) has changed. Previ-
ously, carbon stock and flux estimates for private Tim-
berlands were estimated using the FORCARB model
and associated forest sector models (Birdsey and
Heath 1995). Carbon estimates for all other forestlands
(i.e., public Timberlands, all Reserved Forest Land,
and all Other Forest Land) were estimated by multiply-
ing regional forest statistics resource data (e.g., Powell
et al. 1993) by average regional carbon conversion
factors obtained from information in the FORCARB
model. In this Inventory, carbon estimates for both
the private and public Timberlands are derived from
the FORCARB modeling framework, i.e., using the
method that was used for only private Timberlands
previously. Carbon estimates for all Reserved Forest
Land and Other Forest Land, regardless of ownership,
are still calculated by multiplying regional forest sta-
tistics data by average regional carbon conversion
factors. However, forest statistics data are available
for 1997, and carbon conversion factors are updated
on these lands. In this Inventory, Reserved Forests
are assumed to contain the same carbon stock per
acre as Timberlands of the same forest type, region,
and owner group. For Other Forest Land, carbon
stocks per acre were calculated for the lowest produc-
tivity class of Timberland, and multiplied by 80 per-
cent to represent carbon stocks of these lower pro-
ductivity lands.
Second, a preliminary model to estimate net logging
residue flux was employed. Logging residues were
not included in the previous Inventory.
And lastly, calculations for products and landfills are
now based on estimates of the model constructed by
Skog and Nicholson (1998). This model has a similar
structure to the model by Heath et al. (1996) that was
previously used; however, annual estimates are pro-
duced based on wood product surveys. Net storage
of landfilled carbon is substantially greater in this
model, based on work that indicates that current land-
fill management practices result in low decay rates.
57 Timberland is unreserved forest land that is producing or is capable of producing crops of industrial wood. It is the most productive
type of forest land, growing at a rate of 20 cubic feet per acre per year or more. Reserved Forest Land is forest land withdrawn from
limber use by statute or regulation. Other Forest Land is unreserved forest land, growing at a rate less than 20 cubic feet per acre per
year.
xxif Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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• Agricultural soils. Three changes have been made
to the methodologies used to estimate mineral and
organic soil carbon flux. First, last year's Inventory
included the total land base included in USDA's
soil survey database. The data included in this year's
Inventory only include land areas that are classi-
fied as cropland or grazing land in 1987,1992, and/
or 1997. Second, in estimating carbon stock changes
for last year's Inventory, input data were aggregated
prior to estimating stock changes (Eve et al. 2001).
This resulted in an underestimate of stock changes
for some land areas. For this year's Inventory, stock
changes were estimated for each data point, and
then aggregated (Eve et al. 2000), resulting in a more
precise estimate of net flux. Third, an error in the
computer code used in last year's Inventory was
identified and corrected.
These changes, combined with the revisions to his-
torical data, resulted in an average decrease of 125.5 Tg
CO2 Eq. (11.8 percent) in annual carbon sequestration
from land-use change and forestry for 1990 through 1992,
and an average increase of 233.2 Tg CO2 Eq. (29.4 per-
cent) in annual carbon sequestration from land-use change
and forestry for 1993 through 1998.
Landfills
The methodology used to estimate recovered land-
fill gas has been updated in two ways. First, methane
recovered for landfill gas-to-energy (LFGTE) electricity
projects was estimated based on reported capacity (i.e.,
megawatts) rather than reported landfill gas flow. Although
the data on electricity capacity are generally considered
more reliable than the landfill flow data, capacity data
tend to be underestimated. The main reason for this un-
derestimation is the tendency of landfill owners/opera-
tors to undersize the units to ensure a sufficient and steady
flow of gas to support the unit. Second, in order to avoid
double counting, the estimate of methane emissions
avoided due to flaring was reduced to adjust for LFGTE
projects for which a vendor-specific flare could not be
identified. These steps resulted in a downward revision
of landfill gas recovered. Also, this report reflects flare
data from an additional two vendors, resulting in the
evaluation of 487 flares, as compared to 190 for the previ-
ous Inventory. Finally, this report includes data on 36
additional LFGTE projects. These methodological
changes resulted in an average increase in annual meth-
ane emissions from landfills of 1.5 Tg CO2 Eq. (0.7 per-
cent). This increase is primarily due to a reduction in the
estimate of methane emissions avoided at LFGTE projects,
which is mainly a result of the use of a more conservative
approach for estimating methane avoided.
Waste Combustion
The Waste Combustion section of the Waste chap-
ter has been revised substantially. Formerly, only CO2
emissions from the combustion of plastics and N2O emis-
sions from municipal solid waste were included. Carbon
dioxide from the combustion of tires, synthetic rubber,
synthetic fabrics, and hazardous waste have been added.
These updates have increased the average emissions from
waste combustion by 10.5 Tg CO2 Eq. (91.5 percent) for
1990 through 1998.
Wastewater Treatment
The value for wastewater biological oxygen de-
mand (BOD) produced per capita has been revised from
0.05 to 0.065 (kg/capita/day). The 0.05 value was refer-
enced fromlPCC/UNEP/OECD/DEA (1997). The revised
value of 0.065 is the value given for the United States in
EPA (1997). The IPCC Good Practice Guidance (IPCC
2000) has a default value of 0.06 for this parameter; how-
ever, that value represents an average for all countries.
The wastewater BOD is slightly higher in the United
States due to its use of garbage disposals, as stated in
EPA (1997). Additionally, the emission factor has been
changed from 0.22 kg CH4/kg BOD to 0.6 kg CH4/kg
BOD to reflect the IPCC Good Practice Guidance (IPCC
2000). Additionally, an estimate of emissions from pulp
and paper operations has been included for the first
time under the wastewater category. These methodologi-
cal revisions, together with the data changes described
above, resulted in an average increase of 8.4 Tg CO2 Eq.
(255 percent) in annual methane emissions.
xxiii
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xxiv Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
•xecutive Summary
Central to any study of climate change is the development of an emissions inventory that identifies and
^quantifies a country's primary anthropogenic1 sources and sinks of greenhouse gases. This inventory
adheres to both 1) a comprehensive and detailed methodology for estimating sources and sinks of anthropogenic
greenhouse gases; and 2) a common and consistent mechanism that enables signatory countries to the United Nations
Framework Convention on Climate Change (UNFCCC) to compare the relative contribution of different emission
sources and greenhouse gases to climate change. Moreover, systematically and consistently estimating national and
international emissions is a prerequisite for accounting for reductions and evaluating mitigation strategies.
In June of 1992, the United States signed, and later ratified in October, the UNFCCC. The objective of the
UNFCCC is "to achieve...stabilization of greenhouse gas concentrations in the atmosphere at a level that would
prevent dangerous anthropogenic interference with the climate system."2
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.. ."3 The United States views this report as
an opportunity to fulfill this commitment.
This chapter summarizes the latest information on U.S. anthropogenic greenhouse gas emission trends from 1990
through 1999. To ensure that the U.S. emissions inventory is comparable to those of other UNFCCC signatory coun-
tries, the estimates presented here were calculated using methodologies consistent with those recommended in the
Revised 1996IPCC Guidelines for National Greenhouse Gas Inventories (TPCC/UNEP/OECD/ffiA 1997). For most
source categories, the IPCC default methodologies were expanded, resulting in a more comprehensive and detailed
estimate of emissions.
Naturally occurring greenhouse gases include water vapor, carbon dioxide (CO2), methane (CH4), nitrous oxide
(N2O), and ozone (O3). Several classes of halogenated substances that contain fluorine, chlorine, or bromine are also
greenhouse gases, but they are, for the most part, solely a product of industrial activities. Chlorofluorocarbons (CFCs)
and hydrochlorofluorocarbons (HCFCs) are halocarbons that contain chlorine, while halocarbons that contain bro-
mine are referred to as halons. CFCs, HCFCs, and halons are stratospheric ozone depleting substances and are
therefore covered under the Montreal Protocol on Substances that Deplete the Ozone Layer. The UNFCCC defers to
1 The term "anthropogenic," in this context, refers to greenhouse gas emissions and removals that are a direct result of human activities
or are the result of natural processes that have been affected by human activities (IPCC/UNEP/OECD/IEA 1997).
2 Article 2 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change. See
.
3 Article 4 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change (also
identified in Article 12). See .
Executive Summary ES-1
-------
this earlier international treaty in addressing these ozone
depleting substances; however, some other fluorine-
containing halogenated substances—hydrofluoro-
carbons (HFCs), perfluorocarbons (PFCs), and sulfur
hexafluoride (SFg)—do not deplete stratospheric ozone
but are potent greenhouse gases. These latter substances
are addressed by the UNFCCC and accounted for in na-
tional greenhouse gas inventories.
There are also several gases that do not have a di-
rect global warming effect but indirectly affect terrestrial
radiation absorpon by influencing the formation and de-
struction of tropospheric and stratospheric ozone. These
gases—referred to as ozone precursors—include carbon
monoxide (CO), oxides of nitrogen (NOX), and nonmethane
volatile organic compounds (NMVOCs).4 Aerosols—ex-
BoxES-1: Emission Reporting Nomenclature
The Global Warming Potential (6WP) weighted emissions
of all direct greenhouse gases presented throughout this re-
port are presented in terms of equivalent emissions of carbon
dioxide (Cty, using units of teragrams of carbon dioxide equiva-
lents (Tg C02 Eq.) In previous year's inventories emissions
were reported in terms of carbon—versus carbon dioxide—
equivalent emissions, using units of million metric tons of
carbon equivalents (MMTCE). This change of units for re-
porting was implemented so that the U.S. Inventory would be
more consistent with international practices, which are to re-
port emissions in carbon dioxide equivalent units.
In order to convert the emission estimates presented in
this report to those provided previously, the following equation
can be employed:
Tg C02 Eq. = MMTCE x (%)
There are two elements to the conversion. The first ele-
ment Is simply nomenclature, since one teragram is equal to
one million metric tons:
Tg = 109 kg = 106 metric tons = 1 megaton= 1 million
metric tons
The second element is the conversion, by weight, from
carbon to carbon dioxide. The molecular weight of carbon is
12, and the molecular weight of oxygen is 16; therefore, the
molecular weight of C02 is 44 (i.e., 12+[16 x 2]), as com-
pared to 12 for carbon alone. Thus, carbon comprises
, 12/44lhs of carbon dioxide by weight.
tremely small particles or liquid droplets often produced
by emissions of sulfur dioxide (SO2)—can also affect the
absorptive characteristics of the atmosphere.
Although CO2, CH4, and N2O occur naturally in the
atmosphere, their atmospheric concentrations have been
affected by human activities. Since pre-industrial time
(i.e., since about 1750), concentrations of these green-
house gases have increased by 28, 145, and 13 percent,
respectively (IPCC 1996). This build-up has altered the
chemical composition of the earth's atmosphere, and
therefore effected the global climate system.
Beginning in the 1950s, the use of CFCs and other
stratospheric ozone depleting substances (ODSs) in-
creased by nearly 10 percent per year until the mid-1980s,
when international concern about ozone depletion led to
the signing of the Montreal Protocol. Since then, a phase-
out of the production of ODSs has been occurring. In
recent years, use of ODS substitutes such as HFCs and
PFCs has grown as they begin to be phased in as replace-
ments for CFCs and HCFCs.
Recent Trends in U.S.
Greenhouse Gas Emissions
Total U.S. greenhouse gas emissions rose in 1999
to 6,746.0 teragrams of carbon dioxide equivalents (Tg
CO2 Eq.)5 (11.7 percent above 1990 emissions). The single
year increase in emissions from 1998 to 1999 was 0.9 per-
cent (59.2 Tg CO2 Eq.), less than the average annual rate
of increase for 1990 through 1999 (1.2 percent). The lower
than average increase in emissions, especially given the
robust economic growth in 1999, was primarily attribut-
able to the following factors: 1) warmer than normal sum-
mer and winter conditions; 2) significantly increased out-
put from existing nuclear power plants; and 3) reduced
CH4 emissions from coal mines and HFC-23 by-product
emissions from the chemical manufacture of HCFC-22.
Figure ES-1 through Figure ES-3 illustrate the overall
trends in total U.S. emissions by gas, annual changes,
and absolute change since 1990. Table ES-1 provides a
detailed summary of U.S. greenhouse gas emissions and
sinks for 1990 through 1999.
** Also referred to in the U.S. Clean Air Act as "criteria pollutants."
5 Estimates are presented in units of teragrams of carbon dioxide equivalents (Tg CO2 Eq.), which weight each gas by its Global Wanning
Potential, or GWP, value, (see following section).
ES-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Figure ES-1
Figure ES-2
-r,
8000
7000
6000
o-SOOO
O 4000
£> 3000 •
2000
1000
0 J
B4n1 6,598 6,678 6,6876,746
6,038 5,987
I HFCs, PFCs, & SF6
i Nitrous Oxide
Methane
Carbon Dioxide
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
Figure ES-3
648.6 ,
707.9
1991 1992 1993 1994 1995 1996 1997 1998 1999
Figure ES-4 illustrates the relative contribution of
the direct greenhouse gases to total U.S. emissions in
1999. The primary greenhouse gas emitted by human ac-
tivities was CO2. The largest source of CO2, and of over-
all greenhouse gas emissions in the United States, was
fossil fuel combustion. Methane emissions resulted pri-
marily from decomposition of wastes in landfills, enteric
fermentation associated with domestic livestock, natural
gas systems, and coal mining. Emissions of N2O were
dominated by agricultural soil management and mobile
source fossil fuel combustion. The emissions of substi-
tutes for ozone depleting substances and emissions of
HFC-23 during the production of HCFC-22 were the pri-
mary contributors to aggregate HFC emissions. Electrical
transmission and distribution systems emitted the major-
1991 1992 1993 1994 1995 1996 1997 1998 1999
Figure ES-4
2.0% HFCs, PFCs & SF6
6.4% N2O
9.2% CH4
82.4% C02
ity of SF6, while PFC emissions came mainly from primary
aluminum production.
As the largest source of U.S. greenhouse gas emis-
sions, CO2 from fossil fuel combustion accounted for a
nearly constant 80 percent of global warming potential
(GWP) weighted emissions in the 1990s.6 Emissions from
this source category grew by 13 percent (617.4 Tg CO2
Eq.) from 1990 to 1999 and were responsible for the major-
ity of the increase in national emissions during this pe-
riod. The annual increase in CO2 emissions from fossil
fuel combustion was 1.2 percent in 1999, a figure close to
the source's average annual rate of 1.4 percent during the
1990s. Historically, changes in emissions from fossil fuel
combustion have been the dominant factor affecting U.S.
emission trends.
6 If a full accounting of emissions from fossil fuel combustion is made by including emissions from the combustion of international
bunker fuels and CH4 and N2O emissions associated with fuel combustion, then this percentage increases to a constant 82 percent during
the 1990s.
Executive Summary ES-3
-------
Table ES-1: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg C02 Eq.)
Gas/Source
C02
Fossil Fuel Combustion
Cement Manufacture
Waste Combustion
Lime Manufacture
Natural Gas Flaring
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
; Carbon Dioxide Consumption
Land-Use Change and Forestry (Sink)3
International Bunker Fuels'"
CH4
Landfills
Enteric Fermentation
Natural Gas Systems
Coal Mining
: Manure Management
• Petroleum Systems
1 Wastewater Treatment
Rice Cultivation
Stationary Combustion
. Mobile Combustion
Petrochemical Production
Agricultural Residue Burning
Silicon Carbide Production
International Bunker Fuelsb
N20
" Agricultural Soil Management
Mobile Combustion
- Nitric Acid
- Manure Management
: Stationary Combustion
• Adipic Acid
Human Sewage
Agricultural Residue Burning
Waste Combustion
International Bunker Fuels'1
HFCs, PFCs, and SF6
1990
4,913.0
4,835.7
33.3
17.6
11.2
5.1
5.1
4.1
0.8
(1,059.9)
114.0
644.5
217.3
129.5
121.2
87.9
26.4
27.2
11.2
8.7
8.5
5.0
1.2
0.5
+
+
396.9
269.0
54.3
17.8
16.0
13.6
18.3
7.1
0.4
0.3
1.0
83.9
Substitution of Ozone Depleting Substances 0.9
HCFC-22 Production
Electrical Transmission and Distribution
Aluminum Production
Semiconductor Manufacture
Magnesium Production and Processing
: Total Emissions
Net Emissions (Sources and Sinks)
34.8
20.5
19.3
2.9
5.5
6,038.2
4,978.3
1995
5,219.8
5,121.3
36.8
23.1
12.8
13.6
7.0
4.3
1.0
^ (1,019.1)
:. . 101.0
650.5
222.9
136.3
124.2
74.6
31.0
':..::."'. -- 24.5
""" v : 11.8
9.5
J ~"~" 8.9
4.9
1.5
0.5
"__:__ • _ +
+
431.9
I ~ " 285.4
66.8
19.9
16.4
14.3
20.3
8.2
0.4
0.3
:; ._; : 0.9
99.0
-". 24.0
- 27.1
~ 25.7
11.2
5.5
5.5
6,401.3
5,382.3
1996
5,403.2
5,303.0
37.1
24.0
13.5
13.0
7.3
4.3
1.1
(1,021.6)
102.2
638.0
219.1
132.2
125.8
69.3
30.7
24.0
11.9
8.8
9.0
4.8
1.6
0.6
+
+
441.6
294.6
65.3
20.7
16.8
14.9
20.8
7.8
0.4
0.3
0.9
115.1
34.0
31.2
25.7
11.6
7.0
5.6
6,597.8
5,576.2
1997
5,478.7
5,374.9
38.3
25.7
13.7
12.0
8.3
4.4
1.3
(981.9)
109.8
632.0
217.8
129.6
122.7
68.8
32.6
24.0
12.0
9.6
8.1
4.7
1.6
0.6
+
+••
444.1
299.8
65.2
21.2
17.1
15.0
17.1
7.9
0.4
0.3
1.0
123.3
42.1
30.1
25.7
10.8
7.0
7.5
6,678.0
5,696.2
1998
5,489.7
5,386.8
39.2
25.1
13.9
10.8
8.1
4.3
1.4
(983.3)
112.8
624.8
213.6
127.5
122.1
66.5
35.2
23.3
12.1
10.1
7.6
4.6
1.6
0.6
+
+
433.7
300.3
64.2
20.9
17.2
15.1
7.3
8.1
0.5
0.2
1.0
138.6
49.6
40.0
25.7
10.1
6.8
6.3
6,686.8
5,703.5
1999
5,558.1
5,453.1
39.9
26.0
13.4
11.7
8.3
4.2
1.6
(990.4)
107.3
619.6
214.6
127.2
121.8
61.8 i
34.4
21.9
12.2
10.7 ;
8.1
4.5
1.7
0.6 ;
+ J
+
432.6
298.3
63.4
20.2
17.2
15.7 :
9.0
8.2
0.4
0.2
1.0
135.7
56.7
30.4
25.7
10.0
6.8
6.1
6,746.0
5,755.7
* + Does not exceed 0.05 Tg C02 Eq.
•-- * Sinks are only included In net emissions total, and are based partially on projected activity data.
b Emissions from International Bunker Fuels are not included in totals.
f Note: Totals may not sum due to independent rounding.
; Note: Parentheses indicate negative values (or sequestration).
ES-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Changes in CO2 emissions from fossil fuel combus-
tion are influenced by many long-term and short-term
factors, including population and economic growth, en-
ergy price fluctuations, technological changes, and sea-
sonal temperatures. On an annual basis, the overall de-
mand for fossil fuels hi the United States and other coun-
tries generally fluctuates in response to changes in gen-
eral economic conditions, energy prices, weather, and the
availability of non-fossil alternatives. For example, a year
with increased consumption of goods and services, low
fuel prices, severe summer and winter weather conditions,
nuclear plant closures, and lower precipitation feeding
hydroelectric dams would be expected to have propor-
tionally greater fossil fuel consumption than a year with
poor economic performance, high fuel prices, mild tem-
peratures, and increased output from nuclear and hydro-
electric plants.
Longer-term changes in energy consumption pat-
terns, however, tend to be more a function of changes
that affect the scale of consumption (e.g., population,
number of cars, and size of houses), the efficiency with
which energy is used in equipment (e.g., cars, power
plants, steel mills, and light bulbs) and consumer behav-
ior (e.g., walking, bicycling, or telecommuting to work
instead of driving).
Energy-related CO2 emissions are also a function
of the type fuel or energy consumed and its carbon inten-
sity. Producing heat or electricity using natural gas in-
stead of coal, for example, can reduce the CO2 emissions
associated with energy consumption because of the lower
carbon content of natural gas per unit of useful energy
produced. Table ES-2 shows annual changes in emissions
during the last few years of the 1990s for particular fuel
types and sectors.
Carbon dioxide emissions from fossil fuel combus-
tion grew rapidly in 1996, due primarily to two factors: 1)
fuel switching by electric utilities from natural gas to more
carbon intensive coal as colder winter conditions and the
associated rise in demand for natural gas from residential,
commercial, and industrial customers for heating caused
gas prices to rise sharply; and 2) higher consumption of
petroleum fuels for transportation. Milder weather condi-
tions in summer and winter moderated the growth in emis-
sions in 1997; however, the shut-down of several nuclear
power plants lead electric utilities to increase their con-
sumption of coal and other fuels to offset the lost capacity.
In 1998, weather conditions were again a dominant factor
in slowing the growth in emissions. Warm whiter tempera-
tures resulted in a significant drop in residential, commer-
cial, and industrial natural gas consumption. This drop in
emissions from natural gas used for heating was primarily
offset by two factors: 1) electric utility emissions, which
increased in part due to a hot summer and its associated air
conditioning demand; and 2) increased motor gasoline
consumption for transportation.
In 1999, the increase in emissions from fossil fuel
combustion was driven largely by growth in petroleum
consumption for transportation. In addition, heating fuel
demand partially recovered in the residential, commer-
cial, and industrial sectors as winter temperatures dropped
relative to 1998, although temperatures were still warmer
than normal. These increases were offset, in part, by a
Table ES-2: Annual Change in C02 Emissions from Fossil Fuel Combustion for Selected
Fuels and Sectors (Tg C02 Eq. and Percent)
Sector
Fuel Type
1995 to 1996
1996 to 1997
1997 to 1998
1998 to 1999
f Electric Utility
1 Electric Utility
| Electric Utility
(Transportation*
};ResidentiaL
1 Commercial
| Industrial
^industrial
pll Sectors6
Coal
Natural Gas
Petroleum
Petroleum
Natural Gas
Natural Gas
Coal
Natural Gas
All Fuels
89
-25
5
38
21
7
.9
.3
.1
.8
.4
.0
-7.3
17
181
.8
.7
5.7%
-14.7%
10.0%
2.5%
8.1%
4.3%
-2.7%
3.4%
3.5%
52.0
13.1
8.1
7.6
-14.0
3.1
2.0
-0.5
71.9
3.1%
9.0%
14.4%
0.5%
-4.9%
1.8%
0.8%
-0.1%
1.4%
14.3
16.2
26.7
34.1
-24.0
-11.1
-1.1
-14.5
11.9
0.8%
10.1%
41.6%
2.1%
-8.9%
-6.4%
-0.4%
-2.7%
0.2%
-32.1
-7.8
-17.4
57.6
8.5
2.9
29.2
1.6
66.4
-1.8%
-4.4%
-19.1%
3.6%
3.4%
1.8%
11.2%
0.3%
1.2%
ta Excludes emissions from International Bunker Fuels.
*_b Includes fuels and sectors not shown in table.
Executive Summary ES-5
-------
decline in emissions from electric utilities due primarily
to: 1) an increase in net generation of electricity by nuclear
plants (8 percent) to record levels, which reduced de-
mand from fossil fuel plants; and 2) moderated summer
temperatures compared to the previous year—thereby
reducing electricity demand for air conditioning. Utiliza-
tion of existing nuclear power plants, measured as a plant's
capacity factor,7 has increased from just over 70 percent
in 1990 to over 85 percent in 1999.
Another factor that does not affect total emissions,
but does affect the interpretation of emission trends is
the allocation of emissions from nonutility power pro-
ducers. The Energy Information Administration (EIA)
currently includes fuel consumption by nonutilities with
the industrial end-use sector. In 1999, there was a large
shift in generating capacity from utilities to nonutilities,
as restructuring legislation spurred the sale of 7 percent
of utility generating capability (EIA 2000b). This shift is
illustrated by the increase in industrial end-use sector
emissions from coal and the associated decrease in elec-
tric utility emissions. However, emissions from the in-
dustrial end-use sector did not increase as much as would
be expected even though net generation by nonutilities
increased from 11 to 15 percent of total U.S. electricity
production (EIA 2000b).8
Overall, from 1990 to 1999, total emissions of CO2
and N2O increased by 645.2 (13 percent) and 35.7 Tg CO2
Eq. (9 percent), respectively, while CH4 emissions de-
creased by 24.9 Tg CO2 Eq. (4 percent). During the same
period, aggregate weighted emissions of MFCs, PFCs,
and SF6 rose by 51.8 Tg CO2 Eq. (62 percent). Despite
being emitted in smaller quantities relative to the other
principal greenhouse gases, emissions of HFCs, PFCs,
and SF6 are significant because many of them have ex-
tremely high global warming potentials and, in the cases
of PFCs and SF6, long atmospheric lifetimes. Conversely,
U.S. greenhouse gas emissions were partly offset by car-
bon sequestration in forests and in landfilled carbon,
which were estimated to be 15 percent of total emissions
in 1999.
Other significant trends in emissions from additional
source categories over the nine year period from 1990
through 1999 included the following:
• Aggregate HFC and PFC emissions resulting from
the substitution of ozone depleting substances (e.g.,
CFCs) increased by 55.8 Tg CO2 Eq. This increase
was partly offset, however, by reductions in PFC
emissions from aluminum production (9.2 Tg CO2
Eq. or 48 percent), and reductions in emissions of
HFC-23 from the production of HCFC-22 (4.4 Tg CO2
Eq. or 13 percent). Reductions in PFC emissions from
aluminum production were the result of both volun-
tary industry emission reduction efforts and lower
domestic aluminum production. HFC-23 emissions
from the production of HCFC-22 decreased due to a
reduction in the intensity of emissions from that
source, despite increased HCFC-22 production.
• Emissions of N2O from mobile combustion rose by
9.1 Tg CO2 Eq. (17 percent), primarily due to increased
rates of N2O generation in highway vehicles.
• Methane emissions from coal mining dropped by 26
Tg CO2 Eq. (30 percent) as a result of the mining of
less gassy coal from underground mines and the in-
creased use of methane from degasification systems.
• Nitrous oxide emissions from agricultural soil man-
agement increased by 29.3 Tg CO2 Eq. (11 percent)
as fertilizer consumption and cultivation of nitrogen
fixing crops rose.
• By 1998, all of the three major adipic acid producing
plants had voluntarily implemented N2O abatement tech-
nology, and as a result, emissions fell by 9.3 Tg CO2 Eq.
(51 percent). The majority of this decline occurred from
1997 to 1998, despite increased production.
The following sections describe the concept of Glo-
bal Warming Potentials (GWPs), present the anthropogenic
sources and sinks of greenhouse gas emissions in the
United States, briefly discuss emission pathways, further
summarize the emission estimates, and explain the relative
importance of emissions from each source category.
7 The capacity factor is defined as the ratio of the electrical energy produced by a generating unit for a given period of time to the
electrical energy that could have been produced at continuous full- power operation during the same period (DOE/EIA 2000).
8 It is unclear whether reporting problems for electric utilities and the industrial end-use sector have increased with the dramatic growth
in nonutilities and the opening of the electric power industry to increased competition.
ES-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Box ES-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data
!; There are several ways to assess a nation's greenhouse gas emitting intensity. The basis for measures of intensity can be 1) per
:: unit of aggregate energy consumption, because energy-related activities are the largest sources of emissions; 2) per unit of fossil fuel
•<: consumption, because almost all energy-related emissions involve the combustion of fossil fuels; 3) per unit of electricity consump-
tion, because the electric power industry—utilities and nonutilities combined—were the largest sources of U.S. greenhouse gas
" emissions in 1999; 4) per unit of total gross domestic product as a measure of national economic activity; or 5) on a per capita basis.
> Depending upon the measure used, the United States could appear to have reduced or increased its national greenhouse gas intensity
•during the 1990s.
Table ES-3 provides data on various statistics related to U.S. greenhouse gas emissions normalized to 1990 as a baseline year.
;f Greenhouse gas emissions in the U.S. have grown at an average annual rate of 1.2 percent since 1990. This rate is slightly slower than
•; that for total energy or fossil fuel consumption—thereby indicating an improved or lower greenhouse gas emitting intensity—and
; much slower than that for either electricity consumption or overall gross domestic product. Emissions, however, are growing faster
; than national population, thereby indicating a worsening or higher greenhouse gas emitting intensity on a per capita basis (see Figure
ES-5). Overall, globalatmospheric C02 concentrations—a function of many complex anthropogenic and natural processes—are
increasing at 0.4 percent per year.
Table ES-3: Recent Trends in Various U.S. Data (Index 1990 = 100)
Variable
1991 1992 1993 1994 1995 1996 1997
Growth
1998 1999 Rate'
GH6 Emissions3
Energy Consumption1"
Fossil Fuel Consumption15
Electricity Consumption6
GDP°
Populationd
Atmospheric C02 Concentration6
99
100
99
102
100
101
100
101
101
101
102
103
102
101
103
104
103
105
105
103
101
105
106
105
108
110
104
101
106
108
107
111
112
105
102
109
111
110
114
116
106
102
111
112
112
116
122
107
103
111
112
112
119
127
108
104
112
115
113
120
132
109
104
1.2%
1.5%
1.4%
2.1%
3.2%
1.0%
0.4%
6WP weighted values
Energy content weighted values. (EIA 2000a)
Gross Domestic Product in chained 1996 dollars (BEA 2000)
(U.S. Census Bureau 2000)
Mauna Loa Observatory, Hawaii (Keeling and Whorf 2000)
Average annual growth rate
Figure ES-5
Emissions per $GDP
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
Source: BEA (2000), U.S. Census Bureau (2000), and emission
estimates in this report.
Executive Summary ES-7
-------
Box ES- 3: Weather and Non-Fossil Energy Adjustments to C02 from Fossil Fuel Combustion Trends
1 An analysis was performed using ElA's Short-Term Integrated Forecasting (STIFS) model to examine the effects of variations in
: weather and output from nuclear and hydroelectric generating plants on U.S. energy-related C02 emissions.9 Weather conditions
" affect energy demand because of the impact they have on residential, commercial, and industrial end-use sector heating and cooling
j demands. Wanner winters tend to reduce demand for heating fuels—especially natural gas—while cooler summers tend to reduce
, air conditioning-related electricity demand. Changes in electricity output from hydroelectric and nuclear power plants do not
' necessarily affect final energy demand, but increased output from these plants does offset electricity generation by fossil fuel power
; plants, and therefore leads to reduced C02 emissions.
'; The results of this analysis show that C02 emissions from fossil fuel combustion would have been roughly 1.9 percent higher
[ (102 Tg C02 Eq.) if weather conditions and hydroelectric and nuclear power generation had remained at normal levels (see Figure ES-
6). Similarly, emissions in 1997 and 1998 would have been roughly 0.5 and 1.2 percent (7 and 17 Tg C02 Eq.) greater under normal
I conditions, respectively.
In addition to the absolute level of emissions being greater, the growth rate in C02 emissions from fossil fuel combustion from
- 1998 to 1999 would have been 2.0 percent instead of the actual 1.2 percent if both weather conditions and nonfossil electricity
• generation had been normal (see Figure ES-7). Similarly, emissions in 1998 would have increased by 0.9 percent under normal
' conditions versus the actual rate of 0.2 percent.
Figure ES-6
F1JMT
1999 IS
i | 1998
*
] 1999
U1997
(0) 1997
-1.0% -0.5% 0.0% 0.5% 1.0% 1.5% 2.0%
Hydro &
Nuclear
Electricity ••
Generation ;"
Cooling i"
Degree Days :
Heating
Degree Days
Figure ES-7
Total
1999 Adjusted
103
100
Hydro & |;
Nuclear F
Adjusted i,,
Weather '
Adjusted ;
1997
1998
1999
Warmer winter conditions in both 1998 and 1999 had a significant effect on U.S. C02 emissions" by reducing demand for heating
fuels. Heating degree days in the United States in 1998 and 1999 were 14 and 7 percent below normal, respectively (see Figure
ES-8).10 These warm winters, however, were partially countered by increased electricity demand that resulted from hotter summers.
Cooling degree days in 1998 and 1999 were 18 and 3 percent above normal, respectively (see Figure ES-9).
9 The STIFS model is employed in producing EIA's Short-Term Energy Outlook (DOE/EIA-0202). Complete model documentation can
be found at < http://www.eia.doe.gov/emeu/steo/pub/contents.html>. A variety of other factors that influence energy-related CO2
emissions were also examined such as: changes in output from energy intensive manufacturing industries, and changes in fossil fuel
prices. These additional factors, however, were not found to have a significant effect on emission trends.
10 Degree days are relative measurements of outdoor air temperature. Heating degree days are deviations of the mean daily temperature
below 65° F, while cooling degree days are deviations of the mean daily temperature above 65° F. Excludes Alaska and Hawaii. Normals
are based on data from 1961 through 1990. The variation in these normals during this time period was ±10 percent and ±14 percent
for heating and cooling degree days, respectively (99 percent confidence interval).
ES-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
s; Figure ES-8
I-
(L
I
o
•!LZ s
99% Confidence - Upper Bound
Normal
(4,576 Heating Degree Days)
99% Confidence - Lower Bound
1949 1952 1955 1958 1961 1964 1967 1970 1973 1976 1979 1982 1985 1988 1991 1994 1997
Note: Climatological normal data is highlighted. Statistical confidence interval for "normal" climatology period of 1961
through 1990.
Source: NOAA(2000b)
fc,.
t_
Figure ES-9
20
99% Confidence - Upper Bound
Normal
(1,193 Cooling Degree Days)
99% Confidence - Lower Bound
IM
1949 1952 1955 1958 1961 1964 1967 1970 1973 1976 1979 1982 1985 1988 1991 1994 1997
Note: Climatological normal data is highlighted. Statistical confidence interval for "normal" climatology period of 1961
through 1990.
Source: NOAA(2000b)
Although no new U.S. nuclear power plants have been constructed in many years, the utilization (i.e., capacity factors11)
of existing plants reached record levels in 1998 and 1999, approaching 90 percent. This increase in utilization translated into
an increase in electricity output by nuclear plants of slightly more than 7 percent in both years. This increase in nuclear plant
output, however, was partially offset by reduced electricity output by hydroelectric power plants, which declined by 10 and
4 percent in 1998 and 1999, respectively. Electricity generated by nuclear plants provides approximately twice as much of
the energy consumed in the United States as hydroelectric plants. Nuclear and hydroelectric power plant capacity factors
since 1973 are shown in Figure ES-10.
11 The capacity factor is defined as the ratio of the electrical energy produced by a generating unit for a given period of time to the
electrical energy that could have been produced at continuous full- power operation during the same period (DOE/EIA 2000).
Executive Summary ES-9
-------
Figure ES-10
1973 1978 1983 1988 1993 1998
Box ES-4: 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 Administra-
tion (FHWA), Likewise, the number of miles driven—up 13 percent from 1990 to 1999—and gallons of gasoline consumed each year
in the United States have increased steadily since the 1980s, according to the FHWA and Energy Information Administration,
respectively. These increases in motor vehicle usage are the result of a confluence of factors including population growth, economic
growth, urban sprawl, low fuel prices, and increasing popularity of sport utility vehicles and other light-duty trucks that tend to have
lowerfuel efficiency.12 A similar set of social and economic trends has led to a significant increase in airtravel and freight transporta-
tion—by both air and road modes—during the 1990s.
One of the unintended consequences of these changes is 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 are major sources of carbon monoxide (CO), carbon dioxide (C02), methane (CH4), nonmethane volatile
organic compounds (NMVOCs), nitrogen oxides (NO*), nitrous oxide (N20), and hydrofluorocarbons (HFCs). Motor vehicles are also
important contributors to many serious air pollution problems, including ground-level ozone (i.e., smog), acid rain, fine paniculate
matter, and global warming. Within the United States and abroad, government agencies have taken actions to reduce these emissions.
Since the 1970s, the EPA has required the reduction of 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. New vehicles are now equipped with advanced emissions
controls, which are designed to reduce emissions of NOX, hydrocarbons, and CO.
Table ES-4 summarizes greenhouse gas emissions from all transportation-related activities. Overall, transportation activities-
excluding international bunker fuels—accounted for an almost constant 26 percent of total U.S. greenhouse gas emissions from 1990
to 1999. These emissions were primarily C02from fuel combustion, which increased by 16 percent from 1990 to 1999. However,
because of larger increases in N20 and HFC emissions during this period, overall emissions from transportation activities actually
increased by 18 percent
lz The average miles per gallon achieved by the U.S. highway vehicle fleet actually decreased by slightly less than one percent in both
1998 and 1999.
ES-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table ES-4: Transportation-Related Greenhouse Gas Emissions (Tg C02 Eq.)
"Gas/Vehicle Type
-~C02
""- Passenger Cars
f- Light-Duty Trucks
Other Trucks
l Buses
Aircraft3
' - Boats and Vessels ;
* Locomotives
>*- Other"
^~ International Bunker Fuels0
»CH4
~i Passenger Cars
i Light-Duty Trucks
Other Trucks and Buses
**~ Aircraft
Boats and Vessels ','
Locomotives
* Other*
International Bunker Fuels0
.N20
N— Passenger Cars
["'-" Light-Duty Trucks
fi Other Trucks and Buses
|p Aircraft*
p Boats and Vessels
Jp Locomotives
1==- Other"1
if -: International Bunker Fuels0
flFCsT • ' ' .
•P Mobile Air Conditioners6
iTotal0
1990
1,474.4
620.0
283.1
206.0
10.7
176.7
59.4
28.4
90.1
114.0
5.0
2.4
1.6
0.4
0.2
0.1
6.1
, 0.2
+
54.3
31.0
17.8
2.6
1.7
0.4
0.3
0.6
1.0
' : +
•
1,533.7
" * 1995
'" **=^-™*-£ i,58i:s '
, -^— ,. g^ g
S,***^ 325.3':
'E~!*B*r™' 235.9.
.;.;" '""**" . 13.5:'
' ;^»«2 '171-5
'."-'-' 66.9
..
. •••?*---' -95:3
" ' ^~: : 101.0"
4.9
p:;:":.^ • 2.0
• • <^~-—;- 1i9-.
• .,^2^ Q.5..
- SKBSfSKSS-.! - .0-1
'- fc . • '" '. . '0.1
• ^™~^ ... 0.2
. . . ., ..+
66.8
•— *: :33;|).-
£^T-V^. • •: 27_-(
: ' '^23"^ '-"'3.6
• "^tr™"! iJ'
g^^s Q^
•ir^S -• -' °'3 •
u " 0.6
:~:"A;'U" 0.9
"M'*—M* : 9.5'
• m^^m^m^'^ - :;
'S",,,3 1,663.0 '
1996
1,621.2
654.1
333.5
248.1
11.3
180.2
63.8
33.4
96.7
102.2
4.8
2.0
1.6
0.7
.-'0,1
0.1
0.1
; 0.2
+
65.3
32.7
23.9
5.6
1.8
0.4
0.3
0.6
0.9
13.5
"13.5
1,704.8
1997
1,631.4
660.2
337.3
257.0
12.0
179.0
50.2
34.4
101.4
109.8
4.7
2.0
1.6
0.7
0.2
0.1
0.1
0.2
. +
65.2
32.4
24.0
5.8
1.7
0.3
0.2
0.6
1.0
17.2
* 17.2
1,718.5
1998
1,659.0
674.5
356.9
257.9
12.3
183.0
47.9
33.6
93.0
112.8
4.6
2.0
1.5
0.7
0.1
0.1
+
0.2
+ •
64.2
32.1
23.3
5.9
i.8
0.3
0.2
0.6
1.0
20.6
20.6
1,748.4
1999
1,716.4
688.9
364.8
269.7
12.9
184.6
65.6
35.1
94.9
107.3
4.5
1.9
1.4
0.7
0.2
0.1
-f.
0.2
.+
63.4
31.5
22.7
6.1
1.8
0.4
0.2
0.6
1.0
23.7
23.7
1,808.0
s+Does not exceed 0.05 Tg C02 Eq.. '. .
|,Note: Totals may not sum due to independent rounding.
w Aircraft emissions consist of emissions from all jet fuel (less bunker fuels) and aviation gas consumption.
|j "Other" C02 emissions include motorcycles, construction equipment, agricultural machinery, pipelines, and lubricants.
j£ Emissions from international Bunker Fuels include emissions from both civilian and military activities, but are not included in totals.
*A,-"Other" CH4 and N20 emissions include 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
4 garden, light construction, airport service.
p Includes primarily HFC-134a. '
Executive Summary ES-11
-------
Box ES- 5: Greenhouse Gas Emissions from Electric Utilities
'" Like transportation, activities related to the generation, transmission, and distribution of electricity in the United States resulted in
a significant fraction of total U.S. greenhouse gas emissions. The electric power industry in the United States is composed of traditional
: electric utilities as well as other entities, such as power marketers and nonutility power producers. Table ES-5 presents emissions from
I electric utility-related activities. Aggregate emissions from electric utilities of all greenhouse gases increased by 11 percent from 1990
1 to 1999, and accounted for a relatively constant 29 percent of U.S. emissions during the same period. Emissions from nonutility
- generators are not included in these estimates. Nonutilities were estimated to have produced about 15 percent of the electricity
,, generated in the United States in 1999, up from 11 percent in 1998 (EIA 2000c). Therefore, a more complete accounting of
" greenhouse gas emissions from the electric power industry (i.e., utilities and nonutilities combined) would account for roughly 40
percent of U.S. C02 emissions (EIA 2000d).
The majority of electric utility-related emissions resulted from the combustion of coal in boilers to produce steam that is passed
,, through a turbine to generate electricity. Overall, the generation of electricity—especially when nonutility generator are included—
results in a larger portion of total U.S. greenhouse gas emissions than any other activity.
Table ES-5: Electric Utility-Related Greenhouse Gas Emissions (Tg C02 Eq.)
Gas/Fuel Type or Source
C02
Coal
Natural Gas
Petroleum
Geothermal
CH4
Stationary Combustion (Utilities)
N20
Stationary Combustion (Utilities)
SF6
Electrical Transmission and Distribution
Total
1990
1,757.3
1,509.3
151.1
96.8
0.2
0.5
0.5
7.4
7.4
20.5
20.5
1,785.7
1995
1,810.6
1,587.7
171.8
: 51.0
0.1
0.5
0.5
7.8
7.8
25.7
25.7
1,844.5
1996
1,880.3
1,677.7
146.5
56.0
0.1
0.5
0.5
8.2
8.2
25.7
25.7
1,914.7
1997
1,953.5
1,729.7
159.6
64.1
0.1
0.5
0.5
8.5
8.5
25.7
25.7
1,988.2
1998
2,010.7
1,744.0
175.8
90.8
0.1
0.5
0.5
8.7
8.7
25.7
25.7
2,045.6
1999
1,953.4
1,711.9
168.0
73.4
+
0.5
0.5
8.6
8.6
25.7
25.7
1,988.2
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding. Excludes emissions from non-utilities, which are currently accounted for under the
industrial end-use sector.
Global Warming Potentials
Gases in the atmosphere can contribute to the
greenhouse effect both directly and indirectly. Direct ef-
fects occur when the gas itself is a greenhouse gas. Indi-
rect radiative forcing occurs when chemical transforma-
tions of the original gas produce a gas or gases that are
greenhouse gases, when a gas influences the atmospheric
lifetimes of other gases, and/or when a gas affects other
atmospheric processes that alter the radiative balance of
the earth (e.g., affect cloud formation or albedo). The
concept of a Global Warming Potential (GWP) has been
developed to compare the ability of each greenhouse gas
to trap heat in the atmosphere relative to another gas.
Carbon dioxide (CO^ was chosen as the reference gas to
be consistent with BPCC guidelines.
Global Wanning Potentials are not provided for the
criteria pollutants CO, NOX, NMVOCs, and SO2 because
there is no agreed upon method to estimate the contribu-
tion of gases that are short-lived in the atmosphere and
have only indirect effects on radiative forcing (IPCC1996).
All gases in this executive summary are presented
in units of teragrams of carbon dioxide equivalents (Tg
CO2 Eq.) The relationship between gigagrams (Gg) of a
gas and Tg CO2 Eq. can be expressed as follows:
Tg CO2 Eq.= (Gg of gas)x (GWP)x
l.OOOGg
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 that of one
ES-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
unit mass of carbon dioxide over a period of time. While
any time period can be selected, the 100 year GWPs rec-
ommended by the IPCC and employed by the United
States for policy making and reporting purposes were
used in this report (IPCC 1996). GWP values are listed
below in Table ES-6.
Table ES-6: Global Warming Potentials
(100 Year Time Horizon)
Gas
GWP
Carbon dioxide (C02)
Methane (CH4)*
Nitrous oxide (N20)
HFC-23
HFC-125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
:-... HFC-236fa
HFC-4310mee
CF4
C2F6
c/tF-io
^6^14
SF6
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)
":* The methane GWP includes the direct effects and those
I- indirect effects due to the production of tropospheric ozone and
i. stratospheric water vapor. The indirect effect due to the
i. production of C02 is not included.
Carbon Dioxide Emissions
The global carbon cycle is made up of large carbon
flows and reservoirs. Hundreds of billions of tons of car-
bon in the form of CO2 are absorbed by oceans and living
biomass (sinks) and are emitted to the atmosphere annu-
ally through natural processes (sources). When in equi-
librium, carbon fluxes among these various reservoirs are
roughly balanced.
Since the Industrial Revolution, this equilibrium of
atmospheric carbon has been altered. Atmospheric con-
centrations of CO2 have risen about 28 percent (IPCC
1996), principally because of fossil fuel combustion, which
accounted for 98 percent of total U.S. CO2 emissions in
1999. Changes in land use and forestry practices can also
emit CO2 (e.g., through conversion of forest land to agri-
cultural or urban use) or can act as a sink for CO2 (e.g.,
through net additions to forest biomass).
Figure ES-11 and Table ES-7 summarize U.S. sources
and sinks of CO2. The remainder of this section then dis-
cusses CO2 emission trends in greater detail.
Figure ES-11
Fossil Fuel Combustion
Cement Manufacture
Waste Combustion
Lime Manufacture
Natural Gas Flaring
Limestone and Dolomite Use
Soda Ash Manufacture
and Consumption
Carbon Dioxide Consumption
2S 5'453
3
10 20 30
Tg Co2 Eq.
40
Energy
Energy-related activities accounted for the vast
majority of U.S. CO2 emissions for the period of 1990
through 1999. Carbon dioxide from fossil fuel combus-
tion was the dominant contributor. In 1999, approximately
84 percent of the energy consumed in the United States
was produced through the combustion of fossil fuels.
The remaining 16 percent came from other energy sources
such as hydropower, biomass, nuclear, wind, and solar
(see Figure ES-12 and Figure ES-13). A discussion of spe-
cific trends related to CO2 emissions from energy con-
sumption is presented below.
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 per unit of energy content varies signifi-
cantly by fuel type. For example, coal contains the high-
est amount of carbon per unit of energy, while petroleum
has about 25 percent less carbon than coal, and natural
gas about 45 percent less. From 1990 through 1999, pe-
troleum supplied the largest share of U.S. energy demands,
accounting for an average of 39 percent of total energy
consumption. Natural gas and coal followed in order of
importance, accounting for an average of 24 and 23 per-
cent of total energy consumption, respectively. Most
Executive Summary ES-13
-------
Table ES-7: U.S. Sources of C02 Emissions and Sinks (Tg C02 Eq.)
Source or Sink
Fossil Fuel Combustion
Cement Manufacture
Waste Combustion
Lime Manufacture
Natural Gas Raring
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
"Carbon Dioxide Consumption
Land-Use Change and Forestry (Sink)a
-International Bunker Fuels"
Total Emissions
Net Emissions (Sources and Sinks)
1990
4,835.7 "
33.3
17.6
11.2
5.1 "" *
5.1 "
4.1
0.8 -
(1,059.9)
114.0
4,913.0
3,853.0
1995
5,121.3
36.8
23.1
12.8
13.6
7.0
4.3
1.0
(1,019.1)
101.0
5,219.8
4,200.8
1996
5,303.0
37.1
24.0
13.5
13.0
7.3
4.3
1.1
(1,021.6)
102,2
5,403.2
4,381.6
1997
5,374.9
38.3
25.7
13.7
12.0
8.3
4.4
1.3
(981,9)
109.8
5,478.7
4,496.8
1998
5,386.8
39.2
25.1
13.9
10.8
8.1
4.3
1.4
(983.3)
112.8
5,489.7
4,506.4
1999
5,453.1
39.9
26.0
13.4
11.7
8.3
4.2
1.6
(990.4)
107.3
5,558.1
4,567.8
a Sinks are only included in net emissions total, and are based partially on projected activity data.
11 Emissions from International Bunker Fuels are not included in totals.
= Note: Totals may not sum due to independent rounding.
Note: Parentheses indicate negative values (or sequestration).
Figure ES-12
Figure ES-13
7.6% Renewable
8.0% Nuclear
22.5% Coal
: 22.9% Natural Gas
39.0% Petroleum
Source: DOE/E1A-0384(99), Annual Energy Review 1998,
Tabla 1.3, July 2000
1991
1993
1995
1997
1999
Note: Expressed as gross calorific values.
Source: DOE/EIA-0384(97), Annual Energy Review 1999,
Table 1.3, July 2000
petroleum was consumed in the transportation end-use
sector, while the vast majority of coal was used by elec-
tric utilities, and natural gas was consumed largely in the
industrial and residential end-use sectors.
Emissions of CO2 from fossil fuel combustion in-
creased at an average annual rate of 1.4 percent from 1990
to 1999. The fundamental factors behind this trend in-
clude (1) a robust domestic economy, (2) relatively low
energy prices as compared to 1990, (3) fuel switching by
electric utilities, and (4) heavier reliance on nuclear en-
ergy. After 1990, when CO2 emissions from fossil fuel
combustion were 4,835.7 Tg CO2 Eq., there has been a
relatively steady increase to 5,453.1 Tg CO2 Eq. in 1999.
Overall, CO2 emissions from fossil fuel combustion in-
creased by 13 percent over the ten year period.
In 1999, fossil fuel emission trends were primarily
driven by a strong economy and an increased reliance on
carbon-neutral nuclear power for electricity generation.
Although the price of crude oil increased over 40 percent
from 1998 and relatively mild weather conditions moder-
ated energy consumption for heating and cooling, emis-
sions from fossil fuels still rose 1.2 percent from 1998.
Emissions from the combustion of petroleum products in
1999 grew the most (64 Tg CO2 Eq. or about 3 percent),
although emissions from the combustion of petroleum by
electric utilities decreased 19 percent. That decrease was
ES-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
offset by increased emissions from petroleum combus-
tion in the residential, commercial, industrial, and espe-
cially transportation end-use sectors. Emissions from the
combustion of natural gas in 1999 increased slightly (5
Tg CO2 Eq. or 0.4 percent) and emissions from coal con-
sumption decreased slightly (3 Tg CO2 Eq. or 0.1 percent)
as the industrial end-use sector substituted more natural
gas for coal in 1999.
As introduced above, the four end-use sectors con-
tributing to CO2 emissions from fossil fuel combustion
include industrial, transportation, residential, and com-
mercial. Electric utilities 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, electric utility emissions have been
distributed to each end-use sector based upon their frac-
tion of aggregate electricity consumption. This method
of distributing emissions assumes that each end-use sec-
tor consumes electricity that is generated with the na-
tional average mix of fuels according to their carbon in-
tensity. In reality, sources of electricity vary widely in
carbon intensity. By giving equal carbon-intensity weight
to each sector's electricity consumption, for example,
emissions attributed to the residential sector may be over-
estimated, while emissions attributed to the industrial
sector may be underestimated. Emissions from electric
utilities are addressed separately after the end-use sec-
tors have been discussed.
It is important to note, though, that all emissions
resulting from the generation of electricity by the grow-
ing number of nonutility power plants are currently allo-
cated to the industrial sector. Nonutilities supplied 15
percent of the electricity consumed in the United States
in 1999. Emissions from U.S. territories are also calculated
separately due to a lack of end-use-specific consumption
data. Table ES-8, Figure ES-14, and Figure
ES-15 summarize CO2 emissions from fossil fuel combus-
tion by end-use sector.
Industrial End- Use Sector. Industrial CO2 emissions
resulting from direct fossil fuel combustion and from the
generation of electricity by utilities consumed by indus-
try accounted for 33 percent of CO2 from fossil fuel com-
bustion in 1999. About two-thirds of these emissions re-
sulted from direct fossil fuel combustion to produce steam
and/or heat for industrial processes or by non-utilities to
generate electricity, the latter of which is growing rapidly.
The remaining third of emissions resulted from consum-
ing electricity from electric utilities for motors, electric fur-
naces, ovens, lighting, and other applications.
Transportation End-Use Sector. Transportation
activities—excluding international bunker fuels—ac-
counted for 31 percent of CO2 emissions from fossil fuel
combustion in 1999.13 Virtually all of the energy consumed
in this end-use sector came from petroleum products. Just
under two thirds of the emissions resulted from gasoline
consumption in motor vehicles. The remaining emissions
came from other transportation activities, including the
combustion of diesel fuel in heavy-duty vehicles and jet
fuel in aircraft.
Residential and Commercial End- Use Sectors. The resi-
dential and commercial end-use sectors accounted for 19 and
16 percent, respectively, of CO2 emissions from fossil fuel con-
Table ES-8: C02 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg C02 Eq.)4
K End-Use Sector 1990 ZlZZ: 1995 1996 1997
1998
1999
re Industrial
Transportation
P Residential
»,: Commercial
fc U.S. Territories
* Total
' '.-••••- ; -,-. -
: 1,636.0 :;;„:::-
. 1,474.4 •:--.-•- :.
" . ...930.7.. ;,^£j
760.8 ™- '
. 33.7 - &V^
4,835.7 _„,
1,709.5
1,581.8
988.7
797.2
44.0
5,121.3
1,766.0
1,621.2
1,047.5
828.2
40.1
5,303.0
1,783.6
1,631.4
1,044.2
872.9
42.8
5,374.9
1,758.8
1,659.0
1,040.9
880.2
47.9
5,386.8
1,783.9
1,716.4
1,035.8
864.0
53.0
5,453.1
Emissions Jrom electric utilities are allocated based on aggregate electricity consumption "in each end-use sector.
13 If emissions from international bunker fuels are included, the transportation end-use sector accounted for 33 percent of U.S.
emissions from fossil fuel combustion in 1999.
Executive Summary ES-15
-------
Figure ES-14
Figure ES-15
•plHIip!!«:«B»
,ffiil JO, EmissipMlrlH^
2,000
• Natural Gas
Relative
Contribution
by Fuel Type
Petroleum
Coal
Noto: Utilities also Includes emissions of 0.04 Tg CO2 Eq.
from goothermal based electricity generation
sumption in 1999. Both sectors relied heavily on electricity for
meeting energy needs, with 66 and 74 percent, respectively, of
theiremSssions attributable toelectricityconsumptionfor light-
ing, heating, cooling, and operating appliances. The remaining
emissions were largely due to the consumption of natural gas
and petroleum, primarily for meeting heating and
cooking needs.
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 from fossil fuels and
emitted 36 percent of the CO2 from fossil fuel combus-
tion in 1999. The type of fuel combusted by utilities has
a significant effect on their emissions. For example, some
electricity is generated with low CO2 emitting energy
technologies, particularly non-fossil options such as
nuclear, hydroelectric, or geothermal energy. However,
electric utilities rely on coal for over half of their total
energy requirements and accounted for 85 percent of all
coal consumed in the United States in 1999. Consequently,
changes in electricity demand have a significant impact
on coal consumption and associated CO2 emissions.
Note, again, that all emissions resulting from the genera-
tion of electricity by nonutility plants are currently allo-
cated to the industrial end-use sector.
S
2000
1600
1200
800
400
0
From Electricity Consumption
From Direct Fossil Fuel Cpmbustion
XXX
Note: All emissions related to the generation of electricity by
nonutilities are currently allocated to the combustion category
under the industrial sector due to data limitations.
Natural Gas Flaring
Carbon dioxide is produced when natural gas from
oil wells is flared (i.e., combusted) to relieve rising pres-
sure or to dispose of small quantities of gas that are not
commercially marketable. In 1999, flaring activities emit-
ted approximately 11.7 Tg CO2 Eq., or about 0.2 percent of
U.S. CO2 emissions.
Biomass Combustion
Biomass—in the form of fuel wood and wood
waste—was used primarily by the industrial end-use sec-
tor, while the transportation end-use sector was the pre-
dominant user of biomass-based fuels, such as ethanol
from corn and woody crops. Ethanol and ethanol blends,
such as gasohol, are typically used to fuel public trans-
port vehicles.
Although these fuels do emit CO2, in the long run
the CO2 emitted from biofuel consumption does not in-
crease atmospheric CO2 concentrations if the biogenic car-
bon emitted is offset by the growth of new biomass. For
example, fuel wood burned one year but re-grown the next
only recycles carbon, rather than creating a net increase in
total atmospheric carbon. Net carbon fluxes from changes
in biogenic carbon reservoirs in wooded or croplands are
accounted for under Land-Use Change and Forestry.
ES-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Gross CO2 emissions from biomass combustion
were 234.1 Tg CO2 Eq. in 1999, with the industrial sector
accounting for 81 percent of the emissions, and the resi-
dential sector 14 percent. Ethanol consumption by the
transportation sector accounted for only 3 percent of CO2
emissions from biomass combustion.
Industrial Processes
Emissions are produced as a by-product of many
non-energy-related activities. For example, industrial pro-
cesses can chemically transform raw materials. This trans-
formation often releases greenhouse gases such as CO2.
The major 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 consumption, and CO2 consumption.
Total CO2 emissions from these sources were approxi-
mately 67.4 Tg CO2 Eq. in 1999, accounting for about 1
percent of total CO2 emissions. Since 1990, emissions
from each of these sources increased, except for emis-
sions from soda ash manufacture and consumption, which
has remained relatively constant.
Cement Manufacture (39.9 Tg C02 Eq.)
Carbon dioxide is produced primarily during the
production of clinker, an intermediate product from which
finished Portland and masonry cement are made. Specifi-
cally, CO2 is created when calcium carbonate (CaCO3) is
heated in a cement kiln to form lime and CO2. This lime
combines with other materials to produce clinker, while
the CO2 is released into the atmosphere.
Lime Manufacture (13.4 Tg C02 Eq.)
Lime is used in steel making, construction, pulp and
paper manufacturing, and water and sewage treatment. It
is manufactured by heating milestone (mostly calcium car-
bonate, CaCO3) in a kiln, creating calcium oxide (quick-
lime) and CO2, which is normally emitted to the atmosphere.
Limestone and Dolomite Use (8.3 Tg C02 Eq.)
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 desulfurization systems
to remove sulfur dioxide from the exhaust gases.
Soda Ash Manufacture and Consumption
(4.2TgC02Eq.)
Commercial soda ash (sodium carbonate, Na2CO3)
is used in many consumer products, such as glass, soap
and detergents, paper, textiles, and food. During the manu-
facturing of soda ash, some natural sources of sodium
carbonate are heated and transformed into a crude soda
ash, in which CO2 is generated as a by-product. In addi-
tion, CO2 is often released when the soda ash is
consumed.
Carbon Dioxide Consumption (1.6 Tg C02 Eq.)
Carbon dioxide is used directly in many segments
of the economy, including food processing, beverage
manufacturing, chemical processing, and a host of indus-
trial and other miscellaneous applications. For the most
part, the CO2 used in these applications is eventually
released to the atmosphere.
Land-Use Change and Forestry
Land-Use Change and Forestry (Sink)
(990.4 TgC02Eq.)
When humans alter the terrestrial biosphere
through land use, changes in land-use, and forest man-
agement practices, they alter the natural carbon flux
between biomass, soils, and the atmosphere. Forest
management practices, the management of agricultural
soils, and landfilling of yard trimmings have resulted in
a net uptake (sequestration) of carbon in the United
States that is equivalent to about 15 percent of total
U.S. gross emissions. Forests (including vegetation,
soils, and harvested wood) accounted for approximately
91 percent of the total sequestration, agricultural soils
(including mineral and organic soils and the application
of lime) accounted for 8 percent, and landfilled yard trim-
Executive Summary ES-17
-------
mings accounted for less than 1 percent of the total
sequestration. The net forest sequestration is largely a
result of improved forest management practices, the re-
generation of previously cleared forest areas, and tim-
ber harvesting. In agricultural soils, mineral soils ac-
count for a net carbon sink that is more than three times
larger than the sum of emissions from organic soils and
liming. Net sequestration in agricultural mineral soils is
largely due to improved cropland and grazing land man-
agement practices, especially the adoption of conser-
vation tillage practices and leaving residues on the field
after harvest, and to taking erodable lands out of pro-
duction and planting them with grass or trees through
the Conservation Reserve Program. The landfilled yard
trimmings net sequestration is due to the long-term ac-
cumulation of yard trimming carbon in landfills.
Waste
Waste Combustion (26.0 Tg C02 Eq.)
Waste combustion involves the burning of garbage
and non-hazardous solids, referred to as municipal solid
waste (MSW), as well as the burning of hazardous waste.
Carbon dioxide emissions arise from the organic (i.e., car-
bon) materials found in these wastes. Within MSW, many
products contain carbon of biogenic origin, and the CO2
emissions from their combustion are reported under the
Land-Use Change and Forestry Chapter. However, sev-
eral components of MSW—plastics, synthetic rubber,
synthetic fibers, and carbon black—are of fossil fuel ori-
gin, and are included as sources of CO2 emissions.
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 has been estimated to be 21 times more
effective at trapping heat in the atmosphere than CO2
(i.e., the GWP value of methane is 21). Over the last two
centuries, methane's concentration in the atmosphere has
more than doubled (IPCC 1996). Experts believe these
atmospheric increases were due largely to increasing
emissions from anthropogenic sources, such as landfills,
natural gas and petroleum systems, agricultural activi-
ties, coal mining, stationary and mobile combustion,
wastewater treatment, and certain industrial processes
(see Figure ES-16 and Table ES-9).
Figure ES-16
Landfills
Enteric Fermentation |£
Natural Gas Systems gl
Coal Mining
Manure Management El
Petroleum Systems O
Wastewater Treatment I
Rice Cultivation 1
Stationary Sources I
Mobile Sources \
Petrochemical Production I
Agricultural Residue Burning |
Silicon Carbide Production <0.05
Portion of All
Emissions
0
50 100 150 200 250
Tg CO2 Eq.
Landfills
Landfills are the largest source of anthropogenic
methane emissions in the United States. In an environ-
ment where the oxygen content is low or nonexistent,
organic materials, such as yard waste, household waste,
food waste, and paper, can be decomposed by bacteria,
resulting in the generation of methane and biogenic CO2.
Methane emissions from landfills are affected by site-
specific factors such as waste composition, moisture, and
landfill size.
Methane emissions from U.S. landfills in 1999 were
214.6 Tg CO2 Eq., down 1 percent since 1990. The rela-
tively constant emission estimates are a result of two
offsetting trends: (1) the amount of municipal solid waste
in landfills contributing to methane emissions has in-
creased, thereby increasing the potential for emissions;
and (2) the amount of landfill gas collected and combusted
by landfill operators has also increased, thereby reduc-
ing emissions. Emissions from U.S. municipal solid waste
landfills accounted for 94 percent of total landfill emis-
sions, while industrial landfills accounted for the remain-
der. Approximately 28 percent of the methane generated
ES-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table ES-9: U.S. Sources of Methane Emissions (Tg C02 Eq.)
1990
1995
1996
1997
1998
1999
tUndfills :
r- Enteric Fermentation
1 Natural Gas Systems
jCoal Mining
1 Manure Management
| Petroleum Systems
fWastewater Treatment
|Rice Cultivation
f Stationary Combustion
r Mobile Combustion
;l Petrochemical Production
|Agricultural Residue Burning
^Silicon Carbide Production
1, International Bunker Fuels*
iTStal* . ..••"., .
217,3
129.5
121.2
87.9
26.4
27.2
11.2
8.7
8.5
5.0
1.2
0.5
+
.. . :'.... +.
644.5
• -
-«™ 222-9
_»_.. 136-3
«ra«®s«pfas«*? fe
124.2
74.6
31.0
~* * 24.5
11.8
9.5
8.9
4.9
1.5
0.5
"7 '+.-.
tttfset&l&6,i&-ir af • ' ' i -«
,__ . 650.5
219.1
132.2
125.8
69.3
30.7
24.0
11.9
8.8
9.0
4.8
1.6
0.6
+
+
638.0
217.8
129.6
122.7
68.8
32.6
24.0
12.0
9.6
8.1
4.7
1.6
0.6
+.
+
632.0
213.6
127.5
122.1
66.5
35.2
23.3
12.1
10.1
7.6
4.6
1.6
0.6
+
+
624.8
214.6
127.2
121.8
61.8
34.4
21.9
12.2
10.7
8.1
4.5
1.7
0.6
+
+.
619.6
1^+ Does not exceed 0.05 Tg C02 Eq.
x!* Emissions from International Bunker Fuels are not included in totals.
|Jote_:.. Totals may not sum due to independent rounding./ : .
in U.S. landfills in 1999 was recovered and combusted,
often for energy.
A regulation promulgated in March 1996 requires
the largest U.S. landfills to begin collecting and combus-
ting their landfill gas to reduce emissions of 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
distribution of natural gas, fugitive emissions of methane
often occur. Because natural gas is often found in con-
junction with petroleum deposits, leakage from petroleum
systems is also a source of emissions. Emissions vary
greatly from facility to facility and are largely a function
of operation and maintenance procedures and equipment
conditions. In 1999, methane emissions from U.S. natural
gas systems were estimated to be 121.8 Tg CO2 Eq., ac-
counting for approximately 20 percent of U.S. methane
emissions.
Petroleum is found in the same geological struc-
tures as natural gas, and the two are retrieved together.
Methane is also saturated in crude oil, and volatilizes as
the oil is exposed to the atmosphere at various points
along the system. Methane emissions from the compo-
nents of petroleum systems—including crude oil produc-
tion, crude oil refining, transportation, and distribution—
generally occur as a result of system leaks, disruptions,
and routine maintenance. In 1999, emissions from petro-
leum systems were estimated to be 21.9 Tg CO2 Eq., or
just under 4 percent of U.S. methane emissions.
From 1990 to 1999, combined methane emissions
from natural gas and petroleum systems decreased by 3
percent. Emissions from natural gas systems have re-
mained fairly constant, while emissions from petroleum
systems have declined gradually since 1990 primarily due
to production declines.
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
are 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, methane-
recovery systems may supplement these ventilation sys-
Executive Summary ES-19
-------
terns. Recovery of methane in the United States has in-
creased in recent years. During 1999, coal mining activities
emitted 61.8 Tg CO2 Eq. of methane, or 10 percent of U.S.
methane emissions. From 1990 to 1999, emissions from this
source decreased by 30 percent due to increased use of
the methane collected by mine degasification systems.
Agriculture
Agriculture accounted for 28 percent of U.S. meth-
ane emissions in 1999, with enteric fermentation in do-
mestic livestock, manure management, and rice cultiva-
tion accounting for the majority. Agricultural waste burn-
ing also contributed to methane emissions from agricul-
tural activities.
Enteric Fermentation (127.2Tg C02 Eq.)
During animal digestion, methane is produced
through the process of enteric fermentation, in which mi-
crobes residing in animal digestive systems break down
the feed consumed by the animal. Ruminants, which in-
clude cattle, buffalo, sheep, and goats, have the highest
methane emissions among all animal types because they
have a rumen, or large fore-stomach, in which methane-
producing fermentation occurs. Non-ruminant domestic
animals, such as pigs and horses, have much lower meth-
ane emissions. In 1999, enteric fermentation was the source
of about 21 percent of U.S. methane emissions, and more
than half of the methane emissions from agriculture. From
1990 to 1999, emissions from this source decreased by 2
percent Emissions from enteric fermentation have been
generally decreasing since 1995, primarily due to declining
dairy cow and beef cattle populations.
Manure Management (34.4 Tg C02 Eq.)
The decomposition of organic animal waste in an
anaerobic environment produces methane. The most im-
portant factor affecting the amount of methane produced
is how the manure is managed, because certain types of
storage and treatment systems promote an oxygen-free
environment. In particular, liquid systems tend to encour-
age anaerobic conditions and produce significant quan-
tities of methane, whereas solid waste management ap-
proaches produce little or no methane. Higher tempera-
tures and moist climatic conditions also promote meth-
ane production.
Emissions from manure management were about 6
percent of U.S. methane emissions in 1999, and 20 per-
cent of the methane emissions from agriculture. From 1990
to 1999, emissions from this source increased by 8.0 Tg
CO2 Eq.—the largest absolute increase of all the methane
source categories. The bulk of this increase was from
swine and dairy cow manure, and is attributed to the shift
in the composition of the swine and dairy industries to-
wards larger facilities. Larger swine and dairy farms tend
to use liquid management systems.
Rice Cultivation (10.7 Tg C02 Eq.)
Most of the world's rice, and all of the rice in the
United States, is grown on flooded fields. When fields
are flooded, anaerobic conditions develop and the or-
ganic matter in the soil decomposes, releasing methane
to the atmosphere, primarily through the rice plants. In
1999, rice cultivation was the source of 2 percent of U.S.
methane emissions, and about 6 percent of U.S. methane
emissions from agriculture. Emission estimates from this
source have increased about 23 percent since 1990, due
to an increase in the area harvested.
Agricultural Residue Burning (0.6 Tg C02 Eq.)
Burning crop residue releases a number of green-
house gases, including methane. Because field burning
is not common in the United States, it was responsible for
only 0.1 percent of U.S. methane emissions in 1999.
Other Sources
Methane is also produced from several other
sources in the United States, including waste water treat-
ment, fuel combustion, and some industrial processes.
Methane emissions from domestic wastewater treatment
totaled 12.2 Tg CO2 Eq. in 1999. Stationary and mobile
combustion were responsible for methane emissions of
8.1 and 4.5 Tg CO2 Eq., respectively. The majority of emis-
sions from stationary combustion resulted from the burn-
ing of wood in the residential end-use sector. The com-
bustion of gasoline in highway vehicles was responsible
for the majority of the methane emitted from mobile com-
bustion. Methane emissions from two industrial
ES-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
sources—petrochemical and silicon carbide production—
were also estimated, totaling 1.7 Tg CO2 Eq.
Nitrous Oxide Emissions
Nitrous oxide (N2O) is a greenhouse gas that is
produced both naturally—from a wide variety of biologi-
cal sources in soil and water—and anthropogenically by
a variety of agricultural, energy-related, industrial, and
waste management activities. While total N2O emissions
are much smaller than CO2 emissions, N2O is approxi-
mately 310 times more powerful than CO2 at trapping heat
in the atmosphere (IPCC 1996). During the past two cen-
turies, atmospheric concentrations of N2O have risen by
approximately 13 percent. The main anthropogenic ac-
tivities producing N2O in the United States were agricul-
Figure ES-17
Agricultural
Soil Management
Mobile Sources
Nitric Acid
Stationary Sources
Manure Management
Human Sewage
Adipic Acid
Agricultural
Residue Burning I 0.4
Waste Combustion I 0.2
Portion of All
Emissions
10 20 30 40 50 60 70
Tg CO2 Eq.
rural soil management, fuel combustion in motor vehicles,
and adipic and nitric acid production processes (see
Figure ES-17 and Table ES-10).
Agricultural Soil Management
Nitrous oxide (N2O) is produced naturally in soils
through microbial processes of nitrification and denitrifi-
cation. A number of anthropogenic activities add to the
amount of nitrogen available to be emitted as N2O by
these microbial processes. These activities may add ni-
trogen to soils either directly or indirectly. Direct addi-
tions occur through the application of synthetic and or-
ganic fertilizers; production of nitrogen-fixing crops; the
application of livestock manure, crop residues, and sew-
age sludge; cultivation of high-organic-content soils; and
direct excretion by animals onto soil. Indirect additions
result from volatilization and subsequent atmospheric
deposition, and from leaching and surface run-off, of some
of the nitrogen applied to soils as fertilizer, livestock ma-
nure, and sewage sludge.
In 1999, agricultural soil management accounted
for 298.3 Tg CO2 Eq., or 69 percent of U.S. N2O emissions.
From 1990 to 1999, emissions from this source increased
by 11 percent as fertilizer consumption, manure produc-
tion, and crop production rose.
Fuel Combustion
Nitrous oxide is a product of the reaction that oc-
curs between nitrogen and oxygen during fuel combus-
tion. Both mobile and stationary combustion emit N2O,
and the quantity emitted varies according to the type of
Table ES-10: U.S. Sources of Nitrous Oxide Emissions (Tg C02 Eq.)
Source
1990
1995
1996
1997
1998
1999
£ Agricultural Soil Management
Mobile Combustion
-Nitric. Acid ' , - . .
flvianure Management
-"Stationary Combustion
tAdipic Acid
r Human Sewage
.'" Agricultural Residue Burning
P Waste Combustion
£ International Bunker Fuels*
tTotal*
269.0
- 54.3
17.8
16.0
13.6
18.3
7.1
0.4
0.3
i.o...
396,9
.
.,
•SiSS'SSS'." ' '-
—
285.4
66.8
19.9
16.4
'. 14.3
20.3
8.2
0.4
0.3
0.9
431.9
294.6
65.3:
20.7
16.8
14.9
20.8
7.8
0.4
0.3
0.9
441.6
299.8
65.2
21.2
17.1
15.0
17.1
7.9
0.4
0.3
1.0
444.1
300.3
64.2
20.9
17.2
15.1
7.3
8.1
0.5
0.2
1.0
433.7
298.3
63.4
20.2
17.2
15.7
9.0
8.2
0.4
0.2
1.0
432.6
jr * Emissions from International Bunker Fuels are not included in totals.
t'Note: Totals may not sum due to independent rounding.
Executive Summary ES-21
-------
fuel, technology, and pollution control device used, as
well as maintenance and operating practices. For example,
catalytic converters installed to reduce motor vehicle pol-
lution can result in the formation of N2O.
In 1999, N2O emissions from mobile combustion
totaled 63.4 Tg CO2 Eq., or 15 percent of U.S. N2O emis-
sions. Emissions of N2O from stationary combustion were
15.7 Tg CO2 Eq., or 4 percent of U.S. N2O emissions.
From 1990 to 1999, combined N2O emissions from sta-
tionary and mobile combustion increased by 16 percent,
primarily due to increased rates of N2O generation in
motor vehicles.
Adipic Acid Production
The majority of the adipic acid produced in the
United States is used to manufacture nylon 6,6. Adipic
acid is also used to produce some low-temperature lubri-
cants and to add a "tangy" flavor to foods. Nitrous oxide
is emitted as a by-product of the chemical synthesis of
adipic acid.
In 1999, U.S. adipic acid plants emitted 9.0 Tg CO2
Eq. of N2O, or 2 percent of U.S. N2O emissions. Even
though adipic acid production has increased, by 1998, all
three major adipic acid plants in the United States had
voluntarily implemented N2O abatement technology. As a
result, emissions have decreased by 51 percent since 1990.
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 compo-
nent in the production of adipic acid and explosives.
Virtually all of the nitric acid manufactured in the
United States is produced by the oxidation of ammonia,
during which N2O is formed and emitted to the atmosphere.
In 1999, N2O emissions from nitric acid production were
20.2 Tg C02Eq., or 5 percent of U.S. N2O emissions. From
1990 to 1999, emissions from this source category increased
by 13 percent as nitric acid production grew.
Manure Management
Nitrous oxide is produced as part of microbial nitri-
fication and denitrification processes in managed and
unmanaged manure, the latter of which is addressed un-
der agricultural soil management. Total N2O emissions
from managed manure systems in 1999 were 17.2 Tg CO2
Eq., accounting for 4 percent of U.S. N2O emissions. From
1990 to 1999, emissions from this source category in-
creased by 7 percent, as poultry and swine populations
have increased.
Other Sources
Other sources of N2O included agricultural residue
burning, waste combustion, and human sewage in waste-
water treatment systems. In 1999, agricultural residue burn-
ing and municipal solid waste combustion each emitted
less than 1 Tg C02 Eq. of N2O. The human sewage com-
ponent of domestic wastewater resulted in emissions of
8.2TgCO2Eq.inl999.
HFC, PFC, and SF6 Emissions
Hydrofluorocarbons (HFCs) and perfluorocarbons
(PFCs) are categories of synthetic chemicals that are be-
ing used as alternatives to the ozone depleting substances
(ODSs), which are being phased out under the Montreal
Protocol and Clean Air Act Amendments of 1990. Be-
cause HFCs and PFCs do not directly deplete the strato-
spheric ozone layer, they are not controlled by the
Montreal Protocol,
These compounds, however, along with sulfur
hexafluoride (SF6), are potent greenhouse gases. In addi-
tion to having high global warming potentials, SF6 and
PFCs have extremely long atmospheric lifetimes, result-
ing in their essentially irreversible accumulation in the
atmosphere. Sulfur hexafluoride is the most potent green-
house gas the IPCC has evaluated.
Other emissive sources of these gases include alu-
minum production, HCFC-22 production, semiconductor
manufacturing, electrical transmission and distribution sys-
tems, and magnesium production and processing. Figure
ES-18 and Table ES-11 present emission estimates for HFCs,
PFCs, and SF6, which totaled 135.7 Tg CO2Eq. in 1999.
ES-22 inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table ES-11: Emissions of HFCs, PFCs, and SF6 (Tg C02 Eq.)
Source
1990
1995
1996
1997
1998 1999
Substitution of Ozone Depleting Substance;
HCFC-22 Production
Electrical Transmission and Distribution
Aluminum Production
Semiconductor Manufacture
Magnesium Production and Processing
Total
Note: Totals may not sum due to independent
s 0.9
34.8
20.5
19.3
2.9
5.5
83.9 ;
rounding.
24.0
27.1
25.7
11.2
5.5
5.5
99.0
34.0
31.2
25.7
11.6
7.0
5.6
115.1
42.1
30.1
25.7
10.8
7.0
7.5
123.3
49.6
40.0
25.7
10.1
6.8
6.3
138.6
56.7
30.4
25.7
10.0
6.8
6.1
135.7
Figure ES-18
•
Substitution of Ozone
Depleting Substances
HCFC-22 Production
Electrical Transmission If" 1
and Distribution IT" ' " I
Aluminum Production
Semiconductor
Manufacture |
Magnesium Production I
and Processing |
Portion of All
Emissions
0
10 20 30 40 50 60
Tg CO2 Eq.
Substitution of Ozone Depleting
Substances
The use and subsequent emissions of HFCs and
PFCs as substitutes for ozone depleting substances
(ODS) increased from small amounts in 1990 to 56.7 Tg
CO2 Eq. in 1999. This increase was the result of efforts to
phase-out CFCs and other ODSs in the United States,
especially the introduction of HFC-134a as a CFC substi-
tute hi refrigeration applications. In the short term, this
trend is expected to continue, and will likely accelerate in
the next decade as HCFCs, which are interim substitutes
in many applications, are themselves phased-out under
the provisions of the Copenhagen Amendments to the
Montreal Protocol. Improvements in the technologies
associated with the use of these gases, however, may
help to offset this anticipated increase in emissions.
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, which totaled 10.0
Tg CO2 Eq. were estimated to have decreased by 48 per-
cent between 1990 and 1999 due to voluntary emission
reduction efforts by the industry and falling domestic
aluminum production.
HFC-23 is a by-product emitted during the produc-
tion of HCFC-22. Emissions from this source were 30.4 Tg
CO2 Eq. in 1999, and have decreased by 13 percent since
1990. The intensity of HFC-23 emissions (i.e., the amount
of HFC-23 emitted per kilogram of HCFC-22 manufactured)
has declined significantly since 1990, although produc-
tion has been increasing.
The semiconductor industry uses combinations of
HFCs, PFCs, SF6 and other gases for plasma etching and
to clean chemical vapor deposition tools. For 1999, it was
estimated that the U.S. semiconductor industry emitted a
total of 6.8 Tg CO2 Eq. Emissions from this source cat-
egory have increased with the growth in the semicon-
ductor industry and the rising intricacy of chip designs.
The primary use of SF6 is as a dielectric in electrical
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 since 1990, to 25.7 Tg CO2 Eq. in 1999.
Executive Summary ES-23
-------
Box ES-6: 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 refrigeration,
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). However, they are also potent greenhouse gases.
Recognizing the harmful effects of these compounds on the ozone layer, in 1987 many governments signed the Montreal
Protocol on Substances that Deplete the Ozone Layer to limit the production and importation of a number of CFCs and other
halogenated compounds. The United States furthered its commitment to phase-out ODSs by signing and ratifying the Copenhagen
Amendments to the Montreal Protocol in 1992. Under these amendments, the United States committed to ending the production and
importation of halons by 1994, and CFCs by 1996.
The IPCC Guidelines and the UNFCCC do not include reporting instructions for estimating emissions of ODSs because their use
is being phased-out under the Montreal Protocol. The United States believes, 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-12. Com-
pounds are grouped by class according to their ozone depleting potential. Class I compounds are the primary ODSs; Class II
compounds include partially halogenated chlorine compounds (i.e., HCFCs), some of which were developed as interim replacements
for CFCs. Because these HCFC compounds are only partially halogenated, their hydrogen-carbon bonds are more vulnerable to
oxidation in the troposphere and, therefore, pose only one-tenth to one-hundredth the threat to stratospheric ozone compared to
CFCs.
It should be noted that the effects of these compounds on radiative forcing are not provided. Although many ODSs have relatively
high direct GWPs, their indirect effects from 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 uncertainties
surrounding the net effect of these gases, emissions are reported on an unweighted basis.
Table ES-12: Emissions of Ozone Depleting Substances (Gg)
Compound
1990
1995
1996
1997
1998
1999
Class I
CFC-11
CFC-12
CFC-11 3
CFC-11 4
CFC-11 5
Carbon Tetrachloride
Methyl Chloroform
Halon-1211
Halon-1301
Class 11
HCFC-22
HCFC-123
HCFC-124
HCFC-141b
HCFC-142b
HCFC-225ca/cb
Source: EPA
+ Does not exceed 0.05 Gg
52.4
226.9
39.0
0.7
2.2
25.1
27.9
+
1.0
33.9
+ "
+
+ .. _ . .
+
+
19.1
71.1
7.6
0.8
1.6
5.5
8.7
0.7
1.8
46.2
0.6
5.6
20.6
7.3
+
11.7
72.2
+
0.8
1.6
+
1.6
0.8
1.9
48.8
0.7
5.9
25.4
8.3
+
10.7
63.6
+
0.8
1.4
+
+
0.8
1.9
50.6
0.8
6.2
25.1
8.7
+
9.8
54.9
+
0.6
1.1
+
+
0.8
1.9
52.3
0.9
6.4
26.7
9.0
+
9.2
64.4
+ •
+
1.1
+
+
0.8
1.9
83.0
1.0
6.5
28.7
9.5
: ' +'"'
ES-24 inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Lastly, SF6 is also used as a protective covergas
for the casting of molten magnesium. Estimated emissions
from primary magnesium production and magnesium cast-
ing were 6.1 Tg CO2 Eq. in 1999, an increase of 11 percent
since 1990.
Criteria Pollutant Emissions
In the United States, carbon monoxide (CO), nitro-
gen 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. Criteria pollutants do not have a direct
global warming effect, but indirectly affect terrestrial ra-
diation absorption by influencing the formation and de-
struction of tropospheric and stratospheric ozone, or, in
the case of SO2, by affecting the absorptive characteris-
tics of the atmosphere. Carbon monoxide is produced
when carbon-containing fuels are combusted incom-
pletely. Nitrogen oxides (i.e., NO and NO2) are created by
lightning, fires, fossil fuel combustion, and in the strato-
sphere from nitrous oxide (N2O). NMVOCs—which in-
clude such compounds as propane, butane, and ethane—
are emitted primarily from transportation, industrial pro-
cesses, and non-industrial consumption of organic sol-
vents. In the United States, SO2 is primarily emitted from
the combustion of coal by the electric power industry
and by the metals industry.
Box ES-7: Sources and Effects of Sulfur Dioxide
In part because of their contribution to the forma-
tion of urban smog—and acid rain in the case of SO2 and
NOX—criteria pollutants are regulated under the Clean
Air Act. These gases also indirectly affect the global cli-
mate by reacting with other chemical compounds in the
atmosphere to form compounds that are greenhouse
gases. Unlike other criteria pollutants, SO2 emitted into
the atmosphere is believed to affect the Earth's radiative
budget negatively; therefore, it is discussed separately.
One of the most important indirect climate change
effects of criteria pollutants is their role as precursors for
tropospheric ozone formation. They can also alter the
atmospheric lifetimes of other greenhouse gases. For ex-
ample, CO interacts with the hydroxyl radical—the major
atmospheric sink for methane emissions—to form CO2.
Therefore, increased atmospheric concentrations of CO
limit the number of hydroxyl molecules (OH) available to
destroy methane.
Since 1970, the United States has published esti-
mates of annual emissions of criteria pollutants (EPA
2000).14 Table ES-13 shows that fuel combustion accounts
for the majority of emissions of these gases. Industrial
processes—such as the manufacture of chemical and al-
lied products, metals processing, and industrial uses of
solvents—are also significant sources of CO, NOX and
NMVOCs.
Sulfur dioxide (S02) emitted into the atmosphere through natural and anthropogenic processes affects the Earth's radiative budget
;.-through its photochemical transformation into sulfate aerosols that can (1) scatter sunlight back to space, thereby reducing the
!: ladiation 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
r; forcing is believed to be negative (IPCC1996). 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 S02is 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 67 percent in 1999. Coal combustion
,: contributes nearly all of those emissions (approximately 93 percent). Sulfur dioxide emissions have decreased in recent years, primarily
; as a result of electric utilities switching from high sulfur to low sulfur coal.
14 NOX and CO emission estimates from agricultural residue burning were estimated separately, and therefore not taken from
EPA (2000).
Executive Summary ES-25
-------
Table ES-13: Emissions of NOX, CO, NMVOCs, and S02 (Gg)
Gas/Activity
NOX
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Industrial Processes
Solvent Use
Agricultural Burning
Waste
CO
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Industrial Processes
Solvent Use
Agricultural Burning
Waste
NMVOCs
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Industrial Processes
Solvent Use
Agricultural Burning
Waste
S02
Stationary Fossil Fuel Combustion
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Industrial Processes
Solvent Use
Agricultural Burning
Waste
1990
21,955
9,884
10,900
139
921
1
28
83
85,846
4,999
69,523
302
9,502
4
537
979
18,843
912
8,154
555
3,110
5,217 •=
NA
895
21,481
18,407
1,339
390
1,306
0
NA
38
1995
22,755
9,822
11,870
100
842
3
28
89
80,678
5,383
68,072
316
5,291
5
536
1,075
18,663
973
7,725
582
2,805
5,609
NA
969
17,408
14,724
1,189
334
1,117
1
NA
43
1996
23,663
9,541
12,893
126
977
3
32
92
87,196
5,620
72,390
321
7,227
1
625
1,012
17,353
971
8,251
433
2,354
4,963
IMA
381
17,109
14,727
1,081
304
958
1
NA
37
1997
23,934
9,589
13,095
130
992
3
33
92
87,012
4,968
71,225
333
8,831
1
630
1,024
17,586
848
8,023
442
2,793
5,098
NA
382
17,565
15,106
1,116
312
993
1
NA
37
1998
23,613
9,408
13,021
130
924
3
34
93
82,496
4,575
70,288
332
5,612
1
653
1,035
16,554
778
7,928
440
2,352
4,668
NA
387
17,682
15,192
1,145
310
996
1
NA
38
1999
23,042
9,070
12,794
130
930
3
33
83
82,982
4,798
68,179
332
5,604
1
629
3,439
16,128
820
7,736
385
2,281
4,376
NA
531
17,115
14,598
1,178
309
996
1
NA
33
Source: (EPA 2000) except for estimates from agricultural residue burning.
+ Does not exceed 0.5 Gg
NA (Not Available)
Note: Totals may not sum due to independent rounding.
ES-26 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
1. Introduction
TTnis report presents estimates by the United States government of U.S. anthropogenic greenhouse gas emis-
• sions and sinks for the years 1990 through 1999. A summary of these estimates is provided in Table 1-4 and
Table 1-5 by gas and source category. The emission estimates in these tables are presented on both a full molecular
mass basis and on a Global Warming Potential (GWP) weighted basis in order to show the relative contribution of each
gas to global average radiative forcing.1'2 This report also discusses the methods and data used to calculate these
emission estimates.
In June of 1992, the United States signed, and later ratified in October, the United Nations Framework Convention
on Climate Change (UNFCCC). The objective of the UNFCCC is "to achieve.. .stabilization of greenhouse gas concen-
trations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate sys-
tem."3-4
Parties to the Convention, by signing, make commitments "to develop, periodically update, publish and make
available...national inventories of anthropogenic emissions by sources and removals by sinks of all greenhouse gases
not controlled by the Montreal Protocol, using comparable methodologies.. ."5 The United States views this report as
an opportunity to fulfill this commitment under UNFCCC.
In 1988, preceding the creation of the UNFCCC, the Intergovernmental Panel on Climate Change (IPCC) was jointly
established by the World Meteorological Organization (WMO) and the United Nations Environment Programme (UNEP).
The charter of the IPCC is to assess available scientific information on climate change, assess the environmental and socio-
economic impacts of climate change, and formulate response strategies (IPCC 1996). Under Working Group 1 of the IPCC,
nearly 140 scientists and national experts from more than thirty countries collaborated in the creation of the Revised 1996
IPCC Guidelines for National Greenhouse Gas Inventories (TPCC/UNEP/OECD/IEA 1997) to ensure that the emission
inventories submitted to the UNFCCC are consistent and comparable between nations. The Revised 1996 IPCC Guide-
lines were accepted by the IPCC at its Twelfth Session (Mexico City, 11-13 September 1996). The information provided in
1 See the section below entitled Global Warming Potentials for an explanation of GWP values.
2 See the section below entitled What is Climate Change? for an explanation of radiative forcing.
3 The term "anthropogenic", in this context, refers to greenhouse gas emissions and removals that are a direct result of human activities
or are the result of natural processes that have been affected by human activities (IPCC/UNEP/OECD/IEA 1997).
4 Article 2 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change. See
. (UNEP/WMO 2000)
5 Article 4 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change (also
identified in Article 12). See . (UNEP/WMO 2000)
Introduction 1-1
-------
this inventory is presented in accordance with these guide-
lines. Additionally, in order to fully comply with the Revised
1996IPCC Guidelines, the United States has provided
estimates of carbon dioxide emissions from fossil fuel com-
bustion using the IPCC Reference Approach in Annex R.
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
provide a common and consistent mechanism through
which Parties to the UNFCCC can estimate emissions and
compare the relative contribution of individual sources,
gases, and nations to climate change; and (3) as a prereq-
uisite for accounting for reductions and evaluating pos-
sible mitigation strategies.
What is Climate Change?
Climate change refers to long-term fluctuations in
temperature, precipitation, wind, and other elements of
the Earth's climate system.6 Natural processes such as
solar-irradiance variations, variations in the Earth's or-
bital parameters,7 and volcanic activity can produce varia-
tions in climate. The climate system can also be influ-
enced by changes in the concentration of various gases
in the atmosphere, which affect the Earth's absorption of
radiation.
The Earth naturally absorbs and reflects incoming
solar radiation and emits longer wavelength terrestrial
(thermal) radiation back into space. On average, the 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).
Under the UNFCCC, the definition of climate change
is "a change of climate which is attributed dkectly or
indirectly to human activity that alters the composition
of the global atmosphere and which is in addition to natu-
ral climate variability observed over comparable time pe-
riods."8 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 pro-
duce a radiative forcing by changing either
the reflection or absorption of solar radiation,
or the emission and absorption of terrestrial
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
global climate is currently limited because the
expected signal 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 forc-
ing by, and response to, changes in concentra-
tions of greenhouse gases and aerosols, and
land surface changes. Nevertheless, the balance
of the evidence suggests that there is a
discernable human influence on global climate
(IPCC 1996).
Greenhouse Gases
Although the Earth's atmosphere consists mainly of
oxygen and nitrogen, neither plays a significant role in
enhancing the greenhouse effect because both are essen-
tially transparent to terrestrial radiation. The greenhouse
6 The Earth's climate system comprises the atmosphere, oceans, biosphere, cryosphere, and geosphere.
7 For example, eccentricity, precession, and inclination.
8 Article 1 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate Change.
(UNEP/WMO 2000)
1 -2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
effect is primarily a function of the concentration of water
vapor, carbon dioxide, and other trace gases in the atmo-
sphere that absorb the terrestrial radiation leaving the sur-
face of the Earth (IPCC1996). Changes in the atmospheric
concentrations of these greenhouse gases can alter the
balance of energy transfers between the atmosphere, space,
land, and the oceans. A gauge of these changes is called
radiative forcing, which is a simple measure of changes in
the energy available to the Earth-atmosphere system (IPCC
1996). Holding everything else constant, increases in green-
house gas concentrations in the atmosphere will produce
positive radiative forcing (i.e., a net increase in the absorp-
tion of energy by the Earth).
Climate change can be driven by changes in
the atmospheric concentrations of a number of
radiatively active gases and aerosols. We have
clear evidence that human activities have af-
fected concentrations, distributions 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-
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. Chlorofluorocar-
bons (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 ef-
fect, do influence the formation and destruction of ozone,
which does have such a terrestrial radiation absorbing
effect. These gases—referred to here as ozone precur-
sors—include carbon monoxide (CO), oxides of nitrogen
(NOX), and nonmethane volatile organic compounds
(NMVOCs).9 Aerosols—extremely small particles or liq-
uid droplets often produced by emissions of sulfur diox-
ide (SO2) and other pollutants—can also affect the ab-
sorptive characteristics of the atmosphere.
Carbon dioxide, methane, and nitrous oxide are con-
tinuously emitted to and removed from the atmosphere
by natural processes on Earth. Anthropogenic activities,
however, can cause additional quantities of these and
other greenhouse gases to be emitted or sequestered,
thereby changing their global average atmospheric con-
centrations. Natural activities such as respiration by
plants or animals and seasonal cycles of plant growth
and decay are examples of processes that only cycle car-
bon or nitrogen between the atmosphere and organic bio-
mass. Such processes—except when directly or indirectly
perturbed out of equilibrium by anthropogenic activi-
ties—generally do not alter average atmospheric green-
house gas concentrations over decadal timeframes. Cli-
matic changes resulting from anthropogenic activities,
however, could have positive or negative feedback ef-
fects 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 (H2O). Overall, the most abundant
and dominant greenhouse gas in the atmosphere is water
vapor. Water vapor is neither long-lived nor well mixed in
the atmosphere, varying spatially from 0 to 2 percent
(IPCC 1996). In addition, atmospheric water can exist in
several physical states including gaseous, liquid, and
solid. Human activities are not believed to directly affect
the average global concentration of water vapor; how-
ever, the radiative forcing produced by the increased con-
centrations of other greenhouse gases may indkectly af-
fect the hydrologic cycle. A warmer atmosphere has an
increased water holding capacity; yet, increased concen-
trations of water vapor affects the formation of clouds,
which can both absorb and reflect solar and terrestrial
radiation. Aircraft contrails, which consist of water vapor
and other aircraft emittants, are similar to clouds in then-
radiative forcing effects (IPCC 1999).
9 Also referred to in the U.S. Clean Air Act as "criteria pollutants."
Introduction 1-3
-------
Carbon Dioxide (CO2). In nature, carbon is cycled
between various atmospheric, oceanic, land biotic, ma-
rine biotic, and mineral reservoirs. The largest fluxes oc-
cur between the atmosphere and terrestrial biota, and
between the atmosphere and surface water of the oceans.
In the atmosphere, carbon predominantly exists in its oxi-
dized form as CO2. Atmospheric carbon dioxide is part of
this global carbon cycle, and therefore its fate is a com-
plex function of geochemical and biological processes.
Carbon dioxide concentrations in the atmosphere, as of
1994, increased from approximately 280 parts per million
by volume (ppmv) in pre-industrial10 times to 358 ppmv, a
28 percent increase (IPCC 1996).11 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 pro-
duction) also emit notable quantities of carbon dioxide.
In its scientific assessment, the IPCC also stated
that "[t]he increased amount of carbon dioxide [in the
atmosphere] is leading to climate change and will pro-
duce, on average, a global warming of the Earth's surface
because of its enhanced greenhouse effect—although
the magnitude and significance of the effects are not fully
resolved" (IPCC 1996).
Methane (CH4). Methane is primarily produced
through anaerobic decomposition of organic matter in
biological systems. Agricultural processes such as wet-
land rice cultivation, enteric fermentation in animals, and
the decomposition of animal wastes emit CH4, as does
the decomposition of municipal solid wastes. Methane is
also emitted during the production and distribution of
natural gas and petroleum, and is released as a by-prod-
uct of coal mining and incomplete fossil fuel combustion.
The average global concentration of methane in the at-
mosphere 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 measurements
indicate that roughly 20 percent of methane emissions
are from fossil fuel consumption, and an equal percent-
age 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 react-
ing with the hydroxyl radical (OH) and is ultimately con-
verted to CO2. Increasing emissions of methane, though,
reduces the concentration of OH, and thereby the rate of
further methane removal (IPCC 1996).
Nitrous Oxide (N2O). Anthropogenic sources of
N2O emissions include agricultural soils, especially the
use of synthetic and manure fertilizers; fossil fuel com-
bustion, especially from mobile combustion; adipic (ny-
lon) 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 anthropo-
genic activities (IPCC 1996). Nitrous oxide is removed
from the atmosphere primarily by the photolytic action of
sunlight in the stratosphere.
Ozone (O3). Ozone is present in both the upper
stratosphere,12 where it shields the Earth from harmful
levels of ultraviolet radiation, and at lower concentra-
tions hi the troposphere,13 where it is the main compo-
10 The prc-industrial period is considered as the time preceding the year 1750 (IPCC 1996).
11 Carbon dioxide concentrations during the last 1,000 years of the pre-industrial period (i.e., 750-1750), a time of relative climate
stability, fluctuated by about ±10 ppmv around 280 ppmv (IPCC 1996).
12 The stratosphere is the layer from the troposphere up to roughly 50 kilometers. In the lower regions the temperature is nearly
constant but in the upper layer the temperature increases rapidly because of sunlight absorption by the ozone layer. The ozone layer is
the part of the stratosphere from 19 kilometers up to 48 kilometers where the concentration of ozone reaches up to 10 parts per
million.
13 The troposphere is the layer from the ground up to 11 kilometers near the poles and up to 16 kilometers in equatorial regions (i.e.,
the lowest layer of the atmosphere where people live). It contains roughly 80 percent of the mass of all gases in the atmosphere and
is the site for most weather processes, including most of the water vapor and clouds.
1-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
nent of anthropogenic photochemical "smog." During
the last two decades, emissions of anthropogenic chlo-
rine and bromine-containing halocarbons, such as chlo-
rofluorocarbons (CFCs), have depleted stratospheric
ozone concentrations. This loss of ozone in the strato-
sphere has resulted in negative radiative forcing, repre-
senting an indirect 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 is included in the category referred to as "cri-
teria pollutants" in the United States under the Clean Air
Act14 and its subsequent amendments. The tropospheric
concentrations of both ozone and these precursor gases
are short-lived and, therefore, spatially variable.
Halocarbons, Perfluorocarbons, and Sulfur
Hexafluoride (SF6). Halocarbons are, for the most part,
man-made chemicals that have both direct and indirect
radiative forcing effects. Halocarbons that contain chlo-
rine—chlorofluorocarbons (CFCs), hydrochlorofluoro-
carbons (HCFCs), methyl chloroform, and carbon tetra-
chloride—and bromine—halons, methyl bromide, and
hydrobromofluorocarbons (HBFCs)—result in strato-
spheric ozone depletion and are therefore controlled un-
der the Montreal Protocol on Substances that Deplete
the Ozone Layer. Although CFCs and HCFCs include
potent global wanning gases, their net radiative forcing
effect on the atmosphere is reduced because they cause
stratospheric ozone depletion, which is itself, an impor-
tant greenhouse gas in addition to shielding the Earth
from harmful levels of ultraviolet radiation. Under the
Montreal Protocol, the United States phased out the
production and importation of halons by 1994 and of CFCs
by 1996. Under the Copenhagen Amendments to the Pro-
tocol, a cap was placed on the production and importa-
tion of HCFCs by non-Article 515 countries beginning in
1996, and then followed by a complete phase-out by the
year 2030. The ozone depleting gases covered under the
Montreal Protocol and its Amendments are not covered
by the UNFCCC; however, they are reported in this in-
ventory under Annex O.
Hydrofluorocarbons (HFCs), perfluorocarbons
(PFCs), 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 replacements
for ozone depleting substances but also emitted as a by-
product of the HCFC-22 manufacturing process—cur-
rently have a small aggregate radiative forcing impact;
however, it is anticipated that their contribution to over-
all radiative forcing will increase (IPCC 1996). PFCs and
SF6 are predominantly emitted from various industrial pro-
cesses including aluminum smelting, semiconductor
manufacturing, electric power transmission and distribu-
tion, and magnesium casting. Currently, the radiative forc-
ing impact of PFCs and SF6 is also small; however, be-
cause they have extremely long atmospheric lifetimes,
their concentrations tend to irreversibly accumulate in
the atmosphere.
Carbon Monoxide (CO). Carbon monoxide has an
indirect radiative forcing effect by elevating concentra-
tions of CH4 and tropospheric ozone through chemical
reactions with other atmospheric constituents (e.g., the
hydroxyl radical, OH) that would otherwise assist in de-
stroying CH4 and tropospheric ozone. Carbon monoxide
is created when carbon-containing fuels are burned in-
completely. Through natural processes in the atmosphere,
it is eventually oxidized to CO2. Carbon monoxide con-
centrations are both short-lived in the atmosphere and
spatially variable.
14 [42 U.S.C § 7408, CAA § 108]
13 Article 5 of the Montreal Protocol covers several groups of countries, especially developing countries, with low consumption rates of
ozone depleting substances. Developing countries with per capita consumption of less than 0.3 kg of certain ozone depleting substances
(weighted by their ozone depleting potential) receive financial assistance and a grace period of ten additional years in the phase-out of
ozone depleting substances.
Introduction 1-5
-------
Nitrogen Oxides (NOK). The primary climate change
effects of nitrogen oxides (i.e., NO and NO2) are indkect
and result from their role in promoting the formation of
ozone in the troposphere and, to a lesser degree, lower
stratosphere, where it has positive radiative forcing ef-
fects.16 Additionally, NOX emissions from aircraft are also
likely to decrease methane concentrations, thus having a
negative radiative forcing effect (IPCC 1999). Nitrogen
oxides are created from lightning, soil microbial activity,
biomass burning—both natural and anthropogenic fires—
fuel combustion, and, in the stratosphere, from the photo-
degradation of 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 transporta-
tion and industrial processes, as well as biomass burning
and non-industrial consumption of organic solvents.
Concentrations of NMVOCs tend to be both short-lived
in the atmosphere and spatially variable.
Aerosols. Aerosols are extremely small particles or
liquid droplets found in the atmosphere. They can be
produced by natural events such as dust storms and 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 (SO^17 emissions from
fossil fuel and biomass burning. The net effect of aero-
sols is 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 emissions.18 Locally, the negative radiative forcing ef-
fects of aerosols can offset the positive forcing of green-
house 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). Emission estimates for sulfur
dioxide are provided in Annex P of this report.
Additionally, current research indicates that another
constituent of aerosols, elemental carbon, may have a posi-
tive radiative forcing, second to only carbon dioxide, through-
out the entire atmosphere (Jacobson 2001). Thus, it is pos-
sible that the net radiative forcing from aerosols may be
slightly positive, but is in any event very uncertain. The
large emission sources of elemental carbon include diesel
exhaust, coal combustion, and biomass burning.
Global Warming Potentials
A Global Warming Potential (GWP) is intended as a
quantified measure of the globally averaged relative ra-
diative forcing impacts of a particular greenhouse gas
(see Table 1-1). It is defined as the cumulative radiative
forcing—both direct and indirect effects—over a speci-
fied 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 itself is a greenhouse
gas. Indirect radiative forcing occurs when chemical trans-
formations involving the original gas produce a gas or
gases that are greenhouse gases, or when a gas influ-
ences the atmospheric lifetimes of other gases. The refer-
ence gas used is CO2, and therefore GWP weighted emis-
sions are measured in teragrams of CO2 equivalents (Tg
CO2Eq.)19 The relationship between gigagrams (Gg) of a
gas and Tg CO2Eq. can be expressed as follows:
16 NOS emissions injected higher in the stratosphere, primarily from fuel combustion emissions from high altitude supersonic aircraft,
can lead to stratospheric ozone depletion.
17 Sulfur dioxide is a primary anthropogenic contributor to the formation of "acid rain" and other forms of atmospheric acid deposition.
18 Volcanic activity can inject significant quantities of aerosol producing sulfur dioxide and other sulfur compounds into the strato-
sphere, which can result in a longer negative forcing effect (i.e., a few years) (IPCC 1996).
19 Carbon comprises 12/44"* of carbon dioxide by weight.
1 -6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 1-1: Global Warming Potentials
and Atmospheric Lifetimes (Years)
Tg C02 Eq = (Gg of gas)x (GWP)x
jGas Atmospheric Lifetime GWPa
1 Carbon dioxide (C02)
^Methane (CH4)b '.
f Nitrous oxide (N20)
SflFC-23 .
pFC-125
|HFC-T34a :
EHFC-1433
iHFC-152a
lHFC-227ea
I HFC-236fa
fHFC-4310mee
?CF4 . /:
Scfs
*$fw
* VH
! SF6
f^A .-- -—
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
'" ^ •--. V' f". "'•••'
; 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
f Source: (IPCC 1996) :
j_a 100 year time horizon .... .: : :
iJTb-The methane GWP includes the direct effects and those
f Indirect effects due to the production of tropospheric ozone and
-stratospheric water vapor. The indirect effect due to the.
jj production of C02.is not included, . -;"
'J "' " '' ' ' '"'
Box 1-1: Emission Reporting Nomenclature
l.OOOGg
^ ^
where,
Tg CO2 Eq. = Teragrams of Carbon Dioxide
Equivalents
Gg = Gigagrams (equivalent to a thousand
metric tons)
GWP = Global Wanning Potential
Tg = Teragrams
GWP values allow policy makers to compare the
impacts of emissions and reductions of different gases.
According to the IPCC, GWPs typically have an uncer-
tainty of ±35 percent. The parties to the UNFCCC have
also agreed to use GWPs based upon a 100 year time
horizon although other time horizon values are available.
In addition to communicating emissions in units
of mass, Parties may choose also to use global
warming potentials (GWPs) to reflect their in-
ventories and projections in carbon dioxide-
equivalent terms, using information provided
by the Intergovernmental Panel on Climate
Change (IPCC) in its Second Assessment Re-
port. Any use of GWPs should be based on the
effects of the greenhouse gases over a 100-year
|:;: The Global Warming Potential (GWP) weighted emissions of all direct greenhouse gases presented throughout this report are
| presented in terms of equivalent emissions of carbon dioxide (C02), using units of teragrams of carbon dioxide equivalents (Tg C02
J Eq.) In previous year's inventories emissions were reported in terms of carbon—versus carbon dioxide—equivalent emissions, using
£ units of million metric tons of carbon equivalents (MMTCE). This change of units for reporting was implemented so that the U.S.
^Inventory would be more consistent with international practices, which are to report emissions in carbon dioxide equivalent units.
jj. In order to convert the emission estimates presented in this report to those provided previously, the following equation can be
ffemployed: . : ' . . '
J:- TgC02Eq. = MMTCEx(%) . ,\ ' "; ,' " ; :'" '' '"' -: ' • '
I? J There are two elements to the conversion. The first element is simply nomenclature, since one ;teragram is equal to one million
Ifnetrictons: /.,--.','". -"'.'. '..-'." ":"'
^-;'.~Tg = 109 kg = 106 metric tons = 1megaton = 1 million metric tons
| The second element is the conversion, by weight, from carbon to carbon dioxide. The molecular weight of carbon is 12, and the
implecular weight of oxygen is 16; therefore, the molecular weight of C02 is 44 (i.e., 12+[16x2]), as compared to 12 for carbon alone.
ii-Thus, carbon comprises 12/44ths of carbon dioxide by weight.
Introduction 1-7
-------
time horizon. In addition, Parties may also use
other time horizons.20
Greenhouse gases with relatively long atmospheric
lifetimes (e.g., CO2, CH4, N2O, HFCs, PFCs, and SF6) tend
to be evenly distributed throughout the atmosphere, and
consequently global average concentrations can be de-
termined. The short-lived gases such as water vapor, tro-
pospheric ozone, ozone precursors (e.g., NOX, CO, and
NMVOCs), and tropospheric aerosols (e.g., SO2 prod-
ucts), however, vary regionally, and consequently it is
difficult to quantify their global radiative forcing impacts.
No GWP values are attributed to these gases that are
short-lived and spatially inhomogeneous in the atmo-
sphere. 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 nitrogen
trifluoride(NF3).
Recent Trends in
U.S. Greenhouse Gas Emissions
Total U.S. greenhouse gas emissions rose in 1999
to 6,746.1 teragrams of carbon dioxide equivalents (Tg
CO2Eq.)21 (11.7 percent above 1990 baseline levels). The
single year increase in emissions from 1998 to 1999 was
0.9 percent (59.2 Tg CO2Eq.), less than the 1.2 percent
average annual rate of increase for the 1990s. The lower
than average increase In emissions, especially given the
robust economic growth in 1999, was primarily attribut-
able to the following factors: 1) warmer than normal sum-
mer and winter conditions; 2) significantly increased out-
put from existing nuclear power plants; and 3) reduced
CH4 emissions from coal mines and HFC-23 by-product
emissions from the chemical manufacture of HCFC-22.
Figure 1-1 through Figure 1-3 illustrate the overall trends
in total U.S. emissions by gas, annual changes, and ab-
solute changes since 1990.
Figure 1-1
8000 i
7000
6000 •
ft 5000
O 4000
O
01 3000
2000
1000
0
I HFCs, PFCs, & SF6
I Nitrous Oxide
Methane
Carbon Dioxide
6,038 5,987
6,108 6,211 £345 6,401
6,598 6,678 6,687 6,746
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
Figure 1-2
-1%
1991 1992 1993 1994 1995 1996 1997 1998 1999
As the largest source of U.S. greenhouse gas emis-
sions, CO2 from fossil fuel combustion accounted for a
nearly constant 80 percent of global warming potential
(GWP) weighted emissions in the 1990s.22 Emissions from
this source category grew by 13 percent (617.4 Tg CO2
20 Framework Convention on Climate Change; FCCC/CP/1996/15/Add.l; 29 October 1996; Report of the Conference of the Parties at
its second session; held at Geneva from 8 to 19 July 1996; Addendum; Part Two: Action taken by the Conference of the Parties at its
second session; Decision 9/CP.2; Communications from Parties included in Annex I to the Convention: guidelines, schedule and process
for consideration; Annex: Revised Guidelines for the Preparation of National Communications by Parties Included in Annex I to the
Convention; p. 18. FCCC (1996).
21 Estimates are presented in units of teragrams of carbon dioxide equivalents (Tg CO2 Eq.), which weights each gas by its Global
Warming Potential, or GWP (see previous section) and is consistent with international practices.
1-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Figure 1-3
648.6.
707.9
1991 1992 1993 19941995 19961997 19981999
Eq.) from 1990 to 1999 and were responsible for the major-
ity of the increase in national emissions during this pe-
riod. The annual increase in CO2 emissions from fossil
fuel combustion was 1.2 percent in 1999, a figure close to
the source's average annual rate of 1.4 percent during the
1990s. Historically, changes in emissions from fossil fuel
combustion have been the dominant factor affecting U.S.
emission trends.
Changes in CO2 emissions from fossil fuel combus-
tion are influenced by many long-term and short-term
factors, including population and economic growth, en-
ergy price fluctuations, technological changes, and sea-
sonal temperatures. On an annual basis, the overall de-
mand for fossil fuels in the United States and other coun-
tries generally fluctuates in response to changes in gen-
eral economic conditions, energy prices, weather, and the
availability of non-fossil alternatives. For example, a year
with increased consumption of goods and services, low
fuel prices, severe summer and winter weather conditions,
nuclear plant closures, and lower precipitation feeding
hydroelectric dams would be expected to have propor-
tionally greater fossil fuel consumption than a year with
poor economic performance, high fuel prices, mild tem-
peratures, and increased output from nuclear and hydro-
electric plants.
Longer-term changes in energy consumption pat-
terns, however, tend to be more a function of changes
that affect the scale of consumption (e.g., population,
number of cars, and size of houses), the efficiency with
which energy is used in equipment (e.g., cars, power
plants, steel mills, and light bulbs) and consumer behav-
ior (e.g., walking, bicycling, or telecommuting to work
instead of driving).
Energy-related CO2 emissions are also a function
of the type fuel or energy consumed and its carbon inten-
sity. Producing heat or electricity using natural gas in-
stead of coal, for example, can reduce the CO2 emissions
associated with energy consumption because of the lower
carbon content of natural gas power unit of useful en-
ergy produced. Table 1-2 shows annual changes in emis-
sions during the last few years of the 1990s for particular
fuel types and sectors.
Carbon dioxide emissions from fossil fuel combus-
tion grew rapidly in 1996, due primarily to two factors:
1) fuel switching by electric utilities from natural gas to
more carbon intensive coal as colder winter conditions
and the associated rise in demand for natural gas from
residential, commercial and industrial customers for heat-
ing caused gas prices to rise sharply; and 2) higher con-
sumption of petroleum fuels for transportation. Milder
weather conditions in summer and winter moderated the
growth in emissions in 1997; however, the shut-down of
several nuclear power plants lead electric utilities to in-
crease their consumption of coal and other fuels to offset
the lost capacity. In 1998, weather conditions were again a
dominant factor in slowing the growth in emissions. Warm
winter temperatures resulted in a significant drop in resi-
dential, commercial, and industrial natural gas consump-
tion. This drop in emissions from natural gas used for heat-
ing was primarily offset by two factors: 1) electric utility
emissions, which increased in part due to a hot summer
and its associated air conditioning demand; and 2) in-
creased motor gasoline consumption for transportation.
22 If a full accounting of emissions from fossil fuel combustion is made by including emissions from the combustion of international
bunker fuels and CH4 and N2O emissions associated with fuel combustion, then this percentage increases to approximately 82 percent
during the 1990s.
Introduction 1-9
-------
Table 1-2: Annual Change in C02 Emissions from Fossil Fuel Combustion
for Selected Fuels and Sectors (Tg C02 Eq. and Percent)
Sector
Electric Utility
Electric Utility
Electric Utility
Transportation1
Residential
Commercial
Industrial
Industrial
All Sectors'1
Fuel Type
Coal
Natural Gas
Petroleum
Petroleum
Natural Gas
Natural Gas
Coal
Natural Gas
All Fuels"
1995
89.9
-25.3
5.1
38.8
21.4
7.0
-7.3
17.8
181.7
to 1996
5.7%
-14.7%
10.0%
2.5%
8.1%
4.3%
-2.7%
3.4%
3.5%
1996
52.0
13.1
8.1
7.6
-14.0
3.1
2.0
-0.5
71.9
101997
3.1%
'9.0%
14.4%
0.5%
-4.9%
1.8%
0.8%
-0.1%
1.4%
1997 to
14.3
16.2
26.7
34.1
-24.0
-11.1
-1.1
-14.5
11.9
1998
0.8%
10.1%
41.6%
2.1%
-8.9%
-6.4%
-0.4%
-2.7%
0.2%
1998
-32.1
-7.8
-17.4
57.6
8.5
2.9
29.2
1.6
66.4
to 1999
-1.8%
-4.4%
-19.1%
3.6%
.. 3.4%
1.8%
11.2%
0.3%
1.2%
1 Excludes emissions from International Bunker Fuels.
b Includes fuels and sectors not shown in table.
In 1999, the increase in emissions from fossil fuel
combustion was driven largely by growth in petroleum
consumption for transportation. In addition, heating fuel
demand partially recovered in the residential, commercial
and industrial sectors as winter temperatures dropped
relative to 1998, although temperatures were still warmer
than normal. These increases were offset, in part, by a
decline in emissions from electric utilities due primarily
to: 1) an increase in net generation of electricity by nuclear
plants (8 percent) to record levels, which reduced de-
mand from fossil fuel plants; and 2) moderated summer
temperatures compared to the previous year—thereby
reducing electricity demand for air conditioning. Utiliza-
tion of existing nuclear power plants, measured as aplant's
capacity factor,23 has increased from just over 70 percent
in 1990 to over 85 percent in 1999.
Another factor that does not affect total emissions,
but does affect the interpretation of emission trends is
the allocation of emissions from nonutility power pro-
ducers. The Energy Information Administration (EIA)
currently includes fuel consumption by nonutilities with
the industrial end-use sector. In 1999, there was a large
shift in generating capacity from utilities to nonutilities,
as restructuring legislation spurred the sale of 7 percent
of utility generating capability (EIA 2000b). This shift is
illustrated by the increase in industrial end-use sector
emissions from coal and the associated decrease in elec-
tric utility emissions. However, emissions from the indus-
trial end-use sector did not increase as much as would be
expected even though net generation by nonutilities in-
creased from 11 to 15 percent of total U.S. electricity pro-
duction (EIA 2000b).24
Other notable trends in emissions from additional
source categories over the nine-year period from 1990
through 1999 included the following:
• Aggregate HFC and PFC emissions resulting from
the substitution of ozone depleting substances (e.g.,
CFCs) increased by 55.8 Tg CO2 Eq. This increase
was partly offset, however, by reductions in PFC
emissions from aluminum production (9.2 Tg CO2
Eq. or 48 percent), and reductions in emissions of
HFC-23 from the production of HCFC-22 (4.4 Tg CO2
Eq. or 13 percent). Reductions in PFC emissions from
aluminum production were the result of both volun-
tary industry emission reduction efforts and lower
domestic aluminum production. HFC-23 emissions
from the production of HCFC-22 decreased due to a
reduction in the intensity of emissions from that
23 The capacity factor is defined as the ratio of the electrical energy produced by a generating unit for a given period of time to the
electrical energy that could have been produced at continuous full-power operation during the same period (EIA 1999).
24 It is unclear whether reporting problems for electric utilities and the industrial end-use sector have increased with the dramatic growth
in nonutilities and the opening of the electric power industry to increased competition.
1-10 inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Box 1-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data
There are several ways to assess a nation's greenhouse gas emitting intensity. The basis for measures of intensity can be 1) per unit
of aggregate energy consumption, because energy-related activities are the largest sources of emissions; 2) per unit of fossil fuel
,' consumption, because almost all energy-related emissions involve the combustion of fossil fuels; 3) per unit of electricity consump-
; tion, because the electric power industry—utilities and nonutilities combined—were the largest sources of U.S. greenhouse gas
; emissions in 1999; 4) per unit of total gross domestic product as a measure of national economic activity; or 5) on a per capita basis.
'•• Depending upon the measure used, the United States could appear to have reduced or increased its national greenhouse gas intensity
; during the 1990s.
Table 1-3 provides data on various statistics related to U.S. greenhouse gas emissions normalized to 1990 as a baseline year.
: Greenhouse gas emissions in the U.S. have grown at an average annual rate of 1.2 percent since 1990. This rate is slightly slower than
"'that for total energy or fossil fuel consumption—thereby indicating an improved or lower greenhouse gas emitting intensity—and
much slower than that for either electricity consumption or overall gross domestic product. Emissions, however, are growing faster
• than national population, thereby indicating a worsening or higher greenhouse gas emitting intensity on a per capita basis (see Figure
• 1-4). Overall, atmospheric C02 concentrations—a function of many complex anthropogenic and natural processes—are increasing
; at 0.4 percent per year.
Fable 1-3: Recent Trends in Various
Variable
GHG Emissions3
Energy Consumption11
Fossil Fuel Consumption11
Electricity Consumption11
GDP'
. Population"
Atmospheric CO, Concentration6
1991
99
100
99
102
100
101
100
U.S. Data (Index 19 90 =
1992
101
101
101
102
103
102
101
1993
103
104
103
105
105
103
101
1994
105
106
106
108
110
104
101
100)
1995
106
108
107
111
112
105
102
1996
109
111
110
114
116
106
102
1997
111
112
112
116
122
107
103
1998
111
112
112
119
127
108
104
1999
112
115
113
120
132
109
104
Growth
Rate'
1.2%
1.5%
1.4%
2.1%
3.2%
1.0%
0.4%
a GWP weighted values
b Energy content weighted values (EIA 2000a)
c Gross Domestic Product in chained 1996 dollars (BEA 2000)
d (U.S. Census Bureau 2000)
e Mauna Loa Observatory, Hawaii (Keeling and Whorf 2000)
f Average annual growth rate
Figure 1-4
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
Source: BEA (2000), U.S. Census Bureau (2000) and Emission estimates
In the report.
Introduction 1-11
-------
source, despite increased HCFC-22 production.
• Emissions of N2O from mobile combustion rose by
9.1 Tg CO2 Eq. (17 percent), primarily due to increased
rates of N2O generation in highway vehicles.
• Methane emissions from coal mining dropped by 26.0
Tg CO2 Eq. (30 percent) as a result of the mining of
less gassy coal from underground mines and the in-
creased use of methane from degasification systems.
• Nitrous oxide emissions from agricultural soil man-
agement increased by 29.3 Tg CO2 Eq. (11 percent)
as fertilizer consumption, livestock populations, and
crop production rose.
• By 1998, all of the three major adipic acid producing
plants had voluntarily implemented N2O abatement
technology, and as a result, emissions fell by 9.3 Tg
CO2 Eq. (51 percent). The majority of this decline
occurred from 1997 to 1998, despite increased pro-
duction.
Overall, from 1990 to 1999, total emissions of CO2
and N2O increased by 645.2 (13 percent) and 35.7 Tg CO2
Eq. (9 percent), respectively, while CH4 emissions de-
creased by 24.9 Tg CO2 Eq. (4 percent). During the same
period, aggregate weighted emissions of HFCs, PFCs,
and SF6 rose by 51.8 Tg CO2 Eq. (62 percent). Despite
being emitted in smaller quantities relative to the other
principle greenhouse gases, emissions of HFCs, PFCs,
and SF6 are significant because many of them have ex-
tremely high global warming potentials and, in the cases
of PFCs and SF6, long atmospheric lifetimes. Conversely,
U.S. greenhouse gas emissions were partly offset by car-
bon sequestration in forests and in landfilled carbon,
which were estimated to be 15 percent of total emissions
in 1999.
As an alternative, emissions can be aggregated
across gases by the IPCC defined sectors, referred to
here as chapters. Over the ten year period of 1990 to 1999,
total emissions in the Energy, Industrial Processes, Agri-
culture, and Waste chapters climbed by 603.6 (12 per-
cent), 58.2 (33 percent), 38.3 (8 percent), and 7.8 Tg CO2
Eq. (3 percent), respectively. Estimates of net carbon se-
questration in the Land-Use Change and Forestry chap-
ter declined by 69.5 Tg CO2Eq. (7 percent).
Table 1-4 summarizes emissions and sinks from all
U.S. anthropogenic sources in weighted units of Tg CO2
Eq., while unweighted gas emissions and sinks in
gigagrams (Gg) are provided in Table 1-5. Alternatively,
emissions and sinks are aggregated by chapter in Table
1-6 and Figure 1-5.
Methodology and Data Sources
Emissions of greenhouse gases from various
source and sink categories have been estimated using
methodologies that are consistent with the Revised 1996
IPCC Guidelines for National Greenhouse Gas Invento-
ries OPCC/UNEP/OECD/EEA1997). To the extent possible,
the present U.S. Inventory relies on published activity
and emission factor data. Depending on the emission
source category, activity data can include fuel consump-
tion or deliveries, vehicle-miles traveled, raw material pro-
cessed, etc.; emission factors are factors that relate quan-
tities of emissions to an activity. For some sources, IPCC
default methodologies and emission factors have been
employed. However, for most emission sources, the IPCC
default methodologies were expanded and more compre-
hensive 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-
Figure 1-5
Agriculture
Industrial
Processes
N- CO CO
Land-Use
._,, Change &
Forestry
(sink)
1-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 1 -4: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg C02 Eq.)
Gas/Source
1990
1995
1996 1997
1998
1999
C02
Fossil Fuel Combustion
Cement Manufacture
Waste Combustion
Lime Manufacture
Natural Gas Flaring
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Carbon Dioxide Consumption
Land-Use Change and Forestry (Sink)3
International Bunker Fuels"
CH4
Landfills
Enteric Fermentation
Natural Gas Systems
Coal Mining
Manure Management
Petroleum Systems
Wastewater Treatment
Rice Cultivation
Stationary Combustion
Mobile Combustion
Petrochemical Production
Agricultural Residue Burning
Silicon Carbide Production
International Bunker Fuels"
N20
Agricultural Soil Management
Mobile Combustion
Nitric Acid
Manure Management
Stationary Combustion
AdipicAcid
Human Sewage
Agricultural Residue Burning
Waste Combustion
International Bunker Fuels"
MFCs, PFCs, and SF6
4,913.0
4,835.7
33.3
17.6
11.2
5.1
5.1
4.1
0.8
(1,059.9)
114.0
644.5
217.3
129.5
121.2
87.9
26.4
27.2
11.2
8.7
8.5
5.0
1.2
0.5
+
+
396.9
269.0
54.3
17.8
16.0
13.6
18.3
7.1
0.4
0.3
1.0
83.9
Substitution of Ozone Depleting Substances 0.9
HCFC-22 Production
Electrical Transmission and Distribution
Aluminum Production
Semiconductor Manufacture
Magnesium Production and Processing
Total Emissions
Net Emissions (Sources and Sinks)
34.8
20.5
19.3
2.9
5.5
6,038.2
4,978.3
5,219.8
5,121.3
36.8
23.1
12.8
13.6
7.0
4.3
1.0
(1,019.1)
101.0
650.5
222.9
136.3
124.2
74.6
31.0
24.5
11.8
9.5
8.9
4.9
1.5
0.5
+
+
431.9
285.4
66.8
19.9
16.4
14.3
20.3
8.2
0.4
0.3
0.9
99.0
24.0
27.1
25.7
11.2
5.5
5.5
6,401.3
5,382.3
5,403.2
5,303.0
37.1
24.0
13.5
13.0
7.3
4.3
1.1
(1,021.6)
102.2
638.0
219.1
132.2
125.8
69.3
30.7
24.0
11.9
8.8
9.0
4.8
1.6
0.6
+
+
441.6
294.6
65.3
20.7
16.8
14.9
20.8
7.8
0.4
0.3
0.9
115.1
34.0
31.2
25.7
11.6
7.0
5.6
6,597.8
5,576.2
5,478.7
5,374.9
38.3
25.7
13.7
12.0
8.3
4.4
1.3
(981.9)
109.8
632.0
217.8
129.6
122.7
68.8
32.6
24.0
12.0
9.6
8.1
4.7
1.6
0.6
+
+
444.1
299.8
65.2
21.2
17.1
15.0
17.1
7.9
0.4
0.3
1.0
123.3
42.1
30.1
25.7
10.8
7.0
7.5
6,678.1
5,696.2
5,489.7
5,386.8
39.2
25.1
13.9
10.8
8.1
4.3
1.4
(983.3)
112.8
624.8
213.6
127.5
122.1
66.5
35.2
23.3
12.1
10.1
7.6
4.6
1.6
0.6
+
+
433.7
300.3
64.2
20.9
17.2
15.1
7.3
8.1
0.5
0.2
1.0
138.6
49.6
40.0
25.7
10.1
6.8
6.3
6,686.8
5,703.5
5,558.1
5,453.1
39.9
26.0
13.4
11.7
8.3
4.2
1.6
(990.4)
107.3
619.6
214.6
127.2
121.8
61.8
34.4
21.9
12.2
10.7
8.1
4.5
1.7
0.6
+
+
432.6
298.3
63.4
20.2
17.2
15.7
9.0
8.2
0.4
0.2
1.0
135.7
56.7
30.4
25.7
10.0
6.8
6.1
6,746.1
5,755.7
+ Does not exceed 0.05 Tg C02 Eq.
a Sinks are only included in net emissions total, and are based partially on projected activity data.
b Emissions from International Bunker Fuels are not included in totals.
Note: Totals may not sum due to independent rounding.
Note: Parentheses indicate negative values (or sequestration).
Introduction 1-13
-------
Table 1-5: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg)
Gas/Source
C02 4
Fossil Fuel Combustion 4
Cement Manufacture
Waste Combustion
Lime Manufacture
Natural Gas Flaring
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Carbon Dioxide Consumption
Land-Use Change and Forestry (Sink)3 (1 ,
International Bunker Fuels6
CH4
Landfills
Enteric Fermentation
Natural Gas Systems
Coal Mining
Manure Management
Petroleum Systems
WastewaterTreatment
Rice Cultivation
Stationary Combustion
Mobile Combustion
Petrochemical Production
Agricultural Residue Burning
Silicon Carbide Production
International Bunker Fuels"
M.,0
Agricultural Soil Management
Mobile Combustion
Nitric Acid
Manure Management
Stationary Combustion
Adiplc Acid
Human Sewage
Agricultural Residue Burning
Waste Combustion
International Bunker Fuels"
MFCs, PFCs, and SF6
1990
,912,959
,835,688
33,278
17,572
11,238
5,121
5,117
4,144
800
059,900)
114,001
30,689
10,346
6,166
5,772
4,184
1,256
1,294
533
414
403
237
56
25
1
2
1,280
868
175
58
52
44
59
23
1
1
3
M
Substitution of Ozone Depleting Substances M
HCFC-22 Production6
Electrical Transmission and Distribution"
Aluminum Production
Semiconductor Manufacture
Magnesium Production and Processing"
NOx
CO
NMVOCs
3
1
M
M
0
21,955
85,978
18,843
1995
5,219,832 5
5,121,263 5
36,847
23,065
12,805
13,587
6,987
4,309
968
(1,019,000)(1,
101,014
30,978
10,614
6,492
5,912
3,550
1,477
1,168
561
452
422
232
72
24
1
2
1,393
921
215
64
53
46
66
27
1
1
3
M
M
2
1
M
M
0
22,755
80,784
18,662
1996
,403,220
,302,961
37,079
23,968
13,495
12,998
7,305
4,273
1,140
021,400)
102,197
30,379
10,435
6,295
5,993
3,301
1,463
1,143
567
419
430
228
75
28
1
2
1,424
950
211
67
54
48
67
25
1
1
3
M
M
3
1
M
M
0
23,663
87,306
17,350
1997
5,478,677
5,374,913
38,323
25,674
13,685
12,026
8,327
4,434
1,294
(981,900)
109,788
30,096
10,371
6,172
5,841
3,274
1,553
1,142
572
455
386
225
77
29
1
2
1,433
967
210
68
55
49
55
26
1
1
3
M
M
3
1
M
M
0
23,934
87,131
17,586
1998
5,489,729
5,386,762
39,218
25,145
13,914
10,839
8,114
4,325
1,413
(983,400)
112,771
29,754
10,171
6,072
5,814
3,168
1,677
1,108
577
481
361
219
77
30
1
2
1,399
969
207
67
55
49
23
26
1
1
3
M
M
3
1
M
M
0
23,613
82,619
16,555
1999
5,558,150
5,453,088
39,896
25,960
13,426
11,701
8,290
4,217
1,572
(990,400)
107,345
29,504
10,221
6,057
5,799
2,944
1,638
1,044
583
509
386
215
79
28
1
2
1,395
962
204
65
55
51
29
26
1
.1
3
M
M
3
1
M
M
0
23,042
83,093
16,129
M Mixture of multiple gases
* Sinks are not included in C02 emissions total, and are based partially on projected activity data.
b Emissions from International Bunker Fuels are not included in totals.
c HFC-23 emitted
d SF6 emitted
Note: Totals may not sum due to independent rounding.
Note: Parentheses indicate negative values (or sequestration).
1-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 1-6: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg C02 Eq.)
Chapler/IPCC Sector
1990
1995
1996 1997
1998
1999
Energy
Industrial Processes
Agriculture
Land-Use Change and Forestry (Sink)*
Waste
Total Emissions
Net Emissions (Sources and Sinks)
5,158.4 . "~
175.8 L_
450.5 I
(1,059.9) , ;
253.4 .......
6,038.2
4,978.3
5,452.9
202.7
479.5
(1,019.1)
266.2
6,401.3
5,382.3
5,629.1
221.5
484.1
(1,021.6)
263.1
6,597.8
5,576.2
5,695.4
229.3
489.8
(981.9)
263.6
6,678.1
5,696.2
5,700.9
235.3
491.4
(983.3)
259.2
6,686.8
5,703.5
5,762.0
234.0
488.8
(990.4)
261.3
6,746.1
5,755.7
* Sinks are only included in net emissions total, and are based partially on projected activity data.
Note: Totals may not sum due to independent rounding.
Note: Parentheses indicate negative values (or sequestration).
Box 1-3: 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 Administra-
tion (FHWA). Likewise, the number of miles driven—up 13 percent from 1990 to 1999—and gallons of gasoline consumed each year
in the United States have increased steadily since the 1980s, according to the FHWA and Energy Information Administration,
respectively. These increases in motor vehicle usage are the result of a confluence of factors including population growth, economic
growth, urban sprawl, low fuel prices, and increasing popularity of sport utility vehicles and other light-duty trucks that tend to have
lower fuel efficiency.25 A similar set of social and economic trends has led to a significant increase in air travel and freight transporta-
tion—by both air and road modes—during the 1990s.
One of the unintended consequences of these changes is 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 are major sources of carbon monoxide (CO), carbon dioxide (C02), methane (CH4), nonmethane volatile
organic compounds (NMVOCs), nitrogen oxides (NOx), nitrous oxide (N20), and hydrofluorocarbons (HFCs). Motor vehicles are also
important contributors to many serious air pollution problems, including ground-level ozone (i.e., smog), acid rain, fine particulate
matter, and global warming. Within the United States and abroad, government agencies have taken actions to reduce these emissions.
Since the 1970s, the EPA has required the reduction of 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. New vehicles are now equipped with advanced emissions
controls, which are designed to reduce emissions of NOX, hydrocarbons, and CO.
Table 1 -7 summarizes greenhouse gas emissions from all transportation-related activities. Overall, transportation activities—
excluding international bunker fuels—accounted for an almost constant 26 percent of total U.S. greenhouse gas emissions from 1990
to 1999. These emissions were primarily C02from fuel combustion, which increased by 16 percent from 1990 to 1999. However,
because of larger increases in I\I20 and HFC emissions during this period, overall emissions from transportation activities actually
increased by 18 percent.
25 The average miles per gallon achieved by the U.S. highway vehicle fleet actually decreased by slightly less than one percent in both
1998 and 1999.
Introduction 1-15
-------
Table 1-7: Transportation-Related Greenhouse Gas Emissions (Tg C02 Eq.)
Gas/Vehicle Type
1990
1995
1996
1997
1998
1999
C02
Passenger Cars
Light-Duty Trucks
Other Trucks
Buses
Aircraft11
Boats and Vessels
Locomotives
Other*
International Bunker Fuels0
CH4
Passenger Cars
Light-Duty Trucks
Other Trucks and Buses
Aircraft
Boats and Vessels
Locomotives
Other*
International Bunker Fuels0
N20
Passenger Cars
Light-Duty Trucks
Other Trucks and Buses
Aircraft8
Boats and Vessels
Locomotives
Other*
International Bunker Fuels0
HFCs
Mobile Air Conditioners6
Tola!0
1,474.4
620.0
283.1
206.0
10.7
176.7
59.4
28.4
90.1
114.0
5.0
2.4
1.6
0.4
0.2
0.1
0.1
0.2
+
54.3
31.0
17.8
2.6
1.7
0.4
0.3
0.6
1.0
+
+
1,533.7
1,581.8
641.9
325.3
235.9
13.5
171.5
66.9
31.5
95.3
101.0
4.9
2.0
1.9
0.5
0.1
0.1
0.1
0.2
+
66.8
33.0
27.1
3.6
1.7
0.5
0.3
0.6
0.9
9.5
9.5
1,663.0
1,621.2
654.1
333.5
248.1
11.3
180.2
63.8
33.4
96.7
102.2
4.8
2.0
1.6
0.7
0.1
0.1
0.1
0.2
+
65.3
32.7
23.9
5.6
1.8
0.4
0.3
0.6
0.9
13.5
13.5
1,704.8
1,631.4
660.2
337.3
257.0
12.0
179.0
50.2
34.4
101.4
109.8
4.7
2.0
1.6
0.7
0.2
0.1
0.1
0.2
+
65.2
32.4
24.0
5.8
1.7
0.3
0.2
0.6
1.0
17.2
17.2
1,718.5
1,659.0
674.5
356.9
257.9
12.3
183.0
47.9
33.6
93.0
112.8
4.6
2.0
1.5
0.7
0.1
0.1
+
0.2
+
64.2
32.1
23.3
5.9
1.8
0.3
0.2
0.6
1.0
20.6
20.6
1,748.4
1,716.4
688.9
364.8
269.7
12.9
184.6
65.6
35.1
94.9
107.3
4.5
1.9
1.4
0.7
0.2
0.1
+
0.2
+
63.4
31.5
22.7
6.1
1.8
0.4
0.2
0.6
1.0
23.7
23.7
1,808.0
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
3 Aircraft emissions consist of emissions from all jet fuel (less bunker fuels) and aviation gas consumption.
b "Other" C02 emissions include motorcycles, construction equipment, agricultural machinery, pipelines, and lubricants.
0 Emissions from International Bunker Fuels include emissions from both civilian and military activities, but are not included in totals.
i "Other" CH4 and N20 emissions include 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.
• Includes primarily HFC-134a.
Box 1-4: Greenhouse Gas Emissions from Electric Utilities
Like transportation, activities related to the generation, transmission, and distribution of electricity in the United States resulted in
a significant fraction of total U.S. greenhouse gas emissions. The electric power industry in the United States is composed of traditional
electric utilities as well as other entities, such as power marketers and nonutility power producers.
Table 1-8 presents emissions from electric utility-related activities. Aggregate emissions from electric utilities of all greenhouse
gases increased by 11 percent from 1990 to 1999, and accounted for a relatively constant 29 percent of U.S. emissions during the
same period. Emissions from nonutility generators are not included in these estimates. Nonutilities were estimated to have produced
about 15 percent of the electricity generated in the United States in 1999, up from 11 percent in 1998 (EIA 2000c). Therefore a more
complete accounting of greenhouse gas emissions from the electric power industry (i.e., utilities and nonutilities combined) would
account for roughly 40 percent of U.S. C02 emissions (EIA 2000d).
The majority of electric utility-related emissions resulted from the combustion of coal in boilers to produce steam that is passed
through a turbine to generate electricity. Overall, the generation of electricity—especially when nonutility generators are included—
results in a larger portion of total U.S. greenhouse gas emissions than any other activity.
1-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 1-8: Electric Utility-Related Greenhouse Gas Emissions (Tg C02 Eq.)
Gas/Fuel Type or Source
1990
1995
1996
1997
1998
1999
C02
Coal
= Natural Gas
Petroleum
Geothermal
CH4
Stationary Combustion
N20
; , Stationary Combustion
SF6
: Electrical Transmission
Total
1,757.3
1,509.3
151.1
96.8
0.2
0.5
(Utilities) 0.5
7.4
(Utilities) 7,4
20.5
and Distribution 20.5
1,785.7
1,810.6
1,587.7
171.8
51.0
0.1
0.5
0.5
7.8
7.8
25.7
m__ , 25.7
1,844.5
1,880.3
1,677.7
146.5
56.0
0.1
0.5
0.5
8.2
8.2
25.7
25.7
1,914.7
1,953.5
1,729.7
159.6
64.1
0,1
0.5
0.5
8.5
8.5
25.7
25.7
1,988.2
2,010.7
1,744.0
175.8
90.8
0.1
0.5
0.5
8.7
8.7
25.7
25.7
2,045.6
1,953.4
1,711.9
168.0
73.4
+
0.5
0.5
8.6
8.6
25.7
25.7
1,988.2
; Note: Totals may not sum due to independent rounding.
Box 1-5: IPCC Good Practice Guidance
In response to a request by Parties to the United Nations Framework Convention on Climate Change (UNFCCC), the Intergovern-
f mental Panel on Climate Change (IPCC) finalized a set of good practice guidance in May 2000 on uncertainty and good practices in
; inventory management/The report, entitled Good Practice Guidance and Uncertainty Management in National Greenhouse Gas
: Inventories (Good Practice), was developed with extensive participation of experts from the United States as well as many other
i countries.26 It focuses on providing direction to countries to produce emission estimates that are as accurate, with the least
, uncertainty, as possible. In addition, Good Practice was designed as atool to compliment the methodologies suggested in the Revised
• 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC Guidelines).
; In order to obtain these goals, Good Practice establishes a set of guidelines for ensuring the following standards are met:
• • The most appropriate estimation method is used, within the context of the IPCC Guidelines
I. • Quality control and quality assurance measures are adhered to
: • Proper assessment and documentation of data and information is carried out
>..,„...• Uncertainties are quantified and tracked for each source category as well as the inventory in its entirety
; By providing such direction, the IPCC hopes to help countries provide Inventories that are transparent, documented, and
,, comparable, and that have been assessed for uncertainties, checked for quality control and quality assurance, and used resources
efficiently.
ergy Information Administration (EIA) of the U.S. De-
partment of Energy. 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 -1999 (EPA 2000), which is an annual EPA publica-
tion that provides the latest estimates of regional and
national emissions of criteria pollutants. Emissions of
these pollutants are estimated by the EPA based on sta-
tistical information about each source category, emission
factors, and control efficiencies. While the EPA's estima-
tion methodologies for criteria pollutants are conceptu-
ally similar to the IPCC recommended methodologies, the
large number of sources EPA used in developing its crite-
ria pollutant estimates makes it difficult to reproduce the
methodologies from EPA (2000) in this inventory docu-
ment. In these instances, the references containing de-
tailed documentation of the methods used are identified
See
Introduction 1-17
-------
for the interested reader. For agricultural sources, the EPA
criteria pollutant emission estimates were supplemented
using activity data from other agencies. Complete docu-
mentation of the methodologies and data sources used is
provided in conjunction with the discussion of each
source and in the various annexes.
Emissions from fossil fuels combusted in civilian
and military ships and aircraft engaged in the interna-
tional transport of passengers and cargo are not included
in U.S. totals, but are reported separately as international
bunkers in accordance with IPCC reporting guidelines
flPCC/UNEP/OECD/DEA 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 1999. However, the United
States believes that common and consistent inventories
taken over a period of time can and will contribute to
understanding future emission trends. The United States
produced its first comprehensive inventory of greenhouse
gas emissions and sinks in 1993, and intends to update it
annually, in conjunction with its commitments under the
UNFCCC. The methodologies used to estimate emissions
will also be updated periodically as methods and infor-
mation improve and as further guidance is received from
the IPCC and UNFCCC.
Secondly, there are uncertainties associated with
the emission estimates. Some of the current estimates,
such as those for CO2 emissions from energy-related ac-
tivities and cement processing, are considered to be fairly
accurate. For some other categories of emissions, how-
ever, a lack of data or an incomplete understanding of
how emissions are generated limits the scope or accu-
racy of the estimates presented. Despite these uncertain-
ties, the Revised 1996 IPCC Guidelines for National
Greenhouse Gas Inventories (BPCC/UNEP/OECD/IEA
1997) require that countries provide single point estimates
for each gas and emission or removal source category.
Within the discussion of each emission source, specific
factors affecting the accuracy of the estimates are dis-
cussed.
Finally, while the IPCC methodologies provided in
the Revised 1996 IPCC Guidelines represent baseline
methodologies for a variety of source categories, many
of these methodologies continue to be improved and re-
fined as new research and data becomes available. The
current U.S. inventory uses the IPCC methodologies when
applicable, and supplements them with other available
methodologies and data where possible. The United
States realizes that additional efforts are still needed to
improve methodologies and data collection procedures.
Specific areas requiring further research include:
• Incorporating excluded emission sources. Quanti-
tative 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 ac-
tivities and industrial processes are not included in
the inventory either because data are incomplete or
because methodologies do not exist for estimating
emissions from these source categories. See Annex
S for a discussion of the sources of greenhouse gas
emissions and sinks excluded from this report.
• Improving the accuracy of emission factors. Further
research is needed in some cases to improve the ac-
curacy of emission factors used to calculate emis-
sions from a variety of sources. For example, the ac-
curacy of current emission factors applied to meth-
ane and nitrous oxide emissions from stationary and
mobile combustion is highly uncertain.
• Collecting detailed activity data. Although meth-
odologies exist for estimating emissions for some
sources, problems arise in obtaining activity data at
1-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
a level of detail in which aggregate emission factors
can be applied. For example, the ability to estimate
emissions of SF6 from electrical transmission and dis-
tribution is limited due to a lack of activity data re-
garding national SF6 consumption or average equip-
ment leak rates.
• Applying Global Warming Potentials. GWP values
have several limitations, including that they are not
applicable to unevenly distributed gases and aero-
sols such as tropospheric ozone and its precursors.
They are also intended to reflect global averages
and, therefore, do not account for regional effects.
Overall, the main uncertainties in developing GWP
values are the estimation of atmospheric lifetimes,
assessing indirect effects, choosing the appropriate
integration time horizon, and assessing instanta-
neous radiative forcing effects, which are dependent
upon existing atmospheric concentrations. Accord-
ing to the IPCC, GWPs typically have an uncertainty
of ±35 percent (IPCC 1996).
Emissions calculated for the U.S. inventory reflect
current best estimates; in some cases, however, estimates
are based on approximate methodologies, assumptions,
and incomplete data. As new information becomes avail-
able in the future, the United States will continue to im-
prove and revise its emission estimates.
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/ffiA 1997), this U.S. inventory of greenhouse gas
emissions and sinks is segregated into six sector-specific
chapters, listed below in Table 1-9.
Within each chapter, emissions are identified by
the anthropogenic activity that is the source or sink of
the greenhouse gas emissions being estimated (e.g., coal
mining). Overall, the following organizational structure is
consistently applied throughout this report:
Chapter/I PCC Sector: overview
of emission trends for each IPCC defined sector
Source: Description of source pathway and
emission trends from 1990 through 1999
— Methodology! Description of analytical
methods employed to produce emission esti-
mates
— Data Sources: Identification of dataref-
erences, primarily for activity data and emission
factors
— Uncertainty: Discussion of relevant is-
sues related to the uncertainty in the emission
estimates presented
Table 1-9: IPCC Sector Descriptions
Chapter/IPCC Sector
Activities Included
Energy
Emissions of all greenhouse gases resulting from stationary and mobile energy activities
including fuel combustion and fugitive fuel emissions.
By-product or fugitive emissions of greenhouse gases from industrial processes not directly
related to energy activities such as fossil fuel combustion.
Emissions, of primarily non-methane volatile organic compounds (NMVOCs), resulting from
the use of solvents.
Anthropogenic emissions from agricultural activities except fuel combustion and sewage
emissions, which are addressed under Energy and Waste, respectively.
Land-Use Change and Forestry Emissions and removals from forest and land-use change activities, primarily carbon dioxide.
Industrial Processes
Solvent Use
Agriculture
Waste
Emissions from waste management activities.
Source: (IPCC/UNEP/OECD/IEA 1997)
Introduction 1-19
-------
Special attention is given to carbon dioxide from
fossil fuel combustion relative to other sources because
of its share of emissions relative to other sources and its
dominant influence on emission trends. For example, each
energy consuming end-use sector (i.e., residential, com-
mercial, industrial, and transportation), as well as the elec-
tric utility sector, is treated individually. Additional infor-
mation for certain source categories and other topics is
also provided in several Annexes listed in Table 1-10.
Table 1-10: List of Annexes
ANNEX A Methodology for Estimating Emissions of C02
from Fossil Fuel Combustion
ANNEX B Methodology for Estimating Carbon Stored in
Products from Non-Energy Uses of Fossil Fuels
ANNEX C Methodology for Estimating Emissions of CH4,
N20, and Criteria Pollutants from Stationary
Combustion
ANNEX D Methodology for Estimating Emissions of CH4,
Nj.0, and Criteria Pollutants from Mobile
Combustion
ANNEX E Methodology for Estimating CH4 Emissions from
Coal Mining
ANNEX F Methodology for Estimating CH4 Emissions from
Natural Gas Systems
ANNEX G Methodology for Estimating CH4 Emissions from
Petroleum Systems
ANNEX H Methodology for Estimating Emissions from
International Bunker Fuels Used by the U.S.
Military
ANNEX I Methodology for Estimating HFC, PFC, and SF6
Emissions from Substitution of Ozone Depleting
Substances
ANNEX J Methodology for Estimating CH4 Emissions from
Enteric Fermentation
ANNEX K Methodology for Estimating CH4 Emissions from
Manure Management
ANNEX L Methodology for Estimating N20 Emissions from
Agricultural Soil Management
ANNEX M Methodology for Estimating CH4 Emissions from
Landfills
ANNEX N Global Warming Potential Values
ANNEX 0 Ozone Depleting Substance Emissions
ANNEX P Sulfur Dioxide Emissions
ANNEX Q Complete List of Source Categories
ANNEX R IPCC Reference Approach for Estimating C02
Emissions from Fossil Fuel Combustion
ANNEX S Sources of Greenhouse Gas Emissions Excluded
ANNEX T Constants, Units, and Conversions
ANNEX U Abbreviations
ANNEX V Chemical Symbols
ANNEX W Glossary
1 -20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
nergy
Energy-related activities were the primary sources of U.S. anthropogenic greenhouse gas emissions, ac-
•acounting for 85 percent of total emissions on a carbon equivalent basis in 1999. This included 98,35, and 18
percent of the nation's carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) emissions, respectively. Energy-
related CO2 emissions alone constituted 81 percent of national emissions from all sources on a carbon equivalent
basis, while the non-CO2 emissions from energy-related activities represented a much smaller portion of total national
emissions (4 percent collectively).
Emissions from fossil fuel combustion comprise the vast majority of energy-related emissions, with CO2 being
the primary gas emitted (see Figure 2-1). Due to the relative importance of fossil fuel combustion-related CO2 emis-
sions, 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 com-
pounds (NMVOCs). Mobile fossil fuel combustion was the second largest source of N2O emissions in the United
States, and overall energy-related activities were collectively the largest source of criteria pollutant emissions.
Energy-related activities other than fuel combustion, such as the production, transmission, storage, and distri-
bution 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 in the Energy chapter because biomass
fuels are of biogenic origin. It is assumed that the carbon
released when biomass is consumed is recycled as U.S.
forests and crops regenerate, causing no net addition of
CO2 to the atmosphere. The net impacts of land-use and
forestry activities on the carbon cycle are accounted for in
the Land-Use Change and Forestry chapter. Emissions of
other greenhouse gases from the combustion of biomass
and biomass based fuels are included in national totals
under stationary and mobile combustion.
Overall, emissions from energy-related activities have
increased from 1990 to 1999 due, in part, to the strong
performance of the U.S. economy. Over this period, the
20 40 60 so 100120140 U.S. Gross Domestic Product (GDP) grew approximately 32
Tg co2 Eq. percent, or at an average annual rate of 3.7 percent. This
Figure 2-1
Fossil Fuel Combustion
Natural Gas Systems
Mobile Sources
Coal Mining
Stationary Sources
Petroleum Systems
Natural Gas Flaring
5,453
1
Portion of All
Emissions
Energy 2-1
-------
Table 2-1: Emissions from Energy (Tg C02 Eq.)
Gas/Source
1990
1995
1996
1997
1998
1999
C02
Fossil Fuel Combustion
Natural Gas Flaring
Biomass-Wood*
International Bunker Fuels*
Biomass-Ethanol*
Carbon Stored in Products*
CH4
Natural Gas Systems
Coal Mining
Petroleum Systems
Stationary Sources
Mobile Sources
International Bunker Fuels*
N20
Mobile Sources
Stationary Sources
International Bunker Fuels*
Total
4,840.8
4,835.7
5.1
174.9
114.0
5.7
(276.2)
249.7
121.2
87.9
27.2
8.5
5.0
+
67.9
54.3
13.6
1.0
5,158.4
5,134.8
5,121.3
13.6
193.2
101.0
7.2
(317.9)
237.0
124.2
74.6
24.5
8.9
4.9
+
81.1
66.8
14.3
0.9
5,452.9
5,316.0
5,303.0
13.0
197.0
102.2
5.1
(323.1)
233.0
125.8
69.3
24.0
9.0
4.8
+
80.2
65.3
14.9
0.9
5,629.1
5,386.9
5,374.9
12.0
187.6
109.8
6.7
(338.6)
228.2
122.7
68.8
24.0
8.1
4.7
+
80.2
65.2
15.0
1.0
5,695.4
5,397.6
5,386.8
10.8
187.4
112.8
7.3
(343.4)
224.1
122.1
66.5
23.3
7.6
4.6
+
79.3
64.2
15.1
1.0
5,700.9
5,464.8
5,453.1
11.7
226.3
107.3
7.8
(361.7)
218.2
121.8
61.8
21.9
8.1
4.5
+
79.1
63.4
15.7
1.0
5,762.0
+ Does not exceed 0.05 Tg C02 Eq.
* These values are presented for informational purposes only and are not included or are already accounted for in totals.
Note: Totals may not sum due to independent rounding.
robust economic activity increased the demand for fossil
fuels, with an associated increase hi greenhouse gas emis-
sions. Table 2-1 summarizes emissions for the Energy
chapter in units of teragrams of carbon dioxide equiva-
lents (Tg CO2 Eq.), while unweighted gas emissions in
gigagrams (Gg) are provided in Table 2-2. Overall, emis-
sions due to energy-related activities were 5,762.0 Tg CO2
Eq. in 1999, an increase of 12 percent since 1990.
Carbon Dioxide Emissions from
Fossil Fuel Combustion
Carbon dioxide (CO2) emissions from fossil fuel
combustion grew by 1.2 percent from 1998 to 1999. Mild
winter conditions and increased output from nuclear
plants in 1999 resulted in a demand for energy derived
from fossil fuels that was less than what would have been
expected given the strength of the economy and steady
growth in population. In 1999, CO2 emissions from fossil
fuel combustion were 5,453.1 TgCO2Eq., or 12.8 percent
above emissions in 1990 (see Table 2-3).
Changes in CO2 emissions from fossil fuel combus-
tion are influenced by many long-term and short-term
factors. On a year-to-year basis, the overall demand for
fossil fuels in the United States and other countries gen-
erally fluctuates in response to changes in general eco-
nomic conditions, energy prices, weather, and the avail-
ability of non-fossil alternatives. For example, a year with
increased consumption of goods and services, low fuel
prices, severe summer and winter weather conditions,
nuclear plant closures, and lower precipitation feeding
hydroelectric dams would be expected to have propor-
tionally greater fossil fuel consumption than a year with
poor economic performance, high fuel prices, mild tem-
peratures, and increased output from nuclear and hydro-
electric plants.
Longer-term changes in energy consumption pat-
terns, however, tend to be more a function of changes
that affect the scale of consumption (e.g., population,
number of cars, and size of houses), the efficiency with
which energy is used in equipment (e.g., cars, power
plants, steel mills, and light bulbs), and social planning
and consumer behavior (e.g., walking, bicycling, or
telecommuting to work instead of driving).
Carbon dioxide emissions are also a function of the
source of energy and its carbon intensity. The amount of
carbon in fuels varies significantly by fuel type. For ex-
ample, coal contains the highest amount of carbon per
2-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 2-2: Emissions from Energy (Gg)
Gas/Source
1990
1995
1996
1997
1998
1999
C02
Fossil Fuel Combustion
Natural Gas Flaring
Biomass-Wood*
International Bunker Fuels*
Biomass-Ethanol*
Carbon Stored in Products*
CH4
Natural Gas Systems
Coal Mining
Petroleum Systems
Stationary Sources
Mobile Sources
International Bunker Fuels*
N20
Mobile Combustion
Stationary Combustion
International Bunker Fuels*
4,840,810
4,835,688 1_,
5,121
174,862 '.:;; :
114,001 ;
5,701
(276,233) ""-"•' ~
11,891
5,772
4,184
1,294 *
403
237
2 •
219
175 :
44
3
5,134,850
5,121,263
13,587
193,245
101,014
7,244
(317,931)
11,284
5,912
3,550
1,168
422
232
2
262
215
46
3
5,315,958
5,302,961
12,998
196,973
102,197
5,144
(323,052)
11,096
5,993
3,301
1,143
430
228
2
259
211
48
3
5,386,939
5,374,913
12,026
187,585
109,788
6,731
(338,611)
10,868
5,841
3,274
1,142
386
225
2
259
210
49
3
5,397,600
5,386,762
10,839
187,433
112,771
7,329
(343,383)
10,669
5,814
3,168
1,108
361
219
2
256
207
49
3
5,464,789
5,453,088
11,701
226,287
107,345
7,776
(361,712)
10,388
5,799
2,944
1,044
386
215
2
255
204
51
3
. + Does not exceed 0.05 Gg
* These values are presented for informational purposes only and are not included or are already accounted for in totals.
Note: Totals may not sum due to independent rounding.
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 Therefore, producing heat or
electricity using natural gas instead of coal, for example,
can reduce the CO2 emissions associated with energy
consumption, and using nuclear or renewable energy
sources (e.g., wind) can essentially eliminate emissions
(see Box 2-2).
Figure 2-2
In the United States, 84 percent of the energy con-
sumed was produced through the combustion of fossil
fuels such as coal, natural gas, and petroleum (see Figure
2-2 and Figure 2-3). Of the remaining 16 percent, half was
supplied by nuclear electric power and half by a variety
of renewable energy sources, primarily hydroelectric
power (EIA 2000a). Specifically, petroleum supplied the
largest share of domestic energy demands, accounting
Figure 2-3
7.6% Renewable
8.0% Nuclear
22.5% Coal
22.9% Natural Gas
39.0% Petroleum
Source: DOE/EIA-0384(99), Annual Energy Review 1998,
Table 1.3, July 2000
,•••-- .
120 -
imption (QBtu)
_&
en co o
o o o
Energy Consi
to £.
o o o
Total Energy
Renewable & Nuclear
1991 1993 1995 1997 1999
Note: Expressed as gross calorific values.
Source: DOE/EIA-0384(97), Annual Energy Review 1999,
Table 1.3, July 2000
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: C02 Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg C02 Eq.)
Fuel/Sector
Coal
Residential
Commercial
Industrial
Transportation
Electric Utilities
U.S. Territories
Natural Gas
Residential
Commercial
Industrial
Transportation
Electric Utilities
U.S. Territories
Petroleum
Residential
Commercial
Industrial
Transportation
Electric Utilities
U.S. Territories
Geothermal*
Total
1990
1,775.9
5.8
8.7
251.4
NE
1,509.3
0.6
1,001.9
238.5
142.4
433.8
36.0
151.1
NE
2,057.8
87.7
66.1
338.3
1,435.8
96.8
33.1 ..
0.2
4,835.7
1995
1,867.9
5.0
7.6
266.6
NE
1,587.7
0.9
1,154.0
263.1
164.5
516.2
38.3
171.8
NE
2,099.2
94.2
51.8
318.2
1,541.1
51.0
43.1
0.1
5,121.3
1996
1,950.8
5.1
7.7
259.3
NE
1,677.7
0.9
1,175.5
284.6
171.6
534.0
38.9
146.5
NE
2,176.5
100.7
53.5
347.2
1,579.8
56.0
39.1
0.1
5,303.0
1997
2,005.6
5.5
8.2
261.3
NE
1,729.7
1.0
1,179.8
270.5
174.7
533.5
41.5
159.6
NE
2,189.4
98.9
50.8
346.4
1,587.4
64.1
41.8
0.1
5,374.9
1998
2,015.6
4.2
6.3
260.2
NE
1,744.0
0.9
1,139.8
246.5
163.6
519.0
34.9
175.8
NE
2,231.3
90.3
47.6
334.1
1,621.6
90.8
47.0
0.1
5,386.8
1999
2,012.8
4.2
6.3
289.4
NE
1,711.9
0.9
1,144.7
255.0
166.4
520.5
34.8
168.0
NE
2,295.6
95.0
50.3
345.6
1,679.2
73.4
52.1
+
5,453.1
NE (Not estimated)
+ Does not exceed 0.05 Tg C02 Eq.
* Although not technically a fossil fuel, geothermal energy-related C02 emissions are included for reporting purposes.
Note: Totals may not sum due to independent rounding.
for an average of 39 percent of total energy consumption
from 1990 through 1999. Natural gas and coal followed in
order of importance, each accounting for an average of
23 percent of total consumption. Most petroleum was
consumed in the transportation end-use sector, while the
vast majority of coal was used by electric utilities, with
natural gas broadly consumed in all end-use sectors ex-
cept transportation (see Figure 2-4) (EIA 2000a).
Fossil fuels are generally combusted for the pur-
pose of producing energy for useful heat and work. Dur-
ing the combustion process the carbon stored in the fu-
els is oxidized and emitted as CO2 and smaller amounts of
other gases, including methane (CH4), carbon monoxide
(CO), and non-methane volatile organic compounds
(NMVOCs).2 These other carbon containing non-CO2
gases are emitted as a by-product of incomplete fuel com-
bustion, but are, for the most part, eventually oxidized to
CO2 in the atmosphere. Therefore, except for the soot an
Figure 2-4
' '
• Natural Gas • Petroleum B Coal
Relative
2,000 -I Contribution
Note: Utilities also includes emissions of 0.04 Tg CO2 Eq.
from geothermal based electricity generation
2 See the sections entitled Stationary Combustion and Mobile Combustion in this chapter for information on non-CO2 gas emissions
from fossil fuel combustion.
2-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Box 2-1: Weather and Non-Fossil Energy Adjustments to C02 from Fossil Fuel Combustion Trends
An analysis was performed using ElA's Short-Term Integrated Forecasting System (STIFS). model to examine the effects of
variations in weather and output from nuclear and hydroelectric generating plants on U.S. energy-related C02 emissions.3 Weather
i^ conditions affect energy demand because of the impact they have on residential, commercial, and industrial end-use sector heating
;,;-. and cooling demands. Warmer winters tend to reduce demand for heating fuels—especially natural gas—while cooler summers tend
g to reduce air conditioning-related electricity demand. Changes in electricity output from hydroelectric and nuclear power plants do not
t necessarily affect final energy demand, but increased output from these plants does offset electricity generation by fossil fuel power
l plants, and therefore leads to reduced C02 emissions.
';': The results of this analysis show that CQ2 emissions from fossil fuel combustion would have been roughly 1.9 percent higher (102
!:" Tg C02 Eq.) if weather conditions and hydroelectric and nuclear power generation had achieved normal levels (see Figure 2-5).
; Similarly, emissions in 1997 and 1998 would have been roughly 0.5 and 1.2 percent (7 and 17 Tg C02 Eq.) greater under normal
-conditions, respectively.
L In addition to the absolute level of emissions being greater, the growth rate in C02 emissions from fossil fuel combustion from 1998
f; to 1999 would have been 2.0 percent instead of the actual 1.2 percent if both weather conditions and nonfossil electricity generation
'"; had been normal (see Figure 2-6). Similarly, emissions in 1998 would have increased by 0.9 percent under normal conditions versus
"the actual rate of 0.2 percent.
Figure 2-5
Figure 2-6
1997
1998
1999
103
Hydro & Nuclear
Electricity
Generation
Cooling
Degree Days
Heating
Degree Days
Total
Adjusted
§
Hydro &
Nuclear
Adjusted
Weather
Adjusted
100
-1.0%
0.0%
1.0%
2.0%
1997
1998
1999
3 The STIFS model is employed in producing EIA's Short-Term Energy Outlook (DOE/EIA-0202). Complete model documentation can
be found at < http://www.eia.doe.gov/eraeu/steo/pub/contents.html>. A variety of other factors that influence energy-related CO2
emissions were also examined such as: changes in output from energy intensive manufacturing industries, and changes in fossil fuel prices
for 1997 through 1999. These additional factors, however, were found to have less of an impact on deviations in greenhouse gas
emission trends than weather and nonOfossil fuel generation fluxuations.
Energy 2-5
-------
Box 2-1: Weather and Non-Fossil Energy Adjustments to C02 from Fossil Fuel Combustion Trends (continued)
Warmer winter conditions in both 1 998 and 1 999 had a significant effect on U.S. C02 emissions by reducing demand for heating
fuels. Heating degree days in the United States in 1 998 and 1 999 were 1 4 and 7 percent below normal, respectively (see Figure 2-7).4
These warm winters, however, were partially countered by increased electricity demand that resulted from hotter summers. Cooling
degree days in 1998 and 1999 were 1 8 and 3 percent above normal, respectively (see Figure 2-8).
Although no new U.S. nuclear power plants have been constructed in many years, the utilization (i.e., capacity factors)5 of existing
plants reached record levels in 1998 and 1999, approaching 90 percent. This increase in utilization translated into an increase in
electricity output by nuclear plants of slightly more than 7 percent in both years. This increase in nuclear plant output, however, was
partially offset by reduced electricity output by hydroelectric power plants, which declined by 10 and 4 percent in 1998 and 1999,
respectively. Electricity generated by nuclear plants provides approximately twice as much of the energy consumed in the United States
as hydroelectric plants. Nuclear and hydroelectric capacity factors since 1973 and 1989, respectively, are shown in Figure 2-9.
Figure 2-7
^
99% Confidence - Upper Bound
Normal
(4,576 Heating Degree Days)
99% Confidence - Lower Bound
1949 1952 1955 1958 1961 1964 1967 1970 1973 1976 1979 1982 1985 1988 1991 1994 1997
Note: Cllmatologlcal normal data is highlighted. Statistical confidence interval for "normal" climatology period of 1961
through 1990.
Source: NOAA(2000b)
Figure 2-8
20
99% Confidence - Upper Bound
Normal
(1,193 Cooling Degree Days)
m
99% Confidence - Lower Bound
-20 J
1949 1952 1955 1958 1961 1964 1967 1970 1973 1976 1979 1982 1985 1988 1991 1994 1997
Note: Climatological normal data is highlighted. Statistical confidence interval for "normal" climatology period of 1961
through 1990.
Source: NOAA(2000b)
4 Degree days are relative measurements of outdoor air temperature. Heating degree days are deviations of the mean daily temperature
below 65° F, while cooling degree days are deviations of the mean daily temperature above 65° F. Excludes Alaska and Hawaii. Normals
are based on data from 1961 through 1990. The variation in these normals during this time period was ±10 percent and ±14 percent for
heating and cooling degree days, respectively (99 percent confidence interval).
5 The capacity factor is defined as the ratio of the electrical energy produced by a generating unit for a given period of time to the
electrical energy that could have been produced at continuous full- power operation during the same period (DOE/EIA 2000).
2-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Figure 2-9
100
1973 1978 1983 1988 1993 1998
-
ash left behind during the combustion process, all the
carbon hi fossil fuels used to produce energy is generally
converted to atmospheric CO2.
For the purpose of international reporting, the IPCC
(IPCC/UNEP/OECD/IEA1997) requires that particular ad-
justments be made to national fuel consumption statis-
tics. Certain fossil fuels can be manufactured into plas-
tics, asphalt, lubricants, or other products. A portion of
the carbon consumed for these non-energy products can
be stored (i.e., sequestered) for long periods of time. To
account for the fact that the carbon in these fuels ends
up in products instead of being combusted (i.e., oxidized
and released into the atmosphere), the fraction of fossil
fuel-based carbon hi manufactured products is subtracted
from emission estimates. (See the Carbon Stored in Prod-
ucts from Non-Energy Uses of Fossil Fuels section in
this chapter.) The fraction of this carbon stored in prod-
ucts that is eventually combusted in waste incinerators
or combustion plants is accounted for in the Waste Chapter
under Waste Combustion.
The IPCC (1997) also requires that CO2 emissions
from the consumption of fossil fuels for aviation and
marine international transport activities (i.e., international
bunker fuels) be reported separately, and not included in
national emission totals. Estimates of carbon in products
and international bunker fuel emissions for the United
States are provided in Table 2-4 and Table 2-5.
End-Use Sector Consumption
When analyzing CO2 emissions from fossil fuel
combustion, four end-use sectors were defined: indus-
trial, transportation, residential, and commercial.6 Elec-
tric utilities also emit CO2; however, these emissions oc-
cur as they combust fossil fuels to provide electricity to
one of the four end-use sectors. For the discussion be-
low, electric utility emissions have been distributed to
each end-use sector based upon the sector's share of
national electricity consumption. This method of distrib-
uting emissions assumes that each sector consumes elec-
tricity generated from an equally carbon-intensive mix of
fuels and other energy sources. In reality, sources of elec-
tricity vary widely in carbon intensity (e.g., coal versus
wind power). By giving equal carbon-intensity weight to
each sector's electricity consumption, emissions attrib-
uted to one end-use sector may be somewhat overesti-
mated, while emissions attributed to another end-use sec-
tor may be slightly underestimated. After the end-use
sectors are discussed, emissions from electric utilities are
6 See Glossary (Annex W) for more detailed definitions of the industrial, residential, commercial, and transportation end-use sector, as
well as electric utilities.
Energy 2-7
-------
Table 2-4: Fossil Fuel Carbon in Products (Tg C02 Eq.)*
Sector
1990
1995
1996
1997
* See Carbon Stored in Products from Non-Energy Uses of Fossil Fuels section for additional detail.
Note: Totals may not sum due to independent rounding.
Table 2-5: C02 Emissions from International Bunker Fuels (Tg C02 Eq.)*
Vehicle Mode
1990
1995
1996
1997
* See International Bunker Fuels section for additional detail.
Note: Totals may not sum due to independent rounding.
1998
1998
1999
Industrial
Transportation
Territories
Total
274.4
1.2
0.6
276.2
" 315.8
1.2
1.0
317.9
320.5
1.1
1.5
323.1
335.9
1.2
1.6
338.6
340,6
1.2
1.5
343.4
358.8
1.2
1.7
361.7
1999
Aviation
Marine
Total
46.7
67.3
114.0
51.1
49.9
101.0
52.1
50.1
102.2
55.9
53.9
109.8
55.0
57.8
112.8
61.0
46.4
107.3
addressed separately. Emissions from U.S. territories are
also calculated separately due to a lack of end-use-spe-
cific consumption data. Table 2-6 and Figure 2-10 summa-
rize CO2 emissions from direct fossil fuel combustion and
pro-rated electric utility emissions from electricity con-
sumption by end-use sector.
The electric power industry in the United States is
currently undergoing significant changes. Both Federal
and State government agencies are modifying regulations
to create a competitive market for electricity generation
from what was a market dominated by vertically integrated
and regulated monopolies (i.e., electric utilities). These
changes have led to the growth of nonutility power pro-
ducers, including the sale of generating capacity by elec-
tric utilities to nonutilities.7 As a result, the proportion of
electricity in the United States generated by nonutilities
has grown from about 8 percent in 1990 to 16 percent in
1999. Fuel consumption and emissions by nonutilities
are currently allocated to the industrial end-use sector,
separate from electric utilities, due to data limitations.
Therefore, emissions associated with electricity genera-
tion in Table 2-6 are underestimated and emissions asso-
ciated with direct fuel combustion by the industrial end-
use sector are overestimated by an equal amount.
Figure 2-10
o
2000 1
1600
1200
800
400
0
• From Electricity Consumption
• From Direct Fossil Fuel Combustion
XX
XV
Note: All emissions related to the generation of electricity by
nonutilities are currently allocated to the combustion category
under the industrial sector due to data limitations.
Industrial End-Use Sector
The industrial end-use sector accounted for the
largest share (33 percent) of CO2 emissions from fossil
fuel combustion. On average, 65 percent of these emis-
sions resulted from the direct consumption of fossil fuels
7 In 1999, 50,884 megawatts of electrical generating capacity was sold by electric utilities to nonutilities, or 6.4 percent of total electric
power industry capacity.
2-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 2-6: Fossil Fuel Carbon in Products and C02 Emissions from International Bunker Fuel Combustion (Tg C02 Eq.)
End-Use Sector
1990
1995
1996
1997
1998
1999
.Industrial
Combustion3
; Electricity11
transportation
7 Combustion
Electricity11
Residential
..... Combustion
Electricity11
.Commercial
; Combustion
Electricity11
U.S. Territories
Total
1,636.0
1,023.5
612.6 **~
1,474.4
1,471.8
2.6
930.7
332.1
598.6
760.8
217.3 ^
543.6
33.7
4,835.7
1,709.5
1,101.0
608.5
1,581.8
1,579.4
2.4
988.7
362.3
626.4
797.2
223.9
573.3
44.0
5,121.3
1,766.0
1,140.6
625.4
1,621.2
1,618.8
2.4
1,047.5
390.4
657.0
828.2
232.8
595.4
40.1
5,303.0
1,783.6
1,141.1
642.5
1,631.4
1,628.9
2.5
1,044.2
374.9
669.3
872.9
233.7
639.2
42.8
5,374.9
1,758.8
1,113.3
645.5
1,659.0
1,656.5
2.5
1,040.9
341.0
699.9
880.2
217.4
662.8
47.9
5,386.8
1,783.9
1,155.6
628.3
1,716.4
. 1,714.0
2.4
1,035.8
354.1
681.6
864.0
223.0
641.0
53.0
5,453.1
;.a Includes emissions related to the generation of electricity by nonutility power producers.
: b Does not include emissions related to the consumption of electricity generated by nonutilities—versus regulated electric utilities. All
'"emissions related to the generation of electricity by nonutilities are currently allocated to the combustion category under the industrial sector
t. due to data limitations. . . . .
•: Note: Totals may not sum due to independent rounding. Emissions from fossil fuel combustion by electric utilities are allocated based on
^aggregate national electricity consumption by each end-use sector. .
in order to meet industrial energy demands such as for
steam and process heat. The remaining 35 percent was
associated with their consumption of electricity for uses
such as motors, electric furnaces, ovens, and lighting.8
The industrial end-use sector includes activities
such as manufacturing, construction, mining, and agri-
culture.9 The largest of these activities in terms of energy
consumption is manufacturing, which was estimated in
1994 to have accounted for about 80 percent of industrial
energy consumption (EIA 1997). Manufacturing energy
consumption was dominated by several industries—pe-
troleum products, chemical products, primary metals, pa-
per and products, foods; and stone, clay, and glass prod-
ucts—which combined accounted for about 84 percent
(i.e., roughly two-thirds of the entire industrial end-use
sector in 1994).
In theory, emissions from the industrial end-use
sector should be highly correlated with economic growth
and industrial output; however, certain activities within
the sector, such as heating of industrial buildings and
agricultural energy consumption, are also affected by
weather conditions.10 In addition, structural changes
within the U.S. economy that lead to shifts in industrial
output away from energy intensive manufacturing prod-
ucts to less energy intensive products (e.g., from steel to
computer equipment) also have a significant affect on
industrial emissions.
From 1998 to 1999, total industrial production and
manufacturing output were reported to have increased
by 4.2 and 4.8 percent, respectively (FRB 2000). How-
ever, excluding the fast growing computer, communica-
tion equipment, and semiconductor industries from these
indexes reduces their growth considerably—to 1.2 and
1.5 percent, respectively—and illustrates some of the
structural changes occurring in the U.S. economy (see
Figure 2-11).
8 This fraction only includes emissions from electric utilities, and therefore likely underestimates electricity associated emissions
because it excludes CO2 emissions associated with electricity generated by nonutility power producers. These nonutility power produc-
ers, however, are included in the direct fuel combustion category of the industrial end-use sector. Therefore, because of the inclusion of
nonutilities and the fact that some industrial facilities generate their own electricity without obtaining it from electric utilities, the
fraction of the industrial end-use sector's emissions associated with meeting actual steam and process heat demands is likely overesti-
mated since a portion of that fuel is actually used to generate electricity (e.g., cogeneration).
9 See Glossary (Annex W) for a more detailed definition of the industrial end-use sector.
10 Some commercial customers are large enough to obtain an industrial price for natural gas and/or electricity and are consequently
grouped with the industrial end-use sector in U.S. energy statistics. These misclassifications of large commercial customers likely cause
the industrial end-use sector to appear to be more sensitive to weather conditions.
Energy 2-9
-------
Figure 2-11
Total Index Excluding
Computers,
Communications
Equipment, and
Semiconductors
Paper & Products
=-^:
Foods
Stone, Clay
& Glass
Products
Petroleum
Products
1991
1993
1995
1997
1999
According to current EIA sectoral definitions, the
industrial sector also includes emissions from nonutility
generators (e.g., independent power producers) who pro-
duce electricity for their own use, to sell to large consum-
ers, or to sell on the wholesale electricity market.11 The
number of nonutility generators and the quantity of elec-
tricity they produce has increased significantly as many
States have begun opening their electricity markets to
competition. In future inventories, these nonutility gen-
erators will be removed from the industrial sector and
incorporated into a single electric power sector with elec-
tric utilities.
Despite the growth in industrial output (49 percent)
and the overall U.S. economy (32 percent) from 1990 to
1999, emissions from the industrial end-use sector in-
creased by only 9.0 percent, which is less that all other
end-use sectors in percentage terms. For example, in 1998
emissions decreased by 1.4 percent and then in 1999 in-
creased by the same percentage. The reasons for the dis-
parity between rapid growth in industrial output and stag-
nant growth in industrial emissions are not entirely clear.
It is likely, though, that several factors have influenced
industrial emission trends, including: 1) a mild winter in
1998 and 1999, leading to lower than normal energy con-
sumption in industries affected by the weather; 2) more
rapid growth in output from less energy-intensive indus-
tries relative to traditional manufacturing industries; 3)
improvements in energy efficiency; and 4) a lowering of
the carbon intensity of fossil fuel consumption as indus-
try shifts from its historical reliance on coal and coke to
heavier usage of natural gas. Assessments of industrial
end-use sector trends, however, are complicated by the
growth of nonutility generation and emissions.12
Industry was the largest user of fossil fuels for non-
energy applications. Fossil fuels can be used for produc-
ing products such as fertilizers, plastics, asphalt, or lubri-
cants that can sequester or store carbon for long periods
of time. Asphalt used in-road construction, for example,
stores carbon essentially indefinitely. Similarly, fossil fu-
els used in the manufacture of materials like plastics can
also store carbon, if the material is not burned. The amount
of carbon contained in industrial products made from fos-
sil fuels rose 31 percent between 1990 and 1999, to 361.7
TgC02Eq.13
Transportation End-Use Sector
Transportation was second to the industrial end-
use sector in terms of U.S. CO2 emissions from fossil fuel
combustion, accounting for slightly over 31 percent—
excluding international bunker fuels. Almost all of the
energy consumed in this end-use sector came from pe-
troleum-based products, with nearly two-thirds due to
gasoline consumption in automobiles and other highway
" Nonutility generators also include cogenerators, who produce both useful process heat and electricity. See Glossary (Annex W) for a
more detailed definition.
11 The opening of the electric power industry to competition may have also led to some data collection problems as electric utility
assets are transferred and government reporting requirements are revised. These reporting problems are expected to be corrected,
however, in future inventories.
13 See the Carbon Stored in Products in Non-Energy Uses of Fossil Fuels for a more detailed discussion. Also, see Waste Combustion in
the Waste chapter for a discussion of emissions from the incineration or combustion of fossil fuel-based products.
2-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
vehicles. Other fiiel uses, especially diesel fuel for^the
tracking industry and jet fuel for aircraft, accounted for
the remainder.14
Carbon dioxide emissions from fossil fuel combus-
tion for transportation increased by 16 percent from 1990
to 1999, to 1,716.4 TgCO2Eq. The growthin transporta-
tion end-use sector emissions has been relatively steady,
including a 3.5 percent single year increase in 1999. De-
mand for transportation fuels has been driven by several
factors, including but not limited to: 1) increased activity
in almost all modes of travel; 2) relatively low transporta-
tion fuel prices through 1999; and 3) stagnant vehicle
fuel efficiency.
Since 1990, travel activity in the United States has
grown more rapidly than population, with a 14 percent
increase in vehicle miles traveled per capita and a 9 per-
cent increase in per capita jet fuel consumption by U.S.
commercial air carriers. Motor gasoline and other petro-
leum product prices during the 1990s generally declined,
reaching historic lows in 1998 and only partially rebound-
ing in 1999 (see Figure 2-12). Improvements in the aver-
age fuel efficiency for the U.S. vehicle fleet stagnated in
the 1990s after increasing steadily since 1977 (EIA 2000a).
The average miles per gallon achieved by the fleet actu-
ally decreased by slightly less than one percent in both
1998 and 1999. This trend was due, in part, to the increas-
ing dominance of new motor vehicle sales by less fuel-
efficient light-duty trucks and sport-utility vehicles (see
Figure 2-13).
Table 2-7 below provides a detailed breakdown of
CO2 emissions by fuel category and vehicle type for the
transportation end-use sector. Fifty-seven percent of the
emissions from this end-use sector were the result of the
combustion of motor gasoline in passenger cars and light-
duty trucks. Diesel highway vehicles and jet aircraft were
also significant contributors, accounting for 15 and 13
percent of CO2 emissions from the transportation end-
use sector, respectively.
Figure 2-12
60 -
1972 1975 1978 19811984 1987 1990 1993 1996 1999
Source for gasoline prices: DOE/EIA-0384(99), Annuai
Energy Review 1999, July, 2000, Table 5.22
Source for motor vehicle fuel efficiency: DOT/FHWA,
Highway Statistics Summary to 1995, Highway Statistic
1996,1997,1998,1999.
Figure 2-13
10J
1972 1975 1978 1981 1984 1987 1990 1993 1996 1999
Source: DOT/FHWA, Highway Statistics. Summary to 1995,
Highway Statistics 1996, Highway Statistics 1997,1998,1999.
Residential and Commercial End-Use Sectors
The residential and commercial end-use sectors
accounted for an average 19 and 16 percent, respectively,
of CO2 emissions from fossil fuel combustion. Both end-
use sectors were heavily reliant on electricity for meeting
energy needs, with electricity consumption for lighting,
heating, air conditioning, and operating appliances con-
tributing to about 74 and 66 percent of emissions from
the commercial and residential end-use sectors, respec-
tively.15 The remaining emissions were largely due to the
14 See Glossary (Annex W) for a more detailed definition of the transportation end-use sector.
15 These fractions only include emissions from electric utilities, and therefore likely underestimate electricity associated emissions
because they exclude CO2 emissions associated with electricity generated by nonutility power producers, which are currently allocated
to the direct fuel combustion category under the industrial end-use sector. '
Energy 2-11
-------
Table 2-7: C02 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg C02 Eq.)
Fuel/Vehicle Type
1990
1995
1996
1997
1998
1999
Motor Gasoline
Passenger Cars
Light-Duty Trucks
Other Trucks
Motorcycles
Buses
Construction Equipment
Agricultural Machinery
Boats (Recreational)
Distillate Fuel Oil (Diesel)
Passenger Cars
Light-Duty Trucks
Other Trucks
Buses
Construction Equipment
Agricultural Machinery
Boats (Freight)
Locomotives
Marine Bunkers
Jet Fuel
General Aviation
Commercial Air Carriers
Military Vehicles
Aviation Bunkers
Other3
Aviation Gasoline
General Aviation
Residual Fuel Oil
Boats (Freight)"
Marine Bunkersb
Natural Gas
Passenger Cars
Light-Duty Trucks
Buses
Pipeline
LPG
Light-Duty Trucks
Other Trucks
Buses
Electricity
Buses
Locomotives
Pipeline
Lubricants
Total (Including Bunkers)0
Total (Excluding Bunkers)0
955.5
612.8
274.1
41.4
1.6
2.0
2.2
4.4
16.9
277.4
7.1
9.0
164.1
7.9
10.5
23.1
18.0
26.3
11.4
220.4
6.3
118.2
36.1 -
46.7
13.1
3.1
3.1
80.4
24.5
55.8
36.0
+
+
+
36.0
1.3
+
0.5
0.8
2.6
+
2.1
0.5
11.7
1,588.4
1,474.4
1,023.0
634.3
314.2
40.0
1.7
3.0
2.4
7.9
19.5
312.2
7.6
11.2
195.4
9.9
10.5
23.0
16.1
29.5
9.1
219.9
5.3
121.4
21.6
51.1
20.5
2.7
2.7
72.1
31.3
40.8
38.3
0.1
+
0.1
38.2
1.0
+
0.5
0.5
2.4
+
1.9
0.5
11.2
1,682.8
1,581.8
1,041.4
646.6
320.4
40.7
1.7
2.1
2.4
7.8
19.7
329.0
7.6
13.1
207.0
8.6
10.9
23.8
18.4
31.5
8.2
229.8
5.8
124.9
20.1
52.1
26.8
2.6
2.6
67.5
25.7
41.8
38.9
+
+
0.1
38.8
0.9
+
0.4
0.5
2.4
+
1.9
0.5
10.9
1,723.4
1,621.2
1,050.6
652.3
323.1
40.5
1.7
2.2
2.5
8.2
20.1
342.8
7.9
14.2
216.1
9.2
11.2
24.5
18.3
32.4
9.0
232.1
6.1
129.4
17.8
55.9
23.0
2.7
2.7
56.7
11.8
44.9
41.5
+
+
0.2
41.3
0.8
+
0.4
0.4
2.5
+
1.9
0.6
11.5
1,741.2
1,631.4
1,074.0
666.8
342.4
32.1
1.7
0.8
2.0
7.6
20.5
353.5
7.6
14.4
225.5
10.7
10.8
23.7
17.8
31.6
11.4,
235.6
. 7.7
131.4
18.4
55.0
23.0
2.4
2.4
55.9
9.5
46.4
34.9
+
. . + .
0.2
34.7
0.9
+
0.3
0.5
2.5
+-
2.0
0.5
12.0
1,771.7
1,659.0
1,096.6
680.9
349.6
32.8
1.8
0.9
2.0
7.8
21.0
367.1
8.0
15.1
236.5
11,2
11.3
24.9
18.7
33.2
8.2
242.9
8.4
137.3
17.1
61.0
19.2
2.7
2.7
64.1
25.9
38.2
34.8
+
+
0.2
34.6
1.0
+
0.4
0.6
2.4
+ •.
1.9
0.5
12.1
1,823.7
1,716.4
Note: Totals may not sum due to independent rounding.
* Including but not limited to fuel blended with heating oils and fuel used for chartered aircraft flights.
b Ructuations in emission estimates from the combustion of residual fuel oil are currently unexplained, but may be related to data collection
problems.
c Official estimates exclude emissions from the combustion of both aviation and marine international bunker fuels; however, estimates
including international bunker fuel-related emissions are presented for informational purposes.
+ Does not exceed 0.05 Tg of C02 Eq.
2-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Figure 2-14
Figure 2-15
120 -,
g 110 .
II
"ra
E 100 -
Normal
(4,576 Heating Degree Days)
-- - -f -r - - -9- - - -
80 -<
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
Note: Excludes Alaska and Hawaii
Source: DOE/EIA-0384(99), Annual Energy Review 1999, July,
2000, Table 1.7 and 1.8.
Normal
(1,193 Cooling Degree Days)
120 n
§110
| 100
o
z
90 -
80 J
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
Note: Excludes Alaska and Hawaii
Source: DOE/EIA-0384(99), Annual Energy Review 1999,
July 2000, Table 1.7 and 1.8.
direct consumption of natural gas and petroleum prod-
ucts, primarily for heating and cooking needs. Coal con-
sumption was a minor component of energy use in both
these end-use sectors.
Emissions from residences and commercial build-
ings generally increased throughout the 1990s, and, un-
like in other end-use sectors, emissions in these sectors
did not decline during the economic downturn in 1991
(see Table 2-6). This difference exists because short-term
fluctuations in energy consumption in these sectors are
affected proportionately more by the weather than by
prevailing economic conditions. In the long-term, both
end-use sectors are also affected by population growth,
regional migration trends, and changes in housing and
building attributes (e.g., size and insulation).
In 1999, winter conditions in the United States were
warmer than normal (i.e., heating degree days were 7 per-
cent below normal), although not nearly as warm as in
1998 (see Figure 2-14). Due, in part, to this slight cooling
relative to the previous year, emissions from natural gas
consumption in residences and commercial establish-
ments increased by 3 percent and 2 percent, respectively.
In 1999, electricity sales by electric utilities to the
residential and commercial end-use sectors increased by
1.0 and 0.2 percent, respectively, as compared to the pre-
vious year. Cooler summer conditions in 1999 relative to
1998, although still warmer than normal, helped to moder-
ate growth in air conditioning driven electricity consump-
tion (see Figure 2-15). Historically, the change in energy
demand associated with a change in heating degree days
has been greater than an equivalent change in cooling
degree days. These temperature trends—along with other
trends such as overall population growth—led to a 0.5
and 1.8 percent decrease in residential and commercial
end-use sector emissions from 1998 to 1999, respectively.
Electric Utilities
The United States relies on electricity to meet a
significant portion of its energy requirements. Electricity
was consumed primarily in the residential, commercial,
and industrial end-use sectors for uses such as lighting,
heating, electric motors, appliances, electronics, and air
conditioning (see Figure 2-16).
It is important to note that the electric utility sector
includes only regulated utilities. According to current EIA
sectoral definitions, nonutility generators of electricity
(e.g., independent power producers, qualifying
cogenerators, and other small power producers) are in-
cluded in the industrial end-use sector. These nonutility
16 Degree days are relative measurements of outdoor air temperature. Heating degree days are deviations of the mean daily temperature
below 65° F. Excludes Alaska and Hawaii. Normals are based on data from 1961 through 1990.
17 Degree days are relative measurements of outdoor air temperature. Cooling degree days are deviations of the mean daily temperature
above 65° F. Excludes Alaska and Hawaii. Normals are based on data from 1961 through 1990.
Energy 2-13
-------
Figure 2-16
Figure 2-17
"'' t|f|^iTnTR^
Industrial
Residential >
Commercial
1,2001
. i,ooa
800
600
400*
1972 1975 1978 1981 1984 1987 1990 1993 19961999
Noto: The transportation end-use sector consumes minor
quantise of oloctricty.
generators produce electricity for their own use, to sell to
large consumers, or to sell on the wholesale electricity
market (e.g., to utilities for distribution and resale to retail
customers). The number of nonutility generators and quan-
tity of electricity they produce has increased significantly
as many States have begun opening their electricity mar-
kets for generation to competition (see Figure 2-17).
The Energy Information Agency has estimated
emissions from the entire electric power industry, includ-
ing regulated utilities and nonutilities was roughly 41
percent of U.S. CO2 emissions from fossil fuel combus-
tion versus 36 percent from utilities alone (EIA 2000c).
As U.S. energy statistics are revised to account for the
changes occurring in the electric power industry, these
nonutility generators will be removed from the industrial
end-use sector and incorporated into a single sector with
electric utilities.18
In 1999, CO2 emissions from electric utilities de-
creased by 2.9 percent relative to the previous year de-
spite increased electricity consumption and the robust
growth in the U.S. economy. A large part of this decrease
can be attributed to the sale of approximately 7 percent of
electric utility generating capacity to nonutility power
producers in 1999.19 In addition, the summer of 1999 for
the United States, although slightly warmer than usual,
was cooler than the pervious year's summer, with cooling
3,000 -
2,500 -
2,000 -
-1,500 -
1,000 -
500-
o-
Electric
Utilities
Nonutilities
1990 199119921993 1994199519961997 19981999
Source: EIA (2000c)
degree days down by 13 percent (see Figure 2-15). A
third factor leading to the decline in utility emissions was
the increased output from nuclear plants, which offset
the need for additional fossil fuel consumption. Net gen-
eration of electricity by nuclear plants increased by 8
percent from 1998 to 1999, reaching record levels along
with plant capacity factors (i.e., utilization).20
To generate the majority of their electricity, utilities
combusted fossil fuels, especially coal. The combustion
of fossil fuels accounts for the majority (68 percent) of
the electricity generated by utilities in the United States
(EIA 2000a). Electric utilities rely on more carbon inten-
sive coal for a majority of thek primary energy; however,
they also employ many low or near zero carbon emitting
technologies such as nuclear, hydro,, and wind.
Electric utilities were the dominant consumer of coal
in the United States, accounting for 85 percent in 1999.
Consequently, changes in electricity demand have a sig-
nificant impact on coal consumption and associated U.S.
CO2 emissions. Coal consumption by utilities in 1999 de-
creased by 2 percent (343 Tbtu) in 1999, primarily due to
the sale of generating capacity to nonutility power pro-
ducers. This decrease, therefore, was offset by an 11 per-
cent (314 Tbtu) increase in coal consumption by in in-
dustrial end-use sector (i.e., only the sector in which the
emissions were accounted for actually changed).
18 It is important to note, though, that much of the electricity generated by nonutility power producers is sold to utilities for resale to
retail customers, and therefore is included in electric utility sales statistics.
" Gross generation of electricity by nonutilities increased by about 35 percent from 1998 to 199?.
20 Electricity output from hydroelectric dams was relatively constant, decreasing by 0.6 percent between 1998 and 1999.
2-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Box 2-2: Sectoral Carbon Intensity Trends Related to Fossil Fuel and Overall Energy Consumption
ftLi- Fossil fuels are the predominant source of energy in the United States, arid carbon dioxide (C02) is emitted as a product from their "
|£ complete combustion. Useful energy, however, can be generated from many other sources that do not emit C02 in the energy
if conversion process. In the United States, useful energy is also produced from renewable (i.e., hydropower, biofuels, geothermal, solar,
gand wind) and nuclear sources.21 ; :
|-L: Energy-related C02 emissions can be reduced by not only lowering total energy consumption (e.g., through conservation
|,measufes) but also by lowering the carbon intensity of the energy sourcesemployed (e.g., fuel switching from coalto natural gas).
rThe amount of carbon emitted—in the formof C02-^from the combustion of fossil fuels is dependent upon the carbon content of
Theluel and the fraction of that carbon that is oxidized.22 Fossil fuels vary in their average carbon content, ranging from about 53 Tg
'_C02 Eq./EJ for natural gas to upwards of 95 Tg C02 Eq./EJ for coal and petroleum coke.23 In general, the carbon intensity per unit of
^energy of fossil fuels is the highest for coal products, followed by petroleum arid then natural gas. Other sources of energy, however,
|:rhay be directly or indirectly carbon neutral (i.e., 0 tg C02 Eq./EJ). Energy'generated from nuclear and many renewable sources do
l-not result in direct emissions of CD2. Biofuels such as wood and ethanol are also considered to be carbon neutral, as the C02 emitted
Muring their combustion is assumed to be offset by the carbon sequestered in the growth of new biomass.24 The overall carbon
If Intensity of the U.S. economy is thus dependent upon the quantity and combination of fuels and other energy sources employed to
rneetdemand. ; '. •;.',.-/.. •' .;'.;,-.-,. :•,; : ..'-,:'.,'.' .,.•::,/ -:'", ..:
~ table 2-8 provides a time series of the carbon intensity for each sector of the U.S. economy, the time series incorporates only the
lenergy consumed from the direct combustion of fossil fuels in each sector. For example, the carbon intensity for the residential sector
tjoes not include the energy from or emissions refated to the consumption of electricity for lighting or wood for heat. Looking only at
finis direct consumption of fossil fuels, the residential sector exhibited the lowest carbon intensity, which was related to the large
^percentage of energy derived from natural gas for heating. The carbon intensity of the commercial sector was greater than the
presidential sector for the period from 1990 to 1996, but then declined to a comparable level as commercial businesses shifted away
Jtom petroleum to natural gas. The industrial sector was more dependent on petroleum and coal than either the residential or
gcommercial sectors, and thus had higher carbon intensities over this period. The carbon intensity of the transportation sector was
closely related to the carbon content of petroleum products (e.g., motor gasoline and jet fuel, both around 67 Tg C02 Eq./EJ), which
j}ivere the primary sources of energy. Lastly, the electric utility sector had the highest carbon intensity due to its heavy reliance on coal '
5 for generating electricity.
Table 2-8: Carbon Intensity from Direct Fossil Fuel Combustion by Sector (Tg C02 Eq./EJ)
Sector
1990
1995
1996
1997
1998
1999
^Residential3
Commercial3
JndustriaP
iTransportationa
reecfric Utilities13
53.8
55.7
65.1
67.3
82.0
[AH Sectors0
53.7
54.2
64.2
67.1
82.1
53.6
54.2
63.9
67.0
83.1
53.7
54.0
64.0
67.0
82.9
53.6
53.8
64.6
67.1
82.3
53.6
53.9
65.4
67.1
82.5
69.4
68.9
69.0
69,1
69.5
69.5
pTDoes not include electricity or renewable energy consumption.
C^Does not include electricity produce^ using nuclear or renewable energy.
P-Does not include nuclear or renewable energy consumption.
I Note: Excludes non-energy fuel use emissions and consumption. Exajou'le (EJ) = 1018 joules = 0.9479 QBtu.
21 Small quantities of CO2, however, are released from some geologic formations tapped for geothermal energy. These emissions are
included with fossil fuel combustion emissions from the electric utilities. Carbon dioxide emissions may also be generated from upstream
activities (e.g., manufacture of the equipment) associated with fossil fuel and renewable energy activities, but are not accounted for here.
22 Generally, 97 to 99.5 percent of the carbon in fossil fuel is oxidized to CO2 with most carbon combustion technologies used in the
United States.
23 One exajoule (EJ) is equal to 10IS joules or 0.9478 QBtu.
24 This statement assumes that there is no net loss of biomass-based carbon associated with the land use practices used to produce these
biomass fuels.
Energy 2-15
-------
In contrast to Table 2-8, Table 2-9 presents carbon intensity values that incorporate energy consumed from all sources (i.e., fossil
fuels, renewables, and nuclear). In addition, the emissions related to the generation of electricity have been attributed to both electric
utilities and the end-use sector in which that electricity was eventually consumed.25 This Table, therefore, provides a more complete
picture of the actual carbon intensity of each end-use sector per unit of energy consumed. The transportation end-use sector in Table
2-9 emerges as the most carbon intensive when all sources of energy are included, due to its almost complete reliance on petroleum
products and relatively minor amount of biomass based fuels such as ethanol. The "other end-use sectors" (i.e., residential,
commercial, and industrial) use significant quantities of biofuete such as wood, thereby lowering the overall carbon intensity. The
carbon intensity of electric utilities differs greatly from the scenario in Table 2-8, where only the energy consumed from the direct
combustion of fossil fuels was included. This difference is due almost entirely to the inclusion of electricity generation from nuclear and
hydropower sources, which do not emit carbon dioxide.
By comparing the values in Table 2-8 and Table 2-9, a couple of observations can be made. The usage of renewable and nuclear
energy sources has resulted in a significantly lower carbon intensity of the U.S. economy. However, over the ten year period of 1990
through 1999, the carbon intensity of U.S. fossil fuel consumption has been fairly constant, as the proportion of renewable and
nuclear energy technologies has not changed significantly.
Although the carbon intensity of total energy consumption has remained fairly constant, per capita energy consumption has
increased leading to a greater energy-related C02 emissions per person in the United States since 1990 (see Figure 2-18). Because of
the strong growth in the U.S. economy, though, energy consumption and energy-related C02 emissions per dollar of gross domestic
product (GDP) declined in the 1990s.
Figure 2-19 and Table 2-10 present the detailed C02 emission trends underlying the carbon intensity differences and changes
described in Table 2-8. In Figure 2-19, changes overtime in both overall end-use sector-related emissions and electricity-related
emissions for each year since 1990 are highlighted. In Table 2-10 changes in emissions since 1990 are presented by sector and fuel
type to provide a more detailed accounting.
Figure 2-18
Figure 2-19
Energy Consumption/
Capita
1991
1993
1995
CO2/ $GDP
1997 1999
Source: BEA (2000), Census (2000), Emission and energy
consumption estimate, in this report.
•10° Residential Industrial
Commercial Transportation
Dark shaded columns relate to changes in emissions from
electricity consumption. Lightly shaded columns relate to
changes in emissions from both electricity and direct fossil
fuel combustion.
M In other words, the emissions from the generation of electricity are intentionally double counted by attributing them both to utilities
and the end-use sector in which electricity consumption occurred.
2-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 2-9: Carbon Intensity from Energy Consumption by Sector (Tg C02 Eq./EJ)
Sector
1990
1995
1996
1997
1998
1999
Transportation3
Other End-Use Sectorsa>b
Electric Utilities0
All Sectors'1
67.o rrr"-:--.*:
54.5 :-i:;
56.o . 2: ,
58.6 ^ '
66.8
53.1
54.4
57.5
66.8
53.2
54.8
57.6
66.7
54.0
56.3
58.2
66.8
54.1
56.3
58.4
66.8
53.2
55.2
57.9
.:a Includes electricity (from fossil fuel, nuclear, and renewable sources) and direct renewable energy consumption.
b Other End-Use Sectors include the residential, commercial, and industrial sectors.
0 Includes electricity generation from nuclear and renewable sources.
-------
petroleum, gas), and secondary fuel category (e.g., motor
gasoline, distillate fuel oil, etc.), estimates of total U.S.
fossil fuel consumption for a particular year were made.
The United States does not include territories in its na-
tional energy statistics; therefore, fuel consumption data
for territories was collected separately.26
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 carbon in
each fuel. This total carbon estimate defines the maxi-
mum amount of carbon that could potentially be released
to the atmosphere if all of the carbon in each fuel were
converted to CO2. The carbon content coefficients used
by the United States are presented in Annex A.
3. Subtract the amount of carbon stored in prod-
ucts. Non-energy uses of fossil fuels can result in storage
of some or all of die carbon contained in the fuel for some
period of time, depending on the end-use. For example,
asphalt made from petroleum can sequester up to 100 per-
cent of the carbon for extended periods of time, while
other fossil fuel products, such as lubricants or plastics,
lose or emit some carbon when they are used and/or burned
as waste. Aggregate U.S. energy statistics include con-
sumption of fossil fuels for non-energy uses; therefore,
the portion of carbon that remains in products after they
are manufactured was subtracted from potential carbon
emission estimates.27 The amount of carbon remaining in
products was based on the best available data on the end-
uses and fossil fuel products. These non-energy uses
occurred in the industrial and transportation sectors and
U.S. territories. Emission of CO2 associated with the dis-
posal of these fossil fuel-based products are not accounted
for here, but are instead accounted for under the Waste
Combustion section in the Waste chapter.
4. Adjust for carbon that does not oxidize during
combustion. Because combustion processes are not 100
percent efficient, some of the carbon contained in fuels is
not emitted to the atmosphere. Rather, it remains behind
as soot and ash. The estimated amount of carbon not
oxidized due to inefficiencies during the combustion pro-
cess was assumed to be 1 percent for petroleum and coal
and 0.5 percent for natural gas (see Annex A).
5. Subtract emissions from international bunker
fuels. According to the IPCC guidelines (IPCC/UNEP/
OECD/EEA1997) emissions from international transport
activities, or bunker fuels, should not be included in na-
tional totals. Because U.S. energy consumption statis-
tics include these bunker fueta—distillate fuel oil, residual
fuel oil, and jet fuel—as part of consumption by the trans-
portation end-use sector, emissions from international
transport activities were calculated separately and sub-
tracted from emission estimates for the transportation end-
use sector. The calculations for emissions from bunker
fuels follow the same procedures used for emissions from
consumption of all fossil fuels (i.e., estimation of con-
sumption, determination of carbon content, and adjust-
ment for the fraction of carbon not oxidized).28
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,29 a more detailed accounting of carbon dioxide
emissions is provided. For fuel types other than jet fuel,
fuel consumption data by vehicle type and transporta-
tion mode were used to allocate emissions by fuel type
calculated for the transportation end-use sector. Specific
data by vehicle type were not available for 1999; there-
fore, the 1998 percentage allocations were applied to 1999
fuel consumption data in order to estimate emissions in
1999. Military vehicle jet fuel consumption was provided
by the Defense Energy Support Center, under Depart-
ment of Defense's (DoD) Defense Logistics Agency and
the Office of the Undersecretary of Defense (Environ-
mental Security). The difference between total U.S. jet
fuel consumption (as reported by DOE/EIA) and civilian
air carrier consumption for both domestic and interna-
tional flights (as reported by DOT/BTS and BEA) plus
26 Fuel consumption by U.S. territories (i.e. American Samoa, Guam, Puerto Rico, U.S. Virgin Islands, Wake Island, and other U.S.
Pacific Islands) is included in this report and contributed emissions»of 53 Tg of CO2 Eq. in 1999.
27 See Carbon Stored in Products from Non-Energy Uses of Fossil Fuels section in this chapter for a more detailed discussion.
28 See International Bunker Fuels section in this chapter for a more detailed discussion.
29 Electric utilities are not considered a final end-use sector, because they consume energy solely to provide electricity to the other
sectors.
2-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
military jet fuel consumption is reported as "other" under
the jet fuel category in Table 2-7, and includes such fuel
uses as blending with healing oils and fuel used for char-
tered aircraft flights.
Data Sources
Data on fuel consumption for the United States
and its territories, and carbon content of fuels were ob-
tained directly from the Energy Information Administra-
tion (EIA) of the U.S. Department of Energy (DOE). Fuel
consumption data were obtained primarily from the An-
nual Energy Review (EIA 2000a) and various EIA data-
bases. Data on military jet fuel use was supplied by the
Office of the Under Secretary of Defense (Environmental
Security) and the Defense Energy Support Center (De-
fense Logistics Agency) of the U.S. Department of De-
fense (DoD). Estimates of international bunker fuel emis-
sions are discussed in the section entitled International
Bunker Fuels. Estimates of carbon stored in products are
discussed in the section entitled Carbon Stored in Prod-
ucts from Nonfuel Uses of Fossil Fuels.
IPCC (EPCC/UNEP/OECD/IEA1997) provided frac-
tion oxidized values for petroleum and natural gas. Bechtel
(1993) provided the fraction oxidation values for coal.
Vehicle type fuel consumption data for the allocation of
transportation end-use sector emissions were primarily
taken from the Transportation Energy Databook pre-
pared by the Center for Transportation Analysis at Oak
Ridge National Laboratory (DOE 1993,1994,1995,1996,
1997,1998,1999). Specific data on military fuel consump-
tion were taken from DESC (2000). Densities for each mili-
tary jet fuel type were obtained from the Air Force (1998).
Carbon intensity estimates were developed using
nuclear and renewable energy data from EIA (2000a) and
fossil fuel consumption data as discussed above and pre-
sented in Annex A.
For consistency of reporting, the IPCC has recom-
mended that national inventories report energy data—
and emissions from energy—using the International En-
ergy Agency (TEA) 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.30
It is also important to note that U.S. fossil fuel en-
ergy statistics are generally presented using gross calo-
rific values (GCV) (i.e., higher heating values). Fuel con-
sumption activity data presented here have not been ad-
justed to correspond to international standard, which are
to report energy statistics in terms of net calorific values
(NCV) (i.e., lower heating values).31
Uncertainly
For estimates of CO2 from fossil fuel combustion,
the amount of CO2 emitted, in principle is directly related
to the amount of fuel consumed, the fraction of the fuel
that is oxidized, and the carbon content of the fuel. There-
fore, a careful accounting of fossil fuel consumption by
fuel type, average carbon contents of fossil fuels con-
sumed, and production of fossil fuel-based products with
long-term carbon storage should yield an accurate esti-
mate of CO2 emissions.
There are uncertainties, however, in the consump-
tion data, carbon content of fuels and products, and car-
bon oxidation efficiencies. For example, given the same
primary fuel type (e.g., petroleum), the amount of carbon
contained in the fuel per unit of useful energy can vary.
Although statistics of total fossil fuel and other
energy consumption are considered to be relatively ac-
curate, the allocation of this consumption to individual
end-use sectors (i.e., residential, commercial, industrial,
and transportation) are considerably more uncertain. For
example, for some fuels the sectoral allocations are based
30 See IPCC Reference Approach for estimating CO2 emissions from fossil fuel combustion in Annex R for a comparison of U.S.
estimates using top-down and bottom-up approaches.
31 A crude convention to convert between gross and net calorific values is to reduce the heat content of solid and liquid fossil fuels by
5 percent and gaseous fuels by 10 percent to account for the water content of the fuels. Biomass-based fuels in U.S. energy statistics are
generally presented using net calorific values.
Energy 2-19
-------
on price rates (i.e., tariffs). However, commercial estab-
lishment may be able to negotiate an industrial rate or a
small industrial establishment may end up paying an in-
dustrial rate, leading to a misallocation of emissions. Also,
the deregulation of the natural gas industry and the more
recent deregulation of the electric power industry have
likely led to problems in collecting accurate energy sta-
tistics as firms in these industries have undergone sig-
nificant restructuring.
Non-energy uses of the fuel can also create situa-
tions where the carbon is not emitted to the atmosphere
(e.g., plastics, asphalt, etc.) or is emitted at a delayed rate.
The proportions of fuels used in these non-energy pro-
duction processes that result in the sequestration of car-
bon have been assumed. Additionally, inefficiencies in
the combustion process, which can result in ash or soot
remaining unoxidized for long periods, were also assumed.
These factors all contribute to the uncertainty in the CO2
estimates. More detailed discussions on the uncertainties
associated with Carbon Stored in Products from Non-En-
ergy Uses of Fossil Fuels and with International Bunker
Fuels are provided under those sections in this chapter.
Other sources of uncertainty are fuel consumption
by U.S. territories. The United States does not collect
energy statistics for its territories at the same level of
detail as for the fifty States and the District of Columbia.
Therefore estimating both emissions and bunker fuel con-
sumption by these territories is difficult.
For Table 2-7, uncertainties also exist as to the data
used to allocate CO2 emissions from the transportation
end-use sector to individual vehicle types and transport
modes. In many cases, bottom up estimates of fuel con-
sumption by vehicle type do not match aggregate fuel-
type estimates from EIA. Further research is planned to
better allocate detailed transportation end-use sector
emissions. In particular, fuel consumption data for marine
vehicles are highly uncertain, as shown by the large fluc-
tuations in emissions.
For the United States, however, these uncertainties
impact on overall CO2 emission estimates are believed to
be relatively small. For the United States, CO2 emission
estimates from fossil fuel combustion are considered ac-
curate within several percent. See, for example, Marland
and Pippin (1990).
Carbon Stored in Products from
Non-Energy Uses of Fossil Fuels
Besides being combusted for energy, fossil fuels
are also consumed for non-energy end uses. The types
of fuels used for non-energy uses are listed in Table 2-11.
The fuels are used in the industrial and transportation
end-use sectors and are quite diverse, including natural
gas, asphalt, a viscous liquid mixture of heavy crude oil
distillates, and coking coal. The non-energy fuel uses are
equally diverse, and include application as solvents, re-
duction agents in metals production, lubricants, and
waxes, or as raw materials in the manufacture of plastics,
rubber, synthetic fibers, and fertilizers.
Carbon dioxide emissions arise from non-energy
uses via multiple pathways. Emissions may occur directly
from the fuel's consumption, as is the case with coking
coal used in iron blast furnaces. Emissions may also oc-
cur during the manufacture of a product, as is the case in
producing plastics or rubber from feedstocks. Addition-
ally, in the case of solvents or lubricants, for example,
emissions may occur during the (fuel-derived) product's
lifetime. Overall, more than 75 percent of the total carbon
consumed for non-energy end uses is stored in prod-
ucts, and not released to the atmosphere. However, some
of the products release CO2 at the end of their commercial
life when they are disposed. These emissions are cov-
ered in the Waste chapter under Waste Combustion.
In 1999, fossil fuel consumption for non-energy
uses constituted 8 percent (6,886 TBtu) of overall fossil
fuel consumption, an increase from 1990, when it ac-
counted for 7 percent of total consumption. In 1999, the
carbon in non-energy fuel consumption was approxi-
mately 478 Tg CO2 Eq., an increase of 34 percent since
1990. Nearly 362 Tg CO2 Eq. of this carbon was stored,
while the remaining 117 Tg CO2 Eq. was emitted. Since
1990, the proportion of carbon emitted has grown slightly
from 23 percent to 24 percent of total non-energy con-
sumption. Table 2-12 shows the fate of the non-energy
fossil fuel carbon for 1990 and 1995 through 1999.
2-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 2-11:1999 Non-Energy Fossil Fuel Consumption, Storage, and Emissions (Tg C02 Eq. unless otherwise noted)
Sector/Fuel Type
Consumption (TBlu) Carbon Content Storage Factor (%) Carbon Stored Emissions
Industry
Industrial Coking Coal
Natural Gas to Chemical Plants
Nitrogenous Fertilizers
Other Uses
Asphalt & Road Oil
LPG
;.. Lubricants :
:• PentanesPlus
:'.. Petrochemical Feedstocks :
Naphtha (<401 deg. F)
Other- Oil (>401deg.F)
Still Gas
Petroleum Coke
Special Naphtha
Distillate Fuel Oil
Residual Fuel
Waxes
Miscellaneous Products
Transportation
Lubricants
U.S. Territories
Lubricants
Other Petroleum (Misc. Prod.)
Total
6,476.86
24.48
754.32
381.72
372.60
1,324.41
1,807.12
192.80
331.68
1,313.22
502.08
811.14
"-. -
376.80
145.40
6.99
50.30
37.44
111.91
182.10
182.10
227.42
1.39
226.03
6,886.38
448.04
2.29
40.02
20.25
19.77
100.13
111.82.
14.31
22.18
92.73
33.39
59.34
-
38.48
10.59
0.51
3.96
2.72
8.28
13.51
13.51
16.68
0.10
16.58
478.23
_
0.75
.
.
0.91
1.00
0.91
0.09
0.91
-
0.91
0.91
0.80
0.50
-
0.50
0.50
1.00
1.00
.
0.09
.
0.09
0.10
-
358.8
1.7
17.9
'
17.9
100.1
101.2
1.3
20.1
83.9
30.2
53.7
-
19.2
.
0.3
2.0
2.7
8.3
1.2
1.2
1.7
+ •
1.7
361.7
89.2
0.6
22.1
20.3
1.9
•
10.6
13.0
2.1
8.8
3.2
5.6
,
19.2
10.6
0.3
2.0
_
.
12.3
12.3
15.0
0.1
14.9
116.5
;: +Less than 0.05 Tg C02Eq.
f - Not applicable.
i Jote: Totals may not sum due to independent rounding.
Table 2-12: Storage and Emissions from Non-Energy Fossil Fuel Consumption (Tg C02 Eq.)
Variable
1990
1995
1996
1997
1998
1999
•• Potential Emissions
Carbon Stored
Emissions
357.6 ,
276.2
81.4 ^
406.8
317.9
88.9
417.4
323.1
94.3
434.5
338.6
95.9
450.5
343.4
107.1
478.2
361.7
116.5
Methodology
The first step in estimating carbon stored in prod-
ucts was to determine the aggregate quantity of fossil
fuels diverted to feedstock uses from energy-related com-
bustion uses. The carbon content of these feedstock fu-
els is equivalent to potential emissions, or the product of
consumption and the fuel-specific carbon content val-
ues (see Annex A).
Next, the amount of carbon stored was estimated
by multiplying the potential emissions by a storage fac-
tor, which were calculated using U.S. data on carbon flows.
For asphalt and road oil, petrochemical feedstocks, liquid
petroleum gases (LPG), pentanes plus, and natural gas
for other uses, carbon storage factors were calculated as
the ratio of (a) the carbon stored by the fuel's non-energy
products to (b) the total carbon content of the fuel con-
sumed. A lifecycle approach was used in the develop-
ment of these storage factors in order to account for losses
in the production process—from raw material acquisition
through manufacturing and processing—and during use.
Details of these calculations are shown in Annex B. Be-
cause losses associated with waste management are
handled separately in the Waste chapter, the storage fac-
tors do not account for losses at the disposal end of the
Energy 2-21
-------
life cycle. For the other fuel types, the storage factors
were taken directly from Marland and Rotty (1984).
Lastly, emissions were estimated by subtracting the
carbon stored from the potential emissions.
Data Sources
Non-energy fuel consumption and carbon content
data were supplied by the EIA (2000). Where storage fac-
tors were calculated specifically for the United States,
data was obtained on fuel products such as asphalt, plas-
tics, synthetic rubber, synthetic fibers, pesticides, and
solvents. Data was taken from a variety of industry
sources, government reports, and expert communications.
Sources include EPA compilations of air emission factors
(EPA 1995, EPA 2000c), the National Asphalt Pavement
Association (Connolly 2000), the Emissions Inventory
Improvement Program (EIIP 1999), the U.S. Census Bu-
reau (1999), the American Plastics Council (APC 2000),
the International Institute of Synthetic Rubber Products
(IISRP 2000), the Fiber Economics Bureau (FEB 2000),
and the Chemical Manufacturer's Handbook (CMA1999).
For the other fuel types, storage factors were taken from
Marland and Rotty (1984). Specific data sources are listed
in full detail in Annex B.
Uncertainty
The fuel consumption data and the carbon content
values employed here were taken from the same refer-
ences as the data used for estimating overall CO2 emis-
sions from fossil fuel combustion. Given that the uncer-
tainty in these data is expected to be small, the uncer-
tainty of the estimate for the potential carbon emissions
is also expected to be small. However, there is a large
degree of uncertainty in the storage factors employed,
depending upon the fuel type. For each of the calculated
storage factors, the uncertainty is discussed in detail in
Annex B. Generally, uncertainty arises from assumptions
made to link fuel types with their derivative products and
in determining the fuel products' carbon contents and
emission or storage fates. The storage factors from
Marland and Rotty (1984) are also highly uncertain.
Stationary Combustion
(excluding C02)
Stationary combustion encompasses all fuel com-
bustion activities except those related to transportation
(i.e., mobile combustion). Other than carbon dioxide (CO2),
which was addressed in the previous section, gases from
stationary combustion include the greenhouse gases
methane (CH4) and nitrous oxide (N2O) and the criteria
pollutants nitrogen oxides (NOX), carbon monoxide (CO),
and non-methane volatile organic compounds
(NMVOCs).32 Emissions of these gases from stationary
combustion sources depend upon fuel characteristics,
technology type, usage of pollution control equipment,
and ambient environmental conditions. Emissions also
vary with the size and vintage of the combustion tech-
nology as well as maintenance and operational practices.
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. Car-
bon monoxide emissions from stationary combustion are
generally a function of the efficiency of combustion and
the use of emission controls; they are highest when less
oxygen is present in the air-fuel mixture than is necessary
for complete combustion. These conditions are most likely
to occur during start-up and shut-down and during fuel
switching (e.g., the switching of coal grades at a coal-
burning electric utility plant). Methane and NMVOC emis-
sions from stationary combustion are primarily a func-
tion of the CH4 content of the fuel, combustion efficiency,
and post-combustion controls.
Emissions of CH4 increased slightly from 1990 to
1996, but fell to just below the 1990 level in 1999 to 8.1 Tg
CO2 Eq. (386 Gg). This decrease in emissions was prima-
rily due to lower wood consumption in the residential
sector. Nitrous oxide emissions rose 15 percent since 1990
to 15.7 Tg CO2 Eq. (51 Gg) in 1999. The largest source of
N2O emissions was coal combustion by electric utilities,
which alone accounted for 53 percent of total N2O emis-
32 Sulfur dioxide (SO2) emissions from stationary combustion are addressed in Annex M.
2-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
sions from stationary combustion in 1999. Overall, though,
stationary combustion is a small source of CH4 and N2O
in the United States.
In contrast, stationary combustion was a signifi-
cant source of NOX emissions, but a smaller source of CO
and NMVOCs. In 1999, emissions of NOX from stationary
combustion represented 39 percent of national NOX emis-
sions, while CO and NMVOC emissions from stationary
combustion contributed approximately 6 and 5 percent,
respectively, to the national totals. From 1990 to 1999,
emissions of NOX, CO, and NMVOCs decreased by 8,4,
and 10 percent, respectively.
The decrease in NOX emissions from 1990 to 1999
are mainly due to decreased emissions from electric utili-
ties. Decreases in CO and NMVOC emissions over this
time period can largely be attributed to decreased resi-
dential wood consumption, which is the most significant
source of these pollutants from stationary combustion.
Table 2-13 through and Table 2-16 provide CH4 and N2O
emission estimates from stationary combustion by sec-
tor and fuel type. Estimates of NOX, CO, and NMVOC
emissions in 1998 are given in Table 2-17.33
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. National
coal, natural gas, fuel oil, and wood consumption data
were grouped into four sectors—industrial, commercial/
institutional, residential, and electric utilities.
For NOX, CO, and NMVOCs, the major categories
included in this section are those used in EPA (2000):
coal, fuel oil, natural gas, wood, other fuels (including
LPG, coke, coke oven gas, and others), and stationary
internal combustion. The EPA estimates emissions of NOX,
CO, and NMVOCs by sector and fuel source using a "bot-
tom-up" estimating procedure. In other words, emissions
were calculated either for individual sources (e.g., indus-
Table 2-13: CH4 Emissions from Stationary Combustion (Tg C02 Eq.)
I Sector/Fuel Type 1990 """ 1995 1996
1997
1998
1999
«
t
1
g
ft
1
?
'
1
f;
J
i
5)
fr
£
'*
1
Electric Utilities
. Coal
~" Fuel Oil
Natural gas
v- Wood
Industrial
Coal
• Fuel Oil
Natural gas
: Wood
Commercial/Institutional
Coal
:- Fuel Oil
Natural gas
----- Wood
Residential
Coal
'-.-'-• Fuel Oil
Natural Gas
Wood
Total
0.5
0.3 ~
0.1
0.1
+
2.7
0.6
0.4
0.8
0.9
0-7 1,
+
0.2 ~
0.3
0-2 J .
4.6
0.4 ~"
0.3
0.5 ^
3.5
8.5 ^'
0.5
0.4
+
0.1
+
3.0
0.5
0.4
1.0
1.1
0.7
+
0.2
0.3
0.3
4.7
0.3
0.3
0.5
3.6
8.9
0.5
0.4
+
0.1
+
3.0
0.5
0.4
1.0
1.1
0.8
+
0.2
0.3
0.3
4.7
0.3
0.3
0.5
3.6
9.0
0.5
0.4
0.1
0.1
+
3.1
0.5
0.4
1.0
1.1
0.8
+
0.1
0.3
0.3
3.8
0.4
0.3
0.5
2.6
8.1
0.5
0.4
0.1
0.1
+
3.0
0.5
0.4
1.0
1.1
0.7
+
0.1
0.3
0.3
3.3
0.3
0.3
0.5
2.3
7.6
0.5
0.4
0.1
0.1
+
3.3
0.5
0.4
1.0
1.4
0.8
+
0.1
0.3
0.3
3.5
0.3
0.3
0.5
2.4
8.1
.-"+. Does not exceed 0.05 Tg C02 Eq.
NA (Not Available)
Note: Totals may not sum due to independent rounding
'
See Annex C for a complete time series of criteria pollutant emission estimates for 1990 through 1999.
Energy 2-23
-------
Table 2-14: N20 Emissions from Stationary Combustion (Tg C02 Eq.)
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
7.4
7.1
0.2
0.1
+
4.8
1.2
1.6
0.3
1.8
0.3
+
0.2
0.1
+
1.1
+
0.2
0.1
0.7
13.6
1995
7.8
7.6
0.1
0.1
+
5.1
1.1
1.6
0.3
2.1
0.3
+
0.1
0.1
0.1
1.1
+
0.3
0.1
0.7
14.3
1996
8.2
8.0
0.1
0.1
+
5.2
1.0
1.7 '
0.3
2.1
0.3
+
0.1
0.1
0.1
1.2
+
0.3
0.2
0.7
14.9
1997
8.5
8.2
0.2
0.1
+
5.3
1.0
1.7
0.3
2.2
0.3
+
0.1
0.1
0.1
1.0
+
0.3
0.2
0.5
15.0
1998
8.7
8.4
0.2
0.1
+
5.2
1.0
1.7
0.3
2.3
0.3
+
0.1
0.1
0.1
0.8
+
0.2
0.1
0.4
15.1
1999
8.6
8.4
0.2
0.1
+
5.8
1.0
1.8
0.3
2.8
0.3
+
0.1
0.1
0.1
0.9
+
0.3
0.1
0.5
15.7
+ Does not exceed 0.05 Tg G02 Eq.
Note: Totals may not sum due to independent rounding.
Table 2-15: CH4 Emissions from Stationary Combustion (Gg)
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
23
16
4
3
+
129
27
17
40
44
33
1
9
13
11
218
19
13
21
166
403
1995
23
17
2
3
+
141
25
17
48
50
36
1
7
15
13
223
16
14
24
170
422
1996
23
18
2
3
+
143
24
18
50
52
38
1
7
15
14
226
16
15
26
170
430
1997
25
19
2
3
+
145
24
19
50
53
37
1
7
16
13
179
17
14
24
123
386
1998
26
19
4
3
+
144
23
18
48
55
35
1
7
15
13
156
13
13
22
107
361
1999
25
19
3
3
+
157
22
19
48
67
39
1
7
15
16
165
13
14
23
115
386
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding.
2-24 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 2-16: N20 Emissions from Stationary Combustion (Gg)
Sector/Fuel Type
Electric Utilities
- Coal
-: Fuel Oil
; Natural Gas
•, Wood
Industrial
Coal
p; Fuel Oil
f; Natural Gas
;"-,-.- Wood
Commercial/Institutional
: Coal
, Fuel Oil
|:i . Natural Gas
j: Wood
Residential
; - Coal
., Fuel Oil
; Natural Gas
: Wood
::T6tal
1990
24 *"
23
1
+
+
16
4
5
1 ,
6
1
+
1
+
+
3
+
1
+
2
44
1995
25
24
+
+
+
16
3
5
1
7
1
+
+
+
+
4
+
: 1
+
2
46
1996
27
26
+
+
+
17
3
5
1
7
1
+
+
+
+
4
+
1
1
2
48
1997
27
27
+
+
+
17
3
6
1
7
1
+
+
+
+
3
+
1
+
2
49
1998
28
27
1
+
+
17
3
6
1
7
1
+
+
+
+
3
+
1
+
1
49
1999
28
27
1
+
+
19
3
6
1
9
1
+
+
+
+
3
+
1
+
2
51
+ Does not exceed 0.5 Gg
l Note: Totals may not sum due to independent rounding
trial boilers) or for multiple sources combined, using ba-
sic activity data as indicators of emissions. Depending
on the source category, these basic activity data may
include fuel consumption, fuel deliveries, tons of refuse
burned, raw material processed, etc.
The EPA derived the overall emission control effi-
ciency of a source category from published reports, the
1985 National Acid Precipitation and Assessment Pro-
gram (NAPAP) emissions inventory, and other EPA data-
bases. The U.S. approach for estimating emissions of NOX,
CO, and NMVOCs from stationary combustion, as de-
scribed above, is consistent with the methodology rec-
ommended by the IPCC (IPCC/UNEP/OECD/EA1997).
More detailed information on the methodology for
calculating emissions from stationary combustion, includ-
ing emission factors and activity data, is provided in
Annex C.
Data Sources
Emissions estimates for NOX, CO, and NMVOCs in
this section were taken directly from the EPA's National
Air Pollutant Emissions Trends: 1900 -1999 (EPA 2000).
Fuel consumption data for CH4 and N2O estimates were
provided by the U.S. Energy Information Administration's
Annual Energy Review (EIA 2000). Estimates for wood
biomass consumption for fuel combustion do not include
wood wastes, liquors, municipal solid waste, tires, etc.
that are reported as biomass by EIA. Emission factors
were provided by the Revised 1996 IPCC Guidelines for
National Greenhouse Gas Inventories (IPCC/UNEP/
OECD/EA1997).
Uncertainty
Methane emission estimates from stationary
sources are highly uncertain, primarily due to difficulties
in calculating emissions from wood combustion (i.e., fire-
places and wood stoves). The estimates of CH4 and N2O
Energy 2-25
-------
Table 2-17: NOX, CO, and NMVOC Emissions from
Stationary Combustion in 1999 (Gg)
Sector/Fuel Type
Electric Utilities
Coal
Fuel Oil
Natural Gas
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural Gas
Wood
Other Fuels'
Internal Combustion
Commercial/Institutional
Coal
Fuel Oil
Natural Gas
Wood
Other Fuels8
Residential
Coalb
Fuel Oil"
Natural Gasb
Wood
Other Fuels0
Total
NOX
5,161
4,477
183
349
NA
152
2,844
492
194
1,090
NA
107
961
373
34
73
241
NA
25
692
NA
NA
NA
36
656
9,070
CO
374
217
16
85
NA
55
1,069
99
47
310
NA
309
303
136
14
15
63
NA
45
3,220
NA
NA
NA
2,994
226
4,798
NMVOC
49
26
5
8
NA
10
162
6
7
54
NA
32
63
26
1
3
14
NA
9
582
NA
NA
NA
552
31
820
NA (Not Available)
1 "Other Fuels" include LP6, waste oil, coke oven gas, coke, and
non-residential wood (EPA 2000).
b Coal, fuel oil, and natural gas emissions are included in the
"Other Fuels' category (EPA 2000).
c "Other Fuels" Include LPG, waste oil, coke oven gas, and coke
(EPA 2000).
Note: Totals may not sum due to independent rounding. See
Annex C tor emissions in 1990 through 1999.
emissions presented are based on broad indicators of
emissions (i.e., fuel use multiplied by an aggregate emis-
sion factor for different sectors), rather than specific emis-
sion processes (i.e., by combustion technology and type
of emission control). The uncertainties associated with
the emission estimates of these gases are greater than
with estimates of CO2 from fossil fuel combustion, which
mainly rely on the carbon content of the fuel combusted.
Uncertainties in both CH4 and N2O estimates are due to
the fact that emissions are estimated based on emission
factors representing only a limited subset of combustion
conditions. For the criteria pollutants, uncertainties are
partly due to assumptions concerning combustion tech-
nology types, age of equipment, emission factors used,
and activity data projections.
Mobile Combustion (excluding C02)
Mobile combustion emits greenhouse gases other
than CO2, including methane (CH4), nitrous oxide (N2O),
and the criteria pollutants carbon monoxide (CO), nitro-
gen oxides (NOX), and non-methane volatile organic com-
pounds (NMVOCs).
As with stationary combustion, N2O and NOX emis-
sions are closely related to fuel characteristics, air-fuel
mixes, combustion temperatures, as well as usage of pol-
lution control equipment. Nitrous oxide, in particular, can
be formed by the catalytic processes used to control NOX
CO, and hydrocarbon emissions. Carbon monoxide emis-
sions from mobile combustion are significantly affected
by combustion efficiency and presence of post-combus-
tion emission controls. Carbon monoxide emissions are
highest when air-fuel mixtures have less oxygen than re-
quired for complete combustion. This occurs especially
in idle, low speed and cold start conditions. Methane and
NMVOC emissions from motor vehicles are a function of
the CH4 content of the motor fuel, the amount of hydro-
carbons passing uncombusted through the engine, and
any post-combustion control of hydrocarbon emissions,
such as catalytic converters.
Emissions from mobile combustion were estimated
by transport mode (e.g., highway, air, rail, and water) and
fuel type—motor gasoline, diesel fuel, jet fuel, aviation
gas, natural gas, liquefied petroleum gas (LPG), and re-
sidual fuel oil—and vehicle type. Road transport accounted
for the majority of mobile source fuel consumption, and
hence, the majority of mobile combustion emissions. Table
2-18 through Table 2-21 provide CH4 and N2O emission
estimates from mobile combustion by vehicle type, fuel
type, and transport mode. Estimates of NOX, CO, and
NMVOC emissions in 1999 are given in Table 2-22.34
See Annex C for a complete time series of criteria pollutant emission estimates for 1990 through 1998.
2-26 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 2-1 8: CH4 Emissions from Mobile Combustion (Tg C02 Eq.)
Fuel Type/Vehicle Type 1990
1995
1996
1997
1998
1999
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
4.3
2.4
1.6
0.3
0.1
0.2
+
+
0.2
0.4
0.1
0.1
0.1
+
0.2
+
5.0
4.2
2.0
1.9
0.2
0.1
0.2
+
+
0.2
0.4
0.1
0.1
0.1
+
0.1
+
4.9
4.0
2.0
1.6
0.4
0.1
0.3
+
+
0.3
0.4
0.1
0.1
0.1
+
0.1
+
4.8
4.0
2.0
1.6
0.4
0.1
0.3
+
+
0.3
0.4
0.1
0.1
0.1
+
0.2
+
4.7
3.9
1.9
1.5
0.3
0.1
0.3
+
+
0.3
0.4
0.1
+
0.1
+
0.1
+
4.6
3.8
1.9
1.4
0.3
0.1
0.3
+
+
0.3
0.4
0.1
+
0.1
+
0.2
+
4.5
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
* "Other" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty
diesel powered utility equipment.
Table 2-19: N20 Emissions from Mobile Combustion (Tg C02 Eq.)
Fuel Type/Vehicle Type 1990
1995
1996
1997
1998
1999
Gasoline Highway
Passenger Cars
i Light-Duty Trucks
: Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
-•'•- Locomotives
f Farm Equipment
Construction Equipment
Aircraft
: Other*
} Total
49.6
30.9
17.8
0.9 ;C
+ - ;. -
1.8 —
0.1 " :
+
1.6
2.9
0.4
0.3
0.3
0.1
1.7
0.1
54.3
61.7
33.0
27.1
1.6
+
2.2
0.1
0.1
2.0
3.0
0.5
0.3
0.3
0.1
1.7
0.1
66.8
59.3
32.7
23.9
2.7
+
2.9
+
+
2.9
3.0
0.4
0.3
0.3
0.1
1.8
0.1
65.3
59.2
32.4
24.0
2.8
+
3.1
+
+
3.0
2.9
0.3
0.2
0.3
0.2
1.7
0.1
65.2
58.2
32.1
23.3
2.8
+
3.1
+
+
3.1
2.8
0.3
0.2
0.3
0.2
1.8
0.1
64.2
57.2
31.5
22.7
3.0
+
3.2
+
+
3.2
3.0
0.4
0.2
0.3
0.1
1.8
0.1
63.4
• + Does not exceed 0.05 Tg C02 Eq.
• Note: Totals may not sum due to independent rounding.
* "Other" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty
diesel powered utility equipment.
Energy 2-27
-------
Table 2-20: CH4 Emissions from Mobile Combustion (Gg)
Fuel Type/Vehicle Type 1990
1995
1996
1997
1998
1999
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
207
115
76
12
4
10
+
+
9
21
3
3
6
1
7
1
237
199
95
89
11
4
11
+
+
11
21
4
3
6
1
7
1
232
192
94
76
17
4
16
+
+
15
21
4
3
6
1
7
1
228
189
93
75
17
3
16
+
+
16
20
3
2
6
1 .
7
1
225
184
93
72
16
3
16
+
+
16
19
2
2
5
1
7
1
219
179
92
68
16
3
16
+
+
16
20
4
2
5
1
7
1
215
+ 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
dlesel powered utility equipment.
Table 2-21: N20 Emissions from Mobile Combustion (Gg)
Fuel Type/Vehicle Type 1990
1995
1996
1997
1998
1999
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft
Other*
Total
160
100
57
3
+
6
+
+
5
9
1
1
1
+
6
+
175
199
106
87
5
+
7
+
+
6
10
1
1
1
+
5
+
215
191
105
77
9
+
9
+
+
9
10
1
1
1
+
6
+
211
191
104
77
9
+
10
+
+
10
9
1
1
1
+
6
+
210
188
103
75
9
+
1.0.
+
+
10
9
1
1
1
+
6
+
207
184
102
73
10
+
10
+
+
10
10
1
1
1
+
6
+
204
+ Does not exceed 0.5 Gg
Note: Totals may not sum due to independent rounding.
* "Other" includes snowmobiles, small gasoline powered utility equipment, heavy-duty gasoline powered utility equipment, and heavy-duty
diesel powered utility equipment.
2-28 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 2-22: NOX, CO, and NMVOC Emissions from
Mobile Combustion in 1999 (Gg)
Fuel Type/Vehicle Type NOX
CO
NMVOCs
Gasoline Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
4,496
2,582
1,486
416
12
3,297
7
5
3,284
5,001
975
1,092
826
Construction Equipment ,137
Aircrafta
Otherb
Total
159
813
12,794
43,327
24,664
14,620
3,866
177
2,023
7
5
2,011
22,829
2,170
108
458
1,333
909
17,851
68,179
4,544
2,604
1,562
• 340
38
263
3
2
258
2,929
874
44
99
214
166
1,532
7,736
+ 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.
Mobile combustion was responsible for a small por-
tion of national CH4 emissions but was the second largest
source of N2O in the United States. From 1990 to 1999,
CH4 emissions declined by 10 percent, to 4.5 Tg CO2 Eq.
(215 Gg). Nitrous oxide emissions, however, rose 17 per-
cent to 63.4 Tg CO2 Eq. (204 Gg) (see Figure 2-20). The
reason for this conflicting trend was that the control tech-
nologies employed on highway vehicles in the United
States lowered CO, NOX, NMVOC, and CH4 emissions,
but resulted in higher average N2O emission rates. Fortu-
nately, since 1994 improvements in the emission control
technologies installed on new vehicles have reduced emis-
sion rates of both NOX and N2O per vehicle mile traveled.
Overall, CH4 and N2O emissions were dominated by gaso-
line-fueled passenger cars and light-duty gasoline trucks.
Fossil-fueled motor vehicles comprise the single
largest source of CO emissions in the United States and
are a significant contributor to NOX and NMVOC emis-
sions. In 1999, CO emissions from mobile combustion
contributed 82 percent of national CO emissions and 56
and 48 percent of NOX and NMVOC emissions, respec-
tively. Since 1990, emissions of CO and NMVOCs from
mobile combustion decreased by 2 and 5 percent, respec-
tively, while emissions of NOX increased by 17 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. Depend-
ing upon the category, activity data included such infor-
mation as fuel consumption, fuel deliveries, and vehicle
miles traveled (VMT). Emission estimates from highway
vehicles were based on VMT and emission factors by
vehicle type, fuel type, model year, and control technol-
ogy. Fuel consumption data was employed as a measure
of activity for non-highway vehicles and then fuel-spe-
cific emission factors were applied.35 A complete discus-
sion of the methodology used to estimate emissions from
mobile combustion is provided in Annex D.
The EPA (2000b) provided emissions estimates of
NOX, CO, and NMVOCs for eight categories of highway
vehicles,36 aircraft, and seven categories of off-highway
vehicles.37
Data Sources
Emission factors used in the calculations of CH4
and N2O emissions are presented in Annex D. The Re-
vised 1996 IPCC Guidelines (TPCC/UNEP/OECD/EA
1997) provided emission factors for CH4, and were devel-
oped using MOBILESa, a model used by the Environ-
mental Protection Agency (EPA) to estimate exhaust and
running loss emissions from highway vehicles. The
MOBILESa model uses information on ambient tempera-
35 The consumption of international bunker fuels is not included in these activity data, but are estimated separately under the
International Bunker Fuels source category.
36 These categories included: gasoline passenger cars, diesel passenger cars, light-duty gasoline trucks less than 6,000 pounds in weight,
light-duty gasoline trucks between 6,000 and 8,500 pounds in weight, light-duty diesel trucks, heavy-duty gasoline trucks and buses,
heavy-duty diesel trucks and buses, and motorcycles.
37 These categories included: gasoline and diesel farm tractors, other gasoline and diesel farm machinery, gasoline and diesel construction
equipment, snowmobiles, small gasoline utility engines, and heavy-duty gasoline and diesel general utility engines.
Energy 2-29
-------
Figure 2-20
80
70
60
o- 50
ui
CM
O 40
O
P 30 •
20
10 •
N20
CH4
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
ture, vehicle speeds, national vehicle registration distri-
butions, gasoline volatility, and other variables in order
to produce these factors (EPA 1997).
Emission factors for N2O from gasoline highway
vehicles came from EPA (1998). This report contains emis-
sion 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 re-
cent testing program at EPA's National Vehicle and Fuel
Emissions Laboratory (NVFEL). These emission factors
for gasoline highway vehicles are lower than the U.S.
default values in the Revised 1996IPCC Guidelines, but
are higher than the European default values, both of which
were published before the more recent tests and litera-
ture 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 pas-
senger 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 additional testing data are available. For more details,
see EPA (1998). Nitrous oxide emission factors for diesel
highway vehicles were taken from the European default
values found in the Revised 1996 IPCC Guidelines (IPCC/
UNEP/OECD/IEA 1997). 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 1996 IPCC Guidelines were used for non-high-
way vehicles.
Activity data were gathered from several U.S. gov-
ernment sources including EIA (2000a), EIA (2000b),
FHWA (1999), BEA (2000), DESC (2000), DOC (2000), FAA
(2000), and DOT/BTS (2000). Control technology data for
highway vehicles were obtained from the EPA's Office of
Transportation and Air Quality. Annual VMT data for
1990 through 1999 were obtained from the Federal High-
way Administration's (FHWA) Highway Performance
Monitoring System database, as noted in EPA (2000a).
Emissions estimates for NOX, CO, NMVOCs were
taken directly from the EPA's National Air Pollutant
Emissions Trends, 1900 -1999 (EPA 2000b).
Uncertainty
Mobile combustion emission estimates can vary
significantly due to assumptions concerning fuel type
and composition, technology type, average speeds, type
of emission control equipment, equipment age, and oper-
ating and maintenance practices. Fortunately, detailed
activity data for mobile combustion were available, in-
cluding VMT by vehicle type for highway vehicles. The
allocation of this VMT to individual model years was
done using temporally variable profiles of both vehicle
usage by vehicle age and vehicle usage by model year in
the United States. Data for these profiles were provided
byEPA(2000a).
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 combustion—CO, NOX, and
hydrocarbons—have been extensively researched, and
thus involve lower uncertainty than emissions of unregu-
2-30 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
lated gases. Although methane has not been singled out
for regulation in the United States, overall hydrocarbon
emissions from mobile combustion—a component of
which is methane—are regulated.
In calculating CH4 and N2O emissions from high-
way vehicles, only data for Low Emission Vehicles (LEVs)
in California has been obtained. Data on the number of
LEVs in the rest of the United States will be researched
and may be included in future inventories.
Compared to methane, CO, NOX, and NMVOCs,
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. Research data has
shown that N2O emissions from vehicles with catalytic
converters are greater than those without emission con-
trols, 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. Currently,
N2O gasoline highway emission factors for vehicles other
than passenger cars are scaled based on those for pas-
senger cars and their relative fuel economy. Actual mea-
surements should be substituted for this procedure when
they become available. Further testing is needed to re-
duce the uncertainty in emission factors for all classes of
vehicles, using realistic driving regimes, environmental
conditions, and fuels.
Overall, uncertainty for N2O emissions estimates is
considerably higher than for CH4, CO, NOX, or NMVOC;
however, all these gases involve far more uncertainty than
CO2 emissions from fossil fuel combustion.
U.S. jet fuel and aviation gasoline consumption is
currently all attributed to the transportation sector by EIA,
and it is assumed here that it is all used to fuel aircraft.
However, it is likely that some fuel purchased by airlines is
not necessarily used in aircraft, but instead used to power
auxiliary power units, hi ground equipment, and to test
engines. Some jet fuel may also be used for other pur-
poses such as blending with diesel fuel or heating oil.
In calculating CH4 emissions from aircraft, an aver-
age emission factor is applied to total jet fuel consump-
tion. This average emission factor takes into account the
fact that CH4 emissions occur only during the landing
and take-off (LTO) cycles, with no CH4 being emitted
during the cruise cycle. While there is some evidence
that fuel emissions in cruise conditions may actually de-
stroy methane, the average emission factor used does
not take this into account.
Lastly, in EPA (2000b), U.S. aircraft emission esti-
mates for CO, NOx, and NMVOCs are based upon land-
ing and take-off (LTO) cycles and consequently only cap-
ture near ground-level emissions, which are more relevant
for air quality evaluations. These estimates also include
both domestic and international flights. Therefore, esti-
mates presented here overestimate IPCC-defined domes-
tic CO, NOX, and NMVOC emissions by including LTO
cycles by aircraft on international flights but underesti-
mate because they do not include emissions from aircraft
on domestic flight segments at cruising altitudes.
Coal Mining
All underground and surface coal mining liberates
methane as part of normal operations. The amount of
methane liberated depends upon the amount that remains
in the coal ("in situ") and surrounding strata when min-
ing occurs. This methane content depends upon the
amount of methane created during the coal formation (or
coalification) process, and the geologic characteristics
of the coal seams. Deeper coal deposits tend to generate
more methane during coalification and retain more of the
gas afterwards. Accordingly, deep underground coal
seams generally have higher methane contents than shal-
low coal seams or surface deposits.
Three types of coal mining activities release meth-
ane to the atmosphere: underground mining, surface min-
ing, and post-mining activities. Underground coal mines
contribute the largest share of methane emissions. All
underground coal mines employ ventilation systems to
ensure that methane levels remain within safe concentra-
tions. These systems can exhaust significant amounts of
methane to the atmosphere in low concentrations. Addi-
tionally, twenty gassy U.S. coal mines supplement venti-
Energy 2-31
-------
lation systems with degasification systems.
Degasification systems are wells drilled from the surface
or boreholes drilled inside the mine that remove large
volumes of methane before, during or after mining. In
1999,11 coal mines collected methane from degasification
systems and sold this gas to a pipeline, thus reducing
emissions to the atmosphere. Surface coal mines also re-
lease methane as the overburden is removed and the coal
is exposed; however, the level of emissions is much lower
than from underground mines. Finally, some of the meth-
ane retained in the coal after mining is released during
processing, storage, and transport of the coal.
Total methane emissions in 1999 were estimated to
be 61.8 Tg CO2 Eq. (2,944 Gg), declining 30 percent since
1990 (see Table 2-23 and Table 2-24). Of this amount, un-
derground mines accounted for 64 percent, surface mines
accounted for 14 percent, and post-mining emissions ac-
counted for 21 percent. With the exception of 1994 and
1995, total methane emissions declined hi each succes-
sive year during this period. In 1993, methane generated
from underground mining dropped, primarily due to labor
strikes at many large underground mines. In 1995, there
was an increase in methane emissions from underground
mining due to particularly increased emissions at the high-
Table 2-23: CH4 Emissions from Coal Mining (Tg C02 Eq.)
est-emitting coal mine in the country. The decline in meth-
ane emissions from underground mines in 1999 is the
result of a decrease in coal production, and the mining of
less gassy coal. Surface mine emissions and post-mining
emissions remained relatively constant from 1990 to 1999.
In 1994, EPA's Coalbed Methane Outreach Program
(CMOP) began working with the coal industry and other
stakeholders to identify and remove obstacles to invest-
ments in coal mine methane recovery and use projects.
Emissions reductions attributed to CMOP are estimated
at 0.8,5.1,5.5,6.6,6.2, and 7.0 Tg CO2 Eq. in 1994 through
1999, respectively.
Methodology
The methodology for estimating methane emissions
from coal mining consists of two steps. The first step
involves estimating methane emissions from underground
mines. Because of the availability of ventilation system
measurements, underground mine emissions can be esti-
mated on a mine-by-mine basis and then summed to de-
termine total emissions. The second step involves esti-
mating emissions from surface mines and post-mining
activities by multiplying basin-specific coal production
by basin-specific emissions factors.
Activity
Underground Mining
Liberated
Recovered & Used
Surface Mining
Post- Mining (Underground)
Post-Mining (Surface)
Total
1990
62.8
68.8
(6.0)
10.2
13.1
1.7
87.9
1995
52.2
64.8
(12.6)
8.9
11.9
1.5
74.6
1996
46.3
60.4
(14.1)
9.2
12.4
1.5
69.3
1997
45.0
61.7
(16.7)
9.5
12.8
1.5
68.8
1998
43.0
60.6
(17.5)
9.4
12.6
1.5
66.5
1999
39.8
57.2
(17.4)
8.8
11.7
1.4
61.8
Note: Totals may not sum due to independent rounding.
Table 2-24: CH4 Emissions from Coal Mining (Gg)
Activity
1990
1995
1996
1997
1998
1999
Underground Mining 2,991
Liberated 3,278
Recovered & Used (288)
Surface Mining 488
Post- Mining (Underground) 626
Post-Mining (Surface) 79
Total 4,184
Note; Totals may not sum due to independent rounding.
2,487
3,086
(599)
425
569
69
3,550
2,204
2,875
(671)
436
590
71
3,301
2,141
2,938
(797)
451
609
73
3,274
2,049
2,884
(835)
446
600
72
3,168
1,896
2,726
(829)
421
558
68
2,944
2-32 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Underground mines. Total methane emitted from
underground mines was estimated as the sum of methane
liberated from ventilation systems, plus methane liber-
ated from degasification systems, minus methane recov-
ered and used. The Mine Safety and Heath Administra-
tion (MSHA) samples methane emissions from ventila-
tion systems for all mines with detectable38 methane con-
centrations. These mine-by-mine measurements are used
to estimate methane emissions from ventilation systems.
Some of the higher-emitting underground mines also
use degasification systems (e.g., wells or boreholes) that
remove methane before, during, or after mining. This meth-
ane can then be collected for use or vented to the atmo-
sphere. Various approaches were employed to estimate
the quantity of methane collected by each of the more
than twenty mines using these systems, depending on
available data. For example, some mines report to EPA the
amounts of methane liberated from their degasification
systems. For mines that sell recovered methane to a pipe-
line, pipeline sales data were used to estimate
degasification emissions. Finally, for those mines for which
no other data are available, default recovery efficiency
values were developed, depending on the type of
degasification system employed.
Finally, the amount of methane recovered by
degasification systems and then used (i.e., not vented)
was estimated. This calculation was complicated by the
fact that methane is rarely recovered and used during the
same year in which the particular coal seam is mined. In
1999,11 active coal mines sold recovered methane to pipe-
lines. Emissions avoided for these projects were estimated
using gas sales data reported by various State agencies,
and information supplied by coal mine operators regard-
ing the number of years in advance of mining that gas
recovery occurs. Additionally, some of the State agen-
cies provide individual well production information, which
was used to assign gas sales to a particular year.
Surface Mines and Post-Mining Emissions. Sur-
face mining and post-mining methane emissions were
estimated by multiplying basin-specific coal production
by basin-specific emissions factors. Surface mining emis-
sions factors were developed by assuming that surface
38 MSHA records coal mine methane readings with concentrations
this threshold are considered non-detectable.
mines emit from one to three times as much methane as
the average in situ methane content of the coal. This
accounts for methane released from the strata surround-
ing the coal seam. For this analysis, it was assumed that
twice the average in-situ methane content was emitted.
For post-mining emissions, the emission factor was as-
sumed to be from 25 to 40 percent of the average in situ
methane content of coals mined in the basin. For this
analysis, it was assumed that 32.5 percent of the average
in-situ methane content was emitted.
Data Sources
The Mine Safety and Health Administration pro-
vided mine-specific information on methane liberated from
ventilation systems at underground mines. The EPA de-
veloped 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,
information supplied by mine operators regarding the
number of years in advance of mining that gas recovery
occurred, and reports of gas used on-site. Annual coal
production data were taken from the Energy Information
Administration's Coal Industry Annual (see Table 2-25)
(EIA 1999). Data on in situ methane content and emis-
sions factors are taken from EPA (1993).
Uncertainty
The emission estimates from underground ventila-
tion systems were based upon actual measurement data,
which were estimated to have relatively high accuracy. A
degree of imprecision was introduced because the mea-
surements were not continuous but rather an average of
quarterly instantaneous readings. Additionally, the mea-
surement equipment used possibly resulted in an aver-
age of 10 percent overestimation of annual methane emis-
sions (Mutmansky and Wang 2000). Estimates of meth-
ane liberated from degasification systems are less certain
because the EPA assigns default recovery efficiencies
for a subset of U.S. mines. Compared to underground
mines, there is considerably more uncertainty associated
of greater than 50 ppm (parts per million) methane. Readings below
Energy 2-33
-------
Table 2-25: Coal Production (Thousand Metric Tons)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
199939
Underground
384,250
368,635
368,627
318,478
362,065
359,477
371,816
381,620
378,964
352,753
Surface
546,818
532,656
534,290
539,214
575,529
577,638
593,315
607,163
634,864
639,701
Total
931,068
901,291
902,917
857,692
937,594
937,115
965,131
988,783
1,013,828
992,454
with surface mining and post-mining emissions because
of the difficulty in developing accurate emissions factors
from field measurements. The EPA plans to update the
basin specific surface mining emission factors. Because
underground emissions comprise the majority of total coal
mining emissions, the overall uncertainty is estimated to
be only ±15 percent. Currently, the estimate does not in-
clude emissions from abandoned coal mines because of
limited data. The EPA is conducting research on the fea-
sibility of including an estimate in future years.
Natural Gas Systems
The U.S. natural gas system is vast, encompassing
hundreds of thousands of wells, hundreds of processing
facilities, and over a million miles of transmission and
distribution pipelines. Overall, natural gas systems emit-
ted 121.8 Tg CO2 Eq. (5,799 Gg) of methane in 1999, a
slight increase over emissions hi 1990 (see Table 2-26 and
Table 2-27). Improvements in management practices and
technology, along with the normal replacement of older
equipment, have helped to stabilize emissions. In addi-
tion, EPA's Natural Gas STAR Program, initiated in 1993,
is successfully working with the gas industry to promote
profiTable practices and technologies that reduce meth-
ane emissions.40
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 activities.
Pressure surge relief systems and accidents can lead to
system upset emissions. Below is a characterization of
the four major stages of the natural gas system. Each of
the stages is described and the different factors affecting
methane emissions are discussed.
Field Production. In this initial stage, wells are used
to withdraw raw gas from underground formations. Emis-
sions arise from the wells themselves, gathering pipe-
lines, and well-site gas treatment facilities such as dehy-
drators and separators. Fugitive emissions and emissions
from pneumatic devices account for the majority of emis-
sions. Emissions from field production accounted for
approximately 25 percent of methane emissions from natu-
ral gas systems between 1990 and 1999. Emissions rose
between 1990 and 1993 but by 1999 had returned to slightly
above 1990 levels because of emission reductions by firms
participating in the Natural Gas STAR Program.
Processing. In this stage, natural gas liquids and
various other constituents from the raw gas are removed,
resulting in "pipeline quality" gas, which is injected into
the transmission system. Fugitive emissions from com-
pressors, including compressor seals, are the primary
emission source from this stage. Processing plants ac-
count for about 12 percent of methane emissions from
natural gas systems.
Transmission and Storage. Natural gas transmis-
sion involves high pressure, large diameter pipelines that
transport gas long distances from field production and
processing areas to distribution systems or large volume
customers such as power plants or chemical plants. Com-
pressor station facilities, which contain large reciprocat-
ing and turbine compressors, are used to move the gas
throughout the United States transmission system. Fugi-
tive emissions from these compressor stations and from
metering and regulating stations account for the majority
39 The EIA Coal Industry Annual was not yet available, however, total production was available in the U.S. Coal Supply and Demand:
1999 Review. The split between underground and surface mining production is a preliminary estimate based on data from previous years.
J0 Natural Oas STAR Program reductions are included in emission estimates.
2-34 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 2-26: CH4 Emissions from Natural Gas Systems (Tg C02 Eq.)
Plage 1990 ^* l< v 1995 1996
1997
* Note: Totals may not sum due to independent rounding.
1998
1999
"Field Production
f Processing
iTransmission and Storage
lUisfribution
|Total
29.6
14.7
46.7
30.3
121.2
• .
s --. - , '... O 1 .U
'trrr 15.0 •••
. «^,,,,.- 467
E^::-: 31.5 ;
*SB3KK*T?"S'Slii,-!:." W. *
30.9
14.9
47.1
32.9
125.8
29.6
14.9
46.0
. 32.2
122.7
31.7
14.7
44.8
30.9
122.1
30.8
14.6
44.8
31.6
121.8
Table 2-27: CH4 Emissions from Natural Gas Systems (Gg)
teStage 1990 1995 1996
1997
e: Totals may not sum due to independent rounding.
1998
1999
Ifleld Production
* Processing
^Transmission and Storage
s Distribution
iTbtal
1,407
702
2,223
1,441
5,772
- £^"'2 1,477 : :
•;•" ;•..:. -'.".. .712
C*-: ;:.L 2,225
• 1,498
m^m&tfV^a^-'-.^'^i • '.
srr "5,912
1,474
708
2,243
1,567
5,993
1,407
710
2,192
1,532
5,841
1,510
698
2,135
1,471
5,814
1,468
694
2,134
1,503
5,799
of the emissions from this stage. Pneumatic devices and
engine exhaust are also sources of emissions from trans-
mission facilities. Methane emissions from transmission
account for approximately 37 percent of the emissions
from natural gas systems.
Natural gas is also injected and stored in under-
ground formations during periods of low demand (e.g.,
summer), and withdrawn, processed, and distributed dur-
ing periods of high demand (e.g., winter). Compressors
and dehydrators are the primary contributors to emis-
sions from these storage facilities. Approximately one
percent of total emissions from natural gas systems can
be attributed to storage facilities.
Distribution. Distribution pipelines take the high-
pressure gas from the transmission system at "city gate"
stations, reduce the pressure and distribute the gas
through mains and service lines to individual end users.
There were over 980,000 miles of distribution mains in
1998,41 an increase from just over 837,000 miles in 1990
(AGA1998). Distribution system emissions, which account
for approximately 26 percent of emissions from natural
gas systems, resulted mainly from fugitive emissions from
gate stations and non-plastic piping (cast iron, steel).42
An increased use of plastic piping, which has lower emis-
sions than other pipe materials, has reduced the growth in
emissions from this stage. Distribution system emissions
in 1999 were only slightly higher than 1990 levels.
Methodology
The basis for estimates of methane emissions from
the U.S. natural gas industry is a detailed study by the
Gas Research Institute and EPA (EPA/GRI1996). The EPA/
GRI study developed over 100 emission and activity fac-
tors to characterize emissions from the various compo-
nents within the operating stages of the U.S. natural gas
system. The study was based on a combination of pro-
cess engineering studies and measurements at represen-
tative gas facilities. From this analysis, the EPA devel-
oped a 1992 base year emissions estimate using the emis-
sion and activity factors. For other years, the EPA has
developed a set of industry activity factor drivers that
can be used to update activity factors. These drivers in-
clude statistics on gas production, number of wells, sys-
tem throughput, miles of various kinds of pipe, and other
statistics that characterize the changes in the U.S. natural
gas system infrastructure and operations.
41 1998 is the latest year for which distribution pipeline mileage data was available.
42 The percentages of total emissions from each stage may not add to 100 because of independent rounding.
Energy 2-35
-------
The methodology also adjusts the emission fac-
tors to reflect underlying technological improvement
through both innovation and normal replacement of
equipment. For the period 1990 through 1995, the emis-
sion factors were held constant. Thereafter, emission fac-
tors are reduced at a rate of 0.2 percent per year such that
by 2020, emission factors will have declined by 5 percent
from 1995. See Annex F for more detailed information on
the methodology and data used to calculate methane
emissions from natural gas systems.
Data Sources
Activity factor data were obtained from the follow-
ing sources: American Gas Association (AGA 1991
through 1999); Natural Gas Annual (EIA 1998); Natural
Gas Monthly (EIA 1999); Oil and Gas Journal (PennWell
Corporation 1999, 2000); Independent Petroleum Asso-
ciation of America (JPAA 1998, 1999), and the Depart-
ment of Transportation's Office of Pipeline Safety (OPS
2000). The Minerals Management Service (DOI 1997
through 2000) supplied offshore platform data. All emis-
sion factors were taken from EPA/GRI (1996).
Uncertainty
The heterogeneous nature of the natural gas in-
dustry makes it difficult to sample facilities that are com-
pletely representative of the entire industry. Because of
this, scaling up from model facilities introduces a degree
of uncertainty. Additionally, highly variable emission rates
were measured among many system components, mak-
ing the calculated average emission rates uncertain. De-
spite 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
Methane emissions from petroleum systems are pri-
marily associated with crude oil production, transporta-
tion, and refining operations. During each of these activi-
ties, methane is released to the atmosphere as fugitive
emissions, vented emissions, emissions from operational
upsets, and emissions from fuel combustion. The EPA es-
timates that total methane emissions from petroleum sys-
tems in 1999 were 21.9 Tg CO2 Eq. (1,044 Gg). Since 1990,
emissions declined gradually primarily due to a decline in
domestic oil production. (See Table 2-28 and Table 2-29.)
The various sources of emissions are detailed below.
Production Field Operations. Production field
operations account for approximately 97 percent of total
methane emissions from petroleum systems. Vented meth-
ane from oil wells, storage tanks, and related production
field processing equipment account for the vast majority
of the emissions from production, with storage tanks and
natural-gas-powered pneumatic devices being the domi-
nant sources. (The emissions from storage tanks occur
when the methane, entrained in crude oil under high pres-
sure, volatilizes once the crude oil is dumped into storage
tanks at atmospheric pressure.) The next most dominant
sources of venting emissions are oil wells and offshore
platforms. The remaining emissions from production can
be attributed to fugitives and combustion. The EPA ex-
pects future emissions from production fields to decline
as the number of oil wells declines and crude production
in the United States slows.
Crude Oil Transportation. Crude transportation
activities account for approximately one half percent of
total methane emissions from the oil industry. Venting
from tanks and marine vessel loading operations accounts
for the majority of methane emissions from crude oil trans-
portation. Fugitive emissions, almost entirely from float-
ing roof tanks, account for the remainder.
Crude Oil Refining. Crude oil refining processes
and systems account for only two percent of total meth-
ane emissions from the oil industry because most of the
methane in crude oil is removed or escapes before the
crude oil is delivered to the refineries. Within refineries,
vented emissions account for about 87 percent of the
emissions from refining, while fugitive and combustion
emissions account for approximately seven and six per-
cent, respectively. Refinery system blowdowns for main-
tenance and the process of asphalt blowing—with air to
harden it—are the primary venting contributors. Most of
the fugitive emissions from refineries are from leaks in the
fuel gas system. Refinery combustion emissions accu-
mulate from small amounts of unburned methane in pro-
cess heater stack emissions and from unburned methane
2-36 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 2-28: CH4 Emissions from Petroleum Systems (Tg C02 Eq.)
Activity
1990
1995
1996
1997
1998
1999
Production Field Operations 26.5 "*"""
Tank venting 1 1 .8
Pneumatic device venting 11,7
Wellhead fugitives 0.5
i— . Combustion & process upsets 1 .0
Misc. venting & fugitives 1 .5
Crude Oil Transportation 0.1
Refining 0.5
Total 27.2
Note: Totals may not sum due to independent rounding.
23.9
10.4
10.6
0.5
0.9
1.4
0.1
0.5
24.5
23.3
10.2
10.3
0.5
1.0
1.4
0.1
0.5
24.0
23.3
10.2
10.3
0.5
1.0
1.4
0.1
0.6
24.0
22.6
9.8
10.0
0.5
0.9
1.3
0.1
0.6
23.3
21.2
9.1
9.4
0.5
0.9
1.3
0.1
0.6
21.9
Table 2-29: CH4 Emissions from Petroleum Systems (Gg)
Activity 1990 '~
Production Field Operations 1,263
Tank venting 564
Pneumatic device venting 559 '-• :-~-: -- --•'-'
Wellhead fugitives 24 _: :
Combustion & process upsets 46
Misc. venting & fugitives 70
Crude Oil Transportation 7
Refining 25
Total 1,294 ~
1995
1,136
493
507
25
45
66
6
25
1,168
1996
1,111
485
491
25
45
65
6
26
1,143
1997
1,109
484
490
24
46
65
6
27
1,142
1998
1,075
466
475
24
45
64
6
27
1,108
1999
1,011
433
447
24
44
63
6
27
1,044
Note: Totals may not sum due to independent rounding.
in engine exhausts and flares. The very slight increase in
emissions from refining, relative to the decline in emis-
sions from field production operations, is due to increas-
ing imports of crude oil.
Methodology
The EPA's methodology for estimating methane
emissions from petroleum systems is based on a compre-
hensive study of methane emissions from U.S. petroleum
systems, Estimates of Methane Emissions from the U.S.
Oil Industry (Draft Report) (EPA 1999). The study esti-
mates emissions from 70 activities occurring in petroleum
systems from the oil wellhead through crude oil refining,
including 39 activities for crude oil production field op-
erations, 11 for crude oil transportation activities, and 20
for refining operations. Annex G explains the emission
estimates for these 70 activities in greater detail. The es-
timates of methane emissions from petroleum systems do
not include emissions downstream from oil refineries be-
cause these emissions are very small compared to meth-
ane emissions upstream from oil refineries.
The methodology for estimating methane emissions
from the 70 oil industry activities employs emission and
activity factors initially developed in EPA (1999). The EPA
estimates emissions for each activity by multiplying emis-
sion factors (e.g., emission rate per equipment item or per
activity) by their corresponding activity factor (e.g.,
equipment count or frequency of activity). The report
provides emission factors and activity factors for all ac-
tivities except those related to offshore oil production.
For offshore oil production, the EPA calculates an emis-
sion factor by dividing an emission estimate from the
Minerals Management Service (MMS) by the number of
platforms (the activity factor). Emission factors are held
constant for the period 1990 through 1999.
The EPA collects activity factors for 1990 through
1999 from a wide variety of statistical resources. For some
years, complete activity factor data are not available. In
this case, the EPA employs one of three options. Where
appropriate, the activity factor is assumed to be directly
proportional to annual oil production. Proportionality
constants are calculated by dividing the activity factor
Energy 2-37
-------
for 1995 by the annual oil production for 1995. The result-
ing proportionality constants are then multiplied by the
annual oil production in years for which activity factors
must be estimated. In other cases, the activity factor is
kept constant from 1990 through 1999. Lastly, previous
year data are used when current year data are not yet
available. These data are subsequently updated in the
next inventory cycle.
Data Sources
Nearly all emission factors were taken from earlier
work performed by Radian International LLC (Radian
1996e). Other emission factors were taken from an Ameri-
can Petroleum Institute publication (API 1996), EPA de-
fault values, MMS reports (MMS 1995 and 1999), the
Exploration and Production (E&P) Tank model (API and
GRI), reports by the Canadian Association of Petroleum
Producers (CAPP 1992 and 1993), and consensus of in-
dustry peer review panels.
The EPA uses many references to obtain activity
factors. Among the more important references are the
Energy Information Administration annual and monthly
reports (EIA1995,1996,1997,1998), the API Basic Petro-
leum DataBook (API 1997 and 1999), Methane Emissions
from the Natural Gas Industry prepared for the Gas Re-
search Institute (CRT) and EPA (Radian 1996a-d), consen-
sus of industry peer review panels, MMS reports (MMS
1995 and 1999), and the Oil & Gas Journal (OGJ 1998a,b).
Annex G provides a complete list of references.
Uncertainty
The detailed, bottom-up analysis used to evaluate
U.S. petroleum systems for the current Inventory reduces
the uncertainty related to the methane emission estimates
compared to previous estimates. However, a number of
uncertainties remain. Published activity factors were not
available every year for all 70 activities analyzed for pe-
troleum systems. For example, there is uncertainty asso-
ciated with the estimate of annual venting emissions in
production field operations because a recent census of
tanks and other tank battery equipment, such as separa-
tors and pneumatic devices, was not available. These
uncertainties are important because storage tanks account
for 41 percent of total 1999 methane emissions from pe-
troleum systems. Uncertainties are also associated with
emission factors because emission rates can vary highly
from reservoir to reservoir and well to well. A single sum-
mary emission factor cannot reflect this variation. Since
the majority of methane emissions occur during produc-
tion field operations, where methane can first escape crude
oil, a better understanding of tanks and tank equipment
would reduce the uncertainty. Because of the dominance
of crude storage tank venting and pneumatics, Table 2-30
provides emission estimate ranges for these sources. For
tank venting, these ranges include numbers that are 25
percent higher than or lower than the given point esti-
mates. For pneumatics, the range is between 33 percent
lower than and 25 percent higher than the point estimates.
Natural Gas Flaring and
Criteria Pollutant Emissions
from Oil and Gas Activities
The flaring of natural gas from oil wells is a small
source of carbon dioxide (CO2). In addition, oil and gas
activities also release small amounts of nitrogen oxides
(NOX), carbon monoxide (CO), and nonmethane volatile
organic compounds (NMVOCs). This source accounts
for only a small proportion of overall emissions of each of
these gases. Emissions of CO2, NOX, and CO from petro-
leum and natural gas production activities were all less
than 1 percent of national totals, while NMVOC emis-
sions were roughly 2 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 may be vented, with the remaining 80
percent flared; however, it is now believed that flaring
accounts for an even greater proportion, although some
venting still occurs. Methane emissions from venting are
accounted for under Petroleum Systems. For 1999, CO2
emissions from flaring were estimated to be approximately
11.7 Tg CO2 Eq. (11,701 Gg), an increase of 128 percent
since 1990 (see Table 2-31).
Criteria pollutant emissions from oil and gas pro-
duction, transportation, and storage, constituted a rela-
2-38 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 2-30: Uncertainty in CH4 Emissions from Production Field Operations (Gg)
s Activity
1990
1995
1996
1997
1998
1999
; Tank venting (point estimate) 564 ""
•;, Low 423
!: High 705 -"'•
Pneumatic devices (point estimate) 559
':r Low 372 '--.-- -.
s High 698 "-
493
370
617
507
338
634
485
364
606
491
328
614
484
363
605
490
327
613
466
349
582
475
317
594
433
325
541
447
300
559
lively small and stable portion of the total emissions of
these gases from the 1990 to 1999 (see Table 2-32).
Methodology
The estimates for CO2 emissions were prepared us-
ing an emission factor of 54.71 Tg CO2 Eq./QBtu of flared
gas, and an assumed flaring efficiency of 100 percent. The
quantity of flared gas was estimated as the total reported
vented and flared gas minus the amount assumed to be
vented annually, which varied from 65,772 million cubic
feet in 1990 to 52,670 million cubic feet in 1999.43
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 in terms of total natural gas vented
and flared for estimating CO2 emissions from natural gas
flaring were taken from EIA's Natural Gas Annual (EIA
2000). The emission and thermal conversion factors were
also provided by EIA (see Table 2-33).
Table 2-31: C02 Emissions
from Natural Gas Flaring
EPA (2000) provided emission estimates for NOX,
CO, and NMVOCs from petroleum refining, petroleum
product storage and transfer, and petroleum marketing
operations. Included are gasoline, crude oil and distillate
fuel oil storage and transfer operations, gasoline bulk
terminal and bulk plants operations, and retail gasoline
service stations operations.
Uncertainty
Uncertainties in CO2 emission estimates primarily
arise from assumptions concerning what proportion of
natural gas is flared and the flaring efficiency. Uncertain-
ties in criteria pollutant emission estimates are partly due
to the accuracy of the emission factors used and projec-
tions of growth.
Table 2-32: NOX, NMVOCs, and
CO Emissions from Oil and Gas Activities (Gg)
Year Tg
1990
1995
1 1996
F 1997
• 1998
;;•-• 1999
43 See the methodological
C02 Eq.
5.1
13.6
13.0
12.0
10.8
11.7
discussion
eg
5,121
13,587
12,998
12,026
10,839
11,701
under Petroleum Systems
Year
1990
!
,1995
^996
;i998
_.1999
T- '-
for the basis of the
NOX
139
j.
100
126
130
130
130
portion of natural gas
CO
302
316
321
333
332
332
assumed
NMVOCs
555
582
433
442
440
385
vented.
1
Energy 2-39
-------
International Bunker Fuels
Emissions resulting from the combustion of fuels
used for international transport activities, termed interna-
tional bunker fuels under the United Nations Framework
Convention on Climate Change (UNFCCC), are currently
not included in national emission totals, but are reported
separately based upon location of fuel sales. The deci-
sion to report emissions from international bunker fuels
separately, instead of allocating them to a particular coun-
try, was made by the Intergovernmental Negotiating Com-
mittee in establishing the Framework Convention on Cli-
mate Change.44 These decisions are reflected in the Re-
vised 1996IPCC Guidelines, in which countries are re-
quested to report emissions from ships or aircraft that
depart from their ports with fuel purchased within na-
tional boundaries and are engaged in international trans-
port separately from national totals (IPCC/UNEP/OECD/
IEA1997). The Parties to the UNFCCC have yet to decide
on a methodology for allocating these emissions.45
Greenhouse gases emitted from the combustion of
international bunker fuels, like other fossil fuels, include
carbon dioxide (CO^, methane (CH^, nitrous oxide (N2O),
carbon monoxide (CO), oxides of nitrogen (NOX), non-
methane volatile organic compounds (NMVOCs), particu-
late matter, and sulfur dioxide (SO2).46 Two transport
modes are addressed under the IPCC definition of inter-
national bunker fuels: aviation and marine. Emissions from
ground transport activities—by road vehicles and
trains—even when crossing international borders are al-
located to the country where the fuel was loaded into the
vehicle and, therefore, are not counted as bunker fuel
emissions.
The IPCC Guidelines distinguish between different
modes of air traffic. Civil aviation comprises aircraft used
for the commercial transport of passengers and freight,
military aviation comprises aircraft under the control of
Table 2-33: Total Natural Gas Reported
Vented and Flared (Million Ft3) and
Thermal Conversion Factor (Btu/Ft3)
7 Year
1 1990
1991
-- 1992
; 1993
1994
--• 1995
: 1996
1997
• 1998
T 1999
Vented and
Flared
150,415
169,909
167,519
226,743
228,336
283,739
272,117
256,351
234,472
245,180
Thermal
Conversion
Factor
1,106
1,108
1,110
1,106
1,105
1,106
1,109
1,107
1,110
1,111
national armed forces, and general aviation applies to
recreational and small corporate aircraft. The IPCC Guide-
lines further define international bunker fuel use from
civil aviation as the fuel combusted for civil (e.g., com-
mercial) aviation purposes by aircraft arriving or depart-
ing on international flight segments. However, as men-
tioned above, and in keeping with the IPCC Guidelines,
only the fuel purchased in the United States and used by
aircraft taking-off (i.e., departing) from the United States
are reported here. The standard fuel used for civil avia-
tion is kerosene-type jet fuel, while the typical fuel used
for general aviation is aviation gasoline.47
Emissions of CO2 from aircraft are essentially a func-
tion of fuel use. Methane, N2O, CO, NOX, and NMVOC
emissions also depend upon engine characteristics, flight
conditions, and flight phase (i.e., take-off, climb, cruise,
decent, and landing). Methane, CO, and NMVOCs are the
product of incomplete combustion and occur mainly dur-
ing the landing and take-off phases. In jet engines, N2O
and NOX are primarily produced by the oxidation of atmo-
spheric nitrogen, and the majority of emissions occur dur-
ing the cruise phase. The impact of NOX on atmospheric
** See report of the Intergovernmental Negotiating Committee for a Framework Convention on Climate Change on the work of its
ninth session, held at Geneva from 7 to 18 February 1994 (A/AC.237/55, annex I, para. Ic) (contact secretariat@unfccc.de).
45 Note that the definition of international bunker fuels used by the UNFCCC differs from that used by the International civil Aviation
Organization.
46 Sulfur dioxide emissions from jet aircraft and marine vessels, although not estimated here, are mainly determined by the sulfur content
of the fuel. In the U.S., jet fuel, distillate diesel fuel, and residual fuel oil average sulfur contents of 0.05, 0.3, and 2.3 percent,
respectively. These percentages are generally lower than global averages.
47 Naphtha-type jet fuel is used primarily by the military in turbojet and turboprop aircraft engines.
2-40 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
chemistry depends on the altitude of the actual emission.
The cruising altitude of supersonic aircraft, near or in the
ozone layer, is higher than that of subsonic aircraft. At
this higher altitude, NOX emissions contribute to ozone
depletion.48 At the cruising altitudes of subsonic aircraft,
however, NOX emissions contribute to the formation of
ozone. At these lower altitudes, the positive radiative forc-
ing effect of ozone is most potent.49 The vast majority of
aircraft NOX emissions occur at these lower cruising alti-
tudes of commercial subsonic aircraft (NASA 1996).50
International marine bunkers comprise emissions
from fuels burned by ocean-going ships of all flags that
are engaged in international transport. Ocean-going ships
are generally classified as cargo and passenger carrying,
military (i.e., Navy), fishing, and miscellaneous support
ships (e.g., tugboats). For the purpose of estimating
greenhouse gas emissions, international bunker fuels are
solely related to cargo and passenger carrying vessels,
which is the largest of the four categories, and military
vessels. Two main types of fuels are used on sea-going
vessels: distillate diesel fuel and residual fuel oil. Carbon
dioxide is the primary greenhouse gas emitted from ma-
rine shipping. In comparison to aviation, the atmospheric
impacts of NOX from shipping are relatively minor, as the
emissions occur at ground level.
Overall, aggregate greenhouse gas emissions in
1999 from the combustion of international bunker fuels
from both aviation and marine activities were 108.3 Tg
CO2 Eq., or 6 percent below emissions in 1990 (see Table
2-34). Although emissions from international flights de-
parting from the United States have increased signifi-
cantly (30 percent), emissions from international ship-
ping voyages departing the United States appear to have
decreased by 31 percent since 1990. Increased military
activity during the Persian Gulf War resulted in an in-
creased level of military marine emissions in 1990 and
1991; civilian marine emissions during this period exhib-
ited a similar trend.51 The majority of these emissions
were in the form of carbon dioxide; however, small amounts
of CH4 and N2O were also emitted. Of the criteria pollut-
ants, emissions of NOX by aircraft at cruising altitudes are
of primary concern because of their effects on ozone for-
mation (see Table 2-35).
Emissions from both aviation and marine interna-
tional transport activities are expected to grow in the fu-
ture as both air traffic and trade increase, although emis-
sion rates should decrease over time due to technologi-
cal changes.52
Methodology
Emissions of CO2 were estimated through the ap-
plication of carbon content and fraction oxidized factors
to fuel consumption activity data. This approach is analo-
gous to that described under CO2 from Fossil Fuel Com-
bustion. A complete description of the methodology and
a listing of the various factors employed can be found in
Annex A. See Annex H for a specific discussion on the
methodology used for estimating emissions from inter-
national bunker fuel use by the U.S. military.
Emission estimates for CH4, N2O, CO, NOX, and
NMVOCs were calculated by multiplying emission fac-
tors by measures of fuel consumption by fuel type and
mode. Activity data for aviation included solely jet fuel
consumption statistics, while the marine mode included
both distillate diesel and residual fuel oil.
Data Sources
Carbon content and fraction oxidized factors for
kerosene-type and naphtha-type jet fuel, distillate fuel
oil, and residual fuel oil were taken directly from the En-
ergy Information Administration (EIA) of the U.S. De-
partment of Energy and are presented in Annex A. Heat
content and density conversions were taken from EIA
(2000) and USAF (1998). Emission factors used in the
48 In 1996, there were only around a dozen civilian supersonic aircraft in service around the world which flew at these altitudes, however.
49 However, at this lower altitude, ozone does little to shield the earth from ultraviolet radiation.
50 Cruise altitudes for civilian subsonic aircraft generally range from 8.2 to 12.5 km (27,000 to 41,000 feet).
51 See Uncertainty section for a discussion of data quality issues.
52 Most emission related international aviation and marine regulations are under the rubric of the International Civil Aviation
Organization (ICAO) or the International Maritime Organization (IMO), which develop international codes, recommendations, and
conventions, such as the International Convention of the Prevention of Pollution from Ships (MARPOL).
Energy 2-41
-------
Table 2-34: Emissions from International Bunker Fuels (Tg C02 Eq.)
Gas/Mode
1990
1995
1996
1997
1998
+ Does not exceed 0.05 Tg C02 Eq.
Note: Totals may not sum due to independent rounding. Includes aircraft cruise altitude emissions.
1999
C02
Aviation
Marine
CH4
Aviation
Marine
N20
Aviation
Marine
Total
114.0
46.7
67.3
+
+
+
1.0
0.5
0.5
115.0
101.0
51.1
49.9
+
+
+
0.9
0.5
0.4
101.9
102.2
52.1
50.1
+
+
+
0.9
0.5
0.4
103.1
109.8
55.9
53.9
+
+
+
1.0
0.5
0.4
110.8
112.8
55.0
57.8
+
+.
+
1.0
0.5
0.4
113.8
107.3
61.0
46.4
+
+
+
1.0
0.6
0.4
108.3
Table 2-35: Emissions from International Bunker Fuels (Gg)
Gas/Mode
C02
Aviation
Marine
CH4
Aviation
Marine
N20
Aviation
Marine
CO
Aviation
Marine
NO,
Aviation
Marine
NMVOC
Aviation
Marine
Note: Totals may
1990
114,001
46,728
67,272
2
1
1
3
1
2
116
77
39
1,987
184
1,803
59
12
48
not sum due to independent rounding.
1995
101,014
51,093
49,921
2
1
0
3
2
1
113
84
29
1,541
202
1,339
48
13
36
Includes
1996
102,197
52,135
50,062
2
1
0
3
2
1
115
86
29
1,548
207
1,341
49
13
36
aircraft cruise altitude
1997
109,788
55,899
53,889
2
2
0
3
2
1
124
92
32
1,665
221
1,444
52
14
38
emissions.
1998
112,771
54,988
57,783
2
2
1
3
2
1
124
91
34
1,768
218
1,550
55
14
41
1999
107,345
60,970
46,376
2
2
0
3
2
1
128
100
27
1,485
242
1,243
48
15
33
calculations of CH4, N2O, CO, NOX, and NMVOC emis-
sions were taken from the Revised 1996IPCC Guide-
lines (IPCC/UNEP/OECD/ffiA 1997). For aircraft emis-
sions, the following values, in units of grams of pollutant
per kilogram of fuel consumed (g/kg), were employed:
0.09 forCH4,0.1 forN2O,5.2forCO, 12.5 for NOX, and 0.78
for NMVOCs. For marine vessels consuming either distil-
late diesel or residual fuel oil the following values, in the
same units, except where noted, were employed: 0.03 for
CH4,0.08 for N20,1.9 for CO, 87 forNOx, and 0.052 g/MJ
forNMVOCs.
Activity data on aircraft fuel consumption were
collected from three government agencies. Jet fuel con-
sumed by U.S. flag air carriers for international flight seg-
ments was supplied by the Bureau of Transportation Sta-
tistics (DOT/BTS 2000). It was assumed that 50 percent
of the fuel used by U.S. flagged carriers for international
flights—both departing and arriving in the United States—
was purchased domestically for flights departing from
the United States. In other words, only one-half of the
total annual fuel consumption estimate was used in the
calculations. Data on jet fuel expenditures by foreign
2-42 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
flagged carriers departing U.S. airports was taken from
unpublished data collected by the Bureau of Economic
Analysis (BEA) under the U.S. Department of Commerce
(BEA 2000). Approximate average fuel prices paid by air
carriers for aircraft on international flights was taken from
DOT/BTS (2000) and used to convert the BEA expendi-
ture data to gallons of fuel consumed. Data on jet fuel
expenditures by the U.S. military was supplied by the
Office of the Under Secretary of Defense (Environmental
Security), U.S. Department of Defense (DoD). Estimates
of the percentage of each services' total operations that
were international operations were developed by DoD.
Military aviation bunkers included international opera-
tions, operations conducted from naval vessels at sea,
and operations conducted from U.S. installations princi-
pally over international water in direct support of military
operations at sea. Data on fuel delivered to the military
within the United States was provided from unpublished
data by the Defense Energy Support Center, under DoD's
Defense Logistics Agency (DESC 2000). Together, the
data allow the quantity of fuel used in military interna-
tional operations to be estimated. Jet fuel densities for
each fuel type were obtained from a report from the U.S.
Air Force (USAF 1998). Final jet fuel consumption esti-
mates are presented in Table 2-36. See Annex H for addi-
tional discussion of military data.
Activity data on distillate diesel and residual fuel
oil consumption by cargo or passenger carrying marine
vessels departing from U.S. ports were taken from un-
published data collected by the Foreign Trade Division
of the U.S. Department of Commerce's Bureau of the Cen-
sus (DOC 2000). Activity data on distillate diesel con-
sumption by military vessels departing from U.S. ports
were provided by the Defense Energy Support Center
(DESC). The total amount of fuel provided to naval ves-
sels was reduced by 13 percent to account for fuel used
while the vessels were not-underway (i.e., in port). Data
on the percentage of steaming hours underway versus
not-underway were provided by the U.S. Navy. These
fuel consumption estimates are presented in Table 2-37.
Uncertainty
Emission estimates related to the consumption of
international bunker fuels are subject to the same uncer-
tainties as those from domestic aviation and marine mo-
bile combustion emissions; however, additional uncer-
tainties result from the difficulty in collecting accurate
fuel consumption activity data for international transport
activities separate from domestic transport activities.53
For example, smaller aircraft on shorter routes often carry
sufficient fuel to complete several flight segments with-
out refueling hi order to minimize time spent at the airport
gate or take advantage of lower fuel prices at particular
airports. This practice, called tankering, when done on
international flights, complicates the use of fuel sales
data for estimating bunker fuel emissions. Tankering is
less common with the type of large, long-range aircraft
that make many international flights from the United
States, however. Similar practices occur in the marine ship-
ping industry where fuel costs represent a significant
portion of overall operating costs and fuel prices vary
from port to port, leading to some tankering from ports
with low fuel costs.
Particularly for aviation, the DOT/BTS (2000) inter-
national flight segment fuel data used for U.S. flagged
carriers does not include smaller air carriers and unfortu-
nately defines flights departing to Canada and some
flights to Mexico as domestic instead of international. As
Table 2-36: Aviation Jet Fuel Consumption for International Transport (Million Gallons)
- Nationality
jitLSJCaniers
, Foreign Carriers
; U.S. Military
\ total
SIR-:,,.,, .1. -".,,•--
1990
. . •»-«"»
2;062 ***""-*
862 -^ ;='";;'
4,905 i_:r
1995
2,256
2,549
581
5,385
1996
2,329
2,629
540
5,497
1997
2,482
2,918
496
5,895
1998
2,363
2,935
502
5,799
1999
2,638
3,305
488
6,431
Note: Totals may not sum due to independent rounding.
1 See uncertainty discussions under CO2 from Fossil Fuel Combustion and Mobile Combustion.
Energy 2-43
-------
Table 2-37: Marine Fuel Consumption for International Transport (Million Gallons)
Fuel Type 1990 "
Residual Fuel Oil 4,781
Distillate Diesel Fuel & Other 617 '"
U.S. Military Naval Fuels 522 = -
Total 5,920
1995
3,495
573
334
4,402
1996
3,583
456
362
4,402
1997
3,843
421
477
4,740
1998
3,974
627
506
5,107
1999
3,272 : :
308
506
4,085
Note: Totals may not sum due to Independent rounding.
for the BEA (2000) data on foreign flagged carriers, there
is some uncertainty as to the average fuel price, and to
the completeness of the data. It was also not possible to
determine what portion of fuel purchased by foreign car-
riers at U.S. airports was actually used on domestic flight
segments; this error, however, is believed to be small.54
Uncertainties exist with regard to the total fuel used
by military aircraft and ships, and in the activity data on
military operations and training that were used to esti-
mate percentages of total fuel use reported as bunker fuel
emissions. There are also uncertainties in fuel end-use
consumption by fuel-type, emissions factors, fuel densi-
ties, diesel fuel sulfur content, and aircraft and vessel
engine characteristics and fuel efficiencies.
Total aircraft and ship fuel use estimates were de-
veloped from DoD records, which document fuel sold to
the Navy and Air Force from the Defense Logistics
Agency. This data may slightly over or under estimate
actual total fuel use in aircraft and ships because each
service may have procured fuel from, and/or may have
sold to, traded with, and/or given fuel to other ships,
aircraft, governments, or other entities. Small fuel quanti-
ties may have been used in vehicles or equipment other
than that which was assumed for each fuel type.
There are uncertainties hi aircraft operations and
training activity data. Estimates for the quantity of fuel
actually used in Navy and Air Force flying activities re-
ported as bunker fuel emissions had to be estimated based
on a combination of available data and expert judgements.
Estimates of marine bunker fuel emissions were
based on Navy vessel steaming hour data which reports
fuel used while underway and fuel used while not under-
way; however, this approach does not capture some voy-
ages which could be classified as domestic.
There is also uncertainty in the methodology used
to estimate emissions for 1990 through 1994. These emis-
sions were estimated based on the 1995 values of the
original data set and extrapolated back in time based on a
closely correlating, but not matching, data set of fuel
usage.
The magnitude of the potential errors related to the
various uncertainties has not been calculated, but is be-
lieved to be small. The uncertainties associated with fu-
ture military bunker fuel emissions estimates could be
reduced through additional data collection.
Although aggregate fuel consumption data has
been used to estimate emissions from aviation, the rec-
ommended method for estimating emissions of gases other
than CO2 in the Revised 1996IPCC Guidelines is to use
data by specific aircraft type (IPCC/UNEP/OECD/TEA
1997). The IPCC also recommends that cruise altitude
emissions be estimated separately using fuel consump-
tion data, while landing and take-off (LTO) cycle data be
used to estimate near-ground level emissions of gases
other than CO2.55 The EPA is developing revised esti-
^ Although foreign flagged air carriers are prevented from providing domestic flight services in the United States, passengers may be
collected from multiple airports before an aircraft actually departs on its international flight segment. Emissions from these earlier
domestic flight segments should be classified as domestic, not international, according to the IPCC.
ss It should be noted that in the EPA's National Air Pollutant Emissions Trends, 1900-1999 (EPA 2000), U.S. aviation emission
estimates for CO, NOx, and NMVOCs are based solely upon LTO cycles and consequently only capture near ground-level emissions,
which are more relevant for air quality evaluations. These estimates also include both domestic and international flights. Therefore,
estimates given under Mobile Source Fossil Fuel Combustion overestimate IPCC-defined domestic CO, NOX, and NMVOC emissions by
including landing and take-off (LTO) cycles by aircraft on international flights but underestimate because they do not include emissions
from aircraft on domestic flight segments at cruising altitudes. EPA (1998) is also likely to include emissions from ocean-going vessels
departing from U.S. ports on international voyages.
2-44 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
mates based on this more detailed activity data, and these
estimates are to be presented hi future inventories.
There is also concern as to the reliability of the
existing DOC (2000) data on marine vessel fuel consump-
tion reported at U.S. customs stations due to the signifi-
cant degree of inter-annual variation.
Wood Biomass
and Ethano! 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 carbon
dioxide emitted from biomass consumption does not in-
crease atmospheric carbon dioxide concentrations, assum-
ing the biogenic carbon emitted is offset by the uptake of
CO2 resulting from the growth of new biomass. As a re-
sult, CO2 emissions from biomass combustion have been
estimated separately from fossil fuel-based emissions and
are not included in the U.S. totals. Net carbon fluxes from
changes hi biogenic carbon reservoirs in wooded or crop
lands are accounted for hi the Land-Use Change and For-
estry chapter.
In 1999, CO2 emissions due to burning of woody
biomass within the industrial and residential/commercial
sectors and by electric utilities were about 226.3 Tg CO2
Eq. (226 Gg) (see Table 2-38 and Table 2-39). As the largest
consumer of woody biomass, the industrial sector in 1999
was responsible for 83 percent of the CO2 emissions from
this source. The residential sector was the second largest
emitter, making up 14 percent of total emissions from
woody biomass. The commercial end-use sector and elec-
tric utilities accounted for the remainder.
Biomass-derived fuel consumption in the United
States consisted mainly of ethanol use in the transporta-
tion sector. Ethanol is primarily produced from corn grown
in the Midwest, and was used mostly hi the Midwest and
South. Pure ethanol can be combusted, or it can be mixed
with gasoline as a supplement or octane-enhancing agent.
The most common mixture is a 90 percent gasoline, 10
percent ethanol blend known as gasohol. Ethanol and
ethanol blends are often used to fuel public transport ve-
hicles such as buses, or centrally fueled fleet vehicles.
Ethanol and ethanol blends are believed to burn "cleaner"
than gasoline (i.e., lower in NOX and hydrocarbon emis-
sions), and have been employed in urban areas with poor
air quality. However, because ethanol is a hydrocarbon
fuel, its combustion emits CO2.
Table 2-38: C02 Emissions from Wood Consumption by End-Use Sector (Tg C02 Eq.)
1 End-Use Sector
^Industrial
| Residential
a Commercial
fleciric Utility
J Total
1990
. 1248
46.4 *~" -
3.0
0.7 **• "
174.9 „, _,
1995
141.5
47.6
3.6
0.5
193.2
1996
144.9
47.5
3.9
0.7
197.0
1997
148.6
34.6
3.8
0.6
187.6
1998
153.0
30.1
3.7
0.6
187.4
1999
188.9
32.3
4.5
0.6
226.3
CNbte: Totals may not sum due to independent rounding.
Table 2-39: C02 Emissions from Wood Consumption by End-Use Sector (Gg)
I End-Use Sector 1990 _ """ ' 1995 1996 1997
1998
1999
^Industrial
t Residential
| Commercial
plectric Utility
Itotal
filote: Totals may
124,808 ^
46,424 -
2,956 * * *_
673 t
174,862
not sum due to independent rounding.
141,505
47,622
3,596
522
193,245
144,881
47,542
3,899
651
196,973
148,624
34,598
3,752
612
187,585
152,966
30,123
3,749
595
187,433
188,915
32,281
4,526
566
226,287
Energy 2-45
-------
In 1999, the United States consumed an estimated
112 trillion Btus of ethanol. Emissions of CO2 in 1999 due
to ethanol fuel burning were estimated to be approximately
7.8TgC02Eq. (7,776 Gg) (see Table 2-40).
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 (EIA1997). Production in 1998 and
1999 returned to normal historic levels.
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 es-
Table 2-40: C02 Emissions from
Ethanol Consumption
Year
1990
1995
1996
1997
1998
1999
Tg C02 Eq.
5.7
7.2
5.1
6.7
7.3
7.8
Gg
5,701
7,244
5,144
6,731
7,329
7,776
Table 2-41: Woody Biomass
Consumption by Sector (Trillion Btu)
timated using 87 percent for the fraction oxidized (i.e., com-
bustion 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 (2000) (see Table 2-41). Estimates of wood biomass con-
sumption for fuel combustion do not include wood wastes,
liquors, municipal solid waste, tires, etc. that are reported as
biomass by EIA. The factor for converting energy units to
mass was supplied by EIA (1994). Carbon content and com-
bustion efficiency values were taken from the Revised 1996
IPCC Guidelines (EPCC/UNEP/OECD/IEA1997).
Emissions from ethanol were estimated using con-
sumption data from EIA (2000) (see Table 2-42). The carbon
coefficient used was provided by OTA (1991).
Uncertainty
The fraction oxidized (i.e., combustion efficiency)
factor used is believed to under estimate the efficiency of
wood combustion processes in the United States. The
IPCC emission factor has been used because better data
are not yet available. Increasing the combustion efficiency
would increase emission estimates. In addition, according
to EIA (1994) commercial wood energy use is typically not
reported because there are no accurate data sources to
provide reliable estimates. Emission estimates from etha-
nol production are more certain than estimates from woody
biomass consumption due to better activity data collec-
tion methods and uniform combustion techniques.
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Industrial
1,562
1,528
1,593
1,625
1,724
1,771
1,813
1,860
1,914
2,364
Residential
581
613
645
548
537
596
595
433
377
404
Commercial
37
39
42
44
45
45
49
47
47
57
Electric
Utility
8 . • -
8
8
9
8
7
8
8
7
7
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Trillion Btu
82
65
78
88
97
104
74
97
105
112
2-46 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
3. Industrial
Greenhouse gas emissions are produced as a by-product of various non-energy-related industrial activities.
That is, these emissions are produced from an industrial process itself and are not directly a result of energy
consumed during the process. For example, raw materials can be chemically transformed from one state to another. This
transformation can result in the release of greenhouse gases such as carbon dioxide (CO2), methane (CH^, or nitrous
oxide (N2O). The processes addressed hi this chapter include cement production, lime manufacture, limestone and
dolomite use (e.g., flux stone, flue gas desulfurization, and glass manufacturing), soda ash production and use, CO2
consumption, iron and steel production, ammonia manufacture, ferroalloy production, aluminum production, petrochemi-
cal production, silicon carbide production, adipic acid production, and nitric acid production (see Figure 3-1).:
In addition to the three
greenhouse gases listed above, Figure 3-1
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 ef-
fect of all anthropogenic green-
house gases is small; however,
because of their extremely long
lifetimes, they will continue to ac-
cumulate in the atmosphere as
long as emissions continue. Sul-
fur 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
Substitution of Ozone Depleting Substances
Cement Manufacture
HCFC-22 Production
Electrical Transmission and Distribution
Nitric Acid
Lime Manufacture
Aluminum Production
Adipic Acid
Limestone and Dolomite Use
Semiconductor Manufacture
Magnesium Production and Processing
Soda Ash Manufacture and Consumption
Petrochemical Production
Carbon Dioxide Consumption
Silicon Carbide Production
Bi
Portion of
All Emissions
<0.05
10
20 30 40
Tg CO2 Eq.
50
60
1 Carbon dioxide emissions from iron and steel production, ammonia manufacture, ferroalloy production, and aluminum production are
accounted for in the Energy chapter under Fossil Fuel Combustion of industrial coking coal, natural gas, and petroleum coke.
industrial Processes 3-1
-------
primary substitutes for ozone depleting substances
(ODSs), which are being phased-out under the Montreal
Protocol on Substances that Deplete the Ozone Layer.
In addition to ODS substitutes, MFCs, PFCs, and other
fluorinated compounds are employed and emitted by a
number of other industrial sources in the United States.
These industries include aluminum production, HCFC-22
production, semiconductor manufacture, electric power
transmission and distribution, and magnesium metal pro-
duction and processing.
In 1999, industrial processes generated emissions
of 234.0 Tg CO2 Eq., or 3.5 percent of total U.S. green-
house gas emissions. Carbon dioxide emissions from all
industrial processes were 67.4 Tg CO2 Eq. (67,401 Gg) in
the same year. This amount accounted for only 1.2 per-
cent of national CO2 emissions. Methane emissions from
petrochemical and silicon carbide production resulted in
emissions of approximately 1.7 Tg CO2 Eq. (80 Gg) in
1999, which was less than 1 percent of U.S. CH4 emis-
sions. Nitrous oxide emissions from adipic acid and nitric
acid production were 29.2 Tg CO2 Eq. (94 Gg) hi 1999, or
6.8 percent of total U.S. N2O emissions. In the same year,
combined emissions of MFCs, PFCs and SF6 totaled 135.7
Tg CO2 Eq. Overall, emissions from industrial processes
increased by 33 percent from 1990 to 1999, which was the
result of increases in emissions from several industrial
processes—the largest being substitutes for ozone de-
pleting substances—which was offset by decreases in
emissions from adipic acid production, aluminum produc-
tion, and production of HCFC-22.
Emission estimates are presented in this chapter
for several industrial processes that are actually accounted
for within the Energy chapter. Although process-related
CO2 emissions from iron and steel production, ammonia
manufacture, ferroalloy production, and aluminum pro-
duction are not the result of the combustion of fossil
fuels for energy, then: 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 thek
appropriate chapter, then emissions from energy would
decrease by approximately 105.0 Tg CO2 Eq. in 1999, 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 chapter. For
example, caprolactam—a chemical feedstock for the manu-
facture of nylon 6,6—and urea production are believed to
be industrial sources of N2O emissions. However, emis-
sions for these and other sources have not been esti-
mated 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 thek 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), in-
volves multiplying production data for each process by
an emission factor per unit of production. The emission
factors used were either derived using calculations that
assume precise and efficient chemical reactions or were
based upon empirical data in published references. As a
result, uncertainties in the emission coefficients can be
attributed to, among other things, inefficiencies in the
chemical reactions associated with each production pro-
cess 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 spe-
cific to an individual source category are discussed in
each section.
Table 3-1 summarizes emissions for the Industrial
Processes chapter in units of teragrams of carbon dioxide
equivalents (Tg CO2 Eq.), while unweighted gas emis-
sions in gigagrams (Gg) are provided in Table 3-2.
- Sec Annex P for a discussion of emission sources excluded.
3-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 3-1: Emissions from Industrial Processes (Tg C02 Eq.)
JGas/Source
1990
1996
1997
1998
1999
po2 •'.'''•••.. ':
jp7" Cement Manufacture
E~ Lime Manufacture
| ,- Limestone and Dolomite Use
I: Soda Ash Manufacture and Consumption
K Carbon Dioxide Consumption
!r- Iron and Steel Production*
|" Ammonia Manufacture*
§*"'•'•" .""Ferroalloy Production*
:,: Aluminum Production*
*CH
|En. Petrochemical Production
§1 Silicon Carbide Production
FN o
r. Nitric Acid Production
p Adipic Acid Production
pFCs, PFCs, and SF6
t~- Substitution of Ozone Depleting Substances
|; HCFC-22 Production
& Electrical Transmission and Distribution
P.T: Aluminum Production
1- Semiconductor Manufacture
|- Magnesium Production and Processing
rtotal
54.6
33.3
11.2
5.1
4.1
0.8
87.6
23.1
1.8
6.0
1.2
1.2
• +
36.1
17.8
18.3
83.9
0.9
34.8
20.5
19.3
2.9
5.5
175.8
61.9
36.8
°~ 12.8
' ~~ 7.0
4.3
" " * 1.0
81.4
23.7
1.6
«_ . 5 Q
*"""* * 1.5
jsm ^ 1.5
+
40.2
19.9
20.3
99.0
24.0
27.1
^ 25.7 :
"**** " 11.2
_*"""' 5.5
5.5
««.,.., 2Q2J
63.3
37.1
13.5
7.3
4.3
1.1
79.0
24.4
1.7
5.3
1.6
1.6
-f
41.5
20.7
20.8
115.1
34.0
31.2
25.7
11.6
7.0
5.6
221.5
66.1
38.3
13.7
8.3
4.4
1.3
79.4
24.3
1.8
5.3
1.6
1.6
H-
38.3
21.2
17.1
123.3
42.1
30.1
25.7
10.8
7.0
7.5
229.3
67.0
39.2
13.9
8.1
4.3
1.4
77.1
25.1
.1.8
5.5
1.6
1.6
+
28.1
20.9
7.3
138.6
49.6
40.0
25.7
10.1
6.8
6.3
235.3
67.4
39.9
13.4
8.3
4.2
1.6
71.8
25.8
1.8
5.6
1.7
1.7
+
29.2
20.2
9.0
135.7
56.7
30.4
25.7
10.0
6.8
6.1
234.0
if'+Does not exceed 0.05 Tg C02 Eq.
&*'• Emissions from these sources are accounted for in the Energy chapter and are not included in the Industrial Processes totals.
j Note: Totals may not sum due to independent rounding.
Cement Manufacture
Cement manufacture is an energy and raw material
intensive process resulting in the generation of carbon
dioxide (CO2) from both the energy consumed in making
the cement and the chemical process itself.3 Cement pro-
duction has accounted for about 2.4 percent of total glo-
bal industrial and energy-related CO2 emissions (IPCC
1996), and the United States is the world's third largest
cement producer. Cement is manufactured in almost ev-
ery State and is used in all of them. Carbon dioxide emit-
ted from the chemical process of cement production rep-
resents one of the largest sources of industrial CO2 emis-
sions in the United States.
During the cement production process, calcium
carbonate (CaCO3) is heated in a cement kiln at a tem-
perature of about 1,300°C (2,400°F) to form lime (i.e., cal-
cium oxide or CaO) and CO2. This process is known as
calcination or calcining. Next, the lime is combined with
silica-containing materials to produce clinker (an inter-
mediate product), with the earlier by-product CO2 being
released to the atmosphere. The clinker is then allowed to
cool, mixed with a small amount of gypsum, and used to
make Portland cement. The production of masonry ce-
ment from Portland cement requires additional lime and,
thus, results in additional CO2 emissions. However, this
additional lime is already accounted for in the Lime Manu-
facture source category in this chapter; therefore, the
additional emissions from making masonry cement from
clinker are not counted in this source category's total.
They are presented here for informational purposes only.
In 1999, U.S. clinker production—including Puerto
Rico—totaled 77,152 thousand metric tons, and U.S. ma-
sonry cement production was estimated to be 4,127 thou-
sand metric tons (USGS 2000). The resulting emissions of
3 The CO2 emissions related to the consumption of energy for cement manufacture are accounted for under CO2 from Fossil Fuel
Combustion in the Energy chapter.
Industrial Processes 3-3
-------
Table 3-2: Emissions from Industrial Processes (Gg)
Gas/Source
1990
1995
1996
1997
1998
1999
CO,
Cement Manufacture
Lime Manufacture
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Carbon Dioxide Consumption
Iron and Steel Production3
Ammonia Manufacture3
Ferroalloy Production1
Aluminum Production1
CH4
Petrochemical Production
Silicon Carbide Production
H20
Nitric Acid Production
Adipic Acid Production
MFCs, PFCs, and SF8
HCFC-22 Production6
Electrical Transmission and Distribution11
54,577
33,278
11,238
5,117
4,144
800
87,600
23,138
1,809
5,951
57
56
1
117
58
59
M ;
3 ,
1 ,. ,
Substitution of Ozone Depleting Substances M
Aluminum Production
Semiconductor Manufacture
Magnesium Production and Processing0
M
M -
+
61,917
36,847
12,805
6,987
4,309
968
81,440
23,682
1,625
4,961
72
72
1
130
64
66
M
2
1
M
M
M
+
63,293
37,079
13,495
7,305
4,273
1,140
79,040
24,390
1,695
5,258
76
75
1
134
67
67
M
3
1
M
M
M
+
66,063
38,323
13,685
8,327
4,434
1,294
79,360
24,346
1,789
5,296
77
77
1
124
68
55
M
3
1
M
M
M
+
66,984
39,218
13,914
8,114
4,325
1,413
77,120
25,141
1,793
5,458
78
77
1
91
67
23
M
3
1
M
M
M
+ •
67,401
39,896
13,426
8,290
4,217
1,572
71,840
25,799
1,771
5,555
80
79
1
94
65
29
M
3
1
M
M
M
+
+ Does not exceed 0.5 Gg
M (Mixture of gases)
* Emissions from these sources are accounted for in the Energy chapter and are not included in the Industrial Processes totals.
6 HFC-23 emitted
c SF6 emitted
Note: Totals may not sum due to independent rounding.
CO2 from clinker production were estimated to be 39.9 Tg
CO2 Eq. (39,896 Gg) (see Table 3-3). Emissions from ma-
sonry production from clinker raw material were estimated
to be 0.09 Tg CO2 Eq. (93 Gg) in 1999, but again are ac-
counted for under Lime Manufacture.
After falling in 1991 by 2 percent from 1990 levels,
cement production emissions have grown every year
since. Overall, from 1990 to 1999, emissions increased by
20 percent. In 1999, output by cement plants increased 2
percent over 1998, to 77,152 thousand metric tons. 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, have had con-
siderable influence on cement production.
Table 3-3: C02 Emissions from Cement Production*
j Year Tg CO., Eq. Gg
1990
33.3
33,278
1995
i, 1996
- 1997
1998
1 1999
36.8
37.1
38.3
39.2
39.9
36,847
37,079
38,323
39,218
39,896
: * Totals exclude C02 emissions from making masonry cement
frbm clinker, which are accounted for under Lime Manufacture.
3-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Methodology
Carbon dioxide emissions from cement manufac-
ture are created by the chemical reaction of carbon-con-
taining minerals (i.e., calcining limestone). While in the
kiln, limestone is broken down into CO2 and lime with the
CO2 released to the atmosphere. The quantity of the CO2
emitted during cement production is directly proportional
to the lime content of the clinker. During calcination, each
mole of CaCO3 (i.e., limestone) heated in the clinker kiln
forms one mole of lime (CaO) and one mole of CO2:
CaCO3 + heat -> CaO + CO2
Carbon dioxide emissions were estimated by ap-
plying an emission factor, in tons of CO2 released per ton
of clinker produced, to the total amount of clinker pro-
duced. The emission factor used in this analysis is the
product of the average lime fraction for clinker of 64.6
percent (IPCC 2000) and a constant reflecting the mass of
CO2 released per unit of lime. This calculation yields an
emission factor of 0.507 tons of CO2 per ton of clinker
produced, which was determined as follows:
T 44.01 g/mole CO, 1
EFC]inker = 0.646 CaO x =
[ 56.08 g/mole CaO J
0.507 tons CO2/ton clinker
During clinker production, some of the clinker pre-
cursor materials remain in the kiln as non-calcinated, par-
tially calcinated, or fully calcinated cement kiln dust (CKD).
The emissions attributable to the calcinated portion of
the CKD are not accounted for by the clinker emission
factor. The IPCC recommends that these additional CKD
CO2 emissions should be estimated as 2 percent of the
CO2 emissions calculated from clinker production. Total
cement production emissions were calculated by adding
the emissions from clinker production to the emissions
assigned to CKD (IPCC 2000).
Masonry cement requires additional lime over and
above the lime used in clinker production. In particular,
non-plasticizer additives such as lime, slag, and shale are
added to the cement, increasing its weight by approxi-
mately 5 percent. Lime accounts for approximately 60 per-
cent 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 ev-
ery metric ton of masonry cement produced.
As previously mentioned, the CO2 emissions from
the additional lime added during masonry cement pro-
duction are 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 clinker and masonry cement
production (see Table 3-4) were obtained from U.S. Geo-
logical Survey (USGS 1992,1995a, 1995b, 1996,1997,1998,
1999, 2000). The data were compiled by USGS through
questionnaires sent to domestic clinker and cement manu-
facturing plants. The 1999 value for masonry cement pro-
duction was calculated by applying the average annual
growth rate for 1995 through 1998 to the reported 1998
masonry cement production value.
Uncertainty
The uncertainties contained in these estimates are
primarily due to uncertainties in the lime content of clin-
ker, in the amount of lime added to masonry cement, and
in the percentage of CKD recycled inside the clinker kiln.
The lime content of clinker varies from 64 to 66 percent.
CKD loss can range from 1.5 to 8 percent depending upon
plant specifications. Additionally, some amount of CO2 is
Table 3-4: Cement Production (Gg)
Year
Clinker
Masonry
\ 1990
1991
--••"-• 1992
1993
r" 1994
L ' 1995
r::--.- 1996
?^V 1997
=-- 1998
1999
64,355
62,918
63,415
66,957
69,786
71,257
71,706
74,112
75,842
77,152
3,209
2,856
3,093
2,975
3,283
3,603
3,469
3,634
3,989
4,127
Industrial Processes 3-5
-------
reabsorbed when the cement is used for construction. As
cement reacts with water, alkaline substances such as
calcium hydroxide are formed. During this curing pro-
cess, these compounds may react with CO2 in the atmo-
sphere to create calcium carbonate. This reaction only
occurs in roughly the outer 0.2 inches of surface area.
Because the amount of CO2 reabsorbed is thought to be
minimal, it was not estimated.
Lime Manufacture
Lime is an important manufactured product with
many industrial, chemical, and environmental applications.
Its major uses are in steel making, flue gas desulfurization
(FGD) at coal-fired electric power plants, construction,
pulp and paper manufacturing, and water purification.
Lime has historically ranked fifth in total production of all
chemicals in the United States. For U.S. operations, the
term "lime" actually refers to a variety of chemical com-
pounds. These include calcium oxide (CaO), or high-cal-
cium quicklime; calcium hydroxide (Ca(OH):2), or hydrated
lime; dolomitic quicklime ([CaOMgO]); and dolomitic
hydrate ([Ca(OH)2- MgO] or [Ca(OH)2'Mg(OH)2\).
Lime production involves three main processes:
stone preparation, calcination, and hydration. Carbon
dioxide is generated during the calcination stage, when
limestone—mostly calcium carbonate (CaCO3)—is
roasted at high temperatures in a kiln to produce CaO and
Table 3-5: Net C02 Emissions
from Lime Manufacture
Year
1990
i ""::..
1995
1996
1997
1998
1999
Tg CO, Eq.
11.2
12.8
13.5
13.7
13.9
13.4
I
CO2. The CO2 is driven off as a gas and is normally emit-
ted to the atmosphere. Some of the CO2 generated during
the production process, however, is recovered at some
facilities for use in sugar refining and precipitated cal-
cium carbonate (PCC)4 production. It is also important to
note that, for certain applications, lime reabsorbs CO2
during use (see Uncertainty, below).
Lime production in the United States—including
Puerto Rico—was reported to be 19,618 thousand metric
tons in 1999 (USGS 2000). This resulted in estimated CO2
emissions of 13.4 Tg CO2 Eq. (13,426 Gg) (see Table 3-5
and Table 3-6).
At the turn of the century, over 80 percent of lime
consumed in the United States went for construction uses.
The contemporary quicklime market is distributed across
its four end-use categories as follows: metallurgical uses,
39 percent; chemical and industrial uses, 26 percent; en-
vironmental uses, 24 percent; and construction uses, 11
percent. Construction end-uses are still important to the
hydrated lime market, accounting for 54 percent of con-
sumption. However, hydrated lime constitutes only 10
percent of the total lime market.
Lime production in 1999 declined 2 percent from
1998, the first drop in annual production since 1991. Over-
all, from 1990 to 1999, lime production increased by 24
percent. The increase in production is attributed in part
to growth in demand for environmental applications, es-
pecially flue gas desulfurization technologies. In 1993,
Table 3-6: C02 Emissions
from Lime Manufacture (Gg)
Year
:• 1990_^
pE^Bf
"1995
1996
1997
1998
1999
Potential
11,731
:^|filil:
13,702
14,348
14,649
14,975
14,609
Recovered*
(493)
(896)
(852)
(964)
(1,061)
(t,183)
Net
Emissions
11,238
"'•• •*:„*•-•'.* . - . ' : •„-
12,805
13,495
13,685
13,914
13,426
f*-_for sugar refining and precipitated calcium carbonate
I production. .
i jtote: Totals may not sum due to independent rounding.
** Precipitated calcium carbonate is a specialty filler used in premium-quality coated and uncoated papers.
3-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
the U.S. Environmental Protection Agency (EPA) com-
pleted regulations under the Clean Air Act capping sulfur
dioxide (SO2) emissions from electric utilities. Lime scrub-
bers' high efficiencies and increasing affordability have
allowed the FGD end-use to expand from 10 percent of
total lime consumption in 1990 to 14percentin 1999 (USGS
1992,2000).
Methodology
During the calcination stage of lime manufacture,
CO2 is driven off as a gas and normally exits the system
with the stack gas. To calculate emissions, the amounts
of high-calcium and dolomitic lime produced were multi-
plied by their respective emission factors. The emission
factor is the product of a constant reflecting the mass of
CO2 released per unit of lime and the average calcium
plus magnesium oxide (CaO + MgO) content for lime (95
percent for both types of lime). The emission factors were
calculated as follows:
Forhigh-calciumUme: [(44.01 g/moleCO2) -=- (56.08
g/mole CaO)] x (0.95 CaO/lime) = 0.75 g CO2/g lime
For dolomitic lime: [(88.02 g/mole CO^ -^ (97.01g/
mole CaO)] x (0.95 CaO/lime) = 0.86 g CO2/g lime
Production is adjusted to remove the mass of water
found in hydrated lime, using the midpoint of default
ranges provided by the IPCC Good Practice Guidance
(IPCC 2000). These factors set the water content to 27
percent for high-calcium hydrated lime, and 24 percent
for dolomitic hydrated lime.
Lime production in the United States was 19,618
thousand metric tons in 1999 (USGS 2000), resulting in
potential CO2 emissions of 14,609 Gg. Some pf 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 1,983 thousand metric
tons in 1999, generating 1.5 Tg of CO2. It was assumed
that approximately 80 percent of the CO2 involved in sugar
refining and PCC was recovered.
Data Sources
The activity data for lime manufacture and lime con-
sumption by sugar refining and precipitated calcium car-
bonate (PCC) for 1990 through 1992 (see Table 3-7) were
obtained from USGS (1992,1994,1995,1996,1997,1998,
1999,2000). The CaO and CaO-MgO contents of lime were
obtained from the IPCC Good Practice Guidance (IPCC
2000). Since data for the individual lime types was not
provided prior to 1997, total lime production for 1990
through 1996 was allocated according to the 1997 distri-
bution. For lime consumption, it was assumed that 100
percent was high-calcium based on communication with
the National Lime Association (Males 2001).
Uncertainty
Uncertainties in the emission estimate can be at-
tributed to slight differences in the chemical composition
of these products. Although the methodology accounts
for various formulations of lime, it does not account for
the trace impurities found in lime, such as iron oxide,
Table 3-7: Lime Production and Lime Use
for Sugar Refining and PCC (Thousand Metric Tons)
tets,». ,. . . .
'^^•' •' '
iMfear
fcl990
0:991
r
M993
Cr1994 -
'-1995
r-1996
P1997
|i1998
£=1999-...
High-Calcium
Production3
12,941
12,833
13,300
13,734
14,268
15,185
15,849
16,120
16,750
16,010
Dolomite
Production3'11
2,901
2,845
2,932
3,031
3,122
3,313
3,441
3,552
3,423
3,608
Use
826
964
1,023
1,279
1,374
1,503
1,429
1,616
1,779
1,983
pjncludes hydrated limes.
Ujncludes dead-burned, dolomite
Table 3-8: Hydrated Lime Production
(Thousand Metric Tons)
fc " " ' ""
~;v Year
2-— 1990
*--; 1991
~:: 1992
"--"••'"" 1993
J- 1994
K 1995
;, 1996
=:_.,,_ 1997
; • : 1998
**- •-: 1999
High-Calcium
Hydrate
1,777
1,836
1,887
1,904
1,938
2,023
1,853
1,820
1,950
1,910
Dolomitic
Hydrate
323
334
343
346
352
367
337
352
383
298
Industrial Processes 3-7
-------
alumina, and silica. Due to differences in the limestone
used as a raw material, a rigid specification of lime mate-
rial is impossible. As a result, few plants manufacture lime
with exactly the same properties.
In addition, a portion of the CO2 emitted during lime
manufacture will actually be reabsorbed when the lime is
consumed. As noted above, lime has many different chemi-
cal, industrial, environmental, and construction applica-
tions. In many processes, CO2 reacts with the lime to cre-
ate calcium carbonate (e.g., water softening). Carbon diox-
ide reabsorption rates vary, however, depending on the
application. For example, 100 percent of the lime used to
produce precipitated calcium carbonate (PCC) reacts with
CO2; whereas most of the lime used in steelmaking reacts
with impurities such as silica, sulfur, and aluminum com-
pounds. 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 reab-
sorbed.5 As more information becomes available, this emis-
sion estimate will be adjusted accordingly.
In some cases, lime is generated from calcium car-
bonate by-products at paper mills and water treatment
plants.6 The lime generated by these processes is not
included in the USGS data for commercial lime consump-
tion. In the paper industry, mills that employ the sulfate
process (i.e., Kraft) consume lime in order to causticize a
waste sodium carbonate solution (i.e., black liquor). Most
sulfate mills recover the waste calcium carbonate after
the causticizing operation and calcine it back into lime—
thereby generating CO2—for reuse in the pulping pro-
cess. However, some of these mills capture the CO2 re-
leased in this process to be used as precipitated calcium
carbonate (PCC). Further research is necessary to deter-
mine 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 process. Further
research is necessary to determine the degree to which
lime recycling is practiced by water treatment plants in
the United States.
Limestone and Dolomite Use
Limestone (CaCO3) and dolomite (CaCO3MgCO3)7
are basic raw materials used by a wide variety of indus-
tries, including construction, agriculture, chemical, met-
allurgy, glass manufacture, and environmental pollution
control. Limestone is widely distributed throughout the
world hi deposits of varying sizes and degrees of purity.
Large deposits of limestone occur in nearly every State in
the United States, and significant quantities are extracted
for industrial applications. For some of these applica-
tions, limestone is sufficiently heated during the process
to generate CO2 as a by-product. Examples of such appli-
cations include limestone used as a flux or purifier in
metallurgical furnaces, as a sorbent in flue gas desulfur-
ization (FGD) systems for utility and industrial plants, or
as a raw material in glass manufacturing.
In 1999, approximately 16,568 thousand metric tons
of limestone and 2,068 thousand metric tons of dolomite
were used for these applications. Overall, both limestone
and dolomite usage resulted in aggregate CO2 emissions
of 8.3 Tg CO2Eq. (8,290 Gg) (see Table 3-9 and Table 3-10).
Emissions in 1999 increased 2 percent from the previ-
ous year and 62 percent since 1990. In the future, increases
in demand for crushed stone are anticipated. Demand for
crushed stone from the transportation sector continues to
drive growth in limestone and dolomite use. The Transpor-
tation Equity Act for the 21st Century, which commits over
$200 billion dollars to highway work through 2003, is ex-
pected to maintain the upward trend in consumption.
5 Representatives of the National Lime Association estimate that CO2 reabsorption that occurs from the use of lime offsets as much as
a. third of the CO2 emissions from calcination.
* Some carbide producers may also regenerate lime from their calcium hydroxide by-products, which does not result in emissions of CO2.
In making calcium carbide, quicklime is mixed with coke and heated in electric furnaces. The regeneration of lime in this process is done
using a waste calcium hydroxide (hydrated lime) [CaCj + 2H2O -> C2H2 + CaCOEQJ, not calcium carbonate [CaCO3]. Thus, the calcium
hydroxide is heated in the kiln to simply expel the water [Ca(OH)2 + heat -» CaO + H2O] and no CO2 is released to the atmosphere.
7 Limestone and dolomite are collectively referred to as limestone by the industry, and intermediate varieties are seldom distinguished.
3-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 3-9: C02 Emissions from Limestone & Dolomite Use (Tg C02 Eq.)
! Activity 1990 1995 1996
1997
Methodology
Carbon dioxide emissions were calculated by multi-
plying the amount of limestone consumed by an average
carbon content for limestone, approximately 12.0 percent
for limestone and 13.2 percent for dolomite (based on
stoichiometry). Assuming that all of the carbon was oxi-
dized and released to the atmosphere, the appropriate
emission factor was multiplied by the annual level of con-
sumption for flux stone, glass manufacturing, and FGD
systems to determine emissions.
1998
1999
Flux Stone
: Glass Making
;-- FGD
Total
; Note: Totals may
Table 3-1 0:C02
! Activity
Flux Stone
: Limestone
Dolomite
( Glass Making
I- Limestone
Dolomite
' FGD
Total
• NA (Not Available)
Note: Totals may n
3.0
0.2
1.9 ^_.._ ..- ._
5.1 "'"•':':;'
not sum due to independent rounding.
Emissions from Limestone & Di
1990 "~~
3,005
2,554
452
189 " "
189 "":" -:"'•"
NA
1,922
5,117 _
ot sum due to independent rounding.
3.9
0.5
2.6
7.0
ilomite
1995
3,903
2,523
1,380
526
421
105
2,558
6,987
4.2
0.4
2.7
7.3
Use(Gg)
1996
4,249
3,330
919
362
251
110
2,695
7,305
5.0
0.4
2.9
8.3
1997
5,042
3,970
1,072
383
266
117
2,902
8,327
5.1
0.2
2.8
8.1
1998
5,142
4,298
844
191
65
125
2,781
8,114
5.3
0.2
2.8
8.3
1999
5,312
4,441
871
197
67
129
2,781
8,290
Data Sources
Consumption data for 1990 through 1999 of lime-
stone and dolomite used as flux stone and in glass manu-
facturing (see Table 3-11) were obtained from the USGS
(1993,1995a, 1995b, 1996,1997,1998,1999,2000). Con-
sumption data for limestone used in FGD were taken from
unpublished survey data in the Energy Information
Administration's Form EIA-767, "Steam Electric Plant
Operation and Design Report" (EIA1997,1998,1999). For
1990 and 1994, the USGS did not provide a breakdown of
limestone and dolomite production by end-use and for
Table 3-11: Limestone and Dolomite Consumption (Thousand Metric Tons)
Activity
1990
1991
1992 1993 1994 1995 1996 1997 1998
1999
Flux Stone
Limestone
Dolomite
Glass Making
• Limestone
- Dolomite
FGD
6,737
5,804
933
430
430
NA
4,369
6,052
5,213
838
386
386
NA
4,606
5,185
4,447
738
495
495
NA
4,479
4,263
3,631
632
622
622
NA
4,274
5,487
3,149
2,339
949
949
NA
5,080
8,586
5,734
2,852
1,174
958
216
5,815
9,468
7,569
1,899
799
571
228
6,125
11,239
9,024
2,215
847
605
242
6,595
11,512
9,769
1,743
407
148
259
6,322
11,893
10,093
1,801
421
153
267
6,322
NA (Not Available)
Industrial Processes 3-9
-------
1999 the end-use breakdowns had not yet been finalized
at the time of publication. Consumption figures for these
years were estimated by assuming that limestone and
dolomite accounted for the same percentage of total
crushed stone consumption for a given year as the aver-
age of the percentages for the years before and after.8
Furthermore, following 1996, limestone used in glass
manufacture has only been reported for 1998. For 1996
and 1997, limestone used in glass manufacture was esti-
mated based on the percent of total crushed stone for
1995 and 1998.
It should be noted that there is a large quantity of
crushed stone reported to the USGS under the category
"unspecified uses." A portion of this consumption is be-
lieved to be limestone or dolomite used as flux stone and
for glass manufacture. The quantity listed for "unspeci-
fied uses" was therefore allocated to each reported end-
use according to each end-use's fraction of total con-
sumption in that year.9
Uncertainty
Uncertainties in this estimate are due hi part to varia-
tions in the chemical composition of limestone. In addi-
tion to calcite, limestone may contain smaller amounts of
magnesia, silica, and sulfur. The exact specifications for
limestone or dolomite used as flux stone vary with the
pyrometallurgical process, the kind of ore processed, and
the final use of the slag. Similarly, the quality of the lime-
stone used for glass manufacturing will depend on the
type of glass being manufactured.
Uncertainties also exist in the activity data. Much
of the limestone consumed in the United States is re-
ported as "other unspecified uses;" therefore, it is diffi-
cult to accurately allocate this unspecified quantity to
the correct end-uses. Also, some of the limestone reported
as "limestone" is believed to actually be dolomite, which
has a higher carbon content than limestone. Lastly, the
uncertainty of the estimates for limestone used in glass
making are especially high. Large fluctuations in reported
consumption exist, reflecting year-to-year changes in the
number of survey respondees. The uncertainty resulting
from a shifting survey population is exacerbated by the
gaps in the time series of reports. However, since glass
making accounts for no more than 10 percent of lime-
stone consumption, its contribution to the overall emis-
sions estimate is low.
Soda Ash Manufacture
and Consumption
Soda ash (sodium carbonate, Na2CO3) is a white
crystalline solid that is readily soluble in water and strongly
alkaline. Commercial soda ash is used as a raw material in
a variety of industrial processes and in many familiar con-
sumer products such as glass, soap and detergents, pa-
per, textiles, and food. It is used primarily as an alkali,
either in glass manufacturing or simply as a material that
reacts with and neutralizes acids or acidic substances.
Internationally, two types of soda ash are produced—
natural and synthetic. The United States produces only
natural soda ash and is the largest soda ash-producing
country in the world. Trona is the principal ore from which
natural soda ash is made.
Only two States produce natural soda ash: Wyo-
ming and California. Of these two States, only Wyoming
has net emissions of CO2. This difference is a result of the
production processes employed in each State.10 During
the production process used in Wyoming, natural sources
of sodium carbonate are heated and transformed into a
crude soda ash that requires further refining. Carbon di-
oxide (CO2) is generated as a by-product of this reaction,
and is eventually emitted into the atmosphere. In addi-
tion, CO2 may also be released when soda ash is con-
sumed.
In 1999, CO2 emissions from the manufacture of
soda ash from trona were approximately 1.5 Tg CO2 Eq.
8 Exception: 1990 and 1999 consumption were estimated using the percentages for only 1991 and 1998, respectively.
' This approach was recommended by USGS.
10 In California, soda ash is manufactured using sodium carbonate-bearing brines instead of trona ore. To extract the sodium carbonate,
the complex brines are first treated with CO2 in carbonation towers to convert the sodium carbonate into sodium bicarbonate, which
then precipitates from the brine solution. The precipitated sodium bicarbonate is then calcined back into sodium carbonate. Although
CO2 is generated as a by-product, the CO2 is recovered and recycled for use in the carbonation stage and is not emitted.
3-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 3-12: C02 Emissions
from Soda Ash Manufacture and Consumption
Year
1990
TgCO.Eq.
4.1
1996
1997
1998
. 1999
4.3
4.4
4.3
4.2
Table 3-13: C02 Emissions
from Soda Ash Manufacture and Consumption (Gg)
Year
~ 1990
ft^^^e'
1995
1996
1997
*~~ 1998
1999
Note: Totals
Manufacture
1,435
A * "^*
,.*, ".L." '".
1,607
1,587
1,666
1,607
1,549
may not sum due to
Consumption
2,709
?
t
2,702
2,685
2,768
2,718
2,668
Total
4,144
T !
4,309
4,273
4,434
4,325
4,217
independent rounding.
(1,549 Gg). Soda ash consumption in the United States
also generated 2.7 Tg CO2 Eq. (2,668 Gg) in 1999. Total
emissions from this source in 1999 were then 4.2 Tg CO2
Eq. (4,217 Gg) (see Table 3-12 and Table 3-13). Emissions
have fluctuated since 1990. These fluctuations were
strongly related to the behavior of the export market and
the U.S. economy. Emissions in 1999 decreased by 3 per-
cent from the previous year, but have increased 2 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 1999 was glass making, 51 percent; chemical pro-
duction, 26 percent; soap and detergent manufacturing,
11 percent; distributors, 5 percent; flue gas desulfuriza-
tion, pulp and paper production, and water treatment, 2
percent each; and miscellaneous constituted for the re-
maining 1 percent (USGS 2000).
Soda ash production and consumption decreased
by 4 and 2 percent from 1998 values, respectively. Ex-
ports were a driving force behind U.S. soda ash produc-
tion and the Asian economic crisis beginning in late 1997
has been cited as a major cause for the drop in world soda
ash demand. However, growing demand in Asia and South
America is expected to lead to moderate growth (between
0.5 and 1 percent) in U.S. soda ash production.
Construction is currently underway on a major soda
ash plant that will use a new feedstock—nahcolite, a natu-
ral sodium bicarbonate found in deposits in Colorado's
Piceance Creek Basin. The new facility will have an an-
nual capacity of 900,000 tons of soda ash and is slated to
open in January 2001 (USGS 2000). Part of this produc-
tion process involves the stripping of CO2. At this point,
however, it is unknown whether any CO2 will be released
to the atmosphere or captured and used for conversion
back to sodium bicarbonate.
Methodology
During the production process, trona ore is cal-
cined in a rotary kiln and chemically transformed into a
crude soda ash that requires further processing. Carbon
dioxide and water are generated as by-products of the
calcination process. Carbon dioxide emissions from the
calcination of trona can be estimated based on the fol-
lowing chemical reaction:
2(Na3H(CO3)2x2H20) -> SNa^Og + 5H2O + CO2
[trona] [soda ash]
Based on this formula, approximately 10.27 metric
tons of trona are required to generate one metric ton of
CO2. Thus, the 15.9 million metric tons of trona mined in
1999 for soda ash production (USGS 2000) resulted in CO2
emissions of approximately 1.5 Tg CO2Eq. (1,549 Gg).
Once manufactured, most soda ash is consumed in
glass and chemical production, with minor amounts in
soap and detergents, pulp and paper, flue gas desulfur-
ization and water treatment. As soda ash is consumed for
these purposes, additional CO2 is usually emitted. In
these applications, it is assumed that one mole of carbon
is released for every mole of soda ash used. Thus, ap-
proximately 0.113 metric tons of carbon (or 0.415 metric
tons of CO2) are released for every metric ton of soda ash
consumed.
Industrial Processes 3-11
-------
Data Sources
The activity data for trona production and soda
ash consumption (see Table 3-14) were taken from USGS
(1994,1995,1996,1997,1998,1999,2000). Sodaashmanu-
facture and consumption data were collected by the USGS
from voluntary surveys of the U.S. soda ash industry. All
six of the soda ash manufacturing operations in the United
States completed surveys to provide data to the USGS.
Uncertainty
Emissions from soda ash manufacture are consid-
ered to be relatively certain. Both the emissions factor
and activity data are reliable. However, emissions from
soda ash consumption are dependent upon the type of
processing employed by each end-use. Specific informa-
tion characterizing the emissions from each end-use is
limited. Therefore, uncertainty exists as to the accuracy
of the emission factors.
Carbon Dioxide Consumption
Carbon dioxide (CO2) is used for a variety of appli-
cations, including food processing, chemical production,
carbonated beverages, and enhanced oil recovery (EOR).
Carbon dioxide used for EOR is injected into the ground
to increase reservoir pressure, and is therefore consid-
ered sequestered.11 For the most part, however, CO2 used
Table 3-14: Soda Ash Manufacture and
Consumption (Thousand Metric Tons)
in non-EOR applications will eventually be released to
the atmosphere.
Carbon dioxide is produced from a small number of
natural wells, as a by-product from the production of
chemicals (e.g., ammonia), or separated from crude oil
and natural gas. Depending on the raw materials that are
used, the by-product CO2 generated during these pro-
duction processes may already be accounted for in the
CO2 emission estimates from fossil fuel consumption (ei-
ther during combustion or from non-fuel uses). For ex-
ample, ammonia is primarily manufactured using natural
gas as a feedstock. Carbon dioxide emissions from this
process are accounted for in the Energy chapter under
Fossil Fuel Combustion and, therefore, are not included
here.
In 1999, CO2 emissions from this source not ac-
counted for elsewhere were 1.6 Tg CO2 Eq. (1,572 Gg)
(see Table 3-15). This amount represents an increase of
11 percent from the previous year and is 97 percent higher
than emissions in 1990.
Methodology
Carbon dioxide emission estimates were based on
CO2 consumption with the assumption that the end-use
applications, except enhanced oil recovery, eventually re-
lease 100 percent of the CO2 into the atmosphere. Carbon
dioxide consumption for uses other than enhanced oil re-
Table 3-15: C02 Emissions from
Carbon Dioxide Consumption
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
* Soda ash manufactured
Manufacture*
14,734
14,674
14,900
14,500
14,600
16,500
16,300
17,100
16,500
15,900
from trona ore only.
Consumption
6,527
6,278
6,360
6,350
6,240
6,510
6,470
6,670
6,550
6,430
kr-
Year
:" 1990
If :- " " . ' ,'
p.v ..... - . '.-...
1995
1996
I 1997
1998
T 1999
* Soda ash manufactured
i. ..._...
V-
Tg CO, Eq.
0.8
1.0
1.1
1.3
1.4
1.6
from frona ore only.
Gg
800
968
1,140
1,294
1,413
1,572
" It is unclear to what extent the CO2 used for EOR will be re-released. For example, the CO2 used for EOR may show up at the wellhead
after a few years of injection (Hangebrauk et al. 1992). This CO2, however, is typically recovered and re-injected into the well. More
research is required to determine the amount of CO2 that in fact escapes from EOR operations. For the purposes of this analysis, it is
assumed that all of the CO2 remains sequestered.
3-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
covery was about 7,861 thousand metric tons in 1999. The
Freedonia Group estimates that, in the United States, there
is an 80 to 20 percent split between CO2 produced as a by-
product and CO2 produced from natural wells. Thus, emis-
sions are equal to 20 percent of CO2 consumption. The
remaining 80 percent was assumed to already be accounted
for in the CO2 emission estimates from other categories
(the most important being Fossil Fuel Combustion).
Data Sources
Carbon dioxide consumption data (see Table 3-16)
were obtained from Industrial Gases to 2003, published
by the Freedonia Group Inc. (1994,1996,1999a, 1999b).
The 1999 report contains actual data for 1998 only. Data
for 1996 were obtained by personal communication with
Paul Ita of the Freedonia Group Inc. (Ita 1997). Data for
1997 and 1999 production were calculated from annual-
ized growth rates for 1994 through 1996 and 1996 through
1998 respectively. The 1997 and 1999 values for enhanced
oil recovery were set equal to the 1998 value. The percent
of carbon dioxide produced from natural wells was ob-
tained from Freedonia Group Inc. (1991).
Uncertainty
Uncertainty exists in the assumed allocation of car-
bon dioxide produced from fossil fuel by-products (80
percent) and carbon dioxide produced from wells (20 per-
Table 3-16: Carbon Dioxide Consumption
Year
Thousand Metric Tons
1990
: 1991
1992
r 1993
1994
1995
1996
;. 1997
i 1998
! 1999
4,000
4,200
4,410
4,559
4,488
4,842
5,702
6,468
7,067
7,861
cent). In addition, it is possible that CO2 recovery exists
in particular end-use sectors. Contact with several orga-
nizations did not provide any information regarding re-
covery. More research is required to determine the quan-
tity, if any, that may be recovered.
Iron and Steel Production
In addition to being an energy intensive process,
the production of iron and steel also generates process-
related emissions of CO2. Iron is produced by first reduc-
ing iron oxide (ore) with metallurgical coke in a blast fur-
nace to produce pig iron (impure iron of about 4 to 4.5
percent carbon by weight). Carbon dioxide is produced
as the coke used in this process is oxidized. Steel (less
than 2 percent carbon by weight) is produced from pig
iron in a variety of specialized steel furnaces. The major-
ity of CO2 emissions come from the production of iron,
with smaller amounts evolving from the removal of car-
bon from pig iron to produce steel.
Emissions of CO2 from iron and steel production in
1999 were71.8 Tg CO2Eq. (71,840 Gg). Emissions fluctu-
ated significantly from 1990 to 1999 due to changes in
domestic economic conditions and changes in imports
and exports. For the past several years, pig iron produc-
tion has experienced a downward trend. Production in
1999 was 7 percent lower than 1998, and 12 percent below
1995 levels. Asian economic problems and the availabil-
ity of low-priced imports continue to keep growth in check
(USGS2000).
CO2 emissions from iron and steel production are
not included in totals for the Industrial Processes chapter
because they are accounted for with Fossil Fuel Combus-
tion emissions from industrial coking coal in the Energy
chapter.12 Emissions estimates are presented here for in-
formational purposes only (see Table 3-17). Additional CO2
emissions also occur from the use of limestone or dolomite
flux during production; however, these emissions are ac-
counted for under Limestone and Dolomite Use.
12 Although the CO2 emissions from the use of industrial coking coal as a reducing agent should be included in the Industrial Processes
chapter, information to distinguish individual non-energy uses of fossil fuels is unfortunately not available in DOE/EIA fuel statistics.
Industrial Processes 3-13
-------
Table 3-17: C02 Emissions
Table 3-18: Pig Iron Production
iruin
F
! iron ana on
Year
1990
1995
1996
1997
1998
1999
sei rrouucuon
Tg CO, Eq.
87.6
81.4
79.0
79.4
77.1
71.8
Gg
87,600
81,440
79,040
79,360
77,120
71,840
Year
1990
r : 1991
; I |: - 1992
1 -: ' ' ' 1993 ' ' '
1994
1995
1996
t 1997
;; 1998
T: 1 999
Thousand Metric Tons
54750
44,100 "
47,400 \
48,200
49,400
50,900
49,400
49,600
48,200
44,900
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 COjj/metric 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 (ffCOUNEP/OECD/EA 1997). Produc-
tion data for 1990 through 1997 (see Table 3-18) were ob-
tained from the U.S. Geological Survey's (USGS) Minerals
Yearbook: Volume I-Metals and Minerals (USGS 1995,
1996,1997,1998,1999); datafor 1999 were obtained from
USGS's Mineral Commodity Summaries (2000).
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 could
yield a more accurate estimate, but these factors were not
available. The most accurate alternative would be to cal-
culate emissions based on the amount of reducing agent
used, rather than on the amount of iron or steel produced;
however, these data were also not available.
Ammonia Manufacture
Emissions of carbon dioxide (CO2) occur during the
production of ammonia. In the United States, roughly 98
percent of synthetic ammonia is produced by catalytic
steam reforming of natural gas, and the remainder is pro-
duced using naphtha (a petroleum fraction) or the elec-
trolysis of brine at chlorine plants (EPA 1997). The former
two fossil fuel-based reactions produce carbon monoxide
and hydrogen gas; however, the latter reaction does not
lead to CO2 emissions. Carbon monoxide (CO) in the first
two processes is transformed into CO2 in the presence of a
catalyst (usually a metallic oxide). The hydrogen gas is
diverted and combined with nitrogen gas to produce am-
monia. The CO2, included in a gas stream with other pro-
cess impurities, is absorbed by a scrubber solution. In re-
generating the scrubber solution, CO2 is released.
(catalyst)
CH4+H2O-»4H2+CO2
3H2+N2 ->2NH3
Emissions of CO2 from ammonia production in 1999
were 25.8 Tg CO2 Eq. (25,799 Gg). Carbon dioxide emis-
sions from this source are not included in totals for the
Industrial Processes chapter because these emissions are
accounted for with non-energy use of natural gas under
Fossil Fuel Combustion in the Energy chapter.13 Emis-
sions estimates are presented here for informational pur-
poses only (see Table 3-19).
13 Although the CO2 emissions from the use of natural gas as a feedstock should be included in the Industrial Processes chapter,
information to distinguish individual non-energy uses of fossil fuels is unfortunately not available in DOE/EIA fuel statistics.
3-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Methodology
Emissions of CO2 were calculated by multiplying
annual estimates of ammonia production by an emission
factor (1.5 metric ton CO2/metric 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 pro-
duced using this latter 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).
Ammonia production data (see Table 3-20) were obtained
from the Census Bureau of the U.S. Department of Com-
merce (Census Bureau 1998,2000) as reported hi Chemi-
cal and Engineering News, "Facts & Figures for the
Chemical Industry."
Uncertainty
It is uncertain how accurately the emission factor
used represents an average across all ammonia plants.
By using natural gas consumption data for each ammonia
plant, more accurate estimates could be calculated. How-
ever, these consumption data are often considered confi-
dential and are difficult to acquire. All ammonia produc-
tion in this analysis was assumed to be from the same
process; however, actual emissions could differ because
processes other than catalytic steam reformation may
have been used.
Table 3-19: C02 Emissions from
Ammonia Manufacture
Ferroalloy Production
ji-T --..-.--. '
|: Year
I 1990
" ~ ~ 1995
^ 1996
? 1997
;: 1998
?--- 1999
C
TgCO,Eq.
23.1
23.7
24.4
24.3
25.1
25.8
. . • . s
Gg
23,138
J
1
23,682
24,390
24,346 ;
25,141.
25,799 ;
.-•-:•' '. '9
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 sili-
con) have been calculated. Emissions from the produc-
tion of ferrochromium and ferromanganese are not in-
cluded here because of the small number of manufactur-
ers of these materials. As a result, government informa-
tion disclosure rules prevent the publication of produc-
tion data for them. Similar to emissions from the produc-
tion of iron and steel, CO2is emitted when metallurgical
coke is oxidized during a high-temperature reaction with
iron and the selected alloying element. Due to the strong
reducing environment, CO is initially produced. The CO
is eventually oxidized, becoming CO2. A representative
reaction equation for the production of 50 percent
ferrosilicon is given below:
Emissions of CO2 from ferroalloy production hi 1999
were 1.8 TgCO2Eq. (1,771 Gg). Carbon dioxide emissions
from this source are not included in the totals for the
Industrial Processes chapter because these emissions are
accounted for in the calculations for industrial coking
coal under Fossil Fuel Combustion in the Energy chap-
ter.14 Emission estimates are presented here for informa-
tional purposes only (see Table 3-21).
Table 3-20: Ammonia Manufacture
Year
Thousand .Metric Tons.
K^^- 1990
1991
1992 .
ii*-V. 1.993 •.;•
1994
r*:'-' I995'v""^: • "•
1996
1997
T~^ 1998
s£^;*: 1999 ' ;
15,425 '••
15,576 :
16,261
15,599
16,211
15,788
16,260
16,231
16,761
17,200
j.'_— . • - • .. - • - - - • -±.
14 Although the CO2 emissions from the use of industrial coking coal as a reducing agent should be included in the Industrial Processes
chapter, information to distinguish individual non-energy uses of fossil fuels is unfortunately not available in DOE/EIA fuel statistics.
Industrial Processes 3-15
-------
Methodology
Emissions of CO2 were calculated by multiplying
annual ferroalloy production by material-specific emis-
sion factors. Emission factors were applied to production
data for ferrosilicon 50 and 75 percent (2.35 and 3.9 metric
ton CCVmetric ton, respectively) and silicon metal (4.3
metric ton CO2/metric ton). It was assumed that all
ferroalloy production was produced using coking coal,
although some ferroalloys may have been produced with
wood, other biomass, or graphite carbon inputs.
Data Sources
Emission factors were taken from the Revised 1996
IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).
Ferroalloy production data for 1990 through 1998 (see
Table 3-22) were obtained from the U.S. Geological
Survey's (USGS) Minerals Yearbook: Volume I—Metals
and Minerals (USGS, 1991,1992,1993,1994,1995,1996,
1997,1998,1999,2000); data for 1999 for ferrosilicon 75
percent and silicon metal were obtained from USGS (2000)
Mineral Industry Surveys: Silicon in December 1999.
Data for ferrosilicon 50 percent are no longer provided
separately in USGS Mineral Industry Surveys, so the 1999
value was forecasted using the average annual growth in
ferrosilicon 50 percent production for 1995 through 1998.
Uncertainty
Although some ferroalloys may be produced using
wood or other biomass as a carbon source, information
and data regarding these practices were not available. Emis-
sions from ferroalloys produced with wood would not be
counted under this source because wood-based carbon is
of biogenic origin.15 Emissions from ferroalloys produced
with graphite inputs would be counted in national 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 production, the most
accurate method for these estimates would be basing cal-
culations on the amount of reducing agent used in the
process, rather than on the amount of ferroalloys produced.
These data were not available, however.
Table 3-21: C02 Emissions from Ferroalloy Production
Year Tg CO., Eg. Gg
1990
1.8
1,809
1995
1996
1997
1998
1999
1.6
1.7
1.8
1.8
1.8
1,625
1,695
1,789
1,793
1,771
Petrochemical Production
Small amounts of methane (CH4) are released dur-
ing the production of some petrochemicals. Petrochemi-
cals are chemicals isolated or derived from petroleum or
natural gas. Emissions are presented here from the pro-
duction of five chemicals: carbon black, ethylene, ethyl-
ene dichloride, styrene, and methanol.
Carbon black is an intensely black powder made by
the incomplete combustion of an aromatic petroleum feed-
stock. Almost all output is added to rubber to impart
strength and abrasion resistance, and the tire industry is
by far the largest consumer. Ethylene is consumed in the
production processes of the plastics industry including
Table 3-22: Production of Ferroalloys (Metric Tons)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Ferrosilicon
50%
321,385
230,019
238,562
199,275
198,000
181,000
182,000
175,000
162,000
156,121
Ferrosilicon
75%
109,566
101,549
79,976
94,437
112,000
128,000
132,000
147,000
147,000
145,000
Silicon
Metal
145,744
149,570
164,326
158,000
164,000
163,000
175,000
187,000
195,000
195,000
15 Emissions and sinks of biogenic carbon are accounted for in the Land-Use Change and Forestry chapter.
3-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
polymers such as high, low, and linear low density poly-
ethylene (HDPE, LDPE, LLDPE), polyvinyl chloride (PVC),
ethylene dichloride, ethylene oxide, and ethylbenzene.
Ethylene dichloride is one of the first manufactured chlo-
rinated hydrocarbons with reported production as early
as 1795. In addition to being an important intermediate in
the synthesis of chlorinated hydrocarbons, ethylene
dichloride is used as an industrial solvent and as a fuel
additive. Styrene is a common precursor for many plas-
tics, rubber, and resins. It can be found in many construc-
tion products, such as foam insulation, vinyl flooring,
and epoxy adhesives. Methanol is an alternative trans-
portation fuel as well as a principle ingredient in wind-
shield wiper fluid, paints, solvents, refrigerants, and dis-
infectants. In addition, methanol-based acetic acid is used
in making PET plastics and polyester fibers. The United
States produces close to one quarter of the world's sup-
ply of methanol.
Aggregate emissions of CH4 from petrochemical
production in 1999 were 1.7 Tg CO2 Eq. (79 Gg CH4) (see
Table 3-23). Production levels of all five chemicals have
shown steady growth over the past 5 years, with increases
ranging from 2 to 4 percent. However, petrochemicals are
currently in oversupply and production for 2000 is ex-
pected to decrease slightly.
Table 3-23: CH4 Emissions
from Petrochemical Production
Year
1990,
1995
1996
1997
1998
1999
Tg CO, Eq.
1-2.
1.5
1.6
1.6
1.6
1.7
Gfl
56
72
75
77
77
79
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,16 4 kg CH4/metric ton
styrene, and 2 kg CH4/metric ton methanol. These emis-
sion factors were based upon measured material balances.
Although the production of other chemicals may also
result in methane emissions, there were not sufficient data
to estimate their emissions.
Data Sources
Emission factors were taken from the Revised 1996
IPCC Guidelines (IPCC/UNEP/OECD/BEA1997). Annual
production data for 1990 through 1998 (see Table 3-24)
were obtained from the Chemical Manufacturer's Asso-
ciation Statistical Handbook (CMA 1999). Production
for 1999 was projected using each chemical's average
annual growth rate for 1993 through 1998.
Table 3-24: Production of Selected Petrochemicals (Thousand Metric Tons)
Chemical
1990
1991 1992
1993
1994 1995 1996
1997 1998
1999
Carbon Black
Ethylene
Ethylene Dichloride
Styrene
Methanol
1,306
16,542
6,282
3,637
3,785
1,225
18,124
6,221
3,681
3,948
1,
18,
6,
4,
3,
365
563
872
082
666
1,452
18,709
8,141
4,565
4,782
1,492
20,201
8,482
5,112
4,904
1,524
21,199
7,829
5,167
4,888
1,560
22,197
8,596
5,387
5,330
1,588
23,088
9,152
5,171
5,806
1,610
23,474
8,868
5,183
5,693
1,644
24,563
9,021
5,316
5,895
16 The emission factor obtained from IPCC/UNEP/OECD/IEA (1997), page 2.23 is assumed to have a misprint; the chemical identified
should be dichloroethylene (CyH^C^) instead of ethylene dichloride (C2H4C12).
Industrial Processes 3-17
-------
Uncertainty
The emission factors used here were based on a
limited number of studies. Using plant-specific factors
instead of average factors could increase the accuracy of
the emissions estimates, however, such data were not
available. There may also be other significant sources of
methane arising from petrochemical production activities
that have not been included in these estimates.
Silicon Carbide Production
Methane is emitted from the production of silicon
carbide, a material used as an industrial abrasive. To make
silicon carbide (SiC), quartz (SiO^ is reacted with carbon
in the form of petroleum coke. Methane is produced dur-
ing this reaction from volatile compounds in the petro-
leum coke. Although CO2 is also emitted from this pro-
duction process, the requisite data were unavailable for
these calculations. Regardless, they are already ac-
counted for under CO2 from Fossil Fuel Combustion in
the Energy chapter. Emissions of CH4 from silicon car-
bide production in 1999 (see Table 3-25) were 1 Gg CH4
(less than 0.05 Tg CO2 Eq.).
Methodology
Emissions of CH4 were calculated by multiplying
annual silicon carbide production by an emission factor
(11.6 kg CH4/metric ton silicon carbide). This emission
factor was derived empirically from measurements taken
at Norwegian silicon carbide plants (IPCC/UNEP/OECD/
BEA1997).
Data Sources
The emission factor was taken from the Revised
1996IPCC Guidelines (IPCC/UNEP/OECD/ffiA 1997).
Production data for 1990 through 1998 (see Table 3-26)
were obtained from the Minerals Yearbook: Volume I-
Metals and Minerals, Manufactured Abrasives (USGS
1991,1992,1993,1994,1995,1996,1997,1998,1999,2000).
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. A better alternative would be to calculate emis-
sions based on the quantity of petroleum coke used dur-
ing the production process rather than on the amount of
silicon carbide produced. These data were not available,
however.
Adipic Acid Production
Adipic acid production has been identified as an
anthropogenic source of nitrous oxide (N2O) emissions.
Worldwide, there are few adipic acid plants. The United
States is the major producer with three companies in four
locations accounting for approximately forty percent of
world production. Adipic acid is a white crystalline solid
used in the manufacture of synthetic fibers, coatings,
plastics, urethane foams, elastomers, and synthetic lubri-
cants. Commercially, it is the most important of the ali-
phatic dicarboxylic acids, which are used to manufacture
Table 3-25: CH4 Emissions
from Silicon Carbide Production
Table 3-26: Production of Silicon Carbide
Year Tg COZ Eq.
1990 +
1995 +
1996 +
1997 +
1998 +
1999 +
Hh Doss not 6XC68d 0 05 To COp EQ
Gg
1 j :
1
1
1
1
•j
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
105000
78,900
84,300
74,900
84,700
75,400
73,600
68,200
69,800
69,800
3-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
polyesters. Approximately 80 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.
The first stage of manufacturing usually involves the
oxidation of cyclohexane to form a cyclohexanone/
cyclohexanol mixture. The second stage involves oxidiz-
ing this mixture with nitric acid to produce adipic acid.
Nitrous oxide is generated as a by-product of the nitric
acid oxidation stage and is emitted in the waste gas stream.
Process emissions from the production of adipic acid will
vary with the types of technologies and level of emis-
sions controls employed by a facility. In 1990, two of the
three major adipic acid producing plants implemented N2O
abatement technologies and as of 1998, all of the major
adipic acid production facilities had control systems in
place.17 Only one small plant does not control for N2O,
representing approximately 2 percent of production.
Adipic acid production for 1999 was 1,100 thou-
sand metric tons. Nitrous oxide emissions from this source
were estimated to be 9.0 Tg CO2 Eq. (29 Gg) in 1999 (see
Table 3-27).
In 1999, adipic acid production reached its highest
level in fifteen years. This increase is chiefly due to a
120,000 metric ton expansion in production capacity and
to rising demand for engineering plastics. Though pro-
duction continues to increase, emissions have been sig-
nificantly reduced due to the widespread installation of
Table 3-27: N20 Emissions from
Adipic Acid Production
« Year
k 1990
': 1995
'^ 1996
!' 1997
i 1998
' 1999
« "~
Tg C02 Eq.
18.3
20.3
20.8
17.1
7.3
9.0
GO
59
-" .-.:.•.•• ; •" ' -, , "..
66
67
55
23
29
pollution control measures. The N2O abatement technol-
ogy voluntarily implemented at the three major produc-
ing plants accounts for an overall reduction of emissions
by approximately 51 percent between 1990 and 1999.
Methodology
Nitrous oxide emissions were calculated by multi-
plying adipic acid production by the ratio of N2O emitted
per unit of adipic acid produced and adjusting for the
actual percentage of N2O released as a result of plant-
specific emission controls. Because emissions of N2O in
the United States are not regulated, emissions have not
been well characterized. However, on the basis of experi-
ments (Thiemens and Trogler 1991), the overall reaction
stoichiometry for N2O production in the preparation of
adipic acid was estimated at approximately 0.3 kg of N2O
per kilogram of product. Emissions are determined using
the following equation:
N2O emissions = [production of adipic acid] x
[0.3 kg N2O / kg adipic acid] x
[ 1— (N2O destruction factor x
abatement system utility factor) ]
The "N2O destruction factor" represents the
amount of N2O expressed as a percentage of N2O emis-
sions that are destroyed by the currently installed abate-
ment technology. The "abatement system utility factor"
represents the percent of time that the abatement equip-
ment operates. Overall, in the United States, 63 percent of
production employs catalytic destruction, 34 percent uses
thermal destruction, and 3 percent of production has no
N2O abatement measures. The N2O abatement system
destruction factor is assumed to be 95 percent for cata-
lytic abatement and 98 percent for thermal abatement
(Reimer et al. 1999, Reimer 1999). The abatement system
utility factor is assumed to be 95 percent for catalytic
abatement and 98 percent for thermal abatement (Reimer
et al. 1999, Reimer 1999).
During 1997, the N2O emission controls installed by the third plant operated for approximately a quarter of the year.
Industrial Processes 3-19
-------
Data Sources
Adipic acid production data for 1990 through 1995
(see Table 3-28) were obtained from Chemical and Engi-
neering Ne\vs, "Facts and Figures" and "Production of
Top 50 Chemicals" (C&EN 1992,1993,1994,1995,1996).
For 1996 and 1997 data were projected from the 1995 manu-
factured total based upon suggestions from industry con-
tacts. For 1998, production data were obtained from Chemi-
cal Week, Product focus: adipic acid/adiponitrile (CW
1999). Production data for 1999 are based on an estimate
provided by the adipic acid industry (Reimer 2000). The
emission factor was taken from Thiemens and Trogler
(1991). Adipic acid plant capacities for 1998 and 1999 were
updated using Chemical Week, Product focus: adipic
acid/adiponitrile (CW 1999). Plant capacities for previous
years were obtained from Chemical Market Reporter (1998).
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 allo-
cating total adipic acid production using existing plant
capacities. This creates a degree of uncertainty in the
adipic acid production data used to derive the emission
estimates as it is necessary to assume that all plants op-
erate at equivalent utilization levels.
Table 3-28: Adipic Acid Production
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Thousand Metric Tons
735
771
708
765
815
816
835
860
866
1,100
The emission factor was based on experiments
(Thiemens and Trogler 1991) that attempt to replicate the
industrial process and, thereby, measure the reaction sto-
ichiometry for N2O production in the preparation of adipic
acid. However, the extent to which the lab results are repre-
sentative of actual industrial emission rates is not known.
Nitric Acid Production
Nitric acid (HNO3) is an inorganic compound used
primarily to make synthetic commercial fertilizers. It is
also a major component in the production of adipic acid—
a feedstock for nylon—and explosives. Virtually all of the
nitric acid produced in the United States is manufactured
by the catalytic oxidation of ammonia (EPA 1997). During
this reaction, N2O is formed as a by-product and is re-
leased from reactor vents into the atmosphere.
Currently, the nitric acid industry controls for NO
and NO2, (i.e., NOX). As such the industry uses a combi-
nation of non-selective catalytic reduction (NSCR) and
selective catalytic reduction (SCR) technologies. In the
process of destroying NOX, NSCR systems are also very
affective at destroying N2O. However, NSCR units are
generally not preferred in modern plants because of high
energy costs and associated high gas temperatures.
NSCRs were widely installed in nitric plants built between
1971 and 1977. Currently, it is estimated that approximately
20 percent of nitric acid plants use NSCR (Choe, et al.
1993). The remaining 80 percent use SCR or extended
absorption, neither of which is known to reduce N2O.
Nitric acid production was 8,165 thousand metric
tons in 1999 (C&EN 2000). Nitrous oxide emissions from
this source were estimated at 20.2 Tg CO2 Eq. (65 Gg) (see
Table 3-29). Emissions from nitric acid production de-
creased slightly in 1999, but have increased 13 percent
since 1990.
Methodology
Nitrous oxide emissions were calculated by multi-
plying nitric acid production by the amount of N2O emitted
per unit of nitric acid produced. The emissions factor was
determined as a weighted average of 2 kg for plants using
non-selective catalytic reduction (NSCR) systems and 9.5
3-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 3-29: N20 Emissions
from Nitric Acid Production
Table 3-30: Nitric Acid Production
Year
1990
1995
1996
1997
1998
1999
TgC02Eq.
17.8
19.9
20.7
21.2
20.9
20.2
Gg
58
64
67
68
67
65
kg for plants not equipped with NSCR (Reimer et al. 1992).
An estimated 20 percent of HNO3 plants in the U.S. were
equipped with NSCR (Choe, et al. 1993). In the process of
destroying NOX, NSCR systems also destroy 80 to 90 per-
cent of the N2O. Hence, the emission factor is equal to (9.5
x 0.80) + (2 x 0.20) = 8 kg N2O / metric ton HNO3.
Data Sources
Nitric acid production data for 1990 through 1999
(see Table 3-30) were obtained from Chemical and Engi-
neering News, "Facts and Figures" (C&EN 2000). The
emission factor range was taken from Reimer et al. (1992).
Uncertainty
In general, the nitric acid industry is not well cat-
egorized. A significant degree of uncertainty exists in ni-
tric acid production figures because nitric acid plants are
often part of larger production facilities, such as fertilizer
or explosive manufacturing. As a result, only a small vol-
ume of nitric acid is sold on the market making produc-
tion quantities difficult to track. Emission factors are also
difficult to determine because of the large number of plants
using many different technologies. Based on expert judg-
ment, it is estimated that the N2O destruction factor for
NSCR nitric acid facilities is associated with an uncer-
tainty of approximately ±10 percent.
Year
^.-.-.. ;-: -. " -.'-••„ - - -.. •.- .. • •
r""' 1990
r~-,, 1991
^- 1992
1993
1994
E 1995
1996
1997
r 1998
fe- 1999
Thousand
Metric Tons
7,196
7,191
7,381
7,488
7,905
8,020
8,351
8,557
8,423
8,165
is-
Substitution of Ozone
Depicting 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 1990.18 Ozone de-
pleting substances—chlorofluorocarbons (CFCs), halons,
carbon tetrachloride, methyl chloroform, and
hydrochlorofluorocarbons (HCFCs)—are used in a vari-
ety of industrial applications including refrigeration and
air conditioning equipment, solvent cleaning, foam pro-
duction, sterilization, fire extinguishing, and aerosols.
Although HFCs and PFCs, unlike ODSs, are not harmful
to the stratospheric ozone layer, they are potent green-
house gases. Emission estimates for HFCs and PFCs used
as substitutes for ODSs are provided in Table 3-31 and
Table 3-32.
In 1990 and 1991, the only significant emissions of
HFCs and PFCs as substitutes to ODSs were relatively
small amounts of HFC-152a—a component of the refrig-
erant blend R-500 used in chillers—and HFC- 134a in re-
frigeration 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-404.19
In 1993, use of HFCs in foams and aerosols began, and in
18 [42 U.S.C § 7671, CAA § 601]
19 R-404 contains HFC-125, HFC-143a, and HFC-134a.
Industrial Processes 3-21
-------
Table 3-31: Emissions of HFCs and PFCs from ODS Substitution (Tg C02 Eq.)
Gas
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-236fa
CF<
Others*
Total
1990
+
*
0.7
+
+
+
0.2
0.9
1995
+
1.3
18.6
0.4
+
+
3.6
24.0
1996
0.1
1.9
24.7
0.8
+
H-
6.6
34.0
1997
0.1
2.5
30.5
1.3
0.1
+
7.6
42.1
1998
0.2
3.1
34.9
1.9
0.8
+
8.8
49.6
1999
0.3
3.6
39.4
2.6
1.3
+
9.4
56.7
+ Does not exceed 0.05 Tg C02 Eq.
* Others include HFC-152a, HFC-227ea, HFC-4310mee, and PFC/PFPEs, the latter being a proxy for a diverse collection of PFCs and
perfluoropolyethers (PFPEs) employed for solvent applications. For estimating purposes, the GWP value used for PFC/PFPEs was based
uponC6F14.
Note: Totals may not sum due to independent rounding.
1994 these compounds also found applications as sol-
vents and sterilants. In 1995, ODS substitutes for halons
entered widespread use in the United States as halon
production was phased-out.
The use and subsequent emissions of HFCs and
PFCs as ODS substitutes has been increasing from small
amounts in 1990 to 56.7 Tg CO2 Eq. in 1999. This increase
was the result of efforts to phase-out CFCs and other
ODSs in the United States. In the short term, this trend is
expected to continue, and will likely accelerate in the next
decade as HCFCs, which are interim substitutes in many
applications, are themselves phased out under the provi-
sions of the Copenhagen Amendments to the Montreal
Protocol. Improvements in the technologies associated
with the use of these gases, however, may help to offset
this anticipated increase hi emissions.
Methodology and Data Sources
The EPA used a detailed vintaging model of ODS-
containing equipment and products to estimate the ac-
tual—versus potential—emissions of various ODS sub-
stitutes, including HFCs and PFCs. The name of the model
refers to the fact that the model tracks the use and emis-
sions of various compounds for the annual "vintages" of
new equipment that enter service in each end-use. This
vintaging model predicts ODS and ODS substitute use in
the United States based on modeled estimates of the quan-
tity of equipment or products sold each year containing
these chemicals and the amount of the chemical required
to manufacture and/or maintain equipment and products
over time. Emissions for each end-use were estimated by
applying annual leak rates and release profiles, which
account for the lag in emissions from equipment as they
leak over time. By aggregating the data for more than 40
different end-uses, the model produces estimates of an-
nual use and emissions of each compound. Details on
the Vintaging Model are contained in Annex I.
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 analytical
tools such as the EPA vintaging model or the methods
outlined in IPCC/UNEP/OECD/BEA (1997). Though the
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.
3-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 3-32: Emissions of HFCs and PFCs from ODS Substitution (Mg)
Gas
1990
1995
1996
1997
1998
1999
THFC-23
; HFC-32
i HFC-125
, HFC-1343
HFC-1433
HFC-236fa
iCF4
Others*
+ 2
+ +
+ . _ 478
564 _ 14,345
+ . - _ 111
+ +
+ - +
M M
5
3
675
18,962
209
+
'+' •
M
10
7
889
23,478
334
15
+
M
17
11
1,116
26,854
488
120
+
M
25
17
1,289
30,340
676
213
1
M
M (Mixture of Gases)
+ Does not exceed 0.5 Wig
* Others include HFC-152a, HFG-227ea, HFC-4310mee and PFC/PFPEs, which are a proxy for a diverse collection of PFCs and
perfiuoropolyethers (PFPEs) employed for solvent applications.
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. In 1999, the United States was the larg-
est producer of primary aluminum, with 16 percent of the
world total (USGS 2000). The United States was also a
major importer of primary aluminum. The production of
primary aluminum—in addition to consuming large quan-
tities of electricity—results in process-related 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 cover gas or a fluxing and
degassing agent in experimental and specialized casting
operations. In its application as a cover gas, SF6 is mixed
with nitrogen or carbon dioxide and injected above the
surface of molten aluminum; as a fluxing and degassing
agent, SF6 is mixed with argon, nitrogen, and/or chlorine
and blown through molten aluminum. These practices are
not employed extensively by primary aluminum produc-
ers and are probably isolated to the secondary casting
firms. The aluminum industry in the United States and
Canada is estimated to use 230 Mg of SF6 per year (Maiss
and Brenninkmeijer 1998); however, this estimate is highly
uncertain.
Historically, SF6 from aluminum activities has been
omitted from models of global SF6 emissions, with the
caveat that any emissions would be insignificant (Ko et
al. 1993, Victor and MacDonald 1998). Emissions are
thought to be slight since the concentration of SF6 in the
mixtures is small and a portion of the SF6 is decomposed
in the process (MacNeal et al. 1990, Gariepy and Dube
1992, Ko et al. 1993, Ten Eyck and Lukens 1996, Zurecki
1996). Emissions of SF6 have not been estimated for alu-
minum production.
Carbon dioxide is emitted during the aluminum
smelting process when alumina (aluminum oxide, A12O3)
is reduced to aluminum using the Hall-Heroult reduction
process. The reduction of the alumina occurs through
electrolysis in a molten bath of natural or synthetic 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 5.6 Tg CO2 Eq. (5,555 Gg) in 1999
(see Table 3-33). The CO2 emissions from this source,
however, are accounted for under the non-energy use
portion of CO2 from Fossil Fuel Combustion of petroleum
coke and tar pitch in the Energy chapter. Thus, to avoid
double counting, CO2 emissions from aluminum produc-
tion are not included in totals for the Industrial Processes
chapter. They are provided here for informational pur-
poses only.
Industrial Processes 3-23
-------
In addition to CO2 emissions, the aluminum pro-
duction industry is 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 48 percent since
1990. Since 1990, emissions of CF4 and C2F6 have de-
clined 46 and 58 percent, respectively, to 9.0 Tg CO2 Eq.
of CF4 (1.38 Gg CF^ and 1.1 Tg CO2Eq. of C2F6 (0.12 Gg
CjF6) in 1999, as shown in Table 3-34 and Table 3-35. This
decline was both due to reductions in domestic alumi-
num production and actions taken by aluminum smelting
companies to reduce the frequency and duration of an-
ode effects. The EPA supports aluminum smelters with
these efforts through the Voluntary Aluminum Industrial
Partnership (VAIP).
U.S. primary aluminum production for 1999—total-
ing 3,779 thousand metric tons—increased slightly from
1998. This increase is attributed to the reintroduction of
previously idled production capacity and the start up of
new production capacity (USGS 2000). The transporta-
tion industry remained the largest domestic consumer of
aluminum, accounting for about 37 percent (USGS 2000).
According to the U.S. Geological Survey (2000), overall
consumption in the United States will continue to grow,
driven by strong demand for aluminum in manufacturing
passenger cars and light trucks. However, annual domes-
tic production is expected to decline in 2000. The high
cost of electric power in various regions of the country
has prompted several production curtailments at U.S.
smelters.
Methodology
Carbon dioxide is generated during alumina reduc-
tion to aluminum metal following the reaction below:
2A12O3 + 3C -» 4A1 + 3CO2
The CO2 emission factor employed was estimated
from the production of primary aluminum metal and the
carbon consumed by the process. During alumina reduc-
tion, approximately 1.5 to 2.2 metric tons of CO2 are emit-
ted for each metric ton of aluminum produced
(Abrahamson 1992). Based upon the mass balance for a
Table 3-34: PFC Emissions
from Aluminum Production (Tg C02 Eq.)
p
I
a,-
j,
L-
|"
*
Si. ,
Year
1990
fit . -
1995
1996
1997
1998
1999
Note: Totals
CF4
16.7
10.0
10.3
9.7
9.0
9.0
may not sum due to
C2F6
2.5
1.3
1.3
1.2
1.1
1.1
independent
Total
19.3
11.2
11.6
10.8
10.1
10.0
rounding.
Table 3-33: C02 Emissions
from Aluminum Production
Table 3-35: PFC Emissions
from Aluminum Production (Gg)
Year
1990
In,
1995
1996
1997
1998
1999
TgC02Eq.
6.0
5.0
5.3
5.3
5.5
5.6
Gg
5,951
:.. :;."•" i
4,961
5,258
5,296
5,458
5,555
Year
1990
E - V--
1995
1996
1997
1998
1999
CF4
2.6
A
1.5
1.6
1.5
1.4
1.4
C2F6
0.3
0.1
0.1
0.1
0.1
0.1
^
:
3-24 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
"typical" aluminum smelter (Drexel University Project
Team 1996), the emission factor was set at 1.5 metric tons
CO2 per metric ton of aluminum smelted. This value is at
the low end of the Abrahamson (1992) range.
The CO2 emissions from this source are already ac-
counted for under CO2 Emissions from Fossil Fuel Com-
bustion in the Energy chapter.20 Thus, to avoid double
counting, CO2 emissions from aluminum production are
not included in totals for the Industrial Processes chapter.
PFC emissions from aluminum production were es-
timated using a per unit production emission factor that
is expressed as a function of operating parameters (an-
ode effect frequency and duration), as follows:
PFC (CF4 or C2F6) kg/metric ton Al = S x Anode
Effect Minutes/Cell-Day
where,
S = Slope coefficient
Anode Effect Minutes/Cell-Day = Anode Effect
Frequency X Anode Effect Duration
The slope coefficient was established for each
smelter based on actual field measurements, where avail-
able, or default coefficients by technology-type based
on field measurements. Once established, the slope coef-
ficient was used along with smelter anode effect data,
collected by aluminum companies and reported to the
VAIP, to estimate emissions factors over tune. Emissions
factors were multiplied by annual production to estimate
annual emissions at the smelter level. Emissions were then
aggregated across smelters to estimate national emissions.
The methodology used to estimate emissions is consis-
tent with the methodologies recommended by the Good
Practice Guidance (IPCC 2000).
Data Sources
Primary aluminum production data for 1990 through
1999 (see Table 3-36) were obtained from USGS, Mineral
Industry Surveys: Aluminum Annual Report (USGS 1995,
1998,2000). The USGS requested data from the 12 domes-
tic producers, all of whom responded. The CO2 emission
factor range was taken from Abrahamson (1992). The mass
Table 3-36: Production of Primary Aluminum
Year
1990
- .. .. ,1991
1992
1993
1994
1995
1996
1997
1998
1999
Thousand
Metric Tons
4,048 '
4,121
4,042
3,695
3,299
3,375
3,577
3,603 ;
3,713
3,779
balance for a "typical" aluminum smelter was taken from
Drexel University Project Team (1996).
PFC emission estimates were provided by the EPA
in cooperation with participants in the Voluntary Alumi-
num Industrial Partnership (VAIP) program.
Uncertainty
There is uncertainty 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 more accurate
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.
For PFC emission estimates, the uncertainty in the
aluminum production data is relatively low (± 1 to 2 per-
cent) compared to the uncertainty in the emissions factors
(± 10 to 50 percent). Uncertainty in the emissions factors
arises from the lack of comprehensive data for both the
slope coefficients and anode effect data. Currently, insuf-
ficient measurement data exist to quantify a relationship
between PFC emissions and anode effect minutes for all
smelters. Future inventories will incorporate additional data
reported by aluminum companies and ongoing research
into PFC emissions from aluminum production.
20 Although the carbon contained in the anode is considered a non-energy use of petroleum coke or tar pitch and the CO2 emissions it
generates should be included in the Industrial Processes chapter, information needed to distinguish individual non-energy uses of fossil
fuels is-unfortunately not available in DOE/EIA fuel statistics.
Industrial Processes 3-25
-------
Emissions of SF6 from aluminum fluxing and degas-
sing have not been estimated. Uncertainties exist as to
the quantity of SF6 used by the aluminum industry and
its rate of destruction in its uses as a degassing agent or
cover gas.
HCFC-22 Production
Trifluoromethane (HFC-23 or CHF3) is generated
as a by-product during the manufacture of
chlorodifluoromethane (HCFC-22), which is primarily em-
ployed in refrigeration and air conditioning systems and
as a chemical feedstock for manufacturing synthetic poly-
mers. Since 1990, production and use of HCFC-22 has
increased significantly as it has replaced chlorofluoro-
carbons (CFCs) in many applications. Because HCFC-22
depletes stratospheric ozone, its production for non-feed-
stock uses is scheduled to be phased out by 2020 under
the U.S. Clean Air Act.21 Feedstock production, in con-
trast, is permitted to continue indefinitely.
HCFC-22 is produced by the reaction of chloroform
(CHC13) and hydrogen fluoride (HF) in the presence of a
catalyst, SbCls. The reaction of the catalyst and HF pro-
duces SbClxFy, (where x + y = 5), which reacts with chlo-
rinated hydrocarbons to replace chlorine atoms with fluo-
rine. The HF and chloroform are introduced by submerged
piping into a continuous-flow reactor that contains the
catalyst in a hydrocarbon mixture of chloroform and par-
tially fluorinated intermediates. The vapors leaving the
reactor contain HCFC-21 (CHC12F), HCFC-22 (CHC1F2),
HFC-23 (CHF3), HC1, chloroform, and HF. Theunder-flu-
orinated intermediates (HCFC-21) and chloroform are then
condensed and returned to the reactor, along with re-
sidual catalyst, to undergo further fluorination. The final
vapors leaving the condenser are primarily HCFC-22, HFC-
23, HC1 and residual HF. HC1 is recovered as a useful
byproduct, and the HF is removed. Once separated from
HCFC-22, the HFC-23 is generally vented to the atmo-
sphere as an unwanted by-product, or may be captured
for use in a limited number of applications.
Emissions of HFC-23 in 1999 were estimated to be
30.4 Tg CO2 Eq. (2.6 Gg). This quantity represents a 13
percent decrease from emissions in 1990 (see Table 3-37).
Despite a 19 percent increase in production since 1990,
the intensity of HFC-23 emissions (the amount of HFC-23
emitted per kilogram of HCFC-22 manufactured) has de-
clined significantly.
In the future, production of HCFC-22 in the United
States is expected to decline as non-feedstock HCFC pro-
duction is phased-out. Feedstock production is antici-
pated to continue growing, mainly for manufacturing flu-
orinated polymers. U.S. producers of HCFC-22 are par-
ticipating in a voluntary program with the EPA to reduce
HFC-23 emissions.
Methodology
The EPA studied the conditions of HFC-23 genera-
tion, methods for measuring emissions, and technolo-
gies for emissions control. This effort was undertaken in
cooperation with the manufacturers of HCFC-22.
The methodology employed for estimating emis-
sions was based upon measurements of critical feed com-
ponents at individual HCFC-22 production plants. Indi-
vidual producers also measured HFC-23 concentrations
in their output stream by gas chromatography. Using
measurements of feed components and HFC-23 concen-
trations in output streams, the amount of HFC-23 gener-
ated was estimated. HFC-23 concentrations were deter-
mined at the point the gas leaves the chemical reactor;
therefore, estimates also include fugitive emissions.
Table 3-37: HFC-23 Emissions
from HCFC-22 Production
.... .
fc
Year
1990
;•;.:,, [:^::::,:-
1995
1996
1997
1998
1999
Tg CO, Eq.
34.8
27.1
31.2
30.1
40.0
30.4
Gg
3.0
l'x^
2.3
2.7
2.6
3.4
2.6
zl 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]
3-26 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Data Sources
Emission estimates were provided by the EPA's Cli-
mate Protection Division in cooperation 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 accounted for the declining in-
tensity of HFC-23 emissions over time. The use of a con-
stant emission factor would not have allowed for such
accounting. More simplistic emission estimates gener-
ally assume that HFC-23 emissions are between 2 and 4
percent of HCFC-22 production on a mass ratio basis. By
1996, the rate of HFC-23 generated in the United States as
a percent of HCFC-22 produced dropped, on average,
below 2 percent.
Semiconductor Manufacture
The semiconductor industry uses multiple long-lived
fluorinated gases in plasma etching and chemical vapor
deposition (CVD) processes. The gases most commonly
employed are trifluoromethane (HFC-23), perfluoromethane
(CF4), perfluoroethane (C2F6), nitrogen trifluoride (NF3),
and sulfur hexafluoride (SF6), although other compounds
such as perfluoropropane (C3F8) andperfluorocyclobutane
(c-C4F8) are also used. The exact combination of com-
pounds is specific to the process employed.
Plasma etching is performed to provide pathways
for the conducting material to connect individual circuit
components in the silicon, using HFCs, PFCs, SF6 and
other gases in plasma. The etching process creates fluo-
rine atoms that react at the semiconductor surface ac-
cording to prescribed patterns to selectively remove sub-
strate material. A single semiconductor wafer may require
as many as 100 distinct process steps that utilize these
gases. Chemical vapor deposition chambers, used for
depositing materials that will act as insulators and wires,
are cleaned periodically using PFCs and other gases.
During the cleaning cycle the gas is converted to fluorine
atoms in plasma, which etches away residual material from
chamber walls, electrodes, and chamber hardware. How-
ever, due to the low destruction efficiency (high disso-
ciation energy) of PFCs, a portion of the gas flowing into
the chamber flows unreacted through the chamber and,
unless emission abatement technologies are used, this
portion is emitted into the atmosphere. In addition to
emissions of unreacted gases, these compounds can also
be transformed in the plasma processes into a different
HFC or PFC compound, which is then exhausted into the
atmosphere. For example, when either CHF3 or C2F6 is
used in cleaning or etching, CF4 is generated and emitted
as a process by-product.
For 1999, it was estimated that total weighted emis-
sions of all fluorinated greenhouse gases by the U.S.
semiconductor industry were 6.8 Tg CO2 Eq. Combined
emissions of all fluorinated greenhouse gases are pre-
sented in Table 3-38 below. The rapid growth of this in-
dustry and the increasing complexity of semiconductor
products, which use more PFCs in the production pro-
cess, led to an increase in emissions of over 130 percent
since 1990. However, the growth rate in emissions has
slowed since 1997 due in part to an industry slow down
and possibly to the initial implementation of PFC emis-
sion reduction methods such as process optimization. In
the future, emissions are expected to stabilize and ulti-
mately decline over the next decade due to global indus-
try efforts to reduce emissions.
Table 3-38: Emissions of Fluorinated Greenhouse
Gases from Semiconductor Manufacture
L _1 Year
1990
1995
1996
1997
7 1998
1999
Tg C02 Eq.
2.9
5.5
7.0
7.0
6.8
6.8
Industrial Processes 3-27
-------
Methodology
Emissions have been estimated using two sets of
data. For 1990 through 1994, emissions were estimated
based on the historical consumption of silicon (square
centimeters), the estimated average number of intercon-
necting layers in the chips produced, and an estimated
per-layer emission factor. (The number of layers per chip,
and hence the PFC emissions per square centimeter of
silicon, increases as the line-width of the chip decreases.)
The average number of layers per chip was based on
industry estimates of silicon consumption by line-width
and of the number of layers per line-width. The per-layer
emission factor was based on the total annual emissions
reported by the participants in the PFC Emission Reduc-
tion Partnership for the Semiconductor Industry. For the
three years for which gas sales data are available (1992 to
1994), the estimates derived using this method are within
10 percent of the estimates derived using gas sales data
and average values for emission factors and global warm-
ing potentials (GWPs).
For 1995 through 1999, emissions were estimated
based on the total annual emissions reported by the par-
ticipants in the PFC Emission Reduction Partnership for
the Semiconductor Industry. Partners estimate their emis-
sions using a range of methods. The partners with rela-
tively high emissions typically multiply estimates of their
PFC consumption by process-specific emission factors
that they have either measured or obtained from tool sup-
pliers. To estimate total U.S. emissions from semiconduc-
tor manufacturing, based on reported partner emissions,
a per-plant emission factor was estimated for the part-
ners. This per-plant emission factor was then applied to
PFC-using plants operated by semiconductor manufac-
turers who were not partners, considering the varying
characteristics of the plants operated by partners and
non-partners (e.g., typical plant size and employed
linewidth technology). The resulting estimate of non-part-
ner emissions was added to the emissions reported by
the partners to obtain total U.S. emissions.
Data Sources
Aggregate emissions estimates from the semicon-
ductor manufacturers participating in the PFC Emission
Reduction Partnership were used to develop the 1995
through 1999 national emission estimate. Estimates of the
numbers of plants operated by partners and non-part-
ners, and information on the characteristics of those
plants, were derived from the International Fabs on Disk
(1999) database. Estimates of silicon consumed by line-
width from 1990 through 1994 were derived from informa-
tion from VLSI Research (1998), and the number of layers
per line-width was obtained from the Semiconductor In-
dustry Association's National Technology Roadmap
(1997).
Uncertainty
Emission estimates for this source are improving,
but are still relatively uncertain. Emissions vary depend-
ing upon the total amount of gas used and the tool and
process employed. Much of this information is tracked
by semiconductor manufacturers participating in the EPA's
PFC Emission Reduction Partnership; however, there is
some uncertainty associated with the data collected. In
addition, not all semiconductor manufacturers track this
information, so when it is extrapolated to total U.S. emis-
sions, the uncertainty related to gas use and emission
rates is much greater.
3-28 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
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 (Science and Policy Associates 1997). The gas has
been employed by the electric power industry in the United
States since the 1950s because of its dielectric strength
and arc-quenching characteristics. It is used in gas-insu-
lated substations, circuit breakers, and other switchgear.
Sulfur hexafluoride has replaced flammable insulating oils
in many applications and allows for more compact sub-
stations in dense urban areas.
Fugitive emissions of SF6 can escape from gas-
insulated substations and switch gear through seals, es-
pecially from older equipment. It can also be released
during equipment installation and when equipment is
opened for servicing, which typically occurs every few
years. In the past, some utilities vented SF6 to the atmo-
sphere during servicing; however, increased awareness
and the relatively high cost of the gas have reduced this
practice. In the United States, the voluntary partnership—
SF6 Emissions Reduction Partnership for Electric Power
Systems—is working with utilities to reduce their emis-
sions and will likely contribute to a reduction of emis-
sions over time.
Emissions of SF6 from electrical transmission and
distribution systems were estimated to be 25.7 Tg CO2
Eq. (1.1 Gg) in 1999. This quantity amounts to a 25 per-
cent increase over the estimate for 1990 (see Table 3-39).
Table 3-39: SF6 Emissions
from Electrical Transmission and Distribution
Year
1990
1995
1996
1997
1998
1999
Tg C02 Eq.
20.5
25.7
25.7
25.7
25.7
25.7
Gg
0.9 '
" 1
1
1.1
1.1
1.1
1.1
1.1
*
Methodology
Emissions of SF6 were estimated using a top-down,
or production-based approach. Specifically, emissions
were calculated based upon the following factors: 1) the
estimated U.S. production capacity for SF6, 2) the esti-
mated use of this production capacity, 3) the fraction of
U.S. SF6 production estimated to be sold annually to fill
or refill electrical equipment, and 4) the fraction of these
sales estimated to replace emitted gas.
Based on information gathered from chemical manu-
facturers, it was estimated that in 1994 U.S. production
capacity for SF6 was approximately 3,000 metric tons. It
was assumed that plants were operating at 90 percent
capacity, which was consistent with industry averages
and implied that 2,700 metric tons of SF6 were produced
in 1994. It was further assumed that 75 percent of U.S. SF6
sales were made to electric utilities and electrical trans-
mission and distribution equipment manufacturers. This
assumption is consistent with the estimate—given in Ko,
et al. (1993)—that worldwide, 80 percent of SF6 sales is
for electrical transmission and distribution systems. Sev-
enty-five percent of annual U.S. production in 1994 was
2,000 metric tons.
Finally, it was assumed that approximately 50 per-
cent of this production, or 1,000 metric tons, replaced gas
emitted into the atmosphere in 1994. This amount is
equivalent to 25.7 Tg CO2 Eq. (when rounding is per-
formed at the end of the calculation). The estimate is based
on information showing that emissions rates from elec-
tric equipment have been significant and atmospheric mea-
surements indicating that most of the SF6 produced in-
ternationally since the 1950s has been released. Emis-
sions from electrical equipment are known to have oc-
curred from the service and disposal of the equipment
and leaks during operation. Leaks from older equipment
were reported to release up to 50 percent of the equipment's
charge per year, although leaks from newer equipment
were reported to release considerably less (e.g., less than
1 percent of the charge per year).
It was assumed that emissions have remained con-
stant at 25.7 Tg CO2 Eq. since 1995.
Industrial Processes 3-29
-------
Data Sources
Emission estimates were provided by EPA's Climate
Protection Division in cooperation with U.S. electric utili-
ties and chemical producers.
Uncertainty
There is currently little verifiable data for estimat-
ing SFs emissions from electrical transmission and distri-
bution systems. Neither U.S. gas consumption nor emis-
sion monitoring data were available. In 1999, the EPA
launched a voluntary program to reduce emissions of
SF6 from equipment used to transmit and distribute elec-
tricity such as high voltage circuit breakers, substations,
transformers, and transmission lines. The EPA anticipates
that better information on SF6 emissions will be available
in the future and expects to update SF6 emission esti-
mates. The updated estimates will be derived from the
SFg emissions data reported by the Voluntary SF6 Emis-
sions Reduction Partnership. It is expected that new data
will reveal that emissions from electrical transmission and
distribution have declined in recent years.
Magnesium Production
and Processing
The magnesium metal production and casting in-
dustry uses sulfur hexafluoride (SF6) as a covergas to
prevent the violent oxidation of molten magnesium hi the
presence of air. A dilute gaseous mixture of SF6 with dry
air and/or carbon dioxide is blown over molten magne-
sium metal to induce and stabilize the formation of a pro-
tective crust. A minute portion of the SF6 reacts with the
magnesium to form a thin molecular film of mostly magne-
sium oxide and some magnesium fluoride. In accordance
with current IPCC guidance (IPCC 2000), it is assumed
that the amount of SF6 reacting in magnesium industry
application is negligible and thus all SF6 used is emitted
into the atmosphere. Sulfur hexafluoride has been used
in this application around the world for the last twenty
years. It has largely replaced salt fluxes, sulfur dioxide
(SOi), and boron trifluoride (BF3), which are drastically
more toxic and corrosive than SF6.
Table 3-40: SF6 Emissions
from Magnesium Production and Processing
Er- Year
1990
pffi'T""""1' ™" "" ""^H- T""~
l|fe* * 1" if(| "H, fen *»jS hMi^Klhmliil**
1995
r 1996
1997
1998
1999
Fg C02 Eq.
55
Ur*T"™'
fj^fSMt JS #l.i J
5.5
5.6
7.5
6.3
6.1
Gg
02
' J
02
••0.2V. .'
0.3 :,
0.3
0.3
For 1999, a total of 6.1 Tg CO2 Eq. (0.3 Gg) of SF6
was estimated to have been emitted by the magnesium
industry (see Table 3-40). There are no significant plans
for expansion of primary magnesium production in the
United States, but demand for magnesium metal by U.S.
casting companies is growing as auto manufacturers de-
sign more lightweight magnesium parts into vehicle mod-
els. Foreign magnesium producers are expected to meet
the growing U.S. demand for primary magnesium.
Methodology
Emission estimates for the magnesium industry were
revised this year to incorporate information provided by
EPA's SF6 Emission Reduction Partnership for the Magne-
sium Industry. EPA's magnesium industry partner compa-
nies represent 100 percent of U.S. primary production and
approximately 60 percent of the casting sector. U.S. magne-
sium metal production (primary and secondary) and con-
sumption data from 1993 to 1999 are available from the U.S.
Geological Survey (USGS).22 Emissions were estimated by
multiplying average industry emission factors (kg SFg/tonne
Mg produced or processed) by the amount of metal pro-
duced or consumed in the six major processes that require
SF6 melt protection; 1) primary production, 2) secondary
production, 3) die casting, 4) gravity casting, 5) wrought
products and, 6) anodes. The emission factors are derived
from EPA partner companies' reports, technical publications
(Gjestland and Magers 1996), and expert judgement. Although
not directly employed, the Norwegian Institute for Air Re-
search (NIAR1993) has reported a range of emission factors
for primary magnesium production as being from 1 to 5 kg of
SF6 per metric tonne of magnesium.
http://minerals.usgs.gov/minerals/pubs/commodity/magnesium/index.htmltmis
3-30 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Data Sources
Emission estimates were provided by EPA's Climate
Protection Division in cooperation with the U.S. EPA SF6
Emission Reduction Partnership for the Magnesium In-
dustry and the USGS.
Uncertainty
There are a number of uncertainties in these esti-
mates, including the assumption that SF6 does not react
nor decompose during use. It is possible that the melt
surface reactions and high temperatures associated with
molten magnesium would cause some gas degradation.
Box 3-1: Potential Emission Estimates of HFCs, PFCs, and SF6
Emissions of HFCs, PFCs and SF6 from industrial processes can be estimated in two ways, either as potential emissions or as actual
emissions. Emission estimates in this chapter are "actual emissions," which are defined by the Revised 1996IPCC Guidelines for
National Greenhouse Gas Inventories as estimates that take into account the time lag between consumption and emissions. In
; contrast, "potential emissions" are defined to be equal to the amount of a chemical consumed in a country, minus the amount of a
; ;;cjiemical recovered for destruction or export in the year of consideration. Potential emissions will generally be greater for a given year
, than actual emissions, since some amount of chemical consumed will be stored in products or equipment and will not be emitted to
r the atmosphere until a later date, if ever. Because all chemicals consumed will eventually be emitted into the atmosphere, in the long
term the cumulative emission estimates using the two approaches should be equivalent unless the chemical is captured and
destroyed. Although actual emissions are considered to be the more accurate estimation approach for a single year, estimates of
; potential emissions are provided for informational purposes.
' Separate estimates of potential emissions were not made for industrial processes that fall into the following categories:
• By-product emissions. Some emissions do not result from the consumption or use of a chemical, but are the unintended by-
;, products of another process. For such emissions, which include emissions of CF4 and C2F6 from aluminum production and of
HFC-23 from HCFC-22 production, the distinction between potential and actual emissions is not relevant.
- • Potential emissions that equal actual emissions. For some sources, such as magnesium production and processing, it is assumed
;•' that there is no delay between consumption and emission and that no destruction of the chemical takes place. It this case, actual
emissions equal potential emissions.
• Emissions that are not easily defined. In some processes, such as semiconductor manufacture, the gases used in the process
may be destroyed or transformed into other compounds, which may also be greenhouse gases. It is therefore not logical to
estimate potential emissions based on consumption of the original chemical.
; Table 3-41 presents potential emission estimates for HFCs and PFCs from the substitution of ozone depleting substances and SF6
• emissions from electrical transmission and distribution and other miscellaneous sources such as tennis shoes and sound insulating
: windows.23 Potential emissions associated with the substitution for ozone depleting substances were calculated through a combina-
; tion of the EPA's Vintaging Model and information provided by U.S. chemical manufacturers. For other SF6 sources, estimates were
Abased on an assumed U.S. SF6 production capacity and plant utilization to estimate total sales. The portion of this amount used for
; magnesium processing and assumed to be used for semiconductor manufacture were subtracted.
Table 3-41: 1999 Potential and Actual Emissions of HFCs, PFCs, and SF6 from Selected Sources (Tg C02 Eq.)
Source
Potential
Actual
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production
Semiconductor Manufacture
Magnesium Production and Processing
' Other SF. Sources*
181.4
6.1
61.0
56.7
10.0
30.4
6.8
6.1
25.7
,- Not applicable
includes Electrical Transmission and Distribution and, in the case of potential emissions, other miscellaneous sources.
See Annex P for a discussion of sources of SF6 emissions excluded from the actual emissions estimates in this report.
Industrial Processes 3-31
-------
As is the case for other sources of SF6 emissions, verifi-
able SF6 consumption data for magnesium production
and processing in United States were not available. Sul-
fur hexafluoride may also be used as a covergas for the
casting of molten aluminum with a high magnesium con-
tent; however, it is unknown to what extent this tech-
nique is used in the United States.
Industrial Sources of Criteria Pollutants
In addition to the main greenhouse gases ad-
dressed above, many industrial processes generate emis-
sions of criteria air pollutants. Total emissions of nitro-
gen oxides (NOX), carbon monoxide (CO), and nonmethane
volatile organic compounds (NMVOCs) from non-energy
industrial processes from 1990 to 1999 are reported in
Table 3-42.
Methodology and Data Sources
The emission estimates for this source were taken
directly from the EPA's National Air Pollutant Emissions
Trends, 1900-1999 (EPA 2000). Emissions were calcu-
lated either for individual categories or for many catego-
ries combined, using basic activity data (e.g., the amount
of raw material processed) as an indicator of emissions.
National activity data were collected for individual cat-
egories from various agencies. Depending on the cat-
egory, these basic activity data may include data on pro-
duction, 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 1997). The EPA currently de-
rives the overall emission control efficiency of a source
category from a variety of information sources, including
published reports, the 1985 National Acid Precipitation
and Assessment Program emissions inventory, and other
EPA databases.
Uncertainty
Uncertainties in these estimates are partly due to
the accuracy of the emission factors used and accurate
estimates of activity data.
Table 3-42: NOX, CO, and NMVOC Emissions from Industrial Processes (Gg)
Gas/Source
NO
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*
1990
921
152
88
3
343
335
9,502
1,074
2,395
69
487
5,479
3,110
575
111
1,356
364
705
1995
842
144
89
5
362
242
5,291
1,109
2,159
22
566
1,435
2,805
599
113
1,499
409
185
1996
977
113
75
14
397
377
7,227
955
1,455
64
509
4,244
2,354
351
66
1,169
383
385
1997
992
115
80
15
417
365
8,831
972
1,550
64
528
5,716
2,793
352
71
1,204
397
769
1998
924
117
80
15
424
289
5,612
981
1,544
65
535
2,487
2,352
357
71
1,204
402
318
1999
930
119
80
15
426
290
5,604
981
1,522
65
543
2,492
2,281
358
70
1,125
407
320
* Miscellaneous includes the following categories: catastrophic/accidental release, other combustion, health services, TSDFs (Transport,
Storage, and Disposal Facilities under the Resource Conservation and Recovery Act), cooling towers, and fugitive dust. It does not include
agricultural fires or slash/prescribed burning, which are accounted for under the Agricultural Residue Burning source.
Note: Totals may not sum due to independent rounding.
3-32 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
4. Solvent
TRie use of solvents and other chemical products can result in emissions of various ozone precursors (i.e.,
1 criteria pollutants).1 Nonmethane volatile organic compounds (NMVOCs), commonly referred to as "hydro-
carbons," 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. Surface coatings accounted for just under a majority of NMVOC emissions
from solvent use—44 percent in 1999—while "non-industrial"2 uses accounted for about 36 percent and degreasing
applications for 8 percent. Overall, solvent use accounted for approximately 27 percent of total U.S. emissions of
NMVOCs in 1999, and decreased 16 percent since 1990.
Although NMVOCs are not considered direct greenhouse gases, their role as precursors to the formation of
ozone—which is a greenhouse gas—results in their inclusion in a greenhouse gas inventory. Emissions from solvent
use have been reported separately by the United States to be consistent with the inventory reporting guidelines
recommended by the IPCC. These guidelines identify solvent use as one of the major source categories for which
countries should report emissions. In the United States, emissions from solvents are primarily the result of solvent
evaporation, whereby the lighter hydrocarbon molecules in the solvents escape into the atmosphere. The evaporation
process varies depending on different solvent uses and solvent types. The major categories of solvents uses include:
degreasing, graphic arts, surface coating, other industrial uses of solvents (i.e., electronics, etc.), dry cleaning, and
non-industrial uses (i.e., uses of paint thinner, etc.) Because many of these industrial applications also 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 1990 to 1999 are reported in Table 4-1.
Methodology
Emissions were calculated by aggregating solvent use data based on information relating to solvent uses from
different applications such as degreasing, graphic arts, etc. Emission factors for each consumption category were then
applied to the data to estimate emissions. For example, emissions from surface coatings were mostly due to solvent
evaporation as the coatings solidify. By applying the appropriate solvent emission factors to the type of solvents used
for surface coatings, an estimate of emissions was obtained. Emissions of CO and NOX result primarily from thermal and
catalytic Incineration of solvent laden gas streams from painting booths, printing operations, and oven exhaust.
1 Solvent usage in the United States also results in the emission of small amounts of hydrofluorocarbons (HFCs) and hydrofluoroethers
(HFEs), which are included under Substitution of Ozone Depleting Substances in the Industrial Processes chapter.
2 "Non-industrial" uses include cutback asphalt, pesticide application adhesives, consumer solvents, and other miscellaneous applications.
Solvent Use 4-1
-------
Table 4-1: Emissions of NOX, CO, and NMVOC from Solvent Use (Gg)
Activity
NO,
Degreasing
Graphic Arts
Dry Cleaning
Surface Coating
Other Industrial Processes3
Non-Industrial Processes'1
CO
Degreasing
Graphic Arts
Dry Cleaning
Surface Coating
Other Industrial Processes3
Non-Industrial Processes'1
NMVOCs
Degreasing
Graphic Arts
Dry Cleaning
Surface Coating
Other Industrial Processes3
Non-Industrial Processes'1
1990
1
+
+
+
1
+
+
4 ,
+
+
+
+
4
+
5,217
675
249
195
2,289
85
1,724
1995
3
+
1
+
2
+
+
5
+
+
1
1
3
+
5,609
716
307
209
2,432
87
1,858
1996
3
+
1
+
2
+
+
1
+
+
+
1
+
+
4,963
546
260
140
2,153
96
1,768
1997
3
+
1
+
2
+
+
1
+
+
+
1
+
+
5,098
566
266
148
2,228
100
1,790
1998
3
+
1
+
2
+
+
1
+
+
+
1
+
+
4,668
337
272
151
1,989
101
1,818
1999
3
+
1
+
2
_l_
+
1
+
+
+
1
+
+
4,376
337
266
152
1,938
103
1,581
a Includes rubber and plastics manufacturing, and other miscellaneous applications.
b Includes cutback asphalt, pesticide application adhesives, consumer solvents, and other miscellaneous applications.
Note: Totals may not sum due to independent rounding.
+ Does not exceed 0.5 Gg
Data Sources
The emission estimates for this source were taken
directly from the EPA's National Air Pollutant Emissions
Trends, 1900-1999 (EPA 2000). Emissions were calcu-
lated either for individual categories or for many catego-
ries combined, using basic activity data (e.g., the amount
of solvent purchased) as an indicator of emissions. Na-
tional activity data were collected for individual applica-
tions 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 1997). The EPA currently de-
rives the overall emission control efficiency of a source
category from a variety of information sources, including
published reports, the 1985 National Acid Precipitation
and Assessment Program emissions inventory, and other
EPA data bases.
Uncertainty
Uncertainties in these estimates are partly due to
the accuracy of the emission factors used and the reli-
ability of correlations between activity data and actual
emissions.
4-2 inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
5. Agriculture
Figure 5-1
gricultural activities contribute directly to emissions of greenhouse gases through a variety of processes.
This chapter provides an assessment of non-carbon dioxide emissions from the following source catego-
ries: enteric fermentation in domestic livestock, livestock manure management, rice cultivation, agricultural soil man-
agement, and agricultural residue burning (see Figure 5-1). Carbon dioxide emissions and removals from agriculture-
related land-use activities, such as conversion of grassland to cultivated land, are discussed in the Land-Use Change
and Forestry chapter.
In 1999, agricultural activities were responsible for emis-
sions of 488.8 Tg CO2 Eq., or 7.2 percent of total U.S. green-
house 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 21 and 6 percent of
total CH4 emissions from anthropogenic activities, respec-
tively. Of all domestic animal types, beef and dairy cattle
were by far the largest emitters of methane. Rice cultivation
and agricultural crop residue burning were minor sources of
methane. Agricultural soil management activities such as fer-
tilizer application and other cropping practices were the larg-
est source of U.S. N2O emissions, accounting for 69 percent.
Manure management and agricultural residue burning were
also smaller sources of N2O emissions.
Table 5-1 and Table 5-2 present emission estimates for
the Agriculture chapter. Between 1990 and 1999, CH4 emissions from agricultural activities increased by 4.7 percent
while N2O emissions increased by 10.7 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).
Agricultural Soil
Management
Enteric
Fermentation
Manure
Management
Rice Cultivation
Agricultural
Residue Burning
1.0
100
200
Tg CO2 Eq.
300
400
Agriculture 5-1
-------
Table 5-1: Emissions from Agriculture (Tg C02 Eq.)
Gas/Source
CH4
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Residue Burning
N20
Agricultural Soil Management
Manure Management
Agricultural Residue Burning
Total
Note: Totals may not sum due to independent
1990
165.1
129.5
26.4
8.7
0.5
285.4
269.0
16.0
0.4
450.5
rounding.
1995
177.4
136.3
31.0
9.5
0.5
302.1
285.4
16.4
0.4
479.5
1996
172.
132.
30.
3
2
7
8.8
0.
311.
6
8
294.6
16.8
0.4
484.1
1997
172.4
129.
32.
9.
0.
317.
299.
17.
0.
6
6
6
6
4
8
,1
,4
489.8
1998
173.4
127.
35.
10.
0.
317.
300.
17.
0.
491.
5
2
1
6
9
3
2
5
4
1999
172.9
127.2
34.4
10.7
0.
315.
298.
17.
6
9
3
2
0.4
488.8
Table 5-2: Emissions from Agriculture (Gg)
Gas/Source
CH<
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Residue Burning
N20
Manure Management
Agricultural Soil Management
Agricultural Residue Burning
Note: Totals may not sum due to independent
Enteric Fermentation
1990
7,862
6,166
1,256
414
25
921
52
868
1
rounding.
1995
8,446
6,492
1,477
452
24
975
53
921
1
material that non-:
1996
8,205
6,295
1,463
419
28
1,006
54
950
1
ramie
tan
1997
8,208
6,172
1,553
455
29
1,024
55
967
1
:tanim;
als
1998
8,259
6,072
1,677
481
30
1,026
55
969
1
cannoi
t.:
•V,
1999
8,232
6,057
1,638
509
28
1,019
55
962
1
RuminE
intan
Methane (CH4) is produced as part of normal di-
gestive processes in animals. During digestion, microbes
resident in an animal's digestive system ferment food
consumed by the animal. This microbial fermentation pro-
cess, referred to as enteric fermentation, produces meth-
ane as a by-product, which can be exhaled or eructated
by the animal. The amount of methane produced and ex-
creted by an individual animal depends primarily upon
the animal's digestive system, and the amount and type
of feed it consumes.
Among domesticated animal types, ruminant 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 products that can be
utilized by the animal. The microbial fermentation that
occurs in the rumen enables them to digest coarse plant
among all animal types.
Non-ruminant domesticated animals (e.g., pigs,
horses, mules, rabbits, and guinea pigs) also produce
methane emissions through enteric fermentation, although
this microbial fermentation occurs in the large intestine.
These non-ruminants have significantly lower methane
emissions on a per-animal basis than ruminants because
the capacity of the large intestine to produce methane is
lower.
In addition to the type of digestive system, an
animal's feed intake also affects methane emissions. In
general, a higher feed intake leads to higher methane
emissions. Feed intake is positively related to animal size,
growth rate, and production (e.g., milk production, wool
growth, pregnancy, or work). Therefore, feed intake var-
ies among animal types as well as among different man-
agement practices for individual animal types.
5-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Methane emission estimates from enteric fermenta-
tion are shown in Table 5-3 and Table 5-4. Total livestock
methane emissions in 1999 were 127.2 Tg CO2 Eq. (6,057
Gg) decreasing slightly since 1998. Beef cattle remain the
largest contributor of methane emissions from enteric fer-
mentation, accounting for 75 percent of emissions in 1999.
Emissions from dairy cattle in 1999 accounted for 21 per-
cent of total emissions, and the remaining 4 percent of emis-
sions can be attributed to horses, sheep, swine, and goats.
Methodology
Livestock emission estimates fall into two catego-
ries: cattle and other domesticated animals. Cattle, due to
their large population, large size, and particular digestive
characteristics, account for the majority of methane emis-
sions from livestock in the United States. Cattle produc-
tion systems in the United States are better characterized
in comparison with other livestock management systems.
A more detailed methodology (i.e., D?CC Tier 2) was there-
fore applied to estimating emissions for cattle. Emission
estimates for other domesticated animals were handled
using a less detailed approach (i.e., IPCC Tier 1).
Table 5-3: CH4 Emissions from Enteric Fermentation (Tg C02 Eq.)
While the large diversity of animal management prac-
tices cannot be precisely characterized and evaluated, sig-
nificant scientific literature exists that describes the quan-
tity of methane produced by individual ruminant animals,
particularly cattle. A detailed model that incorporates this
information and other analyses of livestock population,
feeding practices and production characteristics was used
to estimate emissions from cattle populations.
The methodology for estimating emissions from
enteric fermentation involves the four steps indicated
below.
Step 1: Characterize the Cattle Population
National cattle population statistics were disaggre-
gated into the following cattle sub-populations:
Dairy Cattle
• Calves
• Heifer Replacements
• Cows
Livestock Type
Beef Cattle
Dairy Cattle
Horses
Sheep
Swine
= Goats
Total
1990
94.7
28.7 zr :
2.1
1.9
1.7
0.3 t; ;.:'•; '.:
129.5
1995
103.0
27.5
2.3
1.5
1.9
0.3
136.3
1996
100.4
26.1
2.3
1.4
1.8
0.3
132.2
1997
97.8
26.0
2.3
1.3
1.8
0.2
129.6
1998
95.8
25.9
2.3
1.3
2.0
0.2
127.5
1999
95.4
26.1
2.3
1.2
1.9
0.2
127.2
Note: Totals may not sum due to independent rounding.
Table 5-4: CH4 Emissions from Enteric Fermentation (Gg)
:, Livestock Type
'Beef Cattle
\~ Dairy Cattle
if Horses
\ Sheep
t Swine
i Goats
""Total
1990
4,511
1,369 «;;•'-;
102
. Q1 ._,,.
81
13
6,166 . ;: ...
1995
4,902
1,308
108
72
88
12
6,492
1996
4,781
1,241
109
68
84
13
6,295
1997
4,658
1,240
111
64
88
11
6,172
1998
4,561
1,234
111
63
93
10
6,072
1999
4,544
1,245
111
58
89
10.
6,057
Note: Totals may not sum due to independent rounding.
Agriculture 5-3
-------
Beef Cattle
• Calves
• Heifer Replacements
• Heifer and Steer Stockers
• Animals in Feedlots
• Cows
• Bulls
Calf birth estimates, end of year population statis-
tics, detailed feedlot placement information, and slaughter
weight data were used hi the model to initiate and track
cohorts of individual animal types having distinct emis-
sions profiles. The key variables tracked for each of the
cattle population categories are described hi Annex J. These
variables include performance factors such as pregnancy
and lactation as well as average weights and weight gain.
Step 2: Characterize Cattle Nutrition
Diet characteristics were estimated by State and
region for U.S. dairy, beef, and feedlot cattle, and were
used to calculate Digestible Energy (DE) values and meth-
ane conversion rates (Ym) for each population category.
The IPCC recommends Ym values of 3.5 to 4.5 percent for
feedlot cattle and 5.5 to 6.5 percent for all other cattle.
Given the availability of detailed diet information for dif-
ferent regions and animal types in the United States, DE
and Ym values unique to the United States were devel-
oped, rather than using the recommended IPCC values.
The diet characterizations and estimation of DE and Ym
values were based on contact with State agricultural ex-
tension specialists, a review of published forage quality
studies, expert opinion, and modeling of animal physiol-
ogy. See Annex J for more details on the method used to
characterize cattle diets in the United States.
Step 3: Determine Cattle Emissions
In order to estimate methane emissions from cattle,
the population was divided into region, age, sub-type
(e.g., calves, heifer replacements, cows, etc.), and pro-
duction (i.e., pregnant, lactating, etc.) groupings to more
fully capture any differences in methane emissions from
these animal types. Cattle diet characteristics developed
under Step 2 were used to develop regional emission fac-
tors for each sub-category. Tier 2 equations from IPCC
(2000) were used to produce methane emission factors
for the following cattle types: dairy cows, beef cows, dairy
replacements, beef replacements, steer stockers, heifer
stackers, steer feedlot animals, heifer feedlot animals, and
steer and heifer feedlot step-up diet animals. To estimate
emissions from cattle, population data were multiplied by
the emission factor for each cattle type. More details can
be found in Annex J.
Step 4: Determine Other Livestock Emissions
Emission 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 from 1990 through 1999. Also, the variability in
emission factors for each of these other animal types (e.g.
variability by age, production system, and feeding prac-
tice within each animal type) is less than that for cattle.
See Annex J for more detailed information on the
methodology and data used to calculate methane emis-
sions from enteric fermentation.
Data Sources
Annual cattle population data were obtained from
the U.S. Department of Agriculture's National Agricul-
tural Statistics Service (1995a-d, 1996b, 1997,1998a, 1999a-
c,f-g, 2000a,c,d). DE and Ym values were used to calculate
emissions from cattle populations. DE and Ym for dairy
and beef cows, and for beef stockers, were calculated
from diet characteristics using a model simulating rumi-
nant digestion hi growing and/or lactating cattle (Donovan
and Baldwin 1999). For feedlot animals, DE and Ym values
recommended by Johnson (1999) were used. Values from
EPA (1993) were used for dairy replacement heifers. Weight
data were estimated from Feedstuffs (1998), Western
Dairyman (1998), and expert opinion. Annual livestock
population data for other livestock types, except horses,
as well as feedlot placement information were obtained
from the U.S. Department of Agriculture's National Agri-
cultural Statistics Service (USDA 1994a-b, 1998b-c,
1999d,e,h, 2000b,e). Horse data were obtained from the
Food and Agriculture Organization (FAO) statistical da-
tabase (FAO 2000). Methane emissions from sheep, goats,
pigs, and horses were estimated by using emission fac-
5-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
tors utilized in Crutzen et al. (1986). These emission fac-
tors are representative of typical animal sizes, feed in-
takes, and feed characteristics in developed countries.
The methodology is the same as that recommended by
IPCC OPCC/UNEP/OECD/EA1997, IPCC 2000).
Uncertainty
The basic uncertainties associated with estimating
emissions from enteric fermentation are the range of emis-
sion factors possible for the different animal types and
the number of animals with a particular emissions profile
that exist during the year. Although determining an emis-
sion factor for all possible cattle sub-groupings and diet
characterizations in the United States is not possible, the
enteric fermentation model that was used estimates the
likely emission factors for the major animal types and
diets. The model generates estimates for dairy and beef
cows, dairy and beef replacements, beef stackers, and
feedlot animals. The analysis departs from the recom-
mended IPCC (2000) DE and Ym values to account for
diets for these different animal types regionally. Based
on expert opinion and peer reviewer recommendations, it
is believed that the values supporting the development
of emission factors for the animal types studied are ap-
propriate for the situation in the United States.
In addition to the uncertainty associated with de-
veloping emission factors for different cattle population
categories based on estimated energy requirements and
diet characterizations, there is uncertainty in the estima-
tion of animal populations by animal type. The model
estimates the movement of animal cohorts through the
various monthly age and weight classes by animal type.
Several inputs affect the precision of this approach, in-
cluding estimates of births by month, weight gain of ani-
mals by age class, and placement of animals into feedlots
based on placement statistics and slaughter weight data.
However, it is believed that the model accurately charac-
terizes the U.S. cattle population and fully captures the
potential differences in emission factors between differ-
ent animal types.
Manure Management
The management of livestock manure can produce
anthropogenic methane (CH4) and nitrous oxide (N2O)
emissions. Methane is produced by the anaerobic decom-
position of manure. Nitrous oxide is produced as part of
the nitrogen cycle through the nitrification and denitrifica-
tion of the organic nitrogen in livestock manure and urine.
When livestock or poultry manure are stored or
treated in systems that promote anaerobic conditions (e.g.,
as a liquid in lagoons, ponds, tanks, or pits), the decom-
position of materials in the manure tends to produce CH4.
When manure is handled as a solid (e.g., in stacks or pits)
or deposited on pasture, range, or paddock lands, it tends
to decompose aerobically and produce little or no CH4. A
number of other factors related to how the manure is
handled also affect the amount of CH4 produced: 1) ambi-
ent temperature and moisture affect the amount of CH4
produced because they influence the growth of the bac-
teria responsible for methane formation; 2) methane pro-
duction generally increases with rising temperature and
residency time; and 3) for non-liquid based manure sys-
tems, moist conditions (which are a function of rainfall
and humidity) favor CH4 production. Although the ma-
jority of manure is handled as a solid, producing little
CH4, the general trend in manure management, particu-
larly for large dairy and swine producers, is one of in-
creasing use of liquid systems. In addition, use of daily
spread systems at smaller dairies is decreasing, due to
new regulations limiting the application of manure nutri-
ents, which has resulted in an increase of manure man-
aged and stored on site at these smaller dairies.
The composition of manure also affects the amount
of methane produced. Manure composition varies by
animal type and diet. The greater the energy content and
digestibility of the feed, the greater the potential for CH4
emissions. For example, feedlot cattle fed a high energy
grain diet generate manure with a high CH4-producing
capacity. Range cattle fed a low energy diet of forage
material produce manure with about 70 percent of the
CH4-producing potential of feedlot cattle manure. In ad-
dition, there is a trend in the dairy industry for dairy cows
Agriculture 5-5
-------
to produce more milk per year. These high-production
milk cows tend to produce more volatile solids in their
manure as milk production increases, which increases the
probability of CH4 production.
The production of nitrous oxide from livestock ma-
nure depends on the composition of the manure and urine,
the type of bacteria involved in the process, and the
amount of oxygen and liquid in the manure system. For
NoO emissions to occur, the manure must first be handled
aerobically where ammonia nitrogen is converted to ni-
trites (nitrification), and then handled anaerobically where
the nitrite is converted to N2O (denitrification). These
emissions are most likely to occur in dry manure handling
systems that have aerobic conditions, but can also un-
dergo saturation to create pockets of anaerobic condi-
tions. For example, manure at cattle drylots is deposited
on soil, oxidized to nitrite and nitrate nitrogen, and has
the potential to encounter saturated conditions follow-
ing rain events.
Certain N2O emissions are accounted, for and dis-
cussed under Agricultural Soil Management. These are
emissions from livestock manure and urine deposited on
pasture, range, or paddock lands, as well as emissions
from manure and urine that is spread onto fields either
directly as "daily spread" or after it is removed from ma-
nure management systems (e.g., lagoon, pit, etc.)
Table 5-5, Table 5-6, and Table 5-7 provide esti-
mates of CH4 and N2O emissions from manure manage-
ment by animal category. Estimates for methane emis-
sions in 1999 were 34.4 TgCO2Eq. (1,638 Gg), 30 percent
above emissions in 1990. The majority of the increase in
methane emissions over the time series was from swine
and dairy cow manure and is attributed to shifts by the
swine and dairy industries towards larger facilities. Larger
swine and dairy farms tend to use flush or scrape liquid
systems to manage and store manure. Thus the shift to-
wards larger facilities is translated into an increasing use
of liquid manure management systems. This shift was
accounted for by incorporating State-specific weighted
methane conversion factor (MCF) values calculated from
the 1992 and 1997 farm-size distribution reported in the
Census of Agriculture (USDA 1999e). In 1999, swine CH4
emissions decreased from 1998 due to a decrease in swine
animal populations.
As stated previously, dairies are moving away from
daily spread systems. Therefore, more manure is man-
aged and stored on site, contributing to additional CH4
emissions over the time series. The CH4 estimates also
account for changes in volatile solids production from
dairy cows correlated to their generally increasing milk
production. A description of the methodology is pro-
vided in Annex K.
Total N2O emissions from manure management sys-
tems in 1999 were estimated to be 17.2TgCO2Eq. (55 Gg).
The 7 percent increase in N2O emissions from 1990 to
1999 can be partially attributed to a shift in the poultry
industry away from the use of liquid manure management
systems, in favor of litter-based systems and high rise
houses. In addition, there was an overall increase in the
population of poultry and swine, although swine popula-
tions declined slightly in 1993,1995,1996, and 1999 from
previous years. The population of beef cattle in feedlots,
which tend to store and manage manure on site, also
increased.1 Although dairy cow populations went down
overall, the population of dairies managing and storing
manure on site—as opposed to using pasture, range, or
paddock or daily spread systems—went up. Therefore,
the increase in dairies using on-site storage to manage
their manure results in increased N2O emissions. As stated
previously, N2O emissions from livestock manure depos-
ited on pasture, range, or paddock land and manure im-
mediately applied to land in daily spread systems are ac-
counted for under Agricultural Soil Management.
Methodology
The methodologies presented in Good Practice
Guidance and Uncertainty Management in National
Greenhouse Gas Inventories (DPCC 2000) form the basis
of the CH4 and N2O emissions estimates for each animal
type. The calculation of emissions requires the following
information:
1 Methane emissions were mostly unaffected by this increase in the beef cattle population because feedlot cattle primarily use solid
storage systems, which produce little methane.
5-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 5-5: CH4 and N20 Emissions from Manure Management (Tg C02 Eq.)
T , - -
t Animal Type
ICH4
|T Dairy Cattle
F Beef Cattle
pfc Swine
P^Sheep :
|r Goats '
fc Poultry
f Horses
iN20
|~t Dairy Cattle
f Beef Cattle
S- Swine
SsFSheep
£-~: Goats
lEPoutoy
£• Horses
fcTotal
1990
26.4
8.9
3.2
11.1
0.1
+
2.6
0.6
16.0
4.2
4.9
: 0.3 :
: : - +
+
6.3
0.2
42.4
T»~-~. -* —-.---. -
1995
« S 31.0
11.1
3.5
—"•""" -. 13.2
0.1
**--'-* - • +• •
-w~- 2.6.'
0.6
"*"" 16.4
-4.0
5.3
~™~ 0.3
— — +
- - +
'- * ~" 6.5
""" ~" 0.2
*""'* 4?4
.......
1996
30.7
11.2
3.4
12.8
+
+
2.6
0.6
16.8
3.9
5.1
0.3
"+',
+
7.2
0.2
47.5
1997
32.6
11.8
3.4
14.1
+
+
2.6
0.7
17.1
3.9
5.4
0.4
+ -
. +
7.2
0.2
49.7
1998
35.2
12.2
3.4
16.2
+
+
2.7
0.7
17.2
3.8
5.5
0.4
+
+
7.2
0.2
52.4
1999
34.4
12.5
3.3
15.3
. +
+
2.6
0.7
17.2
3.8
5.5
0.4
+
+
7.2
0.2
51.6
|+ Does not exceed 0.05 Tg G02 Eq.
t Note: Totals may not sum due to independent rounding.
Table 5-6: CH4 Emissions from Manure Management (Gg)
| Animal type
f Dairy Cattle
r Beef Cattle
iJSwine
ilSheep
) Goats
f Poultry
ilHorses
flNote: Totals may
1990
'•• ': 422
150
527
3
1
125
29
1,256
not sum due to independent rounding.
___ iggg
•-
«,=5SM.^.r 63Q
fe-*-^s«*w-v«^
-."•""" 2
as,^,,,,.,. ^
^-•-*™ 122
.1,477
1996
532
164
610
2
1
123
31
1,463
1997
561
162
670
2
1
126
31
1,553
1998
583
160
770
2
1
130
31
1,677
1999
593 '•
159
728
2 "
1 i
124 :
31
1,638
Table 5-7: N20 Emissions from Manure Management (Gg)
-Animal Type
fe Dairy Cattle
| Beef Cattle
jpjwine.
fi'Sheep
f Goats
fc Poultry
flHorses
|Tota!
8S" Does not exceed 0.5 Gg
ipjote: Totals may not sum due to
1990
14
16
1
• +
+
20
1
52
independent rounding.
1995
... •
-f ••*: -.•'-'-.„ 13
•*«-.-» ,.-..,.;-. ^
BWM^SS,* . ^
^^^:* ' +
'^''" +
- u,,. ."**'*;* .' 2.1
",'-"-••••— ; 53
•SK"**"**** • • . .
1996
13
16
1
+
+
23
1
54
1997
12
17
1
+
+
23
1
55
f998
12
18
1
+
+
23
1
55
1999
12
18
1
+
+
23
1
55
Agriculture 5-7
-------
• Animal population data (by animal type and State)
• Amount of nitrogen produced (amount per head times
number of head)
• Amount of volatile solids produced (amount per head
times number of head)
• Methane producing potential of the volatile solids
(by animal type)
• Extent to which the methane producing potential is
realized for each type of manure management system
(by State and manure management system)
• Portion of manure managed in each manure manage-
ment system (by State and animal type)
• Portion of manure deposited on pasture, range, or
paddock or used in daily spread systems
Both CH4 and N2O emissions were estimated by
first determining activity data, including animal popula-
tion, waste characteristics, and manure management sys-
tem usage. For swine and dairy cattle, manure manage-
ment system usage was determined for different farm size
categories using data from USDA (USDA 1996b, 1998d,
2000h) and EPA (ERG 2000). For beef cattle and poultry,
manure management system usage data was not tied to
farm size (ERG 2000, USDA 20001). For other animal types,
manure management system usage was based on previ-
ous EPA estimates (EPA 1992).
Next, "base" methane conversion factors (MCFs)
and N2O emissions factors were determined for all manure
management systems. Base MCFs for dry systems and
base N2O emission factors for all systems were set equal
todefaultIPCCfactors(IPCC2000).BaseMCFsforKquid/
slurry and deep pit systems were calculated using the
average annual ambient temperature for the climate zone
where the animal populations are located. For anaerobic
lagoon systems, the base MCFs were calculated based on
the average monthly ambient temperature, the carryover
of volatile solids in the system from month to month due
to long storage tunes exhibited by these systems, and a
factor to account for management and design practices
that result in the loss of volatile solids from the system.
For each animal group—except sheep, goats, and
horses—the base emission factors were weighted to in-
corporate the distribution of management systems used
within each State to create an overall State-specific
weighted emission factor. To calculate this weighted fac-
tor, the percent of manure for each animal group managed
in a particular system in a State was multiplied by the
emission factor for that system and State, and then
summed for all manure management systems in the State.
Methane emissions were estimated by calculating
the volatile solids (VS) production for all livestock. For
each animal group except dairy cows, VS production was
calculated using a national average VS production rate
from the Agricultural Waste Management Field Hand-
book (USDA 1996b), which was then multiplied by the
average weight of the animal and the State-specific ani-
mal population. For dairy cows, the national average VS
constant was replaced with a mathematical relationship
between milk production and VS, which was then multi-
plied by State-specific average annual milk production
(USDA 2000J). The resulting VS for each animal group
was then multiplied by the maximum methane producing
capacity of the waste (B0), and the State-specific meth-
ane conversion factors.
Nitrous oxide emissions were estimated by deter-
mining total Kjeldahl nitrogen (TKN)2 production for all
livestock wastes using livestock population data and ni-
trogen excretion rates. For each animal group, TKN pro-
duction was calculated using a national average nitrogen
excretion rate from the Agricultural Waste Management
Field Handbook (USDA 1996b), which was then multi-
plied by the average weight of the animal and the State-
specific animal population. State-specific weighted N2O
emission factors specific to the type of manure manage-
ment system were then applied to total nitrogen produc-
tion to estimate N2O emissions.
See Annex K for more detailed information on the
methodology and data used to calculate methane and
nitrous oxide emissions from manure management.
Data Sources
Animal population data for all livestock types, ex-
cept horses and goats, were obtained from the U.S. De-
partment of Agriculture's National Agricultural Statistics
Service (USDA 1994a-b, 1995a-b, 1998a-b, 1999a-c, 2000a-
5 Total Kjeldahl nitrogen is a measure of organically bound nitrogen and ammonia nitrogen.
5-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
g). Horse population data were obtained from the
FAOSTAT database (FAO 2000). Goat population data
were obtained from the Census of Agriculture (USDA
1999d). Information regarding poultry turnover (i.e.,
slaughter) rate was obtained from State Natural Resource
Conservation Service (NRCS) personnel (Lange 2000).
Dairy cow and swine population data by farm size for each
State, used for the weighted MCF and emission factor
calculations, were obtained from the Census of Agricul-
ture, which is conducted every five years (USDA 1999e).
Manure management system usage data for dairy
and swine operations were obtained from USDA's Cen-
ters for Epidemiology and Animal Health (USDA 1996b,
1998d, 2000h) for small operations and from preliminary
estimates for EPA's Office of Water regulatory effort for
large operations (ERG 2000). Data for poultry layers were
obtained from a voluntary United Egg Producers' survey
(UEP 1999), previous EPA estimates (EPA 1992), and
USDA's Animal Plant Health Inspection Service (USDA
2000i). Data for beef feedlots were also obtained from
EPA's Office of Water (ERG 2000). Manure management
system usage data for other livestock were taken from
previous EPA estimates (EPA 1992). Data regarding the
use of daily spread and pasture, range, or paddock sys-
tems for dairy cattle were obtained from personal commu-
nications with personnel from several organizations, and
data provided by those personnel (Poe et al. 1999). These
organizations include State NRCS offices, State extension
services, State universities, USDA National Agriculture
Statistics Service (NASS), and other experts (Deal 2000,
Johnson 2000, Miller 2000, Stettler 2000, Sweeten 2000,
and Wright 2000). Additional information regarding the
percent of beef steer and heifers on feedlots was obtained
from contacts with the national USDA office (Milton 2000).
Volatile solids and nitrogen excretion rate data from
the USDA Agricultural Waste Management Field Hand-
book (USDA 1996a) were used for all livestock except
sheep, goats, and horses. Data from the American Society
of Agricultural Engineers (ASAE1999) were used for these
animal types. In addition, annual NASS data for average
milk production per cow per State (USDA 2000J) were used
to calculate State-specific volatile solids production rates
for dairy cows for each year. Nitrous oxide emission fac-
tors and MCFs for dry systems were taken from Good
Practice Guidance and Uncertainty Management in Na-
tional Greenhouse Gas Inventories (IPCC 2000). Meth-
ane conversion factors for liquid/slurry systems were cal-
culated based on average ambient temperatures of the
counties in which animal populations were located.
Uncertainty
The primary factors contributing to the uncertainty
in emission estimates are a lack of information on the
usage of various manure management systems in each
regional location and the exact methane generating char-
acteristics of each type of manure management system.
Because of significant shifts toward larger swine and
dairy farms, it is believed that increasing amounts of ma-
nure are being managed in liquid manure management
systems. The existing estimates reflect these shifts in the
weighted MCFs based on the 1992 and 1997 farm-size
data. However, the assumption of a direct relationship
between farm size and liquid system usage may not apply
in all cases and may vary based on geographic location.
In addition, the CH4 generating characteristics of each
manure management system type are based on relatively
few laboratory and field measurements, and may not match
the diversity of conditions under which manure is man-
aged nationally.
IPCC (2000) published default CH4 conversion fac-
tors of 0 to 100 percent for anaerobic lagoon systems, which
reflects the wide range in performance that may be achieved
with these systems. There exist relatively few data points
on which to determine country-specific MCFs for these
systems. In the United States, many livestock waste treat-
ment systems classified as anaerobic lagoons are actually
holding ponds that are substantially organically overloaded
and therefore not producing methane at the same rate as a
properly designed lagoon. In addition, these systems may
not be well operated, contributing to higher loading rates
when sludge is allowed to enter the treatment portion of
the lagoon or the lagoon volume is pumped too low to
allow treatment to occur. Rather than setting the MCF for
all anaerobic lagoon systems in the United States based
on data available from optimized lagoon systems, an MCF
methodology was developed that more closely matches
Agriculture 5-9
-------
observed system performance and accounts for the affect
of temperature on system performance.
However, there is uncertainty related to the new
methodology. The MCF methodology used includes a fac-
tor to account for management and design practices that
result in the loss of volatile solids from the management
system. This factor is currently estimated based on data
from anaerobic lagoons in temperate climates, and from
only three systems. However, this methodology is intended
to account for systems across arange of management prac-
tices. Future work in gathering measurement data from ani-
mal waste lagoon systems across the country will contrib-
ute to the verification and refinement of this methodology.
It will also be evaluated whether lagoon temperatures dif-
fer substantially from ambient temperatures and whether a
lower bound estimate of temperature should be established
for use with this methodology.
The IPCC provides a suggested MCF for poultry
waste management operations of 1.5 percent. Additional
study is needed in this area to determine if poultry high
rise houses promote sufficient aerobic conditions to war-
rant a lower MCF.
The default N2O emission factors published in Good
Practice Guidance and Uncertainty Management in
National Greenhouse Gas Inventories (IPCC 2000) were
derived using limited information. The IPCC factors are
global averages; U.S.-specific emission factors may be
significantly different. Manure and urine in anaerobic la-
goons and liquid/slurry management systems produce
methane at different rates, and would in all likelihood
produce nitrous oxide at different rates, although a single
N2O emission factors was used for both system types. In
addition, there are little data available to determine the
extent to which nitrification-denitrification occurs in ani-
mal waste management systems. Ammonia concentra-
tions that are present in poultry and swine systems sug-
gest that the N2O emission estimates may be high. Cur-
rent research to measure N2O from liquid manure systems
also suggests that these emissions may be overstated.
At this time, there are insufficient data available to de-
velop U.S.-specific N2O emission factors; however, this
is an area of on-going research, and warrants further study
as more data become available.
Although an effort was made to introduce the vari-
ability in volatile solids production due to differences in
diet for dairy cows, additional work is needed to estab-
lish the relationship between milk production and vola-
tile solids production. In addition, the corresponding dairy
methane emissions may be underestimated because milk
production was unable to be correlated to specific ma-
nure management systems in each State. A methodology
to assess variability in swine volatile solids production
would be useful in future inventory estimates.
Uncertainty also exists with the maximum CH4 pro-
ducing potential of volatile solids excreted by different
animal groups (i.e., B0). The B0 values used in the CH4
calculations are published values for U.S. animal waste.
However, there are several studies that provide a range
of B0 values for certain animals, including dairy and swine.
Separate B0 values for dairy cows and dairy heifers were
chosen to better represent the feeding regimens of these
animal groups. For example, dairy heifers do not receive
an abundance of high energy feed and consequently,
dairy heifer manure will not produce as much CH4 as ma-
nure from a milking cow. However, the data available for
B0 values are sparse, and do not necessarily reflect the
rapid changes that have occurred in this industry with
respect to feed regimens. Further investigation to these
waste characteristics is an area for further improvement.
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, caus-
ing anaerobic conditions in the soil to develop. Once the
environment becomes anaerobic, methane is produced
through anaerobic decomposition of soil organic matter
by methanogenic bacteria. As much as 60 to 90 percent
of the methane produced is oxidized by aerobic
methanotrophic bacteria in the soil (Holzapfel-Pschorn et
al. 1985, Sass et al. 1990). Some of the methane is also
leached away as dissolved methane in floodwater that
percolates from the field. The remaining un-oxidized meth-
ane is transported from the submerged soil to the atmo-
sphere primarily by diffusive transport through the rice
5-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
plants. Some methane also escapes from the soil via dif-
fusion and bubbling through floodwaters.
The water management system under which rice is
grown is one of the most important factors affecting meth-
ane 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), the lower stems and roots of the
rice plants are dead so the primary methane transport
pathway to the atmosphere is blocked. The quantities of
methane released from deepwater fields, therefore, are
believed to be significantly less than the quantities re-
leased from areas with more shallow flooding depths. 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, methane
emissions decrease or stop entirely. This is due to soil
aeration, which not only causes existing soil methane to
oxidize but also inhibits further methane production in
soils. All rice in the United States is grown under con-
tinuously flooded conditions; none is grown under
deepwater conditions. Mid-season drainage does not
occur except by accident (e.g., due to levee breach).
Other factors that influence methane emissions from
flooded rice fields include fertilization practices (espe-
cially the use of organic fertilizers), soil temperature, soil
type, rice variety, and cultivation practices (e.g., tillage,
and seeding and weeding practices). The factors that
determine the amount of organic material that is available
to decompose (i.e., organic fertilizer use, soil type, rice
variety,3 and cultivation practices) are the most impor-
tant variables influencing methane emissions over an
entire growing season because the total amount of meth-
ane released depends primarily on the amount of organic
substrate available. Soil temperature is known to be an
important factor regulating the activity of methanogenic
bacteria, and therefore the rate of methane production.
However, although temperature controls the amount of
time it takes to convert a given amount of organic mate-
rial to methane, that time is short relative to a growing
season, so the dependence of emissions over an entire
growing season on soil temperature is weak. The applica-
tion of synthetic fertilizers has also been found to influ-
ence methane emissions; in particular, both nitrate and
sulfate fertilizers (e.g., ammonium nitrate, and ammonium
sulfate) appear to inhibit methane formation.
Rice is cultivated in seven States: Arkansas, Cali-
fornia, Florida, Louisiana, Mississippi, Missouri, and
Texas. Soil types, soil temperatures, rice varieties, and
cultivation practices for rice vary from State to State, and
even from farm to farm. However, most rice farmers utilize
organic fertilizers in the form of rice residue from the pre-
vious crop, which is left standing, disked, or rolled into
the fields. Most farmers also apply synthetic fertilizer to
their fields, usually urea. Nitrate and sulfate fertilizers are
not commonly used in rice cultivation in the United States.
In addition, the climatic conditions of Arkansas, south-
west Louisiana, Texas, and Florida allow for a second, or
ratoon, rice crop. This second rice crop is produced from
regrowth of the stubble after the first crop has been har-
vested. Because the first crop's stubble is left behind in
ratooned fields, the amount of organic material that is
available for decomposition is considerably higher than
with the first (i.e., primary) crop. Methane emissions from
ratoon crops have been found to be considerably higher
than those from the primary crop.
Rice cultivation is a small source of methane in the
United States (Table 5-8 and Table 5-9). In 1999, methane
emissions from rice cultivation were 10.7 Tg CO2 Eq. (509
Gg)—only about 2 percent of total U.S. methane emis-
sions. Although annual emissions fluctuated up and
down between the years 1990 and 1999, there was a gen-
eral increase over the nine year period due to an increase
in harvested area. Between 1990 and 1999, total emis-
sions increased by 23 percent.
The factors that affect the rice acreage harvested in
any year vary from State to State. In Florida, the State
having the smallest harvested rice area, rice acreage is
largely a function of sugarcane acreage. Sugarcane fields
are flooded each year after harvest to control pests, and
on this flooded land a rice crop is grown along with a
ratoon crop of sugarcane (Schueneman 1997). In Mis-
3 The roots of rice plants shed organic material, which is referred to as "root exudate." The amount of root exudate produced by a rice
plant over a growing season varies among rice varieties.
Agriculture 5-11
-------
Table 5-8: CH4 Emissions from Rice Cultivation (Tg C02 Eq.)
I State
; Arkansas
California
, Florida
Louisiana
Mississippi
• Missouri
:. Texas
; Total
• Note: Totals may not sum due to
1990 ;:,
pr— — f
' ^STS^^=iT^
1.5 r •• ... ,'
0.1 :•" "-
2.7 ^ :._.;
0.5 r
0.2 i *
1.2 L . i ;;
8.7 ___
independent rounding.
1995
2.8
1.8
0.1
2.8
0.6
0.3
1.0
9.5
1996
2.5
1.9
0.1
2.6
0.5
0.3
1.0
8.8
1997
2:9
2.0
0.1
2.9
0.5
0.3
0.8
9.6
1998
3.2
1.8
0.1
3.0
0.6
0.4.
0.9
10.1
1999
3.5
2.1
0.1
3.0
0.7
0.5
0.8
10.7
Table 5-9: CH4 Emissions from Rice Cultivation (Gg)
- State
1 Arkansas
i California
1 Florida
f Louisiana
' Mississippi
1 Missouri
i Texas
i Total
; Note: Totals may not sum due to
1990 r^ -
121 ;•— »-^
72 r™
i ~-
10 """"" •
Si.™...' -BV "i'-~iJ*
55 * ;
414 I_,,LI,;
Independent rounding.
1995
135
85
5
133
30
14
50
452
1996
118
91
5
125
22
12
47
419
1997
140
94
4
136
25
15
40
455
1998
154
87
4
145
28
18
. - 44
481
1999
16
98
4
144
34
23
40
509
souri, rice acreage is affected by weather (e.g., rain dur-
ing the planting season may prevent the planting of rice),
the price differential between soybeans and rice (i.e., if
soybean prices are higher, then soybeans may be planted
on some of the land which would otherwise have been
planted in rice), and government support programs
(Stevens 1997). The price differential between soybeans
and rice also affects rice acreage in Mississippi. 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 therefore harvested area, are affected 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 Louisiana, rice area is influenced by
government programs, weather conditions (e.g., rainfall
during the planting season), as well as the price differen-
tial between rice and corn and other crops (Saichuk 1997).
Arkansas rice area has been influenced in the past by
government programs. However, due to the phase-out of
these programs nationally, which began in 1996, spring
commodity prices have had a greater effect on the amount
of land planted in rice in recent years (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 con-
ditions. Because season lengths are quite variable both
within and among States in the United States, and be-
cause flux measurements have not been taken under all
growing conditions in the United States, an earlier IPCC
methodology (IPCC/UNEP/OECD/BEA 1995) has been
applied here, using season lengths that vary slightly from
the recommended approach. The 1995 IPCC Guidelines
recommend multiplying a daily average emission factor
by growing season length and annual harvested area. The
IPCC Guidelines suggest that the "growing" season be
5-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
used to calculate emissions based on the assumption that
emission factors are derived from measurements over the
whole growing season rather than just the flooding sea-
son. Applying this assumption to the United States, how-
ever, would result in an overestimate of emissions be-
cause the emission factors developed for the United States
are based on measurements over the flooding, rather than
the growing, season. Therefore, the method used here is
based on the number of days of flooding during the grow-
ing season and a daily average emission factor, which is
multiplied by the harvested area. Agricultural extension
agents in each of the seven States in the United States
that produce rice were contacted to determine water man-
agement practices and flooding season lengths in each
State. Although all contacts reported that rice growing
areas were continuously flooded, flooding season lengths
varied considerably among States; therefore, emissions
were calculated separately for each State.
Emissions from ratooned and primary areas are es-
timated separately. Information on ratoon flooding sea-
son lengths was collected from agricultural extension
agents in the States that practice ratooning, and emis-
sion factors for both the primary season and the ratoon
season were derived from published results of field ex-
periments in the United States.
Data Sources
The harvested rice areas for the primary and ratoon
crops in each State are presented in Table 5-10. Data for
1990 through 1999 for all States except Florida were taken
from U.S. Department of 'Agriculture's National Agricul-
ture Statistics Data—Published Estimates Database
(USDA 2000). Harvested rice areas in Florida from 1990 to
1999 were obtained from Tom Schueneman (1999b, 1999c,
2000), a Florida Agricultural Extension Agent. Acreages
for the ratoon crops were derived from conversations with
the agricultural extension agents in each State. In Arkan-
sas, ratooning occurred only in 1998 and 1999, when the
ratooned area was less than 1 percent of the primary area
(Slaton 1999a, 2000). In Florida, the ratooned area was 50
percent of the primary area from 1990 to 1998 (Schueneman
1999a) and about 65 percent of the primary area in 1999
(Schueneman 2000). In the other two States in which ra-
tooning is practiced (i.e., Louisiana and Texas), the per-
centage of the primary area that was ratooned was con-
stant over the entire 1990 to 1999 period. In Louisiana it
was 30 percent (Linscombe 1999a, Bollich 2000), and in
Texas it was 40 percent (Klosterboer 1999a, 2000).
Information about flooding season lengths was
obtained from agricultural extension agents in each State
(Beck 1999, Guethle 1999, Klosterboer 1999b, Linscombe
1999b, Scardaci 1999a and 1999b, Schueneman 1999b,
Slaton 1999b, Street 1999a and 1999b). These data were
assumed to apply to 1990 through 1999, and are presented
in Table 5-11.
To determine what daily methane emission factors
should be used for the primary and ratoon crops, meth-
ane flux inf ormation from rice field measurements in the
United States was collected. Experiments which involved
the application of nitrate or sulfate fertilizers, or other
substances believed to suppress methane formation, as
well as experiments in which measurements were not made
over an entire flooding season or in which floodwaters
were drained mid-season, were excluded from the analy-
sis. This process left ten field experiments from California
(Cicerone etal. 1992), Texas (Sassetal. 1990,1991a, 1991b,
1992), and Louisiana (Lindau etal. 199 l,Lindau and Bollich
1993, Lindau et al. 1993, Lindau et al. 1995, Lindau et al.
1998).4 These experimental results were then sorted by
season and type of fertilizer amendment (i.e., no fertilizer
added, organic fertilizer added, and synthetic and organic
fertilizer added). The results for the primary crop showed
no consistent correlation between emission rate and type
or magnitude of fertilizer application. Although individual
experiments have shown a significant increase in emis-
sions when organic fertilizers are added, when the results
were combined, emissions from fields that received or-
ganic fertilizers were not found to be, on average, higher
4 In some of these remaining experiments, measurements from individual plots were excluded from the analysis because of the reasons
just mentioned. In addition, one measurement from the ratooned fields (i.e., the flux of 2.041 g/m2/day in Lindau and Bollich 1993) was
excluded since this emission rate is unusually high compared to other flux measurements in the United States, as well as in Europe and
Asia (IPCC/UNEP/OECD/IEA 1997).
Agriculture 5-13
-------
Table 5-10: Rice Areas Harvested (Hectares)
State/Crop
Arkansas
Primary
Ratoon*
California
Florida
Primary
Ratoon
Louisiana
Primaty
Ratoon
Mississippi
Missouri
Texas
Primary
Ratoon
Total
1990
485,633
NO
159,854
4,978
2,489
220,558
66,168
101,174
32,376
142,857
57,143
1,273,229
1995
542,291
- J NO
188,183
9,713
4,856
<"
230,676
69,203
116,552
45,326
128,693
51,477
1,386,969
1996
473,493
NO
202,347
8,903
4,452
215,702
64,711
84,176
38,446
120,599
48,240
1,261,068
1997
562,525
NO
208,822
7,689
3,845
235,937
70,781
96,317
47,349
104,816
41,926
1,380,008
1998
617,159
202
193,444
8,094
4,047
250,911
75,273
108,458
57,871
114,529
45,811
1,475,799
1999
665,722
202
216,512
7,229
4,673
249,292
74,788
130,716
74,464
104,816
41,926
1,570,340
Note: Totals may not sum due to independent rounding.
* Arkansas ratooning occurred only in 1998 and 1999.
NO (Not Occurring)
Table 5-11: Rice Flooding Season Lengths (Days)
State/Crop
Arkansas
Primary
Ratoon
California
Florida
Primary
Ratoon
Louisiana
Primary
Ratoon
Mississippi
Missouri
Texas
Primary
Ratoon
Low
60
30
100
90
40
90
70
68
80
60
40
High
80
40
145
110
60
120
75
82
100
80
60
that those from fields that receive synthetic fertilizer only.
In addition, there appeared to be no correlation between
fertilizer application rate and emission rate, either for syn-
thetic or organic fertilizers. These somewhat surprising
results are probably due to other variables that have not
been taken into account, such as timing and mode of
fertilizer application, soil type, cultivar type, and other
cultivation practices. There were limited results from ra-
tooned fields. Of those that received synthetic fertilizers,
there was no consistent correlation between emission rate
and amount of fertilizer applied. All the ratooned fields
that received synthetic fertilizer had emission rates that
were higher than the one ratoon experiment in which no
synthetic fertilizer was applied. Given these results, the
lowest and highest emission rates measured in primary
fields that received synthetic fertilizer only—which
bounded the results from fields that received both syn-
thetic and organic fertilizers—were used as the emission
factor range for the primary crop, and the lowest and high-
est emission rates measured in all the ratooned fields were
used as the emission factor range for the ratoon crop.
These ranges are 0.020 to 0.609 g/m2-day for the primary
crop, and 0.301 to 0.933 g/m2-day for the ratoon crop.
Uncertainty
The largest uncertainty in the calculation of CH4
emissions from rice cultivation is associated with the emis-
sion factors. Daily average emissions, derived from field
measurements in the United States, vary by more than
one order of magnitude. This variability is due to differ-
ences in cultivation practices, particularly the type, amount,
and mode of fertilizer application; differences in cultivar
type; and differences in soil and climatic conditions. By
separating primary from ratooned areas, this Inventory
has accounted for some of this. A range for both the pri-
mary (0.315 g/m2day ±93 percent) and ratoon crop (0.617
5-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
g/m2day ±51 percent) has been used in these calculations
to reflect the remaining uncertainty. Based on this range,
total methane emissions from rice cultivation in 1999 were
estimated to have been approximately 1.6 to 19.8 Tg CO2
Eq. (76 to 943 Gg), or 10.7 Tg CO2Eq. ±85 percent.
Two other sources of uncertainty are the flooding
season lengths and ratoon areas 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 uncer-
tainty. Even within a State, flooding seasons can vary by
county and cultivar type (Linscombe 1999a). Data on the
areas ratooned each year are not compiled regularly, so
expert judgement was used to estimate these areas.
The last source of uncertainty is in the practice of
flooding outside of the normal rice season. According to
agriculture extension agents, all of the rice-growing States
practice this on some part of their rice acreage, ranging
from 5 to 33 percent of the rice acreage. Fields are flooded
for a variety of reasons: to provide habitat for waterfowl,
to provide ponds for crawfish production, and to aid in
rice straw decomposition. To date, methane flux measure-
ments have not been undertaken in these flooded areas,
so this activity is not included in the emission estimates
presented here.
Agricultural Soil Management
Nitrous oxide (N2O) is produced naturally in soils
through the microbial processes of nitrification and deni-
trification.5 A number of agricultural activities add nitro-
gen to soils, thereby increasing the amount of nitrogen
available for nitrification and denitrification, and ultimately
the amount of N2O emitted. These activities may add nitro-
gen to soils either directly or indirectly (Figure 5-2). Direct
additions occur through various soil management prac-
tices and from the deposition of manure on soils by ani-
mals on pasture, range, and paddock (i.e., by animals whose
Figure 5-2
» -»t J*F=*r™^
This graphic illustrates the sources and pathways of nitrogen
that result in direct and indirect N2O emissions from agricul-
tural soils in the United States. Sources of nitrogen applied to,
or deposited on, soils are represented with arrows on the left-
hand side of the graphic. Emission pathways are also shown
with arrows. On the lower right-hand side is a cut-away view of
a representative section of managed soil; histosol cultivation is
represented here.
manure is not managed). Soil management practices that
add nitrogen to soils include fertilizer use, application of
managed livestock manure, disposal of sewage sludge,
production of nitrogen-fixing crops, application of crop
residues, and cultivation of histosols (i.e., soils with a high
organic matter content, otherwise known as organic soils).6
Indirect additions of nitrogen to soils occur through two
mechanisms: 1) volatilization and subsequent atmospheric
5 Nitrification and denitrification are two processes within the nitrogen cycle that are brought about by certain microorganisms in soils.
Nitrification is the aerobic microbial oxidation of ammonium (NH4) to nitrate (NO3), and denitrification is the anaerobic microbial
reduction of nitrate to dinitrogen gas (N2). Nitrous oxide is a gaseous intermediate product in the reaction sequence of denitrification,
which leaks from microbial cells into the soil and then into the atmosphere. Nitrous oxide is also produced during nitrification, although
by a less well understood mechanism (Nevison 2000).
6 Cultivation of histosols does not, per se, "add" nitrogen to soils. Instead, the process of cultivation enhances mineralization of old,
nitrogen-rich organic matter that is present in histosols, thereby enhancing N2O emissions from histosols.
Agriculture 5-15
-------
deposition of applied nitrogen;7 and 2) surface runoff and
leaching of applied nitrogen into groundwater and surface
water. Other agricultural soil management practices, such
as irrigation, drainage, tillage practices, and fallowing of
land, can affect fluxes of N2O, as well as other greenhouse
gases, to and from soils. However, because there are sig-
nificant uncertainties associated with these other fluxes,
they have not been estimated.
Agricultural soil management is the largest source
of N2O in the United States.8 Estimated emissions from
this source in 1999 are 298.3 Tg CO2 Eq. (962 Gg), or ap-
proximately 69 percent of total U.S. N2O emissions. Al-
though annual agricultural soil management emissions fluc-
tuated between 1990 and 1999, there was a general increase
in emissions over the ten-year period (Table 5-12 and Table
5-13).9 This general increase hi emissions was due prima-
rily to an increase in synthetic fertilizer use, manure pro-
duction, and crop production over this period. The year-
to-year fluctuations are largely a reflection of annual varia-
tions in synthetic fertilizer consumption and crop produc-
tion. Over the ten-year period, total emissions of N2O from
agricultural soil management increased by approximately
11 percent. Estimated emissions, by subsource, are pro-
vided in Table 5-14, Table 5-15, and Table 5-16.
Methodology
The methodology used to estimate emissions from
agricultural soil management is consistent with the Re-
vised 1996 IPCC Guidelines (ffCC/UNEP/OECD/IEA
1997), as amended by the IPCC Good Practice Guidance
and Uncertainty Management in National Greenhouse
Gas Inventories (IPCC 2000). The Revised 1996 IPCC
Guidelines divide this N2O source category into three com-
ponents: (1) direct emissions from managed soils due to
applied nitrogen and cultivation of histosols; (2) direct
emissions from soils due to the deposition of manure by
livestock on pasture, range, and paddock; and (3) indirect
emissions from soils induced by applied nitrogen.
Annex L provides more detailed information on the
methodologies and data used to calculate N2O emissions
from each of these three components.
Direct N20 Emissions from
Managed Soils
Direct N2O emissions from managed soils are com-
posed of two parts, which are estimated separately and
then summed. These two parts are 1) emissions due to
nitrogen applications, and 2) emissions from histosol cul-
tivation.
Estimates of direct N2O emissions from nitrogen
applications were based on the total amount of nitrogen
that is applied to soils annually through the following
practices: (a) the application of synthetic and organic
commercial fertilizers, (b) the application of livestock ma-
nure through both daily spread operations and through
the eventual application of manure that had been stored
hi manure management systems, (c) the application of
sewage sludge, (d) the production of nitrogen-fixing
crops, and (e) the application of crop residues. For each
of these practices, the annual amounts of nitrogen ap-
plied were estimated as follows:
a) Synthetic and organic commercial fertilizer nitro-
gen applications were derived from annual fertilizer con-
sumption data and the nitrogen content of the fertilizers.
b) Livestock manure nitrogen applications were
based on the assumption that all livestock manure is ap-
plied to soils except for two components: 1) a small por-
tion of poultry manure that is used as a livestock feed
supplement; and 2) the manure from pasture, range, and
paddock livestock. The manure nitrogen data were de-
rived from animal population and weight statistics, infor-
mation on manure management system usage, annual ni-
trogen excretion rates for each animal type, and informa-
tion on the fraction of poultry litter that is used as a
livestock feed supplement.
7 These processes entail volatilization of applied nitrogen as ammonia (NH3) and oxides of nitrogen (NOX), transformations of these
gases within the atmosphere (or upon deposition), and deposition of the nitrogen primarily in the form of particulate ammonium
(NH4), nitric acid (HNO3), and oxides of nitrogen.
8 Note that the emission estimates for this source category include applications of nitrogen to all soils, but the term "Agricultural Soil
Management" is kept for consistency with the reporting structure of the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).
9 Emission estimates for all years are presented in Annex L.
5-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 5-12: N20 Emissions from Agricultural Soil Management (Tg C02 Eq.)
pActivily
JjDirect
p*" Managed Soils
I;:; Pasture, Range, & Paddock Livestock
jpndirect
iKtal
1990 —'
. ^ .. ^...^
154.4 "^ ':"'-;
40.7 "~~- '
73.9 '-,:••- -'•'*
269.0 •"*
1995
206.4
1.62.4
44.0
79.0
285.4
1996
213.9
170.0
43.9
80.7
294.6
1997
219.4
176.8
42.6
80.4
299.8
1998
220.1
178.4
41.8
80.2
300.3
1999
218.0
176.6
41.4
80.3
298.3
fe Note: Totals may not sum due to independent rounding.
Table 5-13: N20 Emissions from Agricultural Soil Management (Gg)
ISr: .
i- Activity
JLBirect
ft; ; Managed Soils
If - Pasture, Range, & Paddock Livestock
t Indirect
ilbtal ' .
PNote: Totals may not sum due to independent
STn.- - -. - - •
Vft- ,.
1990
629
498
131
238
868 TO~ "
1995
666
524
142
255
921
1996
690
549
142
260
950
1997
708
570
138
259
967
1998
710
575
135
259
969
1999
703
570
133
259
962
rounding.
Table 5-14: Direct N20 Emissions from Managed Soils (Tg C02 Eq.)
pActivity
pCdmmercial Fertilizers*
siLivestock Manure
f Sewage Sludge
p ft Fixation
j| Crop Residue
S Hfstosol Cultivation
pbtal
1990
55.4
12.7 -
0.5
58.6
23.3
3.9 "
154.4 ~
1995
59.2
13.2
0.7
62.0
23.4
3.9
162.5
1996
61.2
13.4
0.7
64.0
26.9
3.9
170.1
1997
61.3
13.7
0.7
68.2
29.1
3.9
176.9
jbNote: Totals may not sum :due to independent rounding.
it ••* Excludes sewage sludge and livestock manure used as commercial fertilizers.
Table 5-15: Direct N20 Emissions from Pasture, Range, and Paddock Livestock Manure
f Animal Type
It Beef Cattle
:i: Dairy Cows
-.'Swine
f'Sheep -.'-•-
'. Goats
^'Poultry
ifiHorses
tlTDtal
1990
35.2 *"
1.7 ™
- + ^
"+ f
+
+
2.5
40.7
1995
38.9
1.5
+
+
+
+
2.7
44.0
1996
39.0
1.4
+
+
+
+
2.7
43.9
1997
37.8
1.3
+
+
+
+
2.7
42.6
1998
61.4
13.8
0.7
69.3
29.3
3.9
178.5
(TgC02Eq.)
1998
37.0
1.3
+
+
+
+
2.7
41.8
1999
61.8
13.8
0.7
68.2
28.3
3.9
176.7
1999
36.7
1.2
+
+
+
+
2.7
41.4
Mote: Totals may not sum due to independent rounding.
|^F Less than 0.5 Tg COj Eq.
Agriculture 5-17
-------
Table 5-16: Indirect N20 Emissions (Tg C02 Eq.)
Activity
Volatilization & Aim. Deposition
Commercial Fertilizers*
Livestock Manure
: Sewage Sludge
Surface Leaching & Runoff
Commercial Fertilizers*
" Livestock Manure
i Sewage Sludge
Total
1990
11.7
4.9
6.6
+
62.2
36.9
24.9
+
73.9
- '
1995
.__«„ ^ 5
" " ' 5.3
E , j 7-1
5s"-;?*-:';,! +
. "---'- 66-5
-. ' - 39.5
•"' "3 26.5
T* ;' 1 0.5
____ 79.0
1996
12.7
5.4
7.1
+
68.0
40.8
26.6
0.5
80.7
1997
12.6
5.5
7.0
.+
67.8
40.9
26.4
0.6
.80.4
1998
12.6
5.5
7.0
+
67.6
40.9
26.1
0.6
80.2
1999 '
12.6
5.5
6.9
'.'..+ '-::
67.7
41.2 :
26.0 ;
0:6 '
80.3 :
; Note: Totals may not sum due to independent rounding.
i * Excludes sewage sludge and livestock manure used as commercial fertilizers.
+ Less than 0.5 Tg C02 Eq.
c) Sewage sludge nitrogen applications were de-
rived from estimates of annual U.S. sludge production,
the nitrogen content of the sludge, and periodic surveys
of sludge disposal methods.
d) The amounts of nitrogen made available to soils
through the cultivation of nitrogen-fixing crops were
based on estimates of the amount of nitrogen in
aboveground plant biomass, which were derived from
annual crop production statistics, mass ratios of
aboveground residue to crop product, dry matter frac-
tions, and nitrogen contents of the plant biomass.
e) Crop residue nitrogen applications were derived
from information about which residues are typically left
on the field, the fractions of residues left on the field,
annual crop production statistics, mass ratios of
aboveground residue to crop product, and dry matter
fractions and nitrogen contents of the residues.
After the annual amounts of nitrogen applied were
estimated for each practice, each amount of nitrogen was
reduced by the fraction that is assumed to volatilize ac-
cording to the Revised 1996 IPCC Guidelines and the
IPCC Good Practice Guidance and Uncertainty Man-
agement in National Greenhouse Gas Inventories. The
net amounts left on the soil from each practice were then
summed to yield total unvolatilized applied nitrogen,
which was multiplied by the IPCC default emission factor
for nitrogen applications.
Estimates of annual N2O emissions from histosol
cultivation were based on estimates of the total U.S. acre-
age of histosols cultivated annually. To estimate annual
emissions, these areas were multiplied by the IPCC de-
fault emission factor for temperate histosols.10
Total annual emissions from nitrogen applications,
and annual emissions from histosol cultivation, were
then summed to estimate total direct emissions from
managed soils.
Direct N20 Emissions from Pasture, Range, and
Paddock Livestock Manure
Estimates of N2O emissions from this component
are based on amounts of nitrogen in the manure that is
deposited annually on soils by livestock in pasture, range,
and paddock. Estimates of annual manure nitrogen from
these livestock were derived from animal population and
weight statistics; information on the fraction of the total
population of each animal type that is on pasture, range,
or paddock; and annual nitrogen excretion rates for each
animal type. The annual amounts of manure nitrogen from
each animal type were summed over all animal types to
yield total pasture, range, and paddock manure nitrogen,
which was then multiplied by the IPCC default emission
factor for pasture, range, and paddock nitrogen to esti-
mate N2O emissions.
10 Note that the IPCC default emission factors for histosols have been revised in the IPCC Good Practice Guidance and Uncertainty
Management in National Greenhouse Gas Inventories (IPCC 2000). The revised default emission factor for temperate histosols (IPCC
2000) was used in these calculations.
5-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Indirect N20 Emissions from Soils
Indirect emissions of N2O are composed of two
parts, which are estimated separately and then summed.
These two parts are 1) emissions resulting from volatil-
ization and subsequent deposition of the nitrogen in ap-
plied fertilizers, applied sewage sludge, and all livestock
manure, and 2) leaching and runoff of nitrogen in applied
fertilizers, applied sewage sludge, and all livestock ma-
nure.11 The activity data (i.e., nitrogen in applied fertiliz-
ers, applied sewage sludge, and all livestock manure) are
the same for both parts, and were estimated in the same
way as for the direct emission estimates.
To estimate the annual amount of applied nitrogen
that volatilizes, the annual amounts of applied synthetic
fertilizer nitrogen, applied sewage sludge nitrogen, and
all livestock manure nitrogen, were each multiplied by the
appropriate IPCC default volatilization fraction. The three
amounts of volatilized nitrogen were then summed, and
the sum was multiplied by the EPCC default emission fac-
tor for volatilized/deposited nitrogen.
To estimate the annual amount of nitrogen that
leaches or runs off, the annual amounts of applied syn-
thetic fertilizer nitrogen, applied sewage sludge nitrogen,
and all livestock manure nitrogen were each multiplied by
the IPCC default leached/runoff fraction. The three
amounts of leached/runoff nitrogen were then summed,
and the sum was multiplied by the IPCC default emission
factor for leached/runoff nitrogen.
Total annual indirect emissions from volatilization,
and annual indirect emissions from leaching and runoff,
were then summed to estimate total indirect emissions of
N2O from managed soils.
Data Sources
The activity data used in these calculations were
obtained from numerous sources. Annual synthetic and
organic fertilizer consumption data for the United States
were obtained from annual publications on commercial
fertilizer statistics (TVA1991,1992a, 1993,1994; AAPFCO
1995,1996,1997,1998,1999). Fertilizer nitrogen contents
were taken from these same publications or Terry (1997).
Livestock population data were obtained from USDA
publications (USDA 1994b,c; 1995a,b; 1998a,c; 1999a-e;
2000a-g), the FAOSTAT database (FAO 2000), and Lange
(2000). Manure management information was obtained
from Poe et al. (1999), Safley et al. (1992), and personal
communications with agricultural experts (Anderson 2000,
Deal 2000, Johnson 2000, Miller 2000, Milton 2000, Stetfler
2000, Sweeten 2000, Wright 2000). Livestock weight data
were obtained from Safley (2000), USDA (1996,1998d),
and ASAE (1999); daily rates of nitrogen excretion from
ASAE (1999) and USDA (1996); and information about
the fraction of poultry litter used as a feed supplement
from Carpenter (1992). Data collected by the U.S. EPA
were used to derive annual estimates of land application
of sewage sludge (EPA 1993, Bastian 1999). The nitrogen
content of sewage sludge was taken from National Re-
search Council (1996). Annual production statistics for
nitrogen-fixing crops were obtained from USDA reports
(USDA 1994a, 1997,1998b, 1999f,2000i),abook on forage
crops (Taylor and Smith 1995, Pederson 1995, Beuselinck
and Grant 1995, Hoveland and Evers 1995), and personal
communications with forage experts (Cropper 2000,
Gerrish 2000, Hoveland 2000, Evers 2000, and Pederson
2000). Mass ratios of aboveground residue to crop prod-
uct, dry matter fractions, and nitrogen contents for nitro-
gen-fixing crops were obtained from Strehler and Stiitzle
(1987), Barnard and Kristoferson (1985), Karkosh (2000),
Ketzis (1999), and IPCC/UNEP/OECD/IEA (1997). Annual
production statistics for crops whose residues are left on
the field were obtained from USDA reports (USDA 1994a,
1997,1998b, 1999f). Aboveground residue to crop mass
ratios, residue dry matter fractions, and residue nitrogen
contents were obtained from Strehler and Stiitzle (1987),
Turn et al. (1997), and Ketzis (1999). Estimates of the frac-
tions of residues left on the field were based on informa-
tion provided by Karkosh (2000), and on information about
rice residue burning (see the Agricultural Residue Burn-
ing section). The annual areas of cultivated histosols were
estimated from 1982,1992, and 1997 statistics in USDA's
1992 and 1997 National Resources Inventories (USDA
1994d and 2000h, as cited in Paustian 1999 and Sperow
2000, respectively).
11 Total livestock manure nitrogen is used in the calculation of indirect N2O emissions because all manure nitrogen, regardless of how
the manure is managed or used, is assumed to be subject to volatilization and leaching and runoff.
Agriculture 5-19
-------
All emission factors, volatilization fractions, and
the leaching/runoff fraction were taken from the Revised
1996IPCC Guidelines (EPCC/UNEP/OECD/IEA 1997),
as amended by the IPCC Good Practice Guidance and
Uncertainty Management in National Greenhouse Gas
Inventories (IPCC 2000).
Uncertainty
The amount of N2O emitted from managed soils
depends not only on N inputs, but also on a large number
of variables, including organic carbon availability, O2
partial pressure, soil moisture content, pH, and soil tem-
perature. However, the effect of the combined interaction
of these other variables on N2O flux is complex and highly
uncertain. Therefore, the IPCC default methodology, which
is used here, is based only on N inputs and does not
utilize these other variables. As noted hi the Revised 1996
IPCC Guidelines (IPCGTJNEP/OECD/EA1997), this is a
generalized approach that treats all soils as being under
the same conditions. The estimated ranges around the
IPCC default emission factors provide an indication of
the uncertainty in the emission estimates due to this sim-
plified methodology. Most of the emission factor ranges
are about an order of magnitude, or larger. Developing an
emission estimation methodology that explicitly utilizes
these other variables will require more scientific research,
and will likely involve the use of process models.
Uncertainties also exist hi the activity data used to
derive emission estimates. In particular, the fertilizer sta-
tistics include only those organic fertilizers that enter the
commercial market, so non-commercial fertilizers (other
than the estimated manure and crop residues) have not
been captured. Also, the nitrogen content of organic fer-
tilizers varies by type, as well as within individual types;
however, average values were used to estimate total or-
ganic fertilizer nitrogen consumed. The livestock excre-
tion values, while based on detailed population and weight
statistics, were derived using simplifying assumptions
concerning the types of management systems employed.
Statistics on sewage sludge applied to soils were not
available on an annual basis; annual production and ap-
plication estimates were based on two data points that
were calculated from surveys that yielded uncertainty
levels as high as 14 percent (Bastian 1999). The produc-
tion statistics for the nitrogen-fixing crops that are forage
legumes are highly uncertain because statistics are not
compiled for these crops except for alfalfa, and the alfalfa
statistics include alfalfa mixtures. Conversion factors for
the nitrogen-fixing crops were based on a limited number
of studies, and may not be representative of all condi-
tions hi the United States. Data on crop residues left on
the field are not available, so expert judgement was used
to estimate the amount of residues applied to soils. And
finally, the estimates of cultivated histosol areas are un-
certain because they are from a natural resource inven-
tory that was not explicitly designed as a soil survey.
However, these areas are consistent with those used in
the organic soils component of the Land-Use Change
and Forestry Chapter. Also, all histosols were assigned
to the temperate climate regime; however, some of these
areas are in subtropical areas, and therefore may be expe-
riencing somewhat higher emission rates.12
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 left on or plowed back into the field,
composted and then applied to soils, landfilled, or burned
in the field. Alternatively, they can be collected and used
as a fuel or sold in supplemental feed markets. Field burn-
ing of crop residues is not considered a net source of
carbon dioxide (CO2) because the carbon released to the
atmosphere as CO2 during burning is assumed to be reab-
sorbed during the next growing season. Crop residue
burning is, however, a net source of methane (CH4), ni-
trous oxide (N2O), carbon monoxide (CO), and nitrogen
oxides (NOX), which are released during combustion.
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, corn, barley, soybeans,
lz As discussed in Annex L, these issues regarding histosols will be researched in future U.S. Inventories.
5-20 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
and peanuts, and of these residues, less than 5 percent is
burned each year, except for rice.13 Annual emissions from
this source over the period 1990 through 1999 averaged
approximately 0.6 Tg CO2Eq. (28 Gg) of CH4,0.4 Tg CO2
Eq. (1 Gg) of N20,740 Gg of CO, and 33 Gg of NOX (see
Table 5-17 and Table 5-18).
Methodology
The methodology for estimating greenhouse gas
emissions from field burning of agricultural residues is
consistent with the Revised 1996IPCC Guidelines (IPCC/
UNEP/OECD/IEA1997). In order to estimate the amounts
of carbon and nitrogen released during burning, the fol-
lowing 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)14
Nitrogen Released = (Annual Crop
Production)x(Residue/Crop Product
Ratio)x(Fraction of Residues Burned
in situ)x(Dry Matter Content of the
Residue)x(Burning Efficiency)x(Nitrogen
Content of the Residue)x (Combustion
Efficiency)
Emissions of CH4 and CO were calculated by multi-
plying the amount of carbon released by the appropriate
IPCC default emission ratio (i.e., CH4-C/C or CO-C/C).
Similarly, N2O and NOX emissions were calculated by
multiplying the amount of nitrogen released by the ap-
propriate IPCC default emission ratio (i.e., N2O-N/N or
NOX-N/N).
Data Sources
The crop residues that are burned in the United
States were determined from various State level green-
house gas emission inventories (ILENR 1993, Oregon
Department of Energy 1995, Wisconsin Department of
Natural Resources 1993) and publications on agricultural
Table 5-17: Emissions from Agricultural Residue Burning (Tg C02 Eq.)
P Gas/Crop Type
iCH4 ~~ • - -- '••••'
| Wheat
ipf Rice .
|L Sugarcane
p. Corn
itBarley
« '.'.. Soybeans
£, Peanuts
tN20
ITWheat
te Rice
fe,. Sugarcane
tCorn
^Barley ""
^Soybeans
E: Peanuts
&Iotal
ft-f Does not exceed 0.05 Tg C02 Eq.
fSote: Totals may not sum due to independent
1990
0.5
01
0.1
+
0.2
+
0.1
+
0.4
+
+
+
0.1
+
0.2
+
0.9
rounding.
-~~-~ 1995
mm- or ^
0.1
*****"*""* +
*** "* 0.2
+ •
0.1
0.4
+
+
+
~" 0.1
— +
0.2
+
'• I ~ 0.9
1996
0.6
0.1
0.1
+
0.3
+
0.1
+
0.4
+
+
+
0.1
• . +
0.2
. +
1.0
1997
0.6
0.1
+
+
0.3
+
0.2
+
0.4
+
+
+
0.1
+
0.3
+
1.0
1998
0.6
0.1
+
+
0.3
+
0.2
+
0.5
+
+
+
0.1
+
0.3
+
1.1
1999
0.6
0.1
+
+
0.3
+.
0.2
+
0.4
+
+
+
0.1
+
0.3
+
1.0
13 The fraction of rice straw burned each year is significantly higher than that for other crops (see "Data Sources" discussion below).
14 Burning Efficiency is defined as the fraction of dry biomass exposed to burning that actually burns. Combustion Efficiency is defined
as the fraction of carbon in the fire that is oxidized completely to CO2. In the methodology recommended by the IPCC, the "burning
efficiency" is assumed to be contained in the "fraction of residues burned" factor. However, the number used here to estimate the
"fraction of residues burned" does not account for the fraction of exposed residue that does not burn. Therefore, a "burning efficiency
factor" was added to the calculations.
Agriculture 5-21
-------
Table 5-18: Emissions from Agricultural Residue Burning (Gg)*
Gas/Crop Type
CH4
Wheat
Rice
Sugarcane
Corn
Bartey
Soybeans
Peanuts
N20
Wheat
Rice
Sugarcane
Com
Barley
Soybeans
Peanuts
CO
Wheat
Rice
Sugarcane
Com
Barley
Soybeans
Peanuts
NO*
Wheat
Rice
Sugarcane
Com
Bartey
Soybeans
Peanuts
* Full molecular weight basis.
•f Does not exceed 0.5 Gg
Note: Totals may not sum due to
1990
25
5
2
1
11
1
6
+
1
+
+
+
+
+
1
+
668
137
65
18
282
16
148
2
28
4
2
+
7
1
14
+
Independent rounding.
1995
24
4
2
•-...-. i
10
1
6
.. : +
1
,. • +
.' +
+
^ +
+
1
----- : , +
641
109
65
20
263
13
167
2
28
3
2
+
6
: +
16
+
1996
28
4
3
1
13
1
7
+
1
+
+
+
+
+
1
+
735
114
73
19
328
15
183
2
32
3
3
+
8
+
17
+
1997
29
5
2
1
12
1
8
+
1
+
+
+
+
+
1
+
750
124
55
21
328
13
207
2
33
3
2
+
8
+
20
+
1998
30
5
2
1
13
1
8
+
1
+
+
+
•: +
+
1
+
776
128
53
22
347
13
211
2
34
3
2
+
8
.--' + '••
20
+
1999
28
4
2
1
13
+ :
8
+
1
+
+
'.. +
+
+
1
• . +
740
115
49
23
336
11
203
2
33
3
2
+
8
+
19
+
burning in the United States (Jenkins et al. 1992, Turn et
al. 1997, EPA 1992).
Crop production data were taken from the USDA's
Field Crops, Final Estimates 1987-1992, 1992-1997
(USDA1994,1998) and Crop Production 1999 Summary
(USDA 2000). The production data for the crop types
whose residues are burned are presented in Table 5-19.
The percentage of crop residue burned was assumed
to be 3 percent for all crops in all years, except rice, based
on State inventory data (ILENR 1993, Oregon Depart-
ment of Energy 1995,Noller 1996, Wisconsin Department
of Natural Resources 1993, and CibrowsM 1996). Estimates
of the percentage of rice acreage on which residue burn-
ing took place were obtained on a State-by-State basis
from agricultural extension agents in each of the seven
rice-producing States (Bollich 2000; Guethle 1999,2000;
Fife 1999; California Air Resources Board 1999;
Klosterboer 1999a, 1999b, 2000; Linscombe 1999a, 1999b;
Najita 2000; Schueneman 1999a, 1999b; Slaton 1999a,
1999b, 2000; Street 1999a, 1999b, 2000) (see Table 5-20
and Table 5-21). The estimates provided for Arkansas
and Florida remained constant over the entire 1990
through 1999 period, while the estimates for all other States
varied over the time series. For California, it was assumed
that the annual percents of rice acreage burned in Sacra-
mento Valley are representative of burning in the entire
State, because the Valley accounts for over 95 percent of
the rice acreage in California (Fife 1999). The annual per-
cents of rice acreage burned in Sacramento Valley were
obtained from a report of the California Air Resources
5-22 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 5-19: Agricultural Crop Production (Thousand Metric Tons of Product)
Crop
,:-. Wheat
i Rice3
':- Sugarcane
hCornb
pBarley
^Soybeans
* Peanuts
;-. a Does not Include rice production I
•; b Corn for grain (i.e., excludes corn
1990
74,292
7,080
25,525
201,534
9,192
52,416
1,635
n Florida because rice
for silage).
1995
59,404
7,887
*" ' 27,922
""" " 187,970
—~ , ^^
59,174
1,570
residues are not burned in
1996
61,980
7,784
26,729
234,518
8,544
64,780
1,661
Florida (see
1997
67,534
8,300
28,766
233,864
7,835
73,176
1,605
Table 5-20).
1998
69,327
8,530
30,896
247,882
7,667
74,598
1,798
1999
62,662
9,546
32,406
239,719
6,137
71,928
1,755
Table 5-20: Percentage of Rice Area Burned by State
E State
;; Arkansas
!; California
|! Florida5
\ Louisiana
^Mississippi
!>• Missouri
'": Texas
;!- a:Values provided
;;. b Burning of crap
Percent Burned
1990-1998
10
variable"
0
6
- 5 - .
3.5
1
in Table 5-21.
residues is illegal in Florida.
Percent Burned
1999
10 :
23
0
0
10
5 '••
2
Table 5-21: Percentage of Rice Area Burned
*;' Year California United States
?:-. _1?90
1995
»-. 1996
• 1997
• 1998
b 1999
*'.
75
'"' ^59"*" """
63
34
33
23
.. ._,:.J6;
"""Ts""
17
12
11
9
Board (1999). These values declined over the 1990 through
1999 period because of a legislated reduction in rice straw
burning (see Table 5-21). To derive the national percent-
age of rice acreage burned each year, the acreages burned
in each State were summed and then divided by total U.S.
rice harvested area (Table 5-21).
All residue/crop product mass ratios except sugar-
cane were obtained from Strehler and Stutzle (1987). The
datum for sugarcane is from University of California
(1977). Residue dry matter contents for all crops except
soybeans and peanuts were obtained from Turn et al.
(1997). Soybean dry matter content was obtained from
Strehler and Stiitzle (1987). Peanut dry matter content was
obtained through personal communications with Jen
Ketzis (1999), who accessed Cornell University's Depart-
ment of Animal Science's computer model, Cornell Net
Carbohydrate and Protein System. The residue carbon
contents and nitrogen contents for all crops except soy-
beans and peanuts are from Turn et al. (1997). The resi-
due carbon content for soybeans and peanuts is the IPCC
default (IPCC/UNEP/OECD/TEA1997). The nitrogen con-
tent of soybeans is from Barnard and Kristoferson (1985).
The nitrogen content of peanuts is from Ketzis (1999).
These data are listed in Table 5-22. The burning efficiency
was assumed to be 93 percent, and the combustion effi-
ciency was assumed to be 88 percent, for all crop types
(EPA 1994). Emission ratios for all gases (see Table 5-23)
were taken from the Revised 1996 IPCC Guidelines (ffCC/
UNEP/OECD/E3A1997).
Uncertainty
The largest source of uncertainty in the calculation
of non-CO2 emissions from field burning of agricultural
residues is in the estimates of the fraction of residue of
each crop type burned each year. Data on the fraction
burned, as well as the gross amount of residue burned
each year, are not collected at either the national or State
level. In addition, burning practices are highly variable
among crops, as well as among States. The fractions of
residue burned used in these calculations were based
upon information collected by State agencies and in pub-
lished literature. It is likely that these emission estimates
will continue to change as more information becomes
available in the future.
Agriculture 5-23
-------
Table 5-22: Key Assumptions for Estimating Emissions from Agricultural Residue Burning4
Crop
Wheat
Rice
Sugarcane
Com
Bartey
Soybeans
Peanuts
Reisduce/Crop
Ration
1.3
1.4
0.8
1.0
1.2
2.1
1.0
Fraction of
Residue Burned
0.03
variable
0.03
0.03
0.03
0.03
0.03
Dry Matter
Fraction
0.93
0.91
0.62
0.91
0.93
0.87
0.86
Carbon
Fraction
0.4428
0.3806
0.4235
0.4478
0.4485
0.4500
0.4500
Nitrogen
Fraction
0.0062
0.0072
0.0040 :
0.0058
0.0077
0.0230
0.0106
* The burning efficiency and combustion efficiency for all crops were assumed to be 0.93 and 0.88, respectively.
Other sources of uncertainty include the residue/
crop product mass ratios, residue dry matter contents,
burning and combustion efficiencies, and emission ra-
tios. A residue/crop product ratio for a specific crop can
vary among cultivars, and for all crops except sugarcane,
generic residue/crop product ratios, rather than ratios
specific to the United States, have been used. Residue
dry matter contents, burning and combustion efficien-
cies, and emission ratios, all can vary due to weather and
other combustion conditions, such as fuel geometry. Val-
ues for these variables were taken from literature on agri-
cultural biomass burning.
Table 5-23: Greenhouse Gas Emission Ratios
Gas
Emission Ratio
""• : CH4a
^ coa
; N20b
N0xb
0.004
: 0.060
0.007
0.121
'f-a Mass of carbon compound released (units of C) relative to
|:rnass of total carbon rejeasedjrbrn burning (units of C).
|,|.Mass of .nitrogen compound released (units of N) relative to
r'rnass of total nitrogen released from burning (units of N).
5-24 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
6.Land-Use Change
and Forestry
iis chapter provides an assessment of the net carbon dioxide (CO2) flux caused by 1) changes in forest
carbon stocks; 2) changes in agricultural soil carbon stocks; and 3) changes in yard trimming carbon stocks
in landfills. Seven components of forest carbon stocks are analyzed: trees, understory, forest floor, forest soils, logging
residues, wood products, and' landfilled wood. The estimated CO2 flux from each of these forest components is based
on carbon stock estimates developed by the USDA Forest Service, using methodologies that are consistent with the
Revised 1996IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). Changes in agricultural soil carbon stocks include
mineral and organic soil carbon stock changes due to agricultural land use and land management (i.e., use and
management of cropland and grazing land), and emissions of CO2 due to the application of crushed limestone and
dolomite to agricultural soils. The methods in the Revised 1996 IPCC Guidelines were used to estimate all three
components of changes in agricultural soil carbon stocks. Changes in yard trimming carbon stocks in landfills were
estimated using EPA's method of analyzing life cycle greenhouse gas emissions and sinks associated with solid waste
management (EPA 1998). Note that the chapter title "Land-Use Change and Forestry" has been used to retain consis-
tency with IPCC reporting structure; however, the chapter covers land-use activities, as well as land-use change and
forestry activities. Therefore, except in table titles, the term "land use, land-use change, and forestry" will be used in
the remainder of this chapter.
Unlike the assessments in other chapters, which are based on annual activity data, the flux estimates hi this
chapter, with the exception of emissions from liming and carbon storage associated with yard trimmings disposed in
landfills, are based on periodic activity data in the form of forest and land use surveys. Carbon dioxide fluxes from
forest carbon stocks and from agricultural soils are calculated on an average annual basis over five or ten year periods.
The resulting annual averages are applied to years between surveys. As a result of this data structure, estimated CO2
fluxes are constant over multi-year intervals. In addition, because the most recent national forest and land use surveys
were completed for the year 1997, the estimates of the CO2 flux from forest carbon stocks are based in part on modeled
projections of stock estimates for years since 1997.
Estimated total annual net CO2 flux from land use, land-use change, and forestry in 1999 is 990.4 Tg CO2 Eq. (270
Tg C) net sequestration (Table 6-1 and Table 6-2). This represents an offset of approximately 15 percent of total U.S.
CO2 emissions. Total land use, land-use change, and forestry net sequestration declined by about 7 percent between
1990 and 1999. This decline is primarily due to increasing forest harvests and land-use changes, which resulted in
decreasing net sequestration rates for forests.
Land-Use Change and Forestry 6-1
-------
Table 6-1: Net C02 Flux from Land-Use Change and Forestry (Tg C02 Eq.)
Component
Forests
Agricultural Soils
Landfilled Yard Trimmings
Total Net Flux
1990
(1,001.7)
(40.4)
(17.8)
(1,059.9)
1995
(938.3)
(68.8)
(12.0)
(1,019.1)
1996
(942.7)
(68.9)
(10.0)
(1,021.6)
1997
7(903.5)
"(69.0)
(9.4)
(981.9)
1998
(897.2)
pra:
(8.8)
(983.3)
1999
(905.7)
.(77.0) ;
"::;:(7,7)._
(990-4)
Note: Parentheses indicate net sequestration. Totals may not sum due to independent rounding. Lightly shaded areas indicate values
based on a combination of historical data and projections. All other values are based on historical data only.
Table 6-2: Net C02 Flux from Land-Use Change and Forestry (Tg C)
Component
1990
1995 1996 1997 1998 1999
Forests
Agricultural Soils
Landfilled Yard Trimmings
(273)
(11)
(5)
(256) (257) (246) (245) (247)
(19) (19) (19) "•-(21) (21)
(3) (3) (3) (2) _(2)
Total Net Flux
(289)
(278) (279) (268) (268) (270)
Note: 1 Tg C = 1 Tg Carbon = 1 million metric tons carbon. This table has been included to facilitate comparison with previous U.S.
Inventories. Parentheses Indicate net sequestration. Totals may not sum due to independent rounding. Lightly shaded areas indicate values
based on a combination of historical data and projections. All other values are based on historical data only.
Changes in Forest Carbon Stocks
The United States covers roughly 2,263 million acres,
of which 33 percent (747 million acres) is forest land (Smith
and Sheffield 2000). Forest land acreage has remained
fairly constant during the last several decades. Between
1977 and 1987, forest land declined by approximately 5.9
million acres, and then between 1987 and 1997, the area
increased by about 9.2 million acres. Although these
changes in forest area are in opposite directions, they
represent average annual fluctuations of only about 0.1
percent.
Given the low rate of change in U.S. forest land
area, the major influences on the current net carbon flux
from forest land are management activities and 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, intensi-
fied 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 inter-
related components, each of which acts as a carbon stor-
age pool, including:
• Trees (i.e., living trees, standing dead trees, roots,
stems, branches, and foliage)
• Understory vegetation (i.e., shrubs and bushes)
• Forest floor (i.e., fine woody debris, tree litter, and
humus)
• Down dead wood (i.e., logging residue and other
dead wood on the ground)
• 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 liv-
ing biomass. As trees age, they continue to accumulate
carbon until they reach maturity, at which point they are
relatively constant carbon stores. As trees die and other-
wise deposit litter and debris on the forest floor, decay
processes release carbon to the atmosphere and also in-
crease soil carbon. The net change in forest carbon is the
6-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
sum of the net changes in the total amount of carbon
stored in each of the forest carbon pools over time.
The net change in forest carbon, however, may not
be equivalent to the net flux between forests and the
atmosphere because timber harvests may not always re-
sult hi an immediate flux of carbon to the atmosphere. For
this reason, the term "apparent flux" is used in this chap-
ter. Harvesting in effect transfers carbon from one of the
"forest pools" to a "product pool." Once in a product
pool, the carbon is emitted over time as CO2 if the wood
product combusts or decays. The rate of emission varies
considerably among different product pools. For example,
if timber is harvested for energy use, combustion results
in an immediate release of carbon. Conversely, if timber is
harvested and subsequently used as lumber in a house,
it may be many decades or even centuries before the
lumber is allowed to decay and carbon is released to the
atmosphere. If wood products are disposed of in 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., net sequestration) of carbon dur-
ing the 1990s. Due to improvements in U.S. agricultural
productivity, the rate of forest clearing for crop cultiva-
tion and pasture slowed in the late 19th century, and by
1920 this practice had all but ceased. As fanning ex-
panded in the Midwest and West, large areas of previ-
ously cultivated land in the East were taken out of crop
production, primarily between 1920 and 1950, and were
allowed to revert to forests or were actively reforested.
The impacts of these land-use changes are still affecting
carbon fluxes from forests in the East. In addition to
land-use changes in the early part of this century, in re-
cent decades carbon fluxes from Eastern forests have
been affected by a trend toward managed growth on pri-
vate 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 feder-
ally sponsored forest management programs (e.g., the
Forestry Incentive Program) and soil conservation pro-
grams (e.g., the Conservation Reserve Program), which
have focused on tree planting, improving timber manage-
ment activities, combating soil erosion, and converting
marginal cropland to forests. In addition to forest regen-
eration and management, forest harvests have also af-
fected 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 quan-
tities of this harvested carbon are transferred to long-
term storage pools rather than being released to the at-
mosphere. The size of these long-term carbon storage
pools has also increased over the last century.
U.S. forest components and harvested wood com-
ponents were estimated to account for an average annual
net sequestration of 940.1 Tg CO2 Eq. (256.4 Tg C) over
the period 1990 through 1999 (Table 6-3 and Table 6-4).1
This net sequestration is a reflection of net forest growth
and increasing forestland area. The rate of annual se-
questration, however, declined by about 10 percent be-
tween 1990 and 1999. This is due to increasing harvests
and land-use changes over this period (Haynes 2000,
Smith and Sheffield 2000). The relatively large shift in
annual net sequestration from 1996 to 1997 is the result of
calculating average annual forest fluxes from periodic,
rather than annual, activity data.
Table 6-5 presents the carbon stock estimates for
forests (i.e., trees, understory, forest floor, and forest soil),
wood products, and landfilled wood. The increase in all
of these stocks over time indicates that, during the exam-
ined periods, forests, forest product pools, and landfilled
wood all accumulated carbon (i.e., carbon sequestration
by forests was greater than carbon removed in wood har-
vests and released through decay; and carbon accumu-
lation in product pools and landfills was greater than car-
bon emissions from these pools by decay and burning).
Logging residue stocks were not available because these
fluxes were not calculated as a difference between stocks,
but as a difference between wood cut and wood removed
from the site for processing.
1 This average annual net sequestration is based on the entire time series (1990 through 1999), rather than the abbreviated time series
presented in Table 6-3 and Table 6-4.
Land-Use Change and Forestry 6-3
-------
Table 6-3: Net C02 Flux from U.S. Forests (Tg C02 Eq.)
Description 1990
1995 1996 1997 1998 1999
Apparent Forest Flux
Trees
Understory
Forest Floor
Forest Soils
Logging Residues
Apparent Harvested Wood Flux
Wood Products
Landfilled Wood
Total Flux
(791.6)
(414.0)
(5.1)
(57.6)
(251.5)
(63.4)
(210.1)
(47.7)
(162.4)
(1,001.7)
(735.2)
(384.6)
; (5-1)
(55.4)
: : (226.6)
(63.4)
(203.1)
: : (53.9)
': • " (149.2)
(938.3)
(735.2)
(384.6)
(5.1)
(55.4)
(226.6)
(63.4)
(207.5)
(56.1)
(151.4)
(942.7)
1690.8)
(387.6)
(4.0)
(51.0)
" (184.8)
~ (63.4)
(212.7)
1(58.6)
1155.1)
(903.5)
(690.8)
(387.6)
(4,0)
(51.0)
(18J.8):
(63.4)
(206.4)
(52.1)
(154.4)
(897.2)
(690.8) '"
(387.6)
.14.0) :•
(51.0)
(184.8)
: (63.4) '
(214.9)
(61.6)
(153.3)
(905.7)
Nole: Parentheses indicate net carbon "sequestration" (i.e., 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. Lightly shaded
areas indicate values based on a combination of historical data and projections. Forest values are based on periodic measurements;
harvested wood estimates are based on annual surveys. Totals may not sum due to independent rounding.
Table 6-4: Net C02 Flux from U.S. Forests (Tg C)
Description
1990
1995 1996 1997 1998 1999
Apparent Forest Flux
Trees
Understory
Forest Floor
Forest Soils
Logging Residues
Apparent Harvested Wood Flux
Wood Products
Landfilled Wood
(216)
(113)
(1)
(16)
(69)
(17)
(57)
(13)
(44)
(201) (201)
(105) (105)
(1) 0)
(15) (15)
(62) (62)
(17) (17)
(55) (57)
(15) (15)
(41) (41)
(188) (188) (188)
(106) (106) (106)
. (1) (1) (1).
ll(14) J14) (14)
(50) (50) (50)
(17) (17) ' (17)
(58) (56) (59)
(16) :(14) (17)
_ (42) (42), (42)
Total Flux
(273)
(256) (257) (246) (245) (247)
Note: Note: 1 Tg C = 1 Tg Carbon = 1 million metric tons carbon. This table has been included to facilitate comparison with previous U.S.
Inventories. Parentheses indicate net carbon "sequestration" (i.e., accumulation into the carbon pool minus emissions or harvest from the
carbon pool). The 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. Lightly
shaded areas Indicate values based on a combination of historical data and projections. Forest values are based on periodic measurements;
harvested wood estimates are based on annual surveys. Totals may not sum due to independent rounding.
Table 6-5: U.S. Forest Carbon Stock Estimates (Tg C)
Description 1987 1992
1997
2000
Forests (excluding logging residue)
Trees
Understory
Forest Floor
Forest Soils
Logging Residues
Harvested Wood
Wood Products
Landfilled Wood
36,251
12,709
557
3,350
19,635
NA
1,920
1,185
735
37,243
13,273
564
3,428
19,978
NA
2,198
1,245
953
38,160
13,798
571
3,504
20,287
NA
2,479
1,319
1,159
38,672
14,115
574
3,545 •:
20,438
NA
2,651
f,366* " '-'•"-•
1,285 '
NA (Not Available)
Note: Forest carbon stocks do not include forest stocks in Alaska, Hawaii, or U.S. territories, or trees on non-forest land (e.g., urban trees);
wood product stocks include exports, even if the logs are processed in other countries, and exclude imports. Lightly shaded areas indicate
values based on a combination of historical data and projections. All other estimates are based on historical data only. Logging residue is
not available because logging residue flux is predicted from differences between wood harvested and wood removed from the site. Totals
may not sum due to independent rounding.
6-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Methodology
The methodology for estimating annual net forest
carbon flux in the United States is based on periodic sur-
veys rather than annual activity data. In addition, be-
cause the most recent survey was compiled for 1997, pro-
jected data, rather than complete historical data, were
used to derive some of the annual flux estimates. A de-
scription of the assumptions underlying this projection
is given in Haynes (2000). The projection reflects as-
sumptions about variables that affect wood demand and
supply, such as population and technological changes;
policies regulating forests and their management are as-
sumed fixed.
The carbon budget of forest ecosystems in the
United States was estimated using a core model,
FORCARB, and several subroutines that calculate addi-
tional information, including carbon in wood products
(Plantinga and Birdsey 1993, Birdsey et al. 1993, Birdsey
and Heath 1995, and Heath et al. 1996). FORCARB is part
of an integrated system of models consisting of an area
change model (Alig 1985), a timber market model (TAMM;
Adams and Haynes 1980), a pulp and paper model
(NAPAP; Ince 1994) and an inventory projection model
(ATLAS; Mills and Kincaid 1992). Through linkage with
these models, FORCARB estimates carbon stocks on pri-
vate timberlands as a function of management intensity
and land-use change. ATLAS does not yet include pub-
lic timberlands, and harvesting on public lands is not
particularly responsive to price, so forest inventory and
harvest data for public timberlands are developed exog-
enously and then used as inputs to the modeling system
to estimate carbon stocks on public timberlands (Heath
1997b). Average annual net carbon flux on timberlands is
estimated by taking the difference between carbon stocks,
and dividing by the length of the period between stock
estimates.
The current version of FORCARB partitions carbon
storage in the forest into five separate components: trees,
understory vegetation, forest floor, forest soils, and log-
ging residues. The tree component includes all above-
ground and below-ground portions of all live and dead
trees, including the merchantable stem, limbs, tops, cull
sections, stump, foliage, bark and rootbark, and coarse
tree roots (greater than 2 mm). Understory vegetation in-
cludes all live vegetation other than live trees. The forest
floor includes litter and fine woody debris. The soil com-
ponent includes all organic carbon in mineral horizons to a
depth of one meter, excluding coarse tree roots. Logging
residue is the portion of the harvested wood that is left on
the site, i.e., not removed for processing.
The FORCARB model essentially converts mer-
chantable volumes from the model linkages into carbon
and predicts carbon in other ecosystem components—
such as soil and forest floor—based on other data from
forest inventories and additional information from inten-
sive-site ecosystem studies. Estimates of average car-
bon storage by age or volume class of forest stands—
analogous to a forest yield table—are made for each eco-
system component for forest classes defined by region,
forest type, productivity class, and land-use history.
Equations that estimate carbon stocks in the forest floor,
soil, and understory vegetation for each forest class are
incorporated in the model. Logging residue is calculated
as the difference between the carbon in wood harvested
(cut) and wood removed from the site for processing at
the mill. Additional details about estimating carbon stor-
age for different regions, forest types, site productivity
class, and past land use are provided in Birdsey (1996).
The methodology for reserved forest lands and
other forest lands differs from that described above for
timberlands.2 Forest carbon stocks on non-timberland
forests were estimated based on average per area carbon
estimates derived from timberlands. Reserved forests
were assumed to contain the same average per area car-
bon stocks as timberlands of the same forest type, re-
gion, and owner group. These averages were multiplied
by the areas in the forest statistics, and then aggregated
for a national total. Average carbon stocks per area were
2 Forest land in the United States includes all land that is at least 10 percent stocked with trees of any size. Timberland is the most
productive type of forest land, growing at a rate of 20 cubic feet per acre per year or more. In 1997, there were about 503 million acres
of timberlands, which represented 67 percent of all forest lands (Smith and Sheffield 2000). Forest land classified as tiniberland is
unreserved forest land that is producing or is capable of producing crops of industrial wood. The remaining 33 percent of forest land
is classified as reserved forest land, which is forest land withdrawn from timber use by statute or regulation, or other forest land, which
includes forests on which timber is growing at a rate less than 20 cubic feet per acre per year.
Land-Use Change and Forestry 6-5
-------
derived for other forest land by estimating carbon stocks
per area for timberlands in the lowest productivity class
that is surveyed. These estimates were multiplied by 80
percent to simulate the effects of lower productivity. The
results indicated these non-timberland forests are hi equi-
librium, and therefore contribute little to the flux estimates.
Estimates of carbon hi wood products and wood
discarded in landfills are based on the methods described
in Skog and Nicholson (1998), and aggregation as de-
scribed in Heath et al. (1996). The disposition of har-
vested wood carbon removed from the forest can be de-
scribed in four general pools: products hi use, discarded
wood in landfills, emissions from wood burned for en-
ergy, and emissions from decaying wood or wood burned
in which energy was not captured. The apparent fluxes
presented here represent the net amounts of carbon that
are stored in wood product and landfilled wood pools
(i.e., inputs to the pools minus emissions from, or trans-
fers out of, the pools). Annual historical estimates and
projections of detailed product production were used to
divide consumed roundwood into product, wood mill resi-
due, and pulp mill residue. The carbon decay rates for
products and landfills were estimated, and applied to the
respective pools. The results were aggregated for na-
tional estimates.
The apparent fluxes from wood product and
landfilled wood pools include exports and exclude im-
ports. Carbon in exported wood is tracked using the same
disposal rates as in the United States. Over the period
1990 through 1999, carbon in exported wood accounts
for an average of 21.3 Tg CO2 Eq. net storage per year,
with little variation from year to year. For comparison,
imports—which are not included in the harvested wood
apparent flux estimates—increase from 26.4 to 44.7 Tg
C02 Eq. net storage per year from 1990 to 1999.
The methodology described above is consistent
with the Revised 1996IPCC Guidelines (DPCC/UNEP/
OECDflEA 1997). The IPCC identifies two approaches to
developing estimates of net carbon flux from Land-Use
Change and Forestry: 1) using average annual statistics
on land use, land-use change, and forest management
activities, and applying carbon density and flux rate data
to these activity estimates to derive total flux values; or
2) using carbon stock estimates derived from periodic
inventories of forest stocks, and measuring net changes
in carbon stocks over time. The latter approach was em-
ployed because the United States conducts periodic sur-
veys of national forest stocks. In addition, the DPCC iden-
tifies two approaches to accounting for carbon emissions
from harvested wood: 1) assuming that all of the har-
vested wood replaces wood products that decay in the
inventory year so that the amount of carbon hi annual
harvests equals annual emissions from harvests; or 2)
accounting for the variable rate of decay of harvested
wood according to its disposition (e.g., product pool,
landfill, combustion). The latter approach was applied
for this inventory using estimates of carbon stored in
wood products and landfilled wood.3 Although there are
uncertainties associated with the data used to develop
the flux estimates presented here, the use of direct mea-
surements from forest surveys and associated estimates
of product and landfilled wood pools is likely to result in
more accurate flux estimates than the alternative IPCC
methodology.
Data Sources
The estimates of forest carbon stocks used in this
Inventory to calculate forest carbon fluxes are based on
areas, volumes, growth, harvests, and utilization factors
derived from the forest inventory data collected by the
USDA Forest Service. Compilations of these data for
1987,1992, and 1997 are given in Waddell et al. (1989),
Powell et al. (1993), and Smith and Sheffield (2000), re-
spectively. The timber volume data include timber stocks
on forest land classified as timberland, reserved forest
land, or other forest land in the contiguous United States,
but do not include stocks on forest land in Alaska, Ha-
waii, or the U.S. territories, or stocks on non-forest land
(e.g., urban trees).4 The timber volume data include esti-
mates by tree species, size class, and other categories.
The forest inventory data are augmented or converted to
3 Again, the product estimates in this study do not account for carbon stored in imported wood products. However, they do include
carbon stored in exports, even if the logs are processed in other countries (Heath et al. 1996).
6-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Box 6-1: Comparison to forest carbon stock and flux estimates in the United States Submission on Land Use,
Land-Use Change, and Forestry
L On August 1,2000, the U.S. government submitted a document to the UNFCCC on methodological issues related to the treatment
I of carbon sinks under Articles 3.3 and 3.4 of the Kyoto Protocol (U.S. Department of State 2000). This document, entitled United
], States Submission on Land Use, Land-Use Change and Forestry (i.e., the U.S. Submission on LULUCF), was submitted in response
to a request of the Subsidiary Body for Scientific and Technological Advice (SBSTA). The U.S. Submission on LULUCF contains
: estimates of carbon stocks and flux from forest lands, croplands, and grazing lands. The estimates of forest carbon stocks and flux
^presented in this Inventory are slightly different from those presented in the U.S. Submission on LULUCFfortwo reasons: 1) the SBSTA
'; requested stock and flux estimates for a different set of forest areas and activities than are accounted for in national greenhouse gas
; inventories required under the UNFCCC; and 2) both the estimates presented here, and those presented in the U.S. Submission on
LULUCF, reflect interim results of forest carbon modeling refinements that are underway atthe USDA Forest Service. These differences
are discussed more fully below.
! First, the U.S. Submission on LULUCF is concerned with only timberlands, and with carbon fluxes due to activities since 1990.
The U.S. Inventory on Greenhouse Gas Emissions and Sinks covers timberlands, reserved forests, and other forests; and U.S.
, Inventory on Greenhouse Gas Emissions and Sinks flux estimates for any particular year include fluxes due to activities in that year, as
:!" well as fluxes due to activities in previous years (i.e., delayed fluxes). Carbon stocks on reserved forests and other forests are believed
f to be stable, so their inclusion in the Inventory only affects carbon stocks, not fluxes. The inclusion of fluxes due to activities prior to
1990 in the Inventory results in higher annual emission estimates (i.e., lower net sequestration) for harvested wood and logging residue
pools compared to the U.S. Submission.
Second, the methodologies used to estimate harvested wood and soil carbon pools vary between the two documents. The
1 harvested wood carbon pools in the U.S. Submission on LULUCF are based on disposition coefficients that were derived using the
• method of Skog and Nicholson (1998) and a run of the integrated forestry model system (FORCARB/TAMM/ATLAS/NAPAP) with 1992
and earlier forest inventory data as inputs. The estimates of harvested wood carbon pools used in the Inventory are also based on the
method of Skog and Nicholson (1998), but with a rerun of the integrated forestry model system with the 1997 forest inventory data as
input. Also, the carbon stocks in the U.S. Submission were derived using a new soils method, which is not yet available for reserved
: forests and other forests, so an older method was used in the inventory. This resulted in higher soil carbon stock estimates in the U.S.
' Submission compared to the Inventory, but did not affect the estimated fluxes.
carbon following the methods described in the method-
ology section. Soil carbon estimates are based on data
from the STATSGO database (USDA 1991). Carbon stocks
in wood products in use and wood stored in landfills are
based on historical data from the USDA Forest Service
(Powell et al. 1993, Smith and Sheffield 2000), and histori-
cal data as implemented in the framework underlying the
NAPAP (Ince 1994) and TAMM/ATLAS (Adams and
Haynes 1980, Mills and Kincaid 1992) models.
Uncertainty
This section discusses uncertainties in the results,
given the methods and data used. There are likely sam-
pling and measurement errors associated with forest sur-
vey data that underlie the forest carbon estimates. These
surveys are based on a statistical sample designed to
represent the wide variety of growth conditions present
over large territories. Although newer inventories are
being conducted annually in every state, much of the
data currently used may have been collected over more
than one year in a state, and data associated with a par-
ticular year may actually have been collected over sev-
eral previous years. Thus, there is uncertainty in the year
associated with the forest inventory data. In addition,
the forest survey data that are currently available exclude
timber stocks on forest land in Alaska, Hawaii, and the
U.S. territories, and trees on non-forest land (e.g., urban
trees). However, net carbon fluxes from these stocks are
believed to be minor. The assumptions that were used to
calculate carbon stocks in reserved forests and other for-
ests in the coterminous United States also contribute to
4 Although forest carbon stocks in Alaska, Hawaii, and U.S. territories are large compared to the U.S. total, net carbon fluxes from forest
stocks in these areas are believed to be minor. Net carbon fluxes from urban tree growth are also believed to be minor.
Land-Use Change and Forestry 6-7
-------
the uncertainty. Although the potential for uncertainty is
large, the sample design for the forest surveys contrib-
utes to limiting the error in carbon flux. Re-measured
permanent plot estimates are correlated, and greater cor-
relation leads to decreased uncertainties in change esti-
mates. For example, in a study on the uncertainty in the
forest carbon budget of U.S. private timberlands, Smith
and Heath (2000) estimated that the uncertainty of the
flux increased about 3.5 times when the correlation coef-
ficient dropped from 0.95 to 0.5.
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. To extrapolate
results of these studies to all forest lands, it was assumed
that they adequately describe regional or national aver-
ages. This assumption can potentially introduce the fol-
lowing errors: 1) bias from applying data from studies
that inadequately represent average forest conditions;
2) modeling errors (e.g., erroneous assumptions); and 3)
errors in converting estimates from one reporting unit to
another (Birdsey and Heath 1995). In particular, the im-
pacts of forest management activities, including harvest,
on soil carbon are not well understood. For example,
Moore et al. (1981) found that harvest may lead to a 20
percent loss of soil carbon, while Johnson (1992) found
little or no net change in soil carbon following harvest.
Heath and Smith (2000) noted that the experimental de-
sign in a number of soil studies was such that the useful-
ness of the studies may be limited in determining har-
vesting effects on soil carbon. Soil carbon impact esti-
mates need to be very precise because even small changes
in soil carbon may sum to large differences over large
areas.
Recent studies have looked at quantifying the
amount of uncertainty in national-level carbon budgets
based on the methods adopted here. Smith and Heath
(2000) and Heath and Smith (2000a) report on an uncer-
tainty analysis they conducted on carbon sequestration
in private timberlands. These studies are not strictly com-
parable to the estimates hi this chapter because they used
an older version of the FORCARB model, and were based
on older data. However, the magnitudes of the uncertain-
ties should be instructive. Their results indicate that the
carbon flux of private timberlands, not including harvested
wood, was approximately the average carbon flux (271 Tg
CO2 Eq. per year) ±15 percent at the 80 percent confi-
dence level for the period 1990 through 1999. The flux
estimate included the tree, soil, understory vegetation,
and forest floor components only. The uncertainty in the
carbon inventory of private timberlands for 2000 was ap-
proximately 5 percent at the 80 percent confidence level.
It is expected that the uncertainty should be greater for
all forest lands (i.e., private and public timberlands, and
reserved and other forest land).
Changes in AgricuStural
Soil Carbon Stocks
The amount of organic carbon contained in soils
depends on the balance between inputs of photosyn-
thetically fixed carbon (i.e., organic matter such as de-
cayed detritus and roots) and loss of carbon through
decomposition. The quantity and quality of organic mat-
ter inputs, and the rate of decomposition, are determined
by the combined interaction of climate, soil properties,
and land use. Agricultural practices such as clearing,
drainage, tillage, planting, grazing, crop residue manage-
ment, fertilization, and flooding, can modify both organic
matter inputs and decomposition, and thereby result in a
net flux of carbon to or from soils. In addition, the appli-
cation of carbonate minerals to soils through liming op-
erations results in emissions of CO2. The IPCC method-
ology for estimation of net CO2 flux from agricultural soils
(TPCC/UNEP/OECD/IEA1997) is divided into three cat-
egories of land-use/land-management activities: 1) agri-
cultural land-use and land-management activities on min-
eral soils; 2) agricultural land-use and land-management
activities on organic soils; and 3) liming of soils. Mineral
soils and organic soils are treated separately because
each responds differently to land-use practices.
Mineral soils contain comparatively low amounts
of organic matter, much of which is concentrated near the
soil surface. Typical well-drained mineral surface soils
contain from 1 to 6 percent organic matter (by weight);
mineral subsoils contain even lower amounts of organic
matter (Brady and Weil 1999). When mineral soils un-
dergo conversion from their native state to agricultural
6-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
use, as much as half of the soil organic carbon can be lost
to the atmosphere. The rate and ultimate magnitude of
carbon loss will depend on native vegetation, conver-
sion method and subsequent management practices, cli-
mate, and soil type. In the tropics, 40 to 60 percent of the
carbon loss generally occurs within the first 10 years fol-
lowing conversion; after that, carbon stocks continue to
decline but at a much slower rate. In temperate regions,
carbon loss can continue for several decades. Eventu-
ally, the soil will reach a new equilibrium that reflects a
balance between carbon accumulation from plant biom-
ass and carbon loss through oxidation. Any changes in
land-use or management practices that result in increased
biomass production or decreased oxidation (e.g., crop
rotations, cover crops, application of organic amendments
and manure, and reduction or elimination of tillage) will
result in a net accumulation of soil organic carbon until a
new equilibrium is achieved.
Organic soils, which are also referred to as histosols,
include all soils with more than 20 to 30 percent organic
matter by weight (depending on clay content) (Brady and
Weil 1999). The organic matter layer of these soils is also
typically extremely deep. Organic soils form under water-
logged conditions, hi which decomposition of plant resi-
dues is retarded. When organic soils are cultivated, till-
ing or mixing of the soil aerates the soil, thereby acceler-
ating the rate of decomposition and CO2 generation. Be-
cause of the depth and richness of the organic layers,
carbon loss from cultivated organic soils can continue
over long periods of time. Conversion of organic soils to
agricultural uses typically involves drainage as well, which
also causes soil carbon oxidation. When organic soils
are disturbed, through cultivation and/or drainage, the
rate at which organic matter decomposes, and therefore
the rate at which CO2 emissions are generated, is deter-
mined primarily by climate, the composition (i.e., decom-
posability) of the organic matter, and the specific land-
use practices undertaken. The use of organic soils for
upland crops results in greater carbon loss than conver-
sion to pasture or forests, due to deeper drainage and/or
more intensive management practices (Armentano and
Verhoeven 1990, as cited in IPCC/UNEP/OECD/EA1997).
Lime in the form of crushed limestone (CaCO3) and
dolomite (CaMg(CO3)2) is commonly added to agricul-
tural soils to ameliorate acidification. When these com-
pounds come in contact with acid soils, they degrade,
thereby generating CO2. The rate of degradation is deter-
mined by soil conditions and the type of mineral applied;
it can take several years for applied limestone and dolo-
mite to degrade completely.
Of the three activities, use and management of min-
eral soils was by far the most important in terms of contri-
bution to total flux during the 1990 through 1999 period
(see Table 6-6). Carbon sequestration in mineral soils in
1999 was estimated at about 109.3 Tg CO2 Eq., while emis-
sions from organic soils were estimated at about 22.4 Tg
CO2Eq. and emissions from liming were estimated at about
9.9 Tg CO2 Eq. Together, the three activities accounted for
net sequestration of 77.0 Tg CO2 Eq. in 1999. Total annual
net CO2 flux was negative each year over the 1990 to 1999
period. Between 1990 and 1999, total net carbon seques-
tration in agricultural soils increased by 90 percent.
The flux estimates and analysis for this source are
restricted to CO2 fluxes associated with the use and man-
agement of agricultural 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 mon-
oxide (CO), to and from soils. For example, when lands
are flooded with freshwater, such as during hydroelectric
Table 6-6: Net C02 Flux From Agricultural Soils (Tg C02 Eq.)
• . Description
^Mineral Soils
^Organic Soils
b timing of Soils
i Total Net Flux
1990
(71.9)
22.0
9.5
(40.4)
^ei^***^***''®
1995
^~~ ^ (100.1)
r 22.4
r 8.9
(68.8)
1996
(100.1)
22.4
8.9
(68.9)
1997
(100.1)
22.4
8.7
(69.0)
1998
?V22.4
9.6
(77.3)
1999
•'(10$:$ :
22.4
9.9
(77.0)
il'Note: Parentheses indicate net sequestration. Totals may not sum due to independent rounding. Lightly shaded areas indicate values based
f on a combination of historical data and projections. All other values are based on historical data only.
Land-Use Change and Forestry 6-9
-------
dam construction, CH4 is produced and emitted to the
atmosphere due to anaerobic decomposition of organic
material in the soil and water column. Conversely, when
flooded lands, such as lakes and wetlands, are drained,
anaerobic decomposition and associated CH4 emissions
will be reduced. Dry soils are a sink of CH4, so eventu-
ally, drainage may result 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 or-
ganic 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 drainage are not assessed in this inventory
due to a lack of activity data on the extent of these prac-
tices in the United States as well as scientific uncertain-
ties about the greenhouse gas fluxes that result from these
activities.5
Methodology and Data Sources
The methodologies used to calculate CO2 emissions
from use and management of mineral and organic soils
and from liming follow the Revised 1996IPCC Guide-
lines (IPCC/UNEP/OECD/E3A1997), except where noted
below.
The estimates of annual net CO2 flux from mineral
soils were taken from Eve et al. (2000a) and U.S. Depart-
ment of State (2000). The approach used to derive these
estimates is described in Eve et al. (2000b). Total mineral
soil carbon stock estimates for 1982,1992, and 1997 were
developed by applying the default IPCC carbon stock
and carbon adjustment factors (with one exception), to
cropland and grazing land area estimates, classified by
climate, soil type, and management regime. The excep-
tion is the base factor for lands set aside for less than 20
years. The IPCC default value is 0.8, but recent research
in the United States (Paustian et al. 2001, Follett et al.
2001, Huggins et al. 1997, and Gebhart et al. 1994) indi-
cates that 0.9 is a more accurate factor for the United
States. Therefore, 0.9 was used instead of 0.8 for the
base factor for grassland set aside through the Conser-
vation Reserve Program. Areas of non-federal cropland
and grazing land, by soil type and land management re-
gime, in 1982, 1992, and 1997 were taken from USDA
(2000a).6 These were assigned to climatic regions using
the climate mapping program in Daly et al. (1994). Esti-
mates of tillage practices were derived from data collected
by the Conservation Technology Information Center
(CTIC).7 The carbon flux estimate for 1990 is based on
the change in stocks between 1982 and 1992, and the
carbon flux estimate for 1995 through 1997 is based on
the change in stocks between 1982 and 1997. The IPCC
base, tillage, and input factors were adjusted to account
for use of a ten-year and a fifteen-year accounting period,
rather than the 20-year period used in the IPCC Guide-
lines. The carbon flux estimate for 1998 and 1999 is based
on the change in stocks between 1982 and a projection
for 2008. The 2008 projection is based on the estimated
1997 stock, adjusted to account for additional acres ex-
pected to be enrolled in the Conservation Reserve Pro-
gram by 2008 (USDA 2000b).
The estimates of annual CO2 emissions from or-
ganic soils were also taken from Eve et al. (2000a) and
U.S. Department of State (2000), and are based on an
approach described in Eve et al. (2000b). The IPCC meth-
odology for organic soils utilizes annual CO2 emission
factors, rather than a stock change approach. Following
the IPCC methodology, only organic soils under intense
management were included, and the default IPCC rates of
carbon loss were applied to the total 1992 and 1997 areas
for the climate/land-use categories defined in the IPCC
Guidelines. The area estimates were derived from the
same climatic, soil, and land-use/land management data-
bases that were used in the mineral soil calculations (Daly
et al. 1994, USDA 2000a). The annual flux estimated for
1992 is applied to 1990, and the annual flux estimated for
1997 is applied to 1995 through 1999.
s However, methane emissions due to flooding of rice fields are included, as are nitrous oxide emissions from agricultural soils. These
are addressed under the Rice Cultivation and Agricultural Soil Management sections, respectively, of the Agriculture chapter.
* Soil carbon stocks on federal grazing lands were assumed to be stable, and so are not included in the flux estimates.
7 Sec .
6-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Carbon dioxide emissions from degradation of lime-
stone and dolomite applied to agricultural soils were cal-
culated by multiplying the annual amounts of limestone
and dolomite applied (see Table 6-7) by CO2 emission
factors (0.120 metric ton C/metric ton limestone, 0.130
metric ton C/metric ton dolomite).8 These emission fac-
tors are based on the assumption that all of the carbon in
these materials evolves as CO2 in the same year in which
the minerals are applied. The annual application rates of
limestone and dolomite were derived from estimates and
industry statistics provided in the Minerals Yearbook
and Mineral Industry Surveys (Tepoidei 1993,1994,1995,
1996,1997,1998,1999,2000; USGS 2000). To develop
these data, USGS (U.S. Bureau of Mines prior to 1997)
obtained production and use information by surveying
crushed stone manufacturers. Because some manufac-
turers were reluctant to provide information, the estimates
of total crushed limestone and dolomite production and
use were divided into three components: 1) production
by end-use, as reported by manufacturers (i.e., "speci-
fied" production); 2) production reported by manufac-
turers without end-uses specified (i.e., "unspecified" pro-
duction); and 3) estimated additional production by manu-
facturers who did not respond to the survey (i.e., "esti-
mated" production).
To estimate the total amounts of crushed limestone
and dolomite applied to agricultural soils, it was assumed
that the fractions of "unspecified" and "estimated" pro-
duction that were applied to agricultural soils were equal
to the fraction of "specified" production that was applied
to agricultural soils. In addition, data were not available
in 1990,1992, and 1999 on the fractions of total crushed
stone production that were limestone and dolomite, and
on the fractions of limestone and dolomite production
that were applied to soils. To estimate the 1990 and 1992
data, a set of average fractions were calculated using the
1991 and 1993 data. These average fractions were ap-
plied to the quantity of "total crushed stone produced or
used" reported for 1990 and 1992 in the 1994 Minerals
Yearbook (Tepordei 1996). To estimate 1999 data, the
1998 fractions were applied to a 1999 estimate of total
crushed stone found in the USGS Mineral Industry Sur-
veys: Crushed Stone and Sand and Gravel in the First
Quarter of 2000 (USGS 2000).
The primary source for limestone and dolomite ac-
tivity data is the Minerals Yearbook, published by the
Bureau of Mines through 1994 and by the U.S. Geologi-
cal Survey from 1995 to the present. In 1994, the "Crushed
Stone" chapter in Minerals Yearbook began rounding
(to the nearest thousand) quantities for total crushed
stone produced or used. It then reported revised
(rounded) quantities for each of the years from 1990 to
1993. In order to minimize the inconsistencies in the ac-
tivity data, these revised production numbers have been
used in all of the subsequent calculations.
Uncertainty
Uncertainties in the flux estimates for mineral and
organic soils result from both the activity data and the
carbon stock and adjustment factors. Each of the datasets
used in deriving the area estimates has a level of uncer-
tainty that is passed on through the analysis, and the
aggregation of data over large areas necessitates a cer-
tain degree of generalization. The default IPCC values
used for estimates of mineral soil carbon stocks under
native vegetation, as well as for the base, tillage and in-
put factors, carry with them high degrees of uncertainty,
as these values represent broad regional averages based
on expert judgment. Moreover, measured carbon loss
rates from cultivated organic soils vary by as much as an
Table 6-7: Quantities of Applied Minerals (Thousand Metric Tons)
I- Description
['. Limestone
::"- Dolomite
1
19,
2,
990
,012
,360
1991
20,312
2,618
1992
17,984
2,232
1993
15,609
1,740
1994
16,686
2,264
1995
17,297
2,769
1996
17,479
2,499
1997
16,539
2,989
1998
14,882
6,389
1999
15,375
6,600
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 6-11
-------
order of magnitude. In addition, this methodology does
not take into account changes in carbon stocks due to
pre-1982 land use and land-use change.
Uncertainties in the estimates of emissions from
liming also result from both the methodology and the
activity data. It can take several years for agriculturally-
applied limestone and dolomite to degrade completely.
The EPCC method assumes that the amount of mineral
applied in any year is equal to the amount that degrades
in that year, so annual application rates can be used to
derive annual emissions. Further research is required to
determine actual degradation rates, which would vary with
varying soil and climatic conditions. However, applica-
tion rates are fairly constant over the entire time series,
so this assumption may not contribute significantly to
overall uncertainty.
There are several sources of uncertainty in the lime-
stone and dolomite activity data. When reporting data to
the USGS (or U.S. Bureau of Mines), some producers do
not distinguish between limestone and dolomite. In these
cases, data are reported as limestone, so this could lead
to an overestimation of limestone and an underestima-
tion of dolomite. In addition, the total quantity of crushed
stone listed each year in the Minerals Yearbook excludes
American Samoa, Guam, Puerto Rico, and the U.S. Virgin
Islands. The Mineral Industry Surveys further excludes
Alaska and Hawaii from its totals.
Changes in Yard Trimming
Carbon Stocks in Landfills
As is the case with landfilled forest products, car-
bon contained in landfilled yard trimmings can be stored
indefinitely. In the United States, yard trimmings (i.e.,
grass clippings, leaves, branches) comprise a significant
portion of the municipal waste stream. In 1990, the EPA
estimated discards of yard trimmings to landfills at over
21 million metric tons (EPA 1999). Since then, programs
banning or discouraging disposal, coupled with a dra-
matic rise in the number of composting facilities, have
decreased the disposal rate for yard trimmings. In 1999,
the landfill disposal of yard trimmings was about 9 Tg
(EPA 1999). The decrease in the yard trimmings landfill
disposal rate has resulted in a decrease in the rate of
landfill carbon storage from about 17.8 Tg CO2 Eq. in
1990 to 7.7 Tg CO2 Eq. in 1999 (see Table 6-8).
Methodology
Table 6-8: Net C02 from Landfilled Yard Trimmings
« Year Tg C02 Eq.
^__ 19?0
, - * i*, )Wfln-< -rw*l
-— """"1995 " """
1996
1997
1998
1999
(17.8)
~i > - t » > • •
" (12.6)
(10.0)
. . (9-4)
(8.8)
j: (7~7)
r"Note: Parentheses indicate net storage. Lightly shaded area
iJndioates values based on projections.
:i±:__ :~n.:"_;. ;_."~.:... .:' ;..:._..„„. _.:.J^ „.:..'..vi:^'....._:-::.V_
The methodology for estimating carbon storage is
based on a life cycle analysis of greenhouse gas emis-
sions and sinks associated with solid waste management
(EPA 1998). According to this methodology, carbon stor-
age is the product of the mass of yard trimmings dis-
posed, on a wet weight basis, and a storage factor. The
storage factor, which is the fraction of total carbon that is
assumed to be stored permanently, is based on a series of
experiments designed to evaluate methane generation and
residual organic material in landfills (Barlaz 1997). These
experiments analyzed grass, leaves, branches, and other
materials, and were designed to promote biodegradation
by providing ample moisture and nutrients.
For purposes of this analysis, the composition of
yard trimmings was assumed to consist of 50 percent
grass clippings, 25 percent leaves, and 25 percent
branches on a wet weight basis. A different storage fac-
tor was used for each component. The weighted average
carbon storage factor is 0.23 (metric ton of carbon stored
indefinitely per metric ton [wet weight] of yard trimmings
landfilled), as shown in Table 6-9.
Data Sources
The yard trimmings discard rate was taken from the
EPA report Characterization of Municipal Solid Waste
in the U.S.: 1998 Update (EPA 1999), which provides
6-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 6-9: Composition of Yard Trimmings
in MSW and Carbon Storage Factor
(Gg C/Gg yard trimmings)
Table 6-10: Yard Trimmings Disposal to Landfills
Component
1 Grass
- Leaves
,, Branches
"-Total/Weighted Average
fc,^ -:.:*..:-. : .-- ;
Percent
50
25
25
100
Storage Factor
0.13
0.43
0.23
0.23
estimates for 1990 through 1998 and forecasts for 2000
and 2005. Yard trimmings discards for 1999 were pro-
jected using the EPA (1999) forecast of generation and
recovery rates (i.e., decrease of 6 percent per year, in-
crease of 8 percent per year, respectively) for 1999
through 2000. This report does not subdivide discards
of individual materials into volumes landfilled and com-
busted, although it does provide an estimate of the over-
all distribution of solid waste between these two man-
agement methods (i.e., 76 percent and 24 percent, respec-
tively) for the waste stream as a whole.9 Thus, yard trim-
mings disposal to landfills is the product of the quantity
discarded and the proportion of discards managed in land-
fills (see Table 6-10). The carbon storage factors were
obtained from EPA (1998).
Uncertainty
The principal source of uncertainty for the landfill
carbon storage estimates stems from an incomplete un-
derstanding of the long-term fate of carbon in landfill
environments. Although there is ample field evidence
Year
-------
6-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Figure 7-1
Wiste management and treatment activities are sources of greenhouse gas emissions (see Figure 7-1).
Landfills are the nation's largest source of anthropogenic methane (CH4) emissions, accounting for 35
percent of the U.S. total.1 Waste combustion is the second largest source in this sector, emitting carbon dioxide (CO2)
and nitrous oxide (N2O). Smaller amounts of methane are emitted from wastewater systems by bacteria used in various
treatment processes. Wastewater treatment systems are also a potentially significant source of N2O emissions; how-
ever, methodologies are not currently available to develop a
complete estimate. Nitrous oxide emissions from the treat-
ment of the human sewage component of wastewater were
estimated, however, using a simplified methodology. Nitro-
gen oxide (NOX), carbon monoxide (CO), and non-methane
volatile organic compounds (NMVOCs) are emitted by each
of these sources, and are addressed separately at the end of
this chapter. A summary of greenhouse gas emissions from
the Waste chapter is presented in Table 7-1 and Table 7-2.
Overall, in 1999, waste activities generated emissions
of 261.3 Tg CO2 Eq., or 3.9 percent of total U.S. greenhouse
gas emissions.
Human
Sewage
50 100 150 200 250
Tg CO2 Eq.
LandfiSSs
Landfills are the largest anthropogenic source of meth-
ane (CH4) emissions in the United States. In 1999, landfill
emissions were approximately 214.6 Tg CO2 Eq. (10,221 Gg).
Emissions from municipal solid waste (MSW) landfills, which received about 61 percent of the total solid waste
generated in the United States, accounted for about 94 percent of total landfill emissions, while industrial landfills
accounted for the remainder. Over 2,200 operational landfills exist in the United States (BioCycle 2000), with the largest
landfills receiving most of the waste and generating the majority of the methane.
Landfills
Waste
Combustion
Wastewater
Treatment
Portion of
All Emissions
1 Landfills also store carbon, due to incomplete degradation of organic materials such as wood products and yard trimmings, as described
in the Land-Use Change and Forestry chapter.
Waste 7-1
-------
Table 7-1: Emissions from Waste (Tg C02 Eq.)
Gas/Source
CH<
Landfills
WastewaterTreatment
C02
Waste Combustion
N20
Human Sewage
Waste Combustion
Total
Note: Totals may not sum
1990
228.5
217.3
11.2
17.6
17.6
7.4
7.1
0.3
253.4
due to independent rounding.
1995
234.7
222.9
11.8
23.1
23.1
8.5
8.2
0.3
266.2
1996
231.0
219.1
11.9
24.0
24.0
8.1
7.8
0.3
263.1
1997
229.8
217.8
12.0
25.7
25.7
8.2
7.9
0.3
263.6
1998
225.7
'213.6
12.1
25.1
25.1
8.3
8.1
0.2
259.2
1999
226.9
214.6
12.2
26.0
26.0
8.4
8.2
0.2
261.3
Table 7-2: Emissions from Waste (Gg)
Gas/Source
CH4
Landfills
WastewaterTreatment
C02
Waste Combustion
N20
Human Sewage
Waste Combustion
Note: Totals may not sum
1990
10,879
10,346
533
17,572
17,572
24
23
1
due to independent rounding.
1995
11,175
10,614
561
23,065
23,065
27
27
1
1996
11,002
10,435
567
23,968
23,968
26
25
1
1997
10,943
10,371
572
25,674
25,674
26
26
1
1998
10,748
10,171
577
25,145
25,145
27
26
1
1999
10,803
10,221
583
25,960
25,960
27
26
1
Methane emissions result from the decomposition
of organic landfill materials such as paper, food scraps,
and yard trimmings. This decomposition process is a natu-
ral mechanism through which microorganisms derive en-
ergy. After being placed in a landfill, organic waste is ini-
tially digested by aerobic (i.e., in the presence of oxygen)
bacteria. After the oxygen supply has been depleted, the
remaining waste is consumed by anaerobic bacteria, which
break down organic matter into substances such as cellu-
lose, amino acids, and sugars. These substances are fur-
ther broken down through fermentation into gases and
short-chain organic compounds that form the substrates
for the growth of methanogenic bacteria. Methane-pro-
ducing anaerobic bacteria convert these fermentation prod-
ucts into stabilized organic materials and biogas consist-
ing of approximately 50 percent carbon dioxide (CO^ and
50 percent methane, by volume.2 Methane production typi-
cally begins one or two years after waste disposal in a
landfill and may last from 10 to 60 years.
Between 1990 and 1999, net methane emissions from
landfills were relatively constant (see Table,7-3 and Table
7-4). The roughly constant emissions estimates are a re-
sult of two offsetting trends: (1) the amount of MSW in
landfills contributing to methane emissions increased,
thereby increasing the potential for emissions; and (2) the
amount of landfill gas collected and combusted by landfill
operators also increased, thereby reducing emissions.
Methane emissions from landfills are a function of
several factors, including: (1) the total amount of MSW
in landfills, which is related to total MSW landfilled an-
nually for the last 30 years; (2) composition of the waste-
in-place; (3) the amount of methane that is recovered and
either flared or used for energy purposes; and (4) the
amount of methane oxidized in landfills instead of being
released into the atmosphere. The estimated total quan-
tity of waste-in-place contributing to emissions increased
from about 4,926 Gg in 1990 to 6,036 Gg in 1999, an in-
2 The percentage of CO2 in biogas released from a landfill may be smaller because some CO2 dissolves in landfill water (Bingemer and
Crutzen 1987). Additionally, less than 1 percent of landfill gas is composed of non-methane volatile organic compounds (NMVOCs).
7-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 7-3: CH4 Emissions from Landfills (Tg C02 Eq.)
^Activity
few Landfills.
I Industrial Landfills
$Becovered
|g6as-to-Energy
|& Flared
| Net Emissions
1990
221.1 ~"~~
15.3
• - 0"%r _«,
(14.7) "~^
(4-5) ' __
217.3 "*""""
1995
254.8
17.5
(21.8)
(27.6)
222.9
1996
261.0
17.8
(24.3)
(35.3)
219.1
1997
267.1
18.2
(28.8)
(38.8)
217.8
1998
272.7
18.5
(36.1)
(41.5)
213.6
1999
279.6
19.0
(42.7)
(41.2)
214.6
I Note: Totals may not sum due to independent rounding.
£r-'/ - ",. '„„ ,-. -:. " .. ..:
Table 7-4: CH4 Emissions from Landfills (Gg)
'Activity
, MSW Landfills
, Industrial Landfills
Recovered
Gas-to-Energy
Flared
'Net Emissions
1990
10,531
731
(702)
(213)
10,346
1995
12,133
- *.-! 833
(1,037)
7 (1,314)
*"* 10,614
1996
12,427
850
(1,159)
(1,683)
10,435
1997
12,720
868
(1,372)
(1,846)
10,371
1998
12,985
883
(1,720)
(1,977)
10,171
1999
13,315
904
(2,034)
(1,964)
10,221
• Note: Totals may not sum due to independent rounding.
Box 7-1: Biogenic Emissions and Sinks of Carbon
* For many countries, C02 emissions from the combustion or degradation of biogenic materials are important because of the
Insignificant amount of energy they derive from biomass (e.g., burning fuelwood). The fate of biogenic materials is also important when
| fvaluating waste management emissions (e.g., the decomposition of paper). The carbon contained in paper was originally stored in
f-'frees during photosynthesis. Under natural conditions, this material would eventually degrade and cycle back to the atmosphere as
|Lp02. The quantity of carbon that these degradation processes cycle through the Earth's atmosphere, waters, soils, and biota is much
I: greater than the quantity added by anthropogenic greenhouse gas sources. But the focus of the United Nations Framework Conven-
ption on Climate Change is on anthropogenic emissions—emissions resulting from human activities and subject to human control—
fbecause it is these emissions that have the potential to alter the climate by disrupting the natural balances in carbon's biogeochemical
&.'~- • • • ' '
fjcycle, and enhancing the atmosphere's natural greenhouse effect.
J"; Carbon dioxide emissions from biogenic materials (e.g., paper, wood products, and yard trimmings) grown on a sustainable basis
r are considered to mimic the closed loop of the natural carbon cycle—that is, they return to the atmosphere C02 that was originally
JT removed by photosynthesis. However, CH4 emissions from landfilled waste occur due to the man-made anaerobic conditions
| conducive to CH4 formation that exist in landfills, and are consequently included in this Inventory.
f:::__ The removal of carbon from the natural cycling of carbon between the atmosphere and biogenic materials—which occurs when
p wastes of biogenic origin are deposited in landfills—sequesters carbon. When wastes of sustainable, biogenic origin are landfilled, and
V dp not completely decompose, the carbon that remains is effectively removed from the global carbon cycle. Landfilling of forest
£, products and yard trimmings results in long-term storage of about 70 Tg C02 Eq. and 7 to 18 Tg C02 Eq. per year, respectively. Carbon
| storage that results from forest products and yard trimmings disposed in landfills is accounted for in the Land-Use Change and Forestry
If chapter, as recommended in the Revised 1996IPCC Guidelines (IPCC/UNEP/OEGD/IEA1997) regarding the tracking of carbon flows.
Waste 7-3
-------
Box 7-2: Recycling and Greenhouse Gas Emissions and Sinks
I U.S. waste management patterns changed dramatically in the 1990s in response to changes in economic and regulatory factors.
I Perhaps the most significant change from a greenhouse gas perspective was the increase in the national average recycling rate,
; which climbed from 16 percent in 1990 to 28 percent in 1997 (EPA 1999).
* This change has affected emissions in several ways, primarily by reducing emissions from waste and energy activities, as well as by
i enhancing forestry sinks. The impact of increased recycling on greenhouse gas emissions can be best understood when emissions are
- considered from a life cycle perspective (EPA 1998). When a material is recycled, it is used in place of virgin inputs in the manufacturing
t process, rather than being disposed and managed as waste. The substitution of recycled inputs for virgin inputs reduces three types
I of emissions throughout the product life cycle. First, manufacturing processes involving recycled inputs generally require less energy
I than those using virgin inputs. Second, the use of recycled inputs leads to reductions in process non-energy emissions (e.g.,
i perfluorocarbon emissions from aluminum smelting). Third, recycling reduces disposal and waste management emissions, including
1 methane from landfills and nitrous oxide and non-biogenic carbon dioxide emissions from combustion; In addition to greenhouse gas
| emission reductions from manufacturing and disposal, recycling of paper products—which are the largest component of the US.
I wastestream—results in increased forest carbon sequestration. When paper is recycled, fewer trees are needed as inputs in the
1 manufacturing process; reduced harvest levels result in older average forest ages, with correspondingly more carbon stored.
I _.„ ,' : •;;;_._...; ^,:_,;.._; ].:-,:.:•:•::.,..... ~\
crease of 23 percent (see Annex M). During this period,
the estimated methane recovered and flared from landfills
increased as well. In 1990, for example, approximately 915
Gg of methane was recovered and combusted (i.e., used
for energy or flared) from landfills. In 1999, the estimated
quantity of methane recovered and combusted increased
to 3,998 Gg.
Over the next several years, the total amount of
MS W generated is expected to increase slightly. The per-
centage of waste landfilled, however, may decline due to
increased recycling and composting practices. In addi-
tion, the quantity of methane that is recovered and either
flared or used for energy purposes is expected to increase,
partially as aresultof a 1996 regulation that requires large
MSW landfills to collect and combust landfill gas (see 40
CFR Part 60, Subparts Cc and WWW).
Methodology
Based on available information, methane emissions
from landfills were estimated to equal the methane pro-
duced from municipal landfills, minus the methane recov-
ered and combusted, minus the methane oxidized before
being released into the atmosphere, plus the methane
produced by industrial landfills.
The methodology for estimating CH4 emissions from
municipal landfills is based on a model that updates the
population of U.S. landfills each year. This model is based
on the pattern of actual waste disposal by each individual
landfill surveyed by the EPA's Office of Solid Waste in
1987. A second model was employed to estimate emis-
sions from the landfill population (EPA 1993). For each
landfill in the data set, the amount of waste-in-place con-
tributing to methane generation was estimated using its
year of opening, its waste acceptance rate, year of clo-
sure, and design capacity. Data on national waste dis-
posed in landfills each year was apportioned by landfill.
Emissions 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 M.
The estimated landfill gas recovered per year was
based on updated data collected from vendors of flaring
equipment, and a database compiled by the EPA's Landfill
Methane Outreach Program (LMOP). Based on the infor-
mation provided by vendors, the methane combusted by
the 487 flares in operation from 1990 to 1999 were esti-
mated. This quantity likely under-estimates flaring. The
EPA believes that more than 700 flares exist in the United
States, and is working with the Solid Waste Association
of North America (SWANA) to better characterize flaring
activities. Additionally, the LMOP database provided suf-
ficient data on landfill gas flow and energy generation for
273 of the approximately 315 operational landfill gas-to-
energy projects (LFGTE). If both flare data and LFGTE
7-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
recovery data for a particular landfill were available, then
the emissions recovery was based on the LFGTE data,
which provides actual landfill-specific data on gas flow
for direct use projects and project capacity (i.e., mega-
watts) for electricity projects. The flare data, on the other
hand, only provided a range of landfill gas flow for a given
size flare. Given that each LFGTE project was likely to also
have had a flare, EPA avoided double counting reduc-
tions from flares and LFGTE projects by subtracting from
the emissions reductions associated with flares, those
emissions reductions associated with LFGTE projects.3
Emissions from industrial landfills were assumed to
be equal to 7 percent of the total methane emissions from
municipal landfills. The amount of methane oxidized was
assumed to be 10 percent of the methane generated (Liptay
et al. 1998). To calculate net methane emissions, both meth-
ane recovered and methane oxidized were subtracted from
methane generated at municipal and industrial landfills.
Data Sources
The landfill population model, including actual
waste disposal data from individual landfills, was devel-
oped from a survey performed by the EPA's Office of
Solid Waste (EPA 1988). National landfill waste disposal
data for 1991 through 1999 were obtained from BioCycle
(2000).4 Documentation on the landfill methane emissions
methodology employed is available in the EPA's Anthro-
pogenic Methane Emissions in the United States, Esti-
mates for 1990: Report to Congress (EPA 1993). Informa-
tion on flares was obtained from vendors, and informa-
tion on landfill gas-to-energy projects was obtained from
the LMOP database.
Uncertainty
Several types of uncertainties are associated with
the estimates of methane emissions from landfills. The
primary uncertainty concerns the characterization of land-
fills. Information is lacking on the area landfilled and
total waste-in-place—the fundamental factors that af-
fect methane production. In addition, the statistical model
used to estimate emissions is based upon methane gen-
eration at landfills that currently have developed energy
recovery projects, and may not precisely capture the
relationship between emissions and various physical
characteristics of individual landfills. Overall, uncertainty
in the landfill methane emission rate is estimated to be
roughly ±30 percent.
Waste Combustion
Combustion is used to manage both municipal solid
wastes (MSW) and hazardous wastes. Combustion of
either type of waste results in conversion of the organic
inputs to carbon dioxide (CO2). According to the IPCC
Guidelines, when the CO2 is of fossil origin, it is counted
as an anthropogenic emission in national inventories.
Thus, the emissions from waste combustion are driven
by estimating the quantity of waste combusted, the frac-
tion of the waste that is carbon, and the fraction of the
carbon that is of fossil origin.
MSW is composed of garbage and non-hazardous
solids. Most of the organic materials in MSW are of bio-
genie origin (e.g., paper, yard trimmings), and have their
net carbon flows accounted for under the Land-Use
Change and Forestry chapter (see Box 7-1). However,
some components—plastics, synthetic rubber, and syn-
thetic fibers—are of fossil origin. Plastics in the U.S.
wastestream are primarily in the form of containers, pack-
aging, and durable goods. Rubber is found in durable
goods, like carpets, and in non-durable goods, such as
clothing and footwear. Fibers in MSW are predominantly
from clothing and home furnishings. Tires are also con-
sidered a "non-hazardous" waste and are included in the
estimate, though waste disposal practices for tires differ
from the rest of MSW.
3 Due to the differences in referencing landfills and incomplete data on the national population of flares, matching flare vendor data
with the LMOP LFGTE data was problematic and EPA was not able to identify a flare for each of the LFGTE projects. Because each
LFGTE project likely has a flare, the aggregate flare estimate of emission reductions was reduced by the LFGTE projects for which a
specific flare could not be identified. This approach eliminated the potential for double counting emissions reductions at landfills with
both flares and a LFGTE project.
4 At the time this section was prepared, BioCycle had not yet published its 1999 estimate for the percent of the total waste landfilled,
so the previous year's figure (61 percent) was used.
Waste 7-5
-------
In 1999, it was estimated that nearly 34 million met-
ric tons of MSW were combusted in the United States
(EPA 1999). Carbon dioxide emissions have risen 46 per-
cent since 1990, to an estimated 20.5 Tg CO2 Eq. (20,470
Gg) in 1999, as the volume of plastics in MSW has in-
creased (see Table 7-5 and Table 7-6). In addition to CO2,
MSW combustion is a source of nitrous oxide (N2O) emis-
sions (De Soete 1993). Nitrous oxide emissions from MSW
combustion were estimated to be 0.2 Tg CO2Eq. (1 Gg) in
1999, and have not changed significantly since 1990.
Hazardous wastes are defined by the EPA under
the Resource Conservation and Recovery Act (RCRA).5
Industrial wastes, such as rejected products, spent re-
agents, reaction by-products, and sludges from waste-
water or air pollution control, are federally regulated as
hazardous wastes if they are found to be ignitable, corro-
sive, reactive, or toxic according to standardized tests or
studies conducted by the EPA.
Hazardous wastes must be treated prior to disposal
according to the federal regulations established under
the authority of RCRA. Combustion is one of the most
common techniques for hazardous waste treatment, par-
ticularly for those wastes that are primarily organic in
composition or contain primarily organic contaminants.
Generally speaking, combustion devices fall into two cat-
egories: incinerators that burn waste solely for the pur-
pose of waste management, and boilers and industrial
furnaces (BIFs) that burn waste in part to recover energy
from the waste. The EPA's Office of Solid Waste requires
biennial reporting of hazardous waste management ac-
tivities, and these reports provide estimates of the amount
of hazardous waste burned for incineration or energy re-
covery. Table 7-7 presents estimates of CO2 emissions
from hazardous waste combustion based on these esti-
mates and assumptions about the composition of the
wastes and efficiency of the combustion process.
Methodology
C02 from Plastics Combustion
In the report, Characterization of Municipal Solid
Waste in the United States (EPA 2000c), the flows of plas-
tics in the U.S. wastestream are reported for seven resin
categories. The 1998 quantity generated, recovered, and
discarded for each resin is shown in Table 7-8. The report
Table 7-5: C02 and N20 Emissions from Municipal Solid Waste Combustion (Tg C02 Eq.)
Gas/Waste Product
C02
Plastics
Synthetic Rubber in Tires
Carbon Black in Tires
Synthetic Rubber in MSW
Synthetic Rbers
N20
Total
1990
14.0
10.3
0.2
0.3
1.6
1.5
0.3
14.3
1995
18.2
11.1
1.4
2.1
1.7
1.9
0.3
18.4
1996
19.1
11.5
1.5
2.3
1.7
2.0
0.3
19.3
1997
20.8
12.5
1.7
2,6
1.8
2.1
0.3
21.0
1998
19.9
12.9
1.1
1.7
1.8
2.2
0.2
20.1
1999
20.5
13.3
1.2
1.8
1.9
2.3
0.2
20.7
Table 7-6: C02and N20 Emissions from Municipal Solid Waste Combustion (Gg)
Gas/Waste Product
1990
1995 1996 1997 1998 1999
C02
Plastics
Synthetic Rubber in Tires
Carbon Black in Tires
Synthetic Rubber in MSW
Synthetic Rbers
N20
14,014
10,320
227
348
1,584
1,535
1
S,' , .-
•
|-
ir~ .'
£•,
£
p.
'&—
-.
i
'••i
1
;|
' 1
I
18,154
11,077
1,353
2,077
1,708
1,938
1
19,061
11,459
1,517
2,329
1,737
2,018
1
20,770
12,484
1,711
2,627
1,807
2,141
1
19,871
12,929
1,134
1,741
1,833
2,233
1
20,470
13,297
1,190
1,827
1,870
2,285
1
5 [42 U.S.C. §6924, SDWA §3004]
7-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 7-7: C02 Emissions from
Hazardous Waste Combustion
i Year
Sfoo,
1995 """
^1996
-1997
1998*
1999*
i *Projection based
TgC02Eq.
3.6 ;
4.9
4.9
4.9
5.3
5.5
on 1989 to 1997 trend.
Gg
3,557
4,911
4,908
4,904
5,274
5,490
does not provide estimates for individual materials
landfilled and combusted, although it does provide such
an estimate for the waste stream as a whole. To estimate
the quantity of plastics landfilled and combusted, total
discards were apportioned based on the proportions of
landfilling and combustion for the entire U.S. wastestream
(76 percent and 24 percent, respectively).
Fossil fuel-based CO2 emissions for 1998 were cal-
culated as the product of plastic combusted, carbon con-
tent, and combustion efficiency (see Table 7-9). The car-
bon content of each of the six types of plastics is listed,
with the value for "other plastics" assumed equal to the
weighted average of the six categories. The fraction oxi-
dized was assumed to be 98 percent.
Emissions for 1990 through 1997 were calculated
using the same approach. Estimates of the portion of plas-
tics in the wastestream in 1999 were not available; there-
fore, they were projected by assuming a 3 percent annual
growth rate in generation and a 5.4 percent growth rate
for recovery, based on reported trends (EPA 1999).
C02 from Combustion of Synthetic Rubber and
Carbon Black in Tires
Emissions from tire combustion require two pieces
of information: the amount of tires combusted and the
carbon content of the tires. The Scrap Tire Use/Disposal
Study 1998/1999 Update (STMC 1999) reports that 114
million of the 270 million scrap tires generated in 1998
(approximately 42 percent of generation) were used for
fuel purposes. Using STMC estimates of average lire com-
position and weight, the weight of synthetic rubber and
carbon black in scrap tires was determined. Synthetic rub-
Table 7-8: 1998 Plastics in the Municipal Solid Waste Stream by Resin (Gg)
MWaste Pathway
. Generation
| Recovery
: Discard
f Landfill
|: Combustion
'r Recovery*
f Discard*
L Landfill*
I . Combustion*
PET
2,023
354
1,669
1,269
401
17%
83%
63%
20%
HOPE
4,500
399
4,101
3,116
984
9%
91%
69%
22%
PVC
1,243
0
1,243
945
298
0%
100%
76%
24%
LDPE/
LLOPE
4,844
127
4,717
3,585
1,132
3%
97%
74%
23%
PP
2,576
154
2,422
1,841
581
6%
94%
71%
23%
PS
1,969
18
1,950
1,482
468
1%
99%
75%
24%
Other
3,139
45
3,094
2,351
742
1%
99%
75%
24%
Total
20,294
1,098
19,196
14,589
4,607
5%
95%
72%
23%
r *As a percent of waste generation.
;' Note: Totals may not sum due to independent rounding. Abbreviations: PET (polyethylene terephthalate), HOPE (high density polyethylene),
'PVC (polyvinyl chloride), LDPE/LLDPE ((linear) low density polyethylene), PP (polypropylene), PS (polystyrene).
Table 7-9: 1998 Plastics Combusted (Gg), Carbon Content (%), and Carbon Combusted
vC •
I- '
:TT -
k
Factor
Quantity Combusted
Carbon Content of Resin
Carbon in Resin Combusted
Emissions (Tg C02 Eq.)b
PET
401
63%
250
0.9
HOPE
984
86%
844
3.0
PVC
298
38%
115
0.4
LDPE/
LLDPE
1,132
86%
970
3.5
PP
581
86%
498
1.8
PS
468
92%
432
1,6
(Gg)
Other
742
66% a
489
1.8
Total
4,607
• -
3,598
12.9
I a Weighted average of other plastics produced in 1998 production.
i b Assumes a fraction oxidized of 98 percent.
Waste 7-7
-------
her in tires was estimated to be 90 percent carbon by
weight, based on the weighted average carbon contents
of the major elastomers used in new tire consumption
(see Table 7-10).6 Carbon black is 100 percent carbon.
Multiplying the proportion of scrap tires combusted by
the total carbon content of the synthetic rubber and car-
bon black portion of scrap tires yielded CO2 emissions,
as shown in Table 7-11. Note that the disposal rate of
rubber in tires (0.4 Tg/yr) is smaller than the consumption
rate for tires shown in Table 7-10 (1.3 Tg/yr); this is due to
the fact that much of the rubber is lost through tire wear
during the product's lifetime and due to the lag time be-
tween consumption and disposal of tires.
C02 from Combustion of Synthetic Rubber in
Municipal Solid Waste
Similar to the methodology for scrap tires, CO2 emis-
sions from synthetic rubber in MSW were estimated by
Table 7-10: Elastomers Consumed in 1998 (Gg)
Carbon Carbon
Elastomer Consumed Content Equivalent
Styrene butadiene
rubber solid
For Tires
For Other Products*
Polybutadiene
For Tires
For Other Products
Ethylene Propylene
For Tires
For Other Products
Polychloroprene
For Tires
For Other Products
Nitrite butadiene
rubber solid
For Tires
For Other Products
Polyisoprene
For Tires
For Other Products
Others
For Tires
For Other Products
Total
90S
743
165
561
404
157
320
10
310
69
0
69
87
1
86
78
65
13
369
63
306
2,392
91%
91%
91%
89%
89%
89%
86%
86%
86%
59%
59%
59%
77%
77%
77%
88%
88%
88%
88%
88%
88%
-
828
677
151
499
359
140
274
8
266
40
0
40
67
1
67
69
57
12
324
56
268
2,101
*Used to calculate carbon content of non-tire rubber products in
municipal solid waste.
- Not applicable
multiplying the amount of rubber combusted by an aver-
age rubber carbon content. The amount of rubber in the
MSW stream was estimated from data provided in the
Characterization of Municipal Solid Waste in the United
States (EPA 2000c). The report organizes rubber found in
MSW into three product categories: other durables (not
including tires), non-durables (which includes clothing
and footwear and other non-durables), and containers
and packaging. Since there was negligible recovery for
these product types, all the waste generated can be con-
sidered discarded. Similar to the plastics method, dis-
cards were apportioned based on the proportions of
landfilling and combustion for the entire U.S. wastestream
(76 percent and 24 percent, respectively). The report ag-
gregates rubber and leather in the MSW stream; an as-
sumed rubber content percentage was assigned to each
product type, as shown in Table 7-12.7 A carbon content
of 85 percent was assigned to synthetic rubber for all
product types, according to the weighted average car-
bon content of rubber consumed for non-tire uses (See
Table 7-10). For 1999, waste generation values were not
provided in the report. Generation was forecast by multi-
plying the 1998 Rubber and Leather waste generation by
the 1990 through 1998 average annual growth rate for
that product category.
C02 from Combustion of Synthetic Fibers
Carbon dioxide emissions from synthetic fibers were
estimated as the product of the amount of synthetic fiber
discarded annually and the average carbon content of
synthetic fiber. Fiber in the MSW stream was estimated
from data provided in the Characterization of Munici-
pal Solid Waste in the United States (EPA 2000c) for
textiles. The amount of synthetic fiber in MSW was esti-
mated by subtracting me amount recovered from the waste
generated (see Table 7-13). As with the other materials in
the MSW stream, discards were apportioned based on
the proportions of landfilling and combustion for the en-
tire U.S. wastestream (76 percent and 24 percent, respec-
tively). It was assumed that approximately 55 percent of
the fiber was synthetic in origin, based on information
received from the Fiber Economics Bureau (DeZan 2000).
6 1,158,000 Tg for the carbon content of tires divided by 1,285,000 Tg for the mass of tires, equals 90 percent.
7 As a biogcnic material, the combustion of leather is assumed to have no net carbon dioxide emissions.
7-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 7-11: Scrap Tire Constituents and C02 Emissions from Scrap Tire Combustion in 1998
Material
Synthetic Rubber
Carbon Black
Total
Weight of
Material (Tg)
0.4
0.5
0.8
Carbon
Content
90%
100%
-
Percent
Combusted
42%
42%
-
Emissions
(TgC02Eq.)*
1.1
1.7
2.9
!• * Assumes a fraction oxidized of 98 percent.
: - Not applicable
Table 7-12: Rubber and Leather in Municipal Solid Waste in 1998
Product Type
Durables (not Tires)
Non-Durables
: Clothing and Footwear
Other Non-Durables
Containers and Packaging
Total
Generation
(Gg)
2,141
744
526
218
18
2,903
Synthetic
Rubber (%)
100%
100%
25%
75%
100%
-
Carbon
Content (%)
1 85%
• 85%
85%
85%
85%
-
Emissions
(TgC02Eq.)*
1.6
0.2
0.1
0.1
+
1.8
* Assumes a fraction oxidized of 98 percent.
+ Less than 0.05 Tg C02 Eq.
- Not applicable
Table 7-13: Textiles in MSW (Gg)
Year
Generation
Recovery
Discards
Combustion
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999*
5,271
5,599
5,948
6,319
6,713
6,713
7,004
7,475
7,802
7,989
599
622
647
672
699
816
862
962
1,007
1,035
4,672
4,977
5,302
5,647
6,015
5,897
6,142
6,514
6,795
6,954
1,121
1,195
1,272
1,355
1,444
1,415
1,474
1,563
1,631
1,669
*Projected using 1998 data and the 1997 to 2000 Average Annual Growth Rate for Generation (EPA 1999).
An average carbon content of 70 percent was assigned
to synthetic fiber using the production-weighted aver-
age of the carbon contents of the four major fiber types
(polyester, nylon, olefin, and acrylic) produced in 1998
(see Table 7-14). The equation relating CO2 emissions to
the amount of textiles combusted is shown below. Since
1999 values were not provided hi the Characterization
report, generation and recovery were forecast by apply-
ing their respective average annual growth rates for 1990
through 1998 to the 1998 values.
CO2 Emissions from the Combustion of Synthetic
Fibers = Annual Textile Combustion (Gg)x "
(Percent of Total Fiber that is Synthetic)x
(Average Carbon Content of Synthetic Fiber)x
(44gC02/12gC)
N20 from Municipal Solid Waste Combustion
Estimates of N2O emissions from MSW combus-
tion in the United States are based on the methodology
outlined in the EPA's Compilation of Air Pollutant Emis-
Waste 7-9
-------
Table 7-14: Synthetic Fiber Production in 1998
Proection
Fiber (Tg)
Polyester 1.8
Nylon 1.3
Olefin 1.3
Acrylic 0.2
Total 4.6
- Not applicable
Carbon
Content
63%
64%
86%
68%
-
Carbon
Equivalent
(Tg C02 Eq.)
4.1
3.0
4.1
0.5
11.7
sion Factors (EPA 1997). According to this methodology,
emissions of N2O from MSW combustion are the product
of the mass of MSW combusted, an emission factor of
N2O emitted per unit mass of waste combusted, and an
N2O emissions control removal efficiency. For MSW com-
bustion in the United States, an emission factor of 30 g
N2O/metric ton MSW, and an estimated emissions con-
trol removal efficiency of zero percent were used. No in-
formation was available on the mass of waste combusted
in 1999, so this was extrapolated, using least-squares lin-
ear regression, from the times series for 1990 through
1998.
C02from Hazardous Waste Combustion
Hazardous wastes combusted are reported to the
EPA, which stores the information in its Biennial Report-
ing System (BRS) database. Combusted wastes are iden-
tified based on management system types M041 through
M049 (incineration) and M051 through M059 (energy re-
covery). Combusted quantities are grouped into four rep-
resentative waste form categories based on the form
codes reported in the BRS: aqueous liquids, organic liq-
uids and sludges, organic solids, and inorganic solids.
For this analysis, energy recovery was considered sepa-
rately from incineration because regulations and practi-
cal considerations require wastes that are burned for en-
ergy recovery to have higher heating values than wastes
sent to incineration. Based on these determinations, com-
busted waste quantities were grouped into categories
representing the two types of combustion (incineration
and energy recovery) and the four major waste forms.
To relate hazardous waste quantities to carbon
emissions, "fuel equivalent" factors were derived for haz-
ardous waste by assuming that they are simple mixtures
of a common fuel, water, and noncombustible ash. For
liquids and sludges, crude oil is used as the fuel equiva-
lent and coal is used to represent solids.
Fuel equivalent factors were multiplied by the tons
of waste burned to obtain the tons of fuel equivalent.
Multiplying the tons of fuel equivalent by the appropri-
ate carbon content factors from Marland and Rotty (1984)
yields tons of carbon emitted. Implied carbon content is
calculated by dividing the tons of carbon emitted by the
associated tons of waste burned.
This analysis was repeated for each of the BRS
reporting years (odd numbered years from 1989 through
1997) assuming a constant average waste composition
(see in Table 7-15) and fraction oxidized over the period.
To obtain estimates for even numbered years, the aver-
age of the previous and subsequent years was used. A
least-squares linear regression from the time series 1989
through 1997 was used for 1998 and 1999.
Table 7-15: Assumed Composition of Combusted
Hazardous Waste by Weight (Percent)
' Noncom- Fuel
; Waste Type Water bustibles Equivalent
f Energy Recovery
•;"Aqueous Waste
iF: Organic Liquids
1 and Sludges
f" Organic Solids
l~. Inorganic Solids
f Incineration
t Aqueous Waste
= Organic Liquids
•j and Sludges
•-- Organic Solids
g. Inorganic Solids
<~ -: . : : " • • • •
90
30
20
20
90
40
20
20
5
10
20
40
5
20
40
70
5
60
60
40
5
40
40
10
Data Sources
For each of the CO2 emissions methods used to
calculate emissions from MSW combustion, there are
generally two types of activity data needed: the quantity
of product combusted and the carbon content of the prod-
uct. For plastics, synthetic rubber in MSW, and synthetic
fibers, the amount of material in MSW and its portion
combusted was taken from the Characterization of Mu-
nicipal Solid Waste in the United States (EPA 2000c).
7-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
For synthetic rubber and carbon black in scrap tires, this
information was provided by the Scrap Tire Use/Disposal
Study 1998/1999 Update (STMC 1999).
Average carbon contents for the "Other" plastics
category, synthetic rubber in scrap tires, synthetic rub-
ber in MSW, and synthetic fibers have been calculated
from recent production statistics which divide their re-
spective markets by chemical compound. The plastics
production data set was taken from the website of the
American Plastics Council (APC 2000); synthetic rubber
production was taken from the website of the Interna-
tional Institute of Synthetic Rubber Producers (USRP
2000); and synthetic fiber production was taken from the
website of the Fiber Economics Bureau (FEE 2000). Per-
sonal communications with the APC (Eldredge-Roebuck
2000) and the FEE (DeZan 2000) validated the website
information. All three sets of production data can also be
found hi Chemical and Engineering News, "Facts & Fig-
ures for the Chemical Industry." Lastly, information about
scrap tke composition was taken from the Scrap Tire
Management Council's webpage entitled "Scrap Tke Facts
and Figures" (STMC 2000).
The assumption of 98 as the fraction of carbon oxi-
dized, which applies to all municipal solid waste combus-
tion categories for CO2 emissions, was reported in the
EPA's life cycle analysis of greenhouse gas emissions
and sinks from management of solid waste (EPA 1998).
The N2O emission estimates are based on different
data sources. The N2O emissions are a function of total
waste combusted, as reported in the April 1999 issue of
BioCycle (Glenn 1999). Table 7-16 provides MSW genera-
tion and percentage combustion data for the total
wastestream. The emission factor of N2O emissions per
quantity of MS W combusted was taken from Olivier (1993).
Waste quantity data for hazardous wastes were
obtained from the EPA's Biennial Reporting System (BRS)
database for reporting years 1989,1991,1993,1995, and
1997 (EPA 2000a). Combusted waste quantities were ob-
tained from Form GM (Generation and Management) for
wastes burned on site and Form WR (Wastes Received)
for waste received from off-site for combustion. Carbon
emission factors for equivalent fuels were obtained from
Marland and Rotty (1984). All other estimates were as-
sumed based on expert judgment.
Table 7-16: Municipal Solid Waste Generation
(Metric Tons) and Percent Combusted
Ifear, .;-'':
feM ::
E1991
fo-199'2
£•1993
61394
fe1995
13596
£1997"
£1998
EJS99 .
Waste Generation
266,541,881
254,796,765
264,843,388
278,572,955
293,109,556
296,586,430
297,268,188
309,075,035
340,090,022
353,986,624
Combusted (%)
11,5
10.0
11.0
10.0
10.0
10.0
10.0
9.0
7.5
7.5
Uncertainty
There is uncertainty associated with the emissions
estimates for both MSW and hazardous waste combus-
tion. For MSW combustion, uncertainty arises from both
the assumptions applied to the data and the quality of
the data itself. For hazardous wastes, the primary source
of uncertainty surrounds the composition of combusted
wastes.
• MSW Combustion Rate: A source of uncertainty af-
fecting both fossil CO2 and N2O emissions is the
estimate of the MSW combustion rate. The EPA (1999)
estimates of materials generated, discarded, and com-
busted embody considerable uncertainty associated
with the material flows methodology used to gener-
ate them. Similarly, the BioCycle (Glenn 1999) esti-
mate of total waste combustion—used for the N2O
emissions estimate—is based on a survey of State
officials, who use differing definitions of solid waste
and who draw from a variety of sources of varying
reliability and accuracy. Despite the differences in
methodology and data sources, the two references—
the EPA's Office of Solid Waste (EPA 1999) and
BioCycle (Glenn 1999)—provide estimates of total
solid waste combusted that are relatively consistent
(see Table 7-17).
• Fraction Oxidized: Another source of uncertainty
for the CO2 emissions estimate is fraction oxidized.
Municipal waste combustors vary considerably in
their efficiency as a function of waste type, moisture--
content, combustion conditions, and other factors.
The value of 98 percent assumed here may not be
representative of typical conditions.
Waste 7-11
-------
Table 7-17: U.S. Municipal Solid Waste Combusted
by Data Source (Metric Tons)
Year
1990
1991
1992
1993
1994
1995
1996
1997
- 1998
1999
NA (Not
EPA
28,939,680
30,236,976
29,656,638
29,865,024
29,474,928
32.241,888
32,740,848
32,294,240
NA
NA
Available)
BioCyde
30,652,316
25,479,677
29,132,773
27,857,295
29,310,956
29,658,643
29,726,819
27,816,753
25,506,752
NA
Use 0/1998 Data on MSW Composition: The mate-
rials that draw on the Characterization report (EPA
2000b) for data incur uncertainty in their 1999 emis-
sions estimates. Emissions have been calculated from
activity that has been extrapolated from reported 1998
values using average annual growth rates.
Average Carbon Contents: Average carbon contents
are applied to the mass of "Other" plastics com-
busted, synthetic rubber in tires and MSW, and syn-
thetic fibers. These average values have been esti-
mated from the average carbon content of the known
products recently produced. The true carbon con-
tent of the combusted waste may differ from this
estimate depending on differences in the formula
between the known and unspecified materials, and
differences between the composition of the material
disposed and that produced. For rubber, this uncer-
tainty is probably very small since the major elas-
tomers' carbon contents range from 77 to 91 percent;
for plastics, where carbon contents range from 29 to
92 percent, it may be more significant. Overall, this is
a small source of uncertainty.
Synthetic/Biogenic Assumptions: A portion of the
fiber and rubber in MSW is biogenic in origin. As-
sumptions have been made concerning the alloca-
tion between synthetic and biogenic materials based
primarily on expert judgement.
Combustion Conditions Affecting N2O Emissions:
Because insufficient data exist to provide detailed
estimates of N2O emissions for individual combus-
tion facilities, the estimates presented are highly un-
certain. The emission factor for N2O from MSW com-
bustion facilities used in the analysis is a default
value used to estimate N2O emissions from facilities
worldwide (Olivier 1993). As such, it has a range of
uncertainty that spans an order of magnitude (be-
tween 25 and 293 g N2O/metric ton MSW combusted)
(Watanabe, et al. 1992). Due to a lack of information
on the control of N2O emissions from MSW com-
bustion facilities in the United States, the estimate of
zero percent for N2O emissions control removal effi-
ciency is also uncertain.
• Hazardous Waste: The greatest uncertainty in the
hazardous waste combustion analysis is introduced
by the assumptions about the composition of com-
busted hazardous wastes, including the character-
ization that hazardous wastes are similar to mixtures
of water, noncombustibles, and fuel equivalent. An-
other limitation is the assumption that all of the car-
bon that enters hazardous waste combustion is emit-
ted—some small fraction is likely to be sequestered
in combustion ash—but given that the destruction
and removal efficiency for hazardous organics is re-
quired to meet or exceed 99.99 percent, this is a minor
source of uncertainty. Carbon emission estimates
from hazardous waste should be considered central
value estimates that are likely to be accurate to within
±50 percent.
Wastewater Treatment
Wastewater is treated to remove soluble organic
matter, suspended solids, pathogenic organisms and other
chemical contaminants. Soluble organic matter is gener-
ally removed using biological processes in which micro-
organisms consume organic waste for maintenance and
generation of new cells. The resulting biomass is removed
from the wastewater prior to discharge to the receiving
stream. Microorganisms can biodegrade soluble organic
material in wastewater under aerobic and anaeriobic con-
ditions. The biodegradation of soluble organic material
in wastewater treatment systems produces methane when
7-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
it occurs under anaerobic conditions. The amount of meth-
ane produced is driven by the extent to which the organic
material is broken down under anaerobic versus aerobic
conditions. During collection and treatment, wastewater
may be incidentally or deliberately managed under anaero-
bic conditions. In addition, the biomass (sludge) produced
by the microorganisms that have consumed the
wastewater's soluble organic material may be further bio-
degraded under aerobic or anaerobic conditions. The
methane 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 contained under anaerobic conditions.
The organic content, expressed in terms of either
biochemical oxygen demand (BOD) or chemical oxygen
demand (COD), determines the methane producing po-
tential of wastewater. BOD represents the amount of oxy-
gen that would be required to completely consume the
organic matter contained in the wastewater through aero-
bic decomposition processes. COD refers to the amount
of oxygen consumed under specified conditions in the
oxidation of the organic and oxidizable inorganic matter
and is a parameter typically used to characterize indus-
trial wastewater. Under anaerobic conditions and with all
other conditions, such as temperature, being the same,
wastewater with higher BOD or COD concentrations will
produce more methane than wastewater with lower BOD
or COD.
In 1999, methane emissions from domestic or mu-
nicipal wastewater treatment were 12.2 Tg CO2 Eq. (583
Gg). Emissions have increased since 1990 in response to
the increase in the U.S. human population. Since estimates
of emissions from industrial wastewater contain only emis-
sions from the pulp and paper industry at this time, these
emissions are not included in totals. In 1999, methane emis-
sions from industrial wastewater treatment were 0.2 Tg
CO2Eq. (8 Gg). In the future, more research will be con-
ducted to analyze and quantify methane emissions from
wastewater treatment processes at other industries.
Table 7-18 and Table 7-19 provide emission esti-
mates from domestic and industrial wastewater treatment.
Methodology
Domestic wastewater methane emissions are esti-
mated using the default IPCC methodology (IPCC 2000).
The total population for each year was multiplied by a per
capita wastewater BOD production rate to determine to-
tal wastewater BOD produced. It was assumed that, per
capita, 0.065 kilograms of wastewater BOD58 is produced
per day and that 15 percent of wastewater BODS is anaero-
bically digested. This proportion of BOD was then multi-
plied by an emission factor of 0.6 kg CH4/kg BOD5.
Table 7-18: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Tg C02 Eq.)
• Activity
to . •"
CBbmestic ^.
[Industrial*
fetal
1gg(J
fiiilSi^fe^siK
Sw**^^^*^**
11.2 —
1995
11.8
0.2
11.8
1996
11.9
0.2
11.9
1997
12.0
0.2
12.0
1998
12.1
0.2
12.1
1999
12.2
0.2
12.2
i|- Industrial activity only. includes the "pulp and paper industry. ;
llJiite: '.Emissions from 'industrial wastewater treatment are. not included in .totals.
Table 7-19: CH4 Emissions from Domestic and Industrial Wastewater Treatment (Gg)
Sctivity
Bomestic
Industrial*
Eoial ,
1990
533
7
533
f 'Industrial activity only includes the pulp and paper industry.
Note: Emissions from industrial wastewater treatment are not
^•-•- '••.••.•.-, ' ' ' ' '
seS^^^SS^SW
3SK»^«JS
included in totals.
1995
561
8
561
1996
567
8
567
1997
572
8
572
1998
577
8
577
1999
583
8
583
The 5-day biochemical oxygen demand (BOD) measurement (Metcalf and Eddy 1972).
Waste 7-13
-------
A top-down approach was used to develop esti-
mates of methane emissions from industrial wastewater
according to the methodology described in the IPCC Good
Practice Guidance (IPCC 2000). Information on indus-
trial wastewater sources contained in the IPCC Good Prac-
tice Guidance was used to help identify industries that
were likely to have significant methane emissions from
industrial wastewater. Industries were chosen that typi-
cally had both a high volume of wastewater generated
and a high BOD or COD wastewater load. Five industries
that met these criteria were:
• Pulp and paper manufacturing
• Food and beverage production
• Textile (natural) manufacturing
• Petroleum refineries
• Organic chemical manufacturing
Estimates of methane from petroleum refining waste-
water processes are included elsewhere in this document
under the category for petroleum systems. Regarding the
other listed industries, national data on total BOD load-
ings were available only for the pulp and paper industry.
Future efforts will attempt to include the other identified
industries.
There are approximately 565 pulp and paper manu-
facturing facilities in the United States (EPA 1997a). Of
these, 316 facilities operate wastewater treatment sys-
tems that discharge directly to receiving streams. These
facilities do not discharge to a Publicly Owned Treatment
Works (POTW). Wastewater discharges to POTWs are
captured under domestic wastewater treatment. About
25 percent of the dkect discharging pulp and paper facili-
ties use fully-aerated activated sludge treatment, about
50 percent use aerated and non-aerated stabilization ba-
sins, while the remainder use other types of treatment.
Industry experts (NCASI 2000) estimate that approxi-
mately 1 percent of dkect discharging pulp and paper
facilities operate anaerobic treatment systems from which
methane (biogas) may be emitted.
Methane emissions for industrial wastewater treat-
ment in the pulp and paper industry were calculated by
multiplying an emission factor by one percent of the na-
tional BOD removal from the wastewater treatment pro-
cess at dkect discharging pulp and paper mills. National
BOD removal from industrial wastewater treatment by the
pulp and paper industry was calculated using reported
national values for raw wastewater load BOD from dkect
discharging mills and wastewater effluent load BOD from
dkect discharging mills (EPA 1993). The effluent load was
subtracted from the raw wastewater load to estimate na-
tional BOD removal. The national BOD removal value
was then multiplied by the emission factor of 0.6 kg CH4/
kg BOD to estimate national methane emissions for 1990.
Emissions for the years 1991 through 1999 were then cal-
culated by projecting the 1990 national BOD removal value
using 1991 through 1999 annual production values for
the pulp and paper industry.
Data Sources
National population data for 1990 to 1999 were sup-
plied by the U.S. Census Bureau (2000). The emission
factor (0.6 kg CH4/kg BODS) employed for both domestic
and industrial wastewater treatment was taken from IPCC
(2000). Per-capita production of BODS for domestic waste-
water was obtained from the EPA (1997b).
Table 7-20 provides U.S. population and wastewa-
ter BOD data.
A tune series of methane emissions for post-1990
years was developed based on production figures re-
ported in the Lockwood-Post Dkectory (Lockwood-Post
Dkectory 1992-1999). The relative proportion of the post-
1990 year's production to the 1990 base year production
was used to adjust the 1990 BOD removal value to the
other years in the time series.
Table 7-20: U.S. Population (Millions) and
Wastewater BOD Produced (Gg)
jfear
Population
BODS
I.. •
M990
U1991
1'.1992
:'1993
11994
.J995 ,.
; 1996
P1997
i 1998
" 1999
-: -
249.4
252.0
254.9
257.7
260.2
.... ........ 26?f7. ....„„.„
265.2
' """"167.7' """•"
270.2
272.6
5,920
5,984
6,052
6,118
6,179
6,238
6,296
'6,356"
6,415
6,473
7-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 7-21 provides U.S. pulp and paper produc-
tion and wastewater BOD data.
Table 7-21: U.S. Pulp and Paper Production
(Million Metric Tons) and Wastewater BOD
Removed (Gg)
Year
Population
BODS
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
128.9
129.2
134.5
134.1
139.3
140.9
140.3
145.6
145.2
146.2
1,200
1,203
1,253
1,249
1,297
1,312
1,306
1,356
1,352
1,361
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.
The estimated methane emissions from wastewater
treatment processes in the pulp and paper industry are
based on an estimated proportion of the national BOD
removal that occurs at facilities operating anaerobic pro-
cesses. Identifying these facilities and the actual BOD
removal that is accomplished in their treatment systems
would result in a more accurate estimate of methane emis-
sions from the industry.
Human Sewage
Sewage, after treatment in a septic system or waste-
water treatment facility, is disposed on land or discharged
into aquatic environments such as rivers and estuaries.
Nitrous oxide (N2O) may be generated during treatment
and disposal through nitrification and denitrification of
the nitrogen that is present in sewage.9 Nitrification oc-
curs aerobically and converts ammonium (NH4+) into ni-
trate (NO3~), while denitrification occurs anaerobically,
and converts nitrate into dinitrogen gas (N2). Nitrous
oxide can be an intermediate product of both processes.
In general, temperature, pH, biochemical oxygen demand
(BOD), and nitrogen concentration affect N2O genera-
tion from human sewage. The amount of protein con-
sumed by humans determines the quantity of nitrogen
contained in sewage.
Nitrous oxide emissions from human sewage were
estimated using the IPCC default methodology (IPCC/
UNEP/OECD/ffiA 1997) with one exception. The IPCC
methodology assumes that N2O emissions associated
with land disposal and sewage treatment are negligible
and all sewage nitrogen is discharged directly into aquatic
environments. In the United States, however, a certain
amount of sewage nitrogen is applied to soils via sewage
sludge applications, and therefore, not all sewage nitro-
gen enters aquatic environments.10 The N2O estimates
presented here account for the amount of nitrogen in
sewage sludge applied to soils.
Emissions of N2O from sewage nitrogen discharged
into aquatic environments were estimated to be 8.2 Tg
CO2 Eq. (26 Gg) in 1999. An increase in the U.S. popula-
tion and the per capita protein intake resulted hi an over-
all increase of 15 percent in N2O emissions from human
sewage between 1990 and 1999 (see Table 7-22).
Table 7-22: N20 Emissions from Human Sewage
^ Year TgC02Eq. Gg
-1990
1995
~:1996
8=1997
SB1998
^'1999
isfe.::;.-: ; ,'. _ ._-..
7.1
8.2
7.8
7.9
8.1
8.2
23
27
25
26
26
26
9 This section focuses on N20 emissions from human sewage. Methane emissions due to the treatment of human sewage in wastewater
treatment facilities are addressed in the previous section of this chapter, Wastewater Treatment.
10 The IPCC methodology is based on the total amount of nitrogen in sewage, which is in turn based on human protein consumption and
the fraction of nitrogen in protein (i.e., Brac^u). A portion of the total nitrogen in sewage in the United States is applied to soils in
the form of sewage sludge each year. This amount is estimated as part of agricultural soil management (see Chapter 6) and is subtracted
here from total nitrogen in human sewage to estimate sewage N2O emissions.
Waste 7-15
-------
Methodology
With the exception described above, N2O emissions
from human sewage were estimated using the IPCC de-
fault methodology (IPCC/UNEP/OECD/ffiA 1997). This
methodology is illustrated below:
N2O(s) = {[(ProteinjxCFracNpj^xCU.S. Population)]
Table 7-23: U.S. Population (Millions) and Average
Protein Intake (kg/Person/Year)
where,
N2O(s) = N2O emissions from human sewage
Protein = Annual, per capita protein consumption
FraCfjpR = Fraction of nitrogen in protein
NSoil = Quantity of sewage sludge N applied to
soils
EF = Emission factor (kg N20-N/kg sewage-N
produced)
= The molecular weight ratio of N2O to N2
Data Sources
U.S. population data were taken from the U.S. Cen-
sus Bureau (2000). Data on annual per capita protein con-
sumption were provided by the United Nations Food and
Agriculture Organization (FAO 2000) (see Table 7-23).
Because data on protein intake were unavailable for 1999,
the value of per capita protein consumption for the previ-
ous year was used. An emission factor has not been spe-
cifically estimated for the United States, so the de-
fault IPCC value (0.01 kg N2O-N/kg sewage-N produced)
was applied. Similarly, the fraction of nitrogen in protein
(0. 1 6 kg N/kg protein) was also obtained from IPCC/UNEP/
OECD/IEA(1997).
Uncertainty
The U.S. population (NR people), per capita pro-
tein intake data (Protein), and fraction of nitrogen in pro-
tein (FracNpR) are believed to be fairly accurate. Signifi-
cant uncertainty exists, however, in the emission factor
(EF). This uncertainty is due to regional differences that
would likely affect N2O emissions but are not accounted
for in the default IPCC factor. Moreover, the underlying
- Year
~ 1990
» 1991
' 1992
^1993
1994
I "f995
i 1996
- 1997
" 1998
T1999
Population
249.4
252.0
' 254.9 "~
257.7
260.2
' "'262.7 '" --
2655 • " '
267.7
270.2
272.6
Protein
39.1
39.7
39.9
40.3
41.4
43.4 .
41.0 '
41.4 :
42.6 , "
42.0
methodological assumption that negligible N2O emissions
result from sewage treatment may be incorrect. Taken to-
gether, these uncertainties present significant difficulties
in estimating N2O emissions from human sewage.
Waste Sources of Criteria Pollutants
In addition to the main greenhouse gases ad-
dressed above, waste generating and handling processes
are also sources of criteria air pollutant emissions. Total
emissions of nitrogen oxides (NOX), carbon monoxide
(CO), and nonmethane volatile organic compounds
(NMVOCs) from waste sources for the years 1990 through
1999 are provided in Table 7-24.
Methodology and Data Sources
These emission estimates were taken directly from
theEPA's National Air Pollutant Emissions Trends, 1900-
1999 (EPA 2000). This EPA report provides emission es-
timates of these gases by sector, using a "top down"
estimating procedure—emissions were calculated either
for individual sources or for many sources combined, us-
ing 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.
7-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table 7-24: Emissions of NOX, CO, and NMVOC from Waste (Gg)
Gas/Source
NOX
Landfills
Wastewater Treatment
Waste Combustion3
Miscellaneous11
CO
Landfills
Wastewater Treatment
Waste Combustion3
Miscellaneous11
NMVOCs
Landfills
Wastewater Treatment
Waste Combustion3
Miscellaneousb
1990
83
4-
4-
82
4-
979
1
4-
978
+
895
58
57
222
558
I 1995
89
.-_:-.-.- ; 1
V "" +
Tl_.: 88
;- 1
1 I 1,075
2
4-
1,073
„ .,,. 1
968
68
61
237
602
1996
92
2
+
89
1
1,012
5
4-
1,006
+
378
32
61
222
64
1997
92
2
4.
89
1
1,024
5
4-
1,019
4-
382
32
62
225
64
1998
93
2
_l_
91
1
1,035
5
4.
1,030
4.
388
33
63
228
65
1999
83
2
_l_
80
1
3,439
5
4.
3,434
4.
532
33
64
369
65
a Includes waste incineration and open burning (EPA 2000)
b 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
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 1997). The EPA currently derives the overall
emission control efficiency of a source category from a
variety of information sources, including published reports,
the 1985 National Acid Precipitation and Assessment Pro-
gram emissions inventory, .and other EPA data bases.
Uncertainty
Uncertainties in these estimates are primarily due
to the accuracy of the emission factors used and accu-
rate estimates of activity data.
Waste 7-17
-------
7-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
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8-30 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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Annexes
The following twenty-three annexes provide additional information to the material presented in the main
body of this report. Annexes A through M 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 N presents a summary of Global Warming Potential values. Annexes O and P summarize U.S. emissions of
ozone depleting substances (e.g., CFCs and HCFCs) and sulfur dioxide (SO2), respectively. Annex Q provides a
complete list of emission sources assessed in this report. Annex R presents the IPCC reference approach for
estimating CO2 emissions from fossil fuel combustion. Annex S addresses the criteria for the inclusion of an
emission source category and some of the sources that meet the criteria but are nonetheless excluded from U.S.
estimates. Annex T provides some useful constants, unit definitions, and conversions. Annexes U and V provide a
listing of abbreviations and chemical symbols used. Finally, Annex W contains a glossary of terms related to
greenhouse gas emissions and inventories.
List of Annexes
ANNEX A
ANNEXE
ANNEX C
ANNEXD
ANNEXE
ANNEXF
ANNEX G
ANNEX H
ANNEX I
ANNEXJ
ANNEXK
ANNEXL
ANNEXM
ANNEXN
ANNEXO
ANNEXP
ANNEX Q
ANNEX R
ANNEXS
ANNEXT
ANNEXU
ANNEXV
ANNEX W
Methodology for Estimating Emissions of CO2 from Fossil Fuel Combustion
Methodology for Estimating Carbon Stored in Products from Non-Energy Uses of Fossil Fuels
Methodology for Estimating Emissions of CHi, N2O, and Criteria Pollutants from Stationary Combustion
Methodology for Estimating Emissions of CH,, N2O, and Criteria Pollutants from Mobile Combustion
Methodology for Estimating CH» Emissions from Coal Mining
Methodology for Estimating CH4 Emissions from Natural Gas Systems
Methodology for Estimating CH4 Emissions from Petroleum Systems
Methodology for Estimating Emissions from International Bunker Fuels Used by the U.S. Military
Methodology for Estimating HFC, PFC, and SF6 Emissions from Substitution of Ozone Depleting Substances
Methodology for Estimating CH, Emissions from Enteric Fermentation
Methodology for Estimating CtLt and N2O Emissions from Manure Management
Methodology for Estimating N2O Emissions from Agricultural Soil Management
Methodology for Estimating CHt Emissions from Landfills
Global Warming Potential Values
Ozone Depleting Substance Emissions
Sulfur Dioxide Emissions
Complete List of Source Categories
IPCC Reference Approach for Estimating CO2 Emissions from Fossil Fuel Combustion
Sources of Greenhouse Gas Emissions Excluded
Constants, Units, and Conversions
Abbreviations
Chemical Symbols
Glossary
-------
-------
ANNEX A
Methodology for Estimating Emissions of C02 from Fossil Fuel Combustion
Carbon dioxide (CCs) emissions from fossil fuel combustion were estimated using a "bottom-up"
methodology characterized by six steps. These steps are described below.
Step 1: Determine Energy Consumption by Fuel Type and Sector
The bottom-up methodology used by the United States for estimating 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 through 8 of Table A-l
through Table A-10, with totals by fuel type in Column 8 and totals by end-use sector in the last rows. Fuel
consumption data for the bottom-up approach were obtained directly from the Energy Information Administration
(EIA) of the U.S. Department of Energy. These data were first gathered in physical units, and then converted to
their energy equivalents (see "Converting Physical Units to Energy Units" in Annex T). The EIA data were
collected through a variety of consumption surveys at the point of delivery or use and qualified with survey data on
fuel production, imports, exports, and stock changes. Individual data elements were supplied by a variety of sources
within EIA. Most information was taken from published reports, although some data were drawn from unpublished
energy studies and databases maintained by EIA.
Energy consumption data were aggregated by 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 1999 total energy consumption across all sectors,
including territories, and energy types was 82,100 trillion British thermal units (TBtu), as indicated in the last entry
of Column 8 in Table A-l. This total includes fuel used for non-energy purposes and fuel consumed as international
bunkers, both of which are deducted in later steps.
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 through
Table A-10 and those recommended in the IPCC emission inventory methodology.
First, consumption data in the U.S. inventory are presented using higher heating values (HHV)1 rather than
the lower heating values (LHV)2 reflected in the IPCC emission inventory methodology. This convention is
followed because data obtained from EIA are based on HHV. Of note, however, is that EIA renewable energy
statistics are often published using LHV. The difference between the two conventions relates to the treatment of the
1 Also referred to as Gross Calorific Values (GCV).
2 Also referred to as Net Calorific Values (NCV).
A-1
-------
heat energy that is consumed in the process of evaporating the water contained in the fuel. The simplified
convention used by the International Energy Agency for converting from HHV to LEV is to reduce the energy
content by 5 percent for petroleum and coal and by 10 percent for natural gas.
Second, while EIA's energy use data for the United States includes only the 50 U.S. states and the District
of Columbia, the data reported to the Framework Convention on Climate Change are to include energy consumption
within territories. Therefore, consumption estimates for U.S. territories were added to domestic consumption of
fossil fuels. Energy consumption data from U.S. territories are presented in Column 7 of Table A-l. It is reported
separately from domestic sectoral consumption, because it is collected separately by EIA with no sectoral
disaggregation.
Third, the domestic sectoral consumption data in Table A-l include bunker fuels used for international
transport activities and non-energy uses of fossil fuels. The IPCC requires countries to estimate emissions from
international bunker f»"ils separately and exclude these emissions from national totals, so international bunker fuel
emissions have been e imated in Table A-l 1 and deducted from national estimates (see Step 4). Similarly, fossil
fuels used to produce u^n-energy products that store carbon rather than release it to the atmosphere are provided in
Table A-12 and deducted from national emission estimates (see Step 3). The final fate of these fossil fuel based
products is dealt with under the waste combustion source category in cases where the products are combusted
through waste management practices.
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 (see Table A-13 and Table A-14) that reflect
the amount of carbon per unit of energy in each fuel. The resulting carbon contents are sometimes referred to as
potential emissions, or the maximum amount of carbon that could potentially be released to the atmosphere if all
carbon in the fuels were oxidized. The carbon content coefficients used in the U.S. inventory were derived by EIA
from detailed fuel information and are similar to the carbon content coefficients contained in the IPCC's default
methodology (IPCC/UNEP/OECD/IEA 1997), with modifications reflecting fuel qualities specific to the United
States.
Step 3: Adjust for the amount of Carbon Stored in Products
Depending on the end-use, non-energy uses of fossil fuels can result in long term storage of some or all of
the carbon contained in the fuel. For example, asphalt made from petroleum can sequester up to 100 percent of the
carbon contained in the petroleum feedstock for extended periods of time. Other non-energy fossil fuel products,
such as lubricants or plastics also store carbon, but can lose or emit some of this carbon when they are used and/or
burned as waste.3
The amount of carbon in non-energy fossil fuel products was based upon data that addressed the fraction of
carbon that remains in products after they are manufactured, with all non-energy use attributed to the industrial,
transportation, and territories end-use sectors. This non-energy consumption is presented in Table A-12. -This data
was then multiplied by fuel-specific carbon content coefficients (Table A-13 and Table A-14) to obtain the carbon
content of the fuel, or the maximum amount of carbon that could remain in non-energy products (Columns 5 and 6
of Table A-12). This carbon content was then multiplied by the fraction of carbon assumed to actually.have
remained in products (Column 7 of Table A-12),.resulting in the final estimates by sector and fuel type, which are
presented in Columns 8 through 10 of Table A-12. A detailed discussion of carbon stored in products is provided in
the Energy Chapter and in Annex B.
Step 4: Subtract Carbon from International Bunker Fuels
Emissions from international transport activities, or international bunker fuel consumption, were not
included in national totals, as required by the IPCC (IPCC/UNEP/OECD/IEA 1997). There is currently
3 See Waste Combustion section of the Waste chapter for a discussion of emissions from the combustion of plastics in
the municipal solid waste stream.
A-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
disagreement internationally as to how these emissions should be allocated, and until this issue is resolved, countries
are asked to report them separately. EIA energy statistics, however, include these bunker fuels—jet fuel for aircraft,
and distillate fuel oil and residual fuel oil for marine shipping—as part of fuel consumption by the transportation
sector. To compensate for this inclusion, international bunker fuel emissions4 were calculated separately (see Table
A-l 1) and the carbon content of these fuels was subtracted from the transportation sector. International bunker fuel
emissions from military activities were developed using data provided by the Department of Defense as described in
the International Bunker Fuels section of the Energy chapter and in Annex H. The calculations of international
bunker fuel emissions followed the same procedures used for other fuel emissions (i.e., estimation of consumption,
determination of carbon content, and adjustment for the fraction of carbon not oxidized).
Step 5: Account for Carbon that Does Not Oxidize During Combustion
Because combustion processes are not 100 percent efficient, some of the carbon contained in fuels is not
emitted in a gaseous form to the atmosphere. Rather, it remains behind as soot, particulate matter and ash. The
estimated fraction of carbon not oxidized in U.S. energy conversion processes due to inefficiencies during
combustion ranges from 0.5 percent for natural gas to 1 percent for petroleum and coal. Except for coal these
assumptions are consistent with the default values recommended by the IPCC (IPCC/UNEP/OECD/IEA 1997). In
the United States, unoxidized carbon from coal combustion was estimated to be no more than one percent (Bechtel
1993). Table A-13 presents fractions oxidized by fuel type, which are multiplied by the net carbon content of the
combusted energy to give final emissions estimates.
Of the fraction of carbon that is oxidized (e.g., 99 to 99.5 percent), the vast majority is emitted in its fully
oxidized form as carbon dioxide (CO2). A much smaller portion of this "oxidized" carbon is also emitted as carbon
monoxide (CO), methane (CHLt), and non-methane volitile organic compounds (NMVOCs). These partially
oxidized or unoxidized carbon compounds when in the atmosphere, though, are generally oxidized to COi through
atmospheric processes (e.g., reaction with hydroxyl (OH)).
Step 6: Summarize Emission Estimates
Actual COi 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 international bunker fuels and carbon in non-energy products were made. Emission
estimates are expressed in teragrams of carbon dioxide equivalents (Tg. CO2 Eq.).
To determine total emissions by final end-use sector, emissions from electric utilities were distributed to
each end-use sector according to its share of aggregate electricity consumption (see Table A-15). This pro-rated
approach to allocating emissions from electric utilities may overestimate or underestimate emissions for particular
sectors due to differences in the average carbon content of utility fuel mixes.
4 Refer to the International Bunker Fuels section of the Energy chapter for a description of the methodology for
distinguishing between bunker and non-bunker fuel consumption.
A-3
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Table A-11: 1999 C02 Emissions From International Bunker Fuel Consumption
Fuel Type Bunker Fuel Carbon Content Potential Fraction
Consumption Coefficient Emissions (Tg Oxidized
Emissions
(Tg CO, Eq.)
(TBtu) (Tg Carbon/QBtu)1 Carbon)
Distillate Fuel Oil
Jet Fuel
Residual Fuel Oil
Total
Table A-12: 1999 Carbon
1
113
869
490
1,471
In Non-Energy Products
2
19.95
19.33
21.49
3
Carbon Content
Fuel Type
Industry
Industrial Coking Coal
Natural Gas
Nitrogenous Fertilizers
Other Uses
Asphalt & Road Oil
LP6
Lubricants
Pentanes Plus
Petrochemical Feedstocks
Naphtha (<401 deg. F)
Other Oil (>401 deg.F)
Still Gas
Petroleum Coke
Special Naphtha
Other (Wax/Misc.)
Distillate Fuel Oil
Residual Fuel
Waxes
Miscellaneous
Transportation
Lubricants
U.S. Territories
Lubricants
Other Petroleum (Misc.)
Total
Non-energy Use
(TBtu) (Tg
6,476.9
24.5
381.7
372.6
1,324.4
1,807.1
192.8
331.7
502.1
811.1
0.0
376.8
145.4
7.0
50.3
37.4
111.9
182.1
182.1
227.4
1.4
226.0
6,886.4
Coefficient
Carbon/QBtu)
25.56
14.47
14.47
20.62
16.88
20.24
18.24
18.14
19.95
17.51
27.85
19.86
19.95
21.49
19.81
20.19
20.24
20.24
20.00
2.3 0.99
16.8 0.99
10.5 0.99
29.6
4
Potential
Emissions
(Tg Carbon)
122.2
0.6
5.5
5.4
27.3
30.5
3.9
6.0
9.1
16.2
0.0
10.5
2.9
0.1
1.1
0.7
2.3
3.7
3.7
4.5
0.0
4.5
130.4
8.2
61.6
38.5
108.3
5
6
Fraction Carbon Stored (Tg
Sequestered9
0.75
0.00
0.91
1.00
0.91
0.09
0.91
0.91
0.91
0.80
0.50
0.00
0.50
0.50
1.00
1.00
0.09
0.09
0.10
CO, Eq.)
358.8
1.7
0.0
17.9
100.1
101.2
1.3
20.1
30.2
53.7
0.0
19.2
0.0
0.3
2.0
2.7
8.3
1.2
1.2
1.7
0.0
1.7
361.7
'See Annex B for additional detail.
• One QBtu is one quadrillion Btu, or 1015 Btu. This unit is commonly referred to as a "Quad.'
A-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table A-13: Key Assumptions for Estimating Carbon Dioxide Emissions
Fuel Type
Carbon Content Coefficient
(Tg Carbon/QBlu)
Fraction Oxidized
Coal
Residential Coal
Commercial Coal
Industrial Coking Coal
Industrial Other Coal
Coke Imports
Transportation Coal
Utility Coal
U.S. Territory Coal (bit)
Natural Gas
Petroleum
Asphalt & Road Oil
Aviation Gasoline
Distillate Fuel Oil
Jet Fuel
Kerosene
LPG
LPG (Territories)
LPG (non-energy use)
Lubricants
Motor Gasoline
Residual Fuel
Other Petroleum
AvGas Blend Components
Crude Oil
MoGas Blend Components
Misc. Products
Misc. Products (Territories)
Naphtha (<401 deg. F)
Other Oil (>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]
[a]
[a]
20.24
[a]
21.49
20.23
18.87
[a]
[a]
[a]
20.00
18.14
19.95
18.24
19.37
27.85
17.51
, 19.86
[a]
19.81
19.81
2.05
0.99
0.99
0.99
0.99
0.99
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
0.99
0.99
0.99
1.00
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).
- Not applicable
NC (Not Calculated)
[a] These coefficients vary annually due to fluctuations in fuel quality (see Table A-14).
A-15
-------
Table A-14: Annually Variable Carbon Content Coefficients by Year (Tg Carbon/QBtu)
Fuel Type
Residential Coal
Commercial Coal
Industrial Coking Coal
Industrial Other Coal
Utility Coal
LPG
LPG (energy use/Territories)
LPG (non-energy use)
Motor Gasoline
Jet Fuel
MoGas Blend Components
Misc. Products
Unfinished Oils
Crude Oil
1990
25.92
25.92
25.51
25.58
25.68
16.99
17.13
16.83
19.41
19.40
19.41
20.16
20.16
20.16
1991
26.00
26.00
25.51
25.59
25.69
16.98
17.12
16.84
19.41
19.40
19.41
20.18
20.18
20.18
1992
26.13
26.13
25.51
25.62
25.69
16.99
17.13
16.84
19.42
19.39
19.42
20.22
20.22
20.22
1993
25.97
25.97
25.51
25.61
25.71
16.97
17.13
16.80
19.43
19.37
19.43
20.22
20.22
20.22
1994
25.95
25.95
25.52
25.63
25.72
17.01
17.13
16.88
19.45
19.35
19.45
20.21
20.21
20.21
1995
26.00
26.00
25.53
25.63
25.74
17.00
17.12
16.87
19.38
19.34
19.38
20.23
20.23
20.23
1996
25.92
25.92
25.55
25.61
25.74
16.99
17.11
16.86
19.36
19.33
19.36
20.25
20.25
20.25
1997
26.00
26.00
25.56
25.63
25.76
16.99
17.11
16.88
19.35
19.33
19.35
20.24
20.24
20.24
1998
26.00
26.00
25.56
25.63
25.76
16.99
17.11
16.87
19.36
19.33
19.36
20.24
20.24
20.24
1999
26.00
26.00
25.56
25.63
25.76
16.99
17.11
16.88
19.36
19.33
19.36
20.19
20.19
20.19
Source: EIA (2000c)
Table A-15: 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
2,763
1993
995
886
977
4
2,861
1994
1,008
914
1,008
4
2,935
1995
1,043
954
1,013
4
3,013
1996
1,082
981
1,030
4
3,098
1997
1,076
1,027
1,033
4
3,140
1998
1,128
1,068
1,040
4
3,240
1999
1,139
1,072
1,050
4
3,265
*E1A electric utility fuel consumption data does not include the U.S. territories.
- Not applicable
Source: EIA(2000a)
A-16 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Annex B
Methodology for Estimating Carbon Stored in Products from Non-Energy Uses of
Fossil Fuels
Carbon storage associated with the non-energy use of fossil fuels was calculated by multiplying each fuel's
potential emissions (i.e., each fuel's total carbon content) by a fuel-specific storage factor. This Annex explains the
methods and data sources employed in revising the storage factors for asphalt and road oil, petrochemical
feedstocks, liquid petroleum gases (LPG), pentanes plus, and natural gas for chemical plants. The storage factors for
the remaining non-energy fuel uses are based on values reported by Marland and Rotty (1984).
Table B-1: Fuel Types and their Non-Energy Storage Factors
Fuel Type
Storage Factor
Industrial Coking Coal
Natural Gas to Chemical Plants
Nitrogenous Fertilizers
Other Uses
Asphalt & Road Oil
Liquefied Petroleum Gas (LPG)
Lubricants
Pentanes Plus
Petrochemical Feedstocks3
Naphtha (b.p.<401°F)
Other Oil (b.p.>401°F)
Petroleum Coke
Special Naphtha
Other
Distillate Fuel Oil
Residual Fuel
Waxes
Miscellaneous Products'"
0.75
0
0.91
1.00
0.91
0.09
0.91
0.91
0.91
0.50
0
0.50
0.50
1.00
1.00
- Not applicable
a Includes still gas, for which EIA has reported zero consumption in 1996,1998, and 1999.
b Because of differences in fuel characteristics between the United States and U.S. Territories, the storage factor for Miscellaneous Products consumed in
U.S. Territories is set at 0.1.
The following sections describe the selected non-energy uses in greater detail, outlining the methods
employed and data used in estimating each storage factor. Several of the fuel types tracked by EIA—petrochemical
feedstocks, pentanes plus, LPG, and natural gas—are used in organic chemical synthesis. Because the methods and
data used to analyze these fuel types overlap, they are handled as a group and are discussed first. Discussions of the
storage factors for (a) asphalt and road oil, and (b) lubricants follow.
Petrochemical Feedstocks, Pentanes Plus, Liquefied Petroleum Gases, and Natural Gas
Petrochemical feedstocks, pentanes plus, liquefied petroleum gases (LPG) and natural gas1 are used in the
manufacture of a wide variety of man-made chemicals and products. Plastics, rubber, synthetic fibers, solvents,
paints, fertilizers, pharmaceuticals, and food additives are just a few of the derivatives of these four fuel types.
1 Natural gas has two categories of non-energy consumption: for fertilizer and for other chemical syntheses. Only
natural gas that is supplied to chemical plants for other uses is included here. Natural gas used for fertilizer is not included
because it is assumed that all of the carbon is converted to carbon dioxide during ammonia synthesis.
B-1
-------
Chemically speaking, these fuels are diverse, ranging from simple natural gas (i.e., predominantly methane, CH4) to
heavier, more complicated naphthas and fuel oils.2
The four fuel categories constituted approximately 247 Tg CO2 Eq., or 52 percent, of the 478 Tg CO2 Eq.
of non-energy fuel consumption in 1999. Of this, 223 Tg CO2 Eq., or 91 percent, of the carbon ends up stored in
products, while the remaining 23 Tg CO2 Eq. was emitted as an industrial process waste or through evaporative
product use. These emissions can be thought of as a variety of organic gases; however, most of these emissions will
eventually oxidize into carbon dioxide in the atmosphere.
Methodology and Data Sources
An empirically determined storage factor was developed for the carbon consumed for non-energy end uses
among petrochemical feedstocks, pentanes plus, LPG, and natural gas. The storage factor is equal to the ratio of
carbon stored in the final products to total carbon content for the nonenergy fossil fuel feedstocks diverted to
industrial processes. Only one aggregate storage factor was calculated for the four fuel types. As noted above, the
fuels were grouped because of the overlap of their derivative products. Due to the many reaction pathways involved
in producing petrochemical products (or wastes), it becomes extraordinarily complex to link individual products (or
wastes) to their parent fuels.
The overall storage factor was determined by investigating the carbon used in manufacturing the major
petrochemical products. Plastics, synthetic rubber, synthetic fibers, carbon black, industrial volatile organic
compound (VOC) emissions, industrial toxic releases, pesticides, and solvents were identified as the major product
categories.3 Estimating the carbon stored by the non-energy use of petrochemical feedstocks, pentanes plus, LPG,
and natural gas requires two pieces of information for each of the major products that are derived from these fuels.
First, the total amount of carbon contained in the product or waste must be determined. The total carbon content of
the fuels was calculated by multiplying the fuels' non-energy consumption by their respective carbon content values.
Similar to fuel consumed for energy purposes, the consumption data was taken from EIA (2000). Carbon content
values are discussed in Annex A.
Next, the carbon must be categorized as either stored or emitted. The aggregate storage factor is the carbon-
weighted average of storage across the fuel types. As discussed later in the section on Uncertainty, data were not
available for all of the non-energy end uses, so the uses analyzed represent only a sample of the total carbon
consumed. The sample accounts for 151 Tg CO2 Eq., or 62 percent, of the 247 Tg CO2 Eq. of carbon within these
fuel types that is consumed for non-energy purposes. The remaining carbon is assumed to be stored and emitted in
the same ratio as the products for which data are available. The following sections provide details on the calculation
steps, assumptions, and data sources employed in estimating and classifying each product's carbon. Summing the
carbon stored and dividing it by the total carbon used yields the overall storage factor, as shown in Table B-2 and
the equation below. The major products and their carbon contents are also shown in Table B-2.
Overall Storage Factor = Carbon Stored / Total Carbon = 136.3 Tg CO2 Eq. / 150.5 Tg CO2 Eq. = 91%
2 Naphthas are compounds distilled from petroleum containing 4 to 12 carbon atoms per molecule and having a boiling
point less than 401° F. Fuel oils are distillates containing 12 to 25 carbon atoms per molecule and having a boiling point greater
than 401° F.
3 For the most part, the releases covered by the U.S. Toxic Release Inventory represent air emissions or water
discharges associated with production facilities. Similarly, VOC emissions are generally associated with production facilities.
These emissions could have been accounted for as part of the Waste chapter, but because they are not necessarily associated with
waste management, they were included here instead. Toxic releases are not a "product" category, but they are referred to as such
for ease of discussion.
B-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table B-2: Carbon Stored and Emitted by Products from Petrochemical Feedstocks, Pentanes Plus, LPG, and
Natural Gas (Tg C02 Eq.)
Product/Waste Type
Plastics
Synthetic Rubber
Synthetic Fiber
Carbon Black
Pesticides
Industrial Releases
Industrial VOCs
TRI Releases
Solvent VOCs
Total
Carbon Stored
110.4
7.7
11.7
5.9
0.4
0.10
"
0.1
-
136.3
Carbon Emitted
.
-
-
-
0.2
4.8
3.8
1.0
9.3
14.3
- Not applicable
Plastics
Data on annual production were taken from the American Plastics Council, as published in Chemical &
Engineering News and through direct communication with the APC (APC 2000, Eldredge-Roebuck 2000). These
data were organized by year and resin type (Table B-3). A carbon content was assigned for each resin. These
contents were based on molecular formulas and are listed in Table B-4 and Table B-5. In cases where the resin type
is generic, referring to a group of chemicals and not a single polymer (e.g., phenolic resins, other styrenic resins), a
representative compound was chosen. For engineering and other resins, a weighted carbon content of 65 percent
was assumed (i.e., it was assumed that these resins had the same content as those for which we could assign a
representative compound).
There were no emissive uses of plastics identified, so 100 percent of the carbon was considered stored in
products. However, an estimate of emissions related to the combustion of these plastics in the municipal solid waste
stream can be found in the Waste Combustion section of the Waste chapter.
Table B-3:1998 Plastic Resin Production (Tg dry weight) and Carbon Stored (Tg C02 Eq.)
Resin Type
Epoxy
Polyester (Unsaturated)
Urea
Melamine
Phenolic
Low-Density Polyethylene (LDPE)
Linear Low-Density Polyethylene (LLDPE)
High Density Polyethylene (HOPE)
Polypropylene (PP)
Acrylonitrile-butadiene-styrene (ABS)
Styrene-acrylonitrile (SAN)
Other Styrenics
Polystyrene (PS)
Nylon
Polyvinyl chloride (PVC)b
Thermoplastic Polyester
Engineering Resins
All Other
Total
1998 Production3
0.29
0.78
1.17
0.13
1.79
3.44
3.28
5.86
6.27
0.65
0.06
0.75
2.83
0.58
6.58
2.01
1.25
3.88
41.59
Carbon Stored
0.8
1.8
1.5
0.1
5.0
10.8
10.3
18.4
19.7
2.0
0.2
2.5
9.6
1.4
9.3
4.6
3.0
9.4
110.4
' Includes production from Canada for ABS, SAN, PVC, PP, Phenolic, Urea, Melamine, and Thermoplastic Polyester.
" Includes copolymers.
B-3
-------
Table B-4: Assigned Carbon Contents of Plastic Resins (by weight)
Resin Type
Carbon
Content
Source of Carbon Content Assumption
Epoxy
Polyester (Unsaturated)
Urea
Melamine
Phenolic
Low-Density Polyethylene (LDPE)
Linear Low-Density Polyethylene (LLDPE)
High Density Polyethylene (HOPE)
Polypropylene (PP)
Acrylonitrile-Butadiene-Styrene (ABS)
Styrene-Acrylonitrile (SAN)
Other Styrenics
Polystyrene (PS)
Nylon
Polyvinyl Chloride (PVC)
Thermoplastic Polyester
Engineering Resins
All Other
76% Typical epoxy resin made from epichlorhydrin and bisphenol A
63% Poly (ethylene terepthalate) (PET)
34% 50% carbamal, 50% N-(hydroxymethyl) urea *
29% Trimethylol melamine *
77% Phenol
86% Polyethylene
86% Polyethylene
86% Polyethylene
86% Polypropylene
85% 50% styrene, 25% acrylonitrile, 25% butadiene
80% 50% styrene, 50% acrylonitrile
92% Polystyrene
92% Polystyrene
65% Average of nylon resins (see Table B-5)
38% Polyvinyl chloride
63% Polyethylene terephthalate
66% Weighted average of other resin production
66% Weighted average of other resin production
*Does not include alcoholic hydrogens.
Table B-5: Major Nylon Resins and their Carbon Contents (by weight)
Nylon Resin
nylon 6
nylon 6,6
nylon 4
nylon 6,10
nylon 6,11
nylon 6,12
nylon 11
Carbon Content
64%
64%
52%
68%
69%
70%
72%
Synthetic Rubber
Annual consumption of synthetic rubber was taken from the International Institute of Synthetic Rubber
Producers (IISRP) press release "Synthetic Rubber Use Growth to Continue Through 2004, Says IISRP and RMA"
(IISRP 2000). Due to the fact that production data for synthetic rubber were unavailable, consumption was assumed
to equal production and used in the calculations. This data is organized by year, and by elastomer type. For each
resin, a carbon content was assigned. These contents, based on stoichiometry, are listed in Table B-6. For the
"Others" category, a weighted carbon content was calculated from total 1998 resin consumption data.
There were no emissive uses of rubber identified, so 100 percent of the carbon was assumed stored.
However, emissions related to the combustion of scrap tires and rubber consumer goods can be found in the Waste
Combustion section of the Waste chapter.
B-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table B-6:1998 Rubber Consumption, Carbon Content, and Carbon Stored
Elastomer Type
SBR Solid
Polybutadiene
Ethylene Propylene
Polychloroprene
NBR Solid
Polyisoprene
Others
Total
1998 Consumption
(Thousand Metric Tons) *
908
561
320
69
87
78
369
2,392
Carbon
Content
91%
89%
86%
59%
77%
88%
88%
-
Carbon Stored
(TgC02Eq.)
3.0
1.8
1.0
0.1
0.2
0.3
1.2
7.7
' Includes consumption in Canada.
- Not applicable
Synthetic Fibers
Annual fiber production data was taken from the Fiber Economics Bureau, as published in Chemical &
Engineering News and exhibited on the FiberSource website (FEE 2000). These data were organized by year and
fiber type. For each fiber, a carbon content was assigned based on stoichiometry (see Table B-7). For polyester, the
carbon content for poly(ethylene terepthalate) (PET) was used as a representative compound. For nylon, the average
carbon content of nylon 6 and nylon 6,6 was used, since these are the most widely produced nylon fibers. Cellulosic
fibers, such as acetate and rayon, have been omitted from the synthetic fibers' carbon accounting because much of
their carbon is of biogenic origin. These fibers account for only 4 percent of overall fiber production, by weight.
There were no emissive uses of fibers identified, so 100 percent of the carbon was considered stored.
However, emissions related to the combustion of textiles in the municipal solid waste stream is accounted for under
the Waste Combustion section of the Waste chapter.
Table B-7:1998 Fiber Production, Carbon Content, and Carbon Stored
Fiber Type
Polyester
Nylon
Olefin
Acrylic
Carbon Stored
Production (Tg) Carbon Content (TgC02Eq.)
1.8
1.3
1.3
0.2
63%
64%
86%
68%
4.1
3.0
4.1
0.5
Total
- Not applicable
4.6
11.7
Carbon Black
Carbon black is a finely divided solid form of carbon produced from the partial oxidation of heavy oil
fractions.4 It is used primarily in tire treads and other abrasion resistant rubber products, but can also be used in
pigments for paints and inks. In 1998, carbon black ranked the 35th in chemical production in the United States with
1,610,280 metric tons produced (CMA 1999).
Since carbon black is essentially pure carbon, its carbon content was assumed to be 100 percent. Also,
since it is used in solid products and resists degradation, it was considered 100 percent stored. For 1998, carbon
stored as a result of carbon black production was estimated to be 5.9 Tg COi Eq. (5,904 Gg).
Carbon black can also be produced from the cracking of natural gas, but this method is uncommon.
B-5
-------
Pesticides
Pesticide consumption data was taken from the 1996/1997 Pesticides Industry Sales and Usage (EPA
1999) report. Although some production data was available, consumption data was used instead because it provided
information on composition, including active ingredients. Active ingredient compound names and consumption
weights were available for the top 25 agriculturally-used pesticides and top 9 pesticides used in the Home and
Garden and the Industry/Commercial/Government categories. Since the report provides a range of consumption for
each active ingredient, the midpoint was used to represent actual consumption. Each of these compounds was
assigned a carbon content value based on stoichiometry. If the compound contained an aromatic ring(s) substituted
with chlorine or other halogens, then the compound was considered persistent and assigned a 100 percent carbon
storage factor. All other pesticides were assumed to release their carbon to the atmosphere. Nearly one-third of
total pesticide active ingredient consumption was not specified by chemical type in the Sales and Usage report (EPA
1999). This unspecified portion of the active ingredient consumption was treated as a single chemical and assigned
a carbon content and a storage factor based on the weighted average of the known chemicals' values.
Table B-8: Active Ingredient Consumption in Pesticides (Million IDS.), and Carbon Emitted and Stored (Tg C02
Eq.)
Pesticide Use
Agricultural Uses •
Non-Agricultural Uses b
Home & Garden
Industry/GovVCommercial
Other
Total
Active Ingredient
551.0
84.5
34.0
50.5
334.5
970.0
Carbon Emitted
0.1
+
+
+
0.1
0.2
Carbon Stored
0.2
+
+
+
0.1
0.4
+ Less than 0.05 TgCOjEq.
M997 estimate (EPA 1999).
"Approximate quantities, 1995/1996 estimates (EPA 1999).
Industrial and Solvent Volatile Organic Compound Emissions
Data on annual volatile organic compound (VOC) emissions were taken from the National Air Quality and
Emissions Trends Report (EPA 2000a). Volatile organic compound emissions are organized by end use category.
The categories selected to represent "Industrial VOC Emissions" were Chemical and Allied Products~, Petroleum and
Related Industries, and Other Industrial Processes. Only industrial process categories where the four fuel types
would be consumed in a non-energy end-use were included to avoid double-counting. All the VOC emissions from
solvent utilization were considered a result of petrochemical non-energy use.
Because emissions are provided in short tons of VOCs, assumptions had to be made concerning the average
carbon content of the emissions. The assumptions for calculating the carbon fraction of industrial and solvent
utilization emissions were made separately and differ slightly. For industrial VOC emissions, the carbon content
was set at 85 percent. This value was chosen to reflect the average carbon content of an average volatile
hydrocarbon based on the list of the most abundant, measured VOCs provided in the Trends Report. The list
contains only pure hydrocarbons, including saturated alkanes (carbon contents ranging from 80 to 85 percent based
upon carbon number), alkenes (carbon contents equal 85.7 percent), and some aromatics (carbon contents
approximately 90 percent, depending upon substitution).
Due to the hundreds of possible formulations for solvents, the assumptions for the carbon content of the
solvent VOCs carry a higher degree of uncertainty. Solvents were split in two categories; half of the solvents were
considered to be similar to an aromatic hydrocarbon, and the remainder was considered to be a halogenated,
unbranched hydrocarbon. Toluene (carbon content of 91 percent) was selected as the representative aromatic
compound; methylene chloride (carbon content of 14 percent) was selected to represent the halogenated compounds.
Use of these assumptions yielded an average carbon content of 53 percent.
The results of the industrial and solvent VOC emissions analysis are provided in Table B-9.
B-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table B-9:1998 Industrial and Solvent VOC Emissions
Activity
Industrial *
Solvent Utilization
VOC Emissions
(Thousand Short Tons)
1,342
5,278
Carbon
Content
85%
53%
Carbon Emitted (Tg
C02Eq.)
3.8
9.3
Includes VOC emissions from Chemical and Allied Products, Petroleum and Related Industries, and Other Industrial Processes categories.
TRI Releases
Carbon is also found in toxic substances released by industrial facilities. The Toxic Release Inventory
(TRI), maintained by the EPA, tracks these releases by chemical and environmental release medium (i.e., land, air,
or water) on a biennial basis (EPA 2000b). By examining the carbon contents and receiving media for the top 35
chemicals released, which account for 90 percent of the total mass of chemicals, the quantity of carbon stored and
emitted in the form of toxic releases can be estimated.
The TRI specifies releases by chemical, so carbon contents were assigned based on stoichiometry. The
TRI also classifies releases by disposal location as either off-site or on-site. The on-site releases are further
subdivided into air emissions, surface water discharges, underground injection, and releases to land; the latter is
further broken down to disposal in a RCRA Subtitle C (i.e., hazardous waste) landfill or to "Other On-Site Land
Disposal".5 The carbon released in each disposal location is provided in Table B-10.
Each on-site classification was assigned a storage factor. One-hundred percent storage was attributed to
Underground Injection and disposal to RCRA Landfills, while the other categories were assumed to result in an
ultimate fate of emission as CO2. The release allocation is not reported for off-site releases; therefore, the approach
was to develop a carbon-weighted average storage factor for the on-site carbon and apply it to the off-site releases.
For the remaining 10 percent of the TRI releases, the weights of all chemicals were added and an average
carbon content value, based upon the top 35 chemicals' carbon contents, was applied. The storage and emission
allocation for the remaining 10 percent of the TRI releases was carried out in the same fashion as for the 35 major
chemicals.
Table B-10:1998 TRI Releases by Disposal Location (Gg C02 Eq.)
Disposal Location
Carbon Stored
Carbon Emitted
Air Emissions
Surface Water Discharges
Underground Injection
RCRA Subtitle C Landfill Disposal
Other On-Site Land Releases
Off-site Releases
89.4
1.4
6.4
924.0
6.7
15.9
36.0
Total
97.2
982.6
- Not applicable
Uncertainty
The aggregate storage factor for petrochemical feedstocks, pentanes plus, liquefied petroleum gases, and
natural gas is based on only a partial sampling of the products derived from these fossil fuel feedstocks. The
products examined only account for 151 Tg CO2 Eq. (62 percent) of the 247 Tg CO2 Eq. consumed across these four
fuel types for non-energy uses. The remaining 96 Tg CO2 Eq. of "unaccounted-for" carbon could have a variety of
end uses, including chemical intermediates, additives (e.g., plasticizers, vulcanizing agents, food and cosmetic
additives), and paints and coatings. These uses have not been explored due to limited data availability. In the
absence of better information, the assumption was made that the products which contained the unaccounted for
5 Only the top 9 chemicals had their land releases separated into RCRA Landfills and Other Land Disposal. For the
remaining chemicals, it was assumed that the ratio of disposal in these two categories was equal to the carbon-weighted average
of the land disposal fate of the top 9 chemicals (i.e., 8 percent attributed to RCRA Landfills and 92 percent in the "Other"
category).
B-7
-------
carbon would store and emit carbon in the same ratio as the investigated products. In the case that the remaining
carbon was all stored, the aggregate storage factor (91 percent) would only change slightly to 94 percent. However,
if the other end uses were highly emissive (similar to the solvents), then the aggregate storage factor could fall as
low as 60 percent.
To a lesser extent, there are uncertainties associated with the simplifying assumptions made for each end
use category carbon estimate. Generally, the estimate for a product is subject to one or both of the following
uncertainties:
• The value used for estimating the carbon content has been assumed or assigned based upon a representative
compound.
• The split between carbon storage and emission has been assumed based on an examination of the
environmental fate of the products in each end use category.
These sources of uncertainty are discussed for each product below.
Plastics
Uncertainty in the carbon storage estimate for plastics arises from three sources. First, the production data
for acrylonitrile-butadiene-styrene, styrene-acrylonitrile, polyvinyl chloride, polypropylene, phenolic, urea,
melamine, and thermoplastic polyester resins include Canadian production and may overestimate the plastic
produced from U.S. fuels. Second, the assumed carbon content values are estimates for representative compounds,
and thus do not account for the many formulations of resins available. This uncertainty is greater for resin
categories that are generic (e.g., phenolics, other styrenics, nylon) than for resins, which have more specific
formulations (e.g., polypropylene, polyethylene). Lastly, the assumption that all of the carbon contained in plastics
is stored ignores certain end uses (e.g., adhesives and coatings) where the resin may be released to the atmosphere;
however, these end uses are likely to be small relative to use in plastics.
Rubber
Similar to plastics, uncertainty results from using consumption data for the United States and Canada,
rather than just domestic consumption. There are also uncertainties as to the assignment of carbon content values;
however, they are much smaller than in the case of plastics. There are probably fewer variations in rubber
formulations than in plastics, and the range of potential carbon content values is much narrower. Lastly, assuming
that all of the carbon contained in rubber is stored ignores the possibility of volatilization or degradation during
product lifetimes. However, the proportion of the total carbon that is released to the atmosphere during use is
probably small.
Fiber
A small degree of uncertainty arises from the assignment of carbon content values; however, the magnitude
of this uncertainty is less than that for plastics or rubber. Although there is considerable variation in final textile
products, the stock fiber formulations are standardized and proscribed explicitly by the Federal Trade Commission.
Pesticides
The largest source of uncertainty involves the assumption that a pesticide's active ingredient carbon is
either 0 or 100 percent stored. This split is a generalization of chemical behavior, based upon active-ingredient
molecular structure, not compound-specific environmental data. The mechanism by which a compound is bound or
released from soils is very complicated and can be affected by many variables, including the type of crop, the
temperature, the delivery method, and the harvesting practice. Another smaller source of uncertainty arises from the
carbon content values applied to the unaccounted for portion of active ingredient. Carbon contents vary widely
among pesticides, from 7 to 72 percent, and the remaining pesticides may have a chemical make-up that is very
different from the 32 pesticides that have been examined.
B-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
VOCs
Aside from the dichotomous split applied to solvent VOC emissions, the overall VOC emission estimates
incur uncertainty from the assumption that consumption is equivalent to emissions. Some amount of carbon storage
may actually be occurring.
TRI
The major uncertainty lies in the storage and emission assumptions. The approach for predicting
environmental fate simplifies some complex processes, and the balance between storage and emissions is very
sensitive to the assumptions on fate. Extrapolating from known to unknown characteristics also introduces
uncertainty. The two extrapolations with the greatest uncertainty are: 1) that the release media and fate of the off-
site releases were assumed to be the same as for on-site releases, and 2) that the carbon content of the least frequent
10 percent of TRI releases was assumed to be the same as for the chemicals comprising 90 percent of the releases.
However, the contribution of these chemicals to the overall estimate is small. The off-site releases only
account for 3 percent of the total releases, by weight, and, by definition, the less frequent compounds only account
for 10 percent of the total releases.
Asphalt
Asphalt is one of the principal non-energy uses of fossil fuels. The term "asphalt" generally refers to a
mixture of asphalt cement and a rock material aggregate, a volatile petroleum distillate, or water. For the purposes
of this analysis, "asphalt" is used interchangeably with asphalt cement, a residue of crude oil. According to EIA
(2000), approximately 100 Tg CO2 Eq. has been used in the production of asphalt cement annually. Though minor
amounts of carbon are emitted during production, asphalt has an overall carbon storage factor of almost 100 percent.
Paving is the primary application of asphalt cement, comprising 86 percent of production. The three types
of asphalt paving produced in the United States are hot mix asphalt (HMA), cut-backs, and emulsified asphalt.
HMA, which makes up 90 percent of total asphalt paving (EPA 2000c), contains asphalt cement mixed with an.
aggregate of rock materials. Cut-back asphalt is composed of asphalt cement thinned with a volatile petroleum
distillate (e.g., naptha). Emulsified asphalt contains only asphalt cement and water. Roofing products are the other
significant end use of asphalt cement, accounting for approximately 14 percent of U.S. production (Kelly 2000). No
data were available on the fate of carbon in asphalt roofing; it was assumed that it has the same fate as carbon in
asphalt paving applications.
Methodology
A carbon storage factor was calculated for each type of asphalt paving. The fraction of carbon emitted by
each asphalt type was multiplied by consumption data for asphalt paving (EPA 2000c, EUP 1998) to come up with a
weighted average carbon storage factor for asphalt as a whole.
The fraction of carbon emitted by HMA was determined by first calculating the organic emissions (volatile
organic compounds [VOCs], carbon monoxide, polycyclic aromatic hydrocarbons [PAHs], hazardous air pollutants
[HAPs], and phenol) from HMA paving, using emission factors reported by the EPA (EPA 2000c) and total HMA
production.6 The next step was to estimate the carbon content of the organic emissions. This calculation was based
on stoichiometry for carbon monoxide (CO) and phenol, and an assumption of 85 percent carbon content for PAHs
and HAPs. The carbon content of asphalt paving is a function of the proportion of asphalt cement in asphalt paving,
and the proportion of carbon in asphalt cement. For the former factor, a 5 percent asphalt cement content was
assumed based on personal communication with an expert from the National Asphalt Paving Association (Connolly
2000). For the latter factor, all paving types were characterized as having a mass fraction of 85 percent carbon in
asphalt cement, based on the assumption that asphalt is primarily composed of saturated paraffinic hydrocarbons. By
combining these estimates, the result is that over 99.99 percent of the carbon in asphalt cement was retained (i.e.,
stored), and less than 0.01 percent was emitted;
6 The emission factors are expressed as a function of asphalt paving tonnage (i.e., including the rock aggregate as well
as the asphalt cement).
B-9
-------
Cut-back asphalt is produced in three forms (i.e., rapid, medium and slow cure). All three forms emit
carbon only from the volatile petroleum distillate used to thin the asphalt cement (EPA 1995). Because the
petroleum distillates are not included in the EIA statistics for asphalt, the storage factor for cut-back is assumed to
be 100 percent.
It was also assumed that there was no loss of carbon from emulsified asphalt (i.e., the storage factor is 100
percent) based on personal communication with an expert from Akzo Nobel Coatings, Inc. (James 2000).
Data Sources
Data on asphalt and road oil consumption and carbon content factors were supplied by the Energy
Information Administration (EIA) of the U.S. Department of Energy (DOE). Hot mix asphalt production and
emissions factors were obtained from "Hot Mix Asphalt Plants Emissions Assessment Report" from the EPA
publication AP-42 (EPA 2000c). The asphalt cement content of HMA was provided by Una Connolly of National
Asphalt Paving Association (Connolly 2000). The consumption data for cut-back and emulsified asphalts were
taken from a Moulthrop, et al. study used as guidance for estimating air pollutant emissions from paving processes
(EUP 1998). "Asphalt Paving Operation" AP-42 (EPA 1995) provided the emissions source information used in the
calculation of the carbon storage factor for cut-back asphalt. The storage factor for emulsified asphalt was provided
by Alan James of Akzo Nobel Coatings, Inc. (James 2000).
Uncertainty
The principal source of uncertainty is that the available data are from short-term studies of emissions
associated with the production and application of asphalt. As a practical matter, the cement in asphalt deteriorates
over time, contributing to the need for periodic re-paving. Whether this deterioration is due to physical erosion of
the cement and continued storage of carbon in a refractory form or physicochemical degradation and eventual
release of CO2 is uncertain. Long-term studies may reveal higher lifetime emissions rates associated with
degradation.
Many of the values used in the analysis are also uncertain and are based on estimates and professional
judgement. For example, the asphalt cement input for HMA was based on expert advice indicating that the range is
variable—from about 3 to 5 percent—with actual content based on climate and geographical factors (Connolly
2000). Over this range, the effect on the calculated carbon storage factor is minimal (on the order of 0.1 percent).
Similarly, changes in the assumed carbon content of asphalt cement would have only a minor effect.
The consumption figures for cut-back and emulsified asphalts are based on information reported for 1994.
More recent trends indicate a decrease in cut-back use due to high VOC emission levels and a related increase in
emulsified asphalt use as a substitute. However, because the carbon storage factor of each is 100 percent, use of
more recent data would not affect the overall result.
Lubricants
Lubricants are used in industrial and transportation applications. They can be subdivided into oils and
greases, which differ in terms of physical characteristics (e.g., viscosity), commercial applications, and
environmental fate. According to EIA (2000), the carbon content of U.S. production of lubricants in 1999 was
approximately 28 Tg COi Eq. Based on apportioning oils and greases to various environmental fates, and
characterizing those fates as resulting in either long-term storage or emissions, the overall carbon storage factor was
estimated to be 9 percent; thus, storage in 1999 was about 3 Tg CO2 Eq.
Methodology
For each lubricant category, a storage factor was derived by identifying disposal fates and applying
assumptions as to the disposition of the carbon for each practice. An overall lubricant carbon storage factor was
calculated by talcing a production weighted average of the oil and grease storage factors.
B-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Oils
Regulation of used oil in the United States has changed dramatically over the past 15 years.7 The effect of
these regulations and policies has been to restrict landfilling and dumping, and to encourage collection of used oil.
Given the relatively inexpensive price of crude oil, the economics have not favored re-refining—instead, most of the
used oil that has been collected has been combusted.
Table B-l 1 provides an estimated allocation of the fates of lubricant oils, along with an estimate of the
proportion of carbon stored in each fate. The ultimate fate of the majority of oils (about 84 percent) is combustion,
either during initial use or after collection as used oil. Combustion results in 99 percent oxidation to CO2, with
correspondingly little long-term storage of carbon in the form of ash. Dumping onto the ground or into" storm
sewers, primarily by "do-it-yourselfers" who change their own oil, is another fate that results in conversion to CO2
given that the releases are generally small and most of the oil is biodegraded. In the landfill environment, which
tends to be anaerobic, at least for municipal landfills, it is assumed that 90 percent of the oil persists in an
undegraded form. Re-refining adds a recycling loop to the fate of oil; it was assumed that about 97 percent of the
carbon in re-refined oil is ultimately oxidized. Because of the dominance of fates that result in eventual release as
CC>2, only about 3 percent of the carbon in oil lubricants goes into long-term storage.
Table B-11: Commercial and Environmental Fate of Oil Lubricants (Percent)
Fate of Oil
Combusted During Use
Not Combusted During Use
Combusted as Used Oil *
Dumped on the ground or in storm sewers
Landfilled
Re-refined into lube oil base stock and other products
Weighted Average
Portion of Total
Oil
20
80
64
6
2
8
-
Carbon Stored
1
1
0
90
3
2.9
* (e.g., in boilers or space heaters)
- Not applicable
Greases
Table B-l2 provides analgous estimates for lubricant greases. Unlike oils, grease is generally not
combusted during use, and combustion for energy recovery and re-refining are thought to be negligible. Although
little is known about the fate of waste grease, it was assumed that 90 percent of the non-combusted portion is
landfilled, and the remainder is dumped onto the ground or storm sewers. Because much of the waste grease will be
in containers that render it relatively inaccessible to biodegradation, it was assumed that 90 percent and 50 percent
of the carbon in landfilled and dumped grease, respectively, would be stored. The overall storage factor is 82
percent for grease.
Table B-12: Commercial and Environmental Fate of Grease Lubricants (Percent)
Fate of Grease
Combusted During Use
Not Combusted During Use
Landfilled
Dumped on the ground or in storm sewers
Total Grease
Carbon Stored
Weighted Average
5
95
85.5
9.5
1
90
50
81.8
- Not applicable
Having derived separate storage factors for oil and grease, the last step was to estimate the weighted
average for lubricants as a whole. No data were found apportioning the mass of lubricants into these two categories,
but the U.S. Census Bureau does maintain records of the value of production of lubricating oils and lubricating
7 For example, the U.S. EPA "RCRA (Resource Conservation and Recovery Act) On-line" web site
(http://www.epa.gov/rcraonline/) has over 50 entries on used oil regulation and policy for 1994 through 2000.
B-11
-------
greases. Assuming that the mass of lubricants can be allocated according to the proportion of value of production
(92 percent oil, 8 percent grease), applying these weights to the storage factors for oils and greases (3 percent and 82
percent) yields an overall storage factor of 9 percent.
Data Sources
The estimate of the volume of lubricants produced annually is based on statistics provided by El A (2000),
which conducts surveys of the oil and grease consumption.
The characterization of fate is based primarily on professional judgement of an EPA regulatory analyst with
experience in used oil (Rinehart 2000). For the proportions combusted, one percent was assumed to remain un-
oxidized in combustion processes (EIIP 1999); for other fates, estimates are based on professional judgement. The
assumption that landfilled oil and grease results in 90 percent storage is based on analogy with the persistence of
petroleum in native petroleum-bearing strata, which are both essentially anaerobic. The assumption that oil dumped
on the ground or in storm sewers is completely degraded is based on the observation that landfarming—application
to soil—is one of the most frequently used methods for degrading refinery wastes. The lower degradation rate for
grease is based on the observation that greases contain longer chain paraffins, which are more persistent. Re-refined
oil was assumed to have a storage factor equal to the weighted average for the other fates (i.e., after re-refining, the
oil would have the same probability of combustion, landfilling, or dumping as virgin oil).
Information on the value of production for oils and greases was obtained from reports by the U.S. Census
Bureau (1999).
Uncertainty
The principal sources of uncertainty are the estimates of the commercial use, post-use, and environmental
fate of lubricants, which, as noted above, are largely based on assumptions and judgement. There is no
comprehensive system to track used oil and greases, which makes it difficult to develop a verifiable estimate of the
commercial fates of oil and grease. The environmental fate estimates for percent of carbon stored are somewhat less
uncertain, but also introduce uncertainty in the estimate.
The assumption that the mass of oil and grease can be divided according to their value also introduces
uncertainty. Given the rather large difference between the storage factors for oil and grease, changes in their share
of total lubricant production has a fairly large effect on the weighted storage factor.
B-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
ANNEX C
Methodology for Estimating Emissions of CH4, N20, and Criteria Pollutants from
Stationary Combustion
Estimates of CH4 and N20 Emissions
Methane (CKU) and nitrous oxide (N2O) emissions from stationary combustion were estimated using IPCC
emission factors and methods. Estimates were obtained by multiplying emission factors—by sector and fuel type—
by fossil fuel and wood consumption data. This "top-down" methodology is characterized by two basic steps,
described below. Data are presented in Table C-l through Table C-5.
Step 1: Determine Energy Consumption by Sector and Fuel Type
Greenhouse gas emissions from stationary combustion activities were grouped into four sectors: industrial,
commercial/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 Annual Energy
Review (2000a), and adjusted from higher to lower heating values assuming a 10 percent reduction for natural gas
and a 5 percent reduction for coal and petroleum fuels. Table C-l provides annual energy consumption data for the
years 1990 through 1999.
Step 2: Determine the Amount of CH4 and N20 Emitted
Activity data for each sector and fuel type were then multiplied by emission factors to obtain emissions
estimates. Emission factors were taken from the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).
Table C-2 provides emission factors used for each sector and fuel type.
Estimates of NOX, CO, and NMVOC Emissions
For criteria pollutants, the major source categories included were those identified in EPA (2000): coal, fuel
oil, natural gas, wood, other fuels (i.e., bagasse, liquefied petroleum gases, coke, coke oven gas, and others), and
stationary internal combustion, which includes emissions from internal combustion engines not used in
transportation. The EPA (2000) 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. The EPA (2000) 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 hi conjunction with emission
factors that relate the quantity of emissions to the activity.
Table C-3 through Table C-5 present criteria pollutant emission estimates for 1990 through 1999.
The basic calculation procedure for most source categories presented in EPA (2000) is represented by the
following equation:
where,
Ep>s = As X EFP>S X (1 - Cp>s/100)
E = emissions
p = pollutant
s = source category
A = activity level
EF = emission factor
C = percent control efficiency
C-1
-------
The EPA currently derives the overall emission control efficiency of a category from a variety of sources,
including published reports, the 1985 National Acid Precipitation and Assessment Program (NAPAP) emissions
inventory, and other EPA databases. The U.S. approach for estimating emissions of NOX, CO, and NMVOCs from
stationary combustion as described above is similar to the methodology recommended by the IPCC
(IPCC/UNEP/OECD/IEA 1997).
Table C-1: Fuel Consumption by Stationary Combustion for Calculating CH4 and N20 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
1995
20,010
53
80
2,886
16,990
11,359
1,361
715
8,624
658
21,444
4,984
3,117
10,090
3,253
2,418
596
45
1,771
7
1996
20,901
54
82
2,812
17,953
12,026
1,457
741
9,103
725
21,843
5,390
3,250
10,428
2,774
2,465
595
49
1,813
8
1997
21,473
58
87
2,827
18,501
12,274
1,432
705
9,315
822
21,889
5,125
3,310
10,432
3,023
2,348
433
47
1,860
8
1998
21,576
44
66
2,812
18,654
12,291
1,311
662
9,152
1,166
21,250
4,669
3,098
10,152
3,330
2,346
377
47
1,914
7
1999
21,548
44
66
3,126
18,311
12,584
1,383
701
9,557
943
21,362
4,830
3,153
10,197
3,182
2,832
404
57
2,364
7
Note: Totals may not sum due to independent rounding.
Table C-2: CH4 and N20
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
Emission Factors by Fuel Type
CH4 N20
300 1.4
10 1.4
10 1.4
1 1.4
10 0.6
10 0.6
2 0.6
3 0.6
5 0.1
5 0.1
5 0.1
1 0.1
300 4.0
300 4.0
30 4.0
30 4.0
and Sector (g/GJ)1
[ GJ (Gigajoule) = 109 joules. One joule = 9.486x10"4 Btu
C-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table C-3: NO, Emissions from Stationary Combustion (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
Coal"
Fuel Oil"
Natural Gasb
Wood
Other Fuels3
Total
1990
6,045
5,119
200
513
NA
213
2,754
530
240
1,072
NA
119
792
336
36
88
181
NA
31
749
NA
NA
NA
42
708
9,884
1991
5,914
5,043
192
526
NA
152
2,703
517
215
1,134
NA
117
720
333
33
80
191
NA
29
829
NA
NA
NA
45
784
9,779
1992
5,901
5,062
154
526
NA
159
2,786
521
222
1,180
NA
115
748
348
35
84
204
NA
25
879
NA
NA
NA
48
831
9,914
1993
6,034
5,211
163
500
NA
160
2,859
534
222
1,207
NA
113
783
360
37
84
211
NA
28
827
NA
NA
NA
40
787
10,080
1994
5,956
5,113
148
536
NA
159
2,855
546
219
1,210
NA
113
767
365
36
86
215
NA
28
817
NA
NA
NA
40
777
9,993
1995
5,792
5,061
87
510
NA
134
2,852
541
224
1,202
NA
111
774
365
35
94
210
NA
27
813
NA
NA
NA
44
769
9,822
1996
5,566
5,057
107
259
NA
143
2,864
493
204
1,093
NA
109
965
367
31
87
224
NA
24
745
NA
NA
NA
46
699
9,541
1997
5,691
5,120
132
289
NA
150
2,814
487
196
1,079
NA
104
948
374
32
88
229
NA
25
710
NA
NA
NA
39
671
9,589
1998
5,628
4,932
202
346
NA
149
2,768
475
190
1,066
NA
104
933
353
34
73
220
NA
26
659
NA
NA
NA
34
624
9,408
1999
5,161
4,477
183
349
NA
152
2,844
492
194
1,090
NA
107
961
373
34
73
241
NA
25
692
NA
NA
NA
36
656
9,070
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 1999).
"Other Fuels" category (EPA 1999).
C-3
-------
Table C-4: CO Emissions from Stationary Combustion (Gg)
Sector/Fuel Type
Electric Utilities
Coal
Fuel Oil
Natural Gas
Wood
Internal Combustion
Industrial
Coal
Fuel Oil
Natural Gas
Wood
Other Fuels'
Internal Combustion
Commercial/Institutional
Coal
Fuel Oil
Natural Gas
Wood
Other Fuels'
Residential
Coal"
Fuel Oil"
Natural Gasb
Wood
Other Fuels'
Total
1990
329
213
18
46
NA
52
798
95
67
205
NA
253
177
205
13
16
40
NA
136
3,668
NA
NA
NA
3,430
238
4,999
1991
317
212
17
46
NA
41
835
92
54
257
NA
242
189
196
13
16
40
NA
128
3,965
NA
NA
NA
3,711
255
5,313
1992
318
214
14
47
NA
43
867
92
58
272
NA
239
205
204
13
16
46
NA
128
4,195
NA
NA
NA
3,930
265
5,583
1993
329
224
15
45
NA
46
946
92
60
292
NA
259
243
207
14
16
48
NA
129
3,586
NA
NA
NA
3,337
249
5,068
1994
335
224
13
48
NA
50
944
91
60
306
NA
260
228
212
13
16
49
NA
134
3,515
NA
NA
NA
3,272
243
5,007
1995
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
5,383
1996
363
228
11
72
NA
53
1,080
100
49
308
NA
317
306
130
13
17
58
NA
42
4,048
NA
NA
NA
3,817
231
5,620
1997
376
233
13
76
NA
54
1,055
99
47
308
NA
302
299
133
13
18
59
NA
44
3,403
NA
NA
NA
3,174
229
4,968
1998
379
220
17
88
NA
54
1,044
96
46
305
NA
303
294
130
14
15
57
NA
44
3,022
NA
NA
NA
2,802
220
4,575
1999
374
217
16
85
NA
55
1,069
99
47
310
NA
309
303
136
14
15
63
NA
45
3,220
NA
NA
NA
2,994
226
4,798
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 1999).
Other Fuels" category (EPA 1999).
C-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table C-5: NMVOC Emissions from Stationary Combustion (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 Fuels'
Residential
Coa!"
Fuel Oil"
Natural Gas"
Wood
Other Fuels3
Total
1990
43
25
5
2
IMA
11
165
7
11
52
NA
46
49
18
1
3
7
NA
8
686
NA
NA
NA
651
35
912
1991
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
1992
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
1,011
1993
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
1994
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
898
1995
40
26
2
2
NA
9
187
5
11
66
NA
45
59
21
1
3
10
NA
8
726
NA
NA
NA
689
37
973
1996
44
25
3
7
NA
9
162
6
8
54
NA
32
63
24
1
3
13
NA
8
739
NA
NA
NA
707
33
971
1997
47
26
4
7
NA
10
160
6
7
54
NA
31
62
24
1
3
13
NA
8
617
NA
NA
NA
585
32
848
1998
50
26
5
9
NA
10
159
6
7
54
NA
31
61
24
1
3
12
NA
8
546
NA
NA
NA
516
30
778
1999
49
26
5
8
NA
10
162
6
7
54
NA
32
63
26
1
3
14
NA
9
582
NA
NA
NA
552
31
n?n
v /
a "Other Fuels" include LPG, waste oil, coke oven gas, coke,
" 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 1999).
"Other Fuels" category (EPA 1999).
C-5
-------
C-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
ANNEX D
Methodology for Estimating Emissions of CH4, N2Q, and Criteria Pollutants from
Mobile Combustion
Estimates of CH4 and N20 Emissions
Greenhouse gas emissions from mobile combustion are reported by transport mode (e.g., road, rail, air, and
water), vehicle type, and fuel type. The EPA does not systematically track emissions of CH, and N2O as in EPA
(2000b); therefore, estimates of these gases were developed using a methodology similar to that outlined in the
Revised 1996IPCC 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 from the
Federal Highway Administration's (FHWA) Highway Performance Monitoring System database, as noted in EPA
(2000b).
National VMT data for gasoline and diesel highway vehicles are presented in Table D-l and Table D-2
respectively. Total VMT for each highway category (i.e., gasoline passenger cars, light-duty gasoline trucks, heavy-
duty gasoline vehicles, diesel passenger cars, light-duty diesel trucks, heavy-duty diesel vehicles, and motorcycles)
were distributed across 25 model years based on the VMT distribution by vehicle age shown in Table D-5. This
distribution was derived by weighting the temporally fixed age distribution of the U.S. vehicle fleet according to
vehicle registrations (Table D-3) by the average annual age-specific vehicle mileage accumulation of U.S. vehicles
(Table D-4), which were both obtained from EPA's Mobile6 model (EPA 2000a).
Activity data for gasoline passenger cars and light-duty trucks in California were developed separately due
to the different emission control technologies deployed in that state relative to the rest of the country. Unlike the
rest of the United States, beginning in model year 1994, a fraction of the computed California VMT for gasoline
passenger cars and light-duty trucks was attributed to low emission vehicles (LEVs). LEVs have not yet been
widely deployed in other states. Based upon U.S. Department of Transportation statistics for 1994, it was assumed
that 8.7 percent of national VMT occurred in California, and this value was used for the entire time series.
Activity data for non-highway vehicles were based on annual fuel consumption statistics by transportation
mode and fuel type. Consumption data for distillate and residual fuel oil by ships and boats (i.e., vessel bunkering),
construction equipment, farm equipment, and locomotives were obtained from EIA (2000b). In the case of ships
and boats, the EIA (2000b) vessel bunkering data was reduced by the amount of fuel used for international bunkers.1
Data on the consumption of jet fuel in aircraft were obtained directly from DOT/BTS, as described under CC>2 from
Fossil Fuel Combustion, and were reduced by the amount allocated to international bunker fuels. Data on aviation
gasoline consumed in aircraft were taken from FAA (2000). Data on the consumption of motor gasoline by ships
and boats, construction equipment, farm equipment, and locomotives data were drawn from FHWA (1999). For
these vehicles, 1998 fuel consumption data were used as a proxy because 1999 data were unavailable. The activity
data used for non-highway vehicles are included in Table D-6.
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 D-7, Table D-8, Table D-9, Table D-10, and Table D-ll. Again, California
gasoline-fueled passenger cars and light-duty tracks were treated separately due to that state's distinct vehicle
1 See International Bunker Fuels section of the Energy Chapter.
D-1
-------
emission standards—including the introduction of Low Emission Vehicles (LEVs) in 1994—compared with the rest
of the United States. The categories "Tier 0" and "Tier 1" were 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).
Step 3: Determine the Amount of CH4 and N20 Emitted by Vehicle, Fuel, and Control Technology Type
Emissions of CHU and N2O from highway vehicles were calculated by multiplying emission factors in
IPCC/UNEP/OECD/IEA (1997) by the VMT for each highway category each year as described in Step 1 (see Table
D-12). The emission factors for highway sources were derived from the EPA's MOBILESa mobile source
emissions model (EPA 1997). The MOBILESa model uses information on ambient temperature, diurnal
temperature range, altitude, vehicle speeds, national vehicle registration distributions, gasoline volatility, emission
control technologies, fuel composition, and the presence or absence of vehicle inspection/maintenance programs in
order to produce these factors. Emissions of CHt and N2O from non-highway vehicles 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 and Table D-13).
Emissions of N2O—in contrast to CHU, CO, NOX, and NMVOCs—have not been extensively studied and
are currently not well characterized. The limited number of studies that have been performed on highway vehicle
emissions of N2O have shown that emissions are generally greater from vehicles with catalytic converter systems
than those without such controls, and greater from aged than from new catalysts. These systems control tailpipe
emissions of NOX (i.e., NO and NO2) by catalytically reducing NOX to N2. Suboptimal catalyst performance, caused
by as yet poorly understood factors, results in incomplete reduction and the conversion of some NOX to N2O rather
than to N2. Fortunately, newer vehicles with catalyst and engine designs meeting the more recent Tier 1 and LEV
standards have shown reduced emission rates of both NOX and N2O compared with earlier catalyst designs.
In order to better characterize the process by which N2O is formed by catalytic controls and to develop a
more accurate national emission estimate, the EPA's Office of Transportation and Air Quality—at its National
Vehicle and Fuel Emissions Laboratory (NVFEL)—conducted a series of tests in order to measure emission rates of
N2O from used Tier 1 and LEV gasoline-fueled passenger cars and light-duty trucks equipped with catalytic
converters. These tests and a review of the literature were used to develop the emission factors for N2O (EPA
1998). The following references were used in developing the N2O emission factors for gasoline-fueled highway
passenger cars presented in Table D-12:
• LEVs. Tests performed at NVFEL (EPA 1998)2
• Tier 1. Tests performed at NVFEL (EPA 1998)
• Tier 0. Smith and Carey (1982), Barton and Simpson (1994), and one car tested at NVFEL (EPA 1998)
• Oxidation Catalyst. Smith and Carey (1982), Urban and Garbe (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 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) as a proxy for fuel economy (see Table D-12).
Data from the literature and tests performed at NVFEL support the conclusion that light-duty trucks have higher
emission rates than passenger cars. However, the use of fuel-consumption ratios to determine emission factors is
considered a temporary measure only, to be replaced as soon as real data are available.
2 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 fiiel (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.
D-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
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 1996 IPCC 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 1996 IPCC Guidelines were used for non-highway
vehicles.
Compared to regulated tailpipe emissions, there is relatively little data available to estimate emission
factors for N2O. Nitrous oxide is not a regulated 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
The emission estimates of NOX, CO, and NMVOCs for mobile combustion were taken directly from the
EPA's National Air Pollutant Emissions Trends, 1900 - 1999 (EPA 2000b). This EPA report provides emission
estimates for these gases by sector and fuel type using a "top down" estimating procedure whereby emissions were
calculated using basic activity data, such as amount of fuel delivered or miles traveled, as indicators of emissions.
Table D-14 through Table D-16 provide complete emissions estimates for 1990 through 1999.
Table D-1: Vehicle Miles Traveled for Gasoline Highway Vehicles (109 Miles)
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Passenger
Cars3
1,268.2
1,223.0
1,235.4
1,238.5
1,266.9
1,295.3
1,328.8
1,367.8
1,407.4
1,434.9
Light-Duty Heavy-Duty Passenger Cars Light-Duty
Trucks8 Vehicles Motorcycles (CA)b Trucks (CA)b
520.3
588.0
640.1
675.3
692.4
715.4
660.9
696.3
711.6
725.5
42.1
42.9
43.7
46.0
49.6
50.8
82.4
82.7
80.7
82.3
9.6
9.3
9.4
9.4
9.6
9.8
9.9
10.1
10.3
10.5
120.8
116.5
117.7
118.0
120.7
123.4
126.6
130.3
134.1
136.7
49.6
56.0
61.0
64.3
66.0
68.2
63.0
66.3
67.8
69.1
" 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 (2000b).
Table D-2: Vehicle Miles Traveled for Diesel Highway Vehicles {TO9 Miles)
Year Passenger Light-Duty Heavy-Duty
Cars
Trucks
Vehicles
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
19.2
18.5
18.7
18.7
19.1
19.6
8.1
6.6
5.3
5.4
4.7
5.3
5.8
6.1
6.3
6.5
4.4
3.9
3.6
3.6
109.9
112.4
115.5
120.0
127.0
133.8
191.0
201.2
206.2
210.5
Source: VMT data are the same as those used in EPA (2000b).
D-3
-------
Table D-3: Age Distribution by Vehicle/Fuel Type for Highway Vehicles
Vehicle Age
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
LDGV
5.3%
7.1%
7.1%
7.1%
7.0%
7.0%
6.9%
6.8%
6.6%
6.3%
5.9%
5.4%
4.6%
3.6%
2.9%
2.3%
1.8%
1.4%
1.1%
0.9%
0.7%
0.6%
0.4%
0.4%
1.0%
LDGT
5.8%
7.6%
7.5%
7.3%
7.1%
6.8%
6.5%
6.1%
5.7%
5.2%
4.7%
4.2%
3.6%
3.1%
2.6%
2.2%
1.8%
1.4%
1.2%
1.1%
1.1%
1.0%
1.0%
0.9%
4.6%
HDGV
4.9%
8.9%
8.1%
7.4%
6.8%
6.2%
5.6%
5.1%
4.7%
4.3%
3.9%
3.6%
3.3%
3.0%
2.7%
2.5%
2.3%
2.1%
1.9%
1.7%
1.6%
1.5%
1.3%
1.2%
5.4%
LDDV
5.3%
7.1%
7.1%
7.1%
7.0%
7.0%
6.9%
6.8%
6.6%
6.3%
5.9%
5.4%
4.6%
3.6%
2.9%
2.3%
1.8%
1.4%
1.1%
0.9%
0.7%
0.6%
0.4%
0.4%
1.0%
LDDT
5.9%
7.4%
6.9%
6.4%
6.0%
5.6%
5.2%
4.8%
4.5%
4.2%
3.9%
3.6%
3.4%
3.2%
2.9%
2.7%
2.5%
2.4%
2.2%
2.1%
1.9%
1.8%
1.7%
1.6%
7.3%
HDDV
4.2%
7.8%
7.2%
6.7%
6.2%
5.8%
5.3%
5.0%
4.6%
4.3%
4.0%
3.7%
3.4%
3.2%
2.9%
2.7%
2.5%
2.4%
2.2%
2.0%
1.9%
1.8%
1.6%
1.5%
7.2%
MC
14.4%
16.8%
13.5%
10.9%
8.8%
7.0%
5.6%
4.5%
3.6%
2.9%
2.3%
9.7%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
LDGV (gasoline passenger cars, also referred to as light-duty gas vehicles)
LD6T (light-duty gas trucks)
HDGV (heavy-duty gas vehicles)
LDDV (diesel passenger cars, also referred to as light-duty diesel vehicles)
LDDT (light-duty diesel trucks)
HOOV (heavy-duty diesel vehicles)
MC (motorcycles)
Note: Based on vehicle registrations.
D-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table D-4: Annual Age-specific Vehicle Mileage Accumulation of U.S. Vehicles (Miles)
Vehicle Age
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Table D-5: 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
14,910
14,174
13,475
12,810
12,178
11,577
11,006
10,463
9,947
9,456
8,989
8,546
8,124
7,723
7,342
6,980
6,636
6,308
5,997
5,701
5,420
5,152
4,898
4,656
4,427
LDGT
19,906
18,707
17,559
16,462
15,413
14,411
13,454
12,541
11,671
10,843
10,055
9,306
8,597
7,925
7,290
6,690
6,127
5,598
5,103
4,642
4,214
3,818
3,455
3,123
2,822
HDGV
20,218
18,935
17,100
16,611
15,560
14,576
13,655
12,793
11,987
11,231
10,524
9,863
9,243
8,662
8,028
7,610
7,133
6,687
6,269
5,877
5,510
5,166
4,844
4,542
4,259
Distribution by Vehicle Age
LDGV
7.51%
9.52%
9.05%
8.59%
8.14%
7.68%
7.22%
6.72%
6.20%
5.64%
5.03%
4.38%
3.54%
2.67%
2.01%
1.52%
1.14%
0.86%
0.65%
0.49%
0.37%
0.28%
0.21%
0.16%
0.43%
LDGT
9.41%
11.56%
10.62%
9.70%
8.80%
7.92%
7.04%
6.19%
5.36%
4.57%
3.82%
3.14%
2.52%
1.99%
1.54%
1.16%
0.87%
0.64%
0.50%
0.43%
0.37%
0.32%
0.27%
0.23%
1.04%
HDGV
7.89%
13.48%
11.11%
9.85%
8.43%
7.21%
6.16%
5.27%
4.51%
3.86%
3.31%
2.83%
2.42%
2.07%
1.76%
1.52%
1.30%
1.12%
0.96%
0.82%
0.70%
0.60%
0.52%
0.44%
1.85%
LDDV
14,910
14,174
13,475
12,810
12,178
11,577
11,006
10,463
9,947
9,456
8,989
8,546
8,124
7,723
7,342
6,980
6,636
6,308
5,997
5,701
5,420
5,152
4,898
4,656
4,427
LDDT
26,371
24,137
22,095
20,228
18,521
16,960
15,533
14,227
13,032
11,939
10,939
10,024
9,186
8,420
7,718
7,075
6,487
5,948
5,454
5,002
4,588
4,209
3,861
3,542
3,250
and Vehicle/Fuel
LDDV
7.51%
9.52%
9.05%
8.59%
8.14%
7.68%
7.22%
6.72%
6.20%
5.64%
5.03%
4.38%
3.54%
2.67%
2.01%
1.52%
1.14%
0.86%
0.65%
0.49%
0.37%
0.28%
0.21%
0.16%
0.43%
LDDT
11.50%
13.07%
11.15%
9.51%
8.11%
6.92%
5.90%
5.04%
4.30%
3.67%
3.13%
2.67%
2.28%
1.95%
1.66%
1.42%
1.21%
1.04%
0.89%
0.76%
0.65%
0.55%
0.47%
0.40%
1.75%
HDDV
28,787
26,304
24,038
21,968
20,078
18,351
16,775
15,334
14,019
12,817
11,719
10,716
9,799
8,962
8,196
7,497
6,857
6,273
5,739
5,250
4,804
4,396
4,023
3,681
3,369
Type
HDDV
8.27%
14.00%
11.86%
10.05%
8.52%
7.22%
6.13%
5.20%
4.41%
3.74%
3.18%
2.70%
2.29%
1.94%
1.65%
1.40%
1.19%
1.01%
0.86%
0.73%
0.62%
0.53%
0.45%
0.38%
1.65%
NIC
4,786
4,475
4,164
3,853
3,543
3,232
2,921
2,611
2,300
1,989
1,678
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
1,368
MC
19.39%
21.15%
15.82%
11.82%
8.77%
6.37%
4.60%
3.31%
2.33%
1.62%
1.09%
3.73%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
Note: Estimated by weighting data in Table D-3 by data in Table D-4.
D-5
-------
Table D-6: Fuel Consumption for Non-Highway Vehicles by Fuel Type (U.S. Gallons)
Vehicle Type/Year
Aircraft'
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Ships and Boats6
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Construction Equipment'
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Farm Equipment'
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Locomotives
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Residual
-
-
-
-
-
-
-
-
-
.
1,521,437,386
1,486,167,178
2,347,064,583
2,758,924,466
2,499,868,472
2,994,692,916
2,286,349,693
1,011,486,526
730,817,822
2,391,245,568
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
25,422
6,845
8,343
4,065
5,956
6,498
9,309
3,431
2,587
3,540
Diesel
-
-
-
-
-
-
-
.
-
-
1,697,600,270
1,693,361,391
1,706,143,771
1,546,310,902
1,630,092,618
1,518,608,116
1,839,335,006
1,801,798,270
1,613,162,288
1,871,478,578
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
2,385,236,000
2,432,182,000
2,409,231,000
3,164,200,000
3,144,200,000
3,274,811,000
3,077,122,000
3,062,436,000
3,093,224,000
3,225,029,000
3,206,359,000
2,965,006,000
2,805,157,000
3,210,111,000
3,026,292,000
3,217,231,000
2,906,998,000
3,063,441,000
3,191,023,000
3,266,861,000
3,067,400,000
2,833,276,000
2,789,926,000
Jet Fuel
18,265,975,286
17,496,936,548
17,269,984,984
17,414,327,932
18,269,315,288
17,809,152,465
18,749,831,246
18,603,782,852
19,060,116,911
19,206,444,324
-
-
-
-
-
-
-
-
-
-
-
-
-
-
.
-
-
-
-
-
-
-
-
-
-
-
-
_
-
-
-
-
-
-
-
-
-
-
-
-
Other
374,216,115
347,126,395
341,582,453
319,448,684
317,306,704
329,318,581
310,796,773
330,284,570
295,344,794
325,912,623
1,300,400,000
1,709,700,000
1,316,170,000
873,687,000
896,700,000
1,060,394,000
993,671,000
987,193,000
956,232,000
956,232,001
1,523,600,000
1,384,900,000
1,492,200,000
1,270,386,667
1,312,161,667
1,351,642,667
1,365,550,667
1,397,748,667
1,373,933,667
1,199,593,667
812,800,000
776,200,000
805,500,000
845,320,000
911,996,000
926,732,000
918,085,000
984,450,000
906,941,000
702,700,000
-
-
-
-
-
-
-
-
-
-
- Not applicable
9 Other fuel Is aviation gasoline.
b Other fuel Is motor gasoline.
e Construction Equipment includes snowmobiles. Other fuel is motor gasoline.
D-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table D-7: Control Technology Assignments for Gasoline Passenger Cars (Percent of VMT)*
Model Years
1973-1974
1975
1976-1977
1978-1979
1980
1981
1982
1983
1984-1993
1994
1995
1996-1999
Non-catalyst
100%
20%
15%
10%
5%
-
-
-
-
-
-
-
Oxidation
-
80%
85%
90%
88%
15%
14%
12%
-
-
-
-
TierO
.
-
.
.
7%
85%
86%
88%
100%
60%
20%
-
Tier 1
.
-
.
•
.
.
.
.
.
40% '
80%
100%
* Excluding California VMT
- Not applicable
Table D-8: Control Technology Assignments
Model Years
1973-1974
1975
1976
1977-1978
1979-1980
1981
1982
1983
1984
1985
1986
1987-1993
1994
1995
1996-1999
Non-catalyst
100%
30%
20%
25%
20%
-
-
-
-
-
-
-
-
-
-
Oxidation
-
70%
80%
75%
80%
95%
90%
80%
70%
60%
50%
5%
-
-
-
for Gasoline
TierO
-
.
.
.
.
5%
10%
20%
30%
40%
50%
95%
60%
20%
-
Light-Duty Trucks (Percent of VMT)*
Tierl
.
-
.
.
.
-
.
.
-
.
.
.
40%
80%
100%
* Excluding California VMT
- Not applicable
Table D-9: Control Technology Assignments for California Gasoline Passenger Cars and Light-Duty Trucks
(Percent of VMT)
Model Years Non-catalyst Oxidation
Tier 0
Tierl
LEV
1973-1974
1975-1979
1980-1981
1982
1983
1984-1991
1992
1993
1994
1995
1996-1999
100%
100%
15%
85%
86%
12%
100%
60%
20%
40%
80%
90%
85%
80%
10%
15%
20%
' Excluding California VMT
Not applicable
D-7
-------
Table D-10: Control Technology Assignments for Gasoline Heavy-Duty Vehicles (Percent of VMT)
Model Years
•S1981
1982-1984
1985-1986
1987
1988-1989
1990-1999
Uncontrolled
100%
95%
Non-catalyst
95%
70%
60%
45%
Oxidation
5%
5%
15%
25%
30%
TierO
15%
15%
. 25%
' Excluding California VMT
-Not applicable
Table D-11: Control Technology Assignments for Diesel Highway VMT
Vehicle Type/Control Technology
Model Years
Diesel Passenger Cars and Light-Duty Trucks
Uncontrolled
Moderate control
Advanced control
Heavy-Duty Diesel Vehicles
Uncontrolled
Moderate control
Advanced control
Motorcycles
Uncontrolled
Non-catalyst controls
1966-1982
1983-1995
1996-1999
1966-1972
1983-1995
1996-1999
1966-1995
1996-1999
D-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table D-12: Emission Factors (g/km) for CH4 and N20 and "Fuel Economy" (g COj/km)0 for Highway Mobile
Combustion
Vehicle Type/Control Technology
Gasoline Passenger Cars
Low Emission Vehicles"
Tierl
TierO
Oxidation Catalyst
Non-Catalyst
Uncontrolled
Gasoline Light-Duty Trucks
Low Emission Vehicles3
Tierl
TierO
Oxidation Catalyst
Non-Catalyst
Uncontrolled
Gasoline Heavy-Duty Vehicles
TierO
Oxidation Catalyst"
Non-Catalyst Control
Uncontrolled
Diesel Passenger Cars
Advanced
Moderate
Uncontrolled
Diesel Light Trucks
Advanced
Moderate
Uncontrolled
Diesel Heavy-Duty Vehicles
Advanced
Moderate
Uncontrolled
Motorcycles
Non-Catalyst Control
Uncontrolled
N?0
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
0.0870
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
0.13
0.26
g CCykm
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
! Applied to California VMT only.
b Methane emission factor assumed based on light-duty trucks oxidation catalyst value.
c The carbon emission factor (g Ctykm) was used as a proxy for fuel economy because of the greater number of significant figures compared to the
km/Lvalues presented in (IPCC/UNEP/OECD/IEA1997).
D-g
-------
Table D-13: Emission Factors for CH4 and N20 Emissions from Non-Highway Mobile Combustion (g/kg Fuel)
Vehicle Type/Fuel Type
Ships and Boats
Residual
Distillate
Gasoline
Locomotives
Residual
Diesel
Coal
Farm Equipment
Gas/Tractor
Other Gas
Dieseyrractor
Other Diesel
Construction
Gas Construction
Diesel Construction
Other Non-Highway
Gas Snowmobile
Gas Small Utility
Gas HD Utility
Diesel HD Utility
Aircraft
Jet Fuel
Aviation Gasoline
N20
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.08
0.1
0.04
CH4
0.23
0.23
0.23
0.25
0.25
0.25
0.45
0.45
0.45
0.45
0.18
0.18
0.18
0.18
0.18
0.18
0.087
2.64
Table D-14: NO, Emissions from Mobile Combustion, 1990-1999 (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
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
AircrafP
Other*
Total
1990
4,418
2,723
1,408
277
10
2,123
26
57
2,040
4,358
908
843
819
1,003
143
642
10,900
1991
4,744
2,774
1,669
291
10
2,112
30
10
2,072
4,445
955
842
837
1,020
141
650
11,301
1992
4,909
2,800
1,818
281
11
2,129
30
10
2,089
4,476
926
858
854
1,036
142
661
11,515
1993
5,047
2,817
1,933
286
11
2,174
30
11
2,133
4,483
886
857
870
1,052
142
676
11,705
1994
5,156
2,867
1,959
318
11
2,261
31
11
2,219
4,550
898
859
886
1,069
146
692
11,967
1995
4,867
2,750
1,807
300
11
2,351
31
11
2,308
4,653
905
898
901
1,090
150
709
11,870
1996
4,747
2,716
1,550
470
11
3,230
13
7
3,210
4,916
939
1,073
852
1,153
152
748
12,893
1997
4,756
2,706
1,580
458
11
3,338
10
6
3,322
5,001
953
1,109
851
1,159
152
777
13,095
1998
4,629
2,649
1,545
424
11
3,368
8
5
3,355
5,024
964
1,102
844
1,155
158
801
13,021
1999
4,496
2,582
1,486
416
12
3,297
7
5
3,284
5,001
975
1,092
826
1,137
159
813
12,794
' Aircraft estimates include only emissions related to LTO cycles, and therefore do not include cruise altitude emissions.
11 "Other" includes gasoline powered recreational, industrial, lawn and garden, light commercial, logging, airport service, other equipment; and diesel
powered recreational, industrial, lawn and garden, light construction, airport service.
Note: Totals may not sum due to independent rounding.
D-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table D-15: CO Emissions from Mobile Combustion, 1990-1999 (Gg)
Fuel Type/Vehicle Type
Gasoline Highway
Passenger Cars
Light-Duly Trucks
Heavy-Duty Vehicles
Motorcycles
Diesel Highway
Passenger Cars
Light-Duty Trucks
Heavy-Duty Vehicles
Non-Highway
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft3
Other"
Total
1990
51
31
15
4
1
1
16
,84U
,576
,530
,562
172
,180
20
42
,119
,503
2,041
1
11
69
110
527
,148
820
,857
,523
1991
55,949
32,208
18,709
4,871
161
1,204
24
8
1,172
16,860
2,053
109
537
1,171
806
12,184
74,012
1992
54,326
30,466
19,538
4,160
162
1,227
24
8
1,195
17,236
2,054
113
547
1,194
818
12,511
72,789
1993
54,852
29,933
20,679
4,067
172
1,243
25
9
1,209
17,592
2,053
108
557
1,216
821
12,837
73,687
1994
55,750
30,048
20,515
5,011
176
1,315
26
9
1,280
17,959
2,060
104
566
1,238
830
13,162
75,024
1995
48,375
26,854
17,630
3,722
169
1,349
27
9
1,313
18,348
2,065
103
575
1,258
855
13,492
68,072
1996
47,443
26,285
15,307
5,679
171
1,899
11
6
1,882
23,048
2,132
106
458
1,452
861
18,039
72,390
1997
46,392
25,809
15,376
5,034
173
1,976
9
5
1,961
22,857
2,150
110
459
1,413
869
17,856
71,225
1998
45,496
25,606
15,375
4,338
177
2,005
7
5
1,993
22,787
2,166
109
460
1,379
903
17,770
70,288
1999
43,327
24,664
14,620
3,866
177
2,023
7
5
2,011
22,829
2,170
108
458
1,333
909
17,851
68,179
' Aircraft estimates include only emissions related to LTO cycles, and therefore do not include cruise altitude emissions.
b "Other" includes gasoline powered recreational, industrial, lawn and garden, light commercial, logging, airport service, other equipment; and diesel
powered recreational, industrial, lawn and garden, light construction, airport service.
Note: Totals may not sum due to independent rounding.
Table D-16: NMVOCs Emissions from Mobile Combustion, 1990-1999 (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
Ships and Boats
Locomotives
Farm Equipment
Construction Equipment
Aircraft3
Other"
Total
1990
5,545
3,298
1,829
368
51
300
8
21
270
2,309
743
48
133
204
163
1,018
8,154
1991
5,753
3,240
2,103
378
33
288
10
4
275
2,341
748
47
133
208
161
1,045
8,383
1992
5,416
2,953
2,129
304
30
289
10
4
274
2,353
729
49
132
212
162
1,068
8,058
1993
5,470
2,901
2,241
296
31
289
10
5
274
2,381
731
47
132
216
160
1,095
8,140
1994
5,654
2,989
2,257
375
33
300
11
5
284
2,424
747
45
131
220
159
1,122
8,378
1995
4,980
2,714
1,937
295
34
296
11
5
280
2,449
738
45
130
225
161
1,150
7,725
1996
4,704
2,608
1,621
442
33
323
4
3
316
3,224
865
44
112
249
161
1,793
8,251
1997
4,632
2,578
1,623
398
33
301
4
3
295
3,090
872
45
110
240
161
1,662
8,023
1998
4,647
2,626
1,622
363
35
287
3
2
282
2,994
878
45
106
229
166
1,569
7,928
1999
4,544
2,604
1,562
340
38
263
3
2
258
2,929
874
44
99
214
166
1,532
7,736
a Aircraft estimates include only emissions related to LTO cycles, and therefore do not include cruise altitude emissions.
b "Other" includes gasoline powered recreational, industrial, lawn and garden, light commercial, logging, airport service, other equipment; and diesel
powered recreational, industrial, lawn and garden, light construction, airport service.
Note: Totals may not sum due to independent rounding.
D-11
-------
D-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
ANNEXE
Methodology for Estimating CH4 Emissions from Coal Mining
The methodology for estimating methane emissions from coal mining consists of two distinct steps. The
first step addresses emissions from underground mines. For these mines, emissions are estimated on a mine-by-
mine basis and then are summed to determine total emissions. The second step of the analysis involves estimating
methane emissions for surface mines and post-mining activities. In contrast to the methodology for underground
mines, which uses mine-specific data, the surface mine and post-mining activities analysis consists of multiplying
basin-specific coal production by basin-specific emission factors.
Step 1: Estimate Methane Liberated and Methane Emitted from Underground Mines
Underground mines generate methane from ventilation systems and from degasification systems. Some
mines recover and use methane generated from degasification systems, thereby reducing emissions to the
atmosphere. Total methane emitted from underground mines equals the methane liberated from ventilation systems,
plus the methane liberated from degasification systems, minus methane recovered and used.
Step 1.1: Estimate Methane Liberated from Ventilation Systems
All coal mines with detectable methane emissions1 use ventilation systems to ensure that methane levels
remain within safe concentrations. Many coal mines do not have detectable levels of methane, while others emit
several million cubic feet per day (MMCFD) from their ventilation systems. On a quarterly basis, the U.S. Mine
Safety and Health Administration (MSHA) measures methane emissions levels at underground mines. MSHA
maintains a database of measurement data from all underground mines with detectable levels of methane in their
ventilation air. Based on the four quarterly measurements, MSHA estimates average daily methane liberated at each
of the underground mines with detectable emissions.
For the years 1990 through 1996, MSHA emissions data were obtained for a large but incomplete subset of
all mines with detectable emissions. This subset includes mines emitting at least 0.1 MMCFD for some years and at
least 0.5 MMCFD for other years, as shown in Table E-l. Well over 90 percent of all ventilation emissions were
concentrated in these subsets. For 1997, the complete MSHA database for all 586 mines with detectable methane
emissions was obtained. These mines were assumed to account for 100 percent of methane liberated from
underground mines. The 1999 emissions dataset from MSHA includes mines emitting at least 0.1 MMCFD.
Using the complete database from 1997, the proportion of total emissions accounted for by mines emitting
more and less than 0.1 MMCFD or 0.5 MMCFD was estimated (see Table E-l). These proportions were then
applied to the years 1990 through 1999 to account for the less than 10 percent of ventilation emissions coming from
mines without MSHA data.
Average daily methane emissions were multiplied by 365 to determine the annual emissions for each mine.
Total ventilation emissions for a particular year were estimated by summing emissions from individual mines.
1 MSHA records coal mine methane readings with concentrations of greater than 50 ppm (parts per million) methane.
Readings below this threshold are considered non-detectable.
E-1
-------
Table E-1: Mine-Specific Data 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)
1998 AH Mines Emitting at Least 0.1 MMCFD (Assumed to Account for 97.8% of Total)*
1999 All Mines Emitting at Least 0.1 MMCFD (Assumed to Account for 97.8% of Total)*
* Factor derived from a complete set of individual mine data collected for 1997.
Step 1.2: Estimate Methane Liberated from Degasification Systems
Coal mines use several different types of degasification systems to remove methane, including vertical
wells and horizontal boreholes to recover methane prior to mining of the coal seam. Gob wells and cross-measure
boreholes recover methane from the overburden (i.e., 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 1999, eleven active coal mines had methane recovery and use projects and sold the recovered methane to
a pipeline. One coal mine also used some recovered methane in a thermal dryer in addition to selling gas to a
pipeline. 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 (e.g., 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 amount of gas recovered and the
number of years in advance of mining that wells were drilled. In most cases, coal mine operators provided this
information, which was then used to estimate emissions avoided for a particular year. Additionally, several state
agencies provided production data for individual wells. For some mines, these 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 were not available for estimating methane emissions from surface coal mines or for
post-mining activities. For surface mines and post-mining activities, basin-specific coal production was multiplied
by a basin-specific emission factor to determine methane emissions.
E-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Step 2.1: Define the Geographic Resolution of the Analysis and Collect Coal Production Data
The first step in estimating methane emissions from surface mining and post-mining activities was to define
the geographic resolution of the analysis and to collect coal production data at that level of resolution. The analysis
was conducted by coal basin as defined in Table E-2, which presents coal basin definitions by basin and by state.
The Energy Information Agency's (EIA) Coal Industry Annual reports state- and county-specific
underground and surface coal production by year. To calculate production by basin, the state level data were
grouped into coal basins using the basin definitions listed in Table E-2. For two states—West Virginia and
Kentucky—county-level production data was used for the basin assignments because coal production occurred from
geologically distinct coal basins within these states. Table E-3 presents the coal production data aggregated by
basin.
Step 2.2: Estimate Emissions Factors for Each Emissions Type
Emission factors for surface mined coal were developed from the in situ methane content of the surface
coal in each basin. Based on an analysis presented in EPA (1993), surface mining emission factors were estimated
to be from 1 to 3 times the average in situ methane content in the basin. For this analysis, the surface mining
emission factor was determined to be twice the in situ methane content in the basin. Furthermore, the post-mining
emission factors used were estimated to be 25 to 40 percent of the average in situ methane content in the basin. For
this analysis, the post-mining emission factor was determined to be 32.5 percent of the in situ methane content in the
basin. Table E-4 presents the average in situ content for each basin, along with the resulting emission factor
estimates.
Step 2.3: Estimate Methane Emitted
The total amount of methane emitted was calculated by multiplying the coal production in each basin by
the appropriate emission factors. Total annual methane emissions is equal to the sum of underground mine
emissions plus surface mine emissions plus post-mining emissions. Table E-5 and Table E-6 present estimates of
methane liberated, used, and emitted for 1990 through 1999. Table E-7 provides emissions by state.
E-3
-------
Table E-2: Coal Basin Definitions by Basin and by State
Basin
States
Northern Appalachian Basin
Centra! 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
E-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table E-3: Annual Coal Production (Thousand Short Tons)
Underground Coal Production
Basin
Northern Appalachia
Central Appalachia
Warrior
Illinois
S. Wesl/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
170
14
69
41
2
399
,122
,893
,471
,050
,681
,738
147
0
,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
1997
112,135
177,720
18,505
64,728
44,503
2,854
212
0
420,657
1998
116,718
171,279
17,316
64,463
45,983
1,723
247
0
417,729
1999
104,793
160,794
14,672
61,666
44,829
1,836
247
0
388,837
Surface Coal Production
Basin
Northern Appalachia
Central Appalachia
Warrior
Illinois
S. Wesl/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
1997
40,179
113,275
5,963
46,862
48,374
349,612
59,061
5,945
669,271
1998
41,043
108,345
5,697
47,715
49,635
385,438
57,951
5,982
699,608
1999
36,352
101,866
4,827
42,300
51,378
404,488
58,262
5,665
705,138
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
1997
152,314
290,995
24,468
111,590
92,877
352,466
59,273
5,945
1,0829,928
1998
157,761
279,624
23,013
110,176
95,618
387,161
58,198
5,982
1,118,132
1999
141,145
262,660
19,499
103,966
96,207
406,324
58,509
5,665
1,093,975
Source for 1990-98 data: EIA (1990-98), Coal Industry Annual. U.S. Department of Energy, Washington, DC, Table 3.
Source for 1999 data: EIA (2000) U.S. Coal Supply and Demand: 1999 Review, U.S. Department of Energy, Washington, DC, Table 1. (EIA table listed
only total coal production for each state; therefore 1998 underground/surface percentages were used to estimate actual 1999 production.)
Note: Totals may not sum due to independent rounding.
Table E-4: Coal Surface and Post-Mining Methane Emission Factors (ft3 per Short Ton)
Surface Average Underground Average Surface Mine Post-Mining Post Mining
Basin in situ Content In situ Content Factors Surface Factors Underground
Northern Appalachia
Central Appalachia
Warrior
Illinois
S. West/Rockies
N. Great Plains
West Interior
Northwest
49.3
49.3
49.3
39.0
15.3
3.2
3.2
3.2
171.7
330.7
318.0
57.20
225.8
41.67
41.67
41.67
98.6
98.6
98.6
78.0
30.6
6.4
6.4
6.4
16.0
16.0
16.0
12.7
5.0
1.0
1.0
1.0
16.0
16.0
16.0
12.7
5.0
1.0
1.0
1.0
Source: EPA (1993), Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to Congress, U.S. Environmental Protection
Agency, Air and Radiation, April.
E-5
-------
Table E-5: Underground Coal Mining Methane Emissions (Billion Cubic Feet)
Activity
Ventilation Output
Adjustment Factor for Mine Data*
Adjusted Ventilation Output
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
1997
96
100.0%
96
57
153
(42)
112
1998
94
97.8%
96
54
150
(44)
107
1999
92
97.8%
94
48
142
(43)
99
'Referto Table E-1
Note: Totals may not sum due to independent rounding.
Table E-6: Total Coal Mining Methane Emissions (Billion Cubic Feet)
Activity
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
Underground Mining
Surface Mining
Post-Mining (Underground)
Post-Mining (Surface)
156 149 142 121 119 130 115 112 107 99
25 23 23 23 24 22 23 24 23 22
33 31 30 27 30 30 31 31 31 29
4444444444
Total
218
207
200
175
177
185
172
171
165
154
Note: Totals may not sum due to independent rounding.
E-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table E-7: Total Coal Mining Methane Emissions by State (Million Cubic Feet)
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maryland
Missouri
Montana
New Mexico
North Dakota
Ohio
Oklahoma
Pennsylvania
Tennessee
Texas
Utah
Virginia
Washington
West Virginia
Wyoming
Total
•fQOn^^"^ 1QQQ
I 3 3U ?;|j|||;j:S|| 1 99O
5
21,229
24
510
20
280
905
217
H
V
27,000
12
433
+
0
7,038
8,737
2,623
1
3
19,823
ill 23
245
131 5
111 267
mm 1'186
Si 238
4,110
14
26,437
350
415
4,562
45,883
37
56,636
iPi 4°6
•99 4-512
mm 30'454
Pll 35
• 39-477
1,578
218,18011111 175,007
1994
30,713
12
464
+
0
9,029
10,624
2,791
+
2
21,037
26
256
6
310
1,223
240
4,377
52
24,026
338
389
3,696
26,782
36
38,565
1,782
176,781
1995
39,945
13
425
+
0
8,541
11,106
2,106
0
2
19,103
28
259
4
294
980
224
3,900
14
27,086
366
392
3,541
19,898
36
44,894
1,977
185,134
1996
30,808
11
371
+
0
5,795
10,890
2,480
0
2
18,292
24
287
5
283
856
222
3,992
14
26,567
418
410
4,061
19,857
34
44,380
2,090
172,149
1997
26,722
11
417
+
0
9,057
8,571
3,088
0
3
20,089
26
296
3
305
961
220
4,313
132
30,339
390
397
4,807
16,990
33
41,454
2,122
170,746
1998
26,967
10
403
+
0
9,057
7,859
3,239
0
3
19,240
24
282
3
319
1,026
223
4,244
137
29,853
309
391
5,060
9,698
35
44,460
2,351
165,192
1999
26,066
12
419
+
0
9,280
7,878
3,006
0
3
18,303
22
268
3
306
1,068
225
3,809
209
27,003
349
395
4,726
3,776
31
43,878
2,505
153,540
+ Does not exceed 0.5 Million Cubic Feet
Note: The emission estimates provided above are inclusive of emissions from underground mines, surface mines and post-mining activities. The
following states have neither underground nor surface mining and thus report no emissions as a result of coal mining: Connecticut, Delaware, Florida,
Georgia, Hawaii, Idaho, Maine, Massachusetts, Michigan, Minnesota, Mississippi, Nebraska, Nevada, New Hampshire, New Jersey, New York, North
Carolina, Oregon, Rhode Island, South Carolina, South Dakota, Vermont, and Wisconsin. Emission estimates are not given for 1991 and 1992 because
underground mine data was not available for those years.
E-7
-------
E-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
ANNEX F
Methodology for Estimating CH4 Emissions from Natural Gas Systems
The following steps were used to estimate methane emissions from natural gas systems.
Step 1: Calculate Emission Estimates for Base Year 1992 Using GRI/EPA Study
The first step in estimating methane emissions from natural gas systems was to develop a detailed base year
estimate of emissions. The study by GRI/EPA (1996) divides the industry into four stages to construct a detailed
emission inventory for the year 1992. These stages include: field production, processing, transmission and storage
(i.e., both underground and liquefied gas storage), and distribution. This study produced emission factors and
activity data for over 100 different emission sources within the natural gas system. Emissions for 1992 were
estimated by multiplying activity levels by emission factors for each system component and then summing by stage.
Since publication, the EPA has updated activity data for some of the components in the system. Table F-l displays
the 1992 GRI/EPA activity levels and emission factors for venting and flaring from the field production stage, and
the current EPA activity levels and emission factors. These data are shown to illustrate the kind of data used to
calculate emissions from all stages.
Step 2: Collect Aggregate Statistics on Main Driver Variables
As detailed data on each of the over 100 sources were not available for the period 1990 through 1999,
activity levels were estimated using aggregate statistics on key drivers, including: number of producing wells (IPAA
1990 through 1998, EIA 1998), number of gas plants (AGA 1990 through 1998; OGJ 1999, 2000), miles of
transmission pipeline (OPS 1998, 1999), miles of distribution pipeline (AGA 1990 through 1999), miles of
distribution services (AGA 1990 through 1999), and energy consumption (EIA 1998, 1999, 2000). Data on the
distribution of gas mains by material type was not available for certain years from AGA. For those years, the
average distribution by type was held constant. Table F-2 provides the activity levels of some of the key drivers in
the natural gas analysis.
Step 3: Estimate Emission Factor Changes Over Time
For the period 1990 through 1995, the emission factors were held constant, based on 1992 values. An
assumed improvement in technology and practices was estimated to reduce emission factors by 5 percent by the year
2020. This assumption, annualized, amounts to a 0.2 percent decline in the 1996 emission factor, a 0.4 percent
decline in the 1997 emission factor, a 0.6 percent decline in the 1998 emission factor and a 0.8 percent decline in the
1999 emission factor, all relative to 1995 emission factors.
Step 4: Estimate Emissions for Each Year and Stage
Emissions from each stage of the natural gas industry were estimated by multiplying the activity factors by
the appropriate emission factors, summing all sources for each stage, and then subtracting the Natural Gas STAR
emission reductions, as reported by industry STAR Partners. Total emissions were estimated by adding the
emission estimates from each stage. Table F-3 illustrates emission estimates for venting and flaring emissions from
the field production stage using this methodology.
F-1
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ANNEX G
Methodology for Estimating CH4 Emissions from Petroleum Systems
The methodology for estimating methane emissions from petroleum systems is based on the 1999 EPA
draft report, Estimates of Methane Emissions from the U.S. Oil Industry (EPA 1999). Seventy activities that emit
methane from petroleum systems were examined for this report. Most of the activities analyzed involve crude oil
production field operations, which accounted for 97 percent of total oil industry emissions. Crude transportation and
refining accounted for the remaining emissions at about one and two percent each, respectively.
The following steps were taken to estimate methane emissions from petroleum systems.
Step 1: Calculate a Detailed Emission Estimate for 1995 Based on the 1999 EPA Report
The emission factors used for the 1995 base year estimate of methane emissions came from the 1999 EPA
draft report. An industry peer-review process identified improvements to activity data for oil wells and tank venting.
These recommendations were incorporated into the estimate provided in this inventory. In addition, the EPA
reviewed data on the number of oil well completions each year for two years after the initial estimates to ensure that
the most up-to-date reports for 1995 were incorporated. The inventory also incorporates updated 1995 data for the
number of offshore oil production platforms and the number of crude oil loadings into marine vessels. The activity
factors for all years are updated to include these data. The 1995 base year format is used as a basis for estimating
emissions 1990-94 and 1996-99 by including the appropriate updated activity factors for each year.
Step 2: Collect Oil Industry Activity Data
Several approaches were used to develop annual activity data for 1990 through 1994 and 1996 through
1999. Most activity data were updated annually at the same level of detail as the 1995 estimate, using reports from
the U.S. Department of Energy (DOE) and the oil industry. For cases in which annual data were not available but
the activity factors were known to correlate well with changes in oil production rates, the activity factors were scaled
from a base year in proportion to annual oil production rate changes. For a small number of sources, 1999 data were
not yet available. In these cases, the 1998 activity factors were used. In the few cases where no data was located,
activity data based on oil industry expert judgment were used.
Step 3: Select Emission Factors
The 1995 emission factors were used for all years, 1990 through 1999. Many of the emission factors are
based on field tests performed several years ago while others were taken from more recent work. The more recently
developed emission factors use tank emission models developed by the American Petroleum Institute for estimating
emissions from fixed roof and floating roof tanks.
Step 4: Estimate Emissions for Each Activity
Emissions from each of the 70 petroleum system activities analyzed were estimated by multiplying the
activity data for each year by the corresponding emission factor. Table G-l, Table G-2, and Table G-3 provide the
1999 activity factors, emission factors, and emission estimates. Table G-4 provides a summary of emission
estimates for the years 1990 through 1999.
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Table G-3:1999 CH4 Emissions from Petroleum Refining
Emission
Activity/Equipment
Vented Emissions:
Tanks
System Slowdowns
Asphalt Blowing
Fugitive Emissions:
Fuel Gas System
Floating Roof Tanks
Wastewater Treating
Cooling Towers
Combustion Emissions:
Atmospheric Distillation
Vacuum Distillation
Thermal Operations
Catalytic Cracking
Catalytic Reforming
Catalytic Hydrocracking
Hydrorefining
Hydrotreating
Alkylation/Polymerization
Aromatics/lsomeration
Lube Oil Processing
Engines
Flares
Total
Factor Units
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2,555 scfClVMbbl
439 McfCH/refinery/yr
587 scf Chyfloating roof tank/yr.
1.88 scfCHVMbbl
2.36 scfChVMbbl
3.61 scfClVMbbl
3.61 scfCH
-------
ANNEXH
Methodology for Estimating Emissions from international Bunker Fuels used by the
U.S. Military
Bunker fuel emissions estimates for the Department of Defense (DoD) were developed using data
generated by the Defense Energy Support Center for aviation and naval fuels. The Defense Energy Support Center
(DESC) of the Defense Logistics Agency (DLA) prepared a special report based on data in the Defense Fuels
Automated Management System (DFAMS). DFAMS contains data for 1995 through 1999, but the data set was not
complete for years prior to 1995. Fuel quantities for 1990 to 1994 were estimated based on a back-calculation of the
1995 DFAMS values using DLA aviation and marine fuel procurement data.
Step 1: Omit Extra-Territorial Fuel Deliveries
Beginning with the complete DFAMS data set for each year, the first step in the development of DoD
related emissions from international bunker fuels was to identify data that would be representative of international
bunker fuel consumption as that term is defined by decisions of the UNFCCC (i.e., fuel sold to a vessel, aircraft, or
installation within the United States or its territories and used in international maritime or aviation transport).
Therefore, fuel data was categorized by the location of fuel delivery in order to identify and omit all extra-territorial
fuel transactions/deliveries (i.e., sales abroad). Table H-l displays the fuels that remain at the completion of Step 1,
summarized by fuel type.
Step 2: Omit Fuel Transactions Received by Military Services that are not Considered to be International
Bunker Fuels
Next, fuel transaction/delivery records were sorted by military Service. The following assumptions were
made regarding bunker fuel use by. Service, leaving only the Navy and Air Force as users of military international
bunker fuels.
• Only fuel delivered to a ship, aircraft, or installation in the United States can be a potential international
bunker fuel. Fuel consumed in international aviation or marine transport should be included in the bunker
fuel estimate of the country where the ship or aircraft was fueled. Fuel consumed entirely within a
country's borders is not bunker fuel.
• Based on discussions with the Army staff, only an extremely small percentage of Army aviation emissions,
and none of its watercraft emissions, qualified as bunker fuel emissions. The magnitude of these emissions
was judged to be insignificant when compared to Air Force and Navy emissions. Based on this, Army
bunker fuel emissions are assumed to be zero.
• Marine Corps aircraft operating while embarked consume fuel reported as delivered to the Navy. Bunker
fuel emissions from embarked Marine Corps aircraft are reported in the Navy bunker fuel estimates.
Bunker fuel emissions from other Marine Corps operations and training are assumed to be zero.
• Bunker fuel emissions from other DoD and non-DoD activities (i.e., other federal agencies) that purchase
fuel from DESC are assumed to be zero.
Step 3: Omit Land-Based Fuels
Navy and Air Force land-based fuel consumption (i.e., fuel not used by ships or aircraft) were also omitted.
The remaining fuels, listed below, were potential military international bunker fuels.
• Marine: naval distillate fuel (F76) and marine gas oil (MGO).
• Aviation: jet fuels (JP8, JP5, JAA, and JA1).
H-1
-------
Step 4: Determine Bunker Fuel Percentages
Next it was necessary to determine what percent of the marine and aviation fuels were used as international
bunker fuels. Military aviation bunkers include international operations (i.e., sorties that originate in the United
States and terminate in a foreign country), operations conducted from naval vessels at sea, and operations conducted
from U.S. installations principally over international water in direct support of military operations at sea (e.g., anti-
submarine warfare flights). For the Air Force, a bunker fuel weighted average was calculated based on flying hours
by major command. International flights were weighted by an adjustment factor to reflect the fact that they typically
last longer than domestic flights. In addition, a fuel use correction factor was used to account for the fact that
transport aircraft bum more fuel per hour of flight than most tactical aircraft. The Air Force bunker fuel percentage
was determined to be 13.2 percent. This percentage was multiplied by total annual Air Force aviation fuel delivered
for U.S. activities, producing an estimate for international bunker fuel consumed by the U.S. Air Force. The naval
aviation bunker fuel percentage of total fuel was calculated using flying hour data from Chief of Naval Operations
Flying Hour Projection System Budget Analysis Report for FY1998, and estimates of bunker fuel percent of flights
provided by the fleet. The naval aviation bunker fuel percentage, determined to be 40.4 percent, was multiplied by
total annual Navy aviation fuel delivered for U.S. activities, yielding total Navy aviation bunker fuel consumed.
For marine bunkers, fuels consumed while ships were underway were assumed to be bunker fuels. The
Navy reported that 87 percent of vessel operations were underway, while the remaining 13 percent of operations
occurred in port (i.e., pierside). Therefore, the Navy maritime bunker fuel percentage was determined to be 87
percent. Table H-2 and Table H-3 display DoD bunker fuel totals for the Navy and Air Force.
Step 5: Calculate Emissions trom Military International Bunker Fuels
Bunker fuel totals were multiplied by appropriate emission factors to determine greenhouse gas emissions
(see Table H-4 and Table H-5.
The rows labeled 'U.S. Military' and 'U.S. Military Naval Fuels' within Table 2-36 and Table 2-37 in the
Energy Chapter were based on the international bunker fuel totals provided in Table H-2 and Table H-3, below.
Total CCK emissions from military bunker fuels are presented in Table H-6. Carbon dioxide emissions from
aviation bunkers and distillate marine bunkers presented in Table 2-7 are the total of military plus civil aviation and
civil marine bunker fuels, respectively. The military component of each total is based on fuels tallied in Table H-2
and Table H-3. Carbon dioxide emissions from military vehicles (e.g., ships, aircraft, and land-based vehicles)
presented in Table 2-7 of the Inventory were calculated by subtracting total aviation bunker fuel in Table H-2 from
the aviation subtotal in Table H-l. Motor gasoline totals presented in Table H-l were estimated using data provided
by the military Services.
H-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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-------
Table H-2: Total U.S. Military Aviation Bunker Fuel (Million Gallons)
Fuel Type/Service 1990 1991 1992 1993
JP8 56.74 56.30 46.40 145.33
Navy 56.74 56.30 46.08 44.56
Air Force + + 0.32 100.77
JP5 370.53 367.66 300.92 290.95
Navy 365.29 362.46 296.66 286.83
Air Force 5.25 5.21 4.26 4.12
JP4 420.77 417.52 341.40 229.64
Navy 0.02 0.02 0.02 0.02
Air Force 420.75 417.50 341.39 229.62
JAA 13.70 13.60 11.13 10.76
Navy 8.45 8.39 6.86 6.64
Air Force 5.25 5.21 4.27 4.12
JA1 + + + +
Navy + + + +
Air Force + + + +
JAB + + + +
Navy + + + +
Air Force + + + +
Navy Subtotal 430.50 427.17 349.62 338.04
Air Force Subtotal 431.25 427.91 350.23 338.63
Total 861.75 855.08 699.85 676.68
1994
223.99
40.06
183.93
261.57
257.87
3.70
113.11
0.01
113.10
9.67
5.97
3.71
+
+
+
+
+
+
303.91
304.44
608.35
1995
300.40
38.25
262.15
249.78
246.25
3.54
21.50
0.01
21.49
9.24
5.70
3.54
+
+
+
+
+
+
290.21
290.72
580.93
1996
308.81
39.84
268.97
219.40
216.09
3.31
1.05
0.00
1.05
10.27
6.58
3.69
+
+
+
+
+
+
262.51
277.02
539.53
1997
292.01
46.92
245.09
194.16
191.15
3.01
0.05
0.00
0.05
9.42
5.88
3.54
+
+
+
+
+
+
243.95
251.70
495.65
1998
306.39
53.81
252.59
184.38
181.36
3.02
0.03
0.00
0.03
10.84
6.63
4.21
0.01
+
0.01
+
+
+
241.80
259.86
501.66
1999
301.35
55.46
245.89
175.37
170.59
4.77
0.02
0.00
0.02
10.78
6.32
4.47
+
+
+
+
+
+
232.37
255.14
487.52
+ Does not exceed 0.005 million gallons.
Note: Totals may not sum due to independent rounding.
Table H-3: Total U.S. DoD Maritime Bunker Fuel (Million Gallons)
Marine Distillates 1990 1991 1992 1993
Navy-MGO + + + +
Navy-F76 522.37 481.15 491.47 448.27
Total 522.37 481.15 491.47 448.27
1994
+
364.01
364.01
1995
+
333.82
333.82
1996
30.34
331.88
362.22
1997
35.57
441.65
477.22
1998
31.88
474.23
506.11
1999
39.74
465.97
505.71
+ Does not exceed 0.005 million gallons.
Note: Totals may not sum due to independent rounding.
Table H-4: Aviation and Marine Carbon Contents (Tg Carbon/Qbtu) and Fraction Oxidized (%)
Mode (Fuel) Carbon Content Fraction
Coefficient Oxidized
Aviation (Jet Fuel) variable 99%
Marine (Distillate) 19.95 99%
Table H-5: Annual Variable Carbon Content Coefficient for Jet
Fuel 1990 1991 1992 1993
Jet Fuel 19.40 19.40 19.39 19.37
1994
19.35
Table H-6: Total U.S. DoD C02 Emissions from Bunker Fuels (Tg
Mode 1990 1991 1992 1993
Aviation 8.3 8.2 6.7 6.5
Marine 5.2 4.8 4.9 4.5
Total 13.5 13.1 11.7 11.0
1994
5.8
3.7
9.5
Fuel (Tg Carbon/Qbtu)
1995
19.34
C02 Eq.)
1995
5.6
3.4
8.9
1996
19.33
1996
5.2
3.6
8.8
1997
19.33
1997
4.8
4.8
9.5
1998
19.33
1998
4.8
5.1
9.9
1999
19.33
1999
4.7
5.1
9.8
Note: Totals may not sum due to independent rounding.
H-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
ANNEX I
Methodology for Estimating HFC, PFC, and SF6 Emissions from Substitution of Ozone
Depleting Substances
The EPA uses a detailed vintaging model of ozone depleting substance (ODS)-containing equipment and
products to estimate the actual—versus potential—emissions of various ODS substitutes, including HFCs and PFCs.
The name of the model refers to the fact that it tracks the use and emissions of various compounds for the annual
"vintages" of new equipment that enter service in each end-use. This vintaging model is a "bottom up" model that
estimates ODS and ODS substitute use in the United States. It is based on modeled estimates of the quantity of
equipment or products sold each year containing these chemicals, and the amount of chemical required to
manufacture and/or maintain equipment and products over time. The model estimates emissions from refrigeration
and air-conditioning, foams, aerosols, solvents, and fire extinguishing end-use groupings. Emissions from more
than 40 different end-uses are estimated by applying annual leak rates and release profiles, which account for the lag
in emissions from equipment as they leak over time. By aggregating the data over the different end-uses, the model
produces estimates of annual use and emissions of each compound. The methodologies used to estimate
consumption and emissions vary depending on the end-use under consideration.
The vintaging model calculates emissions associated with each vintage of equipment on an annual basis.
For most products (e.g., refrigerators, air conditioners, fire extinguishers, etc.), emission calculations are split into
two categories: emissions during equipment lifetime, which arise from annual leakage and service losses plus
emissions from manufacture, and disposal emissions, which occur at the time of discard. For each year, the model
tracks which vintages are in use, which are being discarded, how much of each chemical is being recycled, what
chemicals are in each vintage, and at what rates these chemicals are emitted.
Some products' lifecycles present slightly different cases that do not fit the criteria necessary for both
lifetime and disposal emissions calculations. For example, aerosols, solvents, and foams are not "serviceable" items
and will never be "recharged" with an ODS or ODS substitute. To compensate, "non-serviceable" items' emissions
are adjusted to reflect either "instantaneous" emissions (for aerosols and solvents) or a "progressive disposal" (for
foams) that allows for emissions to extend over a number of years. For example, with aerosols it is assumed that
100 percent of their chemical charge is emitted in the year of production. Hence, the annual disposal emissions for
aerosols are set to equal annual aerosol use.1 Solvent emissions are assumed to be a set percentage of annual use,
reflecting instantaneous but incomplete emissions.2 Foams are slightly more complex, and are given emission
profiles depending on the foam type (i.e., open cell or closed cell). The model assumes that a percentage of the
foam blowing agent is emitted at manufacture, a small amount is emitted throughout the lifetime of the foam, and
some percentage will remain within the foam indefinitely.
For all end-uses, emissions are calculated according to the following steps:
Stepl: Estimate Lifetime Emissions
In order to estimate lifetime emissions, both the amount of chemical leaked during equipment operation
and during service recharges are modeled. These are calculated using a baseline value for total ODS in existing
equipment in 1985, which is the beginning year of the model.3 Growth in equipment demand, changes in chemical
1 This assumption functions independently of when the aerosol is actually used (e.g. whether use occurs during the year
it enters the market or in the firture). Since there is currently no aerosol recycling, it is valid to consider all of a particular year's
production of aerosol propellants as released to the atmosphere.
2 Generally, most of the solvent used remains in the liquid phase and is not emitted as a gas. Thus, emission is
considered "incomplete," and is set as a fraction of the amount of solvent consumed in a year.
3 While the vintaging model was initialized with data collected in 1985, the assumptions made in 1985 are updated as
new information becomes available.
1-1
-------
leak and service rates, and substitute phase-ins are used to calculate emissions for any given year.
emissions in yeary, for each chemical within each end-use, are calculated as follows:
Lifetime
Lifetime Emissions (y) = Market Penetration (y) X Tons Serviced (1985) X Yearly Scale Factor X Growth Rate (y)
where,
Lifetime Emissions =
Market Penetration =
Tons Serviced (1935) =
Yearly Scale Factor =
Growth Rate =
the total end-use emissions in yeary from chemical leak and service recharge.
the marketshare (percent) that a particular chemical achieves for that end-use in yeary.
the amount of chemical emitted due to leaks and servicing in equipment in 1985.
a percentage that accounts for the difference in leak rates and service rates between a chemical
substitute and the original chemical.
the demand for the end-use equipment relative to 1985 demand. Growth rates that applied to
the original ODS containing equipment are continued for the substitute equipment; however,
these rates are modified as new information regarding the growth of the market becomes
available.
In general, substitute chemicals that are phased-in at a later date will have a smaller Yearly Scale Factor
(and consequently a reduced amount of annual service emissions per unit) than earlier substitutes or the original
ODS (i.e., new equipment tends to leak less). This trend is driven by the increased cost of the "newer" substitutes,
which drives improvements in product design and servicing practices, and will reduce leakage and service losses.
Note that the equation is applied to each chemical, in addition to each year.
Step 2: Estimate Disposal Emissions
The disposal emission equations assume that a certain percentage of the chemical consumed in a particular
year will be emitted to the atmosphere when that vintage is discarded. Disposal emissions are thus a function of a
chemical manufactured for new equipment in previous years and the proportion of chemical released at disposal, and
are calculated using the following equation:
Disposal Emissions (y) = Use of Chemical at Manufacture (i985toy> X End-Use Disposal (i985toy)
where,
Disposal Emissions = the amount of chemical emitted at the retirement of the equipment.
Use of Chemical at
Manufacture = the amount of chemical used in manufacturing the equipment.
End-Use Disposal = the percentage of chemical emitted at disposal in year y based on the equipment
lifetime.
The Use of Chemical at Manufacture and the End-Use Disposal percentage factors represent a timeseries of
values. For each year, an End-Use Disposal percentage is associated with the Use of Chemical at Manufacture,
based on the lifetime of the equipment. In order to calculate the Disposal Emissions for a particular year, the Use of
Chemical at Manufacture values for all the years between 1985 and the current year are used with the corresponding
End-Use Disposal Percentage values.
The End-Use Disposal percentage array sets the disposal emissions to occur only when the appropriate
vintage year's equipment is actually discarded. The End-Use Disposal percentages for all the "serviceable" goods,
such as fire extinguishing, refrigeration, and air-conditioning equipment are always set to 100 percent at the end of
the equipment's lifetime. The End-Use Disposal percentage arrays also allow the special cases of "non-serviceable"
products such as aerosols, solvents, and foams.4 Aerosols have a value of 100 percent in the first year,
corresponding to the "instantaneous" disposal assumption. Solvents have values around 15 percent for year one and
zero for all future years, corresponding to instantaneous and incomplete emission in the same year as production.
Foams have End-Use Disposal percentages that fall between zero and 100 percent for year one and also for several
following years. This demonstrates "progressive" disposal, where a portion of the chemical is emitted in the
blowing process, a portion is emitted during the foam's lifetime, and a portion is emitted at discard. The model
4 Note that it is simply an artifact of the model that emissions from "non-serviceable" items are attributed to the
product's disposal rather than it's lifetime. To calculate annual emissions, both disposal and lifetime emissions for all end-uses
are included.
1-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
keeps track of which chemical was used in which type of equipment, such that in any given year, the disposal
emissions from a given end-use may consist of several ODS or ODS substitutes.
The Use of Chemical at Manufacture value contains the growth adjustments for the increase in chemical
demand since the base year (1985) and information on specific chemicals' disposal. Again, this equation is
calculated for each chemical within each end-use. It can be written as follows:
Use of Chemical at Manufacture(y) = Growth Rate(y) X Tons Manufactured(19S5) X
Market Penetration (y) X [1 - (Chemical Disposal Recovery X Retirement Vintage (y))]
where,
Use of Chemical at Manufacture =
Growth Rate =
Tons Manufactured =
Market Penetration =
Chemical Disposal Recovery =
the amount of chemical used in manufacturing the equipment.
the estimated cumulative growth of the industry from 1985 through year y.
the quantity of chemical manufactured in the base year (1985).
the manufacturing market share that a chemical has achieved in year v.
the percentage of chemical that will be recovered from an individual unit at
disposal.
the percent of the equipment being retired from stock in a particular year to the
equipment being manufactured as new in that year.
The product of the first three terms represents the growth- and substitution-adjusted demand for a particular
chemical in a particular year. The product of the Chemical Disposal Recovery percentage and the Retirement
Vintage percentage gauges how much chemical is recovered in a particular year. In essence, it expresses how much
chemical can be recovered from an individual unit and how many units will leave the equipment stock.
Retirement Vintage =
Step 3: Sum emissions for yeary
The final step is to sum disposal and lifetime emissions (Steps 1 and 2) across all end uses, by year and by
chemical, to provide a profile of ODS and ODS substitute emissions from 1985 through 2030.
1-3
-------
1-4 inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
ANNEX J
Methodology for Estimating CH4 Emissions from Enteric Fermentation
Methane emissions from enteric fermentation were estimated for five livestock categories: cattle, horses,
sheep, swine and goats. Emissions from cattle represent the majority of U.S. emissions, consequently, the more
detailed IPCC Tier 2 methodology was used to estimate emissions from cattle and the IPCC Tier 1 methodology was
use to estimate emissions from the other types of livestock.
Estimate Methane Emissions from Cattle
This section describes the process used to estimate methane emissions from cattle enteric fermentation. A
model based on recommendations provided in IPCC/UNEP/OECD/IEA (1997) and IPCC (2000) was developed that
uses information on population, energy requirements, digestible energy, and methane conversion rates to estimate
methane emissions. The emission methodology consists of the following three steps: (1) characterize the cattle
population to account for animal population categories with different emissions profiles; (2) characterize cattle diets
to generate information needed to estimate emissions factors; and (3) estimate emissions using these data and the
IPCC Tier 2 equations.
Step 1. Characterize U.S. Cattle Population
Each stage in the cattle lifecycle was modeled to simulate the cattle population from birth to slaughter.
This level of detail accounts for the variability in methane emissions associated with each life stage. Given that the
time in which cattle can be in a stage can be less than one year (e.g., beef calves are weaned at 7 months), the stages
are modeled on a per month basis. The type of cattle use also impacts methane emissions (e.g., beef versus dairy).
Consequently, cattle life stages were modeled for several categories of dairy and beef cattle. These categories are
listed in Table J-l.
Table J-1: Cattle Population Categories Used for Estimating Methane Emissions
Dairy Cattle
Beef Cattle
Calves
Heifer Replacements
Cows
Calves
Heifer Replacements
Heifer and Steer Stackers
Animals in Feedlots
Cows
Bulls
The key variables tracked for each of these cattle population categories (except bulls1) are as follows:
Calving rates: The number of animals born on a monthly basis was used to initiate monthly cohorts and to
determine population age structure. The number of calves born each month was obtained by multiplying
annual births by the percentage of births by month. Annual birth information was taken from USDA
(1999a). Average percentage of births by month for beef from USDA (USDA/APfflS/VS 1998, 1994,
1993) were used for 1990 through 1999. For dairy animals, birth rates were assumed constant throughout
the year. Whether calves were born to dairy or beef cows was estimated using the dairy cow calving rate
and the total dairy cow population to determine the percent of births attributable to dairy cows, with the
remainder assumed to be attributable to beef cows.
Average weights and weight gains: Average weights were tracked for each monthly age group using
starting weight and monthly weight gain estimates. Weight gain (i.e., pounds per month) was estimated
based on weight gain needed to reach a set target weight, divided by the number of months remaining
* Only end-of-year census population statistics and a national emission factors are used to estimate methane emissions
from the bull population.
J-1
-------
before target weight was achieved. Birth weight was assumed to be 88 pounds for both beef and dairy
animals. Weaning weights were estimated to range from 480 to 575 pounds. Other reported target weights
were available for 12, 15,24, and 36 month-old animals. Live slaughter weights were derived from dressed
slaughter weight data (USDA 1999f). Live slaughter weight was estimated as dressed weight divided by
0.63.
• Feedlotplacements: Feedlot placement statistics were available that specify placement of animals from the
stocker population into feedlots on a monthly basis by weight class. The model used these data to shift a
sufficient number of animals from the stocker cohorts into the feedlot populations to match the reported
data. After animals are placed in feedlots they progress through two steps. First, animals spend time on a
step-up diet to become acclimated to the new feed type. Animals are then switched to a finishing diet for a
period of time before they are slaughtered. The length of time an animal spends in a feedlot depends on the
start weight (i.e., placement weight), the rate of weight gain during the start-up and finishing phase of diet,
and the end weight (as determined by weights at slaughter). Weight gain during start-up diets is estimated
to be 2.8 to 3 pounds per day. Weight gain during finishing diets is estimated to be 3 to 3.3 pounds per day
(Johnson 1999). All animals are estimated to spend 25 days in the step-up diet phase (Johnson 1999).
Length of time finishing can be calculated based on start weight, weight gain per day, and target slaughter
weight.
• Pregnancy and lactation: Energy requirements and hence, composition of diets, level of intake, and
emissions for particular animals, are greatly influenced by whether the animal is pregnant or lactating.
Information is therefore needed on the percentage of all mature animals that are pregnant each month, as
well as milk production, to estimate methane emissions. A weighted average percent of pregnant cows
each month was estimated using information on births by month and average pregnancy term. For beef
cattle, a weighted average total milk production per animal per month was estimated using information on
typical lactation cycles and amounts (NR.C 1999), and data on births by month. This results in a range of
weighted monthly lactation estimates expressed as Ibs/animal/month. The monthly estimates from January
to December are 3.33, 5.06, 8.70, 12.01, 13.58, 13.32, 11.67, 9.34, 6.88, 4.45, 3.04, and 2.77. Monthly
estimates for dairy cattle were taken from USDA monthly milk production statistics.
• Death rates: This factor is applied to all heifer and steer cohorts to account for death loss within the model
on a monthly basis. The death rates are estimated by determining the death rate that results in model
estimates of the end-of-year population for cows that match the published end-of-year population census
statistics.
• Number of animals per category each month: The population of animals per category is calculated based
on number of births (or graduates) into the monthly age group minus those animals that die or are
slaughtered and those that graduate to next category (including feedlot placements). These monthly age
groups are tracked in the enteric fermentation model to estimate emissions by animal type on a regional
basis.
Table J-2 provides the cattle population estimates as output from the enteric fermentation model from 1990
through 1999. This table includes the population categories used in the model to estimate total emissions, including
tracking emissions that occur the following year for feedlot animals placed late in the year. Dairy lactation estimates
for 1990 through 1999 are shown in Table J-3. Table J-4 provides the target weights used to track average weights
of cattle by animal type. Table J-5 provides a summary of the reported feedlot placement statistics for 1999.
Cattle population data were taken from U.S. Department of Agriculture (USDA) National Agricultural
Statistics Service (NASS) reports. The USDA publishes monthly, annual, and multi-year livestock population and
production estimates. Multi-year reports include revisions to earlier published data. Cattle and calf populations,
feedlot placement statistics (e.g., number of animals placed in feedlots by weight class), slaughter numbers, and
lactation data were obtained from the USDA (1990-1999). Beef calf birth percentages were obtained from the
National Animal Health Monitoring System (NAHMS) (USDA/APfflS/VS 1998, 1994, 1993). Estimates of the
number of animals in different population categories of the model differ from the reported national population
statistics. This difference is due to model output indicating the average number of animals in that category for the
year rather than the end of year population census.
J-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Step 2. Characterize U.S. Cattle Population Diets
To support development of digestible energy (DE, the percent of gross energy intake digestible to the
animal) and methane conversion rate (Ym, the fraction of gross energy converted to methane) values for each of the
cattle population categories, data were collected on diets considered representative of different regions. For both
grazing animals and animals being fed mixed rations, representative regional diets were estimated using information
collected from state livestock specialists and from USDA (1996a). The data for each of the diets (e.g., proportions
of different feed constituents, such as hay or grains) were used to determine chemical composition for use in
estimating DE and Ym for each animal type. Additional detail on the regional diet characterization is provided in
EPA (2000).
DE and Ym were used to estimate methane emissions from enteric fermentation and vary by diet and animal
type. The IPCC recommends Ym values of 3.5 to 4.5 percent for feedlot cattle and 5.5 to 6.5 percent for all other
cattle. Given the availability of detailed diet information for different regions and animal types in the United States,
DE and Ym values unique to the United States2 were developed. Table J-6 shows the regional DE, the Ym, and
percent of total U.S. cattle population in each region based on 1999 data.
DE and Ym values were estimated for each cattle population category based on physiological modeling and
expert opinion. DE and Ym values for dairy cows and most grazing animals were estimated using a model (Donovan
and Baldwin 1999) that represents physiological processes in the ruminant animals. The three major categories of
input required by the model are animal description (e.g., cattle type, mature weight), animal performance (e.g.,
initial and final weight, age at start of period), and feed characteristics (e.g., chemical composition, habitat, grain or
forage). Data used to simulate ruminant digestion is provided for a particular animal that is then used to represent a
group of animals with similar characteristics. The model accounts for differing diets (i.e., grain-based, forage-based,
range- based), so that Ym values for the variable feeding characteristics within the U.S. cattle population can be
estimated.
For feedlot animals, DE and Ym values were taken from Johnson (1999). In response to peer reviewer
comments (Johnson 2000), values for dairy replacement heifers are based on EPA (1993).
Step 3. Estimate Methane Emissions from Cattle
Emissions were estimated in three steps: a) determine gross energy intake using the IPCC (2000) equations,
b) determine an emissions factor using the GE values and other factors, and c) sum the daily emissions for each
animal type. The necessary data values include:
• Body Weight (kg)
• Weight Gain (kg/day)
• Net Energy for Activity (Ca)^
• Standard Reference Weight4 (Dairy = 1,324 kg; Beef = 1,195 kg)
• Milk Production (kg/day)
• Milk Fat (percent of fat in milk = 4)
• Pregnancy (percent of population that is pregnant)
• DE (percent of gross energy intake digestible)
• Ym (the fraction of gross energy converted to methane)
2 In some cases, the Ym values used for this analysis extend beyond the range provided by the IPCC. However, EPA
believes that these values are representative for the U.S. due to the research conducted to characterize the diets of U.S. cattle and
to assess the Ym values associated with different animal performance and feed characteristics in the United States.
3 Zero for feedlot conditions, 0.17 for grazing conditions, 0.37 for high quality grazing conditions. Ca factor for dairy
cows is weighted to account for the fraction of the population in the region that grazes during the year.
Standard Reference Weight is used in the model to account for breed potential.
J-3
-------
Step 3a; Gross Energy, GE:
As shown in the following equation, Gross Energy (GE) is derived based on the net energy estimates and
the feed characteristics. Only variables relevant to each animal category are used (e.g., estimates for feedlot animals
do not require the NEi factor). All net energy equations are provided in IPCC (2000).
GE = [((NEm+ NEmobilized+ NE
where,
NEP) /
(NEg / {NEga/DE})] / (DE / 100)
GE =
NE-, =
NE| =
NEp =
NEg =
DE
gross energy (MJ/day)
net energy required by the animal for maintenance (MJ/day)
net energy due to weight loss (mobilized) (MJ/day)
net energy for animal activity (MJ/day)
net energy for lactation (MJ/day)
net energy required for pregnancy (MJ/day)
ratio of net energy available in a diet for maintenance to digestible energy consumed
net energy needed for growth (MJ/day)
ratio of net energy available for growth in a diet to digestible energy consumed
digestible energy expressed as a percentage of gross energy (percent)
Step 36; Emission Factor
The emissions factor (DayEmit) was determined using the GE value and the methane conversion factor
(Ym) for each category. This is shown in the following equation:
DayEmit = [GE X Ym] / [55.65 MJ/kg CHJ
where,
DayEmit = emission factor (kg CHLt/headVday)
GE = gross energy intake (MJ/head/day)
Ym= methane conversion rate which is the fraction of gross energy in feed converted to
methane (percent)
Emission factors were estimated for each animal type, weight and region. The implied national emission
factors for each of the animal categories are outlined in Table J-7.
Step 3c: Estimate Total Emissions
Emissions were summed for each month and for each population category using the daily emission factor
for a representative animal and the number of animals in the category. The following equation was used:
Emissions = DayEmit X Days/Month X SubPop
where,
DayEmit = the emission factor for the subcategory (kg CHyhead/day)
Days/Month = the number of days in the month
SubPop = the number of animals in the subcategory during the month
This process was repeated for each month, and the totals for each subcategory were summed to achieve an
emissions estimate for the entire year. For each of the 10 subcategories of cattle listed in Table J-8. The emissions
for each subcategory were then summed to estimate total emissions from beef cattle and dairy cattle for the entire
year. The total emissions from 1990 through 1999 are shown in Table J-9.
J-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Emission Estimates from Other Livestock
All livestock population data, except for horses, were taken from U.S. Department of Agriculture (USDA)
National Agricultural Statistics Service (NASS) reports. For each animal category, the USDA publishes monthly,
annual, and multi-year livestock population and production estimates. Multi-year reports include revisions to earlier
published data. Recent reports were obtained from the USDA Economics and Statistics System, while historical
data were downloaded from the USDA-NASS. The Food and Agriculture Organization (FAO) publishes horse
population data. These data were accessed from the FAOSTAT database at http://apps.fao.org/. Methane emissions
from sheep, goats, swine, and horses were estimated by multiplying published national population estimates by the
national emission factor for each year. Table J-10 shows the populations used for these other livestock from 1990 to
1999 and Table J-l 1 shows the emission factors used for these other livestock.
A complete time series of enteric fermentation emissions from livestock is shown in Table J-l2 (Tg COi
Eq.) and Table J-13 (Gg).
Table J-2: Estimates of Average Annual Populations of U.S. Cattle 1990-1999 (Thousand Head)
Livestock Type
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
Calves 0-6 months
Dairy
Cows
Replacements
Replacements
Beef
Cows
Replacements
Replacements
Steer Stackers
7-11 months
12-23 months
7-11 months
12-23 months
Heifer Stackers
Total Adjusted
Bulls
Feedlof
Total Placements6'0
22,561
10,015
1,214
2,915
32,454
1,269
2,967
8,639
5,103
10,494
2,160
25,587
22,531
9,965
1,219
2,874
32,520
1,315
3,063
8,215
4,903
10,368
2,196
25,396
22,707
9,728
1,232
2,901
33,007
1,402
3,182
9,303
5,143
10,339
2,239
25,348
23,004
9,658
1,230
2,926
33,365
1,465
3,393
9,066
4,971
9,840
2,278
25,586
23,346
9,528
1,228
2,907
34,650
1,529
3,592
10,378
5,846
10,660
2,312
26,615
23,468
9,487
1,220
2,905
35,156
1,492
3,647
10,126
5,729
11,252
2,385
27,623
23,255
9,416
1,205
2,877
35,228
1,462
3,526
9,457
5,451
11,289
2,384
27,580
22,810
9,309
1,182
2,838
34,271
1,378
3,391
9,008
5,560
11,460
2,350
28,560
22,557
9,191
1,192
2,797
33,683
1,322
3,212
8,703
5,365
11,449
2,270
27,149
22,594
9,133
1,176
2,839
33,745
1,306
3,106
8,276
5,218
12,881
2,281
29,812
Source: Enteric Fermentation Model.
a Total Adjusted Feedlot = Average number in feedlots accounting for current year plus the population carried over from the previous year (e.g., the "next
year" population numbers from this table are added into the following years "adjusted numbers").
6 Placements represent a flow of animals from backgrounding situations to feedlots rather than an average annual population estimate.
c Reported placements from USDA are adjusted using a scaling factor based on the slaughter to placement ratio.
Table J-3: Dairy Lactation by Region (Ibs- year/cow)41
Year
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
California
18,800
18,771
19,072
18,852
20,203
19,573
19,161
19,829
19,442
20,788
West
16,769
16,631
17,838
17,347
17,890
17,724
18,116
18,248
18,377
19,330
Northern Great
Plains
13,502
13,316
13,597
14,109
14,496
14,650
14,872
15,013
15,489
15,910
Southcenlral
12,397
12,389
12,710
13,034
13,236
13,228
13,215
13,212
13,580
13,476
Northeast
14,058
14,560
15,135
14,937
15,024
15,398
15,454
15,928
16,305
16,571
Midwest
14,218
14,555
15,028
15,203
15,374
15,728
15,596
16,027
16,494
16,655
Southeast
12,943
12,850
13,292
13,873
14,200
14,384
14,244
14,548
14,525
14,930
Source: USDA (2000d).
* Beef lactation data were developed using the methodology described in the text.
J-5
-------
Table J-4: Target Weights for Use in Estimating Average Weights and Weight Gains (Ibs)
Cattle Type
Typical Weights
Beef Replacement Heifer Data
Replacement Weight at 15 months
Replacement Weight at 24 months
Mature Weight at 36 months
Dairy Replacement Heifer Data
Replacement Weight at 15 months
Replacement Weight at 24 months
Mature Weight at 36 months
Stackers Data - Grazing/Forage Based Only
Steer Weight Gain/Month to 12 months
Steer Weight Gain/Month to 24 months
Heifer Weight Gain/Month to 12 months
Heifer Weight Gain/Month to 24 months
715"
1,078
1,172
800
1,225
1,350
45
35
35
30
Source: Feedstutfs (1998), Western Dairyman (1998), Johnson (1999), NRC (1999).
Table J-5: Feedlot Placements in the United States for 1999* (Number of animals placed in Thousand Head)
Weight When Placed Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total
< 600 Ibs
600 -700 Ibs
700 -800 Ibs
> 800 Ibs
379
628
604
322
333
497
606
372
357
468
744
462
293
387
572
436
290
430
722
607
295
377
634
488
333
400
578
501
494
486
734
714
629
557
758
815
1,027
802
692
593
766
657
416
331
465
498
422
261
5,661
6,187
7,482
5,902
Total 1,933 1.808 2,031 1,688 2,049 1,794 1,812 2,428 2,759 3,114 2,170 1,646 25,232
Source: USDA (1999b).
Note: Totals may not sum due to independent rounding.
* Data were available for 1996 through 1999. Data for 1990 to 1995 were based on the average of monthly placements from the 1996 to 1998 reported
figures.
J-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table J-6: Regional Digestible Energy (DE), Methane Conversion Rates (Ym), and population percentages for
Cattle in 1999
Animal Type Data California
West Northern Southcentral
Great Plains
Northeast Midwest Southeast
Beef Repl. Heif.a
Dairy Repl. Heif.a
Steer Stackers3
Heifer Stackers3
Steer Feedlof
Heifer Feedlof
Beef Cows3
Dairy Cows6
Steer Step-Up6''
Heifer Step-Up6
DE"
Ym°
Pop.d
DE
Ym
Pop.
DE
Ym
Pop.
DE
Ym
Pop.
DE
Ym
Pop.
DE
Ym
Pop.
DE
Ym
Pop.
DE
Ym
Pop.
DE
Ym
DE
Ym
67
8.0%
3%
66
5.9%
18%
67
8.0%
• 4%
67
8.0%
0%
85
3.0%
3%
85
3.0%
3%
67
8.0%
2%
69
4.8%
16%
76
5.5%
76
5.5%
66
7.4%
11%
66
5.9%
18%
66
7.4%
10%
66
7.4%
8%
85
3.0%
7%
85
3.0%
7%
66
7.4%
8%
66
5.8%
10%
76
5.5%
76
5.5%
68
8.0%
28%
66
5.6%
4%
68
8.0%
38%
68
8.0%
45%
85
3.0%
47%
85
3.0%
47%
68
8.0%
28%
69
5.8%
5%
76
5.5%
76
5.5%
66
8.3%
25%
64
6.4%
4%
66
8.3%
22%
66
8.3%
23%
85
3.0%
24%
85
3.0%
24%
66
8.3%
26%
68
5.7%
6%
76
5.5%
76
5.5%
64
8.4%
4%
68
6.3%
19%
64
8.4%
2%
64
8.4%
2%
85
3.0%
1%
85
3.0%
1%
64
8.4%
2%
69
5.8%
21%
76
5.5%
76
5.5%
68
8.0%
13%
66
5.6%
31%
68
8.0%
16%
68
8.0%
13%
85
3.0%
17%
85
3.0%
17%
68
8.0%
14%
69
5.8%
34%
76
5.5%
76
5.5%
68
7.8%
17%
66
6.9%
5%
68
7.8%
7%
68
7.8%
8%
85
3.0%
1%
85
3.0%
1%
68
7.8%
19%
68
5.6%
8%
76
5.5%
76
5.5%
a Beef and Dairy grazing DE and Ym values were applied to all grazing beef animals. It was assumed that pasture quality remains relatively consistent at a
regional scale.
b Digestible Energy in units of percent GE (MJ/Day).
c Methane Conversion Rate is the fraction of GE in feed converted to methane.
d Estimated percent of each subcategory population present in each region.
6 DE and Ym values for 1990 through 1992 are values from the previous livestock characterization reported in the 1993 Report to Congress. Values for
1993 through 1995 are the mean of current values and the 1993 Report to Congress values. Values for 1996 through 1999 are values from the most
recent livestock characterization.
' Characteristics of heifer and steer step-up diets (i.e., diets fed to animals entering feedlots) were assessed nationally to account for the difference
between initial and finishing diets for feedlot animals.
J-7
-------
Table J-7: Implied Emission Factors for Cattle in the United States (kg CHj/head/yr)
Animal Category
1990
1991 1992 1993 1994 1995 1996 1997 1998 1999
Calves 0-6 months
Dairy
Cows
Replacements 7-11 months
Replacements 12-23 months
Beef
Cows
Replacements 7-11 months
Replacements 12-23 months
Steer Stackers
Heifer Stackers
Total Feedlot
Bulls
0
113
40
63
83
47
73
64
56
47
100
0
114
40
63
83
47
73
64
56
47
100
0
117
40
63
83
47
73
64
57
47
100
0
111
40
63
83
47
73
64
57
40
100
0
113
40
63
83
47
73
64
58
39
100
0
113
40
63
83
47
73
64
57
39
100
0
107
40
63
83
47
73
64
57
34
100
0
109
40
63
83
47
73
64
57
33
100
0
110
40
63
83
48
74
64
57
34
100
0
111
40
63
82
47
74
64
57
33
100
"0" - assumed to be zero.
Source: Enteric Fermentation Model.
Table J-8: CH4 Emissions from Cattle (Gg)
Cattle Type
Dairy
Cows
Replacements 7-11 months
Replacements 12-23
Beef
Cows
months
Replacements 7-1 1 months
Replacements 12-23
Steer Stackers
Heifer Stackers
Feedlot Cattle
Bulls
Total
months
1990
1,369
1,136
49
184
4,511
2,682
59
217
553
288
496
216
5,880
1991
1,370
1,140
49
181
4,485
2,687
62
224
527
276
490
220
5,855
1992
1,368
1,135
49
183
4,628
2,728
66
233
598
292
488
224
5,996
1993
1,307
1,073
49
185
4,565
2,758
69
248
584
283
395
228
5,872
1994
1,307
1,074
49
184
4,851
2,865
72
263
669
337
415
231
6,158
1995
1,308
1,076
49
184
4,902
2,907
70
267
653
329
438
238
6,211
1996
1,241
1,010
48
182
4,781
2,912
68
258
606
311
387
238
6,022
1997
1,240
1,013
48
179
4,658
2,832
65
248
577
319
383
235
5,897
1998
1,234
1,010
48
177
4,561
2,784
63
239
557
307
385
227
5,796
1999
1,245
1,018
47
180
4,544
2,777
62
230
527
297
423
228
5,789
Note: Totals may not sum due to independent rounding.
Table J-9: Cattle Emissions (Tg C02 Eq.)
Cattle Type
Dairy
Beef
Total
1990
28
94
123
.7
.7
.5
1991
28.8
94.2
123.0
1992
28.7
97.2
125.9
1993
27.4
95.9
123.3
1994
27.4
101.9
129.3
1995
27.5
103.0
130.4
1996
26.1
100.4
126.5
1997
26.0
97.8
123.8
1998
25.9
95.8-
121.7
1999
26.1
95.4
121.6
Note: Totals may not sum due to independent rounding.
Table J-10: Other Livestock Populations 1990-1999 (Thousand Head)
Livestock Type
Sheep
Goats
Horses
Swine
1990
11,358
2,545
5,650
53,941
1991
11,174
2,475
5,650
56,478
1992
10,797
2,645
5,850
58,532
1993
10,201
2,605
5,900
58,016
1994
9,825
2,605
6,000
59,951
1995
8,982
2,495
6,000
58,899
1996
8,458
2,545
6,050
56,220
1997
8,015
2,295
6,150
58,728
1998
7,817
2,045
6,150
62,043
1999
7,215
1,995
6,180
59,407
Source: USDA (2000b,e 1999d-e,h, 1998, b-c, 1994a-b), FAO (2000).
J-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table J-11: Emission Factors for Other Livestock (kg Ctyhead/year)
Livestock Type
Emission Factor
Sheep
Goats
Horses
Swine
5
18
1.5
See Table J-7 for emissions factors for cattle.
Source: IPCC (2000).
Table J-12: CH4 Emissions from Enteric Fermentation (Tg C02 Eq.)
Livestock Type
Beef Cattle
Dairy Cattle
Horses
Sheep
Swine
Goats
Total
1990
94.7
28.7
2.1
1.9
1.7
0.3
129.5
1991
94.2
28.8
2.1
1.9
1.8
0.3
129.0
1992
97.2
28.7
2.2
1.8
1.8
0.3
132.1
1993
95.9
27.4
2.2
1.7
1.8
0.3
129.4
1994
101.9
27.4
2.3
1.7
1.9
0.3
135.4
1995
103.0
27.5
2.3
1.5
1.9
0.3
136.3
1996
100.4
26.1
2.3
1.4
1.8
0.3
132.2
1997
97.8
26.0
2.3
1.3
1.8
0.2
129.6
1998
95.8
25.9
2.3
1.3
2.0
0.2
127.5
1999
95.4
26.1
2.3
1.2
1.9
0.2
127.2
Table J-13: CH4 Emissions from Enteric Fermentation (Gg)
Livestock Type
Beef Cattle
Dairy Cattle
Horses
Sheep
Swine
Goats
1990
4,511
1,369
102
91
81
13
1991
4,485
1,370
102
89
85
12
1992
4,628
1,368
105
86
88
13
1993
4,565
1,307
106
82
87
13
1994
4,851
1,307
108
79
90
13
1995
4,902
1,308
108
72
88
12
1996
4,781
1,241
109
68
84 •
13
1997
4,658
1,240
111
64
88
11
1998
4,561
1,234
111
63
93
10
1999
4,544
1,245
111
58
89
10
Total
6,166 6,143 6,289 6,160 6,447 6.492 6,295 6,172
6,072
6,057
J-9
-------
J-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
ANNEX K
Methodology for Estimating CH4 and N20 Emissions from Manure Management
This annex presents a discussion of the methodology used to calculate methane and nitrous oxide emissions
from manure management systems. More detailed discussions of selected topics may be found in supplemental
memoranda in the supporting docket to this inventory.
The following steps were used to estimate methane and nitrous oxide emissions from the management of
livestock manure. Nitrous oxide emissions associated with pasture, range, or paddock systems and daily spread
systems are included in the emissions estimates for Agricultural Soil Management.
Step 1: Collect Livestock Population Characterization Data
Annual animal population data for 1990 through 1999 for all livestock types, except horses and goats, were
obtained from the USDA National Agricultural Statistics Service (USDA 1994a-b, 1995a-b, 1998a, 1999a-c, 2000a-
g). The actual population data used in the emissions calculations for cattle and swine were downloaded from the
USDA National Agricultural Statistics Service Population Estimates Data Base
(). Horse population data were obtained from the FAOSTAT database (FAO
2000). Goat population data for 1992 and 1997 were obtained from the Census of Agriculture (USDA 1999d).
Information regarding poultry turnover (i.e., slaughter) rate was obtained from state Natural Resource Conservation
Service personnel (Lange 2000).
A summary of the livestock population characterization data used to calculate methane and nitrous oxide
emissions is presented in Table K-l. Information on collection of population data for specific animal types is
provided in the following sections.
Dairy Cattle: The total annual dairy cow and heifer state population data for 1990 through 1999 are
provided in various USDA National Agricultural Statistics Service reports (USDA 1995a, 1999a, 2000a-b). The
actual total annual dairy cow and heifer state population data used in the emissions calculations were downloaded
from the U.S. Department of Agriculture National Agricultural Statistics Service Published Estimates Database
().
Beef Cattle: The total annual beef cattle population data for each state for 1990 through 1999 are provided
in various USDA National Agricultural Statistics Service reports (USDA 1995a, 1999a, 2000a-b). The actual data
used in the emissions calculations were downloaded from the U.S. Department of Agriculture National Agricultural
Statistics Service Published Estimates Database (). Additional information
regarding the percent of beef steer and heifers on feedlots was obtained from contacts with the national USDA office
(Milton 2000).
For all beef cattle groups (i.e., cows, heifers, steer, bulls, and calves), the USDA data provide cattle
inventories from January and July of each year. Cattle inventory changes over the course of the year, sometimes
significantly, as new calves are born and as fattened cattle are slaughtered; therefore, to develop the best estimate for
the annual animal population, the average inventory of cattle by state was calculated. The USDA provides January
inventory data for each state; however, July inventory data is only presented as a total for the United States. In order
to estimate average annual populations by state, a "scaling factor" was developed that adjusts the January state-level
data to reflect July inventory changes. This factor equals the average of the U.S. January and July data divided by
the January data. The scaling factor is derived for each cattle group and is then applied to the January state-level
data to arrive at the state-level annual population estimates.
Swine: The total annual swine population data for each state for 1990 through 1999 are provided in various
USDA National Agricultural Statistics Service reports (USDA 1994a, 1998a, 2000c). The USDA data provide
quarterly data for each swine subcategory: breeding, market under 60 pounds (<27 kg), market 60 to 119 pounds (27
to 54 kg), market 120 to 179 pounds (54 to 81 kg), and market 180 pounds and over (>82 kg). The average of the
quarterly data was used in the emissions calculations. For states where only December inventory is reported, the
December data were used directly. The actual data used in the emissions calculations were downloaded from the
K-1
-------
U.S. Department of Agriculture National Agricultural Statistics Service Published Estimates Database
().
Sheep: The total annual sheep population data for each state for 1990 through 1999 were obtained from
USDA National Agricultural Statistics Service (USDA 1994b, 1999c, 2000f). Population data for lamb and sheep
on feed were not available after 1993. The number of lamb and sheep on feed for 1994 through 1999 were
calculated using the average of the percent of lamb and sheep on feed from 1990 through 1993. In addition, all of
the sheep and lamb "on feed" are not necessarily on "feedlots"; they may be on pasture/crop residue supplemented
by feed. Data for those animals on feed that are on feedlots versus pasture/crop residue were provided only for lamb
in 1993. To calculate the populations of sheep and lamb on feedlots for all years, it was assumed that the percentage
of sheep and lamb on feed that are on feedlots versus pasture/crop residue is the same as that for lambs in 1993
(Anderson 2000).
Goats: Annual goat population data by state were available for only 1992 and 1997 (USDA 1999d). The
data for 1992 were used for 1990 through 1992 and the data for 1997 were used for 1997 through 1999. Data for
1993 through 1996 were interpolated using the 1992 and 1997 data.
Poultry: Annual Poultry population data by state for the various animal categories (i.e., hens 1 year and
older, pullets of laying age, pullets 3 months old and older not of laying age, pullets under 3 months of age, other
chickens, broilers, and turkeys) were obtained from USDA National Agricultural Statistics Service (USDA 1995b,
1998b, 1999b, 2000d,e,g). The annual population data for boilers and turkeys were adjusted for turnover (i.e.,
slaughter) rate (Lange 2000).
Horses: The Food and Agriculture Organization (FAO) publishes annual horse population data, which
were accessed from the FAOSTAT database at (FAO 2000).
Step 2: Develop Waste Characteristics Data
Methane and nitrous oxide emissions calculations are based on the following animal characteristics for
each relevant livestock population:
• Volatile solids excretion rate (VS)
• Maximum methane producing capacity (B0) for U.S. animal waste;
• Nitrogen excretion rate (Nex)
• Typical animal mass (TAM)
• Annual state-specific milk production rate
Published sources were reviewed for U.S.-specific livestock waste characterization data that would be
consistent with the animal population data discussed in Step 1. Data from the National Engineering Handbook,
Agricultural Waste Management Field Handbook (USDA 1996a) were chosen as the primary source of waste
characteristics. In some cases, data from the American Society of Agricultural Engineers, Standard D384.1 (ASAE
1999) were used to supplement the USDA data. The volatile solids and nitrogen excretion data for breeding swine
are a combination of the types of animals that make up this animal group, namely gestating and farrowing swine and
boars. It is assumed that a group of breeding swine is typically broken out as 80 percent gestating sows, 15 percent
farrowing swine, and 5 percent boars (Safley 2000). Table K-2 presents a summary of the waste characteristics used
in the emissions estimates.
The method for calculating volatile solids production from dairy cows was revised this year to better
address the relationship between milk production and volatile solids production. Cows that produce more milk per
year also produce more volatile solids in their manure due to their increased feed. Figure 4-1 in the Agricultural
Waste Management Field Handbook (USDA 1996a) was used to determine the mathematical relationship between
volatile solids production and milk production for a 1,400-pound dairy cow. The resulting best fit equation was a
second-order polynomial, defined as follows:
y = -7E-08x2 + 0.0029x - 16.765
R2 = 0.9858
where,
y = volatile solids (Ibs/day)
K-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
x = milk production (Ib/yr)
R2 = probability that a data point will be on the best fit line
Annual milk production data, published by USDA's National Agricultural Statistics Service (USDA
2000J), was accessed for each state and for each year. State-specific volatile solids production rates were then
calculated instead of a single national volatile solids excretion rate constant. Table K-3 presents the volatile solids
production rates used for 1999.
Step 3: Develop Waste Management System Usage Data
Estimates were made of the distribution of wastes by management system and animal type using the
following sources of information: '.
• State contacts to estimate the breakout of dairy cows on pasture, range, or paddock, and the percent of
wastes managed by daily spread systems (Deal 2000, Johnson 2000, Miller 2000, Stettler 2000, Sweeten
2000, Wright 2000)
• Data collected for EPA's Office of Water, including site visits, to medium and large beef feedlot, dairy,
swine, and poultry operations (ERG 2000)
• Contacts with the national USDA office to estimate the percent of beef steer and heifers on feedlots (Milton
2000)
• Survey data collected by USDA (2000h) and re-aggregated by farm size and geographic location, used for
small operations
• Survey data collected by the United Egg Producers (UEP 1999) and USDA (2000i) and previous EPA
estimates (EPA 1992) of waste distribution for layers
• Survey data collected by Cornell University on dairy manure management operations in New York (Poe
1999)
• Previous EPA estimates of waste distribution for sheep, goat, and horse operations (EPA 1992)
Beef Feedlots: Based on EPA site visits and state contacts, it was assumed that beef feedlot manure is
almost exclusively managed in drylots. Therefore, 100 percent of the manure excreted at beef feedlots is expected
to be deposited in drylots and generate emissions. In addition, a portion of the manure that is deposited in the drylot
will run off of the drylot during rain events and be captured in a waste storage pond. An estimate of the runoff has
been made by EPA's Office of Water for various geographic regions of the United States. These runoff estimates
were used to estimate emissions from runoff storage ponds located at beef feedlots. (ERG 2000).
Dairy Cows: Based on EPA site visits and state contacts, it was assumed that manure from dairy cows at
medium (200-700 head) and large (>700 head) operations were managed using either flush systems or scrape/slurry
systems. In addition, they may have a solids separator in place prior to their storage component. Estimates of the
percent of farms that use each type of system, by geographic region, were developed by EPA's Office of Water, and
were used to estimate the percent of wastes managed in lagoons (i.e., flush systems), liquid/slurry systems (i.e.,
scrape systems), and solid storage (i.e., separated solids) (ERG 2000).
Manure management system data for small (<200 head) dairies were obtained from USDA (2000h). These
operations are more likely to use liquid/slurry and solid storage management systems than anaerobic lagoon
systems. The reported manure management systems were deep pit, liquid/slurry (also includes slurry tank, slurry
earth-basin, and aerated lagoon), anaerobic lagoon, and solid storage (also includes manure pack, outside storage,
and inside storage). The percent of wastes by system was estimated using the USDA data broken out by geographic
region and farm size. Farm-size distribution data reported in the 1992 and 1997 Census of Agriculture
(USDA 1999e) were used to determine the percentage of all dairies using the various manure management systems.
Due to lack of additional data for other years, it was assumed that the data provided for 1992 were the same as that
for 1990 and 1991, and data provided for 1997 were the same as that for 1998 and 1999. Data for 1993 through
1996 were extrapolated using the 1992 and 1997 data.
Data regarding the use of daily spread and pasture, range, or paddock systems for dairy cattle were obtained
from personal communications with personnel from several organizations. These organizations include state NRCS
offices, state extension services, state universities, USDA National Agricultural Statistics Service (NASS), and other
experts (Deal 2000, Johnson 2000, Miller 2000, Stettler 2000, Sweeten 2000, and Wright 2000). Contacts at Cornell
K-3
-------
University provided survey data on dairy manure management practices in New York (Poe 1999). Census of
Agriculture population data for 1992 and 1997 (USDA 1999e) were used in conjunction with the state data obtained
from personal communications to determine regional percentages of total dairy cattle and dairy wastes that are
managed using these systems. These percentages were applied to the total annual dairy cow and heifer state
population data for 1990 through 1999, which were obtained from the USDA National Agricultural Statistics
Service (USDA 1995a, 1999a, 2000a-b).
Of the dairies using systems other than daily spread and pasture, range, or paddock systems, some dairies
reported using more than one type of manure management system. Therefore, the total percent of systems reported
by USDA for a region and farm size is greater than 100 percent. Typically, this means that some of the manure at a
dairy is handled in one system (e.g., liquid system), and some of the manure is handled in another system (e.g., dry
system). However, it is unlikely that the same manure is moved from one system to another. Therefore, to avoid
double counting emissions, the reported percentages of systems in use were adjusted to equal a total of 100 percent,
using the same distribution of systems. For example, if USDA reported that 65 percent of dairies use deep pits to
manage manure and 55 percent of dairies use anaerobic lagoons to manage manure, it was assumed that 54 percent
(i.e., 65 percent divided by 120 percent) of the manure is managed with deep pits and 46 percent (i.e., 55 percent
divided by 120percent) of the manure is managed with anaerobic lagoons (ERG 2000).
Dairy Heifers: The percent of dairy heifer operations that are pasture, range, or paddock or that operate as
daily spread was estimated using the same approach as dairy cows. Similar to beef cattle, dairy heifers are housed
on drylots when not pasture based. Based on data from EPA's Office of Water (ERG 2000), it was assumed that 100
percent of the manure excreted by dairy heifers is deposited in drylots and generates emissions. Estimates of runoff
have been made by EPA's Office of Water for various geographic regions of the US (ERG 2000).
Swine: Based on data collected during site visits for EPA's Office of Water (ERG 2000), manure from
swine at large (>2000 head) and medium (200 to 2000 head) operations were primarily managed using deep pit
systems, liquid/slurry systems, or anaerobic lagoons. Manure management system data were obtained from USDA
(1998d). It was assumed those operations with less than 200 head use pasture, range, or paddock systems. The
percent of waste by system was estimated using the USDA data broken out by geographic region and farm size.
Farm-size distribution data reported in the 1992 and 1997 Census of Agriculture (USDA 1999e) were used to
determine the percentage of all swine utilizing the various manure management systems. The reported manure
management systems were deep pit, liquid/slurry (also includes above- and below-ground slurry), anaerobic lagoon,
and solid storage (also includes solids separated from liquids).
Some swine operations reported using more than one management system; therefore, the total percent of
systems reported by USDA for a region and farm size is greater than 100 percent. Typically, this means that some
of the manure at a swine operation is handled in one system (e.g., liquid system), and some of the manure is handled
in another system (e.g., dry system). However, it is unlikely that the same manure is moved from one system to
another. Therefore, to avoid double counting emissions, the reported percentages of systems in use were adjusted to
equal a total of 100 percent, using the same distribution of systems, as explained under "Dairy Cows."
Sheep: It was assumed that all sheep wastes not deposited on feedlots were deposited on pasture, range, or
paddock lands (Anderson 2000).
Goats/Horses: Estimates of manure management distribution were obtained from EPA (1992).
Poultry - Layers: Waste management system data for layers for 1990 were obtained from Appendix H of
Global Methane Emissions from Livestock and Poultry Manure (EPA 1992). The percentage of layer operations
using a shallow pit flush house with anaerobic lagoon or high-rise house without bedding was obtained for 1999
from United Egg Producers, voluntary survey (UEP 1999). These data were augmented for key poultry states (i.e.,
AL, AR, CA, FL, GA, IA, IN, MN, MO, NC, NE, OH, PA, TX, and WA) with USDA data (USDA 2000i). It was
assumed that the change in system usage between 1990 and 1999 was proportionally distributed among those years.
It was also assumed that one percent of poultry wastes were deposited on pasture, range, or paddock lands (EPA
1992).
Poultry - Broilers/Turkeys: The percentage of turkeys and broilers on pasture or in high-rise houses without
bedding was obtained from Global Methane Emissions from Livestock and Poultry Manure (EPA 1992). It was
assumed that one percent of poultry wastes were deposited in pastures, range, and paddocks (EPA 1992).
K-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Step 4: Calculate Base Emission Factor Calculations
Base methane conversion factors (MCFs) and nitrous oxide emission factors used in the emission
calculations were determined using the methodologies described below:
Methane Conversion Factors (MCFs)
Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC
2000) for anaerobic lagoon systems published default methane conversion factors of 0 percent to 100 percent, which
reflects the wide range in performance that may be achieved with these systems. There exist relatively few data
points on which to determine country-specific MCFs for these systems. Therefore, a climate-based approach was
identified to estimate MCFs for anaerobic lagoon and other liquid storage systems.
The following approach was used to develop the base MCFs for liquid/slurry and deep pit systems, and is
based on the van't Hoff-Arrhenius equation used to forecast performance of biological reactions. One practical way
of estimating MCFs for liquid manure handling systems is based on the mean ambient temperature and the van't
Hoff-Arrhenius equation with a base temperature of 30°C, as shown in the following equation (Safley and
Westerman 1990):
where,
Ti =
T2 =
E =
R =
RT,T,
303.16K
ambient temperature (K) for climate zone (in this case, a weighted value for each state)
activation energy constant (15,175 cal/mol)
ideal gas constant (1.987 cal/K mol)
The factor "f' correlates well to the MCF values suggested by IPCC for liquid/slurry and deep pit systems
at a given temperature, and represents the proportion of volatile solids that are biologically available for conversion
to methane based on the temperature of the system. Therefore, the MCF for liquid/slurry and deep pit systems is set
equal to the factor "f shown above. For those animal populations using liquid systems (i.e., dairy cow, dairy heifer,
layers, beef on feedlots, and swine), annual average state temperatures were based on the counties where the specific
animal population resides (i.e., the temperatures were weighted based on the percent of animals located in each
county). The average county and state temperature data were obtained from the National Climate Data Center
(NOAA 2000), and the county population data were based on 1992 and 1997 Census data (USDA 1999e). County
population data for 1990 and 1991 were assumed to be the same as 1992, county population data for 1998 and 1999
were assumed to be the same for 1997, and county population data for 1993 through 1996 were extrapolated based
on 1992 and 1997 data.
The approach used to calculate the base MCF for anaerobic lagoons is also based on the van't Hoff-
Arrhenius equation, but is calculated on a monthly basis to account for the longer retention time and associated build
up of volatile solids in these systems. Base annual MCFs for anaerobic lagoons are calculated as follows for each
animal type, state, and year of the inventory:
1) Monthly temperatures are calculated by using county-level temperature and population data. The
weighted-average temperature for a state is calculated using the population estimates and average
monthly temperature in each county.
2) Monthly temperatures are used to calculate a monthly van't Hoff-Arrhenius "f' factor, using the
equation presented above.
3) Monthly production of volatile solids that are added to the system is estimated based on the number of
animals present, adjusted for a management and design practices factor. This factor accounts for other
mechanisms by which volatile solids are removed from the management system prior to conversion to
methane, such as solids being removed from the lagoon for application to cropland. This factor, equal
to 0.8, has been estimated using currently available methane measurement data from anaerobic lagoon
systems in the United States.
K-5
-------
4) The amount of volatile solids available for conversion to methane is assumed to be equal to the amount
of volatile solids produced during the month (from Step 3) plus volatile solids that may remain in the
system from previous months.
5) The amount of volatile solids consumed during the month is equal to the amount available for
conversion multiplied by the "f' factor.
6) The amount of volatile solids carried over from one month to the next is equal to the amount available
for conversion minus the amount consumed.
7) The estimated amount of methane generated during the month is equal to the monthly volatile solids
consumed multiplied by the maximum methane potential of the waste (B0).
8) The annual anaerobic lagoon MCF is then calculated as:
MCF (annual) = CELj generated (annual) / (VS generated (annual) x B0)
In order to account for the carry over of volatile solids from the year prior to the inventory year for which
estimates are calculated, it is assumed in the MCF calculation for lagoons that a portion of the volatile solids from
October, November, and December of the year prior to the inventory year are available in the lagoon system starting
January of the inventory year.
Following this procedure, the resulting MCF accounts for temperature variation throughout the year,
residual volatile solids in a system (carryover), and management and design practices that may reduce the volatile
solids available for conversion to methane. The base methane conversion factors presented in Table in by state and
waste management system represent the average MCF by state for all animal groups located in that state. However,
hi the calculation of methane emissions, specific MCFs for each animal type in the state are used.
Nitrous Oxide Emission Factors
Base N2O emission factors for all manure management systems were set equal to the default IPCC factors
OPCC 2000).
Step 5: Develop Weighted Emission Factors
For beef cattle, dairy cattle, swine, and poultry, the base emission factors for both CUt and N2O were then
weighted to incorporate the distribution of wastes by management system for each state. The following equation
was used to determine the weighted MCF for a particular animal type in a particular state:
MCFanimal, state = ^^ (MCFsystem, state X Monureanimal, system, state)
system
where,
Weighted MCF for that animal group and state
Base MCF for that system and state (see Step 4)
= Percent of manure managed in the system for that animal group in that state
(expressed as a decimal)
The weighted NaO emission factor for a particular animal type in a particular state was determined as
follows:
EFanimal, state = / t (EFsystem X Mcmweanimal, system, state)
system
where,
state = Weighted EF for that animal group and state
- Base EF for that system (see Step 4)
system, state= Percent of manure managed in the system for that animal group in that state
(expressed as a decimal)
K-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Data for tbe calculated weighted factors for 1992 were taken from the 1992 Census of Agriculture,
combined with assumptions on manure management system usage based on farm size. These values were also used
for 1990 and 1991. Data for the calculated weighted factors for 1997 came from the 1997 Census of Agriculture,
combined with assumptions on manure management system usage based on farm size, and were also used for 1998
and 1999. Factors for 1993 through 1996 were calculated by interpolating between the two sets of factors. A
summary of the weighted MCFs used to calculate beef feedlot, dairy cow and heifer, swine, and poultry emissions
for 1999 are presented in Table K-5.
Step 6: Calculate Methane and Nitrous Oxide Emission Calculations
For beef feedlot cattle, dairy cows, dairy heifers, swine, and poultry, methane emissions were calculated for
each animal group as follows:
Methane animal group = ^(Population XVSxBoXMCFanin,al,SlateXQ.662)
where,
state
ai group = methane emissions for that animal group
Population = annual average state animal population for that animal group (head)
VS = total volatile solids produced annually per animal (kg/yr/head)
B0 = maximum methane producing capacity per kilogram of VS (m3 CILi/kg VS)
MCFanima!, state = weighted MCF for the animal group and state (see Step 5)
0.662 = conversion factor of m3 CHL, to kilograms CH, (kg CH4 /m3 CHO
Methane emissions from other animals (i.e., sheep, goats, and horses) were based on the 1990 methane
emissions estimated using the detailed method described in Anthropogenic Methane Emissions in the United States:
Estimates for 1990, Report to Congress (EPA 1993). This approach is based on animal-specific manure
characteristics and management system data. This process was not repeated for subsequent years for these other
animal types. Instead, national populations of each of the animal types were used to scale the 1990 emissions
estimates to the period 1991 through 1999.
Nitrous oxide emissions were calculated for each animal group as follows:
NilTOUS Oxide animal group = ^ (Population X Nex X EFanlmal, state X 44 / 28)
where,
NitrOUS Oxid
Population =
Nex=
•*-*•!* animal, state
44/28 =
group = nitrous oxide emissions for that animal group (kg/yr)
annual average state animal population for that animal group (head)
total Kjeldahl nitrogen excreted annually per animal (kg/yr/head)
weighted nitrous oxide EF for the animal group and state (see Step 5)
conversion factor for N2O-N to N2O
Emission estimates are summarized in Table K-6 and Table K- 7.
K-7
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Table K-3: Estimated Dairy Cow Volatile Solids Production Rate By State for 1999
Stale
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Volatile Solids1
(kg/day/1000 kg)
7.05
6.95
9.36
6.48
9.11
9.11
8.36
7.63
7.51
7.87
7.07
8.98
7.93
7.80
8.24
7.85
6.47
6.17
7.93
7.80
8.03
8.44
8.20
7.29
7.09
8.04
7.58
8.88
8.05
7.93
9.00
8.14
7.98
7.12
8.11
6.94
8.57
8.30
7.62
7.58
7.37
7.32
7.87
8.24
8.07
7.63
9.49
7.54
8.06
6.84
1 Volatile solids production estimates based on state average annual milk production rates, combined with a mathematical relationship of volatile solids to
milk production (USDA 1996a).
K-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table K-4: Base Methane Conversion Factors by State for Liquid/Slurry Systems for 1999
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Liquid/Slurry
0.3439
0.0564
0.3507
0.3173
0.2398
0.1447
0.1762
0.2346
0.5333
0.3449
0.5103
0.1401
0.2033
0.1986
0.1665
0.2277
0.2480
0.4201
0.1281
0.2230
0.1659
0.1437
0.1264
0.3628
0.2404
0.1292
0.1806
0.2022
0.1289
0.2148
0.2094
0.1500
0.2766
0.1152
0.1899
0.3033
0.1588
0.1727
0.1929
0.3134
0.1481
0.2728
0.4284
0.1760
0.1299
0.2309
0.1590
0.2003
0.1376
0.1224
Anaerobic Lagoon
0.7524
0.4589
0.7863
0.7595
0.7529
0.6344
0.6997
0.7364
0.7597
0.7492
0.7422
0.6400
0.7157
0.7114
0.6918
0.7371
0.7389
0.7642
0.6488
0.7234
0.6895
0.6756
0.6711
0.7570
0.7358
0.6059
0.7050
0.6761
0.6544
0.7220
0.7228
0.6704
0.7387
0.6343
0.7027
0.7627
0.6279
0.7036
0.7027
0.7498
0.6802
0.7426
0.7726
0.6842
0.6493
0.7179
0.6353
0.7029
0.6650
0.6213
Deep Pit
0.3439
0.0564
0.3507
0.3173
0.2398
0.1447
0.1762
0.2346
0.5333
0.3449
0.5103
0.1401
0.2033
0.1986
0.1665
0.2277
0.2480
0.4201
0.1281
0.2230
0.1659
0.1437
0.1264
0.3628
0.2404
0.1292
0.1806
0.2022
0.1289
0.2148
0.2094
0.1500
0.2766
0.1152
0.1899
0.3033
0.1588
0.1727
0.1929
0.3134
0.1481
0.2728
0.4284
0.1760
0.1299
0.2309
0.1590
0.2003
0.1376
0.1224
K-11
-------
Table K-5: Weighted Methane Conversion Factors for 1999
State
Alabama
Alaska
Arizona
Arkansas
California
Colorado
Connecticut
Delaware
Florida
Georgia
Hawaii
Idaho
Illinois
Indiana
Iowa
Kansas
Kentucky
Louisiana
Maine
Maryland
Massachusetts
Michigan
Minnesota
Mississippi
Missouri
Montana
Nebraska
Nevada
New Hampshire
New Jersey
New Mexico
New York
North Carolina
North Dakota
Ohio
Oklahoma
Oregon
Pennsylvania
Rhode Island
South Carolina
South Dakota
Tennessee
Texas
Utah
Vermont
Virginia
Washington
West Virginia
Wisconsin
Wyoming
Beef
Feedlot-
Heifer
0.0195
0.0157
0.0165
0.0190
0.0185
0.0156
0.0168
0.0174
0.0216
0.0194
0.0216
0.0156
0.0162
0.0162
0.0160
0.0164
0.0175
0.0205
0.0163
0.0171
0.0167
0.0159
0.0158
0.0197
0.0164
0.0155
0.0161
0.0156
0.0163
0.0170
0.0159
0.0165
0.0177
0.0157
0.0161
0.0162
0.0171
0.0168
0.0169
0.0191
0.0159
0.0177
0.0165
0.0157
0.0163
0.0172
0.0171
0.0170
0.0158
0.0155
Beef
Feedlot-
Steer
0.0195
0.0157
0.0167
0.0189
0.0187
0.0156
0.0168
0.0174
0.0216
0.0194
0.0216
0.0155
0.0162
0.0162
0.0160
0.0164
0.0175
0.0205
0.0163
0.0171
0.0167
0.0159
0.0158
0.0197
0.0164
0.0155
0.0161
0.0156
0.0164
0.0170
0.0159
0.0165
0.0177
0.0157
0.0161
0.0162
0.0170
0.0168
0.0169
0.0191
0.0159
0.0177
0.0164
0.0157
0.0163
0.0172
0.0172
0.0170
0.0159
0.0155
Dairy Cow
0.0979
0.1346
0.5879
0.0716
0.4967
0.3957
0.0933
0.0854
0.4080
0.1399
0.5116
0.4089
0.0995
0.0834
0.0802
0.0985
0.0378
0.1076
0.0526
0.0804
0.0655
0.1333
0.0708
0.0904
0.0925
0.2221
0.0837
0.4796
0.0597
0.0717
0.5027
0.0785
0.0606
0.0491
0.0858
0.3285
0.2527
0.0515
0.0341
0.0996
0.0721
0.0511
0.4963
0.3368
0.0701
0.0478
0.3067
0.0605
0.0798
0.2020
Dairy
Heifer
0.0184
0.0156
0.0161
0.0181
0.0177
0.0155
0.0164
0.0169
0.0201
0.0184
0.0201
0.0154
0.0160
0.0160
0.0158
0.0161
0.0170
0.0192
0.0160
0.0167
0.0163
0.0158
0.0157
0.0186
0.0162
0.0154
0.0159
0.0155
0.0161
0.0166
0.0157
0.0162
0.0171
0.0156
0.0159
0.0159
0.0166
0.0164
0.0165
0.0182
0.0157
0.0172
0.0161
0.0155
0.0160
0.0168
0.0167
0.0166
0.0157
0.0154
Swine -
Market
0.4619
0.0150
0.4822
0.5179
0.4741
0.2174
0.1219
0.2884
0.2035
0.4704
0.3508
0.1615
0.2643
0.2598
0.3619
0.2786
0.4202
0.1919
0.0150
0.2571
0.1660
0.2354
0.2287
0.5373
0.2843
0.1942
0.2506
0.0150
0.1008
0.1631
0.0150
0.1704
0.5556
0.1858
0.2477
0.5299
0.0999
0.2657
0.1677
0.4825
0.2279
0.3951
0.5055
0.2491
0.0150
0.4669
0.1824
0.1806
0.2139
0.2166
Swine -
Breeding
0.4631
0.0150
0.4822
0.5215
0.4717
0.2172
0.1207
0.2884
0.2044
0.4677
0.3508
0.1605
0.2642
0.2600
0.3633
0.2786
0.4189
0.1912
0.0150
0.2568
0.1655
0.2343
0.2284
0.5383
0.2839
0.1941
0.2502
0.0150
0.1000
0.1653
0.0150
0.1701
0.5543
0.1864
0.2481
0.5391
0.0993
0.2648
0.1677
0.4805
0.2282
0.3942
0.5055
0.2477
0.0150
0.4674
0,1803
0.1799
0.2136
0.2143
Layer
0.3237
0.1260
0.4798
0.0150
0.1058
0.3832
0.0494
0.0498
0.3265
0.3203
0.1968
0.3804
0.0293
0.0150
0.0150
0.0295
0.0511
0.4653
0.0469
0.0511
0.0487
0.0284
0.0150
0.4596
0.0150
0.3721
0.0289
0.0150
0.0472
0.0503
0.4503
0.0478
0.3181
0.0270
0.0150
0.4658
0.1656
0.0150
0.0480
0.4564
0.0282
0.0514
0.1063
0.4217
0.0463
0.0500
0.0879
0.0497
0.0280
0.3763
Broiler
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
Turkey
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
0.0150
K-12 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table K-6: CH4 Emissions from Livestock Manure Management (Gg)
Animal Type
Dairy Cattle
Dairy Cows
Dairy Heifer
Swine
Market Swine
Market <60 Ib.
Market 60-11 9 Ib.
Market 120-1 79 Ib.
Market >1 80 Ib.
Breeding Swine
Beef Cattle
Feedlot Steers
Feedlot Heifers
NOF Bulls
NOF Calves
NOF Heifers
NOF Steers
NOF Cows
Sheep
Goats
Poultry
Hens >1 yr.
Total Pullets
Chickens
Broilers
Turkeys
Horses
1990
422
412
10
527
409
86
86
115
122
118
150
22
11
6
15
14
9
74
3
1
125
31
61
4
19
10
29
1991
451
441
10
549
425
89
90
119
127
123
154
23
12
6
15
14
9
74
3
1
125
29
62
4
20
10
29
1992
448
438
10
568
444
92
93
124
135
124
154
22
11
6
15
15
10
75
3
1
122
32
57
4
21
10
30
1993
464
454
10
555
436
89
90
124
134
119
158
23
12
6
15
15
9
77
3
1
126
33
58
4
21
10
30
1994
503
493
10
620
489
99
100
138
152
131
162
23
12
6
15
16
10
79
3
1
127
33
58
4
22
9
31
1995
527
517
10
630
502
100
102
141
160
128
165
23
12
7
16
17
10
80
2
1
122
32
56
4
21
9
31
1996
532
523
10
610
487
97
98
137
155
123
164
22
12
7
16
17
11
80
2
1
123
31
55
3
24
9
31
1997
561
552
10
670
537
107
109
151
171
133
162
23
13
6
15
16
10
78
2
1
126
31
58
3
25
9
31
1998
583
573
9
770
624
122
125
174
203
146
160
23
13
6
15
16
10
77
2
1
130
33
59
4
25
8
31
1999
593
583
10
728
595
114
118
166
197
133
159
23
14
6
15
15
9
77
2
1
124
30
56
3
26
8
31
Note: Totals may not sum due to independent rounding.
K-13
-------
Table K- 7: N20 Emissions from Livestock Manure Management (Gg)
Animal Type
Dairy Cattle
Dairy Cows
Dairy Heifer
Swine
Market Swine
Market <60 Ib.
Market 60-11 9 Ib.
Market 120-179 Ib.
Market >180lb.
Breeding Swine
Beef Cattle
Feedlot Steers
Feedlot Heifers
Sheep
Goals
Poultry
Hens >1 yr.
Pullets
Chickens
Broilers
Turkeys
Horses
1990
13.6
9.2
4.4
1.0
0.7
0.2
0.0
0.3
0.3
0.3
15.8
10.6
5.2
0.1
0.1
20.5
0.7
1.0
0.0
12.0
6.7
0.7
1991
13.3
9.0
4.4
1.0
0.7
0.2
0.0
0.3
0.3
0.3
17.3
11.5
5.8
0.1
0.1
20.9
0.7
1.0
0.0
12.5
6.6
0.7
1992
13.2
8.7
4.4
1.1
0.8
0.2
0.0
0.3
0.3
0.3
16.2
11.0
5.2
0.1
0.1
21.3
0.7
1.0
0.0
13.1
6.5
0.7
1993
13.1
8.6
4.5
1.1
0.8
0.2
0.0
0.3
0.3
0.3
17.3
11.5
5.7
0.1
0.1
21.6
0.7
0.9
0.0
13.7
6.3
0.7
1994
12.9
8.4
4.6
1.1
0.8
0.2
0.0
0.3
0.3
0.3
17.0
11.3
5.7
0.1
0.1
22.1
0.7
0.9
0.0
14.3
6.1
0.7
1995
12.9
8.3
4.6
1.1
0.8
0.2
0.0
0.3
0.3
0.3
17.1
11.2
5.9
0.1
0.1
20.9
0.6
0.8
0.0
13.3
6.1
0.7
1996
12.6
8.2
4.5
1.1
0.8
0.2
0.0
0.3
0.3
0.3
16.5
10.7
5.8
0.1
0.1
23.2
0.6
0.8
0.0
15.5
6.2
0.7
1997
12.4
8.0
4.5
1.1
0.8
0.2
0.0
0.3
0.3
0.3
17.4
11.1
6.4
0.1
0.1
23.3
0.6
0.8
0.0
15.9
6.0
0.8
1998
12.3
7.8
4.5
1.2
0.9
0.2
0.0
0.3
0.4
0.3
17.8
11.3
6.4
0.1
0.1
23.2
0.6
0.8
0.0
16.2
5.6
0.8
1999
12.3
7.7
4.6
1.2
0.9
0.2
0.0
0.3
0.4
0.3
17.9
11.3
6.6
0.1
0.1
23.2
0.6
0.8
0.0
16.7
5.1
0.8
+ Less than 0.5 Gg
Note: Totals may not sum due to independent rounding,
K-14 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
ANNEX L
Methodology for Estimating N20 Emissions from Agricultural Soil Management
Nitrous oxide (N2O) emissions from agricultural soil management covers activities that add nitrogen (N) to
soils, and thereby enhance natural emissions of N2O. The IPCC methodology (IPCC/UNEP/OECD/IEA 1997, IPCC
2000), which is followed, divides this source category into three components: (1) direct N2O emissions from
managed soils; (2) direct N2O emissions from pasture, range, and paddock livestock manure; and (3) indirect N2O
emissions from soils induced by applications of nitrogen.
There are four steps in estimating N2O emissions from agricultural soil management. First, the activity
data are derived for each of the three components. Note that some of the data used in the first component are also
used in the third component. In the second, third, and fourth steps, N2O emissions from each of the three
components are estimated. The remainder of this annex describes these steps, and data used in these steps, in detail.
Step 1: Derive Activity Data
The activity data for this source category are annual amounts of nitrogen added to soils for each relevant
activity, except for histosol cultivation, for which the activity data are annual histosol areas cultivated.1 The activity
data are derived from statistics, such as fertilizer consumption data or livestock population data, and various factors
used to convert these statistics to annual amounts of nitrogen, such as fertilizer nitrogen contents or livestock
excretion rates. Activity data were derived for each of the three components, as described below.
Step 1a. Direct N20 Emissions from Managed Soils.
The activity data for this component include: a) the amount of synthetic and organic commercial fertilizer
nitrogen applied annually, b) the amount of livestock manure nitrogen applied annually through both daily spread
operations and the eventual application of manure that had been stored in manure management systems, c) the
amount of sewage sludge nitrogen applied annually, d) the amount of aboveground biomass nitrogen in nitrogen-
fixing crops produced annually, e) the amount of nitrogen in crop residues applied to soils annually, and f) the area
of histosols cultivated annually.
Application of synthetic and organic commercial fertilizer: Annual commercial fertilizer consumption data
for the United States were taken from annual publications of synthetic and organic fertilizer statistics (TVA 1991,
1992a, 1993, 1994; AAPFCO 1995, 1996, 1997, 1998, 1999). These data were manipulated in several ways to
derive the activity data needed for the inventory. First, the manure and sewage sludge portions of the organic
fertilizers were subtracted from the total organic fertilizer consumption data because these nitrogen additions are
accounted for under "manure application" and "sewage sludge application."2 Second, the organic fertilizer data,
which are recorded in mass units of fertilizer, had to be converted to mass units of nitrogen by multiplying by the
average organic fertilizer nitrogen contents provided in the annual fertilizer publications. These nitrogen contents
are weighted average values, so they vary from year-to-year (ranging from 2.3 percent to 3.9 percent over the period
1990 through 1999). The synthetic fertilizer data are recorded in units of nitrogen, so these data did not need to be
converted. Lastly, both the synthetic and organic fertilizer consumption data are recorded in "fertilizer year" totals
(i.e., July to June), therefore the data was converted to calendar year totals. This was done by assuming that
approximately 35 percent of fertilizer usage occurred from July to December, and 65 percent from January to June
(TVA 1992b). July to December values were not available for calendar year 1999, so a "least squares line"
statistical extrapolation using the previous ten years of data was used to arrive at an approximate value. Annual
Histosols are soils with a high organic carbon content.
2 Organic fertilizers included in these publications are manure, compost, dried blood, sewage sludge, tankage, and
"other." (Tankage is dried animal residue, usually freed from fat and gelatin). The manure and sewage sludge used as
commercial fertilizer are accounted for elsewhere, so these were subtracted from the organic fertilizer statistics to avoid double
counting.
L-1
-------
consumption of commercial fertilizers—synthetic and non-manure/non-sewage organic—in units of nitrogen and on
a calendar year basis are presented in Table L-l.
Application of livestock manure: To estimate the amount of livestock manure nitrogen applied to soils, it
was assumed that all of the manure produced by livestock would be applied to soils with two exceptions. These
exceptions were: (1) the portion of poultry manure that is used as a feed supplement for ruminants, and (2) the
manure that is deposited on soils by livestock on pasture, range, and paddock. In other words, all of the manure that
is managed, except the portion of poultry manure that is used as a feed supplement, is assumed to be applied to soils.
The amount of managed manure for each livestock type was calculated by determining the population of animals
that were on feedlots or otherwise housed in order to collect and manage the manure. In some instances, the number
of animals in managed systems was determined by subtracting the number of animals in pasture, range, and paddock
from the total animal population for a particular animal type.
Annual animal population data for all livestock types, except horses and goats, were obtained from the
USDA National Agricultural Statistics Service (USDA 1994b-c, 1995a-b, 1998a, 1998c, 1999a-c, 2000a-g). Horse
population data were obtained from the FAOSTAT database (FAO 2000). Goat population data were obtained from
the Census of Agriculture (USDA 1999d). Information regarding poultry turnover (i.e., slaughter) rate was obtained
from state Natural Resource Conservation Service personnel (Lange 2000). Additional population data for different
farm size categories for dairy and swine were obtained from the Census of Agriculture (USDA 1999e).
Information regarding the percentage of manure handled using various manure management systems for
dairy cattle, beef cattle, and sheep was obtained from communications with personnel from state Natural Resource
Conservation Service offices, state universities, National Agricultural Statistics Service, and other experts (Poe et al.
1999, Anderson 2000, Deal 2000, Johnson 2000, Miller 2000, Milton 2000, Stettler 2000, Sweeten 2000, Wright
2000). Information regarding the percentage of manure handled using various manure management systems for
swine, poultry, goats, and horses was obtained from Safley et al. (1992). A more detailed discussion of manure
management system usage is provided in Annex K under Manure Management.
Once the animal populations for each livestock type and management system were estimated, these
populations were then multiplied by an average animal mass constant (USDA 1996a, USDA 1998c, ASAE 1999,
Safley 2000) to derive total animal mass for each animal type in each management system. Total Kjeldahl nitrogen3
excreted per year for each livestock type and management system was then calculated using daily rates of nitrogen
excretion per unit of animal mass (USDA 1996a, ASAE 1999). The total poultry manure nitrogen in managed
systems was reduced by the amount assumed to be used as a feed supplement (i.e., 4.2 percent of the managed
poultry manure; Carpenter 1992). The annual amounts of Kjeldahl nitrogen were then summed over all livestock
types and management systems to derive estimates of the annual manure nitrogen applied to soils (Table L-2).
Application of sewage sludge: Data collected by the EPA were used to derive estimates of annual nitrogen
additions from land application of sewage sludge. Sewage sludge is generated from the treatment of raw sewage in
public or private wastewater treatment works. Based on a 1988 questionnaire returned from 600 publicly owned
treatment works (POTWs), the EPA estimated that 5.4 million metric tons of dry sewage sludge were generated by
POTWs in the United States in that year (EPA 1993). Of this total, 43.7 percent was applied to land, including
agricultural applications, compost manufacture, forest land application, the reclamation of mining areas, and other
forms of surface disposal. An additional 33.9 percent of the total generated was disposed in landfills, 16.1 percent
was incinerated, and 6.3 percent was dumped into the oceans (EPA 1993). In 1997, the EPA conducted a
nationwide state-by-state study that estimated that approximately 7 million metric tons of dry sewage sludge were
generated by 12,000 POTWs (Bastian 1999). The same study concluded that 54 percent of sewage sludge generated
that year was applied to land. Sewage sludge production increased between 1988 and 1997 due to increases in the
number of treatment plants and the magnitude of industrial wastewater treated, as well as changes in sewage
treatment techniques. The proportion of sewage sludge applied to land increased due to the passage of legislation in
1989 that banned all ocean dumping of sewage, as well as stricter laws regulating the use of landfills for sewage
disposal (Bastian 1999).
Annual estimates of sewage sludge nitrogen applied to land for the 1990 to 1999 period were derived
through the following process. To estimate annual amounts of dry sewage sludge applied to land in 1990 through
^ Total Kjeldahl nitrogen is a measure of organically bound nitrogen and ammonia nitrogen in both the solid and liquid
wastes.
L-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
1997, the 1988 and 1997 data for sewage sludge production and percent land applied were linearly interpolated.
Since 1997, growth in annual production and the percent land applied is believed to have leveled off (Bastian 1999),
so the 1998 and 1999 estimates of sewage production and percent land applied were held constant at 1997 levels.
Between 1 and 6 percent of dry weight sewage sludge is nitrogen, both in organic and inorganic form (National
Research Council 1996). Therefore, to covert from metric ton of dry sludge to metric ton of nitrogen, an average 4
percent nitrogen content was used. Final estimates of annual land application of sewage sludge nitrogen are
presented in Table L-l.
Production of nitrogen-fixing crops: Annual production statistics for beans, pulses, and alfalfa were taken
from U.S. Department of Agriculture crop production reports (USDA 1994a, 1997, 1998b, 1999f, 2000i). Annual
production statistics for the remaining nitrogen-fixing crops (i.e., the major non-alfalfa forage crops, specifically red
clover, white clover, birdsfoot trefoil, arrowleaf clover, and crimson clover) were derived from information in a
book on forage crops (Taylor and Smith 1995, Pederson 1995, Beuselinck and Grant 1995, Hoveland and Evers
1995), and personal communications with forage experts (Cropper 2000, Evers 2000, Gerrish 2000, Hoveland 2000,
and Pederson 2000).
The production statistics for beans, pulses, and alfalfa were in tons of product, which needed to be
converted to tons of aboveground biomass nitrogen. This was done by multiplying the production statistics by one
plus the aboveground residue to crop product mass ratios, dry matter fractions, and nitrogen contents. The residue to
crop product mass ratios for all beans and pulses, and the dry matter content for soybeans, were obtained from
Strehler and Stutzle (1987). The dry matter content for peanuts was obtained through personal communications with
Jen Ketzis (1999), who accessed Cornell University's Department of Animal Science's computer model, Cornell
Net Carbohydrate and Protein System. The dry matter content for soybeans was used for all other beans and pulses.
The dry matter content for alfalfa was obtained through personal communications with Karkosh (2000). The IPCC
default nitrogen content of 3 percent (IPCC/UNEP/OECD/IEA 1997) was used for all beans, pulses, and alfalfa.4
The production statistics for the non-alfalfa forage crops were derived by multiplying estimates of areas
planted by estimates of annual yields, in dry matter mass units. These derived production statistics were then
converted to units of nitrogen by applying the IPCC default nitrogen content of 3 percent (IPCC/UNEP/OECD/IEA
1997).
The final estimates of annual aboveground biomass production, in units of nitrogen, are presented in Table
L-3. The residue to crop product mass ratios and dry matter fractions used in these calculations are presented in
Table L-6.
Application of crop residue: It was assumed that 90 percent of residues from corn, wheat, barley, sorghum,
oats, rye, millet, soybeans, peanuts, and other beans and pulses are either plowed under or left on the field (Karkosh
2000).5 It was also assumed that 100 percent of unburned rice residue is applied to soils.6
The derivation of residue nitrogen activity data was very similar to the derivation of nitrogen-fixing crop
activity data. Crop production statistics were multiplied by aboveground residue to crop product mass ratios,
residue dry matter fractions, residue nitrogen contents, and the fraction of residues applied to soils. Annual
production statistics were taken from U.S. Department of Agriculture (USDA 1994a, 1997, 1998b, 1999f, 2000i).
Residue to crop product ratios for all crops were obtained from Strehler and Stutzle (1987). Dry matter contents for
wheat, rice, corn, and barley residue were obtained from Turn et al. (1997). Soybean and millet residue dry matter
contents were obtained from Strehler and Stutzle (1987). Peanut, sorghum, oat, and rye residue dry matter contents
were obtained through personal communications with Jen Ketzis (1999), who accessed Cornell University's
Department of Animal Science's computer model, Cornell Net Carbohydrate and Protein System. The residue
nitrogen contents for wheat, rice, corn, and barley are from Turn et al. (1997). The nitrogen content of soybean
4 This nitrogen content likely overestimates for the residue portion of the aboveground biomass of the beans and
pulses. Also, the dry matter fractions used for beans and pulses were taken from literature on crop residues, and so may under
estimate the product portion of the aboveground biomass. These data will be refined in future inventories.
5 Although the mode of residue application would most likely affect the magnitude of emissions, a methodology for
estimating N2O emissions for these two practices separately has not been developed.
6 Some of the rice residue may be used for other purposes, such as for biofuel or livestock bedding material. Research
to obtain more detailed information regarding final disposition of rice residue, as well as the residue of other crops, will be
undertaken for future inventories.
L-3
-------
residue is from Barnard and Kristoferson (1985), the nitrogen contents of peanut, sorghum, oat, and rye residue are
from Ketzis (1999), and the nitrogen content of millet residue is from Strehler and Stutzle (1987). Estimates of the
amounts of rice residue burned annually were derived using information obtained from agricultural extension agents
in each of the rice-growing states (see Rice Cultivation section of Agriculture Chapter for more detail).
The final estimates of residue applied to soil, in units of nitrogen (N), are presented in Table L-4. The
residue to crop product mass ratios, residue dry matter fractions, and residue nitrogen contents used in these
calculations are presented hi Table L-6.
Cultivation of histosols: Statistics on the areas of histosols cultivated in 1982, 1992, and 1997 were
obtained from the USDA's 1992 and 1997 National Resources Inventories (USDA 1994d and 2000h, as cited in
Paustian 1999 and Sperow 2000, respectively).7 These areas were linearly interpolated to obtain estimates for 1990
through 1997, and linearly extrapolated to obtain area estimates for 1998 and 1999 (Table L-5).
Step 1b. Direct NZ0 Emissions from Pasture, Range, and Paddock Livestock Manure.
Estimates of N^O emissions from this component were based on livestock manure that is not managed in
manure management systems, but instead is deposited directly on soils by animals in pasture, range, and paddock.
The livestock included in this component were: dairy cattle, beef cattle, swine, sheep, goats, poultry, and horses.
Dairy Cattle: Information regarding dairy farm grazing was obtained from communications with personnel
from state Natural Resource Conservation Service offices, state universities, and other experts (Poe et al. 1999, Deal
2000, Johnson 2000, Miller 2000, Stettler 2000, Sweeten 2000, Wright 2000). Because grazing operations are
typically related to the number of animals on a farm, farm-size distribution data reported in the 1992 and 1997
Census of Agriculture (USDA1999e) were used in conjunction with the state data obtained from personal
communications to determine the percentage of total dairy cattle that graze. An overall percent of dairy waste that is
deposited in pasture, range, and paddock was developed for each region of the United States. This percentage was
applied to the total annual dairy cow and heifer state population data for 1990 through 1999, which were obtained
from the USDA National Agricultural Statistics Service (USDA 1995a, 1999a, 2000a,b).
Beef Cattle: To determine the population of beef cattle that are on pasture, range, and paddock, the
following assumptions were made: 1) beef cows, bulls, and calves were not housed on feedlots; 2) a portion of
heifers and steers were on feedlots; and 3) all beef cattle that were not housed on feedlots were located on pasture,
range, and paddock (i.e., total population minus population on feedlots equals population of pasture, range, and
paddock) (Milton 2000). Information regarding the percentage of heifers and steers on feedlots was obtained from
USDA personnel (Milton 2000) and used hi conjunction with USDA National Agricultural Statistics Service
population data (USDA 1995a, 1999a, 2000a,b) to determine the population of steers and heifers on pasture, range,
and paddock.
Swine: Based on the assumption that smaller facilities are less likely to utilize manure management
systems, farm-size distribution data reported in the 1992 and 1997 Census of Agriculture (USDA 1999e) were used
to determine the percentage of all swine whose manure is not managed (i.e., the percentage on pasture, range, and
paddock). These percentages were applied to the average of the quarterly USDA National Agricultural Statistics
Service population data for swine (USDA 1994b, 1998a, 2000e) to determine the population of swine on pasture,
range, and paddock.
Sheep: It was assumed that all sheep and lamb manure not deposited on feedlots was deposited on pasture,
range, and paddock (Anderson 2000). Sheep population data were obtained from the USDA National Agricultural
Statistics Service (USDA 1994c, 1999c, 2000g). However, population data for lamb and sheep on feed were not
available after 1993. The number of lamb and sheep on feed for 1994 through 1999 were calculated using the
average of the percent of lamb and sheep on feed from 1990 through 1993. In addition, all of the sheep and lamb
"on feed" were not necessarily on "feedlots"; they may have been on pasture/crop residue supplemented by feed.
Data for those feedlot animals versus pasture/crop residue were provided only for lamb in 1993. To calculate the
? The estimates of cultivated histosol areas are uncertain because they were derived from a natural resource inventory
that was not explicitly designed as a soil survey. However, these areas are consistent with those used in the organic soils
component of the Land-Use Change and Forestry Chapter. These area statistics will be researched further in future U.S.
Inventories.
L-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
populations of sheep and lamb on feedlots for all years, it was assumed that the percentage of sheep and lamb on
feedlots versus pasture/crop residue is the same as that for lambs in 1993 (Anderson 2000).
Goats: It was assumed that 92 percent of goat manure was deposited on pasture, range, and paddock
(Safley et al. 1992). Annual goat population data by state were available for only 1992 and 1997 (USDA 1999d).
The data for 1992 were used for 1990 through 1992 and the data for 1997 were used for 1997 through 1999. Data
for 1993 through 1996 were extrapolated using the 1992 and 1997 data.
Poultry: It was assumed that one percent of poultry manure was deposited on pasture, range, and paddock
(Safley et al. 1992). Poultry population data were obtained from USDA National Agricultural Statistics Service
(USDA 1995b, 1998a, 1999b, 2000c, 2000d, 2000f). The annual population data for boilers and turkeys were
adjusted for turnover (i.e., slaughter) rate (Lange 2000).
Horses: It was assumed that 92 percent of horse manure was deposited on pasture, range, and paddock
(Safley et al. 1992). Horse population data were obtained from the FAOSTAT database (FAO 2000).
For each animal type, the population of animals within pasture, range, and paddock systems was multiplied
by an average animal mass constant (USDA 1996, ASAE 1999, USDA 1998d, Safley 2000) to derive total animal
mass for each animal type. Total Kjeldahl nitrogen excreted per year was then calculated for each animal type using
daily rates of nitrogen excretion per unit of animal mass (USDA 1996, ASAE 1999). Annual nitrogen excretion was
then summed over all animal types to yield total nitrogen in pasture, range, and paddock manure (Table L-2).
Step 1c. Indirect N20 Emissions from Soils Induced by Applications of Nitrogen.
This component accounts for N2O that is emitted indirectly from nitrogen applied as commercial fertilizer,
sewage sludge, and livestock manure. Through volatilization, some of this nitrogen enters the atmosphere as NHs
and NOX, and subsequently returns to soils through atmospheric deposition, thereby enhancing NiO 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. The activity data for commercial fertilizer and sewage sludge are the
same as those used in the calculation of direct emissions from managed soils (Table L-l). The activity data for
livestock manure are different from those used in other calculations. Here, total livestock manure (i.e., the sum of
managed manure and manure in pasture, range, and paddock) is used. These data are presented in Table L-2.
Table L-1: Commercial Fertilizer Consumption & Land Application of Sewage Sludge (Gg N)
Fertilizer Type
Synthetic
Other Organics*
Sewage Sludge
1990
10,105
3
106
1991
10,262
6
112
1992
10,324
6
118
1993
10,718
6
124
1994
11,162
6
131
1995
10,798
8
137
1996
11,158
10
144
1997
11,172
12
151
1998
11,187
12
151
1999
11,262
11
151
Excludes manure and sewage sludge used as commercial fertilizer.
Table L-2: Livestock Manure Nitrogen (Gg)
Activity
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
Applied to Soils
Pasture, Range, & Paddock
Total Manure
2,610 2,680 2,688 2,723 2,748 2,740
4,173 4,192 4,295 4,339 4,453 4,513
6,815 6,905 7,016 7,096 7,227 7,258
2,746 2,803 2,833 2,832
4,507 4,375 4,285 4,246
7,290 7,215 7,155 7,115
L-5
-------
Table L-3: Aboveground Biomass Nitrogen in Nitrogen-Fixing Crops (Gg)
Crop Type
Soybeans
Peanuts
Dry Edible Beans
Diy Edible Peas
Austrian Winter Peas
Lentils
Wrinkled Seed Peas
Alfalfa
Red Clover
White Clover
Birdsfoot Trefoil
Arrowleaf Clover
Crimson Clover
Total
1990
4,241
84
119
7
+
5
3
1,730
513
2,735
99
67
21
9,624
1991
4,374
115
124
11
+
8
3
1,729
513
2,735
99
67
21
9,799
1992
4,823
100
83
8
+
6
2
1,642
513
2,735
99
67
21
10,098
1993
4,117
79
80
10
+
7
3
1,666
513
2,735
99
65
19
9,394
1994
5,538
99
106
7
+
7
2
1,687
513
2,735
99
63
18
10,874
1995
4,788
81
113
14
+
8
3
1,753
513
2,735
99
61
17
10,184
1996
5,241
86
102
8
+
5
2
1,647
513
2,735
99
58
16
10,512
1997
5,921
83
108
17
+
9
2
1,641
513
2,735
99
56
14
11,198
1998
6,036
93
112
18
+
7
2
1,708
513
2,735
99
54
13
11,389
1999
5,820
91
122
15
+
9
2
1,731
513
2,735
99
52
12
11,200
+ Less than 0.5 Gg nitrogen.
Note: Totals may not sum due to independent rounding.
Table L-4: Nitrogen in Crop Residues Applied to Soils (Gg)
Product Type
Corn
Wheat
Barley
Sorghum
Oats
Rye
Millet
Rice
Soybeans
Peanuts
Dry Edible Beans
Dry Edible Peas
Austrian Winter Peas
Lentils
Wrinkled Seed Peas
Total
+ Less than 0.5 Gg nitrogen.
1990
957
501
71
180
39
2
3
54
1,982
13
15
1
+
1
+
3,821
1991
902
364
78
184
27
2
3
56
2,045
18
16
1
+
1
+
3,696
1992
1,143
453
77
275
32
2
3
64
2,254
16
10
1
+
1
+
4,332
1993
765
440
67
168
23
2
3
55
1,926
13
10
1
+
1
+
3,473
1994
1,219
426
63
206
25
2
3
69
2,633
16
13
1
+
1
+
4,678
1995
890
401
61
145
18
2
3
62
2,241
13
14
2
+
1
+
3,850
1996
1,121
418
67
253
17
1
3
59
2,452
14
13
1
+
1
+
4,420
1997
1,130
456
63
205
19
1
3
66
2,807
13
14
2
+
1
+
4,781
1998
1,177
468
59
164
18
2
3
70
2,821
15
14
2
+
1
+
4,814
1999
1,139
423
47
187
16
2
3
79
2,720
14
15
2
+
1
+
4,649
Note: Totals may not sum due to independent rounding.
Table L-5: Cultivated Histosoi Area (Thousand Hectares)
Year Area
1990 1
1991 1
1992
1993
1994
1995
1996
1997
1998
1999
,013
,005
998
994
991
987
984
980
977
973
L-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table L-6: Key Assumptions for Nitrogen-Fixing Crop Production and Crop Residue Application
Residue/Crop Ratio Residue Dry Residue
Crop Matter Fraction
Soybeans
Peanuts
Dry Edible Beans
Dry Edible Peas
Austrian Winter Peas
Lentils
Wrinkled Seed Peas
Alfalfa
Corn
Wheat
Barley
Sorghum
Oats
Rye
Millet
Rice
2.1
1.0
2.1
1.5
1.5
2.1
1.5
0
1.0
1.3
1.2
1.4
1.3
1.6
1.4
1.4
0.87
0.86
0.87
0.87
0.87
0.87
0.87
0.85
0.91
0.93
0.93
0.91
0.92
0.90
0.89
0.91
Nitrogen Fraction
0.023
0.0106
0.0062
0.0062
0.0062
0.0062
0.0062
NA
0.0058
0.0062
0.0077
0.0108
0.007
0.0048
0.007
0.0072
Note: For the derivation of activity data for nitrogen-fixing crop production, the IPCC default nitrogen content of aboveground biomass (3 percent) was
used.
Step 2: Estimate Direct N20 Emissions from Managed Soils Due to Nitrogen Additions and Cultivation of
Histosols
In this step, N2O emissions were calculated for each of two parts (direct N2O emissions due to nitrogen
additions and direct N2O emissions due to histosol cultivation), which were then summed to yield total direct N2O
emissions from managed soils (Table L-7).
Step 2a. Direct N20 Emissions Due to Nitrogen Additions.
To estimate these emissions, the amounts of nitrogen applied were each reduced by the IPCC default
fraction of nitrogen that is assumed to volatilize, the unvolatilized amounts were then summed, and the total
unvolatilized nitrogen was multiplied by the IPCC default emission factor of 0.0125 kg N2O-N/kg Nitrogen
(IPCC/UNEP/OECD/TEA 1997). The volatilization assumptions are described below.
• Application of synthetic and organic commercial fertilizer: The total amounts of nitrogen applied in the
form of synthetic commercial fertilizers and non-manure/non-sewage organic commercial fertilizers were
reduced by 10 percent and 20 percent, respectively, to account for the portion that volatilizes to NH3 and
NOX (IPCC/UNEP/OECD/IEA 1997).
• Application of livestock manure: The total amount of livestock manure nitrogen applied to soils was
reduced by 20 percent to account for the portion that volatilizes to NH3 and NOX (IPCC/UNEP/OECD/IEA
1997).
• Application of sewage sludge: The total amount of sewage sludge nitrogen applied to soils was reduced by
20 percent to account for the portion that volatilizes to NH3 and NOX (IPCC/UNEP/OECD/IEA 1997, IPCC
2000).
• Production of nitrogen-fixing crops: None of the nitrogen from the aboveground biomass of nitrogen-fixing
crops was assumed to volatilize.
• Application of crop residue: None of the nitrogen in applied crop residue was assumed to volatilize.
L-7
-------
Step 2b. Direct NJ3 Emissions Due to Cultivation ofHistosols.
To estimate annual N2O emissions from histosol cultivation, the histosol areas were multiplied by the IPCC
default emission factor for temperate soils (8 kg N2O-N/ha cultivated; IPCC 2000).8
Step 3: Estimate Direct N20 Emissions from Pasture, Range, and Paddock Livestock Manure
To estimate direct N2O emissions from soils due to the deposition of pasture, range, and paddock manure,
the total nitrogen excreted by these animals was multiplied by the IPCC default emission factor (0.02 kg N2O-N/kg
N excreted) (see Table L-8).
Step 4: Estimate Indirect N20 Emissions Induced by Applications of Nitrogen
In this step, N2O emissions were calculated for each of two parts (indirect N2O emissions due to
volatilization of applied nitrogen and indirect N2O emissions due to leaching and runoff of applied nitrogen) which
were then summed to yield total direct N2O emissions from managed soils.
Step 4a. Indirect Emissions Due to Volatilization.
To estimate these emissions, first the amounts of commercial fertilizer nitrogen and sewage sludge nitrogen
applied, and the total amount of manure nitrogen produced, were each multiplied by the IPCC default fraction of
nitrogen that is assumed to volatilize to NH3 and NOX (10 percent for synthetic fertilizer nitrogen; and 20 percent for
nitrogen in organic fertilizer, sewage sludge, and livestock manure). Next, the volatilized amounts of nitrogen were
summed, and then the total volatilized nitrogen was multiplied by the IPCC default emission factor of 0.01 kg N20-
N/kg N (TPCC/UNEP/OECD/IEA 1997). These emission estimates are presented in Table L-9.
Step 4b. Indirect Emissions Due to Leaching and Runoff.
To estimate these emissions, first the amounts of commercial fertilizer nitrogen and sewage sludge nitrogen
applied, and the total amount of manure nitrogen produced, were each multiplied by the IPCC default fraction of
nitrogen that is assumed to leach and runoff (30 percent for all nitrogen). Next, the leached/runoff amounts of
nitrogen were summed, and then the total nitrogen was multiplied by the IPCC default emission factor of 0.025 kg
N20-N/kg N (IPCC/UNEP/OECD/IEA 1997). These emission estimates are presented in Table L-9.
Table L-7: Direct N20 Emissions from Managed Soils (Tg C02 Eq.)
Activity
Commercial Fertilizers*
Livestock Manure
Sewage Sludge
Nitrogen Fixation
Crop Residue
Histosol Cultivation
Total
1990
55
13
1
59
23
4
154
1991
56
13
1
60
23
4
156
1992
57
13
1
61
26
4
162
1993
59
13
1
57
21
4
155
1994
61
13
1
66
28
4
174
1995
59
13
1
62
23
4
163
1996
61
13
1
64
27
4
170
1997
61
14
1
68
29
4
177
1998
61
14
1
69
29
4
178
1999
62
14
1
68
28
4
177
Note: Totals may not sum due to independent rounding.
* These data do not include sewage sludge and livestock manure used as commercial fertilizers, to avoid double counting.
8 Part of the total U.S. cultivated histosol area is in subtropical regions. These areas should probably be assigned a
higher emission factor. This issue will be researched in future U.S. Inventories.
L-8 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table L-8: Direct N20 Emissions from Pasture, Range, and Paddock Livestock Manure (Tg C02 Eq.)
Animal Type
Beef Cattle
Dairy Cows
Swine
Sheep
Goats
Poultry
Horses
Total
1990
35
2
2
41
1991
35
2
1
2
41
1992
36
2
1
3
42
1993
37
2
3
42
1994
38
2
3
43
1995
39
1
3
44
1996
39
1
3
44
1997
38
1
3
43
1998
37
1
3
42
1999
37
1
3
41
+ Less than 0.5 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
Table L-9: Indirect N20 Emissions (Tg COZ Eq.)
Activity
Volatil. & Atm. Deposition
Comm. Fertilizers
Animal Manure
Sewage Sludge
Surface Leaching & Runoff
Comm. Fertilizers
Animal Manure
Sewage Sludge
Total
1990
12
5
7
+
62
37
25
+
74
1991
12
5
7
+
63
38
25
+
75
1992
12
5
7
+
64
38
26
+
76
1993
12
5
7
+
66
39
26
+
78
1994
13
5
7
+
68
41
26
+
80
1995
12
5
7
+
67
39
27
1
79
1996
13
5
7
+
68
41
27
1
81
1997
13
5
7
+
68
41
26
1
80
1998
13
5
7
+
68
41
26
1
80
1999
13
5
7
+
68
41
26
1
80
+ Less than 0.5 Tg C02 Eq.
Note: Totals may not sum due to independent rounding.
L-9
-------
L-10 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
ANNEX M
Methodology for Estimating CH4 Emissions from Landfills
Landfill methane (CH4) is produced from a complex process of waste decomposition and subsequent
fermentation under anaerobic conditions. The amount and rate of methane production depends upon the
characteristics of the landfilled material and the surrounding environment. To estimate the amount of methane
produced hi a landfill in a given year, the following information is needed: the quantity of waste in the landfill, the
waste characteristics, the residence time of the waste in the landfill, and the landfill capacity.
The amount of methane emitted from a landfill is less than the amount produced in a landfill. If no
measures are taken to extract the methane, a portion of it will oxidize as it travels through the top layer of the landfill
cover. The portion of the methane that oxidizes turns primarily to carbon dioxide (CC^). If the methane is extracted
and combusted (e.g., flared or used for energy), then that portion of the methane produced in the landfill will not be
emitted as methane, but again, would be oxidized to CO2. In general, landfill related CO2 emissions are of biogenic
origin and primarily result from the decomposition, either aerobic or anaerobic, of organic matter such as food or
yard wastes.1
Methane emissions are primarily driven by the quantity of waste in landfills. From an analysis of the
population of municipal solid waste (MSW) landfills, landfill-specific data were extracted and used in an emissions
model to estimate the amount of methane produced by municipal solid waste. Although not explicitly modeled,
methane emissions from industrial landfills were assumed to be seven percent of the total methane generated from
MSW at landfills. Total methane emissions were estimated by adding the methane from MSW landfills, subtracting
the amount recovered or used for energy or flared, subtracting the amount oxidized in the soil, and adding emissions
from industrial landfills. The steps taken to estimate emissions from U.S. landfills for the years 1990 through 1999
are discussed in greater detail below.
Step 1: Estimate Municipal Solid Waste-in-Place Contributing to Methane Emissions
First, landfills were characterized as of 1990 based on a landfill survey (EPA 1988). Each landfill was
characterized in terms of its year of opening, waste acceptance during operation, year of closure, and design
capacity. Following characterization of the landfill population, waste was simulated to be placed in these landfills.
For 1991 through 1999, waste disposal estimates were based on annual BioCycle (2000) data.2 Landfills were
simulated to open and close based on waste disposal rates. If landfills reached their design capacity, they were
simulated to close. New landfills were simulated to open when a significant shortfall in disposal capacity was
predicted. Simulated new landfills were assumed to be larger, on average, reflecting the trend toward fewer and
more centralized facilities. The analysis updated the landfill characteristics each year, calculating the total waste-in-
place and the profile of waste disposal over time. Table M-l shows the amount of waste landfilled each year and the
total estimated waste-in-place contributing to methane emissions.
Step 2: Estimate Landfill Methane Production
Emissions for each landfill were estimated by applying the emissions model (EPA 1993) to the landfill
waste-in-place contributing to methane production. Total emissions were then calculated as the sum of emissions
from all landfills.
1 Emissions and sinks of biogenic carbon are accounted for in the Land-Use Change and Forestry chapter.
2 At the time this section was prepared, BioCycle had not yet published its 1999 estimate for the percent of the total
waste landfilled, so the previous year's figure (61 percent) was used.
M-1
-------
Step 3: Estimate Industrial Landfill Methane Production
Industrial landfills receive waste from factories, processing plants, and other manufacturing activities.
Because no data were available on methane generation at industrial landfills, emissions from industrial landfills
were assumed to equal seven percent of the total methane emitted from MSW landfills (EPA 1993). These
emissions are shown in Table M-2.
Step 4: Estimate Methane Emissions Avoided
The estimate of methane emissions avoided was based on landfill-specific data on flares and landfill gas-to-
energy (LFGTE) projects. The quantity of methane flared—without an LFGTE system—was based on data
collected from flaring equipment vendors. These data included information on the quantity of flares, landfill gas
flow rates, and year of flare installation. Total methane recovered was estimated by summing the median landfill
gas flow rate for each flare provided by flaring equipment vendors. However, several vendors provided information
on the size of flare rather than landfill gas flow rate. Consequently, for flares associated with these vendors, the size
of the flare was matched with the size and corresponding flow rate provided by the other vendors to estimate a
median flow rate. The quantity of methane avoided due to LFGTE systems was estimated based on data in a
database compiled by EPA's Landfill Methane Outreach Program. Using data on landfill gas flow and energy
generation, the total direct methane emissions avoided were estimated. To avoid double counting flares associated
with LFGTE projects, the flare estimates were adjusted to account for LFGTE projects for which an associated flare
could not be identified.
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 ten percent of the methane produced, minus
the amount of gas recovered for flaring or LFGTE projects, was oxidized in the soil (Liptay et al. 1998).
Step 6: Estimate Total Methane Emissions
Total methane emissions were calculated by adding emissions from MSW and industrial waste, and
subtracting methane recovered and oxidized, as shown in Table M-2.
Table M-1: Municipal Solid Waste (MSW) Contributing to Methane Emissions (Tg unless otherwise noted)
Description 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
Total MSW Generated3 267 255 265 279 293 297 297 309 340 354
Percent of MSW Landfilled* 77% 76% 72% 71% 67% 63% 62% 61% 61% 61%
Total MSW Landfilled 206 194 191 198 196 187 184 189 207 216
MSW Contributing to Emissions" 4.926 5,027 5,162 5,292 5,428 5,560 5,677 5.791 5,907 6036
1 Source: BioCycle (2000). Tlie data, originally reported in short tons, are converted to metric tons.
"The EPA emissions model (EPA 1993) defines all waste that has been in place for less than 30 years as contributing to methane emissions.
M-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Table M-2: Methane Emissions from Landfills (Gg)
Activity
MSW Generation
Large Landfills
Medium Landfills
Small Landfills
Industrial Generation
Potential Emissions
Emissions Avoided
Landfill Gas-to-Energy
Flare
Oxidation
Net Emissions
1990
11,599
4,780
5,545
1,273
731
12,330
(1,984)
(702)
(213)
(1,068)
10,346
1991
11,837
4,817
5,720
1,300
746
12,583
(2,224)
(743)
(413)
(1,068)
10,358
1992
12,168
4,883
5,954
1,332
767
12,935
(2,446)
(799)
(566)
(1,080)
10,489
1993
12,499
4,950
6,190
1,359
787
13,286
(2,699)
(881)
(729)
(1,089)
10,588
1994
12,848
5,039
6,425
1,385
809
13,657
(3,049)
(1,002)
(958)
(1,089)
10,609
1995
13,220
5,130
6,682
1,407
833
14,053
(3,438)
(1,037)
(1,314)
(1,087)
10,614
1996
13,492
5,200
6,869
1,423
850
14,342
(3,906)
(1,159)
(1,683)
(1,065)
10,435
1997
13,776
5,281
7,058
1,438
868
14,644
(4,273)
(1,372)
(1,846)
(1,056)
10,371
1998
14,017
5,352
7,212
1,453
883
14,900
(4,729)
(1,720)
(1,977)
(1,032)
10,171
1999
14,350
5,454
7,425
1,471
904
15,254
(5,033)
(2,034)
(1,964)
(1,035)
10,221
Note: Totals may not sum due to independent rounding.
Table M-3: Municipal Solid Waste Landfill Size Definitions (Gg)
Description
Waste-in-Place
Small Landfills
Medium Landfills
Large Landfills
<400
400-2,000
> 2,000
M-3
-------
M-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
ANNEX N
Global Warming Potential Values
A Global Warming Potential (GWP) is intended as a quantified measure of the globally averaged relative
radiative forcing impacts of a particular greenhouse gas (see Table N-l). 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 itself is a greenhouse gas.
Indirect radiative forcing occurs when chemical transformations involving the original gas produces a gas or gases
that are greenhouse gases, or when a gas influences the atmospheric lifetimes of other gases. The reference gas used
is CO2, and therefore GWP weighted emissions are measured in teragrams of CO2 equivalents (Tg CO2 Eq.)1 The
relationship between gigagrams (Gg) of a gas and Tg CO2 Eq. can be expressed as follows:
(Tff ^
—
l,OOOGgJ
where,
Tg CO2 Eq. = Teragrams of Carbon Dioxide Equivalents
Gg = Gigagrams (equivalent to a thousand metric tons)
GWP = Global Warming Potential
Tg = Teragrams (equivalent to a million metric tons)
GWP values allow policy makers to compare the impacts of emissions and reductions of different gases.
According to the IPCC, GWPs typically have an uncertainty of ±35 percent (IPCC 1996). The parties to the
UNFCCC have also agreed to use GWPs based upon a 100 year time horizon although other time horizon values are
available.
In addition to communicating emissions in units of mass, Parties may choose also to use global
warming potentials (GWPs) to reflect their inventories and projections in carbon dioxide-equivalent terms,
using information provided by the Intergovernmental Panel on Climate Change (IPCC) in its Second
Assessment Report. Any use of GWPs should be based on the effects of the greenhouse gases over a 100-
year time horizon. In addition, Parties may also use other time horizons.2
Greenhouse gases with long atmospheric lifetimes (e.g., CO2, Cft,, N2O, HFCs, PFCs, and SF6) tend to be
evenly distributed throughout the atmosphere, and consequently global average concentrations can be determined.
The short-lived gases such as water vapor, 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 attributed to these gases that are short-lived and spatially
inhomogeneous in the atmosphere. Other greenhouse gases not yet listed by the IPCC, but are already or soon will
be in commercial use include: HFC-245fa, hydrofluoroethers (HFEs), and nitrogen trifluoride (NF3).
1 Carbon comprises 12/44ths of carbon dioxide by weight.
2 Framework Convention on Climate Change; FCCC/CP/1996/15/Add.l; 29 October 1996; Report of the Conference
of the Parties at its second session; held at Geneva from 8 to 19 July 1996; Addendum; Part Two: Action taken by the Conference
of the Parties at its second session; Decision 9/CP.2; Communications from Parties included in Annex I to the Convention:
guidelines, schedule and process for consideration; Annex: Revised Guidelines for the Preparation of National Communications
by Parties Included in Annex I to the Convention; p. 18. FCCC (1996)
N-1
-------
Table N-1: Global Warming Potentials (GWP) and Atmospheric Lifetimes (Years)
Gas
Carbon dioxide (C02)
Methane (CH4)b
Nitrous oxide (N20)
HFC-23
HFC-125
HFC-1343
HFC-1433
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
CF<
C2F6
C
-------
ANNEX O
Ozone Depleting Substance Emissions
Ozone is present in both the stratosphere,1 where it shields the Earth from harmful levels of ultraviolet
radiation, and at lower concentrations in the troposphere,2 where it is the main component of anthropogenic
photochemical "smog". Chlorofluorocarbons (CFCs) 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 (OOP) of the compound.3 The production of
CFCs, halons, carbon tetrachloride, and methyl chloroform* all Class I substances* has already ended in the United
States. However, 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; however, 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. See Annex N for a listing of net GWP values for ODS.
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 O-l.
1 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.
2 The troposphere is the layer from the ground up to about 11 kilometers near the poles and 16 kilometers in equatorial
regions (i.e., the lowest layer of the atmosphere, where humans live). It contains roughly 80 percent of the mass of all gases in
the atmosphere and is the site for weather processes including most of the water vapor and clouds.
3 Substances with an ozone depletion potential of 0.2 or greater are 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.
0-1
-------
Table 0-1 Emissions of Ozone Depleting Substances (Gg)
Compound
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
1990
52.4
226.9
39.0
0.7
2.2
25.1
27.9
+
1.0
33.9
-f
+
+
+
+
1991
53.9
233.5
39.8
0.7
2.2
25.6
28.5
0.5
1.2
35.6
+
+
+
+
+
1992
38.4
240.6
33.8
0.7
2.1
20.9
23.8
0.6
1.4
35.7
+
+
+
0.7
+
1993
32.6
237.1
27.5
0.8
1.9
16.0
19.0
0.7
1.6
36.8
+
2.7
4.9
1.7
+
1994
25.9
153.6
17.9
0.8
1.8
10.9
13.9
0.7
1.7
41.9
+
5.3
12.4
4.6
+
1995
19.1
71.1
7.6
0.8
1.6
5.5
8.7
0.7
1.8
46.2
0.6
5.6
20.6
7.3
+
1996
11.7
72.2
+
0.8
1.6
+
1.6
0.8
1.9
48.8
0.7
5.9
25.4
8.3
+
1997
10.7
63.6
+
0.8
1.4
+
+
0.8
1.9
50.6
0.8
6.2
25.1
8.7
+
1998
9.8
54.9
+
0.6
1.1
+
+
0.8
1.9
52.3
0.9
6.4
26.7
9.0
+
1999
9.2
64.4
+
+
1.1
+
+
0.8
1.9
83.0
1.0
6.5
28.7
9.5
+
Source: EPA, Office of Atmospheric Programs
+ Does not exceed 0.05 Gg
Methodology and Data Sources
Emissions of ozone depleting substances were estimated using two simulation models: the Atmospheric
and Health Effects Framework (AHEF) and the EPA's Vintaging Model.
AHEF contains estimates of U.S. domestic use of each of the ozone depleting substances. These estimates
were based upon data that industry reports to the EPA and other published material. The annual consumption of
each compound was divided into various end-uses based upon historical trends and research into specific industrial
applications. These end-uses include refrigerants, foam blowing agents, solvents, aerosol propellants, sterilants, and
fire extinguishing agents.
With the exception of aerosols, solvents, and certain foam blowing agents, emissions of ozone depleting
substances are not instantaneous, but instead occur gradually over time (i.e., emissions in a given year are the result
of both ODS use in that year and use in previous years). Each end-use has a certain release profile, which gives the
percentage of the compound that is released to the atmosphere each year until all releases have occurred. In
refrigeration equipment, for example, the initial charge is released or leaked slowly over the lifetime of the
equipment, which could be 20 or more years. In addition, not all of the refrigerant is ultimately emitted—some will
be recovered when the equipment is retired from operation.
The AHEF model was used to estimate emissions of ODSs that were in use prior to the controls
implemented under the Montreal Protocol. This included CFCs, halons, carbon tetrachloride, methyl chloroform,
and HCFC-22. Certain HCFCs, such as HCFC-123, HCFC-124, HCFC-141b, HCFC-142b, HCFC-225ca and
HCFC-225cb, have also entered the market as interim substitutes for ODSs. Emissions estimates for these
compounds were taken from the EPA's Vintaging Model.
The Vintaging Model was used to estimate the use and emissions of various ODS substitutes, including
HCFCs. The 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.
0-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
ANNEX P
Sulfur Dioxide Emissions
Sulfur dioxide (SO2) emitted into the atmosphere through natural and anthropogenic processes affects the
Earth's radiative budget through photochemical transformation into sulfate aerosols that can (1) scatter sunlight back
to space, thereby reducing the radiation reaching the Earth's surface; (2) affect cloud formation; and (3) affect
atmospheric chemical composition (e.g., stratospheric ozone, by providing surfaces for heterogeneous chemical
reactions). The overall effect of SO2 derived aerosols on radiative forcing is believed to be negative (IPCC 1996).
However, because SO2 is short-lived and unevenly distributed through the atmosphere, its radiative forcing impacts
are highly uncertain. Sulfur dioxide emissions have been provided below in Table P-l.
The major source of SO2 emissions in the United States was the burning of sulfur containing fuels, mainly
coal. Metal smelting and other industrial processes also released significant quantities of SO2. As a result, the
largest contributors to U.S. emissions of SO2 were electric utilities, accounting for 67 percent in 1999 (see Table P-
2). Coal combustion accounted for approximately 93 percent of SO2 emissions from electric utilities in the same
year. The second largest source was industrial fuel combustion, which produced 15 percent of 1999 SO2 emissions.
Overall, SO2 emissions in the United States decreased by 20 percent from 1990 to 1999. The majority of this
decline came from reductions from electric utilities, primarily due to increased consumption of low sulfur coal from
surface mines in western states.
Sulfur dioxide is important for reasons other than its effect on radiative forcing. It is a major contributor to
the formation of urban smog and acid rain. As a contributor to urban smog, high concentrations of SO2 can cause
significant increases in acute and chronic respiratory diseases. In addition, once SO2 is emitted, it is chemically
transformed in the atmosphere and returns to earth as the primary contributor to acid deposition, or acid rain. Acid
rain has been found to accelerate the decay of building materials and paints, and to cause the acidification of lakes
and streams and damage trees. As a result of these harmful effects, the United States has regulated the emissions of
SO2 under the Clean Air Act. The EPA has also developed a strategy to control these emissions via four programs:
(1) the National Ambient Air Quality Standards program,1 (2) New Source Performance Standards,2 (3) the New
Source Review/Prevention of Significant Deterioration Program,3 and (4) the sulfur dioxide allowance program.4
References
EPA (2000) National Air Pollutant Emissions Trends Report, 1900-1999, U.S. Environmental Protection
Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC.
1 [42 U.S.C § 7409, CAA § 109]
2 [42 U.S.C § 7411, CAA § 111]
3 [42 U.S.C § 7473, CAA § 163]
4 [42 U.S.C § 7651, CAA § 401]
P-1
-------
Table P-1: S02 Emissions (Gg)
Sector/Source
1990!
1995
1996
1997
1998
1999
Energy 20,1361
Stationary Combustion 18,4071
* Mobile Combustion 1,3391
Oil and Gas Activities 3901
Industrial Processes 1,3061
Chemical Manufacturing 2691
Metals Processing 6581
Storage and Transport 61
Other Industrial Processes 3621
Miscellaneous* 111
Solvent Use +1
Degreasing +1
Graphic Arts +|
Dry Cleaning NAI
Surface Coating +1
Other Industrial +1
Non-industrial NAi
Agriculture NAi
Agricultural Burning NAI
Waste 381
Waste Combustion - 381
Landfills +1
Wastewater Treatment +1
Miscellaneous Waste +1
16,247
14,724
1,189
334
1,117
260
481
2
365
9
1
NA
NA
NA
43
42
+
1
16,113
14,727
1,081
304
958
231
354
5
354
15
1
1
NA
NA
NA
37
36
1
16,534
15,106
1,116
312
993
235
369
5
371
14
1
1
NA
NA
NA
37
36
1
16,647
15,192
1,145
310
996
237
367
5
376
11
1
1
NA
NA
NA
38
37
1
16,085
14,598
1,178
309
996
238
364
5
379
11
1
1
NA
NA
NA
33
32
1
Total
21,4811
17,408 17,109 17.565 17,682 17,115
Source: (EPA 2000)
* 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 P-2: S02 Emissions from Electric Utilities (Gg)
Fuel Type
1990
1995 1996 1997 1998 1999
Coal
Petroleum
Natural Gas
Misc. Internal Combustion
Other
Source: (EPA 2000)
Note: Totals may not sum due to independent rounding.
P-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
ANNEX Q
Complete List of Source Categories
Chapter/Source
Gas(es)
Energy
Carbon Dioxide Emissions from Fossil Fuel Combustion
Carbon Stored in Products from Non-Energy Uses of Fossil Fuels
Stationary Combustion (excluding C02)
Mobile Combustion (excluding C02)
Coal Mining
Natural Gas Systems
Petroleum Systems
Natural Gas Flaring and Criteria Pollutant Emissions from Oil and Gas Activities
International Bunker Fuels
Wood Biomass and Ethanol Consumption
C02
C02
CH4, N20, CO, NOX, NMVOC
CH4, N20, CO, NOX, NMVOC
CH4
CH4
CH4
C02, CO, NOX, NMVOC
C02, CH4, N20, CO, NOX, NMVOC
CO,
Industrial Processes
Cement Manufacture
Lime Manufacture
Limestone and Dolomite Use
Soda Ash Manufacture and Consumption
Carbon Dioxide Consumption
Iron and Steel Production
Ammonia Manufacture
Ferroalloy Production
Petrochemical Production
Silicon Carbide Production
Adipic Acid Production
Nitric Acid Production
Substitution of Ozone Depleting Substances
Aluminum Production
HCFC-22 Production
Semiconductor Manufacture
Electrical Transmission and Distribution
Magnesium Production and Processing
Industrial Sources of Criteria Pollutants
C02
C02
C02
C02
C02
C02
C02
C02
CH4
CH4
N20
N20
HFCs, PFCsa
C02, CF4, C2F6
HFC-23
HFCs, PFCs, SF6b
SF6
SF6
CO, NO^NMVOC
Solvent Use
CO, NO,, NMVOC
Agriculture
Enteric Fermentation
Manure Management
Rice Cultivation
Agricultural Soil Management
Agricultural Residue Burning
CH4
CH4, N20
CH4
N20
CH4, N,0, CO, NO,
Land-Use Change and Forestry
Changes in Forest Carbon Stocks
Changes in Non-Forest Soil Carbon Stocks
Changes in Non-Forest Carbon Stocks in Landfills
C02 (sink)
C02 (sink)
CO, (sink)
Waste
Landfills
Wastewater Treatment
Human Sewage
Waste Combustion
Waste Sources of Criteria Pollutants
CH4
CH4
N20
C02, N20 -
CO. NO,, NMVOC
a In 1999, included HFC-23, HFC-125, HFC-134a, HFC-143a, HFC-152a, HFC-227ea, HFC-236fa, HFC-4310mee, C4F10, C6F14, PFC/PFPEs
6 Included such gases as HFC-23, CF4, C2F6, SF6
Q-1
-------
Q-2 inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
ANNEX R
IPCC Reference Approach for Estimating C02 Emissions from Fossil Fuel
Combustion
It is possible to estimate carbon dioxide (CO2) emissions from fossil fuel consumption using alternative
methodologies and different data sources than those described in Annex A. For example, the 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.1 These data are presented in Table R-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., BTlPs or joules). Because detailed
fuel production statistics are typically provided in physical units (as in Table R-l), they were converted to units of
energy before CO2 emissions were calculated. Fuel statistics were converted to their energy equivalents by using
conversion factors provided by DOE/EIA. These factors and their data sources are displayed in Table R-l. The
resulting fuel type-specific energy data are provided in Table R-2.
Step 2: Estimate Apparent Fuel Consumption
The next step of the IPCC Reference Approach is to estimate "apparent consumption" of fuels within the
country. This requires a balance of primary fuels produced, plus imports, minus exports, and adjusting for stock
changes. In this way, carbon enters an economy through energy production and imports (and decreases in fuel
stocks) and is transferred out of the country through exports (and increases in fuel stocks). Thus, apparent
consumption of primary fuels (including crude oil, natural gas liquids, anthracite, bituminous, subbituminous and
lignite coal, and natural gas) can be calculated as follows:
Apparent Consumption = Production + Imports - Exports - Stock Change
Flows of secondary fuels (e.g., gasoline, residual fuel, coke) should be added to primary apparent
consumption. The production of secondary fuels, however, should be ignored in the calculations of apparent
consumption since the carbon contained in these fuels is already accounted for in the supply of primary fuels from
1 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 U.S. territories data. The territories include Puerto Rico, U.S. Virgin Islands, Guam,
American Samoa, Wake Island, and U.S. Pacific Islands. Consumption data were used for the territories because they are
thought to be more reliable than production, import, export, and stock change data.
R-1
-------
which they were derived (e.g., the estimate for apparent consumption of crude oil already contains the carbon from
which gasoline would be refined). Flows of secondary fuels should therefore be calculated as follows:
Secondary Consumption = Imports - Exports - Stock Change
Note that this calculation can result in negative numbers for apparent consumption of secondary fuels. This
result is perfectly acceptable since it merely indicates a net export or stock increase in the country of that fuel when
domestic production is not considered.
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 has a different heat
content. Therefore, United States fuel statistics were converted to their heat equivalents before estimating apparent
consumption. The energy value of bunker fuels used for international transport activities was subtracted before
computing energy totals.2 Results are provided in Table R-2.
Step 3: Estimate Carbon Emissions
Once apparent consumption is estimated, the remaining calculations are virtually identical to those for the
"bottom-up" Sectoral Approach (see Annex A). That is:
• Potential carbon emissions were estimated using fuel-specific carbon coefficients (see Table R-3).^
• The carbon in products from non-energy uses of fossil fuels (e.g., plastics or asphalt) was then estimated
and subtracted from the total amount of carbon (see Table R-4).
• 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).4
Step 4: Convert to C02 Emissions
Because the IPCC reporting guidelines recommend that countries report greenhouse gas emissions on a full
molecular weight basis, the final step in estimating COi 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 R-5.
Comparison Between Sectoral and Reference Approaches
These two alternative approaches can both produce reliable estimates that are comparable within a few
percent. The major difference between methodologies employed by each approach lies in the energy data used to
derive carbon emissions (i.e., the actual surveyed consumption for the Sectoral Approach versus apparent
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.
^ 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.
* 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 R-4 for more
specific source information.
4 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 inventoiy uses 1
percent in its calculations for petroleum and coal and 0.5 percent for natural gas.
R-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Differences in Total Amount of Energy Consumed
Table R-75 summarizes the differences between the Reference and Sectoral approaches in estimating total
energy consumption in the United States. Although theoretically the two methods should arrive at the same estimate
for U.S. energy consumption, the Reference Approach provides an energy total that is 2.1 percent lower than the
Sectoral Approach for 1999. The greatest difference lies in the higher estimate of petroleum consumption with the
Sectoral Approach (3.9 percent).
There are several potential sources for the discrepancies in consumption estimates:
• Product Definitions. The fuel categories in the Reference Approach are different from those used in the
Sectoral Approach, particularly for petroleum. For example, the Reference Approach estimates apparent
consumption for crude oil. Crude oil is not typically consumed directly, but refined into other products. As
a result, the United States does not focus on estimating the energy content of the various grades of crude
oil, but rather estimating the energy content of the various products resulting from crude oil refining. The
United States does not believe that estimating apparent consumption for crude oil, and the resulting energy
content of the crude oil, is the most reliable method for the United States to estimate its energy
consumption. Other differences in product definitions include using sector-specific coal statistics in the
Sectoral Approach (i.e., residential, commercial, industrial coking, industrial other, and transportation
coal), while the Reference Approach characterizes coal by rank (i.e. anthracite, bituminous, etc.). Also, the
liquefied petroleum gas (LPG) statistics used in the bottom-up calculations are actually a composite
category composed of natural gas liquids (NGL) and LPG.
• Heat Equivalents. It can be difficult to obtain heat equivalents for certain fuel types, particularly for
categories such as "crude oil" where the key statistics are derived from thousands of producers in the
United States and abroad. For heat equivalents by coal rank, it was necessary to refer back to EIA's State
Energy Data Report 1992 (1994) because this information is no longer published.
• Possible inconsistencies in U.S. Energy Data. The United States has not focused its energy data collection
efforts on obtaining the type of aggregated information used in the Reference Approach. Rather, the
United States believes that its emphasis on collection of detailed energy consumption data is a more
accurate methodology for the United States to obtain reliable energy data. Therefore, top-down statistics
used in the Reference Approach may not be as accurately collected as bottom-up statistics applied to the
Sectoral Approach.
• Balancing Item. The Reference Approach uses apparent consumption estimates while the Sectoral
Approach uses reported consumption estimates. While these numbers should be equal, there always seems
to be a slight difference that is often accounted for in energy statistics as a "balancing item."
Differences in Estimated CO2 Emissions
Given these differences in energy consumption data, the next step for each methodology involved
estimating emissions of CO2. Table R-8 summarizes the differences between the two methods in estimated carbon
emissions.
As shown previously, the Sectoral Approach resulted in a 2.1 percent higher estimate of energy
consumption in the United States than the Reference Approach, but the resulting emissions estimate for the
Reference Approach is 0.6 percent higher. While both methods' estimates of natural gas emissions are almost
exactly the same, coal and petroleum emission estimates from the Reference Approach are higher than the Sectoral
Approach. 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 for the Sectoral Approach. This format
likely results in more accurate estimates than in the Reference Approach. Also, the Reference
Approach relies on a "crude oil" category for determining petroleum-related emissions. Given the
many sources of crude oil in the United States, it is not an easy matter to track potential differences in
for 1996.
1 Although complete energy consumption data and calculations are not presented, comparison tables are also presented
R-3
-------
carbon content between many different sources of crude, particularly since information on the carbon
content of crude oil is not regularly collected.
• Carbon Coefficients. The Reference Approach relies on several default carbon coefficients provided
by IPCC (IPCC/UNEP/OECD/IEA 1997), while the Sectoral Approach uses annually updated
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. The United States believes that it is valuable to
understand both methods.
References
EIA (2000a) Annual Energy Review 1999. Energy Information Administration, U.S. Department of
Energy, Washington, DC. July. DOE/EIA- 0384(99)-annual.
EIA (2000b) Emissions of Greenhouse Gases in the United States 1999. Energy Information
Administration, U.S. Department of Energy, Washington, DC. Draft. Octobers, 1999,DOE/EIA-0535(99)-annual.
EIA (2000c) Monthly Energy Review, Energy Information Administration, U.S. Department of Energy,
Washington, DC. November. DOE/EIA 0035(99)-monthly.
EIA (2000d) Petroleum Supply Annual 1999, Energy Information Administration, U.S. Department of
Energy, Washington, DC, Volume I. DOE/EIA-0340(99)/1.
EIA (2000e) Unpublished supply, disposition, and ending stocks of crude oil and petroleum products data
for 1990-1994 from the Energy Information Administration, U.S. Department of Energy, Washington, DC.
ELA. (1999) Petroleum Supply Annual 1998, Energy Information Administration, U.S. Department of
Energy, Washington, DC, Volume I. DOE/EIA-0340(98)/1.
EIA (1998) Petroleum Supply Annual 1997, Energy Information Administration, U.S. Department of
Energy, Washington, DC, Volume I. DOE/EIA-0340(97)/1.
EIA (1997) Petroleum Supply Annual 1996, Energy Information Administration, U.S. Department of
Energy, Washington, DC, Volume I. DOE/EIA-0340(96)/1.
EIA (1995) Petroleum Supply Annual 1995, Energy Information Administration, U.S. Department of
Energy, Washington, DC, Volume I. DOE/EIA-0340(95)/1.
EIA (1994) State Energy Data Report 1992, Energy Information Administration, U.S. Department of
Energy, Washington, DC. DOE/EIA 0214(92)-annual.
IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories,
Paris: Intergovernmental Panel on Climate Change, United Nations Environment Programme, Organization for
Economic Co-Operation and Development, International Energy Agency.
R-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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Table R-5: 1999 Non-Energy Carbon Stored in Products
Fuel Type
Coal
Natural Gas
Asphalt & Road Oil
LP6
Lubricants
Pentanes Plus
Petrochemical Feedstocks
Petroleum Coke
Special Naptha
Waxes/Misc.
Misc. U.S. Territories Petroleum
Total
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Consumption for Non-
Energy Use (TBtu)
24.5
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Carbon Coefficients Carbon
(Tg Carbon/QBtu) (Tg
25.55
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16.88
20.24
18.24
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19.86
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Carbon
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(Tg.C02Eq.)
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17.90
100.13
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2.57
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83.94
19.24
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13.24
1.66
361.70
are aggregates of
numerous smaller components.
Note: Totals may not sum due to independent rounding.
Table R-6: Reference Approach C02 Emissions from Fossil Fuel Consumption (Tg C02 Eq. unless otherwise
noted)
Fuel Category
Coal
Petroleum
Natural Gas
Total
Potential Carbon
Emissions
2,040.7
2,688.1
1,171.0
5,899.8
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342.1
17.9
361.7
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Emissions
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2,346.0
1,153.1
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Oxidized (%)
99.0%
99.0%
99.5%
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Total
Emissions
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2,322.5
1,147.4
5,488.5
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ANNEXS
Sources of Greenhouse Gas Emissions Excluded
Although this report is intended to be a comprehensive assessment of anthropogenic1 sources and sinks of
greenhouse gas emissions for the United States, certain sources have been identified yet excluded from the estimates
presented for various reasons. Before discussing these sources, however, it is important to note that processes or
activities that are not anthropogenic in origin or do not result in a net source or sink of greenhouse gas emissions are
intentionally excluded from a national inventory of anthropogenic greenhouse gas emissions. In general, processes
or activities that are not anthropogenic are considered natural (i.e., not directly influenced by human activity) in
origin and, as an example, would include the following:
• Volcanic eruptions
• Carbon dioxide (CO2) exchange (i.e., uptake or release) by oceans
• Natural forest fires^
• Methane (CHj) emissions from wetlands not affected by human induced land-use changes
Some processes or activities may be anthropogenic in origin but do not result in net emissions of
greenhouse gases, such as the respiration of CO2 by people or domesticated animals.3 Given a source category that
is both anthropogenic and results in net greenhouse gas emissions, reasons for excluding a source related to an
anthropogenic activity include one or more of the following:
• There is insufficient scientific understanding to develop a reliable method for estimating emissions at a
national level.
• Although an estimating method has been developed, data were not adequately available to calculate
emissions.
• Emissions were implicitly accounted for within another source category (e.g., CO2 from Fossil Fuel
Combustion).
It is also important to note that the United States believes the exclusion of the sources discussed below
introduces only a minor bias in its overall estimate of U.S. greenhouse gas emissions.
Separate Cruise and LTD Emissions from the Combustion of Jet Fuel
The combustion of jet fuel by aircraft results in emissions of CH4, N2O, CO, NOX, and NMVOCs. The
emissions per mass of fuel combusted during landing/take-off (LTO) operations differ from those during aircraft
cruising. Accurate estimation of these emissions requires a detailed accounting of LTO cycles and fuel consumption
during cruising by aircraft model (e.g., Boeing 747-400) as well as appropriate emission factors. Sufficient data for
separately calculating near ground-level emissions during landing and take-off and cruise altitude emissions by
aircraft model were not available for this report, (see Revised 1996IPCC Guidelines for National Greenhouse Gas
Inventories: Reference Manual, pp. 1.93 - 1.96)
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).
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.
3 Respiration of CO2 by biological organisms is simply part of the broader global carbon cycle that also includes uptake
of CO2 by photosynthetic organisms.
S-1
-------
C02 from Burning in Coal Deposits and Waste Piles
Coal is periodically burned in deposits and waste piles. It has been estimated that the burning of coal in
deposits and waste piles would represent less than 1.3 percent of total U.S. coal consumption, averaged over ten-
years. Because there is currently no known source of data on the quantity of coal burned in waste piles and there is
uncertainty as to the fraction of coal oxidized during such burnings, these CO2 emissions are not currently estimated.
Further research would be required to develop accurate emission factors and activity data for these emissions to be
estimated (see Revised 1996IPCC Guidelines for National Greenhouse Gas Inventories: Reference Manual, p.
1.112-1.113).
Fossil C02 from Petroleum and Natural Gas Wells, C02 Separated from Natural Gas, and C02 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.
Carbon dioxide and other gases are naturally present in raw natural gas, in proportions that vary depending
on the geochemical circumstances that caused the formation of the gas. After the heavier gases are removed during
processing, small amounts of carbon dioxide may be allowed to remain in the natural gas. If the amount of CO2
sufficiently lowers the heating value of the natural gas, it is typically extracted by amine scrubbing and, in most
cases, released into the atmosphere. These emissions can be estimated by calculating the difference between the
average carbon dioxide content of raw natural gas and the carbon dioxide content of pipeline gas. The Energy
Information Administration (EIA) estimates that annual CO2 emissions from scrubbing are about 15 Tg CO2 Eq.
Because of imprecision in the reporting of U.S. natural gas production and processing, emissions estimates from
energy production sources may be double-counted or under-reported, and thus are uncertain.
Carbon dioxide is also injected into underground deposits to increase crude oil reservoir pressure in a field
technique known as enhanced oil recovery (EOR). It is thought that much of the injected CO2 may be effectively
and permanently sequestered, but the fraction of injected CO2 that is re-released remains uncertain. The fraction re-
released varies from well to well depending upon the field geology and the gas capture/re-injection technology
employed at the wellhead. Over time, carbon dioxide may also seep into the producing well and mix with the oil
and natural gas present there. If the gas portion of this mixture has a sufficiently high energy content, it may be
collected and sent to a natural gas plant; if not, it may be vented or flared. The EIA estimates that the amount of
COi used for EOR is on the order of 44 Tg CO2 Eq., of which emissions would be some fraction yet to be defined.
This figure is based on the difference between U.S. Department of Commerce sales figures for industrial CO2 (62 Tg
CO2 Eq.) minus the 18 Tg CO2 Eq. reported by the Freedonia Group that is used for purposes other than EOR.
Further research into EOR is required before the resulting CO2 emissions can be adequately quantified. (See Carbon
Dioxide Consumption in the Industrial Processes chapter).
Carbon Sequestration in Underground Injection Wells
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 if this potential sink is to be quantified. (See Carbon Stored in Products from
Non-Energy Uses of Fossil Fuels in the Energy chapter.)
CH4 from Abandoned Coal Mines
Abandoned coal mines are a source of CEU emissions. In general, many of the same factors that affect
emissions from operating coal mines will affect emissions from abandoned mines such as the permeability and
gassiness of the coal, the mine's depth, geologic characteristics, and whether it has been flooded. A few gas
developers have recovered methane from abandoned mine workings; therefore, emissions from this source may be
significant. Further research and methodological development is needed if these emissions are to be estimated. (See
Coal Mining in the Energy chapter.)
S-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
C02 from "Unaccounted for" Natural Gas
There is a discrepancy between the amount of natural gas sold by producers and that reported as purchased
by consumers. This discrepancy, known as "unaccounted for" or unmetered natural gas, was assumed to be the sum
of leakage, measurement errors, data collection problems, undetected non-reporting, undetected over reporting, and
undetected under reporting. Historically, the amount of gas sold by producers has always exceeded that reportedly
purchased by consumers; therefore, some portion of unaccounted for natural gas was assumed to be a source of CO2
emissions. In other words, it was assumed that consumers were underreporting their usage of natural gas. In
DOE/EIA's energy statistics for 1996, however, reported consumption of natural gas exceeded the amount sold by
producers. Therefore, the historical explanation given for this discrepancy has lost credibility and unaccounted for
natural gas is no longer used to calculate CC>2 emissions.
C02 from Shale Oil Production
Oil shale is shale saturated with kerogen.4 It can be thought of as the geological predecessor to crude oil.
Carbon dioxide is released as a by-product of the process of producing petroleum products from shale oil. As of
now, it is not cost-effective to mine and process shale oil into usable petroleum products. The only identified large-
scale oil shale processing facility in the United States was operated by Unocal during the years 1985 to 1990. There
have been no known emissions from shale oil processing in the United States since 1990 when the Unocal facility
closed.
CH4 from the Production of Carbides other than Silicon Carbide
Methane (CH4) may be emitted from the production of carbides because the petroleum coke used in the
process contains volatile organic compounds, which form CtLt 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 CEU 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)
C02 from Calcium Carbide and Silicon Carbide Production
Carbon dioxide is formed by the oxidation of petroleum coke in the production of both calcium carbide and
silicon carbide. These CO2 emissions are implicitly accounted for with emissions from the combustion of petroleum
coke in the Energy chapter. There is currently not sufficient data on coke consumption to estimate emissions from
these sources explicitly. (See Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference
Manual, pp. 2.20 - 2.21)
C02 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 chapter under Fossil Fuel
Combustion.
• Estimating emissions from the use of wood or other biomass materials is unnecessary because these
emissions should be accounted for in Land-Use Change and Forestry chapter 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 chapter, although 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.
4 Kerogen is fossilized insoluble organic material found in sedimentary rocks, usually shales, which can be converted
to petroleum products by distillation.
S-3
-------
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 graphite for these purposes is required to explicitly estimate emissions. (See Iron and Steel
Production and Ferroalloy Production in the Industrial Processes chapter)
N20 from Caprolactam Production
Caprolactam is a widely used chemical intermediate, primarily to produce nylon-6. All processes for
producing caprolactam involve the catalytic oxidation of ammonia, with N2O being produced as a by-product.
Caprolactam production could be a significant source of N2O—it has been identified as such in the Netherlands.
More research is required to determine this source's significance because there is currently insufficient information
available on caprolactam production to estimate emissions in the United States. (See Revised 1996IPCC Guidelines
for National Greenhouse Gas Inventories: Reference Manual, pp. 2.22 - 2.23)
N20 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 CKt emissions. Detailed coke production statistics were not available for
the purposes of estimating CHj emissions from this minor source. (See Petrochemical Production in the Industrial
Processes chapter and the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories: Reference
Manual, p. 2.23)
C02 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 this coke 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
chapter 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)
N20 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)
SFG from Aluminum Fluxing and Degassing
Occasionally, sulfur hexafluoride (SFg) is used by the aluminum industry as a fluxing and degassing agent
in experimental and specialized casting operations. In these cases it is normally mixed with argon, nitrogen, and/or
chlorine and blown through molten aluminum; however, this practice is not used by primary aluminum production
firms in the United States and is not believed to be extensively used by secondary casting firms. Where it does
occur, the concentration of SF« in the mixture is small and a portion of the SF6 is decomposed in the process (Waite
and Bernard 1990, Corns 1990). It has been estimated that 230 Mg of SF6 were used by the aluminum industry in
the United States and Canada (Maiss and Brenninkmeijer 1998); however, this estimate is highly uncertain.
S-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
-------
Miscellaneous SF6 Uses
Sulfur hexafluoride may 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. A preliminary global assessment of aggregate emissions from these applications can be found in Maiss,
M. and C.A.M. Brenninkmeijer (1998).
C02 from Solvent Incineration
Carbon dioxide may be released during the incineration of solvents. Although emissions from this source
are believed to be minor, data need to be gathered and methodologies developed if these emissions are to be
estimated.
N20 from Domestic House Animal Waste Deposited on Soils
A substantial amount of liquid and solid waste is produced by domestic animals that are kept as pets. A
preliminary methodology was developed to estimate nitrous oxide (N2O) emissions from the deposition of domestic
house animal (i.e., dogs and cats) waste on lawns, fields and parks. Estimates calculated with this methodology
suggest that, in 1990, approximately 330 Gg of nitrogen originating as domestic house animal waste were deposited
on soils resulting in approximately 2.9 Tg CCs Eq. of NiO emissions from soils. To estimate the amount of nitrogen
deposited by domestic house animals, only those excretions that remained on land surfaces* as opposed to wastes
that were collected by owners and are managed as municipal solid waste* were included.
Annual dog and cat population numbers were obtained from the Pet Food Institute.5 Annual nitrogen
excretion rates were estimated from protein intake. The recommended protein intake for an average size adult of
each animal type^ was multiplied by the average amount of nitrogen per unit of protein (0.16 kg N/kg protein, from
the Revised 1996IPCC Guidelines) to estimate nitrogen consumption. It was then assumed that 95 percent of this
nitrogen was excreted, either in solid or liquid form (i.e., it was assumed that 5 percent was retained for fur and milk
production). Of the total nitrogen excretion, 90 percent was assumed to occur through liquid waste, with the balance
from solid waste7. Both cat and dog populations were divided into urban and rural fractions, using the metropolitan
and non-metropolitan human population categories, respectively, of the U.S. Census Bureau8. Both liquid and solid
wastes from the urban cat population, and solid waste from the urban dog population were assumed to be collected
(i.e., not deposited on soils). Nitrous oxide emission estimates from domestic house animal excretion were
calculated in the same manner as performed for estimating emissions from livestock excretion. Producing these
estimates involved making a number of simplifying assumptions regarding average animal size and protein
consumption, as well as the proportions of animal populations residing in urban and rural areas and the proportions
of wastes that are deposited on land. Further methodological development and data collection is required in order to
reduce the uncertainty involved in the domestic house animal excretion estimates.
C02 from Food Scraps Disposed in Landfills
A certain amount of food scraps generated from food processing or as leftovers join the waste stream and
are landfilled. Nationally, an estimated 0.4 Tg CO2 Eq. per year are stored in the form of organic carbon contained
in food scraps in landfills, acting as a carbon sink. A portion of the landfilled food scraps becomes a source of
methane emissions, which offset the sink estimates to an extent. Further data collection on the amount and
5 Pet Food Institute (1999) Pet Incidence Trend Report. Pet Food Institute, Washington DC.
6 Bright, S. (1999) Personal communication between Marco Alcaraz of ICF Consulting and Susan Bright of the Dupont
Animal Clinic, Washington, DC, August 1999.
^ Swenson, M.J. and W.G. Reece, eds. (1993) Duke's Physiology of Domestic Animals. Cornell University Press. 11th
Edition.
^ U.S. Census Bureau (1999)
S-5
-------
composition of food scraps generated and landfilled is required in order to reduce the uncertainty associated with
this estimate.
CH4 from Land-Use Changes Including Wetlands Creation or Destruction
Wetlands are a known source of methane (CKU) emissions. When wetlands are destroyed, CELi 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 CUf due to the presence of
methanotrophic bacteria that use CHt 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 (CKO 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.
N20 from Wastewater Treatment
As a result of nitrification and denitrification processes, nitrous oxide (N2O) may be produced and emitted
from both domestic and industrial 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 that originates from human excrement is currently
estimated under the Human Sewage source category — based upon average dietary assumptions. The portion of
emitted NiO that originates from other nitrogen-containing constituents is not currently estimated. Further research
and methodological development is needed if these emissions are to be accurately estimated.
CH4 from Industrial Wastewater Treatment
Methane (CHt) may be produced during the biodegradation of organics in wastewater if other suitable
electron-acceptors (i.e. oxygen, nitrate, or sulfate) besides CO2 are unavailable. Such conditions are called
methanogenic. Methane produced from domestic wastewater treatment plants is accounted for in the Waste chapter.
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, are accounted for in the average
BODs per capita method when this wastewater is sent to domestic wastewater treatment plants. Additionally, CHt
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 in the Waste chapter.)
S-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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ANNEX T
Constants, Units, and Conversions
Metric Prefixes
Although most activity data for the United States is gathered in customary U.S. units, these units are
converted into metric units per international reporting guidelines. The following table provides a guide for
determining the magnitude of metric units.
Table T-1: Guide to Metric Unit Prefixes
Prefix/Symbol
atto (a)
femto (f)
pico (p)
nano (n)
micro (/L/ )
milli (m)
centi (c)
deci (d)
deca (da)
hecto (h)
kilo (k)
mega (M)
giga (G)
tera (T)
peta (P)
exa (E)
Factor
10-18
1 0-15
1Q-12
10'9
io-6
io-3
io-2
io-1
10
102
103
106
109
1012
1015
1018
Unit Conversions
1 kilogram
1 pound
1 short ton
1 metric ton
1 cubic meter
1 cubic foot
1 U.S. gallon
1 barrel (bbl)
1 barrel (bbl)
1 liter
1foot
1 meter
1 mile
1 kilometer
2.205 pounds
0.454 kilograms
2,000 pounds
1,000 kilograms
= 0.9072 metric tons
= 1.1023 short tons
= 35.315 cubic feet
= 0.02832 cubic meters
= 3.785412 liters
= 0.159 cubic meters
= 42 U.S. gallons
= 0.1 cubic meters
0.3048 meters
3.28 feet
1.609 kilometers
0.622 miles
1 acre = 43,560 square feet = 0.4047 hectares = 4,047 square meters
1 square mile = 2.589988 square kilometers
To convert degrees Fahrenheit to degrees Celsius, subtract 32 and multiply by 5/9
To convert degrees Celsius to Kelvin, add 273.15 to the number of Celsius degrees
T-1
-------
Density Conversions1
Methane
Carbon dioxide
1 cubic meter
1 cubic meter
= 0.67606 kilograms
= 1.85387 kilograms
Natural gas liquids
Unfinished oils
Alcohol
Liquefied petroleum gas
Aviation gasoline
Naphtha jet fuel
Kerosene jet fuel
Motor gasoline
Kerosene
Naphtha
Distillate
Residual oil
Lubricants
Bitumen
Waxes
Petroleum coke
Petrochemical feedstocks
Special naphtha
Miscellaneous products
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
1 metric ton
11.6 barrels
7.46 barrels
7.94 barrels
11.6 barrels
8.9 barrels
8.27 barrels
7.93 barrels
8.53 barrels
7.73 barrels
8.22 barrels
7.46 barrels
6.66 barrels
7.06 barrels
6.06 barrels
7.87 barrels
5.51 barrels
7.46 barrels
8.53 barrels
8.00 barrels
1,844.2 liters
1,186.04 liters
1,262.36 liters
1,844.2 liters
1,415.0 liters
1,314.82 liters
1,260.72 liters
1,356.16 liters
1,228.97 liters
1,306.87 liters
1,186.04 liters
1,058.85 liters
1,122.45 liters
963.46 liters
1,251.23 liters
876.02 liters
1,186.04 liters
1,356.16 liters
1,271.90 liters
Energy Conversions
Converting Various Energy Units to Joules
The common energy unit used in international reports of greenhouse gas emissions is the joule. A joule is
the energy required to push with a force of one Newton for one meter. A terajoule (TJ) is one trillion (1012) joules.
A British thermal unit (Btu, the customary U.S. energy unit) is the quantity of heat required to raise the temperature
of one pound of water one degree Fahrenheit at or near 39.2 Fahrenheit.
2.388x1011 calories
1T. 23.88 metric tons of crude oil equivalent
~ 947.8 million Btus
277,800 kilowatt-hours
Converting Various Physical Units to Energy Units
Data on the production and consumption of fuels are first gathered in physical units. These units must be
converted to their energy equivalents. The values in the following table of conversion factors can be used as default
factors, if local data are not available. See Appendix A of EIA's Annual Energy Review 1997 (EIA 1998) for more
detailed information on the energy content of various fuels.
1 Reference: EIA (1998a)
T-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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Table T- 2: Conversion Factors to Energy Units (Heat Equivalents)
Fuel Type (Units)
Factor
Solid Fuels (Million Btu/Shortton)
Anthracite coal 22.573
Bituminous coal 23.89
Sub-bituminous coal 17.14
Lignite 12.866
Coke 24.8
Natural Gas (Btu/Cubic foot) 1,027
Liquid Fuels (Million Btu/Barrel)
Crude oil 5.800
Natural gas liquids and LRGs 3.777
Other liquids 5.825
Motor gasoline 5.253
Aviation gasoline 5.048
Kerosene 5.670
Jet fuel, kerosene-type 5.670
Distillate fuel 5.825
Residual oil 6.287
Naphtha for petrochemicals 5.248
Petroleum coke 6.024
Other oil for petrochemicals 5.825
Special naphthas 5.248
Lubricants 6.065
Waxes 5.537
Asphalt 6.636
Still gas 6.000
Misc. products 5.796
Note: For petroleum and natural gas, Annual Energy Review 1997 (EIA 1998b). For coal ranks, State Energy Data Report 1992 (EIA
1993). All values are given in higher heating values (gross calorific values).
References
EIA (1998a) Emissions of Greenhouse Gases in the United States, DOE/EIA-0573(97), Energy Information
Administration, U.S. Department of Energy. Washington, DC. October.
EIA (1998b) Annual Energy Review, DOE/EIA-0384(97), Energy Information Administration, U.S.
Department of Energy. Washington, DC. July.
EIA (1993) State Energy Data Report 1992, DOE/EIA-0214(93), Energy Information Administration, U.S. Department of Energy.
Washington, DC. December.
T-3
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ANNEX U
Abbreviations
AAPFCO American Association of Plant Food Control Officials
AFEAS Alternative Fluorocarbon Environmental Acceptability Study
AGA American Gas Association
ARC American Plastics Council
ASAE American Society of Agricultural Engineers
BEA Bureau of Economic Analysis, U.S. Department of Commerce
BOD5 Biochemical oxygen demand over a 5-day period
BTS Bureau of Transportation Statistics, U.S. Department of Transportation
Btu British thermal unit
CAAA Clean Air Act Amendments of 1990
CAPP Canadian Association of Petroleum Producers
C&EN Chemical and Engineering News
CFC Chlorofluorocarbon
CFR Code of Federal Regulations
CMA Chemical Manufacturer's Association
CMOP Coalbed Methane Outreach Program
CVD Chemical vapor deposition
DESC Defense Energy Support Center-DoD's defense logistics agency
DIG Dissolved inorganic carbon
DOC U.S. Department of Commerce
DoD U.S. Department of Defense
DOE U.S. Department of Energy
DOI U.S. Department of the Interior
DOT U.S. Department of Transportation
EIA Energy Information Administration, U.S. Department of Energy
EIIP Emissions Inventory Improvement Program
EOR Enhanced oil recovery
EPA U.S. Environmental Protection Agency
FAA Federal Aviation Administration
FAO Food and Agricultural Organization
FCCC Framework Convention on Climate Change
FEB Fiber Economics Bureau
FHWA Federal Highway Administration
GAA Governmental Advisory Associates
GCV Gross calorific value
GDP Gross domestic product
GHG Greenhouse gas
GRI Gas Research Institute
GSAM Gas Systems Analysis Model
GWP Global warming potential
HBFC Hydrobromofluorocarbon
HCFC Hydrochlorofluorocarbon
HDGV Heavy duty gas vehicle
HDDV Heavy duty diesel vehicle
HOPE High density polyethylene
HFC Hydrofluorocarbon
HFE Hydrofluoroethers
ICAO International Civil Aviation Organization
IEA International Energy Association
IISRP International Institute of Synthetic Rubber Products
ILENR Illinois Department of Energy and Natural Resources
IMO International Maritime Organization
IPAA Independent Petroleum Association of America
U-1
-------
IPCC Intergovernmental Panel on Climate Change
LOOT Light duty diesel truck
LDDV Light duty diesel vehicle
LDGV Light duty gas vehicle
LDGT Light duty gas truck
LDPE Low density polyethylene
LEV Low emission vehicles
LF6 Landfill gas
LFGTE Landfill gas-to-energy
LLPDE Linear low density polyethylene
LMOP EPA's Landfill Methane Outreach Program
LPG Liquefied petroleum gas(es)
LTD Landing and take-off
LULUCF Land use, land-use change, and forestry
MC Motorcycle
MCF Methane conversion factor
MMS Minerals Management Service
MMTCE Million metric tons carbon equivalent
MSHA Mine Safety and Health Administration
MSW Municipal solid waste
NAPAP National Acid Precipitation and Assessment Program
NASS USDA's National Agriculture Statistics Service
NCV Net calorific value
NIAR Norwegian Institute for Air Research
NMVOC Non-methane volatile organic compound
NO, Nitrogen Oxides
NRCS Natural Resources Conservation Service
NSCR Non-selective catalytic reduction
NVFEL National Vehicle Fuel Emissions Laboratory
OAQPS EPA Office of Air Quality Planning and Standards
ODS Ozone depleting substances
OECD Organization of Economic Co-operation and Development
OMS EPA Office of Mobile Sources
ORNL Oak Ridge National Laboratory
OSHA Occupational Safety and Health Administration
OTA Office of Technology Assessment
PPC Precipitated calcium carbonate
PFC Perfluorocarbon
PFPE Perfluoropolyether
POTW Publicly Owned Treatment Works
ppmv Parts per million(10B) by volume
ppbv Parts per billion (109) by volume
pptv Parts per trillion (1012) by volume
PVC Polyvinyl chloride
RCRA Resource Conservation and Recovery Act
SAE Society of Automotive Engineers
SBSTA Subsidiary Body for Scientific and Technical Advice
SCR Selective catalytic reduction
SNG Synthetic natural gas
SWANA Solid Waste Association of North America
TBtu Trillion Btu
TgC02Eq. Teragrams carbon dioxide equivalent
TJ Terajoule
TSDF Hazardous waste treatment, storage, and disposal facility
TVA Tennessee Valley Authority
UEP United Egg Producers
U.S. United States
USAF United States Air Force
USDA United States Department of Agriculture
USFS United States Forest Service
U-2 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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USGS United States Geological Survey
UNEP United Nations Environmental Programme
UNFCCC United Nations Framework Convention on Climate Change
VAIP EPA's Voluntary Aluminum Industrial Partnership
VMT Vehicle miles traveled
WMO World Meteorological Organization
U-3
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U-4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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ANNEX V
Chemical Symbols
Table V-1: Guide to Chemical Symbols
Symbol
Name
Al
AI203
Br
C
CH4
C2H6
C3H8
CF4
C2F6
C3F8
C-C4F8
CF3I
CFCI3
CF2CI2
CF3CI
C2F3CI3
CCI3CF3
C2F4CI2
C2F5CI
CHF2CI
^2^3 nCl2
C2F4HCI
C2FH3CI2
C2H3F2Cl
C3F5HCI2
CCI4
CHCICCI2
CCI2CCi2
CH3CI
CH3CCI3
CH2CI2
CHCI3
CHF3
CH2F2
CH3F
C2HF5
^2^*2M
CH2FCF3
C2H3F3
C2H3F3
C2H4r2
C3HF7
C3H2F6
C3H3F5
CsH2F10
CH2Br2
Aluminum
Aluminum Oxide
Bromine
Carbon
Methane
Ethane
Propane
Perfluoromethane
Pertluoroethane, hexafluoroethane
Perfluoropropane
Perfluorocyclobutane
Perfluoropentane
Perfluorahexane
Trifluoroiodomethane
Trichlorofluoromethane (CFC-11)
Dichlorodifluoromethane (CFC-12)
Chlorotrifluoromethane (CFC-13)
Trichlorotrifluoroethane (CFC-113)*
CFC-113a*
Dichlorotetraf luoroethane (CFC-114)
Chloropentafluoroethane (CFC-115)
Chlorodifluoromethane (HCFC-22)
HCFC-123
HCFC-124
HCFC-141b
HCFC-142b
HCFC-225ca/cb
Carbon tetrachloride
Trichloroethylene
Perchloroethylene, tetrachloroethene
Methylchloride •
Methylchloroform
Methylenechloride
Chloroform, trichloromethane
HFC-23
HFC-32
HFC-41
HFC-125
HFC-134
HFC-134a
HFC-143*
HFC-143a*
HFC-1523
HFC-227ea
HFC-236fa
HFC-245ca
HFC-43-10mee
Dibromomethane
V-1
-------
CHjBrCI
CHBr3
CH3Br
CF2BrCI
CF3Br(CBrF3)
CO
C02
CaC03
CaO
Cl
F
Fe
Fe203
FeSi
H.Hj
H20
HA
OH
N.N2
NH3
NH<+
HN03
NF3
N20
NO
N02
NO,
Na
Na2C03
0,02
03
S
H2S04
SF6
S02
Si
SiC
SiO,
Dibromochloromethane
Tribromomethane
Methylbromide
Bromodichloromethane (Halon 1211)
Bromotrifluoromethane (Halon 1301)
Carbon monoxide
Carbon dioxide
Calcium carbonate, Limestone
Dolomite
Calcium oxide, Lime
atomic Chlorine
Fluorine
Iron
Ferric oxide
Ferrosilicon
atomic Hydrogen, molecular Hydrogen
Water
Hydrogen peroxide
Hydroxyl
atomic Nitrogen, molecular Nitrogen
Ammonia
Ammonium ion
Nitric Acid
Nitrogen trifluoride
Nitrous oxide
Nitric oxide
Nitrogen dioxide
Nitrate radical
Sodium
Sodium carbonate, soda ash
Synthetic cryolite
atomic Oxygen, molecular Oxygen
Ozone
atomic Sulfur
Sulfuric acid
Sulfur hexafluoride
Sulfur dioxide
Silicon
Silicon carbide
Quartz
* Distinct isomers.
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ANNEXW
Glossary
Abiotic.7 Nonliving. Compare to biotic.
Absorption of radiation.1 The uptake of radiation by a solid body, liquid or gas. The absorbed energy may be
transferred or re-emitted.
Acid deposition.6 A complex chemical and atmospheric process whereby recombined emissions of sulfur and
nitrogen compounds are redeposited on earth in wet or dry form. See acid rain.
Acid rain.6 Rainwater that has an acidity content greater than the postulated natural pH of about 5.6. It is formed
when sulfur dioxides and nitrogen oxides, as gases or fine particles in the atmosphere, combine with water
vapor and precipitate as sulfuric acid or nitric acid in rain, snow, or fog. The dry forms are acidic gases or
particulates. See acid deposition.
Acid solution. 7 Any water solution that has more hydrogen ions (H+) than hydroxide ions (OH-); any water
solution with a pH less than 7. See basic solution, neutral solution.
Acidic.7 See acid solution.
Adiabaric process. 9 A thermodynamic change of state of a system such that no heat or mass is transferred across
the boundaries of the system.
compression in warming.
In an adiabatic process, expansion always results in cooling, and
Aerosol. Particulate matter, solid or liquid, larger than a molecule but small enough to remain suspended in the
atmosphere. Natural sources include salt particles from sea spray, dust and clay particles as a result of
weathering of rocks, both of which are carried upward by the wind. Aerosols can also originate as a result
of human activities and are often considered pollutants. Aerosols are important in the atmosphere as nuclei
for the condensation of water droplets and ice crystals, as participants in various chemical cycles, and as
absorbers and scatters of solar radiation, thereby influencing the radiation budget of the Earth's climate
system. See climate, particulate matter.
Afforestation.2 Planting of new forests on lands that have not been recently forested.
Air carrier 8 An operator (e.g., airline) in the commercial system of air transportation consisting of aircraft that
hold certificates of, Public Convenience and Necessity, issued by the Department of Transportation, to
conduct scheduled or non-scheduled flights within the country or abroad.
Air pollutant. See air pollution.
Air pollution. 7 One or more chemicals or substances in high enough concentrations in the air to harm humans,
other animals, vegetation, or materials. Such chemicals or physical conditions (such as excess heat or
noise) are called air pollutants.
Albedo. 9 The fraction of the total solar radiation incident on a body that is reflected by it.
Alkalinity.6 Having the properties of a base with a pH of more than 7. A common alkaline is baking soda.
Alternative energy.6 Energy derived from nontraditional sources (e.g., compressed natural gas, solar, hydroelectric,
wind).
Anaerobic.6 A life or process that occurs in, or is not destroyed by, the absence of oxygen.
Anaerobic decomposition.2 The breakdown of molecules into simpler molecules or atoms by microorganisms that
can survive in the partial or complete absence of oxygen.
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Anaerobic lagoon. ~ A liquid-based manure management system, characterized by waste residing in water to a
depth of at least six feet for a period ranging between 30 and 200 days. Bacteria produce methane in the
absence of oxygen while breaking down waste.
Anaerobic organism.7 Organism that does not need oxygen to stay alive. See aerobic organism.
Antarctic "Ozone Hole." 6 Refers to the seasonal depletion of stratospheric ozone in a large area over Antarctica.
See ozone layer.
Anthracite. ~ A hard, black, lustrous coal containing a high percentage of fixed carbon and a low percentage of
volatile matter. Often referred to as hard coal.
Anthropogenic. ~ Human made. In the context of greenhouse gases, emissions that are produced as the result of
human activities.
Arable land.7 Land that can be cultivated to grow crops.
Aromatic.6 Applied to a group of hydrocarbons and their derivatives characterized by the presence of the benzene
ring.
Ash.6 The mineral content of a product remaining after complete combustion.
Asphalt. ~ A dark-brown-to-black cement-like material containing bitumen as the predominant constituent. It is
obtained by petroleum processing. The definition includes crude asphalt as well as the following finished
products: cements, fluxes, the asphalt content of emulsions (exclusive of water), and petroleum distillates
blended with asphalt to make cutback asphalt.
Atmosphere.' The mixture of gases surrounding the Earth. The Earth's atmosphere consists of about 79.1 percent
nitrogen (by volume), 20.9 percent oxygen, 0.036 percent carbon dioxide and trace amounts, of other gases.
The atmosphere can be divided into a number of layers according to its mixing or chemical characteristics,
generally determined by its thermal properties (temperature). The layer nearest the Earth is the
troposphere, which reaches up to an altitude of about 8 kilometers (about 5 miles) in the polar regions and
up to 17 kilometers (nearly 11 miles) above the equator. The stratosphere, which reaches to an altitude of
about 50 kilometers (Similes) lies atop the troposphere. The mesosphere, which extends from 80 to 90
kilometers atop the stratosphere, and finally, the thermosphere, or ionosphere, gradually diminishes and
forms a fuzzy border with outer space. There is relatively little mixing of gases between layers.
Atmospheric lifetime. See lifetime.
Atomic weight. 6 The average weight (or mass) of all the isotopes of an element, as determined from the
proportions in which they are present in a given element, compared with the mass of the 12 isotope of
carbon (taken as precisely 12.000), that is the official international standard; measured in daltons.
Atoms.7 Minute particles that are the basic building blocks of all chemical elements and thus all matter.
Aviation Gasoline. 8 All special grades of gasoline for use in aviation reciprocating engines, as given in the
American Society for Testing and Materials (ASTM) specification D 910. Includes all refinery products
within the gasoline range that are to be marketed straight or in blends as aviation gasoline without further
processing (any refinery operation except mechanical blending). Also included are finished components in
the gasoline range, which will be used for blending or compounding into aviation gasoline.
Bacteria. 7 One-celled organisms. Many act as decomposers that break down dead organic matter into substances
that dissolve in water and are used as nutrients by plants.
Barrel (bbl). A liquid-volume measure equal to 42 United States gallons at 60 degrees Fahrenheit; used in
expressing quantities of petroleum-based products.
Basic solution. 7 Water solution with more hydroxide ions (OH-) than hydrogen ions (H+); water solutions with pH
greater than 7. See acid solution, alkalinity, acid.
Biodegradable. 7 Material that can be broken down into simpler substances (elements and compounds) by bacteria
or other decomposers. Paper and most organic wastes such as animal manure are biodegradable. See
nonbiodegradable.
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Biofuel. Gas or liquid fuel made from plant material (biomass). Includes wood, wood waste, wood liquors,
peat, railroad ties, wood sludge, spent sulfite liquors, agricultural waste, straw, tires, fish oils, tall oil,
sludge waste, waste alcohol, municipal solid waste, landfill gases, other waste, and ethanol blended into
motor gasoline.
Biogeochemical cycle.7 Natural processes that recycle nutrients in various chemical forms from the environment,
to organisms, and then back to the environment. Examples are the carbon, oxygen, nitrogen, phosphorus,
and hydrologic cycles.
Biological oxygen demand (BOD).7 Amount of dissolved oxygen needed by aerobic decomposers to break down
the organic materials in a given volume of water at a certain temperature over a specified time period. See
BODS.
Biomass. Total dry weight of all living organisms that can be supported at each tropic level in a food chain. Also,
materials that are biological in origin, including organic material (both living and dead) from above and
below ground, for example, trees, crops, grasses, tree litter, roots, and animals and animal waste.
Biomass energy.' Energy produced by combusting biomass materials such as wood. The carbon dioxide emitted
from burning biomass will not increase total atmospheric carbon dioxide if this consumption is done on a
sustainable basis (i.e., if in a given period of time, regrowth of biomass takes up as much carbon dioxide as
is released from biomass combustion). Biomass energy is often suggested as a replacement for fossil fuel
combustion.
Biosphere.2&7 The living and dead organisms found near the earth's surface in parts of the lithosphere, atmosphere,
and hydrosphere. The part of the global carbon cycle that includes living organisms and biogenic organic
matter.
Biotic. 7 Living. Living organisms make up the biotic parts of ecosystems. See abiotic.
Bitumen.7 Gooey, black, high-sulfur, heavy oil extracted from tar sand and then upgraded to synthetic fuel oil. See
tar sand.
Bituminous coal.2 A dense, black, soft coal, often with well-defined bands of bright and dull material. The most
common coal, with moisture content usually less than 20 percent. Used for generating electricity, making
coke, and space heating.
BODS. The biochemical oxygen demand of wastewater during decomposition occurring over a 5-day period. A
measure of the organic content of wastewater. See biological oxygen demand.
British thermal unit (Btu).3 The quantity of heat required to raise the temperature of one pound of water one
degree of Fahrenheit at or near 39.2 degrees Fahrenheit.
Bunker fuel. " Fuel supplied to ships and aircraft for international transportation, irrespective of the flag of the
carrier, consisting primarily of residual and distillate fuel oil for ships and jet fuel for aircraft.
Bus. A rubber-tired, self-propelled, manually steered vehicle that is generally designed to transport 30
individuals or more. Bus types include intercity, school and transit.
Capacity Factor. The ratio of the electrical energy produced by a generating unit for a given period of time to the
electrical energy that could have been produced at continuous full- power operation during the same period.
Carbon black. An amorphous form of carbon, produced commercially by thermal or oxidative decomposition of
hydrocarbons and used principally in rubber goods, pigments, and printer's ink.
Carbon cycle. 2 All carbon reservoirs and exchanges of carbon from reservoir to reservoir by various chemical,
physical, geological, and biological processes. Usually thought of as a series of the four main reservoirs of
carbon interconnected by pathways of exchange. The four reservoirs, regions of the Earth in which carbon
behaves in a systematic manner, are the atmosphere, terrestrial biosphere (usually includes freshwater
systems), oceans, and sediments (includes fossil fuels). Each of these global reservoirs may be subdivided
into smaller pools, ranging in size from individual communities or ecosystems to the total of all living
organisms (biota).
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Carbon dioxide.2 A colorless, odorless, non-poisonous gas that is a normal part of the ambient air. Carbon dioxide
is a product of fossil fuel combustion. Although carbon dioxide does not directly impair human health, it is
a greenhouse gas that traps terrestrial (i.e., infrared) radiation and contributes to the potential for global
warming. See global warming.
Carbon equivalent (CE).1 A metric measure used to compare the emissions of the different greenhouse gases
based upon their global warming potential (GWP). Greenhouse gas emissions in the United States are most
commonly expressed as "million metric tons of carbon equivalents" (MMTCE). Global warming potentials
are used to convert greenhouse gases to carbon dioxide equivalents. See global warming potential,
greenhouse gas.
Carbon flux.9 The rate of exchange of carbon between pools (i.e., reservoirs).
Carbon intensity. The relative amount of carbon emitted per unit of energy or fuels consumed.
Carbon pool.9 The reservoir containing carbon as a principal element in the geochemical cycle.
Carbon sequestration.' The uptake and storage of carbon. Trees and plants, for example, absorb carbon dioxide,
release the oxygen and store the carbon. Fossil fuels were at one time biomass and continue to store the
carbon until burned. See carbon sinks.
Carbon sinks.' Carbon reservoirs and conditions that take-in and store more carbon (i.e., carbon sequestration)
than they release. Carbon sinks can serve to partially offset greenhouse gas emissions. Forests and oceans
are large carbon sinks. See carbon sequestration.
Carbon tetrachloride (COU). n A compound consisting of one carbon atom and four chlorine atoms. It is an
ozone depleting substance. Carbon tetrachloride was widely used as a raw material in many industrial
applications, including the production of chlorofluorocarbons, and as a solvent. Solvent use was ended in
the United States when it was discovered to be carcinogenic. See ozone depleting substance.
Chemical reaction. 7 Interaction between chemicals in which there is a change in the chemical composition of the
elements or compounds involved.
Chlorofluorocarbons (CFCs). 7 Organic compounds made up of atoms of carbon, chlorine, and fluorine. An
example is CFC-12 (CC12F2), used as a refrigerant in refrigerators and air conditioners and as a foam
blowing agent Gaseous CFCs can deplete the ozone layer when they slowly rise into the stratosphere, are
broken down by strong ultraviolet radiation, release chlorine atoms, and then react with ozone molecules.
See Ozone Depleting Substance.
Climate.1&9 The average weather, usually taken over a 30 year time period, for a particular region and time period.
Climate is not the same as weather, but rather, it is the average pattern of weather for a particular region.
Weather describes the short-term state of the atmosphere. Climatic elements include precipitation,
temperature, humidity, sunshine, wind velocity, phenomena such as fog, frost, and hail-storms, and other
measures of the weather. See weather.
Climate change.1 The term "climate change" is sometimes used to refer to all forms of climatic inconsistency, but
because the Earth's climate is never static, the term is more properly used to imply a significant change
from one climatic condition to another. In some cases, "climate change" has been used synonymously with
the term, "global warming"; scientists however, tend to use the term in the wider sense to also include
natural changes in climate. See global warming, greenhouse effect, enhanced greenhouse effect, radiative
forcing.
Climate feedback.' An atmospheric, oceanic, terrestrial, or other process that is activated by direct climate change
induced by changes in radiative forcing. Climate feedbacks may increase (positive feedback) or diminish
(negative feedback) the magnitude of the direct climate change.
Climate lag.1 The delay that occurs in climate change as a result of some factor that changes very slowly. For
example, the effects of releasing more carbon dioxide into the atmosphere may not be known for some time
because a large fraction is dissolved in the ocean and only released to the atmosphere many years later.
Climate sensitivity. * The equilibrium response of the climate to a change in radiative forcing; for example, a
doubling of the carbon dioxide concentration. See radiative forcing.
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Cooling Degree Days: The number of degrees per day that the average daily temperature is above 65° Fahrenheit.
The daily average temperature is the mean of the maximum and minimum temperatures for a 24 hour
period. (See Degree Days)
Criteria pollutant.2 A pollutant determined to be hazardous to human health and regulated under EPA's National
Ambient Air Quality Standards. The 1970 amendments to the Clean Air Act require EPA to describe the
health and welfare impacts of a pollutant as the "criteria" for inclusion in the regulatory regime. In this
report, emissions of the criteria pollutants CO, NOX, NMVOCs, and SO2 are reported because they are
thought to be precursors to greenhouse gas formation.
Crop residue." Organic residue remaining after the harvesting and processing of a crop.
Crop rotation.7 Planting the same field or areas of fields with different crops from year to year to reduce depletion
of soil nutrients. A plant such as corn, tobacco, or cotton, which remove large amounts of nitrogen from
the soil, is planted one year. The next year a legume such as soybeans, which add nitrogen to the soil, is
planted.
Crude oil.' A mixture of hydrocarbons that exist in liquid phase in underground reservoirs and remain liquid at
atmospheric pressure after passing through surface separating facilities. See petroleum.
Deciduous trees. Trees such as oaks and maples that lose their leaves during part of the year. See coniferous
trees.
Decomposition. The breakdown of matter by bacteria and fungi. It changes the chemical composition and
physical appearance of the materials.
Deforestation.1 Those practices or processes that result in the conversion of forested lands for non-forest uses.
This is often cited as one of the major causes of the enhanced greenhouse effect for two reasons: 1) the
burning or decomposition of the wood releases carbon dioxide; and 2) trees that once removed carbon
dioxide from the atmosphere in the process of photosynthesis are no longer present.
Degradable.7 See biodegradable.
Degree Days (Population Weighted): Heating or cooling degree days weighted by the population of the area in
which the degree days are recorded. To compute State population-weighted degree days, each State is
divided into from one to nine climatically homogeneous divisions, which are assigned weights based on the
ratio of the population of the division to the total population of the State. Degree day readings for each
division are multiplied by the corresponding population weight for each division and those products are
then summed to arrive at the State population-weighted degree day value. To compute national population-
weighted degree days, the Nation is divided into nine Census regions, each comprising from three to eight
States, which are assigned weights based on the ratio of the population of the Nation. Degree day readings
for each region are multiplied by the corresponding population weight for each region and those products
are then summed to arrive at the national population-weighted degree day value. (See Heating Degree
Days, Cooling Degree Days, and Degree Day Normals)
Degree Day Normals: Simple arithmetic averages of monthly or annual degree days over a long period of time
(usually the 30 year period of 1961 through 1990). The averages may be dimple degree day normals or
population-weighted degree day normals.
Desertification.' The progressive destruction or degradation of existing vegetative cover to form a desert. This can
occur due to overgrazing, deforestation, drought, and the burning of extensive areas. Once formed, deserts
can only support a sparse range of vegetation. Climatic effects associated with this phenomenon include
increased reflectivity of solar radiation, reduced atmospheric humidity, and greater atmospheric dust
(aerosol) loading.
Distillate fuel oil. " A general classification for the petroleum fractions produced in conventional distillation
operations. Included are products known as No. 1, No. 2, and No. 4 fuel oils and No. 1, No. 2, and No. 4
diesel fuels. Used primarily for space heating, on and off-highway diesel engine fuel (including railroad
engine fuel and fuel for agricultural machinery), and electric power generation.
Economy.7 System of production, distribution, and consumption of economic goods.
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Ecosystem. !0 The complex system of plant, animal, fungal, and microorganism communities and their associated
non-living environment interacting as an ecological unit. Ecosystems have no fixed boundaries; instead
their parameters are set to the scientific, management, or policy question being examined. Depending upon
the purpose of analysis, a single lake, a watershed, or an entire region could be considered an ecosystem.
Electric Utility Sector: Privately and publicly owned establishments that generate, transmit, distribute, or sell
electricity primarily for use by the public and meet the definition of an electric utility. Electric utilities
include investor-owned, publicly owned, cooperative, and Federal utilities. Historically, they have
generally been vertically integrated companies that provide for generation, transmission, distribution,
and/or energy services for all customers in a designated service territory. Nonutility power producers are
not included in the electric utility sector.
Electrons.7 Tiny particle moving around outside the nucleus of an atom. Each electron has one unit of negative
charge (-) and almost no mass.
Element. 7 Chemicals such as hydrogen (H), iron (Fe), sodium (Na), carbon (C), nitrogen (N), or oxygen (O),
whose distinctly different atoms serve as the basic building blocks of all matter. There are 92 naturally
occurring elements. Another 15 have been made in laboratories. Two or more elements combine to form
compounds that make up most of the world's matter. See compound.
Emission inventory. A list of air pollutants emitted into a community's, state's, nation's, or the Earth's atmosphere
in amounts per some unit time (e.g. day or year) by type of source. An emission inventory has both
political and scientific applications.
Emissions coefficient/factor.2 A unique value for scaling emissions to activity data in terms of a standard rate of
emissions per unit of activity (e.g., grams of carbon dioxide emitted per barrel of fossil fuel consumed).
Emissions. ~ Releases of gases to the atmosphere (e.g., the release of carbon dioxide during fuel combustion).
Emissions can be either intended or unintended releases. See fugitive emissions.
Energy conservation.7 Reduction or elimination of unnecessary energy use and waste. See energy-efficiency.
Energy intensity. 5 Ratio between the consumption of energy to a given quantity of output; usually refers to the
amount of primary or final energy consumed per unit of gross domestic product.
Energy quality.7 Ability of a form of energy to do useful work. High-temperature heat and the chemical energy in
fossil fuels and nuclear fuels are concentrated high quality energy. Low-quality energy such as low-
temperature heat is dispersed or diluted and cannot do much useful work.
Energy.3 The capacity for doing work as measured by the capability of doing work (potential energy) or the
conversion of this capability to motion (kinetic energy). Energy has several forms, some of which are
easily convertible and can be changed to another form useful for work. Most of the world's convertible
energy comes from fossil fuels that are burned to produce heat that is then used as a transfer medium to
mechanical or other means in order to accomplish tasks. In the United States, electrical energy is often
measured in kilowatt-hours (kWh), while heat energy is often measured in British thermal units (Btu).
Energy-efficiency. 6&8 The ratio of the useful output of services from an article of industrial equipment to the
energy use by such an article; for example, vehicle miles traveled per gallon of fuel (mpg).
Enhanced greenhouse effect.l The concept that the natural greenhouse effect has been enhanced by anthropogenic
emissions of greenhouse gases. Increased concentrations of carbon dioxide, methane, and nitrous oxide,
CFCs, HFCs, PFCs, SF6, NF3, and other photochemically important gases caused by human activities such
as fossil fuel consumption, trap more infra-red radiation, thereby exerting a warming influence on the
climate. See greenhouse gas, anthropogenic, greenhouse effect, climate.
Enhanced oil recovery. 7 Removal of some of the heavy oil left in an oil well after primary and secondary
recovery. See primary oil recovery, secondary oil recovery.
Enteric fermentation. 2 A digestive process by which carbohydrates are broken down by microorganisms into
simple molecules for absorption into the bloodstream of an animal.
Environment. 7 All external conditions that affect an organism or other specified system during its lifetime.
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Ethanol (C2HSOH). 8 Otherwise known as ethyl alcohol, alcohol, or grain spirit. A clear, colorless, flammable
oxygenated hydrocarbon with a boiling point of 78.5 degrees Celsius in the anhydrous state. In
transportation, ethanol is used as a vehicle fuel by itself (El00), blended with gasoline (E85), or as a
gasoline octane enhancer and oxygenate (10 percent concentration).
Evapotranspiration.I0 The loss of water from the soil by evaporation and by transpiration from the plants growing
in the soil, which rises with air temperature.
Exponential growth. 7 Growth in which some quantity, such as population size, increases by a constant percentage
of the whole during each year or other time period; when the increase in quantity over time is plotted, this
type of growth yields a curve shaped like the letter J.
Feedlot. Confined outdoor or indoor space used to raise hundreds to thousands of domesticated livestock. See
rangeland.
Fertilization, carbon dioxide.' An expression (sometimes reduced to 'fertilization') used to denote increased plant
growth due to a higher carbon dioxide concentration.
Fertilizer.7 Substance that adds inorganic or organic plant nutrients to soil and improves its ability to grow crops,
trees, or other vegetation. See organic fertilizer.
Flaring.9 The burning of waste gases through a flare stack or other device before releasing them to the air.
Fluidized bed combustion (FBC).7 Process for burning coal more efficiently, cleanly, and cheaply. A stream of
hot air is used to suspend a mixture of powdered coal and limestone during combustion. About 90 to 98
percent of the sulfur dioxide produced during combustion is removed by reaction with limestone to produce
solid calcium sulfate.
Fluorocarbons. ' Carbon-fluorine compounds that often contain other elements such as hydrogen, chlorine, or
bromine. Common fluorocarbons include chlorofluorocarbons (CFCs), hydrochlorofluorocarbons
(HCFCs), hydrofluorocarbons (MFCs), and perfluorocarbons (PFCs). See chlorofluorocarbons,
hydrochlorofluorocarbons, hydrofluorocarbons, perfluorocarbons.
Forcing mechanism. ' A process that alters the energy balance of the climate system (i.e., changes the relative
balance between incoming solar radiation and outgoing infrared radiation from Earth). Such mechanisms
include changes in solar irradiance, volcanic eruptions, and enhancement of the natural greenhouse effect
by emission of carbon dioxide.
Forest. 7 Terrestrial ecosystem (biome) with enough average annual precipitation (at least 76 centimeters or 30
inches) to support growth of various species of trees and smaller forms of vegetation.
Fossil fuel. A general term for buried combustible geologic deposits of organic materials, formed from decayed
plants and animals that have been converted to crude oil, coal, natural gas, or heavy oils by exposure to
heat and pressure in the earth's crust over hundreds of millions of years. See coal, petroleum, crude oil,
natural gas.
Fossil fuel combustion.' Burning of coal, oil (including gasoline), or natural gas. The burning needed to generate
energy release carbon dioxide by-products that can include unburned hydrocarbons, methane, and carbon
monoxide. Carbon monoxide, methane, and many of the unburned hydrocarbons slowly oxidize into
carbon dioxide in the atmosphere. Common sources of fossil fuel combustion include cars and electric
utilities.
Freon. See chlorofluorocarbon.
Fugitive emissions. ~ Unintended gas leaks from the processing, transmission, and/or transportation of fossil fuels,
CFCs from refrigeration leaks, SF6 from electrical power distributor, etc.
Gasohol. 7 Vehicle fuel consisting of a mixture of gasoline and ethyl or methyl alcohol; typically 10 to 23 percent
ethanol by volume.
General Aviation. 8 That portion of civil aviation, which encompasses all facets of aviation except air carriers. It
includes any air taxis, commuter air carriers, and air travel clubs, which do not hold Certificates of Public
Convenience and Necessity. See air carriers.
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General circulation model (GCM). ' A global, three-dimensional computer model of the climate system which
can be used to simulate human-induced climate change. GCMs are highly complex and they represent the
effects of such factors as reflective and absorptive properties of atmospheric water vapor, greenhouse gas
concentrations, clouds, annual and daily solar heating, ocean temperatures and ice boundaries. The most
recent GCMs include global representations of the atmosphere, oceans, and land surface.
Geosphere. l The soils, sediments, and rock layers of the Earth's crust, both continental and beneath the ocean
floors.
Geothermal energy.7 Heat transferred from the earth's molten core to under-ground deposits of dry steam (steam
with no water droplets), wet steam (a mixture of steam and water droplets), hot water, or rocks lying fairly
close to the earth's surface.
Global Warming Potential (GWP).l The index used to translate the level of emissions of various gases into a
common measure in order to compare the relative radiative forcing of different gases without directly
calculating the changes in atmospheric concentrations. GWPs are calculated as the ratio of the radiative
forcing that would result from the emissions of one kilogram of a greenhouse gas to that from the emission
of one kilogram of carbon dioxide over a period of time (usually 100 years). Gases involved in complex
atmospheric chemical processes have not been assigned GWPs. See lifetime.
Global warming. 10 The progressive gradual rise of the earth's surface temperature thought to be caused by the
greenhouse effect and responsible for changes in global climate patterns. See enhanced greenhouse effect,
greenhouse effect, climate change.
Grassland. 7 Terrestrial ecosystem (biome) found in regions where moderate annual average precipitation (25 to 76
centimeters or 10 to 30 inches) is enough to support the growth of grass and small plants but not enough to
support large stands of trees.
Greenhouse effect.7 Trapping and build-up of heat in the atmosphere (troposphere) near the earth's surface. Some
of the heat flowing back toward space from the earth's surface is absorbed by water vapor, carbon dioxide,
ozone, and several other gases in the atmosphere and then reradiated back toward the earth's surface. If the
atmospheric concentrations of these greenhouse gases rise, the average temperature of the lower
atmosphere will gradually increase. See enhanced greenhouse effect, climate change, global -warming.
Greenhouse gas (GHG).l Any gas that absorbs infrared radiation in the atmosphere. Greenhouse gases include,
but are not limited to, water vapor, carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O),
hydrochlorofluorocarbons (HCFCs), ozone (O3), hydrofluorocarbons (MFCs), perfluorocarbons (PFCs),
and sulfur hexafluoride (SF6). See carbon dioxide, methane, nitrous oxide, hydrochlorofluorocarbon,
ozone, hydrofluorocarbon, perfluorocarbon, sulfur hexafluoride.
Halocarbons. ' Chemicals consisting of carbon, sometimes hydrogen, and either chlorine, fluorine, bromine or
iodine.
Halons.' Compounds, also known as bromofluorocarbons, that contain bromine, fluorine, and carbon. They are
generally used as fire extinguishing agents and cause ozone depletion. Bromine is many times more
effective at destroying stratospheric ozone than chlorine. See ozone depleting substance.
Heat.7 Form of kinetic energy that flows from one body to another when there is a temperature difference between
the two bodies. Heat always flows spontaneously from a hot sample of matter to a colder sample of matter.
This is one way to state the second law of thermodynamics. See temperature.
Heat content.5 The amount of heat per unit mass released upon complete combustion.
Heating Degree Days: The number of degrees per day that the average daily temperature is below 65° Fahrenheit.
The daily average temperature is the mean of the maximum and minimum temperatures for a 24 hour
period. (See Degree Days)
Higher heating value.5 Quantity of heat liberated by the complete combustion of a unit volume or weight of a fuel
assuming that the produced water vapor is completely condensed and the heat is recovered; also known as
gross calorific value. See lower heating value.
Histosol.9 Wet organic soils, such as peats and mucks.
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Hydrocarbons. ' Substances containing only hydrogen and carbon. Fossil fuels are made up of hydrocarbons.
Some hydrocarbon compounds are major air pollutants.
Hydrochlorofluorocarbons (HCFCs). ' Compounds containing hydrogen, fluorine, chlorine, and carbon atoms.
Although ozone depleting substances, they are less potent at destroying stratospheric ozone than
chlorofluorocarbons (CFCs). They have been introduced as temporary replacements for CFCs and are also
greenhouse gases. See ozone depleting substance.
Hydroelectric power plant. 7 Structure in which the energy of fading or flowing water spins a turbine generator to
produce electricity.
Hydrofluorocarbons (HFCs).' Compounds containing only hydrogen, fluorine, and carbon atoms. They were
introduced as alternatives to ozone depleting substances in serving many industrial, commercial, and
personal needs. HFCs are emitted as by-products of industrial processes and are also used in
manufacturing. They do not significantly deplete the stratospheric ozone layer, but they are powerful
greenhouse gases with global warming potentials ranging from 140 (HFC-152a) to 11,700 (HFC-23).
Hydrologic cycle. The process of evaporation, vertical and horizontal transport of vapor, condensation,
precipitation, and the flow of water from continents to oceans. It is a major factor in determining climate
through its influence on surface vegetation, the clouds, snow and ice, and soil moisture. The hydrologic
cycle is responsible for 25 to 30 percent of the mid-latitudes' heat transport from the equatorial to polar
regions.
Hydropovver.7 Electrical energy produced by falling or flowing water. See hydroelectric power plant.
Hydrosphere. 7 All the earth's liquid water (oceans, smaller bodies of fresh water, and underground aquifers),
frozen water (polar ice caps, floating ice, and frozen upper layer of soil known as permafrost), and small
amounts of water vapor in the atmosphere.
Industrial End-Use Sector: Comprises manufacturing industries, which make up the largest part of the sector,
along with mining, construction, agriculture, fisheries, and forestry. Establishments in this sector range
from steel mills to small farms to companies assembling electronic components. Nonutility power
producers are also included in the industrial end-use sector.
Infrared radiation.' The heat energy that is emitted from all solids, liquids, and gases. In the context of the
greenhouse issue, the term refers to the heat energy emitted by the Earth's surface and its atmosphere.
Greenhouse gases strongly absorb this radiation in the Earth's atmosphere, and re-radiate some of it back
towards the surface, creating the greenhouse effect.
Inorganic compound. 7 Combination of two or more elements other than those used to form organic compounds.
See organic compound.
Inorganic fertilizer. 7 See synthetic fertilizer.
Intergovernmental Panel on Climate Change (IPCC).J The IPCC was established jointly by the United Nations
Environment Programme and the World Meteorological Organization in 1988. The purpose of the IPCC is
to assess information in the scientific and technical literature related to all significant components of the
issue of climate change. The IPCC draws upon hundreds of the world's expert scientists as authors and
thousands as expert reviewers. Leading experts on climate change and environmental, social, and
economic sciences from some 60 nations have helped the IPCC to prepare periodic assessments of the
scientific underpinnings for understanding global climate change and its consequences. With its capacity
for reporting on climate change, its consequences, and the viability of adaptation and mitigation measures,
the IPCC is also looked to as the official advisory body to the world's governments on the state of the
science of the climate change issue. For example, the IPCC organized the development of internationally
accepted methods for conducting national greenhouse gas emission inventories.
Irreversibilities.I0 Changes that, once set in motion, cannot be reversed, at least on human time scales.
Jet fuel s Includes both naphtha-type and kerosene-type fuels meeting standards for use in aircraft turbine engines.
Although most jet fuel is used in aircraft, some is used for other purposes such as generating electricity.
Joule.' The energy required to push with a force of one Newton for one meter.
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Kerogen. Solid, waxy mixture of hydrocarbons found in oil shale, with a fine grained sedimentary rock. When
the rock is heated to high temperatures, the kerogen is vaporized. The vapor is condensed and then sent to
a refinery to produce gasoline, heating oil, and other products. See oil shale, shale oil.
Kerosene. - A petroleum distillate that has a maximum distillation temperature of 401 degrees Fahrenheit at the 10
percent recovery point, a final boiling point of 572 degrees Fahrenheit, and a minimum flash point of 100
degrees Fahrenheit. Used in space heaters, cookstoves, and water heaters, and suitable for use as an
illuminant when burned in wick lamps.
Kyoto Protocol. 10 This is an international agreement struck by 159 nations attending the Third Conference of
Parties (COP) to the United Nations Framework Convention on Climate Change (held in December of 1997
in Kyoto Japan) to reduce worldwide emissions of greenhouse gases. If ratified and put into force,
individual countries have committed to reduce their greenhouse gas emissions by a specified amount. See
Framework Convention on Climate Change, Conference of Parties.
Landfill.7 Land waste disposal site in which waste is generally spread in thin layers, compacted, and covered with
a fresh layer of soil each day.
Lifetime (atmospheric).' The lifetime of a greenhouse gas refers to the approximate amount of time it would take
for the anthropogenic increment to an atmospheric pollutant concentration to return to its natural level
(assuming emissions cease) as a result of either being converted to another chemical compound or being
taken out of the atmosphere via a sink. This time depends on the pollutant's sources and sinks as well as its
reactivity. The lifetime of a pollutant is often considered in conjunction with the mixing of pollutants in the
atmosphere; a long lifetime will allow the pollutant to mix throughout the atmosphere. Average lifetimes
can vary from about a week (e.g., sulfate aerosols) to more than a century (e.g., CFCs, carbon dioxide).
See residence time.
Light-duty vehicles.8 Automobiles and light trucks combined.
Lignite.2 A brownish-black coal of low rank with high inherent moisture and volatile matter content, used almost
exclusively for electric power generation. Also referred to as brown coal.
Liquefied natural gas (LNG). 7 Natural gas converted to liquid form by cooling to a very low temperature.
Liquefied petroleum gas (LPG).2 Ethane, ethylene, propane, propylene, normal butane, butylene, and isobutane
produced at refineries or natural gas processing plants, including plants that fractionate new natural gas
plant liquids.
Litter.9 Undecomposed plant residues on the soil surface. See decomposition.
Longwave radiation. 9 The radiation emitted in the spectral wavelength greater than 4 micrometers corresponding
to the radiation emitted from the Earth and atmosphere. It is sometimes referred to as terrestrial radiation
or infrared radiation, although somewhat imprecisely. See infrared radiation.
Low Emission Vehicle (LEV).8 A vehicle meeting the low-emission vehicle standards.
Lower heating value.5 Quantity of heat liberated by the complete combustion of a unit volume or weight of a fuel
assuming that the produced water remains as a vapor and the heat of the vapor is not recovered; also known
as net calorific value. See higher heating value.
Lubricant. " A substance used to reduce friction between bearing surfaces or as a process material, either
incorporated into other materials used as aids in manufacturing processes or as carriers of other materials.
Petroleum lubricants may be produced either from distillates or residues. Other substances may be added
to impart or improve useful properties. Does not include by-products of lubricating oil from solvent
extraction or tars derived from de-asphalting. Lubricants include all grades of lubricating oils from spindle
oil to cylinder oil and those used in greases. Lubricant categories are paraffinic and naphthenic.
Manure.7 Dung and urine of animals that can be used as a form of organic fertilizer.
Mass balance.9 The application of the principle of the conservation of matter.
Mauna Loa. 9 An intermittently active volcano 13,680 feet (4,170 meters) high in Hawaii.
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Methane (Ctti).' A hydrocarbon that is a greenhouse gas with a global warming potential most recently estimated
at 21. Methane is produced through anaerobic (without oxygen) decomposition of waste in landfills,
animal digestion, decomposition of animal wastes, production and distribution of natural gas and
petroleum, coal production, and incomplete fossil fuel combustion. The atmospheric concentration of
methane as been shown to be increasing at a rate of about 0.6 percent per year and the concentration of
about 1.7 per million by volume (ppmv) is more than twice its pre-industrial value. However, the rate of
increase of methane in the atmosphere may be stabilizing.
Methanol (CH3OH). 8 A colorless poisonous liquid with essentially no odor and little taste. It is the simplest
alcohol with a boiling point of 64.7 degrees Celsius. In transportation, methanol is used as a vehicle fuel
by itself (Ml 00), or blended with gasoline (M85).
Methanotrophic. 7 Having the biological capacity to oxidize methane to CO2 and water by metabolism under
aerobic conditions. See aerobic.
Methyl bromide (CH3Br). u An effective pesticide; used to fumigate soil and many agricultural products.
Because it contains bromine, it depletes stratospheric ozone when released to the atmosphere. See ozone
depleting substance.
Metric ton.' Common international measurement for the quantity of greenhouse gas emissions. A metric ton is
equal to 1000 kilograms, 2204.6 pounds, or 1.1023 short tons.
Mineral.7 Any naturally occurring inorganic substance found in the earth's crust as a crystalline solid.
Model year.s Refers to the "sales" model year; for example, vehicles sold during the period from October 1 to the
next September 31 is considered one model year.
Molecule. 7 Chemical combination of two or more atoms of the same chemical element (such as O2) or different
chemical elements (such as H^O).
Montreal Protocol on Substances that Deplete the Ozone Layer. n The Montreal Protocol and its amendments
control the phaseout of ozone depleting substances production and use. Under the Protocol, several
international organizations report on the science of ozone depletion, implement projects to help move away
from ozone depleting substances, and provide a forum for policy discussions. In the United States, the
Protocol is implemented under the rubric of the Clean Air Act Amendments of 1990. See ozone depleting
substance, ozone layer.
Motor gasoline. 2 A complex mixture of relatively volatile hydrocarbons, with or without small quantities of
additives, obtained by blending appropriate refinery streams to form a fuel suitable for use in spark-ignition
engines. Motor gasoline includes both leaded and unleaded grades of finished gasoline, blending
components, and gasohol.
Municipal solid waste (MSW).2 Residential solid waste and some non-hazardous commercial, institutional, and
industrial wastes. This material is generally sent to municipal landfills for disposal. See landfill
Naphtha. ~ A generic term applied to a petroleum fraction with an approximate boiling range between 122 and 400
degrees Fahrenheit.
Natural gas.7 Underground deposits of gases consisting of 50 to 90 percent methane (CHU) and small amounts of
heavier gaseous hydrocarbon compounds such as propane (CsHt) and butane (C4Hio).
Natural gas liquids (NGLs). 2 Those hydrocarbons in natural gas that are separated as liquids from the gas.
Includes natural gas plant liquids and lease condensate.
Nitrogen cycle. 7 Cyclic movement of nitrogen in different chemical forms from the environment, to organisms,
and then back to the environment.
Nitrogen fixation. 7 Conversion of atmospheric nitrogen gas into forms useful to plants and other organisms by
lightning, bacteria, and blue-green algae; it is part of the nitrogen cycle.
Nitrogen oxides (NOx). * Gases consisting of one molecule of nitrogen and varying numbers of oxygen molecules.
Nitrogen oxides are produced, for example, by the combustion of fossil fuels in vehicles and electric power
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plants. In the atmosphere, nitrogen oxides can contribute to formation of photochemical ozone (smog),
impair visibility, and have health consequences; they are considered pollutants.
Nitrous oxide (N2O).l A powerful greenhouse gas with a global warming potential most recently evaluated at 310.
Major sources of nitrous oxide include soil cultivation practices, especially the use of commercial and
organic fertilizers, fossil fuel combustion, nitric acid production, and biomass burning.
Nonbiodegradable. 7 Substance that cannot be broken down in the environment by natural processes. See
biodegradable.
Nonlinearities.10 Occur when changes in one variable cause a more than proportionate impact on another variable.
Non-methane volatile organic compounds (NMVOCs). 2 Organic compounds, other than methane, that
participate in atmospheric photochemical reactions.
Non-point source. 7 Large land area such as crop fields and urban areas that discharge pollutant into surface and
underground water over a large area. See point source.
Nonutility Power Producer: A corporation, person, agency, authority, or other legal entity of instrumentality that
owns electric generating capacity and is not an electric utility. Nonutility producers include qualifying
cogenerators, qualifying small power producers, and other nonutility generators (including independent
power producers) without a designated, franchised, service area that do not file forms listed in the Code of
Federal Regulations, Title 18, Part 141.
Nuclear electric power.3 Electricity generated by an electric power plant whose turbines are driven by steam
generated in a reactor by heat from the fissioning of nuclear fuel.
Nuclear energy. 7 Energy released when atomic nuclei undergo a nuclear reaction such as the spontaneous
emission of radioactivity, nuclear fission, or nuclear fusion.
Oil shale. Underground formation of a fine-grained sedimentary rock containing varying amounts of kerogen, a
solid, waxy mixture of hydrocarbon compounds. Heating the rock to high temperatures converts the
kerogen to a vapor, which can be condensed to form a slow flowing heavy oil called shale oil. See
kerogen, shale oil.
Oil. See crude oil, petroleum.
Ore. Mineral deposit containing a high enough concentration of at least one metallic element to permit the metal
to be extracted and sold at a profit.
Organic compound.7 Molecule that contains atoms of the element carbon, usually combined with itself and with
atoms of one or more other element such as hydrogen, oxygen, nitrogen, sulfur, phosphorus, chlorine, or
fluorine. See inorganic compound.
Organic fertilizer. 7 Organic material such as manure or compost, applied to cropland as a source of plant
nutrients.
Oxidize.2 To chemically transform a substance by combining it with oxygen.
Oxygen cycle. Cyclic movement of oxygen in different chemical forms from the environment, to organisms, and
then back to the environment.
Ozone. 6 A colorless gas with a pungent odor, having the molecular form of O3, found in two layers of the
atmosphere, the stratosphere and the troposphere. Ozone is a form of oxygen found naturally in the
stratosphere that provides a protective layer shielding the Earth from ultraviolet radiation's harmful health
effects on humans and the environment. In the troposphere, ozone is a chemical oxidant and major
component of photochemical smog. Ozone can seriously affect the human respiratory system.
Ozone Depleting Substance (ODS). u A family of man-made compounds that includes, but are not limited to,
chlorofluorocarbons (CFCs), bromofluorocarbons (halons), methyl chloroform, carbon tetrachloride,
methyl bromide, and hydrochlorofluorocarbons (HCFCs). These compounds have been shown to deplete
stratospheric ozone, and therefore are typically referred to as ODSs.
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Ozone layer. 7 Layer of gaseous ozone (O3) in the stratosphere that protects life on earth by filtering out harmful
ultraviolet radiation from the sun. See stratosphere, ultraviolet radiation.
Ozone precursors.2 Chemical compounds, such as carbon monoxide, methane, non-methane hydrocarbons, and
nitrogen oxides, which in the presence of solar radiation react with other chemical compounds to form
ozone, mainly in the troposphere. See troposphere
Participate matter (PM).7 Solid particles or liquid droplets suspended or carried in the air.
Particulates. See particulate matter.
Parts per billion (ppb).7 Number of parts of a chemical found in one billion parts of a particular gas, liquid, or
solid mixture. See concentration.
Parts per million (ppm). 7 Number of parts of a chemical found in one million parts of a particular gas, liquid, or
solid. See concentration.
Pentanes plus.2 A mixture of hydrocarbons, mostly pentanes and heavier fractions, extracted from natural gas.
Perfluorocarbons (PFCs). ' A group of human-made chemicals composed of carbon and fluorine only. These
chemicals (predominantly CF4 and C2F6) were introduced as alternatives, along with hydrofluorocarbons, to
the ozone depleting substances. In addition, PFCs are emitted as by-products of industrial processes and
are also used in manufacturing. PFCs do not harm the stratospheric ozone layer, but they are powerful
greenhouse gases: CF4 has a global warming potential (GWP) of 6,500 and C2F6 has a GWP of 9,200.
Petrochemical feedstock.2 Feedstock derived from petroleum, used principally for the manufacture of chemicals,
synthetic rubber, and a variety of plastics. The categories reported are naphtha (endpoint less than 401
degrees Fahrenheit) and other oils (endpoint equal to or greater than 401 degrees Fahrenheit).
Petrochemicals. 7 Chemicals obtained by refining (i.e., distilling) crude oil. They are used as raw materials in the
manufacture of most industrial chemicals, fertilizers, pesticides, plastics, synthetic fibers, paints, medicines,
and many other products. See crude oil.
Petroleum coke. ~ A residue that is the final product of the condensation process in cracking.
Petroleum. 2 A generic term applied to oil and oil products in all forms, such as crude oil, lease condensate,
unfinished oils, petroleum products, natural gas plant liquids, and non-hydrocarbon compounds blended
into finished petroleum products. See crude oil.
Photosynthesis. 7 Complex process that takes place in living green plant cells. Radiant energy from the sun is used
to combine carbon dioxide (CO2) and water (H2O) to produce oxygen (O2) and simple nutrient molecules,
such as glucose (CgHioOg).
Photovoltaic and solar thermal energy. ~ Energy radiated by the sun as electromagnetic waves (electromagnetic
radiation) that is converted into electricity by means of solar (i.e., photovoltaic) cells or useable heat by
concentrating (i.e., focusing) collectors.
Point source. 7 A single identifiable source that discharges pollutants into the environment Examples are
smokestack, sewer, ditch, or pipe. See non-point source.
Pollution. 7 A change in the physical, chemical, or biological characteristics of the air, water, or soil that can affect
the health, survival, or activities of humans in an unwanted way. Some expand the term to include harmful
effects on all forms of life.
Polyvinyl chloride (PVC). ~ A polymer of vinyl chloride. It is tasteless, odorless and insoluble in most organic
solvents. A member of the family vinyl resin, used in soft flexible films for food packaging and in molded
rigid products, such as pipes, fibers, upholstery, and bristles.
Population. 7 Group of individual organisms of the same species living within a particular area.
Prescribed burning. 7 Deliberate setting and careful control of surface fires in forests to help prevent more
destructive fires and to kill off unwanted plants that compete with commercial species for plant nutrients;
may also be used on grasslands.
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Primary oil recovery. Pumping out the crude oil that flows by gravity into the bottom of an oil well. See
enhanced oil recovery, secondary oil recover)'.
Quad.8 Quad stands for quadrillion, which is, 1015.
Radiation. Energy emitted in the form of electromagnetic waves. Radiation has differing characteristics
depending upon the wavelength. Because the radiation from the Sun is relatively energetic, it has a short
wavelength (e.g., ultraviolet, visible, and near infrared) while energy re-radiated from the Earth's surface
and the atmosphere has a longer wavelength (e.g., infrared radiation) because the Earth is cooler than the
Sun. See ultraviolet radiation, infrared radiation, solar radiation, longwave radiation, terrestrial
radiation.
Radiative forcing. A change in the balance between incoming solar radiation and outgoing infrared (i.e., thermal)
radiation. Without any radiative forcing, solar radiation coming to the Earth would continue to be
approximately equal to the infrared radiation emitted from the Earth. The addition of greenhouse gases to
the atmosphere traps an increased fraction of the infrared radiation, reradiating it back toward the surface of
the Earth and thereby creates a warming influence.
Rail. 8 Includes "heavy" and "light" transit rail. Heavy transit rail is characterized by exclusive rights-of-way,
multi-car trains, high speed rapid acceleration, sophisticated signaling, and high platform loading. Also
known as subway, elevated railway, or metropolitan railway (metro). Light transit rail may be on exclusive
or shared rights of way, high or low platform, multi-car trains or single cars, automated or manually
operated. In generic usage, light rail includes streetcars, trolley cars, and tramways.
Rangeland. 7 Land, mostly grasslands, whose plants can provide food (i.e., forage) for grazing or browsing
animals. Seefeedlot.
Recycling. 7 Collecting and reprocessing a resource so it can be used again. An example is collecting aluminum
cans, melting them down, and using the aluminum to make new cans or other aluminum products.
Reforestation.2 Replanting of forests on lands that have recently been harvested.
Renewable energy.2 Energy obtained from sources that are essentially inexhaustible, unlike, for example, the fossil
fuels, of which there is a finite supply. Renewable sources of energy include wood, waste, geothermal,
wind, photovoltaic, and solar thermal energy. See hydropower, photovoltaic.
Residence time.* Average time spent in a reservoir by an individual atom or molecule. Also, this term is used to
define the age of a molecule when it leaves the reservoir. With respect to greenhouse gases, residence time
usually refers to how long a particular molecule remains in the atmosphere. See lifetime.
Residential End-Use Sector: Consists of all private residences, whether occupied or vacant, owned or rented,
including single family homes, multifamily housing units, and mobile homes. Secondary home, such as
summer homes, are also included. Institutional housing, such as school dormitories, hospitals, and military
barracks, generally are not included in the residential end-use sector, but are instead included in the
commercial end-use sector.
Residual fuel oil.2 The heavier oils that remain after the distillate fuel oils and lighter hydrocarbons are distilled
away in refinery operations and that conform to ASTM Specifications D396 and D975. Included are No. 5,
a residual fuel oil of medium viscosity; Navy Special, for use in steam-powered vessels in government
service and in shore power plants; and No. 6, which includes Bunker C fuel oil and is used for commercial
and industrial heating, electricity generation, and to power ships. Imports of residual fuel oil include
imported crude oil burned as fuel.
Secondary oil recovery. 7 Injection of water into an oil well after primary oil recovery to force out some of the
remaining thicker crude oil. See enhanced oil recovery, primary oil recovery.
Sector. Division, most commonly used to denote type of energy consumer (e.g., residential) or according to the
Intergovernmental Panel on Climate Change, the type of greenhouse gas emitter (e.g. industrial process).
See Intergovernmental Panel on Climate Change.
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Septic tank.7 Underground tank for treatment of wastewater from a home in rural and suburban areas. Bacteria in
the tank decompose organic wastes and the sludge settles to the bottom of the tank. The effluent flows out
of the tank into the ground through a field of drainpipes.
Sewage treatment (primary). 7 Mechanical treatment of sewage in which large solids are filtered out by screens
and suspended solids settle out as sludge in a sedimentation tank.
Shale oil. 7 Slow-flowing, dark brown, heavy oil obtained when kerogen in oil shale is vaporized at high
temperatures and then condensed. Shale oil can be refined to yield gasoline, heating oil, and other
petroleum products. See kerogen, oil shale.
Short ton.' Common measurement for a ton in the United States. A short ton is equal to 2,000 Ibs. or 0.907 metric
tons.
Sink.' A reservoir that uptakes a pollutant from another part of its cycle. Soil and trees tend to act as natural sinks
for carbon.
Sludge. 7 Gooey solid mixture of bacteria and virus laden organic matter, toxic metals, synthetic organic chemicals,
and solid chemicals removed from wastewater at a sewage treatment plant.
Soil. 7 Complex mixture of inorganic minerals (i.e., mostly clay, silt, and sand), decaying organic matter, water, air,
and living organisms.
Soil carbon. 9 A major component of the terrestrial biosphere pool in the carbon cycle. The amount of carbon in
the soil is a function of the historical vegetative cover and productivity, which in turn is dependent in part
upon climatic variables.
Solar energy. 7 Direct radiant energy from the sun. It also includes indirect forms of energy such as wind, falling
or flowing water (hydropower), ocean thermal gradients, and biomass, which are produced when direct
solar energy interact with the earth. See solar radiation.
Solar radiation.' Energy from the Sun. Also referred to as short-wave radiation. Of importance to the climate
system, solar radiation includes ultra-violet radiation, visible radiation, and infrared radiation.
Source.4 Any process or activity that releases a greenhouse gas, an aerosol, or a precursor of a greenhouse gas into
the atmosphere.
Special naphtha.2 All finished products within the naphtha boiling range that are used as paint thinners, cleaners,
or solvents. Those products are refined to a specified flash point.
Still gas. 2 Any form or mixture of gases produced in refineries by distillation, cracking, reforming, and other
processes. Principal constituents are methane, ethane, ethylene, normal butane, butylene, propane,
propylene, etc. Used as a refinery fuel and as a petrochemical feedstock.
Stratosphere. 7 Second layer of the atmosphere, extending from about 19 to 48 kilometers (12 to 30 miles) above
the earth's surface. It contains small amounts of gaseous ozone (Os), which filters out about 99 percent of
the incoming harmful ultraviolet (UV) radiation. Most commercial airline flights operate at a cruising
altitude in the lower stratosphere. See ozone layer, ultraviolet radiation.
Stratospheric ozone. See ozone layer.
Strip mining. 7 Cutting deep trenches to remove minerals such as coal and phosphate found near the earth's surface
hi flat or rolling terrain. See surface mining.
Subbituminous coal.2 A dull, black coal of rank intermediate between lignite and bituminous coal.
Sulfur cycle. 7 Cyclic movement of sulfur in different chemical forms from the environment, to organisms, and
then back to the environment.
Sulfur dioxide (SO2).' A compound composed of one sulfur and two oxygen molecules. Sulfur dioxide emitted
into the atmosphere through natural and anthropogenic processes is changed in a complex series of
chemical reactions in the atmosphere to sulfate aerosols. These aerosols are believed to result in negative
radiative forcing (i.e., tending to cool the Earth's surface) and do result in acid deposition (e.g., acid rain).
See aerosols, radiative forcing, acid deposition, acid rain.
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Sulfur hexafluoride (SF6). ' A colorless gas soluble in alcohol and ether, slightly soluble in water. A very
powerful greenhouse gas used primarily in electrical transmission and distribution systems and as a
dielectric in electronics. The global warming potential of SF6 is 23,900. See Global Warming Potential.
Surface mining. 7 Removal of soil, sub-soil, and other strata and then extracting a mineral deposit found fairly
close to the earth's surface. See strip mining.
Synthetic fertilizer. 7 Commercially prepared mixtures of plant nutrients such as nitrates, phosphates, and
potassium applied to the soil to restore fertility and increase crop yields. See organic fertilizer.
Synthetic natural gas (SNG). 3 A manufactured product chemically similar in most respects to natural gas,
resulting from the conversion or reforming of petroleum hydrocarbons. It may easily be substituted for, or
interchanged with, pipeline quality natural gas.
Tailings.7 Rock and other waste materials removed as impurities when minerals are mined and mineral deposits are
processed. These materials are usually dumped on the ground or into ponds.
Tar sand. 7 Swamp-like deposit of a mixture of fine clay, sand, water, and variable amounts of tar-like heavy oil
known as bitumen. Bitumen can be extracted from tar sand by heating. It can then be purified and
upgraded to synthetic crude oil. See bitumen.
Temperature.7 Measure of the average speed of motion of the atoms or molecules in a substance or combination
of substances at a given moment. See heat.
Terrestrial.7 Pertaining to land.
Terrestrial radiation. 9 The total infrared radiation emitted by the Earth and its atmosphere in the temperature
range of approximately 200 to 300 Kelvin. Terrestrial radiation provides a major part of the potential
energy changes necessary to drive the atmospheric wind system and is responsible for maintaining the
surface air temperature within limits of livability.
Trace gas.J Any one of the less common gases found in the Earth's atmosphere. Nitrogen, oxygen, and argon make
up more than 99 percent of the Earth's atmosphere. Other gases, such as carbon dioxide, water vapor,
methane, oxides of nitrogen, ozone, and ammonia, are considered trace gases. Although relatively
unimportant in terms of their absolute volume, they have significant effects on the Earth's weather and
climate.
Transportation End-Use Sector: Consists of private and public vehicles that move people and commodities.
Included are automobiles, trucks, buses, motorcycles, railroads and railways (including streetcars and
subways), aircraft, ships, barges, and natural gas pipelines.
Troposphere.1&7 The lowest layer of the atmosphere and contains about 95 percent of the mass of air in the Earth's
atmosphere. The troposphere extends from the Earth's surface up to about 10 to 15 kilometers. All weather
processes take place in the troposphere. Ozone that is formed in the troposphere plays a significant role in
both the greenhouse gas effect and urban smog. See ozone precursor, stratosphere, atmosphere.
Tropospheric ozone precursor. See ozone precursor.
Tropospheric ozone.1 See ozone.
Ultraviolet radiation (UV). n A portion of the electromagnetic spectrum with wavelengths shorted than visible
light. The sun produces UV, which is commonly split into three bands of decreasing wavelength. Shorter
wavelength radiation has a greater potential to cause biological damage on living organisms. The longer
wavelength ultraviolet band, UVA, is not absorbed by ozone in the atmosphere. UVB is mostly absorbed
by ozone, although some reaches the Earth. The shortest wavelength band, UVC, is completely absorbed
by ozone and normal oxygen in the atmosphere.
Unfinished oils.3 All oils requiring further refinery processing, except those requiring only mechanical blending.
Includes naphtha and lighter oils, kerosene and light gas oils, heavy gas oils, and residuum.
United Nations Framework Convention on Climate Change (UNFCCC). ' The international treaty unveiled at
the United Nations Conference on Environment and Development (UNCED) in June 1992. The UNFCCC
commits signatory countries to stabilize anthropogenic (i.e. human-induced) greenhouse gas emissions to
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"levels that would prevent dangerous anthropogenic interference with the climate system". The UNFCCC
also requires that all signatory parties develop and update national inventories of anthropogenic emissions
of all greenhouse gases not otherwise controlled by the Montreal Protocol. Out of 155 countries that have
ratified this accord, the United States was the first industrialized nation to do so.
Vehicle miles traveled (VMT).8 One vehicle traveling the distance of one mile. Thus, total vehicle miles is the
total mileage traveled by all vehicles.
Volatile organic compounds (VOCs).6 Organic compounds that evaporate readily into the atmosphere at normal
temperatures. VOCs contribute significantly to photochemical smog production and certain health
problems. See non-methane volatile organic compounds.
Wastewater. 2 Water that has been used and contains dissolved or suspended waste materials. See sewage
treatment.
Water vapor.' The most abundant greenhouse gas; it is the water present in the atmosphere in gaseous form.
Water vapor is an important part of the natural greenhouse effect. While humans are not significantly
increasing its concentration, it contributes to the enhanced greenhouse effect because the warming
influence of greenhouse gases leads to a positive water vapor feedback. In addition to its role as a natural
greenhouse gas, water vapor plays an important role in regulating the temperature of the planet because
clouds form when excess water vapor in the atmosphere condenses to form ice and water droplets and
precipitation.
Waxes. - Solid or semisolid materials derived from petroleum distillates or residues. Light-colored, more or less
translucent crystalline masses, slightly greasy to the touch, consisting of a mixture of solid hydrocarbons in
which the paraffin series predominates. Included are all marketable waxes, whether crude scale or fully
refined. Used primarily as industrial coating for surface protection.
Weather.' Weather is the specific condition of the atmosphere at a particular place and time. It is measured in
terms of such things as wind, temperature, humidity, atmospheric pressure, cloudiness, and precipitation.
In most places, weather can change from hour-to-hour, day-to-day, and season-to-season. Climate is the
average of weather over time and space. A simple way of remembering the difference is that climate is
what you expect (e.g. cold winters) and 'weather' is what you get (e.g. a blizzard). See climate.
Wetland.7 Land that stays flooded all or part of the year with fresh or salt water.
Wetlands.2 Areas regularly saturated by surface or groundwater and subsequently characterized by a prevalence of
vegetation adapted for life in saturated-soil conditions.
Wood energy.2 Wood and wood products used as fuel, including roundwood (i.e., cordwood), limbwood, wood
chips, bark, sawdust, forest residues, and charcoal.
References
1 U.S. Environmental Protection Agency, Global Warming website, .
February 26, 1999.
2 Energy Information Administration, Emissions of Greenhouse Gases in the United States 1997, DOE/EIA-
0573(97), U.S. Department of Energy, Washington, DC. October 1998. [See< http://www.eia.doe.gov>]
3 Energy Information Administration, Annual Energy Review 1997, DOE/EIA-0387(97), U.S. Department of
Energy, Washington, DC., July 1998.
4 United Nations Framework Convention on Climate Change. [See ]
5 Intergovernmental Panel on Climate Change, Climate Change 1995: The Science of Climate Change, Cambridge
University Press: New York, 1996
6 Cooper's Comprehensive Environmental Desk Reference, Arthur R. Cooper, Sr., Van Nostrand Reinhold: New
York, 1996.
7 Miller, G. Tyler, Jr., Living in the Environment, An Introduction to Environment Science, sixth edition, 1990.
W-18 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-1999
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8 Davis, Stacy, Transportation Energy Data Book, Oak Ridge National Laboratory, U.S. Department of Energy,
Edition 17, 1997.
Carbon Dioxide Information Analysis Center, website at , Oak Ridge National
Laboratory, U.S. Department of Energy, February 26, 1999.
Resources for the Future, Weathervane website, , February
26, 1999.
U.S. Environmental Protection Agency, Ozone Depletion Glossary, ,
February 26, 1999.
W-19
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Iron and Steel Production: In iron and steel foundries, coking coal is used as a reducing agent during
the production of the metal. Although a portion of the coal's carbon is combusted and released to the
atmosphere as carbon dioxide, its role as a chemical reagent makes it an example of a non-energy
use of fossil fuel.
Fertilizer: Natural gas is used in the production of ammonia, the key component of most nitrogenous
fertilizers. Through catalytic steam reforming, natural gas is broken down into carbon dioxide, which
is emitted to the atmosphere, and hydrogen, which is combined with nitrogen to make ammonia.
Scrap Tires: Tires are made from synthetic rubber and carbon black, both products of fossil fuels.
Like plastics and synthetic fibers, storage of the carbon in tires is dependent upon the ultimate fate
of the product.
Paint Resin: Paint resin is another example of a product derived from the non-energy use of fossil
fuels. Petrochemical products with a myriad of formulations and uses are produced in the industrial
sector, including lubricants, solvents, and waxes. Carbon is both stored by and emitted from these
products. .
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