### EPA 430-R-05-003



# I NVENTORY OF 

# U.S. G REENHOUSE 

# G AS 

# E MISSIONS AND 

# S INKS 

# :

1990

– 2003

A PRIL 

## 15, 2005

U.S. Environmental Protection Agency
1200 Pennsylvania Ave., N.W.
Washington, DC 20460

U.S.A.

### [Inside Front Cover]

HOW TO OBTAIN COPIES

You can electronically download this document on the U.S. EPA's homepage at <http://www.epa.gov/globalwarming/publications/emissions>. To request free copies of this report, call the National Service Center for Environmental Publications (N SCEP) at (800) 490-9198, or visit the web site above and click on “order online” after selecting an edition.

All data tables of this document are available for the full time series 1990 through 2003, inclusive, at the internet site mentioned above.

FOR FURTHER INFORMATION

Contact Mr. Leif Hockstad, Environmental Protection Agency, (202) 343-9432, hockstad.leif@epa.gov.

Or Ms. Lisa Hanle, Environmental Protection Agency, (202) 343-9434, hanle.lisa@epa.gov.

For more information regarding climate change a nd greenhouse gas emissions, see the EPA web site at <http://www.epa.gov/globalwarming>.

Released for printing: April 15, 2005

[INSERT DISCUSSION OF COVER DESIGN]Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page i 

## Acknowledgments

The Environmental Protection Agency would like to acknowledge the many individual and organizational contributors to this document, without whose efforts this report would not be complete. Although the complete list of researchers, government employees, and consultants w ho have provided technical and editorial support is too long to list here, EPA’s Office of Atmospheric Programs w ould like to thank some key contributors and reviewers whose work has significantly improved this year’s report.

Work on fuel combustion and industrial process emissions was lead by Leif Hockstad and Lisa Hanle. Work on energy and waste sector methane emissi ons was directed by Elizabeth Scheeh le, while work on agriculture sector emissions was directed by Tom Wirth and Joe Mangino. Tom Wirth led the preparation of the chapter on Land-Use Change and Forestry. Work on emissions of HFCs, PFCs, and SF 6 was directed by Deborah Schafer and Dave Godwin. John Davies directed the work on mobile combustion.

Within the EPA, other Offices also cont ributed data, analysis and technical review for this report. The Office of Transportation and Air Quality and the Office of Air Qua lity Planning and Standards provided analysis and review for several of the source categories addressed in this repor t. The Office of Solid Wast e and the Office of Research and Development also contribut ed analysis and research.

The Energy Information Administration and the Department of Energy contributed invaluable data and analysis on numerous energy-related topics. The U.S. Forest Service prepared the forest carbon inventory, and the Department of Agriculture’s Agricultural Resear ch Service and the Natural Resource Ecology Laboratory at Colorado State University contributed leading research on nitrous oxide and carbon fluxes from soils.

Other government agencies have contributed data as well, including the U.S. Geological Survey, the Federal Highway Administration, the Department of Transportation, the Bureau of Transportation Statistics, the Department of Commerce, the National Agricultural Statistics Service, the Federal Aviation Administration, and the Department of Defense.

We would also like to thank Marian Martin Van Pelt, Randall Freed, and their staff at ICF Consulting’s Energy Policy and Programs Practice, including John Venezia, Leonard Crook, Diana Pape, Meg Walsh, Michael Grant, Beth Moore, Ravi Kantamaneni, Robert Lanza, Chris Steuer, Lauren Flynn, Kamala Jayaraman, Dan Lieberman, Jeremy Scharfenberg, Matt Stanberry, Rebecca LePrell, Philip Groth, Sarah Percy, Da niel Karney, Brian Gillis, Zachary Schaffer, Vineet Aggarwal, Lauren Pederson, a nd Toby Mandel for synthesizing this report and preparing many of the individual analyses. Eastern Research Group, Raven Ridge Resources, and Arcadis also provided significant analytical support.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page ii 

## Preface

The United States Environmental Protecti on Agency (EPA) prepares the official U.S. Inventory of Greenhouse Gas Emissions and Sinks to comply with existing commitments under the United Nations Framework Convention on Climate Change (UNFCCC). 1 Under decision 3/CP.5 of the UNFCCC Conference of the Parties, national inventories for UNFCCC Annex I partie s should be provided to the UNFCCC S ecretariat each year by April 15.

In an effort to engage the public a nd researchers across the country, the EPA has instituted an annual public review and comment process for this document. The availability of the draft docum ent is announced via Federal Register Notice and is posted on the EPA web site. 2 Copies are also mailed upon request. The public comment period is generally limited to 30 days; however, comments received after the closure of the public comment period are accepted and considered for the next edition of this annual report.

1 See Article 4(1)(a) of the United Nations Framew ork Convention on Climate Change <http://www.unfccc.int>. 2 See <http://www.epa.gov/globalwar ming/publications/emissions>.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page iii 

## Table of Contents

ACKNOWLEDGMENTS I
TABLE OF CONTENTS III LIST OF TABLES, FIGURES, AND BOXES VI

Tables vi Figures vi

Boxes xiv 

### EXECUTIVE SUMMARY ES-1

ES.1. Background Information ES-1

ES.2. Recent Trends in U.S. Greenhous e Gas Emissions and Sinks ES-3

ES.3. Overview of Sector Emissions and Trends ES-9

ES.4. Other Information ES-12


### 1. INTRODUCTION 1

1.1. Background Information 2

1.2. Institutional Arrangements 10

1.3. Inventory Process 10

1.4. Methodology and Data Sources 12

1.5. Key Sources 13

1.6. Quality Assurance and Quality Control 16

1.7. Uncertainty Analysis of Emission Estimates 17

1.8. Completeness 18

1.9. Organization of Report 18


### 2. TRENDS IN GREENHOUSE GAS EMISSIONS 21

2.1. Recent Trends in U.S. Greenhouse Gas Emissions 21

2.2. Emissions by Economic Sector 42

2.3. Ambient Air Pollutant Emissions 48


### 3. ENERGY 51

3.1. Carbon Dioxide Emissions from Fossil Fuel Combustion (IPCC Source Category 1A) 52

3.2. Carbon Emitted from Non-Energy Uses of Fossil Fuels (IPCC Source Category 1A) 69

3.3. Stationary Combustion (excluding CO 2 ) (IPCC Source Category 1A) 75

3.4. Mobile Combustion (excluding CO 2 ) (IPCC Source Category 1A) 81

3.5. Coal Mining (IPCC Source Category 1B1a) 92

3.6. Abandoned Underground Coal Mines (IPCC Source Category 1B1a) 95

3.7. Petroleum Systems (IPCC Source Category 1B2a) 99Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page iv 3.8. Natural Gas Systems (IPCC Source Category 1B2b) 102

3.9. Municipal Solid Waste Combustion (IPCC Source Category 1A5) 106

3.10. Natural Gas Flaring and Ambient Air Pollutant Emissions from Oil and Gas Activities (IPCC Source Category 1B2) 111

3.11. International Bunker Fuels (IPCC Source Category 1: Memo Items) 113

3.12. Wood Biomass and Ethanol Consumption (IPCC Source Category 1A) 118


### 4. INDUSTRIAL PROCESSES 123

4.1. Iron and Steel Production (IPCC Source Category 2C1) 125

4.2. Cement Manufacture (IPCC Source Category 2A1) 129

4.3. Ammonia Manufacture and Urea Application (IPCC Source Category 2B1) 132

4.4. Lime Manufacture (IPCC Source Category 2A2) 136

4.5. Limestone and Dolomite Use (IPCC Source Category 2A3) 140

4.6. Soda Ash Manufacture and Consumption (IPCC Source Category 2A4) 143

4.7. Titanium Dioxide Production (IPCC Source Category 2B5) 146

4.8. Phosphoric Acid Production (IPCC Source Category 2A7) 148

4.9. Ferroalloy Production (IPCC Source Category 2C2) 151

4.10. Carbon Dioxide Consumption (IPCC Source Category 2B5) 153

4.11. Petrochemical Production (IPCC Source Category 2B5) 157

4.12. Silicon Carbide Production (IPCC Source Category 2B4) 160

4.13. Nitric Acid Production (IPCC Source Category 2B2) 161

4.14. Adipic Acid Production (IPCC Source Category 2B3) 163

4.15. Substitution of Ozone Depleting Substances (IPCC Source Category 2F) 166

4.16. HCFC-22 Production (IPCC Source Category 2E1) 168

4.17. Electrical Transmission and Distribution (IPCC Source Category 2F7) 170

4.18. Aluminum Production (IPCC Source Category 2C3) 174

4.19. Semiconductor Manufacture (IPCC Source Category 2F6) 179

4.20. Magnesium Production and Processing (IPCC Source Category 2C4) 182

4.21. Industrial Sources of Ambient Air Pollutants 186 

### 5. SOLVENT AND OTHER PRODUCT USE 189

5.1. Nitrous Oxide Product Usage (IPCC Source Category 3D) 189

5.2. Ambient Air Pollutants from Solvent Use 192


### 6. AGRICULTURE 195

6.1. Enteric Fermentation (IPCC Source Category 4A) 196

6.2. Manure Management (IPCC Source Category 4B) 200

6.3. Rice Cultivation (IPCC Source Category 4C) 207

6.4. Agricultural Soil Management (IPCC Source Category 4D) 212Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page v 6.5. Field Burning of Agricultural Residues (IPCC Source Category 4F) 222


### 7. LAND-USE CHANGE AND FORESTRY 229

7.1. Forest Land Remaining Forest Land 231

7.2. Land Converted to Forest Land (Source Category 5A2) 241

7.3. Croplands Remaining Croplands 241

7.4. Lands Converted to Croplands (Source Category 5B2) 249

7.5. Settlements Remaining Settlements 250

7.6. Lands Converted to Settlements (Source Category 5E2) 259


### 8. WASTE 261

8.1. Landfills (IPCC Source Category 6A1) 261

8.2. Wastewater Treatment (IPCC Source Category 6B) 265

8.3. Human Sewage (Domestic Wastewater) (IPCC Source Category 6B) 269

8.4. Waste Sources of Ambient Air Pollutants 272


### 9. OTHER 275
10. RECALCULATIONS AND IMPROVEMENTS 277
REFERENCES 281Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2003 Page vi 

## List of Tables, Figures, and Boxes

Tables

Table ES-1: Global Warming Potentials (100 Year Time Horizon) Used in this Report 3

Table ES-2: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO 2 Eq.) 4

Table ES-3: CO 2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO 2 Eq.) 7

Table ES-4: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Ch apter/IPCC Sector (Tg CO 2 Eq.) 9

Table ES-5: Net CO 2 Flux from Land-Use Change and Forestry (Tg CO 2 Eq.) 11 Table ES-6: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO 2 Eq.) 12 Table ES-7: U.S Greenhouse Gas Emissions by Economic Sector and Gas with Electricity-Related Emissions Distributed (Tg CO 2 Eq.) 13

Table ES-8: Recent Trends in Various U.S. Data (Index 1990 = 100) a nd Global Atmospheric CO 2 Concentration 14

Table ES-9: Emissions of NO x , CO, NMVOCs, and SO 2 (Gg) 14 Table 1-1: Global atmospheric concentration (ppm unle ss otherwise specified), rate of concentration change (ppb/year) and atmospheric lifetime (years) of selected greenhouse gases 3 Table 1-2: Global Warming Potentials and Atmospheric Lifetimes (Years) Used in this Report 7 Table 1-3: Comparison of 100 Year GWPs 8

Table 1-4: Effects on U.S. Greenhouse Gas Emission Trends Using IPCC SAR and TAR GWP Values (Tg CO 2 Eq.) 9 Table 1-5: Comparison of Emissions by Sector using IPCC SAR and TAR GWP Values (Tg CO 2 Eq.) 9 Table 1-6: Key Source Categories for the United States (1990-2003) Based on Tier 1 Approach 15 Table 1-7: IPCC Sector Descriptions 18

Table 1-8: List of Annexes 19 Table 2-1: Annual Change in CO 2 Emissions from Fossil Fuel Combustion for Selected Fuels and Sectors (Tg CO 2 Eq. and Percent) 22

Table 2-2: Recent Trends in Various U.S. Data (Index 1990 = 100) a nd Global Atmospheric CO 2 Concentration 24

Table 2-3: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO 2 Eq.) 24

Table 2-4: Recent Trends in U.S. Gr eenhouse Gas Emissions and Sinks (Gg) 26

Table 2-5: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Ch apter/IPCC Sector (Tg CO 2 Eq.) 28 Table 2-6: Emissions from Energy (Tg CO 2 Eq.) 28

Table 2-7: CO 2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO 2 Eq.) 29 Table 2-8: Emissions from Industrial Processes (Tg CO 2 Eq.) 33

Table 2-9: N 2 O Emissions from Solvent and Other Product Use (Tg CO 2 Eq.) 37 Table 2-10: Emissions from Agriculture (Tg CO 2 Eq.) 38

Table 2-11: Net CO 2 Flux from Land-Use Change and Forestry (Tg CO 2 Eq.) 39

Table 2-12: N 2 O Emissions from Land-Use Change and Forestry (Tg CO 2 Eq.) 40Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page vii Table 2-13: Emissions from Waste (Tg CO 2 Eq.) 41 Table 2-14: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO 2 Eq. and Percent of Total in 2003) 42 Table 2-15: Electricity Generation-Related Greenhouse Gas Emissions (Tg CO 2 Eq.) 44 Table 2-16: U.S Greenhouse Gas Emissions by “Economic Sector” and Gas with Electricity-Related Emissions Distributed (Tg CO 2 Eq.) and Percent of Total in 2003 45 Table 2-17: Transportation-Related Greenhouse Gas Emissions (Tg CO 2 Eq.) 47

Table 2-18: Emissions of NO x , CO, NMVOCs, and SO 2 (Gg) 49 Table 3-1: Emissions from Energy (Tg CO 2 Eq.) 51 Table 3-2: Emissions from Energy (Gg) 52

Table 3-3: CO 2 Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg CO 2 Eq.) 53 Table 3-4: Annual Change in CO 2 Emissions from Fossil Fuel Combustion for Selected Fuels and Sectors (Tg CO 2 Eq. and Percent) 54

Table 3-5: CO 2 Emissions from International Bunker Fuels (Tg CO 2 Eq.)* 56

Table 3-6: CO 2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO 2 Eq.) 56

Table 3-7: CO 2 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg CO 2 Eq.) 57 Table 3-8: Carbon Intensity from Direct Fossil Fuel Combustion by Sector (Tg CO 2 Eq./QBtu) 62 Table 3-9: Carbon Intensity from all Energy Consumption by Sector (Tg CO 2 Eq./QBtu) 62

Table 3-10: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Energy-related Fossil Fuel Combustion by Fuel Type and Sector (Tg CO 2 Eq. and Percent) 67

Table 3-11: CO 2 Emissions from Non-Energy Use Fossil Fuel Consumption (Tg CO 2 Eq.) 69 Table 3-12: Adjusted Consumption of Fossil Fuels for Non-Energy Uses (TBtu) 71 Table 3-13: 2003 Adjusted Non-Energy Use Fossil Fuel Consumption, Storage, and Emissions 71 Table 3-14: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Non-Energy Uses of Fossil Fuels (Tg CO 2 Eq. and Percent) 73 Table 3-15: Tier 2 Quantitative Uncertainty Estimates for Storage Factors of Non-Energy Uses of Fossil Fuels (Percent) 73

Table 3-16: CH 4 Emissions from Stationary Combustion (Tg CO 2 Eq.) 75

Table 3-17: N 2 O Emissions from Stationary Combustion (Tg CO 2 Eq.) 76

Table 3-18: CH 4 Emissions from Stationary Combustion (Gg) 77

Table 3-19: N 2 O Emissions from Stationary Combustion (Gg) 77

Table 3-20: NO x , CO, and NMVOC Emissions from Stationary Combustion in 2003 (Gg) 78 Table 3-21: Tier 2 Quantitative Uncertainty Estimates for CH 4 and N 2 O Emissions from Energy -Related Stationary Combustion, Including Biomass (Tg CO 2 Eq. and Percent) 80

Table 3-22: CH 4 Emissions from Mobile Combustion (Tg CO 2 Eq.) 82

Table 3-23: N 2 O Emissions from Mobile Combustion (Tg CO 2 Eq.) 82

Table 3-24: CH 4 Emissions from Mobile Combustion (Gg) 83

Table 3-25: N 2 O Emissions from Mobile Combustion (Gg) 83

Table 3-26: NO x Emissions from Mobile Combustion (Gg) 84Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page viii Table 3-27: CO Emissions from Mobile Combustion (Gg) 84 Table 3-28: NMVOC Emissions from Mobile Combustion (Gg) 85 Table 3-29: Tier 2 Quantitative Uncertainty Estimates for CH 4 and N 2 O Emissions from Mobile Sources (Tg CO 2 Eq. and Percent) 90

Table 3-30: CH 4 Emissions from Coal Mining (Tg CO 2 Eq.) 93

Table 3-31: CH 4 Emissions from Coal Mining (Gg) 93 Table 3-32: Coal Production (Thousand Metric Tons) 94 Table 3-33: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Coal Mining (Tg CO 2 Eq. and Percent) 94

Table 3-34: CH 4 Emissions from Abandoned Coal Mines (Tg CO 2 Eq.) 96

Table 3-35: CH 4 Emissions from Abandoned Coal Mines (Gg) 96 Table 3-36: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Abandoned Underground Coal Mines (Tg CO 2 Eq. and Percent) 98

Table 3-37: CH 4 Emissions from Petroleum Systems (Tg CO 2 Eq.) 100

Table 3-38: CH 4 Emissions from Petroleum Systems (Gg) 100 Table 3-39: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Petroleum Systems (Tg CO 2 Eq. and Percent) 101

Table 3-40: CH 4 Emissions from Natural Gas Systems (Tg CO 2 Eq.)* 103

Table 3-41: CH 4 Emissions from Natural Gas Systems (Gg)* 103 Table 3-42: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Natural Gas Systems (Tg CO 2 Eq. and Percent) 104

Table 3-43: CO 2 and N 2 O Emissions from Municipal Solid Waste Combustion (Tg CO 2 Eq.) 107

Table 3-44: CO 2 and N 2 O Emissions from Municipal Solid Waste Combustion (Gg) 107

Table 3-45: NO x , CO, and NMVOC Emissions from Municipal Solid Waste Combustion (Gg) 107 Table 3-46: Municipal Solid Waste Generation (Metric Tons) and Percent Combusted 108 Table 3-47: Tier 2 Quantitative Uncertainty Estimates for CO 2 and N 2 O from Municipal Solid Waste Combustion (Tg CO 2 Eq. and Percent) 109 Table 3-48: U.S. Municipal Solid Waste Combusted, as Reported by EPA and BioCycle (Metric Tons) 110

Table 3-49: CO 2 Emissions from On-Shore and Off-S hore Natural Gas Flaring (Tg CO 2 Eq.) 111

Table 3-50: CO 2 Emissions from On-Shore and Off-S hore Natural Gas Flaring (Gg) 111

Table 3-51: NO x , NMVOCs, and CO Emissions from Oil and Gas Activities (Gg) 111 Table 3-52: Total Natural Gas Reported Vented and Flared (Million Ft 3 ) and Thermal Conversion Factor (Btu/Ft 3 ) 112 Table 3-53: Volume Flared Offshore (MMcf) and Fraction Vented and Flared (Percent) 112 Table 3-54: Emissions from International Bunker Fuels (Tg CO 2 Eq.) 114 Table 3-55: Emissions from International Bunker Fuels (Gg) 115 Table 3-56: Aviation Jet Fuel Consumption for International Transport (Million Gallons) 116 Table 3-57: Marine Fuel Consumption for International Transport (Million Gallons) 116

Table 3-58: CO 2 Emissions from Wood Consumption by End-Use Sector (Tg CO 2 Eq.) 118Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ix Table 3-59: CO 2 Emissions from Wood Consumption by End-Use Sector (Gg) 118

Table 3-60: CO 2 Emissions from Ethanol Consumption 119 Table 3-61: Woody Biom ass Consumption by S ector (Trillion Btu) 119 Table 3-62: Ethanol Consumption 119

Table 3-63: CH 4 Emissions from Non-Combustion Fossil Sources (Gg) 121

Table 3-64: Formation of CO 2 through Atmospheric CH 4 Oxidation (Tg CO 2 Eq.) 121 Table 4-1: Emissions from Industrial Processes (Tg CO 2 Eq.) 123 Table 4-2: Emissions from Industrial Processes (Gg) 124

Table 4-3: CO 2 and CH 4 Emissions from Iron and Steel Production (Tg CO 2 Eq.) 126

Table 4-4: CO 2 and CH 4 Emissions from Iron and Steel Production (Gg) 126

Table 4-5: CH 4 Emission Factors for Coal Coke, Sinter, and Pig Iron Production (g/kg) 127 Table 4-6: Production and Consumption Data for the Calculation of CO 2 and CH 4 Emissions from Iron and Steel Production (Thousand Metric Tons) 127 Table 4-7: Tier 2 Quantitative Uncertainty Estimates for CO 2 and CH 4 Emissions from Iron and Steel Production (Tg. CO 2 Eq. and Percent) 128

Table 4-8: CO 2 Emissions from Cement Production (Tg CO 2 Eq. and Gg)* 129 Table 4-9: Cement Production (Gg) 131 Table 4-10: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Cement Manufacture (Tg CO 2 Eq. and Percent) 131

Table 4-11: CO 2 Emissions from Ammonia Manufacture and Urea Application (Tg CO 2 Eq.) 132

Table 4-12: CO 2 Emissions from Ammonia Manufacture and Urea Application (Gg) 133 Table 4-13: Ammonia Production (Gg) 133 Table 4-14: Urea Production (Gg) 134 Table 4-15: Urea Net Imports (Gg) 134 Table 4-16: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Ammonia Manufacture and Urea Application (Tg CO 2 Eq. and Percent) 136

Table 4-17: Net CO 2 Emissions from Lime Manufacture (Tg CO 2 Eq.) 137

Table 4-18: CO 2 Emissions from Lime Manufacture (Gg) 137 Table 4-19: Lime Production and Lime Use for Sugar Refining and PCC (Gg) 138 Table 4-20: Hydrated Lime Production (Gg) 138 Table 4-21: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Lime Manufacture (Tg CO 2 Eq. and Percent) 140

Table 4-22: CO 2 Emissions from Limestone & Dolomite Use (Tg CO 2 Eq.) 140

Table 4-23: CO 2 Emissions from Limestone & Dolomite Use (Gg) 140 Table 4-24: Limestone and Dolomite Consumption (Thousand Metric Tons) 142 Table 4-25: Dolomitic Magnesium Meta l Production Capacity (Metric Tons) 142 Table 4-26: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Limestone and Dolomite Use (Tg CO 2 Eq. and Percent) 143Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page x Table 4-27: CO 2 Emissions from Soda Ash Manufacture and Consumption (Tg CO 2 Eq.) 144

Table 4-28: CO 2 Emissions from Soda Ash Manufacture and Consumption (Gg) 144 Table 4-29: Soda Ash Manufacture and Consumption (Gg) 145 Table 4-30: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Soda Ash Manufacture and Consumption (Tg CO 2 Eq. and Percent) 145

Table 4-31: CO 2 Emissions from Titanium Dioxide (Tg CO 2 Eq. and Gg) 146 Table 4-32: Titanium Dioxide Production (Gg) 147 Table 4-33: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Titanium Dioxide Production (Tg CO 2 Eq. and Percent) 147

Table 4-34: CO 2 Emissions from Phosphoric Acid Production (Tg CO 2 Eq. and Gg) 148 Table 4-35: Phosphate Rock Domestic Production, Exports, and Imports (Gg) 149 Table 4-36: Chemical Composition of Phosphate Rock (percent by weight) 150 Table 4-37: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Phosphoric Acid Production (Tg CO 2 Eq. and Percent) 151

Table 4-38: CO 2 Emissions from Ferroalloy Production (Tg CO 2 Eq. and Gg) 151 Table 4-39: Production of Ferroalloys (Metric Tons) 152 Table 4-40: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Ferroalloy Production (Tg CO 2 Eq. and Percent) 153

Table 4-41: CO 2 Emissions from Carbon Dioxide Consumption (Tg CO 2 Eq. and Gg) 154 Table 4-42: Carbon Dioxide Consumption (Metric Tons) 155 Table 4-43: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Carbon Dioxide Consumption (Tg CO 2 Eq. and Percent) 156

Table 4-44: CO 2 and CH 4 Emissions from Petrochemical Production (Tg CO 2 Eq.) 157

Table 4-45: CO 2 and CH 4 Emissions from Petrochemical Production (Gg) 157

Table 4-46: Production of Selected Pe trochemicals (Thousand Metric Tons) 158 Table 4-47: Carbon Black Feedstock (Primary Feedstoc k) and Natural Gas Feedstock (Secondary Feedstock) Consumption (Thousand Metric Tons) 159 Table 4-48: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Petrochemical Production and CO 2 Emissions from Carbon Black Production (Tg CO 2 Eq. and Percent) 159

Table 4-49: CH 4 Emissions from Silicon Carbide Production (Tg CO 2 Eq. and Gg) 160

Table 4-50: Production of S ilicon Carbide (Metric Tons) 160 Table 4-51: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Silicon Carbide Production (Tg CO 2 Eq. and Percent) 161

Table 4-52: N 2 O Emissions from Nitric Acid Production (Tg CO 2 Eq. and Gg) 162 Table 4-53: Nitric Acid Production (Gg) 162 Table 4-54: Tier 1 Quantitative Uncertainty Estimates for N 2 O Emissions from Nitric Acid Production (Tg CO 2 Eq. and Percent) 163

Table 4-55: N 2 O Emissions from Adipic Acid Production (Tg CO 2 Eq. and Gg) 164 Table 4-56: Adipic Acid Production (Gg) 165Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page xi Table 4-57: Tier 1 Quantitative Uncertainty Estimates for N 2 O Emissions from Adipic Acid Production (Tg CO 2 Eq. and Percent) 165 Table 4-58: Emissions of HFCs and PFCs from ODS Substitution (Tg CO 2 Eq.) 166 Table 4-59: Emissions of HFCs and PFCs from ODS Substitution (Mg) 166 Table 4-60: Tier 2 Quantitative Uncertainty Estimates for HFC and PFC Emissions from ODS Substitution (Tg CO 2 Eq. and Percent) 168 Table 4-61: HFC-23 Emissions from HCFC-22 Production (Tg CO 2 Eq. and Gg) 169 Table 4-62: HCFC-22 Production (Gg) 169 Table 4-63: Tier 1 Quantitative Un certainty Estimates for HFC-23 Emi ssions from HCFC-22 Production (Tg CO 2 Eq. and Percent) 170

Table 4-64: SF 6 Emissions from Electric Power Systems and Original Equipment Manufactures (Tg CO 2 Eq.) 170

Table 4-65: SF 6 Emissions from Electric Power Systems and Original Equipment Manufacturers (Gg) 171 Table 4-66: Simulated Variables for Tier 2 Uncertainty Analysis 173 Table 4-67: Tier 2 Quantitative Uncertainty Estimates for SF 6 Emissions from Electri cal Transmission and Distribution (Tg CO 2 Eq. and Percent) 174

Table 4-68: CO 2 Emissions from Aluminum Production (Tg CO 2 Eq. and Gg) 175 Table 4-69: PFC Emissions from Aluminum Production (Tg CO 2 Eq.) 175 Table 4-70: PFC Emissions from Aluminum Production (Gg) 175 Table 4-71: Production of Primary Aluminum (Gg) 177 Table 4-72: Tier 2 Quantitative Un certainty Estimates for PFC Emissi ons from Aluminum Production (Tg CO 2 Eq. and Percent) 178 Table 4-73: PFC, HFC, and SF 6 Emissions from Semiconductor Manufacture (Tg CO 2 Eq.) 179 Table 4-74: PFC, HFC, and SF 6 Emissions from Semiconductor Manufacture (Mg) 179 Table 4-75: Tier 2 Quantitative Uncertainty Estimates for HFC, PFC, and SF 6 Emissions from Semiconductor Manufacture (Tg CO 2 Eq. and Percent) 182

Table 4-76: SF 6 Emissions from Magnesium Production and Processing (Tg CO 2 Eq. and Gg) 182

Table 4-77: SF 6 Emission Factors (kg SF 6 per metric ton of magnesium) 183 Table 4-78: Simulated Variables for Tier 2 Uncertainty Analysis 184 Table 4-79: Tier 2 Quantitative Uncertainty Estimates for SF 6 Emissions from Magnesium Production and Processing (Tg CO 2 Eq. and Percent) 184 Table 4-80: 2003 Potential and Actual Emissions of HFCs, PFCs, and SF 6 from Selected Sources (Tg CO 2 Eq.) 186

Table 4-81: NO x , CO, and NMVOC Emissions from Industrial Processes (Gg) 186

Table 5-1: N 2 O Emissions from Solvent and Other Product Use (Tg CO 2 Eq. and Gg) 189 Table 5-2: Ambient Air Pollutant Emissions from Solvent and Other Product Use (Gg) 189

Table 5-3: N 2 O Emissions from Nitrous Oxide Product Usage (Tg CO 2 Eq. and Gg) 189

Table 5-4: N 2 O Production (Gg) 191 Table 5-5: Tier 1 Quantitative Uncertainty Estimates for N 2 O Emissions from Nitrous Oxide Product Usage (Tg CO 2 Eq. and Percent) 191

Table 5-6: Emissions of NO x , CO, and NMVOC from Solvent Use (Gg) 192Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page xii Table 6-1: Emissions from Agriculture (Tg CO 2 Eq.) 195 Table 6-2: Emissions from Agriculture (Gg) 195

Table 6-3: CH 4 Emissions from Enteric Fermentation (Tg CO 2 Eq.) 196

Table 6-4: CH 4 Emissions from Enteric Fermentation (Gg) 197 Table 6-5: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Enteric Fermentation (Tg CO 2 Eq. and Percent) 199

Table 6-6: CH 4 and N 2 O Emissions from Manure Management (Tg CO 2 Eq.) 201

Table 6-7: CH 4 and N 2 O Emissions from Manure Management (Gg) 201 Table 6-8: Tier 2 Quantitative Uncertainty Estimates for CH 4 and N 2 O Emissions from Manure Management (Tg CO 2 Eq. and Percent) 204

Table 6-9: CH 4 Emissions from Rice Cultivation (Tg CO 2 Eq.) 208

Table 6-10: CH 4 Emissions from Rice Cultivation (Gg CH 4 ) 209 Table 6-11: Rice Areas Harvested (Hectares) 210 Table 6-12: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Rice Cultivation (Tg CO 2 Eq. and Percent) 212

Table 6-13: N 2 O Emissions from Agricultural Soils (Tg CO 2 Eq.) 213

Table 6-14: N 2 O Emissions from Agricultural Soils (Gg) 213

Table 6-15: Direct N 2 O Emissions from Agricultural Soils (Tg CO 2 Eq.) 213

Table 6-16: Direct N 2 O Emissions from PRP Livestock Manure (Tg CO 2 Eq.) 214

Table 6-17: Indirect N 2 O Emissions from all Land Use Types* (Tg CO 2 Eq.) 214 Table 6-18: Tier 1 Quantitative Uncertainty Estimates of N 2 O Emissions from Agricultural Soil Management in 2003 (Tg CO 2 Eq. and Percent) 219 Table 6-19. Comparison of Direct Soil N 2 O Emission Estimates for IPCC versus Current Methodologies (Tg CO 2 Eq.). 221 Table 6-20. Comparison of Indirect Soil N 2 O Emission Estimates for IPCC versus Current Methodologies (Tg CO 2 Eq.) 221 Table 6-21. Comparison of Total Soil N 2 O Emission Estimates for IPCC versus Current Methodologies (Tg CO 2 Eq.) 221 Table 6-22: Emissions from Field Burning of Agricultural Residues (Tg CO 2 Eq.) 222 Table 6-23: Emissions from Field Burning of Agricultural Residues (Gg)* 223 Table 6-24: Agricultural Crop Production (Gg of Product) 225 Table 6-25: Percentage of Rice Area Burned by State 225 Table 6-26: Percentage of Rice Area Burned in California 225 Table 6-27: Key Assumptions for Estimating Emissions from Field Burning of Agricultural Residues 226

Table 6-28: Greenhouse Gas Emission Ratios 226 Table 6-29: Tier 1 Quantitative Uncertainty Estimates for CH 4 and N 2 O Emissions from Field Burning of Agricultural Residues (Tg CO 2 Eq. and Percent) 227

Table 7-1: Net CO 2 Flux from Land-Use Change and Forestry (Tg CO 2 Eq.) 230

Table 7-2: Net CO 2 Flux from Land-Use Change and Forestry (Tg C) 230Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page xiii Table 7-3: Net N 2 O Emissions from Land-Use Change and Forestry (Tg CO 2 Eq.) 231

Table 7-4: Net N 2 O Emissions from Land-Use Change and Forestry (Gg) 231 Table 7-5. Net Annual Changes in Carbon Stocks (Tg CO 2 Eq. yr -1 ) in Forest and Harvested Wood Pools 233 Table 7-6. Net Annual Changes in Carbon Stocks (Tg C yr -1 ) in Forest and Harvested Wood Pools 233 Table 7-7. Carbon Stocks (Tg C) in Forest and Harvested Wood Pools 234 Table 7-8: Tier 2 Quantitative Uncertainty Estimates for CO 2 Net Flux from Forest Land Remaining Forest Land: Changes in Forest Carbon Stocks (Tg CO 2 Eq. and Percent) 237

Table 7-9. N 2 O Fluxes from Soils in Forests Remaining Forests (Tg CO 2 Eq. and Gg) 239 Table 7-10: Tier 1 Quantitative Uncertainty Estimates of N 2 O Fluxes from Forest Soils (Tg CO 2 Eq. and Percent) 240

Table 7-11: Net CO 2 Flux from Agricultural Soils (Tg CO 2 Eq.) 242 Table 7-13: Quantities of Applied Minerals (Thousand Metric Tons) 245 Table 7-14: Tier 2 Quantitative Uncertainty Estimates for CO 2 Flux from Mineral and Organic Agricultural Soil Carbon Stocks (Tg CO 2 Eq. and Percent) 246 Table 7-15: Tier 1 Quantitative Uncertainty Estimates for CO 2 Emissions from Liming of Agricultural Soils (Tg CO 2 Eq. and Percent) 247 Table 7-16: Net Changes in Yard Trimming and Food Scrap Stocks (Tg CO 2 Eq.) 250 Table 7-17: Net Changes in Yard Tr imming and Food Scrap Stocks (Tg C) 250 Table 7-18: Moisture Content (%), Carbon Storage Factor, Initial Carbon C ontent (%), Proportion of Initial Carbon Sequestered (%), and Half-Life (years) for Landfilled Yard Trimmings and Food Scraps 252

Table 7-19: Carbon Stocks in Yard Trimmings and Food Scraps (Tg C) 252 Table 7-20: Tier 2 Quantitative Uncertainty Estimates for CO 2 Flux from Yard Trimmings and Food Scraps (Tg CO 2 Eq. and Percent) 253 Table 7-21: Net C Flux from Urban Trees (Tg CO 2 Eq. and Tg C) 255 Table 7-22: Carbon Stocks (Metric Tons C), Annual Carbon Sequestration (Metric Tons C/yr), Tree Cover (Percent), and Annual Carbon Sequestration per Area of Tree Cover (kg C/m 2 cover-yr) for Ten U.S. Cities 256 Table 7-23: Tier 1 Quantitative Uncer tainty Estimates for Net C Flux from Changes in Carbon Stocks in Urban Trees (Tg CO 2 Eq. and Percent) 257

Table 7-24: N 2 O Fluxes from Soils in Settlements Remaining Settlements (Tg CO 2 Eq.) 258 Table 7-25: Tier 1 Quantitative Uncertainty Estimates of N 2 O Emissions from Soils in Settlements Remaining Settlements (Tg CO 2 Eq. and Percent) 259 Table 8-1: Emissions from Waste (Tg CO 2 Eq.) 261 Table 8-2: Emissions from Waste (Gg) 261

Table 8-3: CH 4 Emissions from Landfills (Tg CO 2 Eq.) 262

Table 8-4: CH 4 Emissions from Landfills (Gg) 262 Table 8-5: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Landfills (Tg CO 2 Eq. and Percent) 264

Table 8-6: CH 4 Emissions from Domestic and Industrial Wastewater Treatment (Tg CO 2 Eq.) 266

Table 8-7: CH 4 Emissions from Domestic and Industrial Wastewater Treatment (Gg) 266 Table 8-8: U.S. Population (Millions) and Wastewater BOD 5 Produced (Gg) 266Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page xiv Table 8-9: U.S. Pulp and Paper, Meat and Poultry, and Vegetables, Fruits and Juices Production (Tg) 267 Table 8-10: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Wastewater Treatment (Tg CO 2 Eq. and Percent) 268

Table 8-11: N 2 O Emissions from Human Sewage (Tg CO 2 Eq. and Gg) 269 Table 8-12: U.S. Population (Millions) and Average Protein In take [kg/(person.year)] 271 Table 8-13: Tier 2 Quantitative Uncertainty Estimates for N 2 O Emissions from Human Sewage (Tg CO 2 Eq. and Percent) 272

Table 8-14: Emissions of NO x , CO, and NMVOC from Waste (Gg) 272 Table 10-1: Revisions to U.S. Greenhouse Gas Emissions (Tg CO 2 Eq.) 278

Table 10-2: Revisions to Net Flux of CO 2 to the Atmosphere from Land-Use Change and Forestry (Tg CO 2 Eq.) 279


### Figures

Figure ES-1: U.S. Greenhouse Gas Emissions by Gas 3 Figure ES-2: Annual Percent Change in U.S. Greenhouse Gas Emissions 3 Figure ES-3: Cumulative Change in U.S. Greenhouse Gas Emissions Relative to 1990 3 Figure ES-4: 2003 Greenhouse Gas Emissions by Gas 5 Figure ES-5: 2003 Sources of CO 2 6 Figure ES-6: 2003 CO 2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type 6 Figure ES-7: 2003 End-Use Sector Emissions of CO 2 from Fossil Fuel Combustion 6 Figure ES-8: 2003 U.S. Sources of CH 4 8 Figure ES-9: 2003 U.S. Sources of N 2 O 8 Figure ES-10: 2003 U.S. Sources of HFCs, PFCs, and SF 6 9 Figure ES-11: U.S. Greenhouse Gas Emissions by Chapter/IPCC Sector 9 Figure ES-12: 2003 U.S. Energy Consumption by Energy Source 10 Figure ES-13: Emissions Allocated to Economic Sectors 12 Figure ES-14: Emissions with Electricity Distributed to Economic Sectors 13 Figure ES-15: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product 14 Figure ES-16: 2003 Key Sources – Tier 1 Level Assessment 15 Figure 2-1: U.S. Greenhouse Gas Emissions by Gas 21 Figure 2-2: Annual Percent Change in U.S. Greenhouse Gas Emissions 21 Figure 2-3: Cumulative Change in U.S. Greenhouse Gas Emissions Relative to 1990 21 Figure 2-4: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product 24 Figure 2-5: U.S. Greenhouse Gas Emissions by Chapter/IPCC Sector 28 Figure 2-6: 2003 Energy Sector Greenhouse Gas Sources 28 Figure 2-7: 2003 U.S. Fossil Carbon Flows (Tg CO 2 Eq.) 28 Figure 2-8: 2003 CO 2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type 30 Figure 2-9: 2003 End-Use Sector Emissions of CO 2 from Fossil Fuel Combustion 30Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page xv Figure 2-10: 2003 Industrial Processes Chapter Greenhouse Gas Sources 33 Figure 2-11: 2003 Agriculture Chapter Greenhouse Gas Sources 37 Figure 2-12: 2003 Waste Sector Greenhouse Gas Sources 40 Figure 2-13: Emissions Allocated to Economic Sectors 42 Figure 2-14: Emissions with Electricity Distributed to Economic Sectors 45 Figure 3-1: 2003 Energy Sector Greenhouse Gas Sources 51 Figure 3-2: 2003 U.S. Fossil Carbon Flows (Tg CO 2 Eq.) 51 Figure 3-3: 2003 U.S. Energy Consumption by Energy Source 54 Figure 3-4: U.S. Energy Consumption (Quadrillion Btu) 54 Figure 3-5: 2003 CO 2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type 54 Figure 3-6: Annual Deviations from Normal Heating Degree Days for the United States (1949-2003) 55 Figure 3-7: Annual Deviations from Normal Cooling Degree Days for the United States (1949-2003) 55 Figure 3-8: Aggregate Nuclear and Hydroelectric Power Plant Capacity Factors in the United States (1973-2003) 55 Figure 3-9: 2003 End-Use Sector Emissions of CO 2 from Fossil Fuel Combustion 57 Figure 3-10: Motor Gasoline Retail Prices (Real) 57 Figure 3-11: Motor Vehi cle Fuel Efficiency 57 Figure 3-12: Industrial Production Indexes (Index 1997=100) 59 Figure 3-13: Heating Degree Days 60 Figure 3-14: Cooling Degree Days 60 Figure 3-15: Electricity Generation Retail Sales by End-Use Sector 60 Figure 3-16: U.S. Energy Consumption and Energy-Related CO 2 Emissions Per Capita and Per Dollar GDP 63 Figure 3-17: Mobile Source CH 4 and N 2 O Emissions 82 Figure 4-1: 2003 Industrial Processes Chapter Greenhouse Gas Sources 123 Figure 6-1: 2003 Agriculture Chapter Greenhouse Gas Emission Sources 195 Figure 6-2: Direct N 2 O Emissions Pathways from Cropland and Grassland Soils, and Indirect N 2 O Emissions Pathways from All Sources. 213 Figure 7-1: Forest Sector Carbon Pools and Flows. 232 Figure 7-2: Estimates of Net Annual Changes in Carbon Stocks for Major Carbon Pools (Tg C yr -1 ) 234 Figure 7-3: Average Carbon Density in the Forest Tree Pool in the Conterminous U.S. During 2004. 234 Figure 7-4: Net Annual CO 2 Flux, per Hectare, From Mineral Soils Under Agricultural Management, 1990-1992 243 Figure 7-5: Net Annual CO 2 Flux, per Hectare, From Mineral Soils Under Agricultural Management, 1993-2003 243 Figure 7-6: Net Annual CO 2 Flux, per Hectare, From Organic Soils Under Agricultural Management, 1990-1992 243 Figure 7-7: Net Annual CO 2 Flux, per Hectare, From Organic Soils Under Agricultural Management, 1993-2003 243 Figure 8-1: 2003 Waste Chapter Greenhouse Gas Sources 261Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page xvi 

### Boxes

Box ES-1: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data 13 Box 1-1: The IPCC Third Assessment Report and Global Warming Potentials 8

Box 1-2: IPCC Good Practice Guidance 12

Box 2-1: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data 23 Box 2-2: Methodology for Aggregating Emissions by Economic Sector 48

Box 2-3: Sources and Effects of Sulfur Dioxide 50 Box 3-1: Weather and Non-Fossil Energy Effects on CO 2 from Fossil Fuel Combustion Trends 55 Box 3-2: Carbon Intensity of U.S. Energy Consumption 61 Box 3-3: Biogenic Emissions and Sinks of Carbon 106

Box 3-4: Formation of CO 2 through Atmospheric CH 4 Oxidation 120 Box 4-1: Potential Emission Estimates of HFCs, PFCs, and SF 6 185Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-1 

## Executive Summary

Central to any study of climate change is the development of an emissions inventory that identifies and quantifies a country's primary anthropogenic 1 sources and sinks of greenhouse gases. This inventory adheres to both 1) a comprehensive and detailed methodology for estimating s ources and sinks of anthropogenic greenhouse gases, and 2) a common and consistent mechanism that enables Parties to the United Nations Framework Convention on Climate Change (UNFCCC) to compar e the relative contribution of diffe rent emission sources and greenhouse gases to climate change.

In 1992, the United States signed and ratified the UNFCCC. As stated in Article 2 of the UNFCCC, “The ultimate objective of this Convention...is to ach ieve...stabilization of greenhouse gas con centrations in the atmosphere at a level that would prevent dangerous anthropogenic interfere nce with the climate system. Such a level should be achieved within a time-frame sufficient to allow ecosystems to adapt naturally to climate change, to ensure that food production is not threatened and to enable economic development to proceed in a sustainable manner.” 2

Parties to the Convention, by ratifying, “shall develop, periodically update, publish a nd make available...national inventories of anthropogenic emissions by sources and rem ovals by sinks of all greenhouse gases not controlled by the Montreal Protocol , using comparable methodologies

... ” 3 The United States views this report as an opportunity to fulfill these commitments.

This chapter summarizes the latest information on U.S. anthropogenic greenhouse gas emission trends from 1990 through 2003. To ensure that the U.S. emissions inventory is comparable to those of other UNFCCC Parties, the estimates presented here were calculated using met hodologies consistent with those recommended in the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997), the IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2000), and the IPCC Good Practice Guidance for Land Use, Land Use Change and Forestry (IPCC 2003). The structure of this report is consistent with the UNFCCC guidelines for inventory reporting. 4 For most source categories, the IPCC methodologies were e xpanded, resulting in a more comprehens ive and detailed estimate of emissions.


### ES.1. Background Information

Naturally occurring greenhouse gases in clude water vapor, carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), and ozone (O 3 ). Several classes of halogenated substances that contain fluorine, chlorine, or bromine are also greenhouse gases, but they are, fo r the most part, solely a product of i ndustrial activities. Chlorofluorocarbons (CFCs) and hydrochlorofluorocarbons (HCFCs) are halocarbons that contain chlorine, while halocarbons that contain bromine are referred to as bromofluorocarbons (i.e., halons). As stratospheric ozone depleting substances, CFCs, HCFCs, and halons are covered under the Montreal Protocol on Substances that Deplete the Ozone Layer

. The UNFCCC defers to this earlier international treaty. Consequently, Parties are not required to include these gases in their national greenhouse gas emission inventories. 5 Some other fluorine-containing halogenated

1 The term “anthropogenic”, in this context, refers to greenhouse gas emissions and rem ovals 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 Conven tion on Climate Change published by th e UNEP/WMO Information Unit on Climate Change. See <http://unfccc.int>. 3 Article 4(1)(a) of the United Nations Framework Convention on C limate Change (also identified in Article 12). Subsequent decisions by the Conference of the Parties elaborated the role of Annex I Parties in preparing national inventories. See <http://unfccc.int>. 4 See <http://unfccc.int/resource/docs/cop8/08.pdf>. 5 Emissions estimates of CFCs, HCFCs, halons and other ozone-depleting substan ces are included in this document for informational purposes.Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-2 substances—hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF 6 )—do not deplete stratospheric ozone but are potent gr eenhouse gases. These latter substances are addressed by the UNFCCC and accounted for in national greenhouse gas emission inventories.

There are also several gases that do not have a direct globa l warming effect but indirectly affect terrestrial and/or solar radiation absorption by influencing the formati on or destruction of other greenhouse gases, including tropospheric and stratospheric ozone. These gases include carbon monoxide (CO), oxides of nitrogen (NO x ), and non-methane volatile organic compounds (NMVOCs). Aerosols, which are ex tremely small particles or liquid droplets, such as those produced by sulfur dioxide (SO 2 ) or elemental carbon emissions, can also affect the absorptive characteristic s of the atmosphere.

Although the direct greenhouse gases CO 2 , CH 4 , and N 2 O occur naturally in the atmosphere, human activities have changed their atmospheric concentrations. Since the pre- industrial era (i.e., ending about 1750), concentrations of these greenhouse gases have increased by 31, 150, and 16 percent, respectively (IPCC 2001).

Beginning in the 1950s, the use of CFCs and other stratos pheric ozone depleting substances (ODSs) increased by nearly 10 percent per year until the mi d-1980s, when international concern about ozone depletion led to the entry into force of the Montreal Protocol . Since then, the production of ODSs is being phased out. In recent years, use of ODS substitutes such as HFCs and PFCs has grown as th ey begin to be phased in as replacements for CFCs and HCFCs. Accordingly, atmospheri c concentrations of these substitu tes have been growing (IPCC 2001). 

### Global Warming Potentials

Gases in the atmosphere can contribute to the greenhouse eff ect both directly and indirectly. Direct effects occur when the gas itself absorbs radiation. Indirect radiative forcing occurs wh en chemical transformations of the substance produce other greenhouse gases, when a gas influen ces the atmospheric lifetimes of other gases, and/or when a gas affects atmospheric processes that alter the radi ative balance of the earth (e.g., affect cloud formation or albedo). 6 The IPCC developed the Global Warming Potentia l (GWP) concept to comp are the ability of each greenhouse gas to trap heat in the atmosphere relative to another gas.

The GWP of a greenhouse gas is defined as the ratio of th e time-integrated radiative forcing from the instantaneous release of 1 kg of a trace substance relative to that of 1 kg of a reference gas (IPCC 2001). Direct radiative effects occur when the gas itself is a greenhouse gas. The reference gas used is CO 2 , and therefore GWP-weighted emissions are measured in teragrams of CO 2 equivalent (Tg CO 2 Eq.). 7 All gases in this Executive Summary are presented in units of Tg CO 2 Eq. The relationship between gigagrams (Gg) of a gas and Tg CO 2 Eq. can be expressed as follows:


## ( )( ) ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× × = Gg 1,000 Tg GWP gas of Gg Eq CO Tg 2

The UNFCCC reporting guidelines for nati onal inventories were updated in 2002, 8 but continue to require the use of GWPs from the IPCC Second Assessment Report (SAR). This requirement ensures that current estimates of aggregate greenhouse gas emissions for 1990 to 2003 are consistent with estimates developed prior to the publication of the IPCC Third Assessment Report (TAR). Therefore, to comply with international reporting standards under the UNFCCC, official emission estimates are reported by the United States using SAR GWP values. All estimates are provided throughout the report in both CO 2 equivalents and unweighted units. A

6 Albedo is a measure of the Earth’s reflectivity ; see the Glossary (Annex 6.8) for definition. 7 Carbon comprises 12/44 ths of carbon dioxide by weight. 8 See <http://unfccc.int/resource/docs/cop8/08.pdf>.Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-3 comparison of emission values using the SAR GWPs versus the TAR GWPs can be found in Chapter 1 and in more detail in Annex 6.1. The GWP values used in this report are listed below in Table ES-1.

Table ES-1: Global Warming Potentials (100 Year Time Horizon) Used in this Report Gas GWP CO 2 1 CH 4 * 21 N 2 O 310 HFC-23 11,700 HFC-32 650 HFC-125 2,800 HFC-134a 1,300 HFC-143a 3,800 HFC-152a 140 HFC-227ea 2,900 HFC-236fa 6,300 HFC-4310mee 1,300 CF 4 6,500 C 2 F 6 9,200 C 4 F 10 7,000 C 6 F 14 7,400 SF 6 23,900 Source: IPCC (1996) * The methane GWP includes the direct effects and those indi rect effects due to the production of tropospheric ozone and stratospheric water vapor. The indirect effect due to the production of CO 2 is not included.

Global warming potentials are not provided for CO, NO x , NMVOCs, SO 2 , and aerosols because there is no agreedupon method to estimate the contribution of gases that are shor t-lived in the atmosphere, spatially variable, or have only indirect effects on radiative forcing (IPCC 1996).



### ES.2. Recent Trends in U.S. Gr eenhouse Gas Emissions and Sinks

In 2003, total U.S. greenhouse gas emissions were 6,900.2 Tg CO 2 Eq. Overall, total U.S. emissions have risen by 13 percent from 1990 to 2003, while the U.S. gross domestic product has increased by 46 percent over the same period (BEA 2004). Emissions rose slightly from 2002 to 2003, increasing by 0.6 percent (42.2 Tg CO 2 Eq.). The following factors were primary contributors to this increase: 1) moderate economic growth in 2003, leading to increased demand for electricity and fossil fuels, 2) in creased natural gas prices, causing some electric power producers to switch to burning coal, and 3) a colder winter , which caused an increase in the use of heating fuels, primarily in the residential end-use sector.

Figure ES-1 through Figure ES-3 illustrate the overall trends in total U.S. emissions by gas, annual changes, and absolute change since 1990. Table ES-2 provides a deta iled summary of U.S. greenhouse gas emissions and sinks for 1990 through 2003.

Figure ES-1: U.S. Greenhouse Gas Emissions by Gas

Figure ES-2: Annual Percent Change in U.S. Greenhouse Gas Emissions

Figure ES-3: Cumulative Change in U.S. Greenhouse Gas Emissions Relative to 1990Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-4 Table ES-2: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO 2 Eq.) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 5,009.6 5,580.0 5,607.2 5,678.0 5,858.2 5,744.8 5,796.8 5,841.5

Fossil Fuel Combustion 4,711.7 5,263.2 5,278.7 5,345.9 5,545.1 5,448.0 5,501.4 5,551.6 Non-Energy Use of Fuels 108.0 120.3 135.4 141.6 124.7 120.1 118.8 118.0 Iron and Steel Production 85.4 71.9 67.4 64.4 65.7 58.9 55.1 53.8 Cement Manufacture 33.3 38.3 39.2 40.0 41.2 41.4 42.9 43.0 Waste Combustion 10.9 17.8 17.1 17.6 18.0 18.8 18.8 18.8 Ammonia Production and Urea

Application 19.3 20.7 21.9 20.6 19.6 16.7 18.6 15.6 Lime Manufacture 11.2 13.7 13.9 13.5 13.3 12.8 12.3 13.0 Natural Gas Flaring 5.8 7.9 6.6 6.9 5.8 6.1 6.2 6.0 Limestone and Dolomite Use 5.5 7.2 7.4 8.1 6.0 5.7 5.9 4.7 Aluminum Production 6.3 5.6 5.8 5.9 5.7 4.1 4.2 4.2 Soda Ash Manufacture and

Consumption 4.1 4.4 4.3 4.2 4.2 4.1 4.1 4.1 Petrochemical Production 2.2 2.9 3.0 3.1 3.0 2.8 2.9 2.8 Titanium Dioxide Production 1.3 1.8 1.8 1.9 1.9 1.9 2.0 2.0 Phosphoric Acid Production 1.5 1.5 1.6 1.5 1.4 1.3 1.3 1.4 Ferroalloys 2.0 2.0 2.0 2.0 1.7 1.3 1.2 1.4 Carbon Dioxide Consumption 0.9 0.8 0.9 0.8 1.0 0.8 1.0 1.3 Land-Use Change and Forestry

(Sinks) a (1,042.0) (930.0) (881.0) (826.1) (822.4) (826.9) (826.5) (828.0) International Bunker Fuels b 113.5 109.9 114.6 105.3 101.4 97.9 89.5 84.2 Biomass Combustion b 216.7 233.2 217.2 222.3 226.8 200.5 207.2 216.8 CH 4 605.3 579.5 569.1 557.3 554.2 546.8 542.5 545.0

Landfills 172.2 147.4 138.5 134.0 130.7 126.2 126.8 131.2 Natural Gas Systems 128.3 133.6 131.8 127.4 132.1 131.8 130.6 125.9 Enteric Fermentation 117.9 118.3 116.7 116.8 115.6 114.5 114.6 115.0 Coal Mining 81.9 62.6 62.8 58.9 56.2 55.6 52.4 53.8 Manure Management 31.2 36.4 38.8 38.8 38.1 38.9 39.3 39.1 Wastewater Treatment 24.8 31.7 32.6 33.6 34.3 34.7 35.8 36.8 Petroleum Systems 20.0 18.8 18.5 17.8 17.6 17.4 17.1 17.1 Rice Cultivation 7.1 7.5 7.9 8.3 7.5 7.6 6.8 6.9 Stationary Sources 7.8 7.4 6.9 7.1 7.3 6.7 6.4 6.7 Abandoned Coal Mines 6.1 8.1 7.2 7.3 7.7 6.9 6.4 6.4 Mobile Sources 4.8 4.0 3.9 3.6 3.4 3.1 2.9 2.7 Petrochemical Production 1.2 1.6 1.7 1.7 1.7 1.4 1.5 1.5 Iron and Steel Production 1.3 1.3 1.2 1.2 1.2 1.1 1.0 1.0 Agricultural Residue Burning 0.7 0.8 0.8 0.8 0.8 0.8 0.7 0.8 Silicon Carbide Production + + + + + + + + International Bunker Fuels b 0.2 0.1 0.2 0.1 0.1 0.1 0.1 0.1 N 2 O 382.0 396.3 407.8 382.1 401.9 385.8 380.5 376.7

Agricultural Soil Management 253.0 252.0 267.7 243.4 263.9 257.1 252.6 253.5 Mobile Sources 43.7 55.2 55.3 54.6 53.2 49.0 45.6 42.1 Manure Management 16.3 17.3 17.4 17.4 17.8 18.0 17.9 17.5 Human Sewage 13.0 14.7 15.0 15.4 15.6 15.6 15.7 15.9 Nitric Acid 17.8 21.2 20.9 20.1 19.6 15.9 17.2 15.8 Stationary Sources 12.3 13.5 13.4 13.5 14.0 13.5 13.5 13.8 Settlements Remaining

Settlements 5.5 6.1 6.1 6.2 6.0 5.8 6.0 6.0 Adipic Acid 15.2 10.3 6.0 5.5 6.0 4.9 5.9 6.0 N 2 O Product Usage 4.3 4.8 4.8 4.8 4.8 4.8 4.8 4.8 Waste Combustion 0.4 0.4 0.3 0.3 0.4 0.4 0.5 0.5 Agricultural Residue Burning 0.4 0.4 0.5 0.4 0.5 0.5 0.4 0.4Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-5 Forest Land Remaining Forest

Land 0.1 0.3 0.4 0.5 0.4 0.4 0.4 0.4 International Bunker Fuels b 1.0 1.0 1.0 0.9 0.9 0.9 0.8 0.8 HFCs, PFCs, and SF 6 91.2 121.7 135.7 134.8 138.9 129.5 138.3 137.0

Substitution of Ozone Depleting

Substances 0.4 46.5 56.6 65.8 75.0 83.3 91.5 99.5 Electrical Transmission and

Distribution 29.2 21.7 17.1 16.4 15.6 15.4 14.7 14.1 HCFC-22 Production 35.0 30.0 40.1 30.4 29.8 19.8 19.8 12.3 Semiconductor Manufacture 2.9 6.3 7.1 7.2 6.3 4.5 4.4 4.3 Aluminum Production 18.3 11.0 9.1 9.0 9.0 4.0 5.2 3.8 Magnesium Production and

Processing 5.4 6.3 5.8 6.0 3.2 2.6 2.6 3.0 Total 6,088.1 6,677.5 6,719.7 6,752.2 6,953.2 6,806.9 6,858.1 6,900.2 Net Emissions (Sources and

Sinks) 5,046.1 5,747.5 5,838.8 5,926.1 6,130.8 5,980.1 6,031.6 6,072.2

+ Does not exceed 0.05 Tg CO 2 Eq.

a Sinks are only included in net emissions total, and are based partially on projected activity data. Parentheses indicate nega tive values (or sequestration). b Emissions from International B unker Fuels and Biomass combustion are not included in totals. Note: Totals may not sum due to independent rounding.

Figure ES-4 illustrates the relative contri bution of the direct greenhouse gases to total U.S. emissions in 2003. The primary greenhouse gas emitted by human activities in the United States was CO 2 , representing approximately 85 percent of total greenhouse gas emissions. The largest source of CO 2 , and of overall greenhouse gas emissions, was fossil fuel combustion. Methane emissions, which have steadily declined since 1990, resulted primarily from decomposition of wastes in landfills, natural gas systems, and enteric fermentation associated with domestic livestock. Agricultural soil management and mobile sour ce fossil fuel combustion were the major sources of N 2 O emissions. The emissions of substitutes for ozone depleting substances and emissions of HFC-23 during the production of HCFC-22 were the primary contributors to aggregate HFC emissions. Electrical transmission and distribution systems accounted for most SF 6 emissions, while PFC emissions resulted from semiconductor manufacturing and as a by-product of primary aluminum production.

Figure ES-4: 2003 Greenhouse Gas Emissions by Gas

Overall, from 1990 to 2003, total emissions of CO 2 increased by 832.0 Tg CO 2 Eq. (17 percent), while CH 4 and N 2 O emissions decreased by 60.4 Tg CO 2 Eq. (10 percent) and 5.2 Tg CO 2 Eq. (1 percent), respectively. During the same period, aggregate weighted emissions of HFCs, PFCs, and SF 6 rose by 45.8 Tg CO 2 Eq. (50 percent). Despite being emitted in smaller quantities relative to the other pr incipal greenhouse gases, emi ssions of HFCs, PFCs, and SF 6 are significant because many of them have extremely high global warming pot entials and, in the cases of PFCs and SF 6 , long atmospheric lifetimes. Conversely, U.S. gr eenhouse gas emissions were partly offset by carbon sequestration in forests, trees in urban areas, agricultu ral soils, and landfilled yard trimmings and food scraps, which, in aggregate, offset 12 per cent of total emissions in 2003. The following sections describe each gas’ contribution to total U.S. greenhouse gas emissions in more detail.



### Carbon Dioxide Emissions

The global carbon cycle is made up of la rge carbon flows and reservoirs. Billions of tons of carbon in the form of CO 2 are absorbed by oceans and living biomass (i.e., si nks) and are emitted to the atmosphere annually through natural processes (i.e., sources). When in equilibri um, carbon fluxes among these vari ous reservoirs are roughly balanced. Since the Industrial Revolution, atmospheric concentrations of CO 2 have risen about 31 percent (IPCC 2001), principally due to the combustion of fossil fuels. Within the United States, fu el combustion accounted for 95 percent of CO 2 emissions in 2003. Globally, approximately 24,240 Tg of CO 2 were added to the atmosphereInventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-6 through the combustion of fossil fuels in 2000, of wh ich the United States account ed for about 23 percent. 9 Changes in land use and forestry practices can also emit CO 2 (e.g., through conversion of forest land to agricultural or urban use) or can act as a sink for CO 2 (e.g., through net additions to forest biomass).

Figure ES-5: 2003 Sources of CO 2

As the largest source of U.S. greenhouse gas emissions, CO 2 from fossil fuel combustion has accounted for a nearly constant 80 percent of GWP weighted emissions since 1990. Emissions of CO 2 from fossil fuel combustion increased at an average annual rate of 1.3 percent from 1990 to 2003. The fundamental factors influencing this trend include (1) a generally growing domestic economy ove r the last 13 years, and (2) significant growth in emissions from transportation activities and elect ricity generation. Between 1990 and 2003, CO 2 emissions from fossil fuel combustion increased from 4,711.7 Tg CO 2 Eq. to 5,551.6 Tg CO 2 Eq.

⎯ an 18 percent total increase over the thirteen-year period. Historically, changes in emissions from fossil fuel combustion have been the dominant factor affecting U.S. emission trends.

From 2002 to 2003, these emissions increased by 50.2 Tg CO 2 Eq. (1 percent). A number of factors played a major role in the magnitude of this increase. The U.S. economy experienced moderate growth from 2002, causing an increase in the demand for fuels. The price of natura l gas escalated dramatically , causing some electric power producers to switch to coal, which remained at relatively stable prices. Colder winter conditions brought on more demand for heating fuels, primarily in the residential sector. Though a cooler summer partially offset demand for electricity as the use of air-conditioners decreased, electricity consumption continued to increase in 2003. The primary drivers behind this trend were the growing economy and the increase in U.S. housing stock. Use of nuclear and renewable fuels remained relatively stable. Nuclear capacity decreased slightly, for the first time since 1997. Use of renewable fuels rose slightly due to increas es in the use of hydroelectric power and biofuels.

Figure ES-6: 2003 CO 2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type

Figure ES-7: 2003 End-Use Sector Emissions of CO 2 from Fossil Fuel Combustion

The four major end-use sectors contributing to CO 2 emissions from fossil fuel combustion are industrial, transportation, residential, and commercial. Electricity generation also emits CO 2 , although these emissions are produced as they consume fossil fuel to provide electricity to one of the four end-use sectors. For the discussion below, electricity generation emissions have been distribut ed to each end-use sector on the basis of each sector’s share of aggregate electricity consump tion. This method of distributing emi ssions assumes that each end-use sector consumes electricity that is generate d from the national average mix of fuels according to their carbon intensity. In reality, sources of electricity vary widely in carbon intensity. By assumi ng the same carbon intensity for each enduse sector's electricity consumption, for example, emissions attributed to the residential end-use sector may be underestimated, while emissions attributed to the industrial end-use sector may be overestimated. Emissions from electricity generation are al so addressed separately after the end- use sectors have been discussed.

Note that emissions from U.S. territories are calculated separately due to a lack of specific consumption data for the individual end-use sectors.

Figure ES-6, Figure ES-7, and Table ES-3 summarize CO 2 emissions from fossil fuel combustion by end-use sector.

9 Global CO 2 emissions from fossil fuel combustion were taken from Marland et al. (2003) <http://cdiac.esd.ornl.gov/trends/emis/tre_glob.htm>.Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-7 Table ES-3: CO 2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO 2 Eq.) End-Use Sector 1990 1997 1998 1999 2000 2001 2002 2003 Transportation 1,449.8 1,606.4 1,636.5 1,693.9 1,741.0 1,723.1 1,755.4 1,770.4

Combustion 1,446.8 1,603.3 1,633.4 1,690.8 1,737.7 1,719.7 1,752.3 1,767.2 Electricity 3.0 3.1 3.1 3.2 3.4 3.4 3.2 3.2 Industrial 1,553.9 1,703.0 1,668.5 1,651.2 1,684.4 1,587.4 1,579.0 1,572.9

Combustion 882.8 963.8 911.6 888.1 905.0 878.2 876.6 858.6 Electricity 671.1 739.2 757.0 763.1 779.4 709.3 702.4 714.3 Residential 924.8 1,040.7 1,044.4 1,063.5 1,124.2 1,116.2 1,145.0 1,168.9

Combustion 339.6 370.6 338.6 359.3 379.1 367.0 371.4 385.1 Electricity 585.3 670.2 705.8 704.2 745.0 749.2 773.6 783.8 Commercial 755.1 876.7 892.9 901.2 959.5 972.7 973.9 983.1

Combustion 224.2 237.2 219.7 222.3 235.2 226.7 230.0 234.0 Electricity 530.9 639.5 673.2 678.9 724.3 745.9 743.9 749.2 U.S. Territories 28.0 36.4 36.3 36.2 35.9 48.6 48.1 56.2 Total 4,711.7 5,263.2 5,278.7 5,345.9 5,545.1 5,448.0 5,501.4 5,551.6 Electricity Generation 1,790.3 2,051.9 2,139.0 2,149.3 2,252.1 2,207.8 2,223.0 2,250.5 Note: Totals may not sum due to indepe ndent rounding. Combustion-related emissions from electricity generation are allocated based on aggregate national electricity consumption by each end-use sector. Transportation End-Use Sector . Transportation activities ( excluding international bunker fuels ) accounted for 32 percent of CO 2 emissions from fossil fuel combustion in 2003. 10 Virtually all of the energy consumed in this enduse sector came from petroleum products. Over 60 percent of the emissions resulted from gasoline consumption for personal vehicle use. The remaining emissions came from other transportation activities, including the combustion of diesel fuel in heavy-duty vehi cles and jet fuel in aircraft.

Industrial End-Use Sector . Industrial CO 2 emissions, resulting both directly from the combustion of fossil fuels and indirectly from the generation of el ectricity that is consumed by i ndustry, accounted for 28 percent of CO 2 from fossil fuel combustion in 2003. About half of these emissions resulted from direct fossil fuel combustion to produce steam and/or heat for industrial processes. The other half of the emissions resulted from consuming electricity for motors, electric furnaces, ovens, li ghting, and othe r applications.

Residential and Commercial End-Use Sectors . The residential and commercial end-use sectors accounted for 21 and 18 percent, respectively, of CO 2 emissions from fossil fuel combustion in 2003. Both sectors relied heavily on electricity for meeting energy demands, with 67 and 76 percent, respectively, of their emissions attributable to electricity consumption for lighting, heating, cooling, a nd operating appliances. The remaining emissions were due to the consumption of natural gas a nd petroleum for heating and cooking.

Electricity Generation . The United States relies on electricity to m eet a significant portion of its energy demands, especially for lighting, electric motors, heating, and air conditioning. Electric ity generators consumed 35 percent of U.S. energy from fossil fuels and emitted 41 percent of the CO 2 from fossil fuel combustion in 2003. The type of fuel combusted by electricity generators has a significant e ffect on their emissions. For ex ample, some electricity is generated with low CO 2 emitting energy technologies, par ticularly non-fossil options such as nuclear, hydroelectric, or geothermal energy. However, electricity generators re ly on coal for over half of their total energy requirements and accounted for 93 percent of all coal consumed for ener gy in the United States in 2003. Consequently, changes in electricity demand have a significant impact on coal consumption and associated CO 2 emissions.

Other significant CO 2 trends included the following:

10 If emissions from international bunker fuels are included, the tr ansportation end-use sector accounted for 33 percent of U.S. emissions from fossil fuel combustion in 2003.Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-8 ● Carbon dioxide emissions from iron and steel production decreased to 53.8 Tg CO 2 Eq. in 2003, and have declined by 31.7 Tg CO 2 Eq. (37 percent) from 1990 through 2003, due to reduced domestic production of pig iron, sinter, and coal coke.

● Carbon dioxide emissions from waste combustion (18.8 Tg CO 2 Eq. in 2003) increased by 7.9 Tg CO 2 Eq. (72 percent) from 1990 through 2003, as the volume of plastics and other fossil carbon-containing materials in municipal solid waste grew.

● Net CO 2 sequestration from land-use change and forestry decreased by 214.0 Tg CO 2 Eq. (21 percent) from 1990 through 2003. This decline was primarily attributable to forest soils, a result of the slowed rate of forest area increases after 1997. 

### Methane Emissions

According to the IPCC, CH 4 is more than 20 times as effective as CO 2 at trapping heat in the atmosphere. Over the last two hundred and fifty years, the concentration of CH 4 in the atmosphere increased by 150 percent (IPCC 2001). Experts believe that over half of this atmospheric incr ease was due to emissions from anthropogenic sources, such as landfills, natural gas and petroleum systems, agricultural activities, coal mining, wastewater treatment, stationary and mobile combustion, and certain industrial processes (see Figure ES-8).

Figure ES-8: 2003 U.S. Sources of CH 4

Some significant trends in U.S. emissions of CH 4 included the following:

● Landfills are the largest anthropogenic source of CH 4 emissions in the United States. In 2003, landfill CH 4 emissions were 131.2 Tg CO 2 Eq. (approximately 24 percent of total CH 4 emissions), which represents a decline of 41.1 Tg CO 2 Eq., or 24 percent, since 1990.

● Methane emissions from coal mining declined by 28.1 Tg CO 2 Eq. (34 percent) from 1990 to 2003, as a result of the mining of less gassy coal from underground mines and the increased use of methane collected from degasification systems. 

### Nitrous Oxide Emissions

Nitrous oxide is produced by biological processes that occur in soil and water and by a variety of anthropogenic activities in the agricultura l, energy-related, industrial, and wast e management fields. While total N 2 O emissions are much lower than CO 2 emissions, N 2 O is approximately 300 times more powerful than CO 2 at trapping heat in the atmosphere. Since 1750, the atmospheric concentration of N 2 O has risen by approximately 16 percent (IPCC 2001). The main anthropogenic activities producing N 2 O in the United States are agri cultural soil management, fuel combustion in motor vehicles, manure management, nitric acid production, human sewage, and stationary fuel combustion (see Figure ES-9).

Figure ES-9: 2003 U.S. Sources of N 2 O

Some significant trends in U.S. emissions of N 2 O included the following:

● Agricultural soil management activities such as fertilizer application a nd other cropping practices were the largest source of U.S. N 2 O emissions, accounting for 67 percent (253.5 Tg CO 2 Eq.).

● In 2003, N 2 O emissions from mobile combustion were 42.1 Tg CO 2 Eq. (approximately 11 percent of U.S. N 2 O emissions). From 1990 to 2003, N 2 O emissions from mobile combustion decreased by 4 percent.Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-9 

### HFC, PFC, and SF 6 

### Emissions

HFCs and PFCs are families of synthetic chemicals that are being used as alternatives to the ODSs, which are being phased out under the Montreal Protocol and Clean Air Act Amendments of 1990. HFCs and PFCs do not deplete the stratospheric ozone layer, and are therefore acceptable alternatives under the Montreal Protocol

. These compounds, however, along with SF 6 , are potent greenhouse gases. In addition to having high global warming potentials, SF 6 and PFCs have extremely long atmospheric lifetimes, resulting in their essentially irreversible accumulation in the atmosphere once emitted. Sulfur hexafluoride is the most potent greenhouse gas the IPCC has evaluated.

Other emissive sources of these gases include HCFC-22 production, electrical transmission and distribution systems, semiconductor manufacturing, aluminum pr oduction, and magnesium production and processing (see Figure ES-10).

Figure ES-10: 2003 U.S. Sources of HFCs, PFCs, and SF 6

Some significant trends in U.S. HFC, PFC and SF 6 emissions included the following:

● Emissions resulting from the substitution of ozone depleting substances (e.g., CFCs) have been increasing from small amounts in 1990 to 99.5 Tg CO 2 Eq. in 2003. Emissions from substitu tes for ozone depleting substances are both the largest and the fastest growing source of HFC, PFC and SF 6 emissions.

● The increase in ODS emissions is offset substantia lly by decreases in emission of HFCs, PFCs, and SF 6 from other sources. Emissions from aluminum production decreased by 79 percent (14.5 Tg CO 2 Eq.) from 1990 to 2003, due to both industry emission reduction efforts a nd lower domestic aluminum production. Emissions from the production of HCFC-22 decreased by 65 percent (22.6 Tg CO 2 Eq.), due to a stead y decline in the emission rate of HFC-23 (i.e., the amount of HFC-23 em itted per kilogram of HCFC-22 manufactured) and the use of thermal oxidation at some plants to reduce HFC-23 emissions. Emissions from electric power transmission and distribution systems decreased by 52 percent (15.1 Tg CO 2 Eq.) from 1990 to 2003, primarily because of higher purchase prices for SF 6 and efforts by industry to reduce emissions.



### ES.3. Overview of Sector Emissions and Trends

In accordance with the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997), and the 2003 UNFCCC Guidelines on Reporting and Review (UNFCCC 2003), this Inventory of U.S. Greenhouse Gas Emissions and Sinks is segregated into six sector-specific chapters. Figure ES-11 and Table ES-4 aggregate emissions and sinks by these chapters.

Figure ES-11: U.S. Greenhouse Gas Emissions by Chapter/IPCC Sector

Table ES-4: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Ch apter/IPCC Sector (Tg CO 2 Eq.) Chapter/IPCC Sector 1990 1997 1998 1999 2000 2001 2002 2003 Energy 5,141.7 5,712.8 5,737.7 5,802.6 5,985.3 5,877.3 5,920.7 5,963.4 Industrial Processes 299.9 327.1 334.9 329.2 332.1 304.7 315.4 308.6 Solvent and Other Product Use 4.3 4.8 4.8 4.8 4.8 4.8 4.8 4.8 Agriculture 426.5 432.8 449.8 425.9 444.1 437.5 432.4 433.3 Land-Use Change and Forestry (Emissions) 5.6 6.4 6.5 6.6 6.3 6.2 6.4 6.4 Waste 210.1 193.7 186.0 183.1 180.6 176.5 178.3 183.8 Total 6,088.1 6,677.5 6,719.7 6,752.2 6,953.2 6,806.9 6,858.1 6,900.2 Land-Use Change and Forestry (Sinks) (1042.0) (930.0) (881.0) (826.1) (822.4) (826.9) (826.5) (828.0) Net Emissions (Sources and Sinks) 5,046.1 5,747.5 5,838.8 5,926.1 6,130.8 5,980.1 6,031.6 6,072.2Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-10 * 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 nega tive values (or sequestration).



### Energy

The Energy chapter contains emissi ons of all greenhouse gases resulting fro m stationary and mobile energy activities including fuel combustion and fugitive fuel emissions. Energy-related activities, primarily fossil fuel combustion, accounted for the vast majority of U.S. CO 2 emissions for the period of 1990 through 2003. In 2003, approximately 86 percent of the energy consumed in the United States was produced through the combustion of fossil fuels. The remaining 14 percent came from other energy sources such as hydropower, biomass, nuclear, wind, and solar energy (see Figure ES-12). Ener gy related activities are also responsible for CH 4 and N 2 O emissions (39 percent and 15 percent of total U.S. emissions, respectively). Overall, emission sources in the Energy chapter account for a combined 87 percent of total U.S. greenhouse gas emissions in 2003.

Figure ES-12: 2003 U.S. Energy Consumption by Energy Source



### Industrial Processes

The Industrial Processes chapter contains by-product or fugitive emissions of greenhouse gases from industrial processes not directly related to energy activities such as fossil fuel combusti on. For example, industrial processes can chemically transform raw materials, wh ich often release waste gases such as CO 2, CH 4, and N 2 O. The processes include iron and steel production, cement manufacture, ammonia manufacture and urea application, lime manufacture, limestone and dolomite use (e.g., flux stone, fl ue gas desulfurization, and glass manufacturing), soda ash manufacture and use, titanium dioxide production, phosphor ic acid production, ferroalloy production, CO 2 consumption, aluminum pr oduction, petrochemical production, silicon car bide production, nitr ic acid production, and adipic acid production. Additi onally, emissions from industrial pr ocesses release HFCs, PFCs and SF 6 . Overall, emission sources in the Industrial Process chapter account for 4.5 percent of U.S. greenhouse gas emissions in 2003.



### Solvent and Other Product Use

The Solvent and Other Product Use chapter contains emissions Greenhouse gas emissions are produced as a byproduct of various solvent and other product uses. In the United States, emissions from N 2 O Product Usage, the only source of greenhouse gas emissions from this sector , accounted for less than 0.1 percent of total U.S. anthropogenic greenhouse gas emissions on a carbon equivalent basis in 2003.


### Agriculture

The Agricultural chapter contains an thropogenic emissions from agricultural activities (except fuel combustion, which is addressed in the Energy ch apter). Agricultural activities contribut e directly to emissions of greenhouse gases through a variety of processes, including the following source categories: enteric fermentation in domestic livestock, livestock manure management, rice cultivation, agricultural soil management, and field burning of agricultural residues. Methane and N 2 O were the primary greenhouse gases emitted by agricultural activities. Methane emissions from enteric fermentation and manure ma nagement represented about 21 percent and 7 percent of total CH 4 emissions from anthropogenic activities, respectivel y in 2003. Agricultural soil management activities such as fertilizer application and other cropping practi ces were the largest source of U.S. N 2 O emissions in 2003, accounting for 67 percent. In 2003, emi ssion sources accounted for in the Agri cultural chapters were responsible for 6.3 percent of total U.S. greenhouse gas emissions. 

### Land-Use Change and Forestry

The Land-Use Change and Forestry chapter contains emissions and removals of CO 2 from forest management, other land-use activities, and land-use change. Forest management practices, tree planting in urban areas, theInventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-11 management of agricultural soils, and the landfilling of yard trimmings and food scraps ha ve resulted in a net uptake (sequestration) of carbon in the United States. Forests (includi ng vegetation, soils, and harvested wood) accounted for approximately 91 percent of tota l 2003 sequestration, urban trees accounted for 7 percent, agricultural soils (including mineral and organic soils and the application of lime) accounted for 1 percent, and landfilled yard trimmings and food scraps accounted for 1 percent of the to tal sequestration in 2003. The net forest sequestration is a result of net forest growth and increasing forest area, as well as a net accumulation of carbon stocks in harvested wood pools. The net sequestration in urban forests is a result of net tree growth in these areas. In agricultural soils, mineral soils account for a net carbon sink that is approximately one and a third times larger than the sum of emissions from organic soils and liming. The mineral soil carbon sequestration is largely due to conversion of cropland to permanent pastures and hay production, a re duction in summer fallow areas in semi-arid areas, an increase in the adoption of conservation tillage practices, a nd an increase in the amounts of organic fertilizers (i.e., manure and sewage sludge) applied to agriculture lands. The landfilled ya rd trimmings and food scraps net sequestration is due to the long-te rm accumulation of yard trimming carbon and food scraps in landfills.

Land use, land-use change, and forestry activities in 2003 resulted in a net carbon sequestration of 828.0 Tg CO 2 Eq. (Table ES-5). This represents an offset of approximately 14 percent of total U.S. CO 2 emissions, or 12 percent of total gross greenhouse gas emissions in 2003. Tota l land use, land-use change, and forestry net carbon sequestration declined by approximately 21 percent betw een 1990 and 2003. This decline was primarily due to a decline in the rate of net carbon accumulation in forest carbon stocks. Annual carbon accumulation in landfilled yard trimmings and food scraps also slowed over this period, as did annual carbon accumulation in agricultural soils. As described above, the cons tant rate of carbon accumulation in ur ban trees is a reflection of limited underlying data (i.e., this rate represents an average for 1990 through 1999).

Land use, land-use change, and forestry activ ities in 2003 also resulted in emissions of N 2 O (6.4 Tg CO 2 Eq.). Total N 2 O emissions from the application of fertilizers to forests and settlements increased by approximately 14 percent between 1990 and 2003.

Table ES-5: Net CO 2 Flux from Land-Use Change and Forestry (Tg CO 2 Eq.) Sink Category 1990 1997 1998 1999 2000 2001 2002 2003 Forest Land Remaining Forest Land (949.3) (851.0) (805.5) (751.7) (747.9) (750.9) (751.5) (752.7)

Changes in Forest Carbon Stocks (949.3) (851.0) (805.5) (751.7) (747.9) (750.9) (751.5) (752.7) Cropland Remaining Cropland (8.1) (7.4) (4.3) (4.3) (5.7) (7.1) (6.2) (6.6)

Changes in Agricultural Soil Carbon

Stocks (8.1) (7.4) (4.3) (4.3) (5.7) (7.1) (6.2) (6.6) Settlements Remaining Settlements (84.7) (71.6) (71.2) (70.0) (68.9) (68.9) (68.8) (68.7)

Urban Trees (58.7) (58.7) (58.7) (58.7) (58.7) (58.7) (58.7) (58.7) Landfilled Yard Trimmings and Food

Scraps (26.0) (12.9) (12.5) (11.4) (10.2) (10.3) (10.2) (10.1) Total (1,042.0) (930.0) (881.0) (826.1) (822.4) (826.9) (826.5) (828.0)

Note: Parentheses indicate net se questration. Totals may not sum due to independent rounding.



### Waste

The Waste chapter contains emissions from waste management activities (except waste incineration, which is addressed in the Energy chapter). Landfills were the largest source of anthropogenic CH 4 emissions, accounting for 24 percent of total U.S. CH 4 emissions. 11 Wastewater treatment systems ar e a potentially significant source of N 2 O emissions; however, methodologies are not currently available to develop a complete estimate. Nitrous oxide emissions from the treatment of the human sewage component of wastewater were estimated, however, using a

11 Landfills also store carbon, due to incomplete degradation of organic materials such as wood products and yard trimmings, as described in the Land-Use Change and Forestry chapter.Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-12 simplified methodology. Overall, in 2003, emission sources accounted for in the Waste chapter generated 2.7 percent of total U.S. greenhouse gas emissions.



### ES.4. Other Information Emissions by Economic Sector

Throughout this report, emission estimates are grouped into six sectors (i.e., chapters) defined by the IPCC: Energy, Industrial Processes, Solvent Use, Agriculture, Land-Use Change and Forestry, and Waste. While it is important to use this characterization for consistency with UNFCCC reporting guidelines, it is also useful to allocate emissions into more commonly used sectoral categories. This section reports emissions by the following economic sectors: Residential, Commercial, Industry, Transporta tion, Electricity Generation, and Agriculture, and U.S. Territories. Table ES-6 summarizes emissions from each of these sectors, and Figure ES-13 shows the trend in emissions by sector from 1990 to 2003.

Figure ES-13: Emissions Allocated to Economic Sectors

Table ES-6: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO 2 Eq.) Economic Sector 1990 1997 1998 1999 2000 2001 2002 2003 Electric Power Industry 1,841.8 2,104.6 2,186.8 2,197.3 2,299.0 2,254.9 2,269.7 2,296.2 Transportation 1,506.8 1,693.0 1,728.7 1,790.0 1,839.6 1,819.8 1,851.6 1,864.4 Industry 1,446.1 1,509.1 1,470.6 1,427.9 1,431.8 1,371.0 1,365.7 1,331.4 Agriculture 473.3 492.0 508.4 486.9 495.3 488.6 485.6 486.4 Commercial 435.4 445.2 424.2 426.8 440.7 431.4 440.2 453.5 Residential 350.9 391.0 358.4 379.5 399.7 387.1 391.6 406.1 U.S. Territories 33.8 42.7 42.7 43.9 47.0 54.1 53.6 62.3 Total 6,088.1 6,677.5 6,719.7 6,752.2 6,953.2 6,806.9 6,858.1 6,900.2 Land-Use Change and Forestry

Sinks (1,042.0) (930.0) (881.0) (826.1) (822.4) (826.9) (826.5) (828.0) Net Emissions (Sources and

Sinks) 5,046.1 5,747.5 5,838.8 5,926.1 6,130.8 5,980.1 6,031.6 6,072.2 Note: Totals may not sum. Emissions include CO 2 , CH 4 , HFCs, PFCs, and SF 6 . See Table 2-14 for more detailed data.

Using this categorization, emissions from electricity ge neration accounted for the largest portion (33 percent) of U.S. greenhouse gas emissions in 2003. Transportation ac tivities, in aggregate, account ed for the second largest portion (27 percent). Emissions from industry accounted for 19 percent of U. S. greenhouse gas emissions in 2003. In contrast to electricity generation and transportation, emissions from industry have declined over the past decade, as structural changes have occurred in the U.S. economy (i.e., shifts from a manufacturing based to a service-based economy), fuel switching has occurred, and efficiency impr ovements have been made. The remaining 21 percent of U.S. greenhouse gas emissions were contributed by the re sidential, agriculture, and commercial economic sectors, plus emissions from U.S. Territories. Residences account ed for about 6 percent, and primarily consisted of CO 2 emissions from fossil fuel combustion. Activities related to agriculture accounted for roughly 7 percent of U.S. emissions; these emissions were dominated by N 2 O emissions from agricultural soils instead of CO 2 from fossil fuel combustion. The commercial sector acc ounted for about 7 percent of emissions , while U.S. territories accounted for 1 percent.

Carbon dioxide was also emitted and seque stered by a variety of activities rela ted to forest management practices, tree planting in urban areas, the management of agricultural soils, and landfilling of yard trimmings.

Electricity is ultimately consumed in the economic sect ors described above. Table ES-7 presents greenhouse gas emissions from economic sectors with emissions related to electricity generation distributed into end-use categories (i.e., emissions from electricity generation are allocated to the economic sectors in which the electricity isInventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-13 consumed). To distribute electricity emissions among end-use sectors, emissions from the source categories assigned to electricity generation were allocated to the residential, commercial, industry, transportation, and agriculture economic sectors accordi ng to retail sales of electricity. 12 These source categories include CO 2 from fossil fuel combustion and the use of limestone and dolomite for flue gas desulfurization, CO 2 and N 2 O from waste combustion, CH 4 and N 2 O from stationary sources, and SF 6 from electrical transmission and distribution systems.

When emissions from electricity are di stributed among these sectors, industry accounts for the largest share of U.S. greenhouse gas emissions (30 percent) in 2003. Emissions from the residential and commercial sectors also increase substantially due to their relatively large share of electricity consumption (e.g., lighting, appliances, etc.). Transportation activities remain the second largest contribut or to emissions. In all sectors except agriculture, CO 2 accounts for more than 75 percent of greenhouse gas emissions, primarily from the combustion of fossil fuels. Figure ES-14 shows the trend in these emissions by sector from 1990 to 2003.

Table ES-7: U.S Greenhouse Gas Emissions by Economic Sector and Gas with Electricity-Related Emissions Distributed (Tg CO 2 Eq.) Economic Sector 1990 1997 1998 1999 2000 2001 2002 2003 Industry 2,075.7 2,247.3 2,223.2 2,190.1 2,207.7 2,074.0 2,062.9 2,040.1 Transportation 1,509.9 1,696.1 1,731.8 1,793.2 1,843.0 1,823.2 1,854.8 1,867.6 Commercial 981.6 1,083.8 1,093.5 1,104.9 1,161.8 1,170.6 1,178.5 1,196.8 Residential 953.0 1,060.3 1,060.0 1,082.9 1,141.4 1,129.6 1,159.5 1,183.7 Agriculture 534.1 547.4 568.6 537.3 552.3 555.5 548.8 549.8 U.S. Territories 33.8 42.7 42.7 43.9 47.0 54.1 53.6 62.3 Total 6,088.1 6,677.5 6,719.7 6,752.2 6,953.2 6,806.9 6,858.1 6,900.2 Land-Use Change and Forestry Sinks (1,042.0) (930.0) (881.0) (826.1) (822.4) (826.9) (826.5) (828.0) Net Emissions (Sources and Sinks) 5,046.1 5,747.5 5,838.8 5,926.1 6,130.8 5,980.1 6,031.6 6,072.2 See Table 2-16 for more detailed data.

Figure ES-14: Emissions with Electricity Distributed to Economic Sectors

[BEGIN BOX]

Box ES-1: Recent Trends in Various U. S. Greenhouse Gas Emissions-Related Data Total emissions can be compared to other economic and social indices to highlight changes over time. These comparisons include: 1) emissions per unit of aggregate energy consumption, because energy-related activities are the largest sources of emissions; 2) emissions per unit of fossil fuel consumption, becau se almost all energy-related emissions involve the combustion of fo ssil fuels; 3) emissions per unit of electricity consumption, because the electric power industry—utilities and nonutilities combined —was the largest source of U.S. greenhouse gas emissions in 2003; 4) emissions per unit of total gross domestic product as a measure of national economic activity; or 5) emissions per capita.

Table ES-8 provides data on various statistics related to U.S. greenhouse gas emissions normalized to 1990 as a baseline year. Greenhouse gas emissions in the United States have grown at an average annual rate of 1.0 percent since 1990. This rate is slower than that for total energy or fossil fuel consumption and much slower than that for either electricity consumption or overall gross domestic product. Total U.S. greenhouse gas emissions have also grown more slowly than national population since 1990 (see Figure ES-15). Overall, global atmospheric CO 2

12 Emissions were not distributed to U.S. territories, since th e electricity generation sector only includes emissions related to the generation of electricity in the 50 states and the District of Columbia.Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-14 concentrations

⎯ a function of many complex anthropogenic and natural processes

⎯ are increasing at 0.5 percent per year.

Table ES-8: Recent Trends in Various U.S. Data (Index 1990 = 100) a nd Global Atmospheric CO 2 Concentration

Variable 1991 1997 1998 1999 2000 2001 2002 2003 Growth Rate f Greenhouse Gas Emissions a 99 110 110 111 114 112 113 113 1.0% Energy Consumption b 100 112 113 114 117 114 116 116 1.2% Fossil Fuel Consumption b 99 112 113 114 117 115 116 116 1.2% Electricity Consumption b 102 117 121 124 128 125 129 130 2.1% GDP c 100 122 127 133 138 139 142 146 3.0% Population d 101 109 110 112 113 114 115 116 1.1% Atmospheric CO 2

Concentration e 100 103 104 104 104 105 105 106 0.5%

a GWP weighted values b Energy content weighted values (EIA 2004)

c Gross Domestic Product in chained 2000 dollars (BEA 2004) d (U.S. Census Bureau 2004)

e Mauna Loa Observatory, Hawaii (Keeling and Whorf 2004) f Average annual growth rate

Figure ES-15: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product

[END BOX]



### Ambient Air Pollutant Emissions

In the United States, CO, NO x , NMVOCs, SO 2 are referred to as "ambient air pollutants," and are regulated under the Clean Air Act in an effort to protect human health and the environment. These pollutants do not have a direct global warming effect, but indirectly affect terrestrial radiation absorption by influencing the formation and destruction of tropospheric and stratospheric ozone, or, in the case of SO 2 , by affecting the ab sorptive characteristics of the atmosphere. Additionally, some of these pollu tants may react with other chemical compounds in the atmosphere to form compounds that are greenhouse gases. Since 1970, the United States has published estimates of annual emissions of ambient air pollutants (EPA 2004). 13 Table ES-9 shows that fuel combustion accounts for the majority of emissions of these gases. Industrial processes

⎯ such as the manufacture of chemical and allied products, metals processing, and industrial uses of solvents

⎯ are also significant sources of CO, NO x, and NMVOCs.

Table ES-9: Emissions of NO x , CO, NMVOCs, and SO 2 (Gg) Gas/Activity 1990 1997 1998 1999 2000 2001 2002 2003 NO x 22,860 22,284 21,964 20,530 20,288 19,414 18,850 18,573

Stationary Fossil Fuel Combustion 9,884 9,578 9,419 8,344 8,002 7,667 7,523 7,222 Mobile Fossil Fuel Combustion 12,134 11,768 11,592 11,300 11,395 10,823 10,389 10,418 Oil and Gas Activities 139 130 130 109 111 113 135 124 Waste Combustion 82 140 145 143 114 114 134 121

13 NO x and CO emission estimates from field bur ning of agricultural residues were estimat ed separately, and therefore not taken from EPA (2004).Inventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-15 Industrial Processes 591 629 637 595 626 656 630 648 Solvent Use 1 3 3 3 3 3 5 4 Agricultural Burning 28 34 35 34 35 35 33 33 Waste 0 3 3 3 2 2 2 2 CO 130,580 101,138 98,984 94,361 92,895 89,329 87,451 85,077

Stationary Fossil Fuel Combustion 4,999 3,927 3,927 5,024 4,340 4,377 4,020 4,454 Mobile Fossil Fuel Combustion 119,482 90,284 87,940 83,484 83,680 79,972 78,574 75,526 Oil and Gas Activities 302 333 332 145 146 147 116 125 Waste Combustion 978 2,668 2,826 2,725 1,670 1,672 1,672 1,674 Industrial Processes 4,124 3,153 3,163 2,156 2,217 2,339 2,308 2,431 Solvent Use 4 1 1 46 46 45 46 65 Agricultural Burning 689 767 789 767 790 770 707 794 Waste 1 5 5 13 8 8 8 8 NMVOCs 20,937 16,994 16,403 15,869 15,228 15,048 14,222 13,939

Stationary Fossil Fuel Combustion 912 1,016 1,016 1,045 1,077 1,080 926 1,007 Mobile Fossil Fuel Combustion 10,933 7,928 7,742 7,586 7,230 6,872 6,560 6,351 Oil and Gas Activities 555 442 440 414 389 400 340 345 Waste Combustion 222 313 326 302 257 258 281 263 Industrial Processes 2,426 2,038 2,047 1,813 1,773 1,769 1,725 1,711 Solvent Use 5,217 5,100 4,671 4,569 4,384 4,547 4,256 4,138 Agricultural Burning NA NA NA NA NA NA NA NA Waste 673 157 161 140 119 122 133 125 SO 2 20,936 17,091 17,189 15,917 14,829 14,452 13,928 14,463

Stationary Fossil Fuel Combustion 18,407 15,104 15,191 13,915 12,848 12,461 11,946 12,477 Mobile Fossil Fuel Combustion 793 659 665 704 632 624 631 634 Oil and Gas Activities 390 312 310 283 286 289 315 293 Waste Combustion 39 29 30 30 29 30 24 28 Industrial Processes 1,306 985 991 984 1,031 1,047 1,009 1,029 Solvent Use 0 1 1 1 1 1 2 2 Agricultural Burning NA NA NA NA NA NA NA NA Waste 0 1 1 1 1 1 1 1 Source: (EPA 2004) except fo r estimates from field burning of agricultural residues. + Does not exceed 0.5 Gg NA (Not Available) Note: Totals may not sum due to independent rounding.

Figure ES-16: 2003 Key Sources – Tier 1 Level Assessment



### Quality Assurance and Quality Control (QA/QC)

The United States seeks to continually improve the quality, transparency and credibility of the Inventory of U.S. Greenhouse Gas Emissions and Sinks. To assist in these efforts, the United States implemented a systematic approach to QA/QC. While QA/QC has always been an integral part of the U.S. national system for Inventory development, the procedures followed for the current I nventory have been formali zed in accordance with the QA/QC plan and the UNFCCC reporting guidelines.


### Uncertainty Analysis of Emission Estimates

While the current U.S. emissions inventory provides a so lid foundation for the development of a more detailed and comprehensive national inventory, there are uncertainties associated with the emissi on estimates. Some of the current estimates, such as those for CO 2 emissions from energy-related activities and cement processing, are considered to have low uncertainties. For some other categories of emissions, however, a lack of data or an incomplete understanding of how emissions are generated increases the uncertainty associated with the estimatesInventory of U.S. Greenhouse Gas Emissions and Sin ks: 1990-2003 Page ES-16 presented. Acquiring a better understanding of the uncertainty associated with Inventory estimates is an important step in helping to prioriti ze future work and improve the overall quality of the Inventory. Recognizing the benefit of conducting an uncertainty analysis, the UNFCCC re porting guidelines follow the recommendations of the IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (hereafter referred to as the IPCC Good Practice Guidance ) and require that countries provide single point estimates of uncertainty for many source and sink categories.

Currently, a qualitative discussion of uncertainty is presented for all source and sink categories. Within the discussion of each emission source, specific factors affecting the uncer tainty surrounding the estimates are discussed. Most sources also c ontain a quantitative uncertainty assessm ent, in accordance with UNFCCC reporting guidelines.Fi g ure ES-1: U.S. GHG Emissions b y Gas

Fi g ure ES-2: Annual Percent Chan g e in U.S. Greenhouse Gas Emissions

Fi g ure ES-3: Cumulative Chan g e in U.S. Greenhouse Gas Emissions Relative to 1990 6,953 6,752 6,088 6,038 6,121 6,251 6,343 6,407 6,621 6,678 6,720 6,807 6,858 6,900

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Tg CO2Eq. HFCs, PFCs, & SF
Nitrous Oxide
Methane
Carbon Dioxide 6

1.0% 3.3%

0.9% 0.6% 0.5% 3.0%

0.8% 0.6% 1.5% 2.1%
1.4%

-2.1% -0.8%

-3% -2% -1% 0% 1% 2% 3% 4%

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

33 163 255 319 533 589 632 664 865

719 770 812

-50

-100

0 100 200 300 400 500 600 700 800 900

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Tg CO2Eq.Figure ES-4: 2003 Greenhouse Gas Emissions by Gas

Figure ES-5: 2003 Sources of CO 2 5,551.6

0 10 20 30 40 50 60 Carbon Dioxide Consumption Ferroalloys Phosphoric Acid Production Titanium Dioxide Production Soda Ash Manufacture and Consumption Aluminum Production Limestone and Dolomite Use Natural Gas Flaring Lime Manufacture Ammonia Production and Urea Application Waste Combustion Cement Manufacture Iron and Steel Production

Fossil Fuel Combustion

Tg CO 2 Eq CO 2 as a Portion of all Emissions

84.7% CO 2 CH 4 N 2 O

84.7% 7.9% 5.5% HFCs, PFCs & SF 6 2.0%Figure ES- 6 : 2003 CO 2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type

Figure ES- 7 : 2003 End-Use Sector Emissions of CO 2 from Fossil Fuel Combustion Note: Electricity generation also includes emissions of less than 1 Tg CO 2 Eq. from geothermal-based electricity generation.

0 200 400 600 800 1000 1200 1400 1600 1800 2000

Re

s i d

e n t ia

l
C o m

m

e r c i a l

I n d

u s t r i a l

T r a n s p o r t a t i o n

U

. S

. T e r r i t o r ie

sTg CO2Eq From Electricity Consumption From Direct Fossil Fuel Combustion 0 500 1,000 1,500 2,000ResidentialCommercialIndustrialTransportationElectricityGenerationU.S.TerritoriesTg CO2Eq Natural Gas
Petroleum
Coal Relative Contribution by Fuel TypeFigure ES-8: 2003 Sources of CH 4

Figure ES-9: 2003 Sources of N 2 O 0 20 40 60 80 100 120 140 Silicon Carbide Production Agricultural Residue Burning

Iron and Steel Production Petrochemical Production Mobile Sources Abandoned Coal Mines Stationary Sources Rice Cultivation Petroleum Systems Wastewater Treatment

Manure Management Coal Mining Enteric Fermentation Natural Gas Systems Landfills

Tg CO 2 Eq. <0.05 CH 4 as a Portion of all Emissions

7.9%

<1.0 <1.0

0 10 20 30 40 50 60 70 Waste Combustion Agricultural Residue Burning N2O Product Usage Adipic Acid Stationary Sources Nitric Acid Human Sewage Manure Management Mobile Sources Agricultural Soil Management

Tg CO 2 Eq 253.5

N 2 O as a Portion of all Emissions
5.5%Figure ES-10: 2003 Sources of HFCs, PFCs, and SF 6

Fi g ure ES-11: U.S. Greenhouse Gas Emissions and Sinks b y Chapter/IPCC Secto r (2,000) (1,000) 0 1,000 2,000 3,000 4,000 5,000 6,000 7,00019901991199219931994199519961997199819992000200120022003Tg CO2Eq.
Energy

Land-Use Change and Forestry (sink) Industrial Processes Agriculture Waste

0 10 20 30 40 50 60 70 80 90 100 Magnesium Production and Processing Aluminum Production Semiconductor Manufacture HCFC-22 Production Electrical Transmission

and Distribution Substitution of Ozone Depleting Substances

Tg CO 2 Eq HFCs, PFCs, and SF 6 as a Portion of all Emissions 2.0%Fi g ure ES-12: 2003 U.S. Ener gy Consumption b y Ener gy Sourc e 39.1% Petroleum 22.5% Natural Gas

22.8% Coal 8.0% Nuclear 6.1% RenewableFigure ES-1 3 : Emissions Allocated to Economic Sectors Note: Does not include U.S. territories.

Figure ES-1 4 : Emissions with Electricity Distributed to Economic Sectors Note: Does not include U.S. territories. 0 500 1,000 1,500 2,000 2,50019901991199219931994199519961997199819992000200120022003Tg CO2Eq. Transportation Industrial

Residential

A griculture Commercial 0 500 1,000 1,500 2,000 2,500

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Year(Tg CO2Eq.) Transportation Electricity Generation

Industry

Residential A griculture

CommercialFi g ure ES-1 5 : U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product Emissions per $GDP Emissions per capita Population Real GDP

70 80 90 100 110 120 130 140 150

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Index (1990 = 100)Fi g ure ES-16: 2003 Ke y Sources - Tier 1 Level Assessmen t Note: For a complete discussion of the ke y source anal y sis see Annex 1. 0 200 400 600 800 1000 1200 1400 1600 1800 2000 N20 - Mobile Combustion: Road & Other CO2 - Cement Production CO2 - Iron and Steel Production CH4 - Fugitive Emissions from Coal Mining and Handling CO2 - Mobile Combustion: Marine Indirect N2O Emissions from Nitrogen Used in Agriculture Various - Substitutes for Ozone Depleting Substances CH4 - Enteric Fermentation in Domestic Livestock CO2 - Non-Energy Use of Fuels CH4 - Fugitive Emissions from Natural Gas Operations CH4 - Solid Waste Disposal Sites Direct N2O Emissions from Agricultural Soils CO2 - Mobile Combustion: Aviation CO2 - Stationary Combustion - Oil CO2 - Stationary Combustion - Gas CO2 - Mobile Combustion: Road & Other CO2 - Stationary Combustion - Coal

Tg CO 2 Eq.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 1 

## 1. Introduction

This report presents estimates by the United States government of U.S. anthropogenic greenhouse gas emissions and sinks for the years 1990 through 2003. A summary of these estimates is provided in Table 2-3 and Table 2-4 by gas and source category in the Trends in Greenhouse Gas Emissions chapter. The emission estimates in these tables are presented on both a full molecular mass basis and on a Global Warming Potential (GWP) weighted basis in order to show the relative contribution of each ga s to global average radiative forcing. 1 This report also discusses the methods and data used to calculate these emission estimates.

In June of 1992, the United States signed, and later ratif ied in October, the United Nations Framework Convention on Climate Change (UNFCCC). As stated in Article 2 of the UNFCCC, ‘The ultimate objective of the UNFCCC is to achieve...stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system . Such a level should be achieved within a time-frame sufficient to allow ecosystems to adapt naturally to climat e change, to ensure that food production is not threatened and to enable economic development to proceed in a sustainable manner.” 2,3

Parties to the Convention, by ratifying, “shall develop, periodically update, publish a nd make available...national inventories of anthropogenic emissions by sources and rem ovals by sinks of all greenhouse gases not controlled by the Montreal Protocol, using comparable methodologies...” 4 The United States views this report as an opportunity to fulfill these commitm ents under the UNFCCC.

In 1988, preceding the creation of the UNFCCC, the Worl d Meteorological Organiza tion (WMO) and the United Nations Environment Programme (UNEP) jointly estab lished the Intergovernmental Panel on Climate Change (IPCC). The charter of the IPCC is to assess available scientific information on climate change, assess the environmental and socio-economic impacts of climate change, and formulate response strategies (IPCC 1996). Under Working Group 1 of the IPCC, nearly 140 scientists and national experts from more than thirty countries collaborated in the creation of the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997) to ensure that the emissi on inventories submitted to the UNFCCC are consistent and comparable between nations. The IPCC accepted the Revised 1996 IPCC Guidelines at its Twelfth Session (Mexico City, 11-13 September 1996). Th is report presents information in accordance with these guidelines. In addition, this inventory is in accordance with the IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories , which further expanded upon the methodologies in the Revised 1996 IPCC Guidelines. The IPCC has also accepted the Good Practice Guidance for Land Use, Land-Use Change and Forestry at its Twenty-First Session (Vienna, November 3-7, 2003), as an elaboration of the Revised 1996 Guidelines. Overall, this inventory of anthropogenic greenhouse gas emissions provides a common and consistent mechanism through which Parties to the UNFCCC can estimate emissions and compare the relative contribution of individual sources, gases, and nations to climate change. The structure of this report is consistent with the current UNFCCC Guidelines on Reporting and Review (UNFCCC 2003).

1 See the section below entitled Global Warming Potentials for an explanation of GWP values. 2 The term “anthropogenic”, in this context, refers to greenhouse gas emissions and rem ovals that are a direct result of human activities or are the result of natural processes that have been affected by human activities (IPCC/UNEP/OECD/IEA 1997). 3 Article 2 of the Framework Conven tion on Climate Change published by th e UNEP/WMO Information Unit on Climate Change. See <http://unfccc.int>. (UNEP/WMO 2000) 4 Article 4(1)(a) of the United Nations Framework Convention on C limate Change (also identified in Article 12). Subsequent decisions by the Conference of the Parties elaborated the role of Annex I Parties in preparing national inventories. See <http://unfccc.int>.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 2 

### 1.1. Background Information

Greenhouse Gases

Although the Earth’s atmosphere consists mainly of oxy gen and nitrogen, neither plays a significant role in enhancing the greenhouse effect because both are essentially transparent to terrestrial radiation. The greenhouse effect is primarily a function of the concentration of water vapor, carbon dioxide (CO 2 ), and other trace gases in the atmosphere that absorb the terrestri al radiation leaving the surface of the Earth (IPCC 1996). Changes in the atmospheric concentrations of these greenhouse gases can alter the balance of energy transfers between the atmosphere, space, land, and the oceans. 5 A gauge of these changes is called radiative forcing, which is a simple measure of changes in the energy available to the Earth-atmosphere system (IPCC 1996). Holding everything else constant, increases in greenhouse gas concentrations in the atmosphere will produce positive radiative forcing (i.e., a net increase in the absorpti on of energy by the Earth).

Climate change can be driven by changes in the atmo spheric concentrations of a number of radiatively active gases and aerosols. We have clear evidence t hat human activities have affected concentrations, distributions and life cycles of these gases (IPCC 1996).

Naturally occurring greenhouse gases include water vapor, CO 2 , methane (CH 4 ), nitrous oxide (N 2 O), and ozone (O 3 ). Several classes of halogenated substances that c ontain fluorine, chlorine, or bromine are also greenhouse gases, but they are, for the most pa rt, solely a product of industrial activ ities. Chlorofluorocarbons (CFCs) and hydrochlorofluorocarbons (HCFCs) are halocarbons that contain chlorine, while halocarbons that contain bromine are referred to as bromofluorocarbons (i.e., halons). As stratospheric ozone depleting substances, CFCs, HCFCs, and halons are covered under the Montreal Protocol on Substances that Deplete the Ozone Layer . The UNFCCC defers to this earlier international treaty. Consequently, Parties are not required to include these gases in national greenhouse gas inventories. 6 Some other fluorine-containing halogenated substances—hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF 6 )—do not deplete stratospheric ozone but are potent greenhouse gases. These latter substances are addre ssed by the UNFCCC and accounted for in national greenhouse gas inventories.

There are also several gases that, although they do not have a commonly agreed upon direct radiative forcing effect, do influence the global radiation budget. These tropospheric gases include carbon monoxide (CO), nitrogen dioxide (NO 2 ), sulfur dioxide (SO 2 ), and tropospheric (ground level) O 3 . Tropospheric ozone is formed by two precursor pollutants, volatile organic compounds (VOCs) and nitrogen oxides (NO x ) in the presence of ultraviolet light (sunlight). Aerosols are extremely small particles or liquid droplets that are often composed of sulfur compounds, carbonaceous combustion products, crustal materials and other human induced pollutants. They can affect the absorptive characteristics of the atmosphere. Comparatively, however, the level of scientific understanding of aerosols is still very low (IPCC 2001).

Carbon dioxide, CH 4 , and N 2 O are continuously emitted to and removed fro m the atmosphere by natural processes on Earth. Anthropogenic activities, however, can cause a dditional quantities of these and other greenhouse gases to be emitted or sequestered, thereby changing their global average atmospheric concentrations. Natural activities such as respiration by plants or anim als and seasonal cycles of plant growth and decay are examples of processes that only cycle carbon or nitrogen between the atmosphere and organic biomass. Such processes, except when directly or indirectly pe rturbed out of equilibrium by anthropogenic activities, ge nerally do not alter average atmospheric greenhouse gas concentrations over decad al timeframes. Climatic changes resulting from anthropogenic activities, however, could have positive or ne gative feedback effects on these natural systems.

5 For more on the science of climate change, see NRC (2001). 6 Emissions estimates of CFCs, HCFCs, halons and other ozone-depleting substan ces are included in this document for informational purposes.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 3 Atmospheric concentrations of these gases, along with thei r rates of growth and atmospheric lifetimes, are presented in Table 1-1.

Table 1-1: Global atmospheric concentration (ppm unle ss otherwise specified), rate of concentration change (ppb/year) and atmospheric lifetime (years) of selected greenhouse gases Atmospheric Variable CO 2 CH 4 N 2 O SF 6 a CF 4 a Pre-industrial atmospheric

concentration 280 0.722 0.270 0 40 Atmospheric concentration b 372.3 1.729-1.843 c 0.317-0.318 c 4.7-4.8 80 Rate of concentration change d 1.5 e 0.007 e 0.0008 0.24 1.0 Atmospheric Lifetime 50-200 f 12 g 114 g 3,200 >50,000 Source: Current atmospheric concentrations for CO 2 , CH 4 , N 2 O, and SF 6 are from Blasing and Jones (2003). All other data is from IPCC (2001).

a Concentrations in parts per trillion (ppt) a nd rate of concentration change in ppt/year. b Concentration for SF 6 was measured in 2001; concentration for CF 4 was measured in 2000. Concentrations for all other gases were measured in 2002.

c The low and high endpoints of the range represent concentrations from Tasmania, a mid-latitude Southern-Hemisphere site, and Ireland, a mid-latitude Northern-Hemisphere site, respectively. d Rate is calculated over the period 1990 to 1999.

e Rate has fluctuated between 0.9 and 2.8 ppm per year for CO 2 and between 0 and 0.013 ppm per year for CH 4 over the period 1990 to 1999. f No single lifetime can be defined for CO 2 because of the different rates of uptake by different removal processes.

g This lifetime has been defined as an “a djustment time” that takes into account the indirect effect of the gas on its own resid ence time. A brief description of each greenhouse gas, its sources, a nd its role in the atmosphere is given below. The following section then explains the concept of GWPs, whic h are assigned to individual gases as a measure of their relative average global radiative forcing effect.

Water Vapor (H 2 O). Overall, the most abundant and dominant gree nhouse 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 seve ral physical states including gaseous, liquid, and solid. Human activities are not believed to affect directly the average global concentration of water vapor, but, the radiative forcing produced by the increased concentrati ons of other greenhouse gases may indirectly affect the hydrologic cycle. While a warmer atmo sphere has an increased water holding capacity, increased concentrations of water vapor affects the formation of clouds, which can both absorb and reflect solar and terrestrial radiation. Aircraft contrails, which consist of wate r vapor and other ai rcraft emittants, are similar to clouds in their radiative forcing effects (IPCC 1999).

Carbon Dioxide . In nature, carbon is cycled be tween various atmospheric, oceanic , land biotic, marine biotic, and mineral reservoirs. The largest fluxes occur between th e atmosphere and terrestrial biota, and between the atmosphere and surface water of the oceans. In the atmos phere, carbon predominantly exists in its oxidized form as CO 2 . Atmospheric CO 2 is part of this global carbon cycle, and therefore its fate is a complex function of geochemical and biological processes. Carbon dioxide concentrations in the atmosphere increased from approximately 280 parts per m illion by volume (ppmv) in pre-industrial times to 372.3 ppmv in 2001, a 33 percent increase (IPCC 2001 and Blasing and Jones 2004). 7 , 8 The IPCC definitively states that “the present atmospheric CO 2 increase is caused by anthropogenic emissions of CO 2 ” (IPCC 2001). The predominant source of anthropogenic CO 2 emissions is the combustion of fossil fuels. Forest clearing, other biomass burning, and some non-energy production processes (e.g., cement pr oduction) also emit notable quantities of CO 2 .

7 The pre-industrial period is considered as the time preceding the year 1750 (IPCC 2001). 8 Carbon dioxide concentrations during the last 1,000 years of the pre-industrial period (i.e., 750-1750), a time of relative cl imate stability, fluctuated by about ± 10 ppmv around 280 ppmv (IPCC 2001).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 4 In its second assessment, the IPCC also stated that “[t]he increased amount of carbon dioxide [in the atmosphere] is leading to climate change and will pr oduce, on average, a global warming of the Earth’s surface because of its enhanced greenhouse effect

⎯ although the magnitude and significance of the effects are not fully resolved” (IPCC 1996).

Methane . Methane is primarily produced th rough anaerobic decomposition of organi c matter in biological systems. Agricultural processes such as wetland rice cultivation, enteric fermentation in animals, and the decomposition of animal wastes emit CH 4 , as does the decomposition of municipal solid wastes. Methane is also emitted during the production and distribution of natural gas and petroleum, and is released as a by-product of coal mining and incomplete fossil fuel combustion. Atmospheric concentrations of CH 4 have increased by about 150 percent since pre-industrial times, although the rate of increase has been declining. The IPCC has estimated that slightly more than half of the current CH 4 flux to the atmosphere is anthropogenic, from human activities such as agriculture, fossil fuel use, and waste disposal (IPCC 2001).

Methane is removed from the atmosphere through a reacti on with the hydroxyl radical (OH) and is ultimately converted to CO 2 . Minor removal processes also include reaction with chlorine in the marine boundary layer, a soil sink, and stratospheric reactions. Increasing emissions of CH 4 reduce the concentration of OH, a feedback that may increase the atmospheric lifetime of CH 4 (IPCC 2001).

Nitrous Oxide . Anthropogenic sources of N 2 O emissions include agricultural soils, especially production of nitrogen-fixing crops and forages, the use of synthetic and manure fertilizers, and manure deposition by livestock; fossil fuel combustion, especially from mobile combustion; adipic (nylon) and nitric acid production; wastewater treatment and waste combustion; and biomass burning. The atmospheric concentration of N 2 O has increased by 17 percent since 1750, from a pre-industrial value of about 270 ppb to 314 ppb in 1998, a concentration that has not been exceeded during the last thousand years. Nitrous oxide is primarily removed from the atmosphere by the photolytic action of sunlight in the stratosphere (IPCC 2001).

Ozone . Ozone is present in both the upper stratosphere, 9 where it shields the Earth from harmful levels of ultraviolet radiation, and at lower concentrations in the troposphere, 10 where it is the main component of anthropogenic photochemical “smog.” During the last two decades, emissi ons of anthropogenic chlorine and bromine-containing halocarbons, such as CFCs, have deplet ed stratospheric ozone concentrations. This loss of ozone in the stratosphere has resulted in negative radiative forcing, representing an indirect effect of anthropogenic emissions of chlorine and bromine compounds (IPCC 1996). Th e depletion of stratospheric ozone and its radiative forcing was expected to reach a maximu m in about 2000 before starting to recove r, with detection of such recovery not expected to occur much before 2010 (IPCC 2001).

The past increase in tropospheric ozone, which is also a greenhouse gas, is estimated to provide the third largest increase in direct radiative forcing since the pre-industrial era, behind CO 2 and CH 4 . Tropospheric ozone is produced from complex chemical reactions of volatile organic compounds mixing with NO x in the presence of sunlight. Ozone, CO, SO 2 , nitrogen dioxide (NO 2 ) and particulate matter are include d in the category referred to as “ambient air pollutants” in the United States under the Clean Air Act 11 and its subsequent amendments. The tropospheric concentrations of ozone and these other pollutants are short-lived and, therefore, spatially variable.

9 The stratosphere is the layer from the troposphere up to roughly 50 kilometers. In the lower re gions the temperature is nearl y constant but in the upper layer the temperat ure increases rapidly because of sunlight absorption by the ozone layer. The ozone

layer is the part of the stratosphere from 19 kilometers up to 48 kilometers where the concentration of ozone reaches up to 10 parts per million. 10 The troposphere is the layer from the ground up to 11 kilometers n ear 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 pro cesses, including most of the water vapor and clouds. 11 [42 U.S.C § 7408, CAA § 108]Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 5 Halocarbons, Perfluorocarbons, and Sulfur Hexafluoride . Halocarbons are, for the most part, man-made chemicals that have both direct and indirect radiative forcing eff ects. Halocarbons that contain chlorine (CFCs, HCFCs, methyl chloroform, and carbon tetrachloride) and bromine (halons, methyl bromide, and hydrobromofluorocarbons (HBFCs)) result in stratospheric ozone depl etion and are therefore controlled under the Montreal Protocol on Substances that Deplete the Ozone Layer . Although CFCs and HCFCs include potent global warming gases, their net radiative forcing effect on the atmo sphere is reduced because they cause stratospheric ozone depletion, which itself is an important greenhouse gas in addition to shielding the Earth from harmful levels of ultraviolet radiation. Under the Montreal Protocol , the United States phased out the production and importation of halons by 1994 and of CFCs by 1996. Under the Copenhagen Amendments to the Protocol , a cap was placed on the production and importation of HCFCs by non-Article 5 12 countries beginning in 1996, and then followed by a complete phase-out by the year 2030. While ozone depleting gases covered under the Montreal Protocol and its Amendments are not covered by the UNFCCC; they are reported in this inventory under Annex 6.2 fo r informational purposes.

HFCs, PFCs, and SF 6 are not ozone depleting substances, and therefore are not covered under the Montreal Protocol . They are, however, powerful greenhouse gases. HFCs are primarily used as replacements for ozone depleting substances but also emitted as a by -product of the HCFC-22 manufacturing process . C urrently, they have a small aggregate radiative forcing impact, but it is anticipated that their contribution to overall radiative forcing will increase (IPCC 2001). PFCs and SF 6 are predominantly emitted from vari ous industrial processes including aluminum smelting, semiconductor manufacturing, electric power transmission and distribution, and magnesium casting. Currently, the radiative forcing impact of PFCs and SF 6 is also small, but they have a significant growth rate, extremely long atmospheric lifetimes, and are strong ab sorbers of infrared radiation, and therefore have the potential to influence climate far into the future (IPCC 2001).

Carbon Monoxide . Carbon monoxide has an indirect radiative forc ing effect by elevating concentrations of CH 4 and tropospheric ozone through chemical reactions with other atmospheric c onstituents (e.g., the hydroxyl radical, OH) that would otherwise assist in destroying CH 4 and tropospheric ozone. Carbon monoxide is created when carbon-containing fuels are burned incompletely. Through natural processes in the atmosphere, it is eventually oxidized to CO 2 . Carbon monoxide concentrations are both short-liv ed in the atmosphere and spatially variable.

Nitrogen Oxides . The primary climate change effects of nitrogen oxides (i.e., NO and NO 2 ) are indirect and result from their role in promoting the formation of ozone in the troposphere and, to a lesser degree, lower stratosphere, where it has positive radiative forcing effects. 13 Additionally, NO x emissions from aircraft are also likely to decrease CH 4 concentrations, thus having a negative radiativ e 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 N 2 O. Concentrations of NO x are both relatively short-lived in the atmosphere and spatially variable.

Nonmethane Volatile Organic Compounds (NMVOCs) . Nonmethane volatile organic compounds include substances such as propane, butane, and ethane. These compounds participate, along with NO x , in the formation of tropospheric ozone and other photochemical oxidants. NMVOCs are emitted primarily from transportation and industrial processes, as well as biomass burning a nd non-industrial consumption of organic solvents. Concentrations of NMVOCs tend to be both short-liv ed in the atmosphere and spatially variable.

Aerosols . Aerosols are extremely small particles or liquid droplets found in the atmosphere. They can be produced by natural events such as dust storms and volcanic activity , or by anthropogenic processes such as fuel combustion

12 Article 5 of the Montreal Protocol covers several groups of countries, especia lly developing countries, with low consumption rates of ozone depleting substances. De veloping countries with per capita consump tion of less than 0.3 kg of certain ozone depleting substances (weighted by their ozone depleting pot ential) receive financial assistance and a grace period of ten additional years in the phase-out of ozone depleting substances. 13 NO x emissions injected higher in the stratosphere, primarily from fuel combustion emissions from high altitude supersonic aircraft, can lead to stratospheric ozone depletion.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 6 and biomass burning. Aerosols affect radiative forcing di fferently than greenhouse gases, and their radiative effects occur through direct and indirect mechanisms: directly by s cattering and absorbing solar radiation; and indirectly by increasing droplet counts that modify the formation, precipitation efficiency, and radiative properties of clouds. Aerosols are removed from the atmosphere relatively rapi dly by precipitation. Becau se aerosols generally have short atmospheric lifetimes, and have concentrations and compositions that vary regionally, spatially, and temporally, their contributions to radiative forcing are difficult to quantify (IPCC 2001).

The indirect radiative forcing from aerosols is typically divided into two effects. The first effect involves decreased droplet size and increased droplet concentration resulting fro m an increase in airborne aerosols. The second effect involves an increase in the water content and lifetime of clouds due to the effect of reduced droplet size on precipitation efficiency (IPCC 2001). R ecent research has placed a greater fo cus on the second indirect radiative forcing effect of aerosols.

Various categories of aerosols exist, including naturally produced aerosols such as soil dust, sea salt, biogenic aerosols, sulfates, and volcanic aerosols, and anthropogeni cally manufactured aerosols such as industrial dust and carbonaceous 14 aerosols (e.g., black carbon, organic carbon) from transportation, coal combustion, cement manufacturing, waste incineration, and biomass burning.

The net effect of aerosols on radiative forcing is believed to be negative (i.e., net cooling effect on the climate), although because they remain in the at mosphere for only days to weeks, th eir concentrations respond rapidly to changes in emissions. 15 Locally, the negative radiative forcing effects of aerosols can offset the positive forcing of greenhouse gases (IPCC 1996). “However, the aerosol effects do not cancel the global-scale effects of the much longer-lived greenhouse gases, a nd significant climate changes can still result” (IPCC 1996).

The IPCC’s Third Assessment Report notes that “the indirect radiative effect of aerosols is now understood to also encompass effects on ice and mixed-phase clouds, but the magnitude of any such indirect effect is not known, although it is likely to be positive” (IPCC 2001). Additionally, current research suggests th at another constituent of aerosols, black carbon, may have a positive radiative fo rcing (Jacobson 2001). The pr imary anthropogenic emission sources of black carbon include diesel exhaust and open biomass burning. 

### Global Warming Potentials

A GWP is a quantified measure of the globally averaged relative radiative forcing impacts of a particular greenhouse gas (see Table 1-2). It is defined as the ra tio of the time-integrated radiative forcing from the instantaneous release of 1 kg of a trace substance relative to that of 1 kg of a reference gas (IPCC 2001). Direct radiative effects occur when the gas its elf absorbs radiation. Indirect radiative forci ng occurs when chemical transformations involving the original gas produces a gas or gases that are greenhouse gases, or when a gas influences other radiatively important processes such as th e atmospheric lifetimes of other gases. The reference gas used is CO 2 , and therefore GWP weighted emissions are measured in teragrams of CO 2 equivalent (Tg CO 2 Eq.) 16 The relationship between gigagrams (Gg) of a gas and Tg CO 2 Eq. can be expressed as follows:


# ( )( ) ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× × = Gg 1,000 Tg GWP gas of Gg Eq CO Tg 2

where,

14 Carbonaceous aerosols are aerosols that are comprised mainly of organic substances and forms of black carbon (or soot) (IPCC 2001). 15 Volcanic activity can inject significant quantities of aerosol producing sulfur dioxide and other sulfur compounds into the stratosphere, which can result in a longer negativ e forcing effect (i.e., a few years) (IPCC 1996). 16 Carbon comprises 12/44 ths of carbon dioxide by weight.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 7 Tg CO 2 Eq. = Teragrams of Carbon Dioxide Equivalent Gg = Gigagrams (equivalent to a thousand metric tons) GWP = Global Warming Potential Tg = Teragrams GWP values allow for a comparison of the impacts of emissi ons and reductions of different gases. According to the IPCC, GWPs typically have an uncertainty of ± 35 percent. The parties to the UNFCCC have also agreed to use GWPs based upon a 100-year time horizon although other time horizon values are available.

Greenhouse gas emissions and removals should be presented on a gas-by-gas basis in units of mass... In addition, consistent with decision 2/CP.3, Parties should report aggregate emissions and removals of greenhouse gases, expressed in CO 2 equivalent terms at summary in ventory level, using GWP values provided by the IPCC in its Second Assessment Repor t... based on the effects of greenhouse gases over a 100-year time horizon. 17

Greenhouse gases with relatively long atmospheric lifetimes (e.g., CO 2 , CH 4 , N 2 O, HFCs, PFCs, and SF 6 ) tend to be evenly distributed throughout the atmosphere, and consequen tly global average concentrations can be determined. The short-lived gases such as water vapor, carbon monoxide, tropospheric ozone, ozone precursors (e.g., NO x , and NMVOCs), and tropospheric aerosols (e.g., SO 2 products and carbonaceous partic les), however, vary regionally, and consequently it is difficult to quantify their global radiative forcing impacts. No GWP values are attributed to these gases that are short-lived and spatially inhomogeneous in the atmosphere.

Table 1-2: Global Warming Potentials and Atmospheric Lifetimes (Years) Used in this Report Gas Atmospheric Lifetime GWP a CO 2 50-200 1 CH 4 b 12 ± 3 21 N 2 O 120 310 HFC-23 264 11,700 HFC-32 5.6 650 HFC-125 32.6 2,800 HFC-134a 14.6 1,300 HFC-143a 48.3 3,800 HFC-152a 1.5 140 HFC-227ea 36.5 2,900 HFC-236fa 209 6,300 HFC-4310mee 17.1 1,300 CF 4 50,000 6,500 C 2 F 6 10,000 9,200 C 4 F 10 2,600 7,000 C 6 F 14 3,200 7,400 SF 6 3,200 23,900 Source: (IPCC 1996)

a 100-year time horizon
b The GWP of CH 4 includes the direct effects and those indirect e ffects due to the production of tropospheric ozone and stratospheric water vapor. The indirect effect due to the production of CO 2 is not included.

17 Framework Convention on Climate Change; <http://unfccc.int/r esource/docs/cop8/08.pdf>; 1 November 2002; Report of the Conference of the Parties at its eighth session; held at New Delhi from 23 October to 1 Nove mber 2002; Addendum; Part One: Action taken by the Conference of the Parties at its eighth se ssion; Decision -/CP.8; Communica tions from Parties included in Annex I to the Convention: Guidelines for the Preparation of National Communications by Parties Included in Annex I to the Convention, Part 1: UNFCCC reporting guidelines on annual inventories; p. 7. (UNFCCC 2003)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 8 [Begin Box]

Box 1-1: The IPCC Third Assessment Report and Global Warming Potentials In 2001, the IPCC published its Third Assessment Report (TAR), which provided an updated and more comprehensive scientific assessment of climate change. Within this report, the GWPs of several gases were revised relative to the IPCC’s Second Assessment Report (SAR), a nd new GWPs have been calculated for an expanded set of gases. Since the SAR, the IPCC has applied an improved calculation of CO 2 radiative forcing and an improved CO 2 response function (presented in WMO 1999). The GWPs are drawn from WMO (1999) and the SAR, with updates for those cases where significantly different new laboratory or radiative transfer results have been published. Additionally, the atmospheric lifetimes of some gases have been recalculated. Because the revised radiative forcing of CO 2 is about 12 percent lower than that in the SAR, the GWPs of the other gases relative to CO 2 tend to be larger, taking into account re visions in lifetimes. In addition, the values for radiative forcing and lifetimes have been calculated for a variety of halocar bons, which were not presented in the SAR. Table 1-3 presents the new GWPs, relative to those presented in the SAR.

Table 1-3: Comparison of 100 Year GWPs Gas SAR TAR Change CO 2 1 1 NC NC CH 4 * 21 23 2 10% N 2 O 310 296 (14) (5%) HFC-23 11,700 12,000 300 3% HFC-32 650 550 (100) (15%) HFC-125 2,800 3,400 600 21% HFC-134a 1,300 1,300 NC NC HFC-143a 3,800 4,300 500 13% HFC-152a 140 120 (20) (14%) HFC-227ea 2,900 3,500 600 21% HFC-236fa 6,300 9,400 3,100 49% HFC-4310mee 1,300 1,500 200 15% CF 4 6,500 5,700 (800) (12%) C 2 F 6 9,200 11,900 2,700 29% C 4 F 10 7,000 8,600 1,600 23% C 6 F 14 7,400 9,000 1,600 22% SF 6 23,900 22,200 (1,700) (7%) Source: (IPCC 2001) NC (No Change) Note: Parentheses indicate negative values.

* The GWP of CH 4 includes the direct effects and those indirect e ffects due to the production of tropospheric ozone and stratospheric water vapor. The indirect effect due to the production of CO 2 is not included.

To comply with international repor ting standards under the UNFCCC, official emission estimates are reported by the United States using SAR GWP values. The UNFCCC reporting guidelines for national inventories 18 were updated in 2002 but continue to require the use of GWPs from the SAR so that current estimates of aggregate greenhouse gas emissions for 1990 through 2003 are consistent and comparable with estimates developed prior to the publication of the TAR. For informational purposes, emission estimates that use the updated GWPs are presented below and in even more detail in Annex 6.1. Overall, these revisions to GWP values do not have a significant effect on U.S. emission trends, as shown in Table 1-4. All estimates provided throughout this report are also presented in unweighted units.

18 See <http://unfccc.int/resource/docs/cop8/08.pdf>.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 9 Table 1-4: Effects on U.S. Greenhouse Gas Emission Trends Using IPCC SAR and TAR GWP Values (Tg CO 2 Eq.) Change from 1990 to 2003 Revi sions to Annual Estimates Gas SAR TAR 1990 2003 CO 2 832.0 832.0 0 0 CH 4 (60.4) (66.1) 57.7 51.9 N 2 O (5.2) (5.0) (17.3) (17.0) HFCs, PFCs, and SF 6 45.8 45.5 (2.7) (2.9) Total 812.1 806.3 37.7 31.9 Percent Change 13.3% 13.2% 0.6% 0.5% Note: Parentheses indicate negative values. To tals may not sum due to independent rounding.

Table 1-5 below shows a comparison of total emission estimates by sector using both the IPCC SAR and TAR GWP values. For most sectors, the change in emissions was minimal. The effect on emissions from waste was by far the greatest (8.3 percent in 2003), due the predominance of CH 4 emissions in this sector. Emissions from all other sectors were comprised of mainly CO 2 or a mix of gases, which moderated the effect of the changes.

Table 1-5: Comparison of Emissions by Sector using IPCC SAR and TAR GWP Values (Tg CO 2 Eq.) Sector 1990 1997 1998 1999 2000 2001 2002 2003 Energy

SAR GWP (Used In Inventory) 5,141.7 5,712.8 5,737.3 5,802.6 5,985.3 5,877.3 5,920.7 5,963.4 TAR GWP 5,162.9 5,732.0 5,756.6 5,820.7 6,003.7 5,895.6 5,938.6 5,981.1 Difference (%) 0.4% 0.3% 0.3% 0.3% 0.3% 0.3% 0.3% 0.3% Industrial Processes

SAR GWP (Used In Inventory) 299.9 327.1 334.9 329.2 332.1 304.7 315.4 308.6 TAR GWP 296.0 323.3 332.0 325.7 328.4 301.2 311.8 304.9 Difference (%) (1.3%) (1.1%) (0.9%) (1.1%) (1.1%) (1.1%) (1.1%) (1.2%) Solvent and Other Product Use

SAR GWP (Used In Inventory) 4.3 4.8 4.8 4.8 4.8 4.8 4.8 4.8 TAR GWP 4.1 4.6 4.6 4.6 4.6 4.6 4.6 4.6 Difference (%) (4.5%) (4.5%) (4.5%) (4.5%) (4.5%) (4.5%) (4.5%) (4.5%) Agriculture

SAR GWP (Used In Inventory) 426.5 432.8 449.8 425.9 444.1 437.5 432.4 433.3 TAR GWP 429.2 436.1 452.6 429.7 446.8 440.4 435.6 436.4 Difference (%) 0.6% 0.8% 0.6% 0.9% 0.6% 0.7% 0.7% 0.7% Land-Use Change and Forestry

SAR GWP (Used In Inventory) (1,036.5) (923.6) (874.5) (819.5) (816.1) (820.7) (820.1) (821.6) TAR GWP (1,036.7) (923.9) (874.8) (819.8) (816.4) (821.0) (820.4) (821.9) Difference (%) + + + + + + + + Waste

SAR GWP (Used In Inventory) 210.1 193.7 186.0 183.1 180.6 176.5 178.3 183.8 TAR GWP 228.3 210.1 201.6 198.4 195.6 191.1 193.1 199.1 Difference (%) 8.7% 8.5% 8.4% 8.3% 8.3% 8.3% 8.3% 8.3% Net Emissions (Sources and Sinks)

SAR GWP (Used In Inventory) 5,046.1 5,747.5 5,838.8 5,926.1 6,130.8 5,980.1 6,031.6 6,072.2 TAR GWP 5,083.8 5,782.2 5,872.6 5,959.2 6,162.6 6,012.0 6,063.2 6,104.1 Difference (%) 0.7% 0.6% 0.6% 0.6% 0.5% 0.5% 0.5% 0.5% NC (No change) + Less than 0.05%. Note: Parentheses indicate negative values. To tals may not sum due to independent rounding. [End Box]Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 10 

### 1.2. Institutional Arrangements

The U.S. Environmental Protection Agency (EPA), in c ooperation with other U.S. government agencies, prepares the Inventory of U.S. Greenhouse Gas Emissions and Sinks. A wide range of agencies and individuals are involved in supplying data to, reviewing, or preparing portions of the U.S. Inventory—including federal and state government authorities, research and academic institutions, industry associ ations, and private consultants.

Within EPA, the Office of Atmospheric Programs (OAP) is the lead office responsible for the emission calculations provided in the Inventory, as well as the completion of the National Inventory Report and the Common Reporting Format tables. The Office of Transpor tation and Air Quality (OTAQ) is also involved in calcula ting emissions for the Inventory. While the U.S. Depart ment of State officially submits th e annual Inventory to the UNFCCC, EPA’s OAP serves as the focal point for tec hnical questions and comments on the U.S. Inventory. The staff of OAP and OTAQ coordinates the annual methodological choice, activity data collection, and emission calculations at the individual source category level. Within OAP, an Inventory coordinator compiles the entire Inventory into the proper reporting format for s ubmission to the UNFCCC, and is responsible for the collection and consistency of cross-cutting issues in the Inventory.

Several other government agencies contribute to the collec tion and analysis of the underlying activity data used in the Inventory calculations. Formal relationships exist between EPA and other U.S. agencies that provide official data for use in the Inventory. The U.S. Department of Energy’s Energy Information Administration provides national fuel consumption data and th e U.S. Department of Defense provide s military fuel consumption and bunker fuels. Informal relationships also exist with other U.S. agencies to provide activity data for use in EPA’s emission calculations. These include: the U.S. Department of Agriculture, the U.S. Geological Survey, the Federal Highway Administration, the Department of Transportation, the Bureau of Transportation Statistics, the Department of Commerce, the National Agricultural Statistics Service, and the Federal Aviation Administration. Academic and research centers also provide activity data and calculations to EPA, as well as individual companies participating in voluntary outreach efforts with EPA. Fi nally, the U.S. Department of State o fficially submits the Inventory to the UNFCCC each April.



### 1.3. Inventory Process

EPA has a decentralized approach to pr eparing the annual U.S. Inventory, wh ich consists of a National Inventory Report (NIR) and Common Reporting Format (CRF) tables. The Inventory coordinator at EPA is responsible for compiling all emission estimates, and ensuring consiste ncy and quality throughout the NIR and CRF tables. Emission calculations for indi vidual sources are the responsibility of indi vidual source leads, who are most familiar with each source category and the unique characteristics of its emissions profile. The individual source leads determine the most appropriate methodology and collect the best activity data to use in the emission calculations, based upon their expertise in the source category, as well as coordinating with research ers and contractors familiar with the sources. A multi-stage pro cess for collecting information from th e individual source leads and producing the Inventory is undertaken annually to compile all information and data. 

### Methodology Development, Data Collecti on, and Emissions and Sink Estimation

Source leads at EPA collect input data and, as necessary, evaluate or de velop the estimation methodology for the individual source categories. For most source categories, the methodology for the previous year is applied to the new “current” year of the Inventory, and Inventory analysts collect any new data or update data that have changed from the previous year. If estimates for a new source cate gory are being developed for the first time, or if the methodology is changing for an existing source category (e.g., the United States is implementing a higher Tiered approach for that source category), th en the source category lead will devel op a new methodology, gather the most appropriate activity data and emission factors (or in some cases direct emission measurements) for the entire time series, and conduct a special source-specific peer revi ew process involving relevant experts from industry, government, and universities.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 11 Once the methodology is in place and the data are collected , the individual source leads calculate emissions and sink estimates. The source leads then update or create the relevant text and acco mpanying annexes for the Inventory. Source leads are also responsible for completing the relevant sectoral background tables of the Common Reporting Format, conducting quality assurance and quality control (QA/QC) check s, and uncertainty analyses. 

### Summary Spreadsheet Compilation and Data Storage

The Inventory coordinator at EPA collects the source categorie s’ descriptive text and Annexes, and also aggregates the emission estimates into a summary spreadsheet that links the individual source category spreadsheets together. This summary sheet contains all of the essential data in one central location, in formats commonly used in the Inventory document. In addition to the data from each s ource category, national trend and related data is also gathered in the summary sheet for us e in the Executive Summary, Introduction, and Recent Trends sections of the Inventory report. Electronic copies of each year’s summary spreadsheet, wh ich contains all the emission and sink estimates for the United States, are kept on a central server at EPA under the jurisdiction of the Inventory coordinator.


### National Inventory Report Preparation

The NIR is compiled from the sections developed by each individual source lead. In addition, the Inventory coordinator prepares a brief overview of each chapter that summarizes the em issions from all sources discussed in the chapters. The Inventory coordinator then carries out a key source analysis for the Inventory, consistent with the IPCC Good Practice Guidance , IPCC Good Practice Guidance for Land Use, Land Use Change and Forestry , and in accordance with the reporting requirements of the UNF CCC. Also at this time, the Introduction, Executive Summary, and Recent Trends sections are drafted, to refl ect the trends for the most recent year of the current Inventory. The analysis of trends necessitates gathering supplemental data, including weather and temperature conditions, economic activity and gross domestic product, population, atmospheric conditions, and the annual consumption of electricity, energy, and fossil fuels. Changes in these data are used to explain the trends observed in greenhouse gas emissions in the United States. Furthermore, specific factors that affect individual sectors are researched and discussed. Many of the factors that affect emissions are included in the Inventory document as separate analyses or side discussions in boxes within the text. Text boxes are also created to examine the data aggregated in different ways than in the remainder of the document, such as a focus on transportation activities or emissions from electricity generation. The document is prepared to match the specification of the UNFCCC reporting guidelines for National Inventory Reports. 

### Common Reporting Format Table Compilation

The CRF tables are compiled from individual tables comple ted by each individual source lead, which contain source emissions and activity data. The Inventory coordinator integrates the source data into the complete CRF tables for the United States, assuring consistency across all sectoral tables. The summary reports for emissions, methods, and emission factors used, the overview tabl es for completeness and quality of es timates, the recalculation tables, the notation key completion tables, and the emission trends tabl es are then completed by the Inventory coordinator. Internal automated quality checks on the CRF tables, as well as reviews by the source leads, are completed for the entire time series of CRF tables before submission. 

### QA/QC and Uncertainty

QA/QC and uncertainty analyses are supervised by the QA/QC coordinator, who has general oversight over the implementation of the QA/QC plan and the overall uncertainty analysis for the Inventory (see sections on QA/QC and Uncertainty, below). The QA/QC coordinator works cl osely with the source leads to ensure a consistent QA/QC plan and uncertainty analysis is implemented across all inventory sources. The inventory QA/QC plan, detailed in a following section, is consistent with the quality assurance procedures outlined by EPA.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 12 

### Expert and Public Review Periods

During the Expert Review period, a first draft of the document is sent to a select list of technical experts outside of EPA. The purpose of the Expert Review is to encourage feedback on the methodological and data sources used in the current Inventory, especially for sources which have experienced any changes since the previous Inventory.

Once comments are received and addressed, a second draft of the document is released for public review by publishing a notice in the U.S. Federal Register and posting the document on the EPA Web site. The Public Review period allows for a 30 day comment period and is open to the entire U.S. public. 

### Final Submittal to UNFCCC and Document Printing

After the final revisions to incorporate any comments from the Expert Review and Public Review periods, EPA prepares the final National Inventory Report and the accompanying Common Reporting Format Tables. The U.S. Department of State sends the official submission of the U.S. Inventory to the UNFCCC. The document is then formatted for printing, posted online, printed by the U.S. Government Printing Office, and made available for the general public.



### 1.4. Methodology and Data Sources

Emissions of greenhouse gases from various source and si nk categories have been estimated using methodologies that are consistent with the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997). To the extent possible, the present report relies on published activity and emission factor data. Depending on the emission source category, activ ity data can include fuel consumption or deliveries, vehicle-miles traveled, raw material processed, etc. Emi ssion factors are factors that relate quantities of emissions to an activity.

The IPCC methodologies provided in the Revised 1996 IPCC Guidelines represent baseline methodologies for a variety of source categories, and many of these methodologies continue to be improved a nd refined as new research and data become available. This report uses the IPCC methodologies when applicable, and supplements them with other available methodologies and data where possible. Choices made regarding the methodologies and data sources used are provided in conjunction with the discussion of each source categor y in the main body of the report. Complete documentation is provided in the annexes on the detailed methodologies and data sources utilized in the calculation of each source category.

[Begin Text Box]

Box 1-2: IPCC Good Practice Guidance In response to a request by Parties in 1998 to the United Nations Framework Convention on Climate Change (UNFCCC), the Intergovernmental Panel on Climate Change (IPCC) prepared and published a report on inventory good practice. The report, entitled Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC Good Practice Guidance), was developed with extensive participation of experts from the United States and many other countries. 19 It focuses on providing direction to countries to produce emission estimates that are as accurate and tran sparent as possible, with the least po ssible uncertainty. In addition, the IPCC Good Practice Guidance was designed as a tool to complement the methodologies suggested in the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC Guidelines)

.

19 See <http://www.ipcc-nggip.iges .or.jp/public/gp/gpgaum.htm>Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 13 In order to obtain these goals, IPCC Good Practice Guidance gives specific guidance in the following areas:

• Selection of the most appropriate estimation method, within the context of the IPCC Guidelines

• Implementation of quality control and quality assurance measures

• Proper assessment and documentation of data and information

• Quantification of uncertainties for most source categories By providing such direction, the IPCC hopes to help countries provide inventories that are transparent, documented, and comparable.

In addition, the IPCC accepted the Land Use, Land-Use Change, and Forestry (LULUCF) Good Practice Guidance report in 2003, and the United States has implemented the new guidance in this Inventory submission.

[End Box]

The UNFCCC reporting guidelines require c ountries to complete a "top-down" reference approach for estimating CO 2 emissions from fossil fuel combustion in addition to their “bottom-up” sectoral methodology. This estimation method uses alternative methodologies and different data sources than those contained in that section of the Energy chapter. The reference approach estimates fossil fuel consumption by adjusting national aggregate fuel production data for imports, exports, and stock changes rather than relying on end-user consumption surveys (see Annex 4). The reference approach assumes that once carbon-based fuel s are brought into a national economy, they are either saved in some way (e.g., stored in products, kept in fuel stocks, or left unoxidized in ash) or combusted, and therefore the carbon in them is oxidized and released into the atmosphere. Accounting for actual consumption of fuels at the sectoral or sub-national level is not required.



### 1.5. Key Sourc es

The IPCC’s Good Practice Guidance (IPCC 2000) defines a key source category as a “[source category] that is prioritized within the national inventor y system because its estimate has a si gnificant influence on a country’s total inventory of direct greenhouse gases in terms of the absolute level of emissions, the trend in emissions, or both.” 20 By definition, key source categories include those sources that have the greatest contribution to the absolute level of national emissions. In addition, when an entire time series of emission estimates is prepared, a thorough investigation of key source categories must also account for the influence of trends of individual source categories. Therefore, a trend assessment is conducted to identify source categories for which significant uncertainty in the estimate would have considerable effects on overall emission trends. This analysis culls out source categories that diverge from the overall trend in national emissions. Finally, a qualitative evaluation of key source categories is performed to capture any categories that were not identified in either of the quantitative analyses.

A Tier 1 approach, as defined in the IPCC’s Good Practice Guidance (IPCC 2000), was implemented to identify the key source categories for the United States. Using this a pproach, a number of key source categories were identified based on an assessment of their absolute emission level and/or trend in emissions.

Due to the relative quantity of CO 2 emissions from fossil fuel combustion—particularly from mobile combustion in road vehicles and stationary combustion of coal, gas, and oil—these sources contributed most to this year’s level assessment. Additionally, the following sources were identified as key sources based on the level assessments for each year (listed in descending order of their 2003 emissions):

20 See chapter 7 “Methodological Choice and Recalculation” in IPCC (2000). < http://www.ipcc-nggip.iges.o r.jp/public/gp/gpgaum.htm>Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 14 • CO 2 emissions from mobile combustion in the aviation sector;

• Direct N 2 O from agricultural soils;

• CH 4 from solid waste disposal sites;

• Fugitive emissions from natural gas operations;

• CO 2 from non-energy use of fuel;

• CH 4 from enteric fermentation in domestic livestock;

• Indirect N 2 O emissions from nitrogen used in agriculture;

• Fugitive emissions from coal mining;

• CO 2 emissions from iron and steel production;

• CO 2 emissions from cement production; and

• N 2 O emissions from mobile combustion in road vehicles.

The remaining key sources identified under the level assessment varied by year. The following five source categories were determined to be key using the level assessment for only part of the complete time series (listed in descending order of their 2003 emissions):

• HFC and PFC emissions from substitutes fo r ozone depleting s ubstances (1996-2003);

• CO 2 emissions from mobile combustion in the marine sector (1990-1997, 1999-2003);

• CH 4 emissions from manure management (1990-2000);

• CH 4 emissions from wastewater handling (1995 and 1997); and

• HFC-23 emissions from HCFC-22 manufacture (1990-1996, 1998).

Although other sources have fluctuated by greater percentages since 1990, by virtue of their size, CO 2 emissions from mobile combustion from road vehicles and stationary combustion of coal are the greatest contributors to the overall trend for 2003. The third largest contributor to the overall trend in 2003 is emissions from substitutes for ozone depleting substances (ODSs). These emissions ha ve grown quickly with the phase out of ODSs under the Montreal Protocol.

Two additional source categories with trends of note are fugitive emissions from coal mining and PFC emissions from aluminum manufacturing, which decreased from 1990 through 2003 by approximately 34 and 79 percent, respectively. Reductions in emissions from coal mining are primarily due to EPA’s voluntary coalbed methane capture program and the mining of less gassy coal than in previous years. PFC emissions have decreased primarily as a result of emission reduction activ ities by the aluminum industry.

The remaining source categories that were identified as key sources based solely on a trend assessment are listed below (listed in descending order of their 2003 emissions).

• CO 2 emissions from waste incineration;

• Fugitive emissions from oil operations;

• CO 2 emissions from ammonia production and urea application;

• SF 6 emissions from elect rical equipment; and

• N 2 O emissions from adipic acid production.

In addition to conducting Tier 1 level and trend assessments, a qualitative assessment of the source categories, as described in the IPCC’s Good Practice Guidance (IPCC 2000), was conducted to capture any key sources that wereInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 15 not identified by either quantitative method. One additional key source was identified using this qualitative assessment. A brief discussion of the reasoning for the qualitative designation is provided below.

• International bunker fuels are fuels consumed for aviati on or marine international transport activities, and emissions from these fuels are reporte d separately from totals in accord ance with IPCC guidelines. If these emissions were included in the to tals, bunker fuels would qualify as a key source according to the Tier 1 approach. The amount of uncertainty associated with estimation of emissions from international bunker fuels also supports the qualification of this source category as key.

Table 1-6 presents the key source categories for the United States based on the Tier 1 approach using emissions data in this report, and ranked according to their sector and global warming potential-weighted emissions in 2003. The table also indicates the criteria used in identifying these source categories (i.e., level, trend, and/or qualitative assessments). Please see Annex 1 for additional inform ation regarding the key source categories in the United States and the methodologies used to identify them.

Table 1-6: Key Source Categories for the United States (1990-2003) Based on Tier 1 Approach

IPCC Source Categories Gas Level Trend Qual a 2003 Emissions (Tg CO 2 Eq.) Energy

CO 2 Emissions from Stationary Combustion - Coal CO 2 ✓ ✓ 2,013.8 Mobile Combustion: Road & Other CO 2 ✓ ✓ 1,538.5 CO 2 Emissions from Stationary Combustion - Gas CO 2 ✓ ✓ 1,134.9 CO 2 Emissions from Stationary Combustion - Oil CO 2 ✓ ✓ 635.3 Mobile Combustion: Aviation CO 2 ✓ ✓ 171.3 Fugitive Emissions from Natural Gas Operations CH 4 ✓ ✓ 125.9 CO 2 Emissions from Non-Energy Use of Fuels CO 2 ✓ 118.0 International Bunker Fuels b Several ✓ 85.1 Mobile Combustion: Marine CO 2 ✓ 57.5 Fugitive Emissions from Coal Mining and Handling CH 4 ✓ ✓ 53.8 Mobile Combustion: Road & Other N 2 O ✓ ✓ 39.9 Fugitive Emissions from Oil Operations CH 4 ✓ 17.1 Industrial Processes

Emissions from Substitutes for Ozone Depleting Substances Several ✓ ✓ 99.5 CO 2 Emissions from Iron and Steel Production CO 2 ✓ ✓ 53.8 CO 2 Emissions from Cement Production CO 2 ✓ ✓ 43.0 CO 2 Emissions from Ammonia Production and Urea

Application CO 2 ✓ 15.6 SF 6 Emissions from Electrical Equipment SF 6 ✓ 14.1 HFC-23 Emissions from HCFC-22 Manufacture HFCs ✓ ✓ 12.3
N 2 O Emissions from Adipic Acid Production N 2 O ✓ 6.0 PFC Emissions from Aluminum Production PFCs ✓ 3.8 Agriculture

Direct N 2 O Emissions from Agricultural Soils N 2 O ✓ 155.3 CH 4 Emissions from Enteric Fermentation in Domestic

Livestock CH 4 ✓ ✓ 115.0 Indirect N 2 O Emissions from Nitrogen Used in Agriculture N 2 O ✓ ✓ 98.2 CH 4 Emissions from Manure Management CH 4 ✓ 39.1 Waste

CH 4 Emissions from Solid Waste Disposal Sites CH 4 ✓ ✓ 131.2 CH 4 Emissions from Wastewater Handling CH 4 ✓ ✓ 36.8Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 16 CO 2 Emissions from Waste Incineration CO 2 ✓ 18.8 Subtotal of Key Source Emissions 6,833.5 Total Emissions 6,900.2 Percent of Total 99.0%

a Qualitative criteria. b Emissions from these sources not included in totals. Note: Sinks (e.g., LUCF, Landfill Carbon Storag e) are not included in this analysis. The Tier 1 approach for identifying key source categories does not directly include an assessment of uncertainty in emission estimates. 

### 1.6. Quality Assurance and Quality Control

As part of efforts to achieve its stated goals for inve ntory quality, transparency, and credibility, the United States has developed a quality assurance and quality control plan designed to check, document and improve the quality of its inventory over time. QA/QC activities on the Inventor y are undertaken within th e framework of the U.S. QA/QC plan, Quality Assurance/Quality Cont rol and Uncertainty Management Plan for the U.S. Greenhouse Gas Inventory: Procedures Manual for QA/QC and Uncertainty Analysis

. In particular, key attributes of the QA/QC plan include:

• The plan includes specific detailed procedures (or protocol s) and templates (or forms) that serve to standardize the process of documenting and archiving information, as well as to guide the implementation of QA/QC and the analysis of the uncertainty of the inventory estimates.

• The plan includes expert review as well as QC—for bot h the inventory estimates and the Inventory (which is the primary vehicle for disseminating the results of the inventory development process). In addition, the plan provides for public review of the Inventory.

• The QC process includes both Tier 1 (general) and Tier 2 (source-specific) quality controls and checks, as recommended by IPCC Good Practice Guidance.

• Investigations of secondary data quality and source-specific quality check s (Tier 2 QC) are considered in parallel and coordination with the uncertainty assessmen t; the development of protocols and templates provides for more structured communication and integration with the suppliers of secondary information.

• The plan contains record-keeping provisions to track what procedures have been followed, and the results of the QA/QC and uncertainty analysis, and contains feedback mechanisms for corrective action based on the results of the investigations, thereby providing for continual data quality improvement and guided research efforts.

• The plan is designed so that QA/QC procedures are implemented throughout the whole inventory development process—from initial data collection, through preparation of the emissi on estimates, to publication of the Inventory.

• The plan includes a schedule for multi-year implementation.

• The plan promotes and involves coordination and inter action within the EPA, across Federal agencies and departments, state government programs, and research institutions a nd consulting firms i nvolved in supplying data or preparing estimates for the inventory. The QA/QC plan itself is intended to be revised and reflect new information that becomes available as the program de velops, methods are improve d, or additional supporting documents become necessary. For example, the availability of new information or additional detail on techniques or procedures for checki ng the quality of data inputs or emi ssion calculations could necessitate revising the procedures in the Procedures Manual or preparing a background paper expanding on procedures to be used.

The quality checking and control activ ities described in the U.S. QA/QC plan occur throughout the inventory process; QA/QC is not separate from, but is an integral part of, preparing the inventory. Quality control—in the form of both good practices (such as documentation procedures) and checks on whether good practices and procedures are being followed—is applie d at every stage of inventory development and document preparation. InInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 17 addition, quality assurance occurs at two stages—an expert review and a public review. While both phases can significantly contribute to inventory quality, the public review phase is also essential for promoting the openness of the inventory development process and the transparency of the inventory data and methods.

QA/QC procedures guide the process of ensuring inventory qua lity by describing data and methodology checks, developing processes governing peer review and public comments, and developing guidance on conducting an analysis of the uncertainty surrounding the emission estimates. The QA/QC procedures also include feedback loops and provide for corrective actions that are designe d to improve the inventory estimates over time.

In addition, based on the national QA/QC plan for the Inve ntory, source-specific QA/QC plans have been developed for a limited number of sources. These plans follow the procedures outlined in the national QA/QC plan, tailoringthe procedures to the specific text and spreadsheets of the individual sources. For the current Inventory, sourcespecific plans have been developed and implemented for the majority of sources within the Energy and Industrial Process sectors.

Throughout this Inventory, a minimum of a Tier 1 QA/QC analysis has b een undertaken. Where QA/QC activities for a particular source go beyond the minimum Tier 1 level, further explanation is provided within the respective source category text.



### 1.7. Uncertainty Analysi s of Emission Estimates

Uncertainty estimates are an essential element of a complete and transparen t emissions inventory. Uncertainty information is not intended to dispute the validity of the inventory estimates, but to help prioritize efforts to improve the accuracy of future inventories a nd guide future decisions on methodological choice. Wh ile the U.S. Inventory calculates its emission estimates with the highest possible accuracy, uncertaintie s are associated to a varying degree with the development of emission estimates for any inventor y. Some of the current estimates, such as those for CO 2 emissions from energy-related activities and cement processing, are considered to have minimal uncertainty associated with them. For some other categories of emissions, however, a lack of data or an incomplete understanding of how emissions are generated increases the uncertainty surrounding the estimates presented. Despite these uncertainties, the UNFCCC reporting guidelines follow the recommendation in the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997) and require that countries provide singl e point estimates of uncertainty for each ga s and emission or removal source category. Within the discussion of each emission source, specific f actors affecting the uncertain ty associated with the estimates are discussed.

Additional research in the following areas could help reduce uncertainty in the U.S. Inventory 

### :

• Incorporating excluded emission sources. Quantitative estimates for some of the sources and sinks of greenhouse gas emissions are not available at this time. In particular, emissions from some land-use activities and industrial processes are not incl uded in the inventory either because data are incomplete or because methodologies do not exist for estimating emissions from these source categories. See Annex 5 for a discussion of the sources of greenhouse gas emissions and sinks excluded from this report.

• Improving the accuracy of emission factor s. Further research is needed in some cases to improve the accuracy of emission factors used to calculate emissions from a variety of sources. For example, the accuracy of current emission factors applied to CH 4 and N 2 O emissions from stationary and mobile combustion is highly uncertain.

• Collecting detailed activity data. Although methodologies exist for estimating emissions for some sources, problems arise in obtaining activity data at a level of detail in which aggregate emission factors can be applied. For example, the ability to estimate emissions of SF 6 from electrical transmission and distribution is limited due to a lack of activity data regarding national SF 6 consumption or average equipment leak rates.

The IPCC provides good practice guidance on two approaches—Tier 1 and Tier 2—to estimating uncertainty for individual source categories. The Tier 1 method is a spr eadsheet-based analysis that estimates uncertainties by using the error propagation equation. The spreadsheet em ploys uncertainty ranges for activity data and emissionInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 18 factors consistent with the sectoral good practice guidance. The Tier 2 uncertainty estimation methodology employs the Monte Carlo Stochastic Simulation technique. The principle of Monte Carlo analysis is to select random values of emission factor and activity data from within their individual probability density functions, and to calculate the corresponding emission values. Tier 2 uncertainty analysis was applied wherever data and resources permitted. Consistent with the Good Practice Guid ance, over a multi-year timeframe, the Un ited States expects to continue to improve the uncertainty estimates pres ented in this report and add quantitativ e estimates of uncertainty where none currently exist. See Annex 7, Uncertainty, of this report for further details on the U.S. process for estimating uncertainties associated with emission estimates and for a more detailed discussion of the limitations of the current analysis and plans for improvement.

While there are two types of estimation uncertainty, para meter uncertainty and model uncertainty, the Tier 1 and Tier 2 approaches were applied only to estimate parameter uncertainty of emission estimates. Parameter uncertainty refers to the uncertainty associated with quantifying the parameters used as inputs (e.g., activity data and emission factors) to the emission estimation models. Model uncertainty refers to the uncertainty associated with developing mathematical equations or models to characterize the em ission and/or removal processes. Model uncertainties can be evaluated by comparing the model results with the results of other models that are developed to characterize the same emission generation process and through sensitivity analysis. Model uncertainties for some sources are identified, but not evaluated.

Emissions calculated for the U.S. Inventory reflect current best estimates; in some cases, however, estimates are based on approximate methodologies, assumptions, and incomple te data. As new information becomes available in the future, the United States will continue to improve and revise its emission estimates.



### 1.8. Completeness

This report, along with its accompanying CRF tables, serv es as a thorough assessment of the anthropogenic sources and sinks of greenhouse gas emissions for the United States for the time series 1990 through 2003. Although this report is intended to be comprehensive, certain sources have been identified yet excluded from the estimates presented for various reasons. Generally speaking, sources not accounted for in this Inventory are excluded due to data limitations or a lack of thorough understanding of the emission process. The United States is continually working to improve upon the understanding of such sources a nd seeking to find the data required to estimate related emissions. As such improvements are made, new emission sources are quantified and included in the Inventory. For a complete list of sources excluded, see Annex 5.



### 1.9. Organization of Report

In accordance with the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997), and the 2003 UNFCCC Guidelines on Reporting and Review (UNFCCC 2003), this Inventory of U.S. Greenhouse Gas Emissions and Sinks is segregated into six sector-specific chapters, listed below in Table 1-7. In addition, chapters on Trends in Greenhouse Gas Emissions and Other information to be considered as part of the U.S. Inventory submission are included.

Table 1-7: IPCC Sector Descriptions Chapter/IPCC Sector Activities Included Energy Emissions of all greenhouse gase s resulting from stationary and mobile energy activities including fuel combustion and fugitive fuel emissions. Industrial Processes By-produc t or fugitive emissions of greenhouse gases from industrial processes not directly related to energy activities such as fossil fuel combustion. Solvent and Other Product Use Emissions, of primar ily NMVOCs, resulting from the use of solvents and N 2 O from product usage. Agriculture Anthropogenic emissions fro m agricultural activ ities except fuelInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 19 combustion, which is addressed under Energy. Land-Use Change and Forestry Emissions and removals of CO 2 from forest management, other landuse activities, and land-use change. Waste Emissions from waste management activities. Source: (IPCC/UNEP/OECD/IEA 1997)

Within each chapter, emissions are id entified by the anthropogenic activity that is the source or sink of the greenhouse gas emissions being estimated (e.g., coal mining). Overall, the following organizational structure is consistently applied throughout this report: 

### Chapter/IPCC Sector : Overview of emission trends for each IPCC defined sector Source category : Description of source pathway and emission trends. Methodology : Description of analytical methods employed to produce emission estimates and identification of data references, primarily for activity data and emission factors. Uncertainty : A discussion and quantification of the uncertainty in emission estimates and a discussion of timeseries consistency.
QA/QC and Verification: A discussion on steps taken to QA/QC and verify the emission estimates, where beyond the overall U.S. QA/QC plan, and any key findings.
Recalculations: A discussion of any data or methodological changes necessitati ng a recalculation of previous years’ emission estimates, and the impact of the r ecalculation on the emission estimates, if applicable. Planned Improvements: A discussion on any source-specific planned improvements, if applicable.

Special attention is given to CO 2 from fossil fuel combustion relative to other sources because of its share of emissions relative to other sources and its dominant in fluence on emission trends. For example, each energy consuming end-use sector (i.e., residential, commercial, i ndustrial, and transportation), as well as the electricity generation sector, is described individua lly. Additional information for certain source categories and other topics is also provided in several Annexes listed in Table 1-8.

Table 1-8: List of Annexes ANNEX 1 Key Source Analysis ANNEX 2 Methodology and Data for Estimating CO 2 Emissions from Fossil Fuel Combustion 2.1. Methodology for Estimating Emissions of CO 2 from Fossil Fuel Combustion 2.2. Methodology for Estimating the Carbon Content of Fossil Fuels 2.3. Methodology for Estimating Carbon Stored in Products from Non-Energy Uses of Fossil Fuels ANNEX 3 Methodological Descri ptions for Additional Source or Sink Categories 3.1. Methodology for Estimating Emissions of CH 4 , N 2 O, and Ambient Air Pollutants from Stationary Combustion 3.2. Methodology for Estimating Emissions of CH 4 , N 2 O, and Ambient Air Pollutants from Mobile Combustion and Methodology for and Supplemental Information on Transportation-Related Greenhouse Gas Emissions 3.3. Methodology for Estimating CH 4 Emissions from Coal Mining 3.4. Methodology for Estimating CH 4 Emissions from Natural Gas Systems 3.5. Methodology for Estimating CH 4 Emissions from Petroleum Systems 3.6. Methodology for Estimating CO 2 and N 2 O Emissions from Municipal Solid Waste Combustion 3.7. Methodology for Estimating Emi ssions from International Bunker Fu els used by the U.S. Military 3.8. Methodology for Estimating HFC and PFC Emissions from Substitution of Ozone Depleting Substances 3.9. Methodology for Estimating CH 4 Emissions from Enteric Fermentation 3.10. Methodology for Estimating CH 4 and N 2 O Emissions from Manure Management 3.11. Methodology for Estimating N 2 O Emissions from Agricultural Soil Management 3.12. Methodology for Estimating Net Carbon Stock Changes in Forest Carbon Stocks 3.13. Methodology for Estimating Net Changes in Carbon Stocks in Mineral and Organic Soils 3.14. Methodology for Estimating CH 4 Emissions from Landfills ANNEX 4 IPCC Reference Approach for Estimating CO 2 Emissions from Fossil Fuel CombustionInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 20 ANNEX 5 Assessment of the Sources and Sinks of Greenhouse Gas Emissions Excluded ANNEX 6 Additional Information 6.1. Global Warming Potential Values 6.2. Ozone Depleting Substance Emissions 6.3. Sulfur Dioxide Emissions 6.4. Complete List of Source Categories 6.5. Constants, Units, and Conversions 6.6. Abbreviations 6.7. Chemical Formulas 6.8. Glossary ANNEX 7 Uncertainty 7.1. Overview 7.2. Methodology and Results 7.3. Uncertainty Estimation as a Process 7.4. Planned ImprovementsInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 21 

## 2. Trends in Greenhouse Gas Emissions

2.1. Recent Trends in U.S. Greenhouse Gas Emissions

In 2003, total U.S. greenhouse gas emissions were 6, 900.2 teragrams of carbon dioxide equivalent (Tg CO 2 Eq.) 1 (13.3 percent above 1990 emissions). Emissions rose s lightly from 2002 to 2003, increasing by 0.6 percent (42.2 Tg CO 2 Eq.). The following factors were primary contributors to this increase: 1) moderate economic growth in 2003, leading to increased demand for electricity and fossil fuels, 2) increased natural gas prices, causing some electric power producers to switch to burning coal, and 3) a colder winter, which caused an increase in the use of heating fuels, primarily in the residential sector. (See the following section for an analysis of emission trends by general economic sectors.) Figure 2-1 th rough Figure 2-3 illustrate the overall trends in total U.S. emissions by gas, annual changes, and absolute changes since 1990.

Figure 2-1: U.S. Greenhouse Gas Emissions by Gas

Figure 2-2: Annual Percent Change in U.S. Greenhouse Gas Emissions

Figure 2-3: Cumulative Change in U.S. Greenhouse Gas Emissions Relative to 1990

As the largest source of U.S. greenhouse gas emissions, carbon dioxide (CO 2 ) from fossil fuel combustion has accounted for a nearly constant 80 percent of global warming potential (GWP) weighted emissions since 1990. Emissions from this source category grew by 17.8 percent (839.8 Tg CO 2 Eq.) from 1990 to 2003 and were responsible for most of the increase in national emissions during this period. From 2002 to 2003, these emissions increased by 50.2 Tg CO 2 Eq. (0.9 percent), the same rate as the sour ce's average annual growth rate of 1.3 percent from 1990 through 2003. Historically, changes in emissions from fossil fuel combustion have been the dominant factor affecting U.S. emission trends.

Changes in CO 2 emissions from fossil fuel combustion are influenced by many long-term and short-term factors, including population and economic growth, energy price fluctuations, technological changes, and seasonal temperatures. On an annual basis, the overall consumption of fossil fuels in the United States generally fluctuates in response to changes in general economic conditions, ener gy prices, weather, and the availability of non-fossil alternatives. For example, in a year with increased c onsumption of goods and services, low fuel prices, severe summer and winter weather conditions, nuclear plant closur es, and lower precipitation feeding hydroelectric dams, there would likely be proportionally greater fossil fuel consumption than a year with poor economic performance, high fuel prices, mild temperatures, and increased output from nuclear and hydroelectric plants.

In the longer-term, energy consumption patterns respond to changes that affect the scale of consumption (e.g., population, number of cars, and size of houses), the efficiency with which energy is used in equipment (e.g., cars, power plants, steel mills, and light bulbs) and consumer be havior (e.g., walking, bicycling, or telecommuting to work instead of driving).

1 Estimates are presented in units of teragrams of carbon dioxide equivalent (Tg CO 2 Eq.), which weight each gas by its Global Warming Potential, or GWP, value. (See sec tion on Global Warming Potentials, Chapter 1.)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 22 Energy-related CO 2 emissions also depend on the type of fuel or energy consumed and its carbon intensity. Producing a unit of heat or electricity using natural gas instead of coal, for example, can reduce the CO 2 because of the lower carbon content of natural gas. Table 2-1 shows annual changes in emissions during the last six years for coal, petroleum, and natural gas in selected sectors.

Table 2-1: Annual Change in CO 2 Emissions from Fossil Fuel Combustion for Selected Fuels and Sectors (Tg CO 2 Eq. and Percent) Sector Fuel Type 1999 to 2000 2000 to 2001 2001 to 2002 2002 to 2003 Electricity Generation Coal 87.6 5% -62.6 -3% 22.2 1% 36.6 2% Electricity Generation Natural Gas 20.8 8% 8.4 3% 16.5 6% -28.0 -9% Electricity Generation Petroleum -5.6 -6% 9.8 11% -23.5 -23% 18.9 24% Transportation a Petroleum 47.0 3% -16.4 -1% 29.4 2% 16.6 1% Residential Natural Gas 13.9 5% -10.7 -4% 6.2 2% 11.5 4% Commercial Natural Gas 7.1 4% -7.9 -5% 4.2 3% 2.0 1% Industrial Coal 1.1 1% -4.4 -3% -7.9 -6% 0.8 1% Industrial Natural Gas 8.2 2% -38.5 -8% 9.5 2% -27.6 -6% All Sectors b All Fuels b 199.2 4% -97.1 -2% 53.5 1% 50.2 1%

a Excludes emissions from In ternational Bunker Fuels. b Includes fuels and sectors not shown in table.

In 1999, the increase in emissions from fossil fuel combustion was driven largely by growth in petroleum consumption for transportation. In addition, residential and commercial heating fuel demand partially recovered as winter temperatures dropped relative to 1998, alt hough temperatures were still warmer than normal. 2 These increases were offset, in part, by a decline in emissi ons from electric power producers due primarily to: 1) an increase in net generation of electricity by nuclear plan ts which reduced demand from fossil fuel plants; and 2) moderated summer temperatures compared to the previous year—thereby reducing electricity demand for air conditioning.

Emissions from fuel combustion increased considerably in 2000, due to several factors. The primary reason for the increase was the robust U.S. economy, which produced a high demand for fuels—especially for petroleum in the transportation sector—despite increases in the price of both natural gas and petroleum. Colder winter conditions relative to the previous year triggered a rise in residential and commercial demand for heating. Additionally, electricity generation became more carbon intensive as coal and natural gas consumpti on offset reduced hydropower output.

In 2001, economic growth in the United States slowed considerably for the second time since 1990, contributing to a decrease in CO 2 emissions from fossil fuel combustion, also for the second time since 1990. A significant reduction in industrial output contributed to weak economic growth, primarily in manufacturing, and led to lower emissions from the industrial sector. Several other factors also played a role in this decrease in emissions. Warmer winter conditions compared to 2000, along with higher na tural gas prices, reduced demand for heating fuels. Additionally, nuclear facilities operated at a very high capacity, offsetting elect ricity produced from fossil fuels. Since there are no greenhouse gas emissions associated with electricity production from nuclear plants, this substitution reduces the overall carbon inte nsity of electricity generation.

Emissions from fuel combustion resumed a modest growth in 2002, slightly less than the average annual growth rate since 1990. There were a number of reasons behind this increase. The U.S. economy experienced moderate growth, recovering from weak conditions in 2001. Prices for fuels remained at or below 2001 levels; the cost of natural gas, motor gasoline, and electricity were all lower– triggering an increase in demand for fuel. In addition, the United States experienced one of the hottest summers on r ecord, causing a significant incr ease in electricity use in

2 Normals are based on data from 1971 through 2000. Source: EIA (2004b)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 23 the residential sector as the use of air-conditioners increased. Partially offsetting this increased consumption of fossil fuels, however, were increases in the use of nuclear and renewable fuels. Nuclear facilities operated at the highest capacity on record in 2002. Furthermore, there was a considerable increase in the use of hydroelectric power in 2002 after a very low output the previous year.

Emissions from fuel combustion continued growing in 2003, at about the average annual growth rate since 1990. A number of factors played a major role in the magnitude of this increase. The U.S. economy experienced moderate growth from 2002, causing an increase in the demand for fuel s. The price of natural gas escalated dramatically, causing some electric power producers to sw itch to coal, which remained at relatively stable prices. Colder winter conditions brought on more demand for heating fuels, primar ily in the residential sector. Though a cooler summer partially offset demand for electricity as the use of air-conditioners decreased, electricity consumption continued to increase in 2003. The primary drivers behind this trend were the growing economy and the increase in U.S. housing stock. Use of nuclear and renewable fuels remained rela tively stable. Nuclear capacity decreased slightly, and for the first time since 1997. Use of renewable fuels rose slightly due to increases in the use of hydroelectric power and biofuels.

Other significant trends in emissions from additional source categories over the fourteen-year period from 1990 through 2003 included the following:

● Carbon dioxide emissions from waste combustion increased by 7.9 Tg CO 2 Eq. (72 percent), as the volume of plastics and other fossil carbon-containing materials in municipal solid waste grew.

● Net CO 2 sequestration from land use change and forestry decreased by 214.0 Tg CO 2 Eq. (21 percent), primarily due to a decline in the ra te of net carbon accumulation in forest carbon stocks. This decline largely resulted from a decrease in the estimated rate of forest soil sequestration caused by a slowing rate of increase in forest area after 1997.

● Methane (CH 4 ) emissions from coal mining declined by 28.1 Tg CO 2 Eq. (34 percent) from 1990 to 2003, as a result of the mining of less gassy coal from underground mi nes and the increased use of methane collected from degasification systems.

● The increase in ODS emissions is offset substantia lly by decreases in emission of HFCs, PFCs, and SF 6 from other sources. Emissions from aluminum production decreased by 79 percent (14.5 Tg CO 2 Eq.) from 1990 to 2003, due to both industry emission reduction efforts a nd lower domestic aluminum production. Emissions from the production of HCFC-22 decreased by 65 percent (22.6 Tg CO 2 Eq.) from 1990 to 2003, due to a steady decline in the emission rate of HFC-23 (i.e., the amount of HFC-23 emitted per kilogram of HCFC-22 manufactured) and the use of thermal oxidation at some plants to reduce HFC-23 emissions. Emissions from electric power transmission and distribution systems decreased by 52 percent (15.1 Tg CO 2 Eq.) from 1990 to 2003, primarily because of higher purchase prices for SF 6 and efforts by industry to reduce emissions. Overall, from 1990 to 2003, total emissions of CO 2 increased by 832.0 Tg CO 2 Eq. (17 percent), while CH 4 and N 2 O emissions decreased by 60.4 Tg CO 2 Eq. (10 percent) and 5.2 Tg CO 2 Eq. (just over 1 percent), respectively. During the same period, aggregate weighted emissions of HFCs, PFCs, and SF 6 rose by 45.8 Tg CO 2 Eq. (50 percent). Despite being emitted in smaller quantities relativ e to the other principal greenhouse gases, emissions of HFCs, PFCs, and SF 6 are significant because many of them have ex tremely high global warming potentials and, in the cases of PFCs and SF 6 , long atmospheric lifetimes. Conversely, U.S. greenhouse gas emissions were partly offset by carbon sequestration in forests, trees in urban areas, agricu ltural soils, and landfilled yard trimmings, which was estimated to be 12 percent of total emissions in 2003.

[BEGIN BOX]

Box 2-1: Recent Trends in Various U. S. Greenhouse Gas Emissions-Related Data Total emissions can be compared to other economic and social indices to highlight changes over time. These comparisons include: 1) emissions per unit of aggregate energy consumption, because energy-related activities are the largest sources of emissions; 2) emissions per unit of fossil fuel consumption, becau se almost all energy-relatedInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 24 emissions involve the combustion of fo ssil fuels; 3) emissions per unit of electricity consumption, because the electric power industry—utilities and nonutilities combined —was the largest source of U.S. greenhouse gas emissions in 2003; 4) emissions per unit of total gross domestic product as a measure of national economic activity; or 5) emissions per capita.

Table 2-2 provides data on various statistics related to U.S. greenhouse gas emissions normalized to 1990 as a baseline year. Greenhouse gas emissions in the United States have grown at an average annual rate of 1.0 percent since 1990. This rate is slower than that for total energy or fossil fuel consumption and much slower than that for either electricity consumption or overall gross domestic product. Total U.S. greenhouse gas emissions have also grown more slowly than national population since 1990 (see Figure 2-4). Overall, global atmospheric CO 2 concentrations

⎯ a function of many complex anthropogenic and natural processes

⎯ are increasing at 0.5 percent per year.

Table 2-2: Recent Trends in Various U.S. Data (Index 1990 = 100) a nd Global Atmospheric CO 2 Concentration

Variable 1991 1997 1998 1999 2000 2001 2002 2003 Growth Rate f Greenhouse Gas Emissions a 99 110 110 111 114 112 113 113 1.0% Energy Consumption b 100 112 113 114 117 114 116 116 1.2% Fossil Fuel Consumption b 99 112 113 114 117 115 116 116 1.2% Electricity Consumption b 102 117 121 124 128 125 129 130 2.1% GDP c 100 122 127 133 138 139 142 146 3.0% Population d 101 109 110 112 113 114 115 116 1.1% Atmospheric CO 2 Concentration e 100 103 104 104 104 105 105 106 0.5%

a GWP weighted values b Energy content weighted values (EIA 2004a)

c Gross Domestic Product in chained 2000 dollars (BEA 2004) d (U.S. Census Bureau 2004)

e Mauna Loa Observatory, Hawaii (Keeling and Whorf 2004) f Average annual growth rate

Figure 2-4: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product Source: BEA (2004), U.S. Census Bureau ( 2004), and emission estimat es in this report.

[END BOX]

As an alternative, emissions of all gases can be totaled fo r each of the IPCC sectors. Ov er the thirteen year period of 1990 to 2003, total emissions in the Energy, Industrial Processes, Agriculture, and Solvent and Other Product Use sectors climbed by 821.6Tg CO 2 Eq. (16 percent), 8.7 Tg CO 2 Eq. (3 percent), 6.8 Tg CO 2 Eq. (2 percent), and 0.5 Tg CO 2 Eq. (11 percent), respectively, while emissi ons from the Waste sector decreased 26.3 Tg CO 2 Eq. (13 percent). Over the same period, estimates of net carbon sequestration in the Land-Use Change and Forestry sector declined by 214.8 Tg CO 2 Eq. (21 percent).

Table 2-3 summarizes emissions and sinks from all U.S. anthropogenic sources in weighted units of Tg CO 2 Eq., while unweighted gas emissions and sinks in gigagrams (Gg) are provided in Table 2-4. Alternatively, emissions and sinks are aggregated by chapter in Table 2-5 and Figure 2-5.

Table 2-3: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO 2 Eq.) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 5,009.6 5,580.0 5,607.2 5,678.0 5,858.2 5,744.8 5,796.8 5,841.5

Fossil Fuel Combustion 4,711.7 5,263.2 5,278.7 5,345.9 5,545.1 5,448.0 5,501.4 5,551.6 Non-Energy Use of Fuels 108.0 120.3 135.4 141.6 124.7 120.1 118.8 118.0 Iron and Steel Production 85.4 71.9 67.4 64.4 65.7 58.9 55.1 53.8 Cement Manufacture 33.3 38.3 39.2 40.0 41.2 41.4 42.9 43.0Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 25 Waste Combustion 10.9 17.8 17.1 17.6 18.0 18.8 18.8 18.8 Ammonia Production and Urea

Application 19.3 20.7 21.9 20.6 19.6 16.7 18.6 15.6 Lime Manufacture 11.2 13.7 13.9 13.5 13.3 12.8 12.3 13.0 Natural Gas Flaring 5.8 7.9 6.6 6.9 5.8 6.1 6.2 6.0 Limestone and Dolomite Use 5.5 7.2 7.4 8.1 6.0 5.7 5.9 4.7 Aluminum Production 6.3 5.6 5.8 5.9 5.7 4.1 4.2 4.2 Soda Ash Manufacture and

Consumption 4.1 4.4 4.3 4.2 4.2 4.1 4.1 4.1 Petrochemical Production 2.2 2.9 3.0 3.1 3.0 2.8 2.9 2.8 Titanium Dioxide Production 1.3 1.8 1.8 1.9 1.9 1.9 2.0 2.0 Phosphoric Acid Production 1.5 1.5 1.6 1.5 1.4 1.3 1.3 1.4 Ferroalloys 2.0 2.0 2.0 2.0 1.7 1.3 1.2 1.4 Carbon Dioxide Consumption 0.9 0.8 0.9 0.8 1.0 0.8 1.0 1.3 Land-Use Change and Forestry

(Sinks) a (1,042.0) (930.0) (881.0) (826.1) (822.4) (826.9) (826.5) (828.0) International Bunker Fuels b 113.5 109.9 114.6 105.3 101.4 97.9 89.5 84.2 Biomass Combustion b 216.7 233.2 217.2 222.3 226.8 200.5 207.2 216.8 CH 4 605.3 579.5 569.1 557.3 554.2 546.8 542.5 545.0

Landfills 172.2 147.4 138.5 134.0 130.7 126.2 126.8 131.2 Natural Gas Systems 128.3 133.6 131.8 127.4 132.1 131.8 130.6 125.9 Enteric Fermentation 117.9 118.3 116.7 116.8 115.6 114.5 114.6 115.0 Coal Mining 81.9 62.6 62.8 58.9 56.2 55.6 52.4 53.8 Manure Management 31.2 36.4 38.8 38.8 38.1 38.9 39.3 39.1 Wastewater Treatment 24.8 31.7 32.6 33.6 34.3 34.7 35.8 36.8 Petroleum Systems 20.0 18.8 18.5 17.8 17.6 17.4 17.1 17.1 Rice Cultivation 7.1 7.5 7.9 8.3 7.5 7.6 6.8 6.9 Stationary Sources 7.8 7.4 6.9 7.1 7.3 6.7 6.4 6.7 Abandoned Coal Mines 6.1 8.1 7.2 7.3 7.7 6.9 6.4 6.4 Mobile Sources 4.8 4.0 3.9 3.6 3.4 3.1 2.9 2.7 Petrochemical Production 1.2 1.6 1.7 1.7 1.7 1.4 1.5 1.5 Iron and Steel Production 1.3 1.3 1.2 1.2 1.2 1.1 1.0 1.0 Agricultural Residue Burning 0.7 0.8 0.8 0.8 0.8 0.8 0.7 0.8 Silicon Carbide Production + + + + + + + + International Bunker Fuels b 0.2 0.1 0.2 0.1 0.1 0.1 0.1 0.1 N 2 O 382.0 396.3 407.8 382.1 401.9 385.8 380.5 376.7

Agricultural Soil Management 253.0 252.0 267.7 243.4 263.9 257.1 252.6 253.5 Mobile Sources 43.7 55.2 55.3 54.6 53.2 49.0 45.6 42.1 Manure Management 16.3 17.3 17.4 17.4 17.8 18.0 17.9 17.5 Human Sewage 13.0 14.7 15.0 15.4 15.6 15.6 15.7 15.9 Nitric Acid 17.8 21.2 20.9 20.1 19.6 15.9 17.2 15.8 Stationary Sources 12.3 13.5 13.4 13.5 14.0 13.5 13.5 13.8 Settlements Remaining

Settlements 5.5 6.1 6.1 6.2 6.0 5.8 6.0 6.0 Adipic Acid 15.2 10.3 6.0 5.5 6.0 4.9 5.9 6.0 N 2 O Product Usage 4.3 4.8 4.8 4.8 4.8 4.8 4.8 4.8 Waste Combustion 0.4 0.4 0.3 0.3 0.4 0.4 0.5 0.5 Agricultural Residue Burning 0.4 0.4 0.5 0.4 0.5 0.5 0.4 0.4 Forest Land Remaining Forest

Land 0.1 0.3 0.4 0.5 0.4 0.4 0.4 0.4 International Bunker Fuels b 1.0 1.0 1.0 0.9 0.9 0.9 0.8 0.8 HFCs, PFCs, and SF 6 91.2 121.7 135.7 134.8 138.9 129.5 138.3 137.0

Substitution of Ozone Depleting

Substances 0.4 46.5 56.6 65.8 75.0 83.3 91.5 99.5Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 26 Electrical Transmission and

Distribution 29.2 21.7 17.1 16.4 15.6 15.4 14.7 14.1 HCFC-22 Production 35.0 30.0 40.1 30.4 29.8 19.8 19.8 12.3 Semiconductor Manufacture 2.9 6.3 7.1 7.2 6.3 4.5 4.4 4.3 Aluminum Production 18.3 11.0 9.1 9.0 9.0 4.0 5.2 3.8 Magnesium Production and

Processing 5.4 6.3 5.8 6.0 3.2 2.6 2.6 3.0 Total 6,088.1 6,677.5 6,719.7 6,752.2 6,953.2 6,806.9 6,858.1 6,900.2 Net Emissions (Sources and

Sinks) 5,046.1 5,747.5 5,838.8 5,926.1 6,130.8 5,980.1 6,031.6 6,072.2

+ Does not exceed 0.05 Tg CO 2 Eq.

a Sinks are only included in net emissions total, and are based partially on projected activity data. Parentheses indicate nega tive values (or sequestration). b Emissions from International B unker Fuels and Biomass Combustion are not included in totals. Note: Totals may not sum due to independent rounding.

Table 2-4: Recent Trends in U.S. Gr eenhouse Gas Emissions and Sinks (Gg) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 5,009,552 5,579,984 5,607,159 5,677,970 5,858,201 5,744,782 5,796,757 5,841,504

Fossil Fuel Combustion 4,711,741 5,263,164 5,278,721 5,345,904 5,545,083 5,447,969 5,501,427 5,551,580 Non-Energy Use of

Fuels 107,965 120,301 135,352 141,583 124,714 120,104 118,811 118,001 Iron and Steel

Production 85,413 71,863 67,428 64,376 65,693 58,887 55,082 53,763 Cement Manufacture 33,278 38,323 39,218 39,991 41,190 41,357 42,898 43,030 Waste Combustion 10,919 17,761 17,094 17,632 17,979 18,781 18,781 18,781 Ammonia Production

and Urea Application 19,306 20,650 21,934 20,615 19,616 16,719 18,571 15,560 Lime Manufacture 11,238 13,685 13,914 13,466 13,315 12,823 12,304 12,983 Natural Gas Flaring 5,805 7,874 6,566 6,943 5,769 6,094 6,233 5,970 Limestone and Dolomite

Use 5,533 7,242 7,449 8,057 5,959 5,733 5,885 4,720 Aluminum Production 6,315 5,621 5,792 5,895 5,723 4,114 4,220 4,219 Soda Ash Manufacture

and Consumption 4,141 4,354 4,325 4,217 4,181 4,147 4,139 4,082 Petrochemical

Production 2,221 2,919 3,015 3,054 3,004 2,787 2,857 2,777 Titanium Dioxide

Production 1,308 1,836 1,819 1,853 1,918 1,857 1,997 2,013 Phosphoric Acid

Production 1,529 1,544 1,593 1,539 1,382 1,264 1,338 1,382 Ferroalloys 1,980 2,038 2,027 1,996 1,719 1,329 1,237 1,374 Carbon Dioxide

Consumption 860 808 912 849 957 818 978 1,267 Land-Use Change and

Forestry (Sinks) a (1,042,050) (930,011) (880,995) (826,106) (822,409) (826,879) (826,483) (828,046) International Bunker

Fuels b 113,503 109,858 114,557 105,294 101,404 97,865 89,489 84,193 Biomass Combustion 216,702 233,243 217,201 222,340 226,765 200,477 207,249 216,813 CH 4 28,826 27,595 27,100 26,537 26,389 26,039 25,832 25,950

Landfills 8,202 7,017 6,595 6,382 6,223 6,010 6,039 6,246 Natural Gas Systems 6,112 6,363 6,276 6,066 6,289 6,277 6,221 5,998 Enteric Fermentation 5,612 5,634 5,557 5,561 5,505 5,454 5,458 5,475 Coal Mining 3,900 2,983 2,989 2,805 2,677 2,647 2,497 2,561 Manure Management 1,485 1,733 1,850 1,846 1,813 1,853 1,873 1,864Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 27 Wastewater Treatment 1,183 1,509 1,550 1,602 1,635 1,651 1,705 1,751 Petroleum Systems 951 895 879 848 836 831 815 815 Rice Cultivation 339 356 376 395 357 364 325 328 Stationary Sources 373 351 328 338 349 318 305 319 Abandoned Coal Mines 288 385 341 349 369 331 303 306 Mobile Sources 228 193 185 172 161 147 138 128 Petrochemical

Production 56 78 80 81 80 68 72 72 Iron and Steel

Production 63 60 57 56 57 51 48 49 Field Burning of

Agricultural Residues 33 37 38 37 38 37 34 38 Silicon Carbide

Production 1 1 1 1 1 + + + International Bunker

Fuels b 8 7 7 6 6 5 4 4 N 2 O 1,232 1,278 1,315 1,233 1,297 1,245 1,228 1,215

Agricultural Soil

Management 816 813 864 785 851 829 815 818 Mobile Sources 141 178 179 176 171 158 147 136 Manure Management 52 56 56 56 57 58 58 57 Human Sewage 42 47 48 50 50 50 51 51 Nitric Acid 58 68 67 65 63 51 56 51 Stationary Sources 40 44 43 43 45 43 44 45 Settlements Remaining

Settlements 18 20 20 20 19 19 19 19 Adipic Acid 49 33 19 18 19 16 19 19 N 2 O Product Usage 14 15 15 15 15 15 15 15 Waste Combustion 1 1 1 1 1 1 1 1 Field Burning of

Agricultural Residues 1 1 1 1 1 1 1 1 Forest Land Remaining

Forest Land + 1 1 2 1 1 1 1 International Bunker

Fuels b 3 3 3 3 3 3 3 2 HFCs, PFCs, and SF 6 M M M M M M M M

Substitution of Ozone

Depleting Substances M M M M M M M M Electrical Transmission

and Distribution d 1 1 1 1 1 1 1 1 HCFC-22 Production c 3 3 3 3 3 2 2 1 Semiconductor

Manufacture M M M M M M M M Aluminum Production M M M M M M M M Magnesium Production

and Processing d + + + + + + + + SO 2 20,936 17,091 17,189 15,917 14,829 14,452 13,928 14,463 NO x 22,860 22,284 21,964 20,530 20,288 19,414 18,850 18,573 CO 130,580 101,138 98,984 94,361 92,895 89,329 87,451 85,077 NMVOCs 20,937 16,994 16,403 15,869 15,228 15,048 14,222 13,939 + Does not exceed 0.5 Gg. M Mixture of multiple gases

a Sinks are not included in CO 2 emissions total, and are based partially on projected activity data. b Emissions from International B unker Fuels and Biomass Combustion are not included in totals.

c HFC-23 emittedInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 28 d SF 6 emitted Note: Totals may not sum due to independent rounding. Note: Parentheses indicate nega tive values (or sequestration).

Figure 2-5: U.S. Greenhouse Gas Emissions by Chapter/IPCC Sector

Table 2-5: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Ch apter/IPCC Sector (Tg CO 2 Eq.) Chapter/IPCC Sector 1990 1997 1998 1999 2000 2001 2002 2003 Energy 5,141.7 5,712.8 5,737.7 5,802.6 5,985.3 5,877.3 5,920.7 5,963.4 Industrial Processes 299.9 327.1 334.9 329.2 332.1 304.7 315.4 308.6 Solvent and Other Product Use 4.3 4.8 4.8 4.8 4.8 4.8 4.8 4.8 Agriculture 426.5 432.8 449.8 425.9 444.1 437.5 432.4 433.3 Land-Use Change and Forestry (Emissions) 5.6 6.4 6.5 6.6 6.3 6.2 6.4 6.4 Waste 210.1 193.7 186.0 183.1 180.6 176.5 178.3 183.8 Total 6,088.1 6,677.5 6,719.7 6,752.2 6,953.2 6,806.9 6,858.1 6,900.2 Land-Use Change and Forestry (Sinks) (1042.0) (930.0) (881.0) (826.1) (822.4) (826.9) (826.5) (828.0) Net Emissions (Sources and Sinks) 5,046.1 5,747.5 5,838.8 5,926.1 6,130.8 5,980.1 6,031.6 6,072.2 * 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 nega tive values (or sequestration).



### Energy

Energy-related activities, primarily fossil fuel combustion, accounted fo r the vast majority of U.S. CO 2 emissions for the period of 1990 through 2003. In 2003, approximately 86 percent of the energy consumed in the United States was produced through the combustion of fossil fuels. The remaining 14 percent came from other energy sources such as hydropower, biomass, nuclear, wind, and solar energy (see Figure 2-6 and Figure 2-7). A discussion of specific trends related to CO 2 as well as other greenhouse gas emissions from energy consumption is presented below. Energy related activities are also responsible for CH 4 and N 2 O emissions (39 percent and 15 percent of total U.S. emissions, respectively). Table 2-6 presents greenhouse gas emissions from the Energy sector, by source and gas.

Figure 2-6: 2003 Energy Sector Greenhouse Gas Sources

Figure 2-7: 2003 U.S. Fossil Carbon Flows (Tg CO 2 Eq.)

Table 2-6: Emissions from Energy (Tg CO 2 Eq.) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 4,836.4 5,409.1 5,437.7 5,512.1 5,693.5 5,592.9 5,645.3 5,694.3

Fossil Fuel Combustion 4,711.7 5,263.2 5,278.7 5,345.9 5,545.1 5,448.0 5,501.4 5,551.6 Non-Energy Use of Fuels 108.0 120.3 135.4 141.6 124.7 120.1 118.8 118.0 Waste Combustion 10.9 17.8 17.1 17.6 18.0 18.8 18.8 18.8 Natural Gas Flaring 5.8 7.9 6.6 6.9 5.8 6.1 6.2 6.0 Biomass-Wood* 212.5 226.3 209.5 214.3 217.6 190.8 195.8 201.0 International Bunker Fuels* 113.5 109.9 114.6 105.3 101.4 97.9 89.5 84.2 Biomass-Ethanol* 4.2 7.0 7.7 8.0 9.2 9.7 11.5 15.8 CH 4 248.9 234.6 230.9 222.1 224.3 221.6 215.8 212.7

Natural Gas Systems 128.3 133.6 131.8 127.4 132.1 131.8 130.6 125.9 Coal Mining 81.9 62.6 62.8 58.9 56.2 55.6 52.4 53.8 Petroleum Systems 20.0 18.8 18.5 17.8 17.6 17.4 17.1 17.1Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 29 Stationary Sources 7.8 7.4 6.9 7.1 7.3 6.7 6.4 6.7 Abandoned Coal Mines 6.1 8.1 7.2 7.3 7.7 6.9 6.4 6.4 Mobile Sources 4.8 4.0 3.9 3.6 3.4 3.1 2.9 2.7 International Bunker Fuels* 0.2 0.1 0.2 0.1 0.1 0.1 0.1 0.1 N 2 O 56.4 69.1 69.1 68.4 67.5 62.8 59.6 56.4

Mobile Sources 43.7 55.2 55.3 54.6 53.2 49.0 45.6 42.1 Stationary Sources 12.3 13.5 13.4 13.5 14.0 13.5 13.5 13.8 Waste Combustion 0.4 0.4 0.3 0.3 0.4 0.4 0.5 0.5 International Bunker Fuels* 1.0 1.0 1.0 0.9 0.9 0.9 0.8 0.8 Total 5,141.7 5,712.8 5,737.7 5,802.6 5,985.3 5,877.3 5,920.7 5,963.4 * These values are presented fo r informational purposes only and are not included in totals or are already accounted for in oth er source categories. Note: Totals may not sum due to independent rounding. Fossil Fuel Combustion (5,551.6 Tg CO 2 Eq.)
As fossil fuels are combusted, the carbon stored in them is emitted almost entirely as CO 2 . The amount of carbon in fuels per unit of energy content varies significantly by fuel type. For example, coal contains the highest amount of carbon per unit of energy, while petroleum and natural ga s have about 25 percent and 45 percent less carbon than coal, respectively. From 1990 through 2003, petroleum supplied the largest share of U.S. energy demands, accounting for an average of 39 percent of total energy consumption with natural gas and coal accounting for 24 and 23 percent of total energy consumption, respectively. Petroleum was consumed primarily in the transportation end-use sector, the vast majority of coal was used by electric power generators, and natural gas was consumed largely in the industrial and residential end-use sectors.

Emissions of CO 2 from fossil fuel combustion increased at an average annual rate of 1.3 percent from 1990 to 2003. The fundamental factors influencing this trend include (1) a generally growing domestic economy over the last 13 years, and (2) significant growth in emissions from tran sportation activities and electricity generation. Between 1990 and 2003, CO 2 emissions from fossil fuel combustion increased from 4,711.7 Tg CO 2 Eq. to 5,551.6 Tg CO 2 Eq.

⎯ an 18 percent total increase ove r the thirteen-year period.

The four major end-use sectors contributing to CO 2 emissions from fossil fuel combustion are industrial, transportation, residential, and commercial. Electricity generation also emits CO 2 , although these emissions are produced as they consume fossil fuel to provide electricity to one of the four end-use sectors. For the discussion below, electricity generation emissions have been distribut ed to each end-use sector on the basis of each sector’s share of aggregate electricity consump tion. This method of distributing emi ssions assumes that each end-use sector consumes electricity that is generate d from the national average mix of fuels according to their carbon intensity. In reality, sources of electricity vary widely in carbon intensity. By assumi ng the same carbon intensity for each enduse sector's electricity consumption, for example, emissions attributed to the residential end-use sector may be underestimated, while emissions attributed to the industrial end-use sector may be overestimated. Emissions from electricity generation are al so addressed separately after the end- use sectors have been discussed.

Note that emissions from U.S. territories are calculated separately due to a lack of specific consumption data for the individual end-use sectors. Table 2-7, Figure 2-8, and Figure 2-9 summarize CO 2 emissions from fossil fuel combustion by end-use sector.

Table 2-7: CO 2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO 2 Eq.) End-Use Sector 1990 1997 1998 1999 2000 2001 2002 2003 Transportation 1,449.8 1,606.4 1,636.5 1,693.9 1,741.0 1,723.1 1,755.4 1,770.4

Combustion 1,446.8 1,603.3 1,633.4 1,690.8 1,737.7 1,719.7 1,752.3 1,767.2 Electricity 3.0 3.1 3.1 3.2 3.4 3.4 3.2 3.2 Industrial 1,553.9 1,703.0 1,668.5 1,651.2 1,684.4 1,587.4 1,579.0 1,572.9

Combustion 882.8 963.8 911.6 888.1 905.0 878.2 876.6 858.6 Electricity 671.1 739.2 757.0 763.1 779.4 709.3 702.4 714.3 Residential 924.8 1,040.7 1,044.4 1,063.5 1,124.2 1,116.2 1,145.0 1,168.9Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 30 Combustion 339.6 370.6 338.6 359.3 379.1 367.0 371.4 385.1 Electricity 585.3 670.2 705.8 704.2 745.0 749.2 773.6 783.8 Commercial 755.1 876.7 892.9 901.2 959.5 972.7 973.9 983.1

Combustion 224.2 237.2 219.7 222.3 235.2 226.7 230.0 234.0 Electricity 530.9 639.5 673.2 678.9 724.3 745.9 743.9 749.2 U.S. Territories 28.0 36.4 36.3 36.2 35.9 48.6 48.1 56.2 Total 4,711.7 5,263.2 5,278.7 5,345.9 5,545.1 5,448.0 5,501.4 5,551.6 Electricity Generation 1,790.3 2,051.9 2,139.0 2,149.3 2,252.1 2,207.8 2,223.0 2,250.5 Note: Totals may not sum due to indepe ndent rounding. Combustion-related emissions from electricity generation are allocated based on aggregate national electricity consumption by each end-use sector.

Figure 2-8: 2003 CO 2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type

Figure 2-9: 2003 End-Use Sector Emissions of CO 2 from Fossil Fuel Combustion

Transportation End-Use Sector . Transportation activities ( excluding international bunker fuels ) accounted for 32 percent of CO 2 emissions from fossil fuel combustion in 2003. 3 Virtually all of the energy consumed in this enduse sector came from petroleum products. Over 60 percent of the emissions resulted from gasoline consumption for personal vehicle use. The remaining emissions came from other transportation activities, including the combustion of diesel fuel in heavy-duty vehi cles and jet fuel in aircraft.

Industrial End-Use Sector . Industrial CO 2 emissions, resulting both directly from the combustion of fossil fuels and indirectly from the generation of el ectricity that is consumed by i ndustry, accounted for 28 percent of CO 2 from fossil fuel combustion in 2003. About half of these emissions resulted from direct fossil fuel combustion to produce steam and/or heat for industrial processes. The other half of the emissions resulted from consuming electricity for motors, electric furnaces, ovens, li ghting, and othe r applications.

Residential and Commercial End-Use Sectors . The residential and commercial end-use sectors accounted for 21 and 18 percent, respectively, of CO 2 emissions from fossil fuel combustion in 2003. Both sectors relied heavily on electricity for meeting energy demands, with 67 and 76 percent, respectively, of their emissions attributable to electricity consumption for lighting, heating, cooling, a nd operating appliances. The remaining emissions were due to the consumption of natural gas a nd petroleum for heating and cooking.

Electricity Generation . The United States relies on electricity to m eet a significant portion of its energy demands, especially for lighting, electric motors, heating, and air conditioning. Electric ity generators consumed 35 percent of U.S. energy from fossil fuels and emitted 41 percent of the CO 2 from fossil fuel combustion in 2003. The type of fuel combusted by electricity generators has a significant e ffect on their emissions. For ex ample, some electricity is generated with low CO 2 emitting energy technologies, par ticularly non-fossil options such as nuclear, hydroelectric, or geothermal energy. However, electricity generators re ly on coal for over half of their total energy requirements and accounted for 93 percent of all coal consumed for ener gy in the United States in 2003. Consequently, changes in electricity demand have a significant impact on coal consumption and associated CO 2 emissions.

3 If emissions from international bunker fuels are included, the tr ansportation end-use sector accounted for 33 percent of U.S. emissions from fossil fuel combustion in 2003.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 31 Non-Energy Use of Fossil Fuels (118.0 Tg CO 2 Eq.)
In addition to being combusted for energy, fossil fuels ar e also consumed for non-energy uses (NEUs). Fuels are used in the industrial and transportation end-use sectors for a variety of NEUs, including application as solvents, lubricants, and waxes, or as raw materials in the manuf acture of plastics, rubber, and synthetic fibers. Carbon dioxide emissions arise from non-energy uses via several pathways. Emissions may occur during the manufacture of a product, as is the case in producing plastics or rubbe r from fuel-derived feedstoc ks. Additionally, emissions may occur during the product’s lifetime, such as during solvent use. Where appropriate data and methodologies are available, NEUs of fossil fuels used for industrial pro cesses are reported in the Industrial Processes sector. Emissions in 2003 for non-energy uses of fossil fuels were 118.0 Tg CO 2 Eq., which constituted 2 percent of overall fossil fuel CO 2 emissions and 2 percent of total national CO 2 emissions, approximately the same proportion as in 1990.
Waste Combustion (19.2 Tg CO 2 Eq.)
Combustion is used to manage about 7 to 17 percent of th e municipal solid wastes generated in the United States. The burning of garbage and non-hazardous solids, referred to as municipal solid waste, as well as the burning of hazardous waste, is usually performed to recover ener gy from the waste material s. Carbon dioxide and N 2 O emissions arise from the organic materials found in these wastes. Within municipal solid waste, many products contain carbon of biogenic origin (e.g., paper, yard trimmings), and the CO 2 emissions from their combustion are accounted for under the Land Use Change and Forestry chapter. Several components of municipal solid waste, such as plastics, synthetic rubber, synthetic fibers, and carbon black
, are of fossil fuel origin, and are included as sources of CO 2 and N 2 O emissions. In 2003, CO 2 emissions from waste combustion amounted to 18.8 Tg CO 2 Eq., while N 2 O emissions amounted to 0.5 Tg CO 2 Eq.
Natural Gas Flaring (6.0 Tg CO 2 Eq.)
The flaring of natural gas from oil wells results in the release of CO 2 emissions. Natural gas is flared from both onshore and off-shore oil wells to relieve rising pressure or to dispose of small quantities of gas that are not commercially marketable. In 2003, flaring accounted for approxima tely 0.1 percent of U.S. CO 2 emissions.

Natural Gas Systems (125.9 Tg CO 2 Eq.)
Methane is the major component of na tural gas. Fugitive emissions of CH 4 occur throughout the production, processing, transmission, and distribution of natural gas. Because natu ral gas is often found in conjunction with petroleum deposits, leakage from petroleum systems is also a source of emissions. Emissions vary greatly from facility to facility and are largely a f unction of operation and maintenance pro cedures and equipment conditions. In 2003, CH 4 emissions from U.S. natural gas systems accounted for approximately 23 percent of U.S. CH 4 emissions.

Coal Mining (53.8 Tg CO 2 Eq.)
Produced millions of years ago during the formation of coal, CH 4 trapped within coal seams and surrounding rock strata is released when the coal is mined. The quantity of CH 4 released to the atmosphere during coal mining operations depends primarily upon the type of coal and the method and rate of mining.

Methane from surface mines is emitted dir ectly to the atmosphere as the rock strata overlying the coal seam are removed. Because CH 4 in underground mines is explosive at concentrations of 5 to 15 percent in air, most active underground mines are required to vent this methane, typically to the atmosphere. At some mines, CH 4 -recovery systems may supplement these ventila tion systems. Recovery of CH 4 in the United States has increased in recent years. During 2003, coal mining activities emitted 10 percent of U.S. CH 4 emissions. From 1990 to 2003, emissions from this source decreased by 34 percent due to increased use of the CH 4 collected by mine degasification systems and a general shift toward surface mining.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 32 Petroleum Systems (17.1 Tg CO 2 Eq.)
Petroleum is often found in the same geological structures as natural gas, and the two are often retrieved together. Crude oil is saturated with many lighter hydrocarbons, in cluding methane. When the oil is brought to the surface and processed, many of the dissolved lighter hydrocarbons (as well as water) are removed through a series of highpressure and low-pressure separators. The remaining hydrocarbons in the o il are emitted at various points along the system. Methane emissions from the components of petroleu m systems generally occur as a result of system leaks, disruptions, and routine maintenance. In 2003, emissions from petroleum systems were just over 3 percent of U.S. CH 4 emissions.

Mobile Combustion (44.8 Tg CO 2 Eq.)

Mobile combustion results in N 2 O and CH 4 emissions. Nitrous oxide is a pr oduct of the reaction that occurs between nitrogen and oxygen dur ing fuel combustion. The quantity emitted varies according to the type of fuel, technology, and pollution control device used, as well as ma intenance and operating practices. For example, some types of catalytic converters installed to reduce motor vehicle pollution can promote the formation of N 2 O. In 2003, N 2 O emissions from mobile combustion were 42.1 Tg CO 2 Eq. (11 percent of U.S. N 2 O emissions). From 1990 to 2003, N 2 O emissions from mobile combustion decreased by about 4 percent.

In 2003, CH 4 emissions were estimated to be 2.7 Tg CO 2 Eq. The combustion of gasoline in highway vehicles was responsible for the majority of the CH 4 emitted from mobile combustion.

Stationary Combustion (20.5 Tg CO 2 Eq.)
Stationary combustion results in N 2 O and CH 4 emissions. In 2003, N 2 O emissions from stationary combustion accounted for 13.8 Tg CO 2 Eq. (4 percent of U.S. N 2 O emissions). From 1990 to 2003, N 2 O emissions from stationary combustion increased by 13 percent, due to increased fuel consumption. In 2003, CH 4 emissions were 6.7 Tg CO 2 Eq. (1 percent of U.S. CH 4 emissions). The majority of CH 4 emissions from stationary combustion resulted from the burning of wood in the residential end-use sector.

Abandoned Coal Mines (6.4 Tg CO 2 Eq.)
Coal mining activities result in the emission of CH 4 into the atmosphere. However, the closure of a coal mine does not correspond with an immediate cessa tion in the release of emissions. Following an initial decline, abandoned mines can liberate CH 4 at a near-steady rate over an extended period of time, or, if flooded, produce gas for only a few years. In 2003, the emissions from abandone d coal mines constituted 1 percent of U.S. CH 4 emissions.

CO 2 from Biomass Combustion (216.8 Tg CO 2 Eq.)
Biomass refers to organically-based carbon fu els (as opposed to fossil-based). Biomass in the form of fuel wood and wood waste wa s used primarily in the industrial sector, while the transportation sector was the predominant user of biomass-based fuels, such as ethanol from corn and woody crops.

Although these fuels do emit CO 2, in the long run the CO 2 emitted from biomass consumption does not increase atmospheric CO 2 concentrations if the biogenic carbon emitted is offset by the growth of new biomass. For example, fuel wood burned one year but re-grown the next only recycles carbon, rather than creating a net increase in total atmospheric carbon. Net carbon fluxes from change s in biogenic carbon reservoirs in wooded or croplands are accounted for in the estimates for the Land-Use Change and Forestry sector. As a result, CO 2 emissions from biomass combustion have been estimated separately from fossil fuel-based emissions and are not included in the U.S. totals.

The consumption of wood biomass in the industrial, residential, electric power, and commercial end-use sectors accounted for 66, 17, 8, and 2 percent of gross CO 2 emissions from biomass combustion, respectively. Ethanol consumption in the transportation end-use sector accounted for the remaining 7 percent.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 33 International Bunker Fuels (85.1 Tg CO 2 Eq.)
Greenhouse gases emitted from the combustion of fuels us ed for international tran sport activities, termed international bunker fuels under the UNFCCC, include CO 2 , CH 4 , and N 2 O. Emissions from these activities are currently not included in national emission totals, but are re ported separately based upon location of fuel sales. The decision to report emissions from international bunker fuels se parately, instead of allocating them to a particular country, was made by the Intergovern mental Negotiating Committee in esta blishing the Framework Convention on Climate Change. These decisions are reflected in the Revised 1996 IPCC Guidelines , in which countries are requested to report emissions from ships or aircraft that depart from their ports with fuel purchased within national boundaries and are engaged in international transport separately from national totals (IPCC/UNEP/OECD/IEA 1997).

Two transport modes are addressed under the IPCC definiti on of international bunker fuel s: aviation and marine. Emissions from ground transport activities

⎯ by road vehicles and trains, ev en when crossing international borders—are allocated to the country where the fuel was loaded into the vehicle and, therefore, are not counted as bunker fuel emissions. Emissions of CO 2 , CH 4 , and N 2 O from international bunker fuel combustion were 84.2, 0.1, and 0.8 Tg CO 2 Eq. in 2003, respectively.



### Industrial Processes

Emissions are produced as a by-product of many non-ener gy-related industrial process activities. For example, industrial processes can chemically transform raw materials, which often release waste gases such as CO 2, CH 4, and N 2 O. The processes include iron and steel production, cement manufacture, ammonia manufacture and urea application, lime manufacture, limestone and dolomite use (e.g., flux stone, flue gas desulfurization, and glass manufacturing), soda ash manufacture and use, titanium dioxide production, phosphoric aci d production, ferroalloy production, CO 2 consumption, aluminum producti on, petrochemical production, s ilicon carbide production, nitric acid production, and adipic acid produc tion (see Figure 2-10). Additionally, emissions from industrial processes release HFCs, PFCs and SF 6 . Table 2-8 presents greenhouse gas emissions from Industrial Processes by source category.

Figure 2-10: 2003 Industrial Processes Chapter Greenhouse Gas Sources

Table 2-8: Emissions from Industrial Processes (Tg CO 2 Eq.) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 173.1 170.9 169.4 165.9 164.7 151.8 151.5 147.2

Iron and Steel Production 85.4 71.9 67.4 64.4 65.7 58.9 55.1 53.8 Cement Manufacture 33.3 38.3 39.2 40.0 41.2 41.4 42.9 43.0 Ammonia Manufacture & Urea Application 19.3 20.7 21.9 20.6 19.6 16.7 18.6 15.6 Lime Manufacture 11.2 13.7 13.9 13.5 13.3 12.8 12.3 13.0 Limestone and Dolomite Use 5.5 7.2 7.4 8.1 6.0 5.7 5.9 4.7 Aluminum Production 6.3 5.6 5.8 5.9 5.7 4.1 4.2 4.2 Soda Ash Manufacture and Consumption 4.1 4.4 4.3 4.2 4.2 4.1 4.1 4.1 Petrochemical Production 2.2 2.9 3.0 3.1 3.0 2.8 2.9 2.8 Titanium Dioxide Production 1.3 1.8 1.8 1.9 1.9 1.9 2.0 2.0 Phosphoric Acid Production 1.5 1.5 1.6 1.5 1.4 1.3 1.3 1.4 Ferroalloy Production 2.0 2.0 2.0 2.0 1.7 1.3 1.2 1.4 Carbon Dioxide Consumption 0.9 0.8 0.9 0.8 1.0 0.8 1.0 1.3 CH 4 2.5 2.9 2.9 2.9 2.9 2.5 2.5 2.5

Petrochemical Production 1.2 1.6 1.7 1.7 1.7 1.4 1.5 1.5 Iron and Steel Production 1.3 1.3 1.2 1.2 1.2 1.1 1.0 1.0 Silicon Carbide Production + + + + + + + + N 2 O 33.0 31.5 26.9 25.6 25.6 20.8 23.1 21.8

Nitric Acid Production 17.8 21.2 20.9 20.1 19.6 15.9 17.2 15.8Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 34 Adipic Acid Production 15.2 10.3 6.0 5.5 6.0 4.9 5.9 6.0 HFCs, PFCs, and SF 6 91.2 121.7 135.7 134.8 138.9 129.5 138.3 137.0

Substitution of Ozone Depleting Substances 0.4 46.5 56.6 65.8 75.0 83.3 91.5 99.5

Electrical Transmission and Distribution 29.2 21.7 17.1 16.4 15.6 15.4 14.7 14.1 HCFC-22 Production 35.0 30.0 40.1 30.4 29.8 19.8 19.8 12.3 Aluminum Production 18.3 11.0 9.1 9.0 9.0 4.0 5.2 3.8 Semiconductor Manufacture 2.9 6.3 7.1 7.2 6.3 4.5 4.4 4.3 Magnesium Production and Processing 5.4 6.3 5.8 6.0 3.2 2.6 2.6 3.0 Total 299.9 327.1 334.9 329.2 332.1 304.7 315.4 308.6 + Does not exceed 0.05 Tg CO 2 Eq. Note: Totals may not sum due to independent rounding. Iron and Steel Production (54.8 Tg CO 2 Eq.)
Pig iron is the product of combining iron oxi de (i.e., iron ore) and sinter with me tallurgical coke in a blast furnace. The pig iron production process, as well as the thermal processes used to create sinter and metallurgical coke, resulted in emissions of CO 2 and CH 4 . In 2003, iron and steel production resulted in 1.0 Tg CO 2 Eq. of CH 4 emissions, with the majority of the emissions coming from the pig iron production process. The majority of CO 2 emissions from iron and steel processes come from the producti on of coke for use in pig iron creation, with smaller amounts evolving from the removal of carbon from pig iron used to produce steel. CO 2 emissions from iron and steel amounted to 53.8 Tg CO 2 Eq. in 2003. From 1990 to 2003, emissions from this source decreased by 37 percent.
Cement Manufacture (43.0 Tg CO 2 Eq.)
Clinker is an intermediate product in the formation of finished Portland and masonry cement. Heating calcium carbonate (CaCO 3 ) in a cement kiln forms lime and CO 2 . The lime combines with other materials to produce clinker, and the CO 2 is released into the atmosphere. From 1990 to 2003, emissions from this source increased by 29 percent.
Ammonia Manufacture and Urea Application (15.6 Tg CO 2 Eq.)
In the United States, roughly 98 percent of synthetic ammonia is produced by catalytic steam reforming of natural gas, and the remainder is produced using naphtha (i.e., a petr oleum fraction) or the electro lysis of brine at chlorine plants (EPA 1997). The two fossil fuel-based reacti ons produce carbon monoxide and hydrogen gas. This carbon monoxide is transformed into CO 2 in the presence of a catalyst. The CO 2 is generally released into the atmosphere, but some of the CO 2 , together with ammonia, is used as a raw material in the production of urea [CO(NH 2 ) 2 ], which is a type of nitrogenous fertilizer. Th e carbon in the urea that is produced and assumed to be subsequently applied to agricultural land as a nitrogenous fertilizer is ultimately released into the environment as CO 2 . Lime Manufacture (13.0 Tg CO 2 Eq.)
Lime is used in steel making, construction, flue gas de sulfurization, and water and sewage treatment. It is manufactured by heating limestone (mostly calcium carbonate, CaCO 3 ) in a kiln, creating quicklime (calcium oxide, CaO) and CO 2 , which is normally emitted to the atmosphere.

Limestone and Dolomite Use (4.7 Tg CO 2 Eq.)
Limestone (CaCO 3 ) and dolomite (CaMg(CO 3 )) are basic raw materials used in a wide variety of industries, including construction, agriculture, chemical, and metallurgy. For example, limestone can be used as a purifier in refining metals. In the case of iron ore, limestone heated in a blast furnace reacts with impurities in the iron ore and fuels, generating CO 2 as a by-product. Limestone is also used in flue gas desulfurization systems to remove sulfur dioxide from the exhaust gases.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 35 Aluminum Production (8.0 Tg CO 2 Eq.)
Aluminum production results in emissions of CO 2 , CF 4 and C 2 F 6 . Carbon dioxide is emitted when alumina (aluminum oxide, Al 2 O 3 ) is reduced to aluminum. The reduction of the alumina occurs through electrolysis in a molten bath of natural or synthetic cryolite. The reducti on cells contain a carbon lining th at 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 th is carbon is oxidized and released to the atmosphere as CO 2 . In 2003, CO 2 emissions from aluminum production amounted to 4.2 Tg CO 2 Eq.

During the production of primary aluminum, CF 4 and C 2 F 6 are emitted as intermittent by-products of the smelting process. These PFCs are formed when fluorine from the cryolite bath comb ines with carbon from the electrolyte anode. PFC emissions from aluminum production have decreased by 79 percent between 1990 and 2003 due to emission reduction efforts by th e industry and falling domestic al uminum production. In 2003, CF 4 and C 2 F 6 emissions from aluminum production amounted to 3.8 Tg CO 2 Eq.
Soda Ash Manufacture and Consumption (4.1 Tg CO 2 Eq.)
Commercial soda ash (sodium carbonate, Na 2 CO 3 ) is used in many consumer products, such as glass, soap and detergents, paper, textiles, and food. During the manufact uring of soda ash, some natural sources of sodium carbonate are heated and transformed into a crude soda ash, in which CO 2 is generated as a by-product. In addition, CO 2 is often released when the soda ash is consumed.

Petrochemical Production (4.3 Tg CO 2 Eq.)
The production process for carbon black results in the release CO 2 emissions to the atmosphere. Carbon black is a black powder generated by the incomplete combustion of an aromatic petroleum or coal-based feedstock production. The majority of carbon black produced in the United States is consumed by the tire industry, which adds it to rubber to increase strength and abrasion resistance. Small amounts of CH 4 are also released during the production of five petrochemicals: carbon black, ethylene, ethylene dichloride, styrene, and methanol. These production processes resulted in emissions of 2.8 Tg CO 2 Eq. of CO 2 and 1.5 Tg CO 2 Eq. of CH 4 in 2003.

Titanium Dioxide Production (2.0 Tg CO 2 Eq.)
Titanium dioxide (TiO 2 ) is a metal oxide manufactured from titanium ore, and is principally used as a pigment. It is used in white paint and as a pigment in the manufacture of white paper, foods, and other products. Two processes, the chloride process and the sulfat e process, are used for making TiO 2 . Carbon dioxide is emitted from the chloride process, which uses petroleum coke and chlorine as raw materials.

Phosphoric Acid Production (1.4 Tg CO 2 Eq.)
Phosphoric acid is a basic raw material in the producti on of phosphate-based fertilizers. The phosphate rock consumed in the United States originates from both domestic mines, located primarily in Florida, North Carolina, Idaho, and Utah, and foreign mining operations in Morocco. The primary use of this material is as a basic component of a series of chemical reactions that lead to the production of phosphoric acid, as well as the byproducts CO 2 and phosphogypsum.

Ferroalloy Production (1.4 Tg CO 2 Eq.)
Carbon dioxide is emitted from the producti on of several ferroalloys. Ferroallo ys are composites of iron and other elements such as silicon, manganese, and chromium. When incorporated in alloy steels, ferroalloys are used to alter the material properties of the steel.

Carbon Dioxide Consumption (1.3 Tg CO 2 Eq.)
Many segments of the economy consume CO 2 , including food processing, beverage manufacturing, chemical processing, and a host of industrial and other miscellaneous applications. Carbon dioxide may be produced as a by-Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 36 product from the production of certain chemicals (e.g., ammoni a), from select natural gas wells, or by separating it from crude oil and natural gas. The majority of the CO 2 used in these applications is eventually released to the atmosphere.

Silicon Carbide Production (0.01 Tg CO 2 Eq.)

Small amounts of CH 4 are released during the production of silicon carbide, a material used as an industrial abrasive. Silicon carbide (SiC) is made through a reaction of quartz (SiO 2 ) and carbon (in the form of petroleum coke). Methane is produced during this reaction fro m volatile compounds in the petroleum coke. Methane emissions from silicon carbide production have declined significantly due a 67 percent decrease in silicon carbide production since 1990. In 2003, only two companies produced silicon carbide in the United States (one company produced abrasive-grade silicon carbide and the other produced a small quan tity for heat-resistant products).

Nitric Acid Production (15.8 Tg CO 2 Eq.)
Nitric acid production is an industrial source of N 2 O emissions. Used primarily to make synthetic commercial fertilizer, this raw material is also a major compone nt in the production of ad ipic acid and explosives.

Virtually all of the nitric acid manufactured in the United States is produced by the oxidation of ammonia, during which N 2 O is formed and emitted to the atmosphere. In 2003, N 2 O emissions from nitric acid production accounted for 4 percent of U.S. N 2 O emissions. From 1990 to 2003, emissions from this source category decreased by11 percent with the trend in the time series closely tracking the changes in production.

Adipic Acid Production (6.0 Tg CO 2 Eq.)
Most adipic acid produced in the United States is used to manufacture nylon 6,6. Adipic acid is also used to produce some low-temperature lubricants and to add a "ta ngy" flavor to foods. Nitrous oxide is emitted as a byproduct of the chemical synthesis of adipic acid.

In 2003, U.S. adipic acid plants emitted 2 percent of U.S. N 2 O emissions. Even though adipic acid production has increased in recent years, by 1998 a ll three major adipic acid plants in the United States had voluntarily implemented N 2 O abatement technology. As a result, emissions have decreased by 60 percent since 1990.

Substitution of Ozone Depleting Substances (99.5 Tg CO 2 Eq.)
The use and subsequent emissions of HFCs and PFCs as substitutes for ODSs have increased from small amounts in 1990 to account for 73 percent of aggregate HFC, PFC, and SF 6 emissions. This increase was in large part the result of efforts to phase-out CFCs and other ODSs in th e United States, especially the introduction of HFC-134a as a CFC substitute in refrigeration and ai r-conditioning applications. In the shor t term, this trend is expected to continue, and will likely accelerate ove r the coming decade as HCFCs, whic h are interim substitutes in many applications, are themselves phased-out under the provisions of the Copenhagen Amendments to the Montreal Protocol. Improvements in the technologies associated with the use of these gases and the introduction of alternative gases and technologies, however, may help to offset this anticipated increase in emissions.

HCFC-22 Production (12.3 Tg CO 2 Eq.)
HFC-23 is a by-product of the production of HCFC-22. Emissions from this source have decreased by 65 percent since 1990. The HFC-23 emission rate (i.e., the am ount of HFC-23 emitted per kilogram of HCFC-22 manufactured) has declined significantly since 1990, although production has been increasing.

Electrical Transmission and Di stribution Systems (14.1 Tg CO 2 Eq.)
The primary use of SF 6 is as a dielectric in electrical transmission a nd distribution systems. Fugitive emissions of SF 6 occur from leaks in and servicing of substations and circ uit breakers, especially from older equipment. The gas can also be released during equipment manufacturing, installation, servicing, and disposal. Estimated emissionsInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 37 from this source decreased by 52 percent since 1990, primarily due to higher SF 6 prices and industrial efforts to reduce emissions.

Semiconductor Manufacture (4.3 Tg CO 2 Eq.)
The semiconductor industry uses combinations of HFCs, PFCs, SF 6, and other gases for plasma etching and to clean chemical vapor deposition tools. Emissions from this source category have increased 49 percent since 1990 with the growth in the semiconductor industry and the rising intricacy of chip desi gns. However, the growth rate in emissions has slowed since 1997, and emissions actually declined between 1999 and 2003. This later reduction is due to the implementation of PFC emission reduction methods, such as process optimization.

Magnesium Production (3.0 Tg CO 2 Eq.)
Sulfur hexafluoride is also used as a protective cover gas for the casting of molten magnesium. Emissions from primary magnesium production and magnesium casting have d ecreased by 45 percent since 1990. This decrease has primarily taken place since 1999, due to a decline in the qua ntity of magnesium die cast and the closure of a U.S. primary magnesium production facility.



### Solvent and Other Product Use

Greenhouse gas emissions are produced as a by-product of various solvent and other product uses. In the United States, emissions from N 2 O Product Usage, the only source of greenhouse gas emissions from this sector, accounted for 4.8 Tg CO 2 Eq. of N 2 O, or less than 0.1 percent of total U.S. anthropogenic greenhouse gas emissions on a carbon equivalent basis in 2003 (see Table 2-9).

Table 2-9: N 2 O Emissions from Solvent and Other Product Use (Tg CO 2 Eq.) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 N 2 O 4.3 4.8 4.8 4.8 4.8 4.8 4.8 4.8

Nitrous Oxide Product Usage 4.3 4.8 4.8 4.8 4.8 4.8 4.8 4.8 Total 4.3 4.8 4.8 4.8 4.8 4.8 4.8 4.8

N 2 O Product Usage (4.8 Tg CO 2 Eq.)
Nitrous oxide is used in carrier gases with oxygen to administer more potent inhalation anesthetics for general anesthesia and as an anesthetic in various dental and veterinary applications. As such, it is used to treat short-term pain, for sedation in minor elective surgeries and as an induction anesthetic. The second main use of N 2 O is as a propellant in pressure and aerosol products, the largest application being pressure-packaged whipped cream. In 2003, N 2 O emissions from product usage constituted approximately 1 percent of U.S. N 2 O emissions. From 1990 to 2003, emissions from this source category increased by 11 percent.


### Agriculture

Agricultural activities contribute directly to emissions of greenhouse gases thr ough a variety of processes, including the following source categories: enteric fermentation in domestic livestock, livestock manure management, rice cultivation, agricultural soil management, and field burning of agricultural residues.

In 2003, agricultural activities were res ponsible for emissions of 433.3 Tg CO 2 Eq., or 6 percent of total U.S. greenhouse gas emissions. Methane and N 2 O were the primary greenhouse gases emitted by agricultural activities. Methane emissions from enteric fermentation and manure ma nagement represented about 21 percent and 7 percent of total CH 4 emissions from anthropogenic activities, respectivel y in 2003. Agricultural soil management activities such as fertilizer application and other cropping practi ces were the largest source of U.S. N 2 O emissions in 2003, accounting for 67 percent. Table 2-10 presents emission estimates for the Agriculture sector.

Figure 2-11: 2003 Agriculture Chapter Greenhouse Gas SourcesInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 38 Table 2-10: Emissions from Agriculture (Tg CO 2 Eq.) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CH 4 156.9 163.0 164.2 164.6 162.0 161.9 161.5 161.8

Enteric Fermentation 117.9 118.3 116.7 116.8 115.6 114.5 114.6 115.0 Manure Management 31.2 36.4 38.8 38.8 38.1 38.9 39.3 39.1 Rice Cultivation 7.1 7.5 7.9 8.3 7.5 7.6 6.8 6.9 Field Burning of Agricultural

Residues 0.7 0.8 0.8 0.8 0.8 0.8 0.7 0.8 N 2 O 269.6 269.8 285.6 261.3 282.1 275.6 270.9 271.5

Agricultural Soil Management 253.0 252.0 267.7 243.4 263.9 257.1 252.6 253.5 Manure Management 16.3 17.3 17.4 17.4 17.8 18.0 17.9 17.5 Field Burning of Agricultural

Residues 0.4 0.4 0.5 0.4 0.5 0.5 0.4 0.4 Total 426.5 432.8 449.8 425.9 444.1 437.5 432.4 433.3 Note: Totals may not sum due to independent rounding. Enteric Fermentation (115.0 Tg CO 2 Eq.)
During animal digestion, CH 4 is produced through the process of enteric fermentation, in which microbes residing in animal digestive systems break down food. Ruminants, which include cattle, buffalo, sheep, and goats, have the highest CH 4 emissions among all animal types because they ha ve a rumen, or large fore-stomach, in which CH 4 - producing fermentation occurs. Non-ruminant domestic anim als, such as pigs and horses, have much lower CH 4 emissions. In 2003, enteric fermentation was the source of about 21 percent of U.S. CH 4 emissions, and more than 71 percent of the CH 4 emissions from agriculture. From 1990 to 2003, emissions from this source decreased by 2 percent. Emissions from enteric fermentation have decreasing significantly since 1995, primarily due to declining dairy cow and beef cattle populations as a result of improved efficiency in m ilk and beef production.

Manure Management (56.7 Tg CO 2 Eq.)

Both CH 4 and N 2 O resulted from manure management. The decomposition of organic animal waste in an anaerobic environment produces CH 4 . The most important factor affecting the amount of CH 4 produced is how the manure is managed, because certain types of storage and treatme nt systems promote an oxyge n-free environment. In particular, liquid systems tend to encourage anaerobic conditions and produce significant quantities of CH 4 , whereas solid waste management approaches produce little or no CH 4 . Higher temperatures and moist climatic conditions also promote CH 4 production.

Emissions from manure management were 39.1 Tg CO 2 Eq., or about 7 percent of U.S. CH 4 emissions in 2003 and 24 percent of the CH 4 emissions from the agriculture sector. From 1990 to 2003, emissions from this source increased by 26 percent. The bulk of this increase was fro m swine and dairy cow manure, and is attributed to the shift in the composition of th e swine and dairy industries towards larger facilities. Larger swine and dairy farms tend to use liquid management systems.

Nitrous oxide is also produced as part of microbial n itrification and denitrification processes in managed and unmanaged manure. Emissions from unmanaged manure are accounted for within the agricultural soil management source category. Total N 2 O emissions from managed manure syst ems in 2003 accounted for 17.5 Tg CO 2 Eq., or 5 percent of U.S. N 2 O emissions. From 1990 to 2003, emissions from this source category increased by 8 percent, primarily due to increases in swine and poultry populations over the same time period.

Rice Cultivation (6.9 Tg CO 2 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 devel op and the organic matter in the soil decomposes, releasing CH 4 to the atmosphere, primarily through the rice plants. In 2003, rice cultivation was the source of 1 percent of U.S. CH 4 emissions, and about 4 percent of U.S. CH 4 emissions from agriculture. Emissi on estimates from this source have decreased about 3 percent since 1990.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 39 Field Burning of Agricultural Residues (1.2 Tg CO 2 Eq.)
Burning crop residue releases N 2 O and CH 4 . Because field burning is not a co mmon debris clearing method used in the United States, it was responsible for only 0.1 percent of U.S. CH 4 (0.8 Tg CO 2 Eq.) and N 2 O (0.4 Tg CO 2 Eq.) emissions in 2003.

Agricultural Soil Management (253.5 Tg CO 2 Eq.)
Nitrous oxide is produced naturally in soils through microbi al processes of nitrification and denitrification. A number of anthropogenic activities add to the amount of nitrogen available to be emitted as N 2 O by microbial processes. These activities may add nitroge n to soils either directly or indirec tly. Direct additions occur through the application of synthetic and organic fertilizers; production of nitrogen-fixing crops and fo rages; the application of livestock manure, crop residues, and sewage sludge; cultiva tion 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 applie d to or deposited on soils as fertilizer, livestock manure, and sewage sludge.

In 2003, agricultural soil management accounted for 67 percent of U.S. N 2 O emissions. From 1990 to 2003, emissions from this source increased slightly as fer tilizer consumption, manure production, and production of nitrogen-fixing and other crops rose. Year-to-year fluctuations are larg ely a reflection of annual variations in climate, synthetic fertilizer c onsumption, and crop production. 

### Land-Use Change and Forestry

When humans alter the terrestrial biosphere through land us e, changes in land use, and land management practices, they also alter the background carbon fluxes between bioma ss, soils, and the atmosphere. Forest management practices, tree planting in urban areas, the management of agricultural soils, and the landfilling of yard trimmings and food scraps have resulted in a ne t uptake (sequestration) of carbon in the United States, which offset about 12 percent of total U.S. gross CO 2 emissions in 2003. Forests (including vegetation, soils, and harvested wood) accounted for approximately 91 percent of total 2003 sequestration, urban trees accounted for 7 percent, agricultural soils (including mineral and organic so ils and the application of lime) account ed for 1 percent, and landfilled yard trimmings and food scraps accounted for 1 percent of the to tal sequestration in 2003. The net forest sequestration is a result of net forest growth and increasing forest area, as well as a net accumulation of carbon stocks in harvested wood pools. The net sequestration in urban forests is a result of net tree growth in these areas. In agricultural soils, mineral soils account for a net carbon sink that is approximately one and a third times larger than the sum of emissions from organic soils and liming. The mineral soil carbon sequestration is largely due to conversion of cropland to permanent pastures and hay production, a re duction in summer fallow areas in semi-arid areas, an increase in the adoption of conservation tillage practices, a nd an increase in the amounts of organic fertilizers (i.e., manure and sewage sludge) applied to agriculture lands. The landfilled ya rd trimmings and food scraps net sequestration is due to the long-te rm accumulation of yard trimming carbon and food scraps in landfills.

Land use, land-use change, and forestry activities in 2003 resulted in a net carbon sequestration of 828.0 Tg CO 2 Eq. (Table ES-5). This represents an offset of approximately 14 percent of total U.S. CO 2 emissions. Total land use, land-use change, and forestry net carbon sequestrati on declined by approximately 21 percent between 1990 and 2003. This decline was primarily due to a decline in the rate of net car bon accumulation in forest carbon stocks. Annual carbon accumulation in landfilled yard trimmings and food scraps also slowed over this period, as did annual carbon accumulation in agricultural soils. As descri bed above, the constant ra te of carbon accumulation in urban trees is a reflection of limited underlying data (i.e ., this rate represents an average for 1990 through 1999).

Table 2-11: Net CO 2 Flux from Land-Use Change and Forestry (Tg CO 2 Eq.) Sink Category 1990 1997 1998 1999 2000 2001 2002 2003 Forest Land Remaining Forest Land (949.3) (851.0) (805.5) (751.7) (747.9) (750.9) (751.5) (752.7)

Changes in Forest Carbon Stocks (949.3) (851.0) (805.5) (751.7) (747.9) (750.9) (751.5) (752.7) Cropland Remaining Cropland (8.1) (7.4) (4.3) (4.3) (5.7) (7.1) (6.2) (6.6)

Changes in Agricultural Soil Carbon (8.1) (7.4) (4.3) (4.3) (5.7) (7.1) (6.2) (6.6)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 40 Stocks Settlements Remaining Settlements (84.7) (71.6) (71.2) (70.0) (68.9) (68.9) (68.8) (68.7)

Urban Trees (58.7) (58.7) (58.7) (58.7) (58.7) (58.7) (58.7) (58.7) Landfilled Yard Trimmings and Food

Scraps (26.0) (12.9) (12.5) (11.4) (10.2) (10.3) (10.2) (10.1) Total (1,042.0) (930.0) (881.0) (826.1) (822.4) (826.9) (826.5) (828.0)

Note: Parentheses indicate net se questration. Totals may not sum due to independent rounding.

Land use, land-use change, and forestry activ ities in 2003 also resulted in emissions of N 2 O (6.4 Tg CO 2 Eq., Table 2-12). Total N 2 O emissions from the application of fertilizers to forests and settlements increased by approximately 14 percent between 1990 and 2003.

Table 2-12: N 2 O Emissions from Land-Use Change and Forestry (Tg CO 2 Eq.) Sink Category 1990 1997 1998 1999 2000 2001 2002 2003 Forest Land Remaining Forest Land 0.1 0.3 0.4 0.5 0.4 0.4 0.4 0.4

N 2 O Fluxes from Soils 0.1 0.3 0.4 0.5 0.4 0.4 0.4 0.4 Settlements Remaining Settlements 5.5 6.1 6.1 6.2 6.0 5.8 6.0 6.0

N 2 O Fluxes from Soils 5.5 6.1 6.1 6.2 6.0 5.8 6.0 6.0 Total 5.6 6.4 6.5 6.6 6.3 6.2 6.4 6.4

Note: Totals may not sum due to independent rounding. Forest Land Remaining Forest Land (0.4 Tg CO 2 Eq.)
As with other agricultural applications, forests may be fertilized to stimulate growth rates. This relative magnitude of the impact of this practice is lim ited, however, because forests are genera lly only fertilized twice during their life cycles, and applications account for no more than one percent of total U.S. fertilizer applications annually. In terms of trends, however, N 2 O emissions from forest soils for 2003 were almost 7 times higher than in 1990, primarily the result of an increase in fer tilized area of pine plantations in the s outheastern U.S. This source accounts for approximately 0.1 percent of total U.S. N 2 O emissions.

Settlements Remaining Settlements (6.0 Tg CO 2 Eq.)
Of the fertilizers applied to soils in the U.S., approximately 10 percent are applied to lawns, golf courses, and other landscaping within settled areas. In 2003, N 2 O emissions from settlement soils constituted approximately 1.6 percent of total U.S N 2 O emissions. There has been an overall increase in emissions of 9 percent since 1990, a result of a general increase in the applications of synthetic fertilizers.



### Waste

Waste management and treatment activities are sources of greenhouse gas emissions (see Figure 2-12). Landfills were the largest source of anthropogenic methane (CH 4 ) emissions, accounting for 24 percent of total U.S. CH 4 emissions. 4 Wastewater treatment systems are a poten tially significant source of nitrous oxide (N 2 O) emissions; however, methodologies are not currently available to develop a complete estimate. Nitrous oxide emissions from the treatment of the human sewage component of wastewater were estimated, however, using a simplified methodology. Nitrogen oxide (NO x ), carbon monoxide (CO), and non-me thane volatile organic compounds (NMVOCs) are also emitted by waste activities. A summary of greenhouse gas and ambien t air pollutant emissions from the Waste sector is presented in Table 2-13.

Figure 2-12: 2003 Waste Sector Greenhouse Gas Sources

4 Landfills also store carbon, due to incomplete degradation of organic materials such as wood products and yard trimmings, as described in the Land-Use Change and Forestry chapter.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 41 Overall, in 2003, waste activities generated emissions of 183.8 Tg CO 2 Eq., or 3 percent of total U.S. greenhouse gas emissions.

Table 2-13: Emissions from Waste (Tg CO 2 Eq.) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CH 4 197.1 179.0 171.0 167.7 165.0 160.9 162.6 167.9

Landfills 172.2 147.4 138.5 134.0 130.7 126.2 126.8 131.2 Wastewater Treatment 24.8 31.7 32.6 33.6 34.3 34.7 35.8 36.8 N 2 O 13.0 14.7 15.0 15.4 15.6 15.6 15.7 15.9

Human Sewage 13.0 14.7 15.0 15.4 15.6 15.6 15.7 15.9 Total 210.1 193.7 186.0 183.1 180.6 176.5 178.3 183.8 Note: Totals may not sum due to independent rounding.

Landfills (131.2 Tg CO 2 Eq.)
Landfills are the largest anthropogenic source of CH 4 emissions in the United States, accounting for approximately 24 percent of total CH 4 emissions in 2003. In an environment where the oxygen content is low or zero, anaerobic bacteria can decompose organic material s, such as yard waste, household wast e, food waste, and paper, resulting in the generation of CH 4 and biogenic CO 2 . Site-specific factors, such as waste composition, moisture, and landfill size, influence the level of methane generation.

From 1990 to 2003, net CH 4 emissions from landfills decreased by approximately 24 percent, with small increases occurring in some interim years. This downward trend in overall emissions is the result of increases in the amount of landfill gas collected and combusted by landfill operators, which has more than offset the additional CH 4 emissions resulting from an increase in the am ount of municipal solid waste landfilled.

Wastewater Treatment (36.8 Tg CO 2 Eq.)
Wastewater from domestic sources (i.e., municipal sewage) and industrial sources is treated to remove soluble organic matter, suspended solids, pathogenic organisms and chemical contaminants. Soluble organic matter is generally removed using biological processes in which mi croorganisms consume the organic matter for maintenance and growth. Microorganisms can biodegrade soluble organic material in wastewater under aerobic or anaerobic conditions, with the latter condition producing CH 4 . During collection and treat ment, wastewater may be accidentally or deliberately manage d under anaerobic conditions. In add ition, the sludge may be further biodegraded under aerobic or anaer obic conditions. Untreated wa stewater may also produce CH 4 if contained under anaerobic conditions. In 2003, wastewater treatment was the source of approximately 7 percent of U.S. CH 4 emissions.

Human Sewage (Domestic Wastewater) (15.9 Tg CO 2 Eq.)
Domestic human sewage is usually mixed with other household wastewater, which includes shower drains, sink drains, washing machine effluent, etc., and transported by a co llection system to either a di rect discharge, an on-site or decentralized or centralized wastewater treatment system. After processi ng, treated effluent may be discharged to a receiving water environment (e.g ., river, lake, estuary, etc.), applied to soils, or disposed of below the surface. Nitrous oxide may be generated during bot h nitrification and denitrification of the nitrogen present, usually in the form of urea, ammonia, and proteins. Emissions of N 2 O from treated human sewage discharged into aquatic environments accounted for 4 percent of U.S. N 2 O emissions in 2003. From 1990 to 2003, emissions from this source category increased by 22 percent.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 42 

### 2.2. Emissions by Economic Sector

Throughout this report, emission estimates are grouped into six sectors (i.e., chapters) defined by the IPCC: Energy, Industrial Processes, Solvent Use, Agriculture, Land-Use Change and Forestry, and Waste. While it is important to use this characterization for consistency with UNFCCC reporting guidelines, it is also useful to allocate emissions into more commonly used sectoral categories. This section reports emissions by the following “economic sectors”: Residential, Commercial, Industry, Transporta tion, Electricity Generation, and Agriculture, as well as U.S. Territories. Using this categorization, emissions from electricity generation accounted for the largest portion (33 percent) of U.S. greenhouse gas emissions in 2003. Transportation activities, in aggregate, accounted for the second largest portion (27 percent). Additional discussi on and data on these two ec onomic sectors is provided below.

Emissions from industry accounted for 19 percent of U.S. greenhouse gas emissions in 2003. In contrast to electricity generation and tran sportation, emissions from industry have dec lined over the past decade, as structural changes have occurred in the U.S. economy (i.e., shifts from a manufacturing-based to a service-based economy), fuel switching has occurred, and efficiency improvements ha ve been made. The residential, agriculture, commercial economic sectors, and U.S. territories, contributed the re maining 20 percent of emissions. The residential economic sector accounted for approximately 6 percent, and primarily consisted of CO 2 emissions from fossil fuel combustion. Activities related to agri culture accounted for roughly 7 percent of U.S. emissions, but unlike all other economic sectors these emissions were dominated by non-CO 2 emissions. The commercial sector accounted for about 7 percent of emissions, while U.S. territo ries accounted for 1 percent of total emissions.

Carbon dioxide was also emitted and seque stered by a variety of activities rela ted to forest management practices, tree planting in urban areas, the management of agricultural soils, and landfilling of yard trimmings.

Table 2-14 presents a detailed breakdown of emissions from each of these econom ic sectors by source category, as they are defined in this report. Figure 2-13 shows the trend in emissions by sector from 1990 to 2003.

Figure 2-13: Emissions Allocated to Economic Sectors

Table 2-14: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO 2 Eq. and Percent of Total in 2003) Sector/Source 1990 1997 1998 1999 2000 2001 2002 2003 Percent a Electricity Generation 1,841.8 2,104.6 2,186.8 2,197.3 2,299.0 2,254.9 2,269.7 2,296.2 33.3%

CO 2 from Fossil Fuel

Combustion 1,790.3 2,051.9 2,139.0 2,149.3 2,252.1 2,207.8 2,223.0 2,250.5 32.6% Stationary Combustion d 8.1 9.3 9.5 9.5 10.0 9.7 9.8 10.0 0.1% Electrical Transmission and

Distribution c 29.2 21.7 17.1 16.4 15.6 15.4 14.7 14.1 0.2% Waste Combustion b 11.3 18.1 17.4 18.0 18.3 19.2 19.2 19.2 0.3% Limestone and Dolomite

Use 2.8 3.6 3.7 4.0 3.0 2.9 2.9 2.4 + Transportation 1,506.8 1,693.0 1,728.7 1,790.0 1,839.6 1,819.8 1,851.6 1,864.4 27.0%

CO 2 from Fossil Fuel

Combustion 1,446.8 1,603.3 1,633.4 1,690.8 1,737.7 1,719.7 1,752.3 1,767.2 25.6% Mobile Combustion d 48.1 58.7 58.7 57.7 56.1 51.6 48.1 44.3 0.6% Substitution of ODS e + 19.4 24.4 29.3 33.8 37.4 40.4 42.7 0.6% Non-Energy Use of Fuels 11.9 11.6 12.1 12.3 12.1 11.1 10.9 10.2 0.1% Industry 1,446.1 1,509.1 1,470.6 1,427.9 1,431.8 1,371.0 1,365.7 1,331.4 19.3%

CO 2 from Fossil Fuel

Combustion 836.5 905.4 853.9 828.0 854.6 827.9 824.3 806.3 11.7% Non-Energy Use of Fuels 90.4 102.6 117.0 121.8 101.7 103.7 102.6 101.9 1.5% Stationary Combustion 5.3 5.9 5.5 5.5 5.6 5.2 5.3 5.3 0.1%Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 43 Coal Mining 81.9 62.6 62.8 58.9 56.2 55.6 52.4 53.8 0.8% Abandoned Coal Mines 6.1 8.1 7.2 7.3 7.7 6.9 6.4 6.4 0.1% Natural Gas Systems 128.3 133.6 131.8 127.4 132.1 131.8 130.6 125.9 1.8% Petroleum Systems 20.0 18.8 18.5 17.8 17.6 17.4 17.1 17.1 0.2% Natural Gas Flaring 5.8 7.9 6.6 6.9 5.8 6.1 6.2 6.0 0.1% Titanium Dioxide

Production 1.3 1.8 1.8 1.9 1.9 1.9 2.0 2.0 + Aluminum Production h 24.7 16.6 14.8 14.9 14.7 8.1 9.5 8.0 0.1% Iron and Steel Production f 86.7 73.1 68.6 65.5 66.9 60.0 56.1 54.8 0.8% Ferroalloys 2.0 2.0 2.0 2.0 1.7 1.3 1.2 1.4 + Ammonia Manufacture 19.3 20.7 21.9 20.6 19.6 16.7 18.6 15.6 0.2% Cement Manufacture 33.3 38.3 39.2 40.0 41.2 41.4 42.9 43.0 0.6% Lime Manufacture 11.2 13.7 13.9 13.5 13.3 12.8 12.3 13.0 0.2% Limestone and Dolomite

Use 2.8 3.6 3.7 4.0 3.0 2.9 2.9 2.4 + Soda Ash Manufacture and

Consumption 4.1 4.4 4.3 4.2 4.2 4.1 4.1 4.1 0.1% Carbon Dioxide

Consumption 0.9 0.8 0.9 0.8 1.0 0.8 1.0 1.3 + Petrochemical Production 3.4 4.6 4.7 4.8 4.7 4.2 4.4 4.3 0.1% Silicon Carbide Production + + + + + + + + + Phosphoric Acid Production 1.5 1.5 1.6 1.5 1.4 1.3 1.3 1.4 + Adipic Acid 15.2 10.3 6.0 5.5 6.0 4.9 5.9 6.0 0.1% Nitric Acid 17.8 21.2 20.9 20.1 19.6 15.9 17.2 15.8 0.2% N 2 O Product Usage 4.3 4.8 4.8 4.8 4.8 4.8 4.8 4.8 0.1% HCFC-22 Production g 35.0 30.0 40.1 30.4 29.8 19.8 19.8 12.3 0.2% Semiconductor

Manufacture e 2.9 6.3 7.1 7.2 6.3 4.5 4.4 4.3 0.1% Magnesium Production and

Processing c 5.4 6.3 5.8 6.0 3.2 2.6 2.6 3.0 + Substitution of ODS e 0.1 4.1 5.1 6.4 7.4 8.4 9.7 11.2 0.2% Agriculture 473.3 492.0 508.4 486.9 495.3 488.6 485.6 486.4 7.0%

CO 2 from Fossil Fuel

Combustion 46.3 58.4 57.6 60.0 50.4 50.3 52.3 52.2 0.8% Stationary Combustion d + + + + + + + + + Mobile Combustion d 0.4 0.5 0.5 0.5 0.4 0.4 0.5 0.5 + Enteric Fermentation 117.9 118.3 116.7 116.8 115.6 114.5 114.6 115.0 1.7% Manure Management d 47.4 53.7 56.2 56.2 55.9 56.9 57.3 56.7 0.8% Rice Cultivation 7.1 7.5 7.9 8.3 7.5 7.6 6.8 6.9 0.1% Agricultural Residue

Burning d 1.1 1.2 1.2 1.2 1.2 1.2 1.1 1.2 + Agricultural Soil

Management 253.0 252.0 267.7 243.4 263.9 257.1 252.6 253.5 3.7% Forest Soil Fertilization 0.1 0.3 0.4 0.5 0.4 0.4 0.4 0.4 + Commercial 435.4 445.2 424.2 426.8 440.7 431.4 440.2 453.5 7.0%

CO 2 from Fossil Fuel

Combustion 224.2 237.2 219.7 222.3 235.2 226.7 230.0 234.0 3.4% Stationary Combustion d 1.1 1.1 1.1 1.1 1.2 1.0 1.1 1.1 + Substitution of ODS d + 13.1 17.4 20.3 23.8 27.1 30.8 34.7 0.5% Landfills 172.2 147.4 138.5 134.0 130.7 126.2 126.8 131.2 1.9% Human Sewage 13.0 14.7 15.0 15.4 15.6 15.6 15.7 15.9 0.2% Wastewater Treatment 24.8 31.7 32.6 33.6 34.3 34.7 35.8 36.8 0.5% Residential 350.9 391.0 358.4 379.5 399.7 387.1 391.6 406.1 5.9%

CO 2 from Fossil Fuel

Combustion 339.6 370.6 338.6 359.3 379.1 367.0 371.4 385.1 5.6%Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 44 Stationary Combustion c 5.5 4.4 4.0 4.3 4.5 4.0 3.6 3.9 0.1% Substitution of ODS e 0.3 9.9 9.6 9.8 10.1 10.3 10.6 11.0 0.2% Settlement Soil Fertilization 5.5 6.1 6.1 6.2 6.0 5.8 6.0 6.0 0.1% U.S. Territories 33.8 42.7 42.7 43.9 47.0 54.1 53.6 62.3 0.9%

CO 2 from Fossil Fuel

Combustion 33.8 42.7 42.7 43.9 47.0 54.1 53.6 62.3 0.9% Total 6,088.1 6,677.5 6,719.7 6,752.2 6,953.2 6,806.9 6,858.1 6,900.2 100.0% Sinks (1,042.0) (930.0) (881.0) (826.1) (822.4) (826.9) (826.5) (828.0) -12.0%

Forests (949.3) (851.0) (805.5) (751.7) (747.9) (750.9) (751.5) (752.7) -10.9% Urban Trees (58.7) (58.7) (58.7) (58.7) (58.7) (58.7) (58.7) (58.7) -0.9% Agricultural Soils (8.1) (7.4) (4.3) (4.3) (5.7) (7.1) (6.2) (6.6) -0.1% Landfilled Yard Trimmings (26.0) (12.9) (12.5) (11.4) (10.2) (10.3) (10.2) (10.1) -0.1% Net Emissions (Sources and

Sinks) 5,046.1 5,747.5 5,838.8 5,926.1 6,130.8 5,980.1 6,031.6 6,072.2 Note: Includes all emissions of CO 2 , CH 4 , N 2 O, HFCs, PFCs, and SF 6 . Parentheses indicate negativ e values (or sequestration). Totals may not sum due to independent rounding. ODS (Ozone Depleting Substances) + Does not exceed 0.05 Tg CO 2 Eq. or 0.05%. - Not applicable.

a Percent of total emissions for year 2003. b Includes both CO 2 and N 2 O.

c SF 6 emitted. d Includes both CH 4 and N 2 O.

e May include a mixture of HFCs, PFCs, and SF 6 . f Includes both CH 4 and CO 2 . g HFC-23 emitted. h Includes both CO 2 and PFCs.



### Emissions with Electricity Distr ibuted to Economic Sectors

It can also be useful to view greenhouse gas emissions from economic sectors with emissions related to electricity generation distributed into end-use categories (i.e., emi ssions from electricity genera tion are allocated to the economic sectors in which the electricity is consumed). The generation, transmission, and distribution of electricity, which is the largest economic sector in the United Stat es, accounted for 33 percent of total U.S. greenhouse gas emissions in 2003. Emissions increased by 25 percent since 1990, as electricity demand grew and fossil fuels remained the dominant energy source for generation. The electricity generation sector in the United States is composed of traditional electric utilities as well as othe r entities, such as power marketers and nonutility power producers. The majority of electricity generated by these entities was through th e combustion of coal in boilers to produce high-pressure steam that is passed through a turbine. Table 2-15 provides a detailed summary of emissions from electricity generation-related activities.

Table 2-15: Electricity Generation-Related Greenhouse Gas Emissions (Tg CO 2 Eq.) Gas/Fuel Type or Source 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 1,804.0 2,073.3 2,159.9 2,171.0 2,273.1 2,229.4 2,244.8 2,271.7

CO 2 from Fossil Fuel Combustion 1,790.3 2,051.9 2,139.0 2,149.3 2,252.1 2,207.8 2,223.0 2,250.5 Coal 1,513.0 1,758.4 1,786.4 1,792.4 1,880.0 1,817.4 1,839.7 1,876.3 Natural Gas 176.0 218.9 248.0 259.9 280.7 289.1 305.6 277.6 Petroleum 101.0 74.3 104.3 96.7 91.0 100.9 77.4 96.3 Geothermal 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.3 Waste Combustion 10.9 17.8 17.1 17.6 18.0 18.8 18.8 18.8 Limestone and Dolomite Use 2.8 3.6 3.7 4.0 3.0 2.9 2.9 2.4 CH 4 0.6 0.6 0.7 0.7 0.7 0.7 0.7 0.7

Stationary Combustion* 0.6 0.6 0.7 0.7 0.7 0.7 0.7 0.7 N 2 O 8.0 9.0 9.2 9.2 9.6 9.4 9.5 9.8

Stationary Combustion* 7.6 8.6 8.9 8.9 9.3 9.0 9.1 9.3Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 45 Waste Combustion 0.4 0.4 0.3 0.3 0.4 0.4 0.5 0.5 SF 6 29.2 21.7 17.1 16.4 15.6 15.4 14.7 14.1

Electrical Transmission and Distribution 29.2 21.7 17.1 16.4 15.6 15.4 14.7 14.1 Total 1,841.8 2,104.6 2,186.8 2,197.3 2,299.0 2,254.9 2,269.7 2,296.2 Note: Totals may not sum due to independent rounding. * Includes only stationary combustion emissions related to the generation of electricity.

To distribute electricity emissions among economic end-use sectors, emissions from the source categories assigned to the electricity generation sector were allocated to th e residential, commercial, industry, transportation, and agriculture economic sectors according to retail sales of electricity (EIA 2004a and Duffield 2004). These three source categories include CO 2 from fossil fuel combustion, CH 4 and N 2 O from stationary sources, and SF 6 from electrical transmission and distribution systems. 5

When emissions from electricity are di stributed among these sectors, industry accounts for the largest share of U.S. greenhouse gas emissions (30 percent). Emissions from the residential and commercial sectors also increase substantially due to their relatively large share of electricity consumption. Transportation activities remain the second largest contributor to emissions. In all sectors except agriculture, CO 2 accounts for more than 75 percent of greenhouse gas emissions, primarily from the combustion of fossil fuels.

Table 2-16 presents a detailed breakdow n of emissions from each of these ec onomic sectors, with emissions from electricity generation distributed to them. Figure 2-14 shows the trend in these emissions by sector from 1990 to 2003.

Figure 2-14: Emissions with Electricity Distributed to Economic Sectors

Table 2-16: U.S Greenhouse Gas Emissions by “Economic Sector” and Gas with Electricity-Related Emissions Distributed (Tg CO 2 Eq.) and Percent of Total in 2003 Sector/Gas 1990 1997 1998 1999 2000 2001 2002 2003 Percent a Industry 2,075.7 2,247.3 2,223.2 2,190.1 2,207.7 2,074.0 2,062.9 2,040.1 29.6% Direct Emissions 1,446.1 1,509.1 1,470.6 1,427.9 1,431.8 1,371.0 1,365.7 1,331.4 19.3%

CO 2 1,103.0 1,183.2 1,143.2 1,118.6 1,123.7 1,086.7 1,081.7 1,059.0 15.3% CH 4 240.9 228.4 225.3 216.5 218.7 216.4 211.2 207.9 3.0% N 2 O 40.5 39.8 34.9 33.6 33.7 28.7 31.1 29.8 0.4% HFCs, PFCs, and SF 6 61.7 57.7 67.2 59.1 55.6 39.3 41.8 34.6 0.5% Electricity-Related 629.6 738.2 752.5 762.2 775.9 702.9 697.2 708.7 10.3%

CO 2 616.7 727.2 743.3 753.1 767.2 695.0 689.5 701.2 10.2% CH 4 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 + N 2 O 2.7 3.2 3.2 3.2 3.3 2.9 2.9 3.0 + SF 6 10.0 7.6 5.9 5.7 5.3 4.8 4.5 4.4 0.1% Transportation 1,509.9 1,696.1 1,731.8 1,793.2 1,843.0 1,823.2 1,854.8 1,867.6 27.1% Direct Emissions 1,506.8 1,693.0 1,728.7 1,790.0 1,839.6 1,819.8 1,851.6 1,864.4 27.0%

CO 2 1,458.7 1,614.9 1,645.6 1,703.0 1,749.8 1,730.8 1,763.2 1,777.4 25.8% CH 4 4.4 3.5 3.4 3.1 2.9 2.6 2.4 2.2 + N 2 O 43.7 55.2 55.3 54.6 53.2 49.0 45.6 42.1 0.6% HFCs b + 19.4 24.4 29.3 33.8 37.4 40.4 42.7 0.6%

5 Emissions were not distributed to U.S. territories, since th e electricity generation sector only includes emissions related to the generation of electricity in the 50 states and the District of Columbia.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 46 Electricity-Related 3.1 3.1 3.1 3.1 3.3 3.4 3.1 3.2 +

CO 2 3.0 3.0 3.0 3.1 3.3 3.3 3.1 3.2 + CH 4 + + + + + + + + + N 2 O + + + + + + + + + SF 6 + + + + + + + + + Commercial 981.6 1,083.8 1,093.5 1,104.9 1,161.8 1,170.6 1,178.5 1,196.8 17.3% Direct Emissions 435.4 445.2 424.2 426.8 440.7 431.4 440.2 453.5 6.6%

CO 2 224.2 237.2 219.7 222.3 235.2 226.7 230.0 234.0 3.4% CH 4 197.8 179.8 171.8 168.5 165.8 161.6 163.4 168.7 2.4% N 2 O 13.4 15.0 15.3 15.8 15.9 16.0 16.0 16.2 0.2% HFCs + 13.1 17.4 20.3 23.8 27.1 30.8 34.7 0.5% Electricity-Related 546.2 638.7 669.3 678.1 721.1 739.2 738.3 743.3 10.8%

CO 2 535.0 629.2 661.0 670.0 713.0 730.9 730.2 735.3 10.7% CH 4 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 + N 2 O 2.4 2.7 2.8 2.8 3.0 3.1 3.1 3.2 + SF 6 8.7 6.6 5.2 5.1 4.9 5.1 4.8 4.6 0.1% Residential 953.0 1,060.3 1,060.0 1,082.9 1,141.4 1,129.6 1,159.5 1,183.7 17.2% Direct Emissions 350.9 391.0 358.4 379.5 399.7 387.1 391.6 406.1 5.9%

CO 2 339.6 370.6 338.6 359.3 379.1 367.0 371.4 385.1 5.6% CH 4 4.4 3.5 3.1 3.4 3.5 3.1 2.8 3.1 + N 2 O 6.6 7.1 7.0 7.1 6.9 6.7 6.8 6.9 0.1% HFCs 0.3 9.9 9.6 9.8 10.1 10.3 10.6 11.0 0.2% Electricity-Related 602.1 669.3 701.6 703.4 741.7 742.5 767.9 777.6 11.3%

CO 2 589.7 659.3 693.0 695.0 733.3 734.1 759.4 769.3 11.2% CH 4 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 + N 2 O 2.6 2.9 3.0 2.9 3.1 3.1 3.2 3.3 + SF 6 9.6 6.9 5.5 5.2 5.0 5.1 5.0 4.8 0.1% Agriculture 534.1 547.4 568.6 537.3 552.3 555.5 548.8 549.8 8.0% Direct Emissions 473.3 492.0 508.4 486.9 495.3 488.6 485.6 486.4 7.0%

CO 2 46.3 58.4 57.6 60.0 50.4 50.3 52.3 52.2 0.8% CH 4 157.0 163.1 164.4 164.8 162.1 162.0 161.6 162.0 2.3% N 2 O 270.0 270.5 286.3 262.1 282.8 276.3 271.7 272.2 3.9% Electricity-Related 60.8 55.4 60.2 50.4 57.0 66.9 63.2 63.4 0.9%

CO 2 59.6 54.6 59.5 49.8 56.3 66.2 62.5 62.7 0.9% CH 4 + + + + + + + + + N 2 O 0.3 0.2 0.3 0.2 0.2 0.3 0.3 0.3 + SF 6 1.0 0.6 0.5 0.4 0.4 0.5 0.4 0.4 + U.S. Territories 33.8 42.7 42.7 43.9 47.0 54.1 53.6 62.3 0.9%

CO 2 33.8 42.7 42.7 43.9 47.0 54.1 53.6 62.3 0.9% Total 6,088.1 6,677.5 6,719.7 6,752.2 6,953.2 6,806.9 6,858.1 6,900.2 100.0% Note: Emissions from electricity generation are allocated base d on aggregate electricity consumption in each end-use sector. Totals may not sum due to independent rounding. + Does not exceed 0.05 Tg CO 2 Eq. or 0.05%.

a Percents for year 2003. b Includes primarily HFC-134a.



### Transportation

Transportation activities accounted for 27 percen t of U.S. greenhouse gas emissions in 2003. Table 2-17 provides a detailed summary of greenhouse gas emissions from transporta tion-related activities. Total emissions in Table 2-17 differ slightly from those shown in Table 2-16 primarily because the table below excludes a few minor nontransportation mobile sources, such as construction and industrial equipment.

From 1990 to 2003, transportation emissions rose by 24 percent due, in part, to increased demand for travel and the stagnation of fuel efficiency across the U.S. vehicle fleet. Since the 1970s, the number of highway vehiclesInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 47 registered in the United States has increased faster than the overall popula tion, according to the Federal Highway Administration (FHWA). Likewise, the number of miles driven ( up 35 percent from 1990 to 2003 ) and the gallons of gasoline consumed each year in the United States have increased st eadily 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 vehicl es and other light-duty trucks that te nd to have lower fu el efficiency. A similar set of social and economic trends has led to a significant increase in air travel and freight transportation by both air and road modes during the 1990s.

Almost all of the energy consumed for transportation wa s supplied by petroleum-based products, with nearly twothirds being related to gasoline consumption in automobiles and other highway vehicles. Other fuel uses, especially diesel fuel for freight trucks and jet fuel for aircra ft, accounted for the remainder. The primary driver of transportation-related emissions was CO 2 from fossil fuel combustion, which increased by 22 percent from 1990 to 2003. This rise in CO 2 emissions, combined with an increase of 42.7 Tg CO 2 Eq. in HFC emissions over the same period, led to an increase in overall emissions from transportation activities of 24 percent.

Table 2-17: Transportation-Related Greenhouse Gas Emissions (Tg CO 2 Eq.) Gas/Vehicle Type 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 1,461.7 1,618.0 1,648.7 1,706.2 1,753.1 1,734.2 1,766.4 1,780.7

Passenger Cars 612.5 595.5 613.8 622.4 623.4 625.7 639.5 633.7 Light-Duty Trucks 312.2 421.6 432.1 449.2 452.1 456.2 468.1 478.8 Other Trucks 217.0 279.9 290.4 304.3 320.4 327.5 327.5 341.2 Buses 7.8 9.1 9.3 10.4 10.2 9.6 9.1 8.9 Aircraft a 177.2 179.0 181.3 186.7 193.2 183.4 174.9 171.3 Ships and Boats 49.2 38.7 32.4 42.3 63.1 42.7 57.2 57.5 Locomotives 36.3 40.0 40.5 41.7 41.8 42.8 41.0 42.8 Other b 49.4 54.2 48.7 49.3 48.9 46.1 49.0 46.6 International Bunker Fuels c 93.6 106.1 103.3 102.7 102.2 98.5 89.5 84.2 CH 4 4.6 3.8 3.7 3.4 3.2 2.9 2.7 2.4

Passenger Cars 2.6 1.9 1.8 1.7 1.5 1.4 1.2 1.1 Light-Duty Trucks 1.4 1.3 1.3 1.1 1.0 0.9 0.9 0.8 Other Trucks and Buses 0.3 0.3 0.3 0.3 0.2 0.2 0.2 0.2 Aircraft 0.2 0.2 0.1 0.2 0.2 0.1 0.1 0.1 Ships and Boats 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Locomotives 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Motorcycles + + + + + + + + International Bunker Fuels c 0.2 0.1 0.2 0.1 0.1 0.1 0.1 0.1 N 2 O 42.9 54.2 54.4 53.7 52.2 47.9 44.5 40.9

Passenger Cars 25.5 26.7 26.7 25.9 24.7 23.1 21.6 19.9 Light-Duty Trucks 14.1 23.7 23.7 23.6 23.0 20.6 18.6 16.8 Other Trucks and Buses 0.9 1.4 1.6 1.7 1.7 1.7 1.8 1.8 Aircraft 1.7 1.7 1.8 1.8 1.9 1.8 1.7 1.7 Ships and Boats 0.4 0.3 0.3 0.3 0.5 0.3 0.5 0.5 Locomotives 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 Motorcycles + + + + + + + + International Bunker Fuels c 1.0 1.0 1.0 0.9 0.9 0.9 0.8 0.8 HFCs + 19.4 24.4 29.3 33.8 37.4 40.4 42.7

Mobile Air Conditioners d + 13.8 17.4 20.8 24.0 26.7 28.8 30.3 Refrigerated Transport + 5.5 7.0 8.5 9.8 10.8 11.5 12.3 Total 1,509.3 1,695.4 1,731.1 1,792.5 1,842.2 1,822.4 1,853.9 1,866.7 + Does not exceed 0.05 Tg CO 2 Eq. Note: Totals may not sum due to independent rounding.

a Aircraft emissions consis t of emissions from all jet fuel (less bunke r fuels) and aviation gas consumption. b "Other" CO 2 emissions include motorcycle s, pipelines, and lubricants.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 48 c Emissions from International Bunker Fuels include emissions from both civilian and military activities, but are not included i n totals. d Includes primarily HFC-134a.

[BEGIN TEXT BOX]

Box 2-2: Methodology for Aggregating Emissions by Economic Sector

In order to aggregate emissions by economic sector, source category emissi on estimates were generated according to the methodologies outlined in the a ppropriate sections of this report. Those emissions were then simply reallocated into economic sectors. In most cases, the IPCC subcategories distinctly fit into an apparent economic sector category. Several exceptions exist, and the methodologies used to disaggregate these subcategories are described below:

● Agricultural CO 2 Emissions from Fossil Fuel Combustion, and non-CO 2 emissions from Stationary and Mobile Combustion. Emissions from on-farm energy use were accounted for in the Energy chapter as part of the industrial and transportation end-use sectors. To calculate agricultural emissions related to fossil fuel combustion, energy consumption estimates were obtained from economic survey data from the U.S. Department of Agriculture (Duffield 2004) and fuel sales data (EIA 1991 through 2004). To avoid doublecounting, emission estimates of CO 2 from fossil fuel combustion and non-CO 2 from stationary and mobile sources were subtracted from the industrial economic sector, although some of these fuels may have been originally accounted for under the transportation end-use sector.

● Landfills, Wastewater Treatment, and Human Sewage. CH 4 emissions from landfills and wastewater treatment, as well as N 2 O emissions from human sewage, were allocated to the commercial sector.

● Waste Combustion. CO 2 and N 2 O emissions from waste combustion were allocated completely to the electricity generation sector since nearly all waste combustion occurs in waste-to-energy facilities.

● Limestone and Dolomite Use. CO 2 emissions from limestone and dolomite use are allocated to the electricity generation (50 percent) and industrial (50 percent) sectors, because 50 per cent of the total emissions for this source are used in flue gas desulfurization.

● Substitution of Ozone De pleting Substances. All greenhouse gas emissions resulting from the substitution of ozone depleting substances were placed in the industrial economic sector, with the exception of emissions from domestic, commercial, mobile and transport refrige ration/air-conditioni ng systems were placed in the residential, commercial, and transportation sectors, respectively. Emissions from non-MDI aerosols were attributed to the residential economic sector.

● Settlement Soil Fertilization, Forest Soil Fertilization. Emissions from settlement soil fertilization were allocated to the residential economic sector; forest so il fertilization was allocated to the agriculture economic
sector.

[END TEXT BOX]



### 2.3. Ambient Air Pollutant Emissions

In the United States, carbon monoxide (CO), nitrogen oxides (NO x ), nonmethane volatile organic compounds (NMVOCs), and sulfur dioxide (SO 2 ) are referred to as "ambient air pollutants," and are regulated under the Clean Air Act in an effort to protect human health and the environment. These pollutants do not have a direct global warming effect, but indirectly affect terrestrial radiation absorption by influencing the formation and destruction ofInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 49 tropospheric and stratospheric ozone, or, in the case of SO 2 , by affecting the absorp tive characteristics of the atmosphere. Additionally, some of these pollutants may r eact with other chemical compounds in the atmosphere to form compounds that are greenhouse gases. Carbon monoxide is produced when carbon-containing fuels are combusted incompletely. Nitrogen oxides (i.e., NO and NO 2 ) are created by lightning, fires, fossil fuel combustion, and in the stratosphere from nitrous oxide (N 2 O). NMVOCs

⎯ which include hundreds of organic compounds that participate in atmospheric chemical reactions (i.e., propane, butane, xylene , toluene, ethane and many others)

⎯ are emitted primarily from transportation, i ndustrial processes, and non-industrial c onsumption of organic solvents. In the United States, SO 2 is primarily emitted from coal combustion for electric power generation and the metals industry. Sulfur-containing compounds em itted into the atmosphere tend t exer t a negative radiative forcing (i.e., cooling) and therefore are discussed separately.

One important indirect climate change effect of NMVOCs and NO x is their role as precursors for tropospheric ozone formation. They can also alter the atmospheric lifetimes of other greenhouse gases. Another example of ambient air pollutant formation into greenhouse gases is carbon monoxide’s interaction with the hydroxyl radical

⎯ the major atmospheric sink for methane emissions

⎯ to form CO 2 . Therefore, increased atmospheric concentrations of CO limit the number of hydroxyl molecules (OH) available to destroy methane.

Since 1970, the United States has published estimates of annual emissions of ambient air pollutants (EPA 2004). 6 Table 2-18 shows that fuel combustion accounts for the majority of emissions of these gases. Industrial
processes

⎯ such as the manufacture of chemical and allied pr oducts, metals processing, and industrial uses of solvents

⎯ are also significant sources of CO, NO x, and NMVOCs.

Table 2-18: Emissions of NO x , CO, NMVOCs, and SO 2 (Gg) Gas/Activity 1990 1997 1998 1999 2000 2001 2002 2003 NO x 22,860 22,284 21,964 20,530 20,288 19,414 18,850 18,573

Stationary Fossil Fuel Combustion 9,884 9,578 9,419 8,344 8,002 7,667 7,523 7,222 Mobile Fossil Fuel Combustion 12,134 11,768 11,592 11,300 11,395 10,823 10,389 10,418 Oil and Gas Activities 139 130 130 109 111 113 135 124 Waste Combustion 82 140 145 143 114 114 134 121 Industrial Processes 591 629 637 595 626 656 630 648 Solvent Use 1 3 3 3 3 3 5 4 Field Burning of Agricultural

Residues 28 34 35 34 35 35 33 33 Waste 0 3 3 3 2 2 2 2 CO 130,580 101,138 98,984 94,361 92,895 89,329 87,451 85,077

Stationary Fossil Fuel Combustion 4,999 3,927 3,927 5,024 4,340 4,377 4,020 4,454 Mobile Fossil Fuel Combustion 119,482 90,284 87,940 83,484 83,680 79,972 78,574 75,526 Oil and Gas Activities 302 333 332 145 146 147 116 125 Waste Combustion 978 2,668 2,826 2,725 1,670 1,672 1,672 1,674 Industrial Processes 4,124 3,153 3,163 2,156 2,217 2,339 2,308 2,431 Solvent Use 4 1 1 46 46 45 46 65 Field Burning of Agricultural

Residues 689 767 789 767 790 770 707 794 Waste 1 5 5 13 8 8 8 8 NMVOCs 20,937 16,994 16,403 15,869 15,228 15,048 14,222 13,939

Stationary Fossil Fuel Combustion 912 1,016 1,016 1,045 1,077 1,080 926 1,007 Mobile Fossil Fuel Combustion 10,933 7,928 7,742 7,586 7,230 6,872 6,560 6,351 Oil and Gas Activities 555 442 440 414 389 400 340 345

6 NO x and CO emission estimates from field bur ning of agricultural residues were estimat ed separately, and therefore not taken from EPA (2004).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 50 Waste Combustion 222 313 326 302 257 258 281 263 Industrial Processes 2,426 2,038 2,047 1,813 1,773 1,769 1,725 1,711 Solvent Use 5,217 5,100 4,671 4,569 4,384 4,547 4,256 4,138 Field Burning of Agricultural

Residues NA NA NA NA NA NA NA NA Waste 673 157 161 140 119 122 133 125 SO 2 20,936 17,091 17,189 15,917 14,829 14,452 13,928 14,463

Stationary Fossil Fuel Combustion 18,407 15,104 15,191 13,915 12,848 12,461 11,946 12,477 Mobile Fossil Fuel Combustion 793 659 665 704 632 624 631 634 Oil and Gas Activities 390 312 310 283 286 289 315 293 Waste Combustion 39 29 30 30 29 30 24 28 Industrial Processes 1,306 985 991 984 1,031 1,047 1,009 1,029 Solvent Use 0 1 1 1 1 1 2 2 Field Burning of Agricultural

Residues NA NA NA NA NA NA NA NA Waste 0 1 1 1 1 1 1 1 Source: (EPA 2004) except fo r estimates from field burning of agricultural residues. + Does not exceed 0.5 Gg NA (Not Available) Note: Totals may not sum due to independent rounding.

[BEGIN BOX]

Box 2-3: Sources and Effects of Sulfur Dioxide

Sulfur dioxide (SO 2 ) emitted into the atmosphere through natural a nd anthropogenic processes affects the Earth's radiative budget through its photochemical transformation into sulfate aerosols that can (1) scatter radiation from the sun back to space, thereby reducing the radiation reaching the Earth's surface; (2) affect cloud fo rmation; and (3) affect atmospheric chemical compositi on (e.g., by providing surfaces for heter ogeneous chemical reactions). The indirect effect of sulfur-derived aerosols on radiative forcing can be considered in two parts. The first indirect effect is the aerosols’ tendency to decrease water dropl et size and increase water droplet concentration in the atmosphere. The second indirect effect is the tendency of the reduction in cloud droplet size to affect precipitation by increasing cloud lifetime and thickness. Although still highly uncertain, the radiative forcing estimates from both the first and the second indirect effect are believed to be negative, as is the combined radiative forcing of the two (IPCC 2001). However, because SO 2 is short-lived and unevenly distributed in the atmosphere, its radiative forcing impacts are highly uncertain.

Sulfur dioxide is also a majo r contributor to the formati on of regional haze, which can cause significant increases in acute and chronic respiratory diseases. Once SO 2 is emitted, it is chemically transformed in the atmosphere and returns to the Earth as the primary source of acid rain. Because of these harmful effects, the United States has regulated SO 2 emissions in the Clean Air Act.

Electricity generation is the largest anthropogenic source of SO 2 emissions in the United States, accounting for 69 percent in 2003. Coal combustion contributes nearly all of those emissions (approximately 92 percent). Sulfur dioxide emissions have decreased in recent years, primar ily as a result of electric pow er generators switching from high sulfur to low sulfur coal and installing flue gas desulfurization equipment.

[END BOX]Fi g ure 2-1: U.S. Greenhouse Gas Emissions b y Gas

Fi g ure 2-2: Annual Percent Chan g e in U.S. Greenhouse Gas Emissions

Fi g ure 2-3: Cumulative Chan g e in U.S. Greenhouse Gas Emissions Relative to 1990 1.0% 3.3%

0.9% 0.6% 0.5% 3.0%

0.8% 0.6%

-0.8%

-2.1%

1.4% 2.1% 1.5%

-3% -2% -1% 0% 1% 2% 3% 4%

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

33 163 255 319 533 589 632 664 865

719 770 812

-50

-100

0 100 200 300 400 500 600 700 800 900

1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Tg CO2Eq. 6,900 6,858 6,807 6,720 6,678 6,621 6,407 6,343 6,251 6,121 6,038 6,088 6,752 6,953

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Tg CO2Eq. HFCs, PFCs, & SF
Nitrous Oxide
Methane
Carbon Dioxide 6Fi g ure 2-4: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Produc t

Fi g ure 2-5: U.S. Greenhouse Gas Emissions and Sinks b y Chapter/IPCC Secto r (2,000) (1,000) 0 1,000 2,000 3,000 4,000 5,000 6,000 7,00019901991199219931994199519961997199819992000200120022003Tg CO2Eq.
Energy

Land-Use Change and Forestry (sink) Industrial Processes Agriculture Waste Emissions per $GDP Emissions per capita Population Real GDP

70 80 90 100 110 120 130 140 150

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Index (1990 = 100)Fi g ure 2-6: 2003 Ener gy Sector Greenhouse Gas Sources 5,551.6

0 20 40 60 80 100 120 140 Natural Gas Flaring Petroleum Systems Waste Combustion Stationary Sources Coal Mining Mobile Sources Natural Gas Systems Fossil Fuel Combustion

Tg CO 2 Eq. Energy as a Portion

of all Emissions

86.6%Figure 2-8 : 2003 CO 2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type

Figure 2-9 : 2003 End-Use Sector Emissions of CO 2 from Fossil Fuel Combustion Note: Electricity generation also includes emissions of less than 1 Tg CO 2 Eq. from geothermal-based electricity generation.

0 200 400 600 800 1000 1200 1400 1600 1800 2000

Re

s i d

e n t ia

l
C o m

m

e r c i a l

I n d

u s t r i a l

T r a n s p o r t a t i o n

U

. S

. T e r r i t o r ie

sTg CO2Eq From Electricity Consumption From Direct Fossil Fuel Combustion 0 500 1,000 1,500 2,000ResidentialCommercialIndustrialTransportationElectricityGenerationU.S.TerritoriesTg CO2Eq Natural Gas
Petroleum
Coal Relative Contribution by Fuel TypeFi g ure 2-10 : 2003 Industrial Processes Chapter Greenhouse Gas Sources <0.05

0 10 20 30 40 50 60 70 80 90 100 Silicon Carbide Production Carbon Dioxide Consumption Ferroalloys Phosphoric Acid Production Titanium Dioxide Production Magnesium Production and Processing Soda Ash Manufacture and Consumption Petrochemical Production Semiconductor Manufacture Limestone and Dolomite Use Adipic Acid Aluminum Production

HCFC-22 Production

Lime Manufacture Electrical Transmission and Distribution Ammonia Production and Urea Application Nitric Acid Cement Manufacture Iron and Steel Production Substitution of Ozone Depleting Substances

Tg CO 2 Eq. Industrial Processes as a Portion of all Emissions

4.5%Figure 2-11 : 2003 Agriculture Chapter GHG Sources

Figure 2-12 : 2003 Waste Chapter Greenhouse Gas Sources 1.2

0 50 100 150 200 250 Agricultural Residue Burning Rice Cultivation Manure Management Enteric Fermentation Agricultural Soil

Management

Tg CO 2 Eq A g riculture as a Portion of all

Emissions
6.3%

0 20 40 60 80 100 120 140 Human Sewage Wastewater Treatment Landfills

Tg CO 2 Eq Waste as a Portion of all Emissions

2.7%Figure 2- 13 : Emissions Allocated to Economic Sectors

Figure 2- 14 : Emissions with Electricity Distributed to Economic Sectors 0 500 1,000 1,500 2,000 2,500

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
Year(Tg CO2Eq.) Transportation Electricity Generation

Industry

Residential A griculture

Commercial

0 500 1,000 1,500 2,000 2,50019901991199219931994199519961997199819992000200120022003Tg CO2Eq. Transportation Industrial

Residential

A griculture

CommercialInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 51 

## 3. Energy

Energy-related activities were the primary sources of U.S. anthropogenic greenhouse gas emissions, accounting for 86 percent of total emissions on a carbon equivalent basis in 2003. This included 97, 39, and 15 percent of the nation's carbon dioxide (CO 2 ), methane (CH 4 ), and nitrous oxide (N 2 O) emissions, respectively. Energy-related CO 2 emissions alone constituted 83 percent of national em issions from all sources on a carbon equivalent basis, while the non-CO 2 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 CO 2 being the primary gas emitted (see Figure 3-1). Globally, approximately 24,240 Tg CO 2 were added to the atmosphere through the combustion of fossil fuels in 2000, of wh ich the United States account ed for about 23 percent. 1 Due to the relative importance of fossil fuel combustion-related CO 2 emissions, they are considered separately, and in more detail than other energy-related emissions (see Figure 3-2). Fossil fuel combustion also emits CH 4 and N 2 O, as well as ambient air pollutants such as nitrogen oxides (NO x ), carbon monoxide (CO), and non-methane volatile organic compounds (NMVOCs). Mobile fossil fuel combustion was the second largest source of N 2 O emissions in the United States, and overall energy-related activities were collectively the largest source of these ambient air pollutant emissions. Figure 3-1: 2003 Energy Sector Greenhouse Gas Sources

Figure 3-2: 2003 U.S. Fossil Carbon Flows (Tg CO 2 Eq.)

Energy-related activities other than fuel combustion, such as the production, tr ansmission, storage, and distribution of fossil fuels, also emit greenhouse gases. Th ese emissions consist primarily of fugitive CH 4 from natural gas systems, petroleum systems, and coal mining. Smaller quantities of CO 2 , CO, NMVOCs, and NO x are also emitted.

The combustion of biomass and biomass-based fuels also emits greenhouse gases. Carbon dioxide emissions from these activities, however, are not included in national emissions totals because biomass fuels are of biogenic origin. It is assumed that the carbon released during the consumption of biomass is recycled as U.S. forests and crops regenerate, causing no net addition of CO 2 to the atmosphere. The net impacts of land-use and forestry activities on the carbon cycle are accounted for within the Land-Use Change and Forestry s ector. Emissions of other greenhouse gases from the combustion of biomass and biomass-based fu els are included in national totals under stationary and mobile combustion.

Table 3-1 summarizes emissions from the Energy sector in units of teragrams of CO 2 equivalents (Tg CO 2 Eq.),while unweighted gas emissions in gigagrams (Gg) are provided in Table 3-2. Overall, emissions due to energyrelated activities were 5,963.4 Tg CO 2 Eq. in 2003, an increase of 16 percent since 1990.

Table 3-1: Emissions from Energy (Tg CO 2 Eq.) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 4,836.4 5,409.1 5,437.7 5,512.1 5,693.5 5,592.9 5,645.3 5,694.3

Fossil Fuel Combustion 4,711.7 5,263.2 5,278.7 5,345.9 5,545.1 5,448.0 5,501.4 5,551.6 Non-Energy Use of Fuels 108.0 120.3 135.4 141.6 124.7 120.1 118.8 118.0 Waste Combustion 10.9 17.8 17.1 17.6 18.0 18.8 18.8 18.8

1 Global CO 2 emissions from fossil fuel com bustion were taken from Marland et al. (2003) <http://cdiac.esd.ornl.gov/trends/emis/meth_reg.htm>.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 52 Natural Gas Flaring 5.8 7.9 6.6 6.9 5.8 6.1 6.2 6.0 Biomass-Wood* 212.5 226.3 209.5 214.3 217.6 190.8 195.8 201.0 International Bunker Fuels* 113.5 109.9 114.6 105.3 101.4 97.9 89.5 84.2 Biomass-Ethanol* 4.2 7.0 7.7 8.0 9.2 9.7 11.5 15.8 CH 4 248.9 234.6 230.9 222.1 224.3 221.6 215.8 212.7

Natural Gas Systems 128.3 133.6 131.8 127.4 132.1 131.8 130.6 125.9 Coal Mining 81.9 62.6 62.8 58.9 56.2 55.6 52.4 53.8 Petroleum Systems 20.0 18.8 18.5 17.8 17.6 17.4 17.1 17.1 Stationary Sources 7.8 7.4 6.9 7.1 7.3 6.7 6.4 6.7 Mobile Sources 4.8 4.0 3.9 3.6 3.4 3.1 2.9 2.7 Abandoned Coal Mines 6.1 8.1 7.2 7.3 7.7 6.9 6.4 6.4 International Bunker Fuels* 0.2 0.1 0.2 0.1 0.1 0.1 0.1 0.1 N 2 O 56.4 69.1 69.1 68.4 67.5 62.8 59.6 56.4

Mobile Sources 43.7 55.2 55.3 54.6 53.2 49.0 45.6 42.1 Stationary Sources 12.3 13.5 13.4 13.5 14.0 13.5 13.5 13.8 Waste Combustion 0.4 0.4 0.3 0.3 0.4 0.4 0.5 0.5 International Bunker Fuels* 1.0 1.0 1.0 0.9 0.9 0.9 0.8 0.8 Total 5,141.7 5,712.8 5,737.7 5,802.6 5,985.3 5,877.3 5,920.7 5,963.4 * These values are presented for inform ational purposes only and are not included or are already accounted for in totals. Note: Totals may not sum due to independent rounding.

Table 3-2: Emissions from Energy (Gg) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 4,836,430 5,409,100 5,437,734 5,512,062 5,693,544 5,592,947 5,645,251 5,694,332

Fossil Fuel Combustion 4,711,741 5,263,164 5,278,721 5,345,904 5,545,083 5,447,969 5,501,427 5,551,580 Non-Energy Use of Fuels 107,964.9 120,300.6 135,352.1 141,582.9 124,713.8 120,104.1 118,810.6 118,001.4 Waste Combustion 10,919 17,761 17,094 17,632 17,979 18,781 18,781 18,781 Natural Gas Flaring 5,805 7,874 6,566 6,943 5,769 6,094 6,233 5,970 Biomass-Wood* 212,547 226,265 209,490 214,323 217,577 190,776 195,776 201,042 International Bunker Fuels* 113,503 109,858 114,557 105,294 101,404 97,865 89,489 84,193 Biomass-Ethanol* 4,155 6,978 7,711 8,017 9,188 9,701 11,473 15,771 CH 4 11,852 11,170 10,997 10,577 10,680 10,551 10,279 10,126

Natural Gas Systems 6,112 6,363 6,276 6,066 6,289 6,277 6,221 5,998 Coal Mining 3,900 2,983 2,989 2,805 2,677 2,647 2,497 2,561 Petroleum Systems 951 895 879 848 836 831 815 815 Stationary Sources 373 351 328 338 349 318 305 319 Mobile Sources 228 193 185 172 161 147 138 128 Abandoned Coal Mines 288 385 341 349 369 331 303 306 International Bunker Fuels* 8 7 7 6 6 5 4 4 N 2 O 182 223 223 221 218 203 192 182

Mobile Combustion 141 178 179 176 171 158 147 136 Stationary Combustion 40 44 43 43 45 43 44 45 Waste Combustion 1 1 1 1 1 1 1 1 International Bunker Fuels* 3 3 3 3 3 3 3 2 * These values are presented for inform ational purposes only and are not included or are already accounted for in totals. Note: Totals may not sum due to independent rounding.



### 3.1. Carbon Dioxide Emissions from Fossil Fuel Combustion (IPCC Source Category 1A)

Carbon dioxide emissions from fossil fuel combustion in 2003 increased 0.9 percent from the previous year. This increase is primarily a result of increased demand for fuels due to a growing economy, fuel-switching from natural gas to coal in the electric power sector, and increased use of heating fuels in th e residential sector caused by a colderInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 53 winter. In 2003, CO 2 emissions from fossil fuel combustion were 5,551.6 Tg CO 2 Eq., or 18 percent above emissions in 1990 (see Table 3-3). 2

Table 3-3: CO 2 Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg CO 2 Eq.) Fuel/Sector 1990 1997 1998 1999 2000 2001 2002 2003 Coal 1,680.9 1,920.2 1,936.5 1,938.2 2,025.6 1,959.2 1,973.1 2,013.8

Residential 2.4 1.5 1.2 1.3 1.1 1.1 1.0 1.1 Commercial 12.1 12.2 8.7 9.7 8.6 9.2 8.6 9.3 Industrial 152.6 147.2 139.2 133.8 135.0 130.6 122.7 123.4 Transportation NE NE NE NE NE NE NE NE Electricity Generation 1,513.0 1,758.4 1,786.4 1,792.4 1,880.0 1,817.4 1,839.7 1,876.3 U.S. Territories 0.6 1.0 1.0 0.9 0.9 0.9 1.2 3.6 Natural Gas 1,009.5 1,193.7 1,169.9 1,173.6 1,224.1 1,174.4 1,214.0 1,170.3

Residential 238.8 270.2 246.5 256.5 270.3 259.7 265.9 277.3 Commercial 142.6 174.3 163.5 165.2 172.4 164.5 168.7 170.7 Industrial 416.3 489.1 476.7 456.4 464.6 426.0 435.5 407.9 Transportation 35.9 41.1 35.1 35.6 35.5 33.9 37.1 35.4 Electricity Generation 176.0 218.9 248.0 259.9 280.7 289.1 305.6 277.6 U.S. Territories NO NO NO NO 0.7 1.2 1.2 1.4 Petroleum 2,020.9 2,148.9 2,172.0 2,233.7 2,295.0 2,314.0 2,314.0 2,367.1

Residential 98.3 98.9 90.9 101.5 107.7 106.2 104.5 106.7 Commercial 69.5 50.7 47.5 47.3 54.2 53.1 52.7 53.9 Industrial 313.9 327.4 295.6 297.8 305.5 321.6 318.4 327.3 Transportation 1,410.9 1,562.2 1,598.3 1,655.2 1,702.2 1,685.8 1,715.2 1,731.8 Electricity Generation 101.0 74.3 104.3 96.7 91.0 100.9 77.4 96.3 U.S. Territories 27.4 35.5 35.4 35.2 34.3 46.5 45.7 51.2 Geothermal* 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.3 Total 4,711.7 5,263.2 5,278.7 5,345.9 5,545.1 5,448.0 5,501.4 5,551.6 NE (Not estimated) NO (Not occurring) + Does not exceed 0.05 Tg CO 2 Eq. * Although not technically a fossil fuel, geothermal energy-related CO 2 emissions are included for reporting purposes. Note: Totals may not sum due to independent rounding.

Trends in CO 2 emissions from fossil fuel combustion are influenced by many long-term and short-term factors. On a year-to-year basis, the overall demand for fossil fuels in the United States and other countries generally fluctuates in response to changes in general economic conditions, en ergy prices, weather, and the availability of non-fossil alternatives. For example, in a year with increased c onsumption of goods and services, low fuel prices, severe summer and winter weather conditions, nuclear plant closur es, and lower precipitation feeding hydroelectric dams, there would likely be proportionally greater fossil fuel consumption than a year with poor economic performance, high fuel prices, mild temperatures, and increased output from nuclear and hydroelectric plants.

Longer-term changes in energy consumption patterns, howev er, tend to be more a function of aggregate societal trends that affect the scale of consumption (e.g., population, number of cars, and size of houses), the efficiency with which energy is used in equipment (e.g., cars, power plants, steel mills, and light bulbs), and social planning and consumer behavior (e.g., walking, bicycling, or telecommuting to work instead of driving).

Carbon dioxide emissions also depend on the source of energy and its carbon intensity. The amount of carbon in fuels varies significantly by fuel type. For example, coal contains the highest amount of carbon per unit of useful

2 An additional discussion of fossil fuel emission trends is pres ented in the Trends in U.S. Greenhouse Gas Emissions Chapter.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 54 energy. Petroleum has roughly 75 percent of the carbon per unit of energy as coal, and natural gas has only about 55 percent. 3 Producing a unit of heat or electricity using natural gas instead of coal can reduce the CO 2 emissions associated with energy consumption, and using nuclear or renewable energy sources (e.g., wind) can essentially eliminate emissions (see Box 3-2). Table 3-4 shows annual changes in emissions during the last six years for coal, petroleum, and natural gas in selected sectors.

Table 3-4: Annual Change in CO 2 Emissions from Fossil Fuel Combustion for Selected Fuels and Sectors (Tg CO 2 Eq. and Percent) Sector Fuel Type 1999 to 2000 2000 to 2001 2001 to 2002 2002 to 2003 Electricity Generation Coal 87.6 5% -62.6 -3% 22.2 1% 36.6 2% Electricity Generation Natural Gas 20.8 8% 8.4 3% 16.5 6% -28.0 -9% Electricity Generation Petroleum -5.6 -6% 9.8 11% -23.5 -23% 18.9 24% Transportation a Petroleum 47.0 3% -16.4 -1% 29.4 2% 16.6 1% Residential Natural Gas 13.9 5% -10.7 -4% 6.2 2% 11.5 4% Commercial Natural Gas 7.1 4% -7.9 -5% 4.2 3% 2.0 1% Industrial Coal 1.1 1% -4.4 -3% -7.9 -6% 0.8 1% Industrial Natural Gas 8.2 2% -38.5 -8% 9.5 2% -27.6 -6% All Sectors b All Fuels b 199.2 4% -97.1 -2% 53.5 1% 50.2 1%

a Excludes emissions from In ternational Bunker Fuels. b Includes fuels and sectors not shown in table.

In the United States, 86 percent of the energy consumed in 2003 was produced through the combustion of fossil fuels such as coal, natural gas, a nd petroleum (see Figure 3-3 and Figure 3-4). The remaining portion was supplied by nuclear electric power (8 percent) and by a variety of renewable energy sources (6 percent), primarily hydroelectric power and biofuels (EIA 2004a). Specifically, petroleum supplied the largest share of domestic energy demands, accounting for an average of 39 percent of total energy consumption from 1990 through 2003. Natural gas and coal followed in order of importance, accounting for 24 and 23 percent of total consumption, respectively. Petroleum was consumed primarily in the tran sportation end-use sector, the vast majority of coal was used in electricity generation, and natural gas was broa dly consumed in all end-use sectors except transportation (see Figure 3-5) (EIA 2004a).

Figure 3-3: 2003 U.S. Energy Consumption by Energy Source

Figure 3-4: U.S. Energy Consumption (Quadrillion Btu)

Figure 3-5: 2003 CO 2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type

Fossil fuels are generally combusted for the purpose of producing energy for useful heat and work. During the combustion process, the carbon stored in the fuels is oxidized and emitted as CO 2 and smaller amounts of other gases, including CH 4 , CO, and NMVOCs. 4 These other carbon containing non-CO 2 gases are emitted as a byproduct of incomplete fuel combustion, but are, for the most part, eventually oxidized to CO 2 in the atmosphere. Therefore, except for the soot and ash left behind during the combustion process, all the carbon in fossil fuels used to produce energy is eventually converted to atmospheric CO 2 .

3 Based on national aggregate carbon content of all coal, natura l gas, and petroleum fuels combusted in the United States. 4 See the sections entitled Stationary Combustion and Mobile Combustion in this chapter for information on non-CO 2 gas emissions from fossil fuel combustion.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 55 [BEGIN BOX]

Box 3-1: Weather and Non-Fossil Energy Effects on CO 2 from Fossil Fuel Combustion Trends

In 2003, weather conditions became cooler in both the wi nter and summer. Heating degree days in the United States were 2 percent below normal (see Figure 3-6), wh ile cooling degree days in 2003 were 5 percent above normal (see Figure 3-7) (EIA 2004f). 5 Winter conditions were colder in 2003 than in 2002, which, coupled with a 1.2 percent increase in the U.S. housing stock (EIA 2004f), led to an increase in demand for heating fuels, despite escalating fuel prices for heating fuels. Though the summer of 2003 was cooler than the near record heat of 2002, demand for electricity increased most likely due to the growing economy and increase in housing stock.

Figure 3-6: Annual Deviations from Normal Heating Degree Days for the United States (1949-2003)

Figure 3-7: Annual Deviations from Normal Cooling Degree Days for the United States (1949-2003)

Although no new U.S. nuclear power plants have been constructed in recent years, the utilization (i.e., capacity factors 6 ) of existing plants remained high, at 88 percent in 2003. This utilization level actually represents a 2 percent decrease in electricity output by nuclear plants, down from a record high of 90 percent in 2002. Electricity output by hydroelectric power plants increased in 2003 by approximately 4 percent. Nevertheless, electricity generated by nuclear plants in 2003 provided almost 3 times as much of the energy consumed in the United States as hydroelectric plants (EIA 2004a). Aggregate nuclear and hydroelectric power plant capacity factors since 1973 are shown in Figure 3-8.

Figure 3-8: Aggregate Nuclear and Hydroelectric Power Plant Capacity Factors in the United States (1973-2003)

[END BOX]

For the purpose of international reporting, the IPCC (IPCC/UNEP/OECD/IEA 1997) recommends that particular adjustments be made to national fuel consumption statistics. Certain fossil fuels can be manufactured into plastics, asphalt, lubricants, or other products. A portion of th e carbon consumed for these non-energy products can be stored (i.e., sequestered) indefinitely. To account for the fact that the carbon in these fuels ends up in products instead of being combusted (i.e., oxidized and released in to the atmosphere), consumption of fuels for non-energy purposes is estimated and subtracted from total fuel consumption estimates. Emissions from non-energy uses of fuels are estimated in the Carbon Emitte d and Stored in Products from Non-Ener gy Uses of Fossil Fuels section in this chapter.

5 Degree days are relative measur ements of outdoor air temperature. Heating de gree days are deviations of the mean daily temperature below 65 ° F, while cooling degree days are deviati ons of the mean daily temperature above 65 ° F. Heating degree days have a considerably greater affect on energy demand and related emissions than do cooli ng degree days. Excludes Alaska and Hawaii. Normals are based on data from 1971 through 2000. The variation in th ese normals during this time period was
± 10 percent and ± 14 percent for heating and cooling degree days, respectively (99 percent confidence interval). 6 The capacity factor is defined as the ratio of the electrical energy produced by a generating unit for a given period of time to the electrical energy that could have been produced at c ontinuous full-power operation during the same period (EIA 2004a).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 56 According to the UNFCCC reporting guidelines, CO 2 emissions from the consumption of fossil fuels for aviation and marine international transport ac tivities (i.e., international bunker fuels) should be reported se parately, and not included in national emission totals. Estimates of international bunker fuel emissions for the United States are provided in Table 3-5.

Table 3-5: CO 2 Emissions from International Bunker Fuels (Tg CO 2 Eq.)* Vehicle Mode 1990 1997 1998 1999 2000 2001 2002 2003 Aviation 46.2 55.9 56.7 58.9 60.5 59.4 61.8 59.6 Marine 67.3 54.0 57.9 46.4 40.9 38.5 27.7 24.6 Total 113.5 109.9 114.6 105.3 101.4 97.9 89.5 84.2 * See International Bunker Fuels section for additional detail. Note: Totals may not sum due to independent rounding.


### End-Use Sector Consumption

An alternative method of presenting CO 2 emissions is to allocate emissions asso ciated with electricity generation to the sectors in which it is used. Four end-use sectors we re defined: industrial, transportation, residential, and commercial. 7 For the discussion below, elect ricity generation emissi ons have been distributed to each end-use sector based upon the sector’s share of national electricity consumption. This method of distributing emissions assumes that each sector consumes el ectricity generated from an equally car bon-intensive mix of fuels and other energy sources. In reality, sources of electricity vary widely in carbon intensity (e.g., coal versus wind power). By giving equal carbon-intensity wei ght to each sector's electricity consumpti on, emissions attributed to one end-use sector may be somewhat overestimated, while emissions a ttributed to another end-use sector may be slightly underestimated. After the end-use sectors are discusse d, emissions from electricity generation are addressed separately. Emissions from U.S. territories are also cal culated separately due to a lack of end-use-specific consumption data. Table 3-6 and Figure 3-9 summarize CO 2 emissions from direct fossil fuel combustion and prorated electricity generation emissions from electricity consumption by end-use sector.

Table 3-6: CO 2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO 2 Eq.) End-Use Sector 1990 1997 1998 1999 2000 2001 2002 2003 Transportation 1,449.8 1,606.4 1,636.5 1,693.9 1,741.0 1,723.1 1,755.4 1,770.4

Combustion 1,446.8 1,603.3 1,633.4 1,690.8 1,737.7 1,719.7 1,752.3 1,767.2 Electricity 3.0 3.1 3.1 3.2 3.4 3.4 3.2 3.2 Industrial 1,553.9 1,703.0 1,668.5 1,651.2 1,684.4 1,587.4 1,579.0 1,572.9

Combustion 882.8 963.8 911.6 888.1 905.0 878.2 876.6 858.6 Electricity 671.1 739.2 757.0 763.1 779.4 709.3 702.4 714.3 Residential 924.8 1,040.7 1,044.4 1,063.5 1,124.2 1,116.2 1,145.0 1,168.9

Combustion 339.6 370.6 338.6 359.3 379.1 367.0 371.4 385.1 Electricity 585.3 670.2 705.8 704.2 745.0 749.2 773.6 783.8 Commercial 755.1 876.7 892.9 901.2 959.5 972.7 973.9 983.1

Combustion 224.2 237.2 219.7 222.3 235.2 226.7 230.0 234.0 Electricity 530.9 639.5 673.2 678.9 724.3 745.9 743.9 749.2 U.S. Territories 28.0 36.4 36.3 36.2 35.9 48.6 48.1 56.2 Total 4,711.7 5,263.2 5,278.7 5,345.9 5,545.1 5,448.0 5,501.4 5,551.6 Electricity Generation 1,790.3 2,051.9 2,139.0 2,149.3 2,252.1 2,207.8 2,223.0 2,250.5 Note: Totals may not sum due to indepe ndent rounding. Emissions from fossil fuel combustion by electricity generation are allocated based on aggregate national electricity consumption by each end-use sector.

7 See Glossary (Annex 6.8) for more detailed definitions of the industrial, residential, commerc ial, and transportation end-use sector, as well as electricity generation.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 57 Figure 3-9: 2003 End-Use Sector Emissions of CO 2 from Fossil Fuel Combustion

Transportation End-Use Sector
Using this allocation method, the tran sportation end-use sector accounted fo r the largest share (approximately 32 percent) of CO 2 emissions from fossil fuel combustion. 8 Almost all of the energy consumed in the transportation sector was petroleum-based, with nearly two-thirds be ing gasoline consumption in automobiles and other highway vehicles. Other fuel uses, especially diesel fuel for freight trucks and jet fuel for aircraft, accounted for the remainder. 9

Carbon dioxide emissions from fossil fuel combustion for transportation increased by 22 percent from 1990 to 2003, to 1,770.4 Tg CO 2 Eq. The growth in transportation end-use sector emissions has been relatively steady, excluding a 4 percent single year increase in 1999 and slight decreases in 1991 and 2001. Like overall energy demand, transportation fuel demand is a function of many short and long-term factors. In the short term only minor adjustments can generally be made th rough consumer behavior (e.g., not driving as far for summer vacation). However, long-term adjustments such as vehicle purchase choices, transpor t mode choice and access (i.e., trains versus planes), and urban planning can ha ve a significant impact on fuel demand.

In 2003, CO 2 emissions from the transportation sector increased by approximately 1 percent. A 12 percent increase in the price of motor gasoline in 2003 tempered the effects of the growing economy 10 on demand for vehicle fuel (see Figure 3-10).

Since 1990, travel activity in the United States has grown more rapidly than population, with a 16 percent increase in vehicle miles traveled per capita. In the meantime, improvements in the av erage fuel efficiency of the U.S. vehicle fleet stagnated after increasing steadily since 1976 (FHWA 1996 through 2004). The average miles per gallon achieved by the U.S. vehicle fleet has remained fairly constant since 1991. This trend is due, in part, to the increasing dominance of new motor vehicle sales by less fuel-efficient light-duty trucks and sport-utility vehicles (see Figure 3-11).

Figure 3-10: Motor Gasoline Retail Prices (Real)

Figure 3-11: Motor Vehi cle Fuel Efficiency

Table 3-7 provides a detailed breakdown of CO 2 emissions by fuel category and vehicle type for the transportation end-use sector. Fifty-nine percent of the emissions from this end-use sector in 2003 were the result of the combustion of motor gasoline in passenger cars and light-duty tr ucks. Diesel highway vehicles and jet aircraft were also significant contributors, accounting for 18 and 12 percent of CO 2 emissions from the transportation end-use sector, respectively. 11 For information on transportation-related CO 2 emissions from agriculture and construction equipment, other off-road equipment, and recreational vehicles, please re fer to Table 3-36 in Annex 3.2.

Table 3-7: CO 2 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg CO 2 Eq.) Fuel/Vehicle Type 1990 1997 1998 1999 2000 2001 2002 2003 Gasoline 955.2 1,042.5 1,072.9 1,099.9 1,105.9 1,111.2 1,138.7 1,143.7

8 Note that electricity generation is actually the largest emitter of CO 2 when electricity is not dist ributed among end-use sectors. 9 See Glossary (Annex 6.8) for a more detailed definition of the transportation end-use sector. 10 Gross domestic product increased 3.1 percent between 2002 and 2003 (BEA 2004). 11 These percentages include emissions from bunker fuels.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 58 Automobiles 605.1 589.8 608.6 618.4 620.1 622.3 636.1 630.2 Light-Duty Trucks 301.0 406.1 416.3 432.6 435.3 438.7 450.9 460.9 Other Trucks 37.7 33.3 34.6 35.7 37.3 37.1 38.7 39.6 Buses 0.3 0.4 0.4 0.4 0.4 0.4 0.3 0.3 Motorcycles 1.7 1.7 1.8 1.8 1.8 1.6 1.6 1.6 Boats (Recreational) 9.4 11.2 11.2 11.1 11.2 11.2 11.1 11.0 Distillate Fuel Oil (Diesel) 265.1 338.4 348.4 362.2 374.0 383.2 378.1 392.6

Automobiles 7.4 5.6 5.2 4.0 3.4 3.5 3.4 3.4 Light-Duty Trucks 10.7 15.1 15.4 16.3 16.6 17.2 16.9 17.6 Other Trucks 178.4 246.2 255.2 268.1 282.7 289.9 288.3 301.1 Buses 7.5 8.6 8.7 9.7 9.4 8.8 8.2 8.0 Locomotives 33.3 37.0 37.4 38.5 38.4 39.4 37.9 39.6 Ships & Boats 16.3 16.9 15.0 17.4 17.3 19.1 18.4 17.0 Ships (Bunkers) 11.4 9.1 11.5 8.2 6.2 5.2 5.1 6.0 Jet Fuel 220.4 232.1 235.6 242.9 251.2 240.4 234.4 228.6

Commercial Aircraft 117.2 128.5 126.3 136.4 140.6 132.8 121.7 122.8 Military Aircraft 34.8 21.0 21.5 20.6 21.0 22.8 20.4 20.5 General Aviation Aircraft 6.3 6.1 7.7 9.2 9.2 9.0 9.3 9.4 Other Aircraft b 15.9 20.6 23.4 17.8 19.9 16.4 21.2 16.3 Aircraft (Bunkers) 46.2 55.9 56.7 58.9 60.5 59.4 61.8 59.6 Aviation Gasoline 3.1 2.7 2.4 2.7 2.5 2.4 2.3 2.2

General Aviation Aircraft 3.1 2.7 2.4 2.7 2.5 2.4 2.3 2.2 Residual Fuel Oil 79.3 55.5 52.6 51.9 69.2 45.7 50.4 48.1

Ships & Boats c 23.4 10.6 6.2 13.7 34.6 12.4 27.7 29.5 Ships (Bunkers) c 55.8 44.9 46.4 38.2 34.6 33.2 22.6 18.6 Natural Gas 35.9 41.1 35.1 35.6 35.5 33.9 37.1 35.4

Automobiles + + + + + + + + Light Trucks + + + + + + + + Buses + 0.2 0.2 0.3 0.4 0.5 0.6 0.6 Pipeline 35.9 40.9 34.9 35.3 35.0 33.4 36.4 34.8 LPG 1.4 0.8 1.0 0.8 0.7 0.8 0.9 0.8

Light Trucks 0.5 0.4 0.4 0.3 0.3 0.3 0.3 0.3 Other Trucks 0.8 0.4 0.6 0.5 0.4 0.5 0.5 0.5 Buses + + + + + + + + Electricity 3.0 3.1 3.1 3.2 3.4 3.4 3.2 3.2

Rail 3.0 3.1 3.1 3.2 3.4 3.4 3.2 3.2 Total (Including Bunkers) d 1,563.3 1,716.2 1,751.1 1,799.2 1,842.5 1,821.0 1,844.9 1,854.6 Total (Excluding Bunkers) d 1,449.8 1,606.4 1,636.5 1,693.9 1,741.0 1,723.1 1,755.4 1,770.4 Note: Totals may not sum due to independent rounding.

a Emissions are no longer allocated to gasoline and diesel c onsumption from agriculture and construction, and electricity consumption from pipelines. This based on recognition that EIA statistics account for these activ ities in the industrial sector

. b This category represents all other jet fuel consumption, and may include some small commercial aircraft and jet fuel used for heating oil.

c Fluctuations in emission estimates from th e combustion of residual fuel oil are curren tly unexplained, but may be related to d ata collection problems. d Official estimates exclude emissions from the combustion of both aviation a nd marine international bunker fuels; however, estimates including international bunker fuel-related em issions are presented fo r informational purposes. + Less than 0.05 Tg CO 2 Eq.

Industrial End-Use Sector
The industrial end-use sector accounted for 28 percent of CO 2 emissions from fossil fuel combustion. On average, 55 percent of these emissions resulted from the direct c onsumption of fossil fuels for steam and process heat production. The remaining 45 percent was associated with their consumption of electricity for uses such as motors, electric furnaces, ovens, and lighting.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 59 The industrial end-use sector include s activities such as manufacturing, c onstruction, mining, and agriculture. 12 The largest of these activities in term s of energy consumption is manufactur ing, which was estimated in 1998 to have accounted for about 84 percent of industrial energy c onsumption (EIA 2001a). Just six industries—Petroleum, Chemicals, Primary Metals, Paper, Food, and Stone, Cl ay, and Glass products—represent 83 percent of total manufacturing energy use.

In theory, emissions from the industrial end-use sector should be highly correlated with economic growth and industrial output, but heating of industrial buildings and agri cultural energy consumption is also affected by weather conditions. 13 In addition, structural changes within the U.S. economy that lead to shifts in industrial output away from energy intensive manufacturing products to less energy intensive products (e.g., from steel to computer equipment) also have a significant affect on industrial emissions.

From 2002 to 2003, total industrial production and manufacturing output increased slightly, by 0.2 and 0.1 percent, respectively (FRB 2004). Also from 2002 to 2003, output in creased for the Petroleum Refinery, Nonmetallic Mineral Product, and Chemical industries, but declined for the Primary Metal, Food, and Paper industries (see Figure 3-12).

Figure 3-12: Industrial Production Indexes (Index 1997=100)

Despite the growth in industrial output (44 percent) and the overall U.S. economy (46 percent) from 1990 to 2003, emissions from the industrial end-use sector increased only slightly (by 1 percent). The reasons for the disparity between rapid growth in industrial output and stagnant growth in industrial emissions are not entirely clear. It is likely, though, that several factors have influenced industr ial emission trends, including: 1) more rapid growth in output from less energy-intensi ve industries relative to traditional manuf acturing industries, 2) improvements in energy efficiency; and 3) a lowering of the carbon intensity of fossil fuel consumption as industry shifts from its historical reliance on coal and coke to heavier usage of natural gas. In 2003, carbon dioxide emissions from fossil fuel combustion and electricity use within the industrial end-use sectors were 1,572.9 Tg CO 2 Eq., or 0.4 percent below 2002 emissions.

Residential and Commercial End-Use Sectors

The residential and commercial end-use sectors accounted for an average 21 and 18 percent, respectively, of CO 2 emissions from fossil fuel combustion. Both end-use sector s were heavily reliant on elect ricity for meeting energy needs, with electricity consumption for lighting, heating, air conditioning, and operating appliances contributing to about 67 and 76 percent of emissions from the residentia l and commercial end-use sectors, respectively. The remaining emissions were largely due to the direct consum ption of natural gas and petroleum products, primarily for heating and cooking needs. Coal consumption was a minor component of energy use in both of these end-use sectors. In 2003, CO 2 emissions from fossil fuel combustion and electricity use within the residential and commercial end-use sectors were 1,168.9 Tg CO 2 Eq. and 983.1 Tg CO 2 Eq., respectively.

Emissions from the residential and commercial sectors ha ve generally been increasing since 1990, and are often correlated with short-term fluctuations in energy consum ption caused by weather conditions, rather than prevailing economic conditions (see Table 3-6). In the long-term, both end-use sectors ar e also affected by population growth, regional migration trends, and changes in housing a nd building attributes (e.g., size and insulation).

12 See Glossary (Annex 6.8) for a more detaile d definition of the industrial end-use sector. 13 Some commercial customers are large enough to obtain an i ndustrial 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 commercia l customers likely cause the industrial end-use sector to appear to be more sensitive to weather conditions.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 60 Emissions from natural gas consumption re present over 70 percent of the direct (not including electricity) fossil fuel emissions from the residential and commercial sectors. In 2003, these emissions increased by 4 and 1 percent, respectively, in each of these sectors. Colder winter conditions in the United States (see Figure 3-13) and an increasing U.S. housing stock led to higher demand for natura l gas, despite drastic increases in natural gas prices (66 percent).

Figure 3-13: Heating Degree Days 14

Electricity sales to the residential and commercial e nd-use sectors in 2003 increased by 1 and 0.4 percent, respectively. This trend can largely be attributed to the growing economy (3.1 percent) and increase in U.S. housing stock (1.2 percent), which led to increased dema nd for electricity. Increased consumption due to these factors was somewhat offset by decr eases in air conditioning-related electri city consumption expected with the cooler summer (see Figure 3-14), and increas es in electricity prices (1 and 2 percent higher to the residential and commercial sectors, respectively). Electricity-related emissions in both sectors rose with increasing consumption and the higher carbon intensity of electricity generation. Total emissions from the residential sector increased by 2.1 percent in 2003, with emission from the commercial sector 0.9 percent higher than in 2002.

Figure 3-14: Cooling Degree Days 15



### Electricity Generation

The process of generating electricity is the single largest source of CO 2 emissions in the United States (39 percent). Electricity was consumed primarily in the residential, commercial, and industrial end-use sectors for lighting, heating, electric motors, appliances, electronics, and air conditioning (see Figure 3-15). Electricity generation also accounted for the largest share of CO 2 emissions from fossil fuel combustion, approximately 41 percent in 2003.

Figure 3-15: Electricity Generation Retail Sales by End-Use Sector

The electric power industry includes a ll power producers, consisting of bot h regulated utilities and nonutilities (e.g. independent power producers, qualifying cogenerators, and other small power producers). While utilities primarily generate power for the U.S. electric grid for sale to retail customers, nonutilities produ ce electricity for their own use, to sell to large consumers, or to sell on the wholesale electricity market (e.g., to utilities for distribution and resale to customers). However, the electric power industry in the United States has undergone significant changes as both federal and state government ag encies have modified re gulations to create a more competitive market for electricity generation. These change s have led to the growth of nonutility power producers, including the sale of generating capacity by electric utilities to nonutilities. As a result, the Department of Energy no longer categorizes electric power generation into these ownership groups, and instead uses three functional categories: the electric power sector, the commercial sector, and the industrial sector . The electric power sector consists of electric utilities and independent power producers whose primary business is the production of electricity, while the other sectors consist of those producers that indicate their primary business is other than the production of electricity.

In 2003, the amount of electricity generated decreased very slightly, by 0.3 percent. Although total U.S. electricity use actually increased by 1 percent, net generation declin ed due to increased net imports and reduced losses of

14 Degree days are relative measur ements of outdoor air temperature. Heating de gree days are deviations of the mean daily temperature below 65 ° F. Excludes Alaska and Hawaii. No rmals are based on data from 1971 through 2000. 15 Degree days are relative measur ements of outdoor air temperature. Cooling de gree days are deviations of the mean daily temperature above 65 ° F. Excludes Alaska and Hawaii. No rmals are based on data from 1971 through 2000.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 61 electricity. 16 However, CO 2 emissions increased by 1.2 percent, as escalating natural gas prices caused power producers to switch from natural gas to coal, a more carbon-intensive fuel. Coal consumption for electricity generation increased by 2.0 percent in 2003, while natural ga s consumption decreased by 9.2 percent. As a result of this shift, carbon intensity from energy consumption for electricity generation increased in 2003 (see Table 3-9). Coal is consumed primarily by the electric power sector in the United States, which accounted for 93 percent of total coal consumption for energy purposes in 2003. Elect ricity generation by nuclear and renewable resources remained relatively stable, increasing 1 percent in 2003.

[BEGIN BOX]

Box 3-2: Carbon Intensity of U.S. Energy Consumption

Fossil fuels are the dominant source of energy in the United States, and CO 2 is emitted as a product from their combustion. Useful energy, however, can be generated from many other sources that do not emit CO 2 in the energy conversion process. In the United States, useful energy is also produced from renewable (i.e., hydropower, biofuels, geothermal, solar, and wind) and nuclear sources. 17

Energy-related CO 2 emissions can be reduced by not only lowering total energy consumption (e.g., through conservation measures) but also by lowering the carbon intensity of the energy sources employed (e.g., fuel switching from coal to natural gas). The amount of carbon emitted from the combustion of fossil fuels is dependent upon the carbon content of the fuel and the fraction of that carbon that is oxidized. 18 Fossil fuels vary in their average carbon content, ranging from about 53 Tg CO 2 Eq./QBtu for natural gas to upwards of 95 Tg CO 2 Eq./QBtu for coal and petroleum coke. 19 In general, the carbon content per unit of energy of fossil fuels is the highest for coal products, followed by petroleum, and then natural gas. Other sources of energy, however, may be directly or indirectly carbon neutral (i.e., 0 Tg CO 2 Eq./Btu). Energy generated from nuc lear and many renewable sources do not result in direct emissions of CO 2 . Biofuels such as wood and ethanol are also considered to be carbon neutral; although these fuels do emit CO 2 , in the long run the CO 2 emitted from biomass consumption does not increase atmospheric CO 2 concentrations if the biogenic carbon emitted is offset by the growth of new biomass. 20 The overall carbon intensity of the U.S. economy is thus depende nt upon the quantity and combin ation of fuels and other energy sources employed to meet demand.

Table 3-8 provides a time series of the carbon intensity fo r each sector of the U.S. economy. The time series incorporates only the energy consumed from the direct combustion of fossil fuel s in each sector. For example, the carbon intensity for the residential sector does not include the energy from or emissions related to the consumption of electricity for lighting or wood for heat. Looking only at this direct consumption of fossil fuels, the residential sector exhibited the lowest carbon intensity, which is related to the large percentage of its energy derived from

16 EIA statistics track net generation, impor ts, exports, and compare thes e with the end use of electricity. The difference between these values is classi fied as “T&D losses and Unaccounted for”. T&D losses refer to electricity lost during the transmission and distribution of electricity from the source to th e end user. There also exists a small amount of electricity not accounted for due to data collection time fra me differences and nonsampling error. 17 Small quantities of CO 2 , however, are released from some geologic form ations tapped for geothermal energy. These emissions are included with fossil fuel co mbustion emissions from the electricity gene ration. Carbon dioxide emissions may als o be generated from upstream activities (e.g., manufacture of the equi pment) associated with fossil fuel and renewable energy activities, but are not accounted for here. 18 Generally, more than 97 percent of th e carbon in fossil fuel is oxidized to CO 2 with most carbon combustion technologies used in the United States. 19 One exajoule (EJ) is equal to 10 18 joules or 0.9478 QBtu. 20 Net carbon fluxes from changes in biogenic carbon reservoirs in wooded or croplands are accounted for in the estimates for Land-Use Change and Forestry.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 62 natural gas for heating. The carbon intensity of the commercial sector has predominantly declined since 1990 as commercial businesses shift away from petroleum to natura l gas. The industrial sector was more dependent on petroleum and coal than either the re sidential or commercial sectors, and t hus had higher carbon intensities over this period. The carbon intensity of the transportation sector was closely related to the carbon content of petroleum products (e.g., motor gasoline and jet fuel, both around 70 Tg CO 2 Eq./EJ), which were the primary sources of energy. Lastly, the electricity generation sector had the highest carbon intensity due to its heavy reliance on coal for generating electricity.

Table 3-8: Carbon Intensity from Direct Fossil Fuel Combustion by Sector (Tg CO 2 Eq./QBtu) Sector 1990 1997 1998 1999 2000 2001 2002 2003 Residential a 57.0 56.5 56.5 56.6 56.6 56.7 56.6 56.5 Commercial a 59.3 57.4 57.1 57.1 57.2 57.3 57.2 57.3 Industrial a 66.1 65.8 65.2 65.1 65.1 64.7 64.5 65.0 Transportation a 70.3 70.1 70.1 70.2 70.3 70.3 70.3 70.3 Electricity Generation b 85.8 85.9 85.2 84.9 84.7 84.3 84.1 84.8 U.S. Territories c 73.3 73.3 73.2 73.0 72.5 72.9 73.0 73.5 All Sectors c 72.6 72.5 72.6 72.5 72.5 72.3 72.2 72.5

a Does not include electricity or renewable energy consumption. b Does not include electricity produced using nuclear or renewable energy.

c Does not include nuclear or renewable energy consumption. Note: Excludes non-energy fuel us e emissions and consumption.

In contrast to Table 3-8, Table 3-9 presents carbon intensity values that incorporate energy consumed from all sources (i.e., fossil fuels, renewables, a nd nuclear). In addition, the emissions related to the generation of electricity have been attributed to both electricity generation and the end-use sectors in which that electricity was eventually consumed. 21 This table, therefore, provides a more complete picture of the actual carbon intensity of each end-use sector per unit of energy consumed. The transportation end-use sector in Table 3-9 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 et hanol. The “other end-use sectors” (i.e., residential, commercial, and industrial) use significant quantities of bi ofuels such as wood, thereby lowering the overall carbon intensity. The carbon intensity of the electricity generation sector differs greatly from the scenario in Table 3-8, 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 CO 2 . Table 3-9: Carbon Intensity from all Energy Consumption by Sector (Tg CO 2 Eq./QBtu) Sector 1990 1997 1998 1999 2000 2001 2002 2003 Transportation a 70.1 69.8 69.8 69.8 69.9 69.8 69.8 69.6 Other End-Use Sectors a, b 57.8 57.8 57.9 57.3 58.0 58.2 57.5 58.0 Electricity Generation c 58.4 58.9 59.1 58.2 59.2 59.3 58.3 59.0 All Sectors d 61.1 61.0 61.1 60.8 61.3 61.5 60.9 61.2

a Includes electricity (from fossil fuel, nuclear, and renewa ble sources) and direct rene wable energy consumption. b Other End-Use Sectors includes the residen tial, commercial, and industrial sectors.

c Includes electricity generation fro m nuclear and renewable sources. d Includes nuclear and renewable energy consumption. Note: Excludes non-energy fuel use emissions and consumption.

21 In other words, the emissions from the generation of electric ity are intentionally double counted by attributing them both to electricity generation and the end-use sector in which electricity consumption occurred.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 63 By comparing the values in Table 3-8 and Table 3-9, a few observations can be made. The use of renewable and nuclear energy sources has resulted in a significantly lower carbon intensity of the U.S. economy. Over the thirteen-year period of 1990 through 2003, however, the carbon intensity of U.S. energy consumption has been fairly constant, as the proportion of renewable and nuc lear energy technologies has not changed significantly.

The carbon intensity of total energy consumption in the United States has remained fairly constant. Per capita energy consumption has fluctuated, but has generally de monstrated a constant overall trend since 1990 (see Figure 3-16). Due to a general shift from a manufacturing-base d economy to a service-based economy, as well as overall increases in efficiency, energy consumption and energy-related CO 2 emissions per dollar of gross domestic product (GDP) have both declined since 1990.

Figure 3-16: U.S. Energy Consumption and Energy-Related CO 2 Emissions Per Capita and Per Dollar GDP

Carbon intensity estimates were developed using nuclear and renewable energy data from EIA (2004a) and fossil fuel consumption data as discussed above and presented in Annex 2.1.

[END BOX]


### Methodology

The methodology used by the United States for estimating CO 2 emissions from fossil fuel combustion is conceptually similar to the approach recommended by the IPCC for countries that intend to develop detailed, sectoral-based emission estimates (IPCC/UNEP/OECD/IEA 1997). A detailed description of the U.S. methodology is presented in Annex 2.1, and is characterized by the following steps:

1. Determine total fuel consumption by fuel type and sector . Total fossil fuel consumption for each year is estimated by aggregating consumption data by end-use s ector (e.g., commercial, industrial, etc.), primary fuel type (e.g., coal, petroleum, gas), and s econdary fuel category (e.g., motor gasoline, distillate fuel oil, etc.). Fuel consumption data for the United States were obtained directly from the Energy Information Administration (EIA) of the U.S. Department of Energy (DOE), primarily from the Monthly Energy Review and unpublished supplemental tables on petroleum product detail (EIA 2004b). The United States does not include territories in its national energy statistics, so fuel consumption data for territories were collected separately from Grillot (2004). 22

For consistency of reporting, the IPCC has recomme nded that countries report energy data using the International Energy Agency (IEA) reporting conventi on and/or IEA data. Data in the IEA format are presented "top down"

⎯ that is, energy consumption for fuel type s and categories are estimated from energy production data (accounting for imports , exports, stock changes, and lo sses). The resulting quantities are referred to as "apparent consumption." The data collect ed in the United States by EIA, and used in this inventory, are, instead, "bottom up" in nature. In other words, they are collected through surveys at the point of delivery or use and aggregated to determine national totals. 23

It is also important to note that U.S. fossil fuel energy statistics are generally presented using gross calorific values (GCV) (i.e., higher heating values). Fuel cons umption activity data presented here have not been

22 Fuel consumption by U.S. territories (i.e. American Samoa, Guam, Puerto Rico, U.S. Virgin Islands, Wake Island, and other U.S. Pacific Islands) is incl uded in this report and contributed emissions of 56 Tg CO 2 Eq. in 2003. 23 See IPCC Reference Approach for estimating CO 2 emissions from fossil fuel combustion in Annex 4 for a comparison of U.S. estimates using top-down and bottom-up approaches.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 64 adjusted to correspond to international standard, which are to report energy statistics in terms of net calorific values (NCV) (i.e., lower heating values). 24

2. Subtract uses accounted for in the Industrial Processes chapter. Portions of the fuel consumption data for five fuel categories—coking coal, petroleum coke, natural gas, residual fuel oil, and other oil—were reallocated to the industrial processes chapter, as they were consumed during non-energy related industrial activity. To make these adjustments, additional data were collected from Gambogi (2004), EFMA (1995), U.S. Census Bureau (1991 through 1994), U.S. Census Bureau (1998 through 2003), U.S. Census Bureau (2003), U.S. Census Bureau (2004a), EIA (2000 through 2004), EIA (2001b), USGS (2003 through 2004), USGS (1998 through 2002), USGS (1995), USGS (1995 through 2004), USGS (1991 through 1994), USGS (1991 through 2003), U.S. International Trade Commission (2004a), U.S. International Trade Commission (2004b), and Onder and Bagdoyan (1993). 25

3. Adjust for biofuels, conversion of fossil fuels, and exports of CO 2 . Fossil fuel consumption estimates are adjusted downward to exclude 1) fuels with biogenic orig ins, 2) fuels created from other fossil fuels, and 3) exports of CO 2 . Fuels with biogenic origins are assumed to result in no net CO 2 emissions, and must be subtracted from fuel consumption estimates. These fuel s include ethanol added to motor gasoline and biomass gas used as natural gas. Synthetic natural gas is creat ed from industrial coal, and is currently included in EIA statistics for both coal and natural gas. Therefore, synt hetic natural gas is subtracted from energy consumption statistics. 26 Since October 2000, the Dakota Gasification Plant has been exporting CO 2 to Canada by pipeline. Since this CO 2 is not emitted to the atmosphere in the Un ited States, energy used to produce this CO 2 is subtracted from energy consumption statistics. To make these adjustments, additional data for ethanol and biogas were collected from EIA (2004b) and data for sy nthetic natural gas were collected from EIA (2004e), and data for CO 2 exports were collected from the Dakota Gasification Company (2003), Fitzpatrick (2002), and Erickson (2003).

4. Adjust for fuels consumed for non-energy uses . U.S. aggregate energy statistics include consumption of fossil fuels for non-energy purposes. Depending on the end-use, this can result in storage of some or all of the carbon contained in the fuel for a period of time. As the emission pathways of carbon used for non-energy purposes are vastly different than fuel combus tion, these emissions are estimated separately in the Carbon Emitted and Stored in Products from Non-Energy Uses of Fossil Fuels s ection in this chapter. Therefore, the amount of fuels used for non-energy purposes was subtracted from total fuel consumption. Data on non-fuel consumption was provided by EIA (2004b).

5. Subtract consumption of international bunker fuels . According to the UNFCCC reporting guidelines emissions from international transport activities, or bunker fuels, should not be in cluded in national totals. U.S. energy consumption statistics include these bunker fu els (e.g., distillate fuel oil, residual fuel oil, and jet fuel) as part of consumption by the transportation end-use sector, however, so emissions from international transport activities were calculated separately following the same procedur es used for emissions from consumption of all fossil fuels (i.e., estimation of consumption, determination of carbon content, and adjustment for the fraction of carbon not oxidized). 27 The Office of the Under Secretary of Defense (Installations and Environment) and the Defense Energy Support Center (Defense Logistics Agen cy) of the U.S. Department of Defense (DoD) (DESC 2004) supplied data on military jet fuel use. Comme rcial jet fuel use was obt ained from BEA (1991 through

24 A crude convention to convert between gross and net calorific va lues is to multiply the heat content of solid and liquid fossi l fuels by 0.95 and gaseous fuels by 0.9 to account for the water content of the fuels. Biomass-based fuels in U.S. energy statistics, however, are generally pr esented using net calorific values. 25 See sections on Iron and Steel Production, Ammonia Manufactur e, Petrochemical Production, Titanium Dioxide Production, Ferroalloy Production, and Aluminum Producti on in the Industrial Processes chapter. 26 These adjustments are explained in greater detail in Annex 2.1. 27 See International Bunker Fuels section in th is chapter for a more detailed discussion.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 65 2004) and DOT (1991 through 2004); residua l and distillate fuel use for ci vilian marine bunkers was obtained from DOC (1991 through 2004). Consumption of these fuels was subtracted from the corresponding fuels in the transportation end-use sector. Estimates of international bunker fuel emissions are discussed further in the section entitled International Bunker Fuels.

6. Determine the total carbon content of fuels consumed . Total carbon was estimated by multiplying the amount of fuel consumed by the amount of carbon in each fu el. This total carbon estimate defines the maximum amount of carbon that could potentially be released to the atmosphere if all of the carbon in each fuel was converted to CO 2 . The carbon content coefficients used by the United States were obtained from EIA’s Emissions of Greenhouse Gases in the United States 2003 (EIA 2004c) and EIA’s Monthly Energy Review and unpublished supplemental tables on petroleum product deta il EIA (EIA 2004b). They are presented in Annexes 2.1 and 2.2.

7. Adjust for carbon that does not oxidize during combustion . Because combustion processes are not 100 percent efficient, some of the carbon containe d in fuels is not emitted to the atmosphere. Rather, it remains behind as soot and ash. The estimated amount of carbon not oxidized due to inefficiencies during the combustion process was assumed to be 1 percent for petroleum and coal and 0.5 percent for natural gas (see Annex 2.1). Unoxidized or partially oxidized organic (i.e., carbon c ontaining) combustion products were assumed to have eventually oxidized to CO 2 in the atmosphere. 28 IPCC provided fraction oxidized values for petroleum and natural gas (IPCC/UNEP/OECD/IEA 1997). Bechtel (1993) provided the fraction oxidation value for coal.

8. Allocate transportation emissions by vehicle type . This report provides a more detailed accounting of emissions from transportation because it is such a la rge consumer of fossil fuels in the United States. 29 For fuel types other than jet fuel, fuel consumption data by vehi cle type and transportation mode were used to allocate emissions by fuel type calculated for the transportation end-use sector. For jet fuel, CO 2 emissions were calculated directly based on reported consumption of fuel . For highway vehicles, annual estimates of combined motor gasoline and diesel fuel consumption by ve hicle category were obtained from FHWA (1996 through 2004); for each vehicle category, the per cent gasoline, diesel, and other (e.g ., CNG, LPG) fuel consumption are estimated using data from DOE (1993 through 2004). For non-highway vehicles, activity data were obtained from AAR (2004), BEA (1991 through 2004), Benson (2002 through 2004), DOE (1993 through 2004), DESC (2004), DOC (1991 through 2004), DOT (1991 through 2004), EIA (2002a), EIA (2002b), EIA (2004a), EIA (2004b), EIA (2003 through 2004), EIA (1991 through 2004), EPA (2004c), and FAA (2004). Heat contents and densities were obtained fro m EIA (2004a) and USAF (1998). 30 The difference between total U.S. jet fuel consumption (as reported by EIA) and civilian air carrier consumption for both domestic and international flights (as reported by DOT and BEA) plus military jet fuel consumption is reported as “other” under the jet fuel category in Table 3-7, and includes such fuel uses as blending with heating oils and fuel used for chartered aircraft flights.


### Uncertainty

For estimates of CO 2 from fossil fuel combustion, the amount of CO 2 emitted is directly related to the amount of fuel consumed, the fraction of the fuel that is oxidized, and the carbon content of the fuel. Therefore, a careful accounting of fossil fuel consumption by fuel type, average carbon contents of fossil fuels consumed, and production of fossil fuel-based products with long-term carbon storage should yield an accurate estimate of CO 2 emissions.

28 See Indirect CO 2 from CH 4 Oxidation section in this chapte r for a more detailed discussion. 29 Electricity generation is not considered a final end-use sector, because energy is consumed primarily to provide electricity t o the other sectors. 30 For a more detailed description of the data sources used for th e analysis of the transportation end use sector see the Mobile Combustion (excluding CO 2 ) and International Bunker Fuels sections of the Energy chapter, Annex 3.2, and Annex 3.7.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 66 Nevertheless, there are uncertainties in the consump tion data, carbon content of fuels and products, and carbon oxidation efficiencies. For ex ample, given the same primary fuel type (e.g., coal, petroleum, or natural gas), the amount of carbon contained in the fuel per unit of useful energy can vary. For the United States, however, the impact of these uncertainties on overall CO 2 emission estimates is believed to be relatively small. See, for example, Marland and Pippin (1990).

Although statistics of total fossil fuel and other energy consumption are rela tively accurate, the allocation of this consumption to individual end-use sectors (i.e., residentia l, commercial, industrial, and transportation) is less certain. For example, for some fuels th e sectoral allocations are based on pri ce rates (i.e., tariffs), but a commercial establishment may be able to negotiate an industrial rate or a small industrial establishment may end up paying an industrial rate, leading to a misallocation of emissions. Also, the deregulation of the natural gas industry and the more recent deregulation of the elect ric power industry have likely led to some minor problems in collecting accurate energy statistics as firms in these i ndustries have undergone si gnificant restructuring.

To calculate the total CO 2 emission estimate from energy-related fossil fuel combustion, the amount of fuels used in these non-energy production processes were subtracted from the total fossil fuel consumption for 2003. The amount of CO 2 emissions resulting from non-energy related fossil fuel us e has been calculated separately and reported in the Carbon Emitted from Non-Energy Uses of Fossil Fuels secti on of this report. Additiona lly, inefficiencies in the combustion process, which can result in ash or soot re maining unoxidized for long periods, were also assumed. These factors all contribute to the uncertainty in the CO 2 estimates. Detailed discussions on the uncertainties associated with Carbon emitted from Non- Energy Uses of Fossil Fuels can be found within that section of this chapter.

Various sources of uncertainty surround the estimation of emissions from international bunker fuels, which are subtracted from the U.S. totals (see the detailed discussions on these uncertainties provided in the International Bunker Fuels section of this chapter). Another source of uncertainty is fuel consumption by U.S. territories. The United States does not collect energy statistics for its territori es at the same level of detail as for the fifty states and the District of Columbia. Therefore, estimating both emissions and bunker fuel consumption by these territories is difficult.

Uncertainties in the emission estimates presented above also result from the data used to allocate CO 2 emissions from the transportation end-use sector to individual vehicl e types and transport modes. In many cases, bottom-up estimates of fuel consumption by vehicle type do not match aggregate fuel-type estimates from EIA. Further research is planned to improve the allocation into detaile d transportation end-use sector emissions. In particular, residual fuel consumption data for marine vessels are hi ghly uncertain, as shown by the large fluctuations in emissions that do not mimic changes in other variables such as shipping ton miles.

The uncertainty analysis was performed by primary fuel type for each end- use sector, using the IPCC-recommended Tier 2 uncertainty estimation methodology, Monte Carlo Simulation technique, with @RISK software. For this uncertainty estimation, the inventory estimation model for CO 2 from fossil fuel combustion was integrated with the relevant inventory variables from the inventory estimation model for International Bunker Fuels, to realistically characterize the interaction (or endogenous correlation) between the variables of these two models. About 150 input variables were modeled for CO 2 from energy-related Fossil Fuel Combustion (including about 10 for nonenergy fuel consumption and about 20 for International Bunker Fuels).

In developing the uncertainty estimation model, uniform distributions were assumed for all activity-related input variables and emission factors, based on the SAIC/EIA (2001) report. 31 Triangular distributions were assigned for

31 SAIC/EIA (2001) characterizes the underlyi ng probability density function for the input variables as a combination of uniform and normal distributions (the former to represent the bias component and the latte r to represent the random component). However, for purposes of the current uncerta inty analysis, it was determined that unifo rm distribution was more appropriate to characterize the probability density func tion underlying each of these variables.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 67 the oxidization factors (or combustion efficiencies). The uncertainty ranges were assigned to the input variables based on the data reported in SAIC/EIA (2001) a nd on conversations with various agency-personnel. 32

The uncertainty ranges for the activity-related input vari ables were typically asymmetric around their inventory estimates; the uncertainty ranges for the emissions factor s were symmetric. Bias (or systematic uncertainties) associated with these variables accounted for much of th e uncertainties associated with these variables (SAIC/EIA 2001). 33 For purposes of this uncertainty analysis, each input variable was simula ted 10,000 times through Monte Carlo Sampling.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-10. Fossil fuel combustion CO 2 emissions in 2003 were estimated to be between 5,474.3 and 5,863.3 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Simulations). This i ndicates a range of 1 percent below to 6 percent above the 2003 emission estimate of 5,551.6 Tg CO 2 Eq.

Table 3-10: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Energy-related Fossil Fuel Combustion by Fuel Type and Sector (Tg CO 2 Eq. and Percent)

Fuel/Sector 2003 Emission Estimate (Tg CO 2 Eq.) Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (%) Lower Bound Upper Bo und Lower Bound Upper Bound Coal b 2,013.8 1,962.0 2,220.5 -3% +10%

Residential 1.1 1.1 1.3 -5% +16% Commercial 9.3 8.9 10.8 -4% +16% Industrial 123.4 120.0 144.1 -3% +17% Transportation NE NE NE NA NA Electricity Generation 1,876.3 1815.7 2,072.5 -3% +10% U.S. Territories 3.6 3.2 4.3 -12% +20% Natural Gas b 1,170.3 1,161.0 1,229.9 -1% +5%

Residential 277.3 270.5 297.7 -2% +7% Commercial 170.7 166.5 183.2 -2% +7% Industrial 407.9 396.6 439.0 -3% +8% Transportation 35.4 34.5 38.0 -2% +7% Electricity Generation 277.6 270.5 292.8 -3% +5% U.S. Territories 1.4 1.2 1.7 -12% +17% Petroleum b 2,367.1 2,256.9 2,518.5 -5% +6%

Residential 106.7 101.7 112.5 -5% +6% Commercial 53.9 51.6 56.7 -4% +5% Industrial 327.3 283.4 386.0 -13% +18% Transportation 1,731.8 1,627.9 1,857.2 -6% +7% Electric Utilities 96. 3 93.8 101.8 -3% +6% U.S. Territories 51.2 47.6 57.2 -7% +12% Total (excluding Geothermal) b 5,551.2 5,474.0 5,863.0 -1% +6%

32 In the SAIC/EIA (2001) report, the quan titative uncertainty estimates were develope d for each of the three major fossil fuels used within each end-use sector; the variati ons within the sub-fuel types within each end-use sector were not modeled. However, for purposes of assigning uncertainty estimates to the sub-fuel type categories within each end-use sector in the current uncertainty analysis, SAIC/EIA (2001)-reported uncertainty estimates were extrapolated. 33 Although, in general, random uncertainties are the main focus of statistical uncertainty an alysis, when the uncertainty estimates are elicited from experts, their estimates include both random and systematic uncertainties. Hence, both these types of uncertainties are represented in this uncertainty analysis.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 68 Geothermal 0.3 NE NE NE NE Total (including Geothermal) b,c 5,551.6 5,474.3 5,863.3 -1% +6% NA (Not Applicable) NE (Not Estimated) Notes:

a Range of emission estimates predic ted by Monte Carlo Simulation for a 95 percent confidence interval.

b The low and high estimates for total emissi ons were calculated separately through si mulations and, hence, the low and high emission estimates for the sub-source cat egories do not sum to total emissions.

c Geothermal emissions added for re porting purposes, but an uncertainty analysis was not performed for CO 2 emissions from geothermal production. 

### QA/QC and Verification

A source-specific QA/QC plan for CO 2 from fossil fuel combustion was developed and implemented. This effort included a Tier 1 analysis, as well as portions of a Tier 2 analysis. The Tier 2 procedures that were implemented involved checks specifically focusing on the activity data and methodology used for estimating CO 2 emissions from fossil fuel combustion in the United States. Emission totals for the different sectors a nd fuels were compared and trends were investigated to determin e whether any corrective actions were n eeded. Minor corrective actions were taken.



### Recalculations Discussion

A major change this year was the decision to report emissions from fuels used for non-energy purposes separately from fuel combustion emission estimates. Previously, the carbon stored from non-energy uses was subtracted from total carbon in fuels. However, this method resulted in non-energy emissions being reported within the emission estimates for fuel combustion. This year, these emissi ons are reported separately in the section entitled “Carbon Emitted and Stored in Products from N on-Energy Uses of Fossil Fuels.”

Bunker fuel consumption estimates are now subtracted out from total fuel consumption, instead of subtracting the total carbon in bunker fuels from total potential carbon. This change in methodology does not have any affect on emission estimates, though it allows for clearer and more transparent emission calculations.

Adjustments are now made to the consumption data for residual oil and other oils (>401 deg F) to subtract consumption for carbon black production, for which emissions are estimated in the Petrochemical Production section of the Industrial Processes chapter.

EIA statistics report consumption for non-energy use for a num ber of fuels to be roughly equivalent to total use of these fuels, though for certain years these data series did not match exactly. After discussions with EIA, it was assumed that 100 percent of the use of these fuels should be assumed to be for non-energy purposes. These fuels are asphalt & road oil, lubricants, naphtha, other oil (> 401 deg. F), special naphtha, waxes, and miscellaneous products.

The Energy Information Administration (EIA 2004a) update d energy consumption data for all years. These revisions primarily impacted the emission estimates for 2002.

The combination of the methodological and historical data changes, as well as changes in the estimates of Carbon Emitted and Stored in Products from Non-Energy Uses of Fo ssil Fuels and International Bunker Fuels (which affect emissions from this source) resulted in an average annual decrease of 115.8 Tg CO 2 Eq. (2.2 percent) in CO 2 emissions from fossil fuel combustion for the period 1990 through 2002. This decrease is largely a result of reporting emissions from non-energy uses separately this year.


### Planned Improvements

Several items are being evaluated to improve the estimates of CO 2 emissions from fossil fuel combustion and to reduce uncertainty:Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 69 • Currently, the IPCC guidelines recommend a default factor of 0.99 to represent the fraction of carbon in fossil fuels that is oxidized to CO 2 during the fuel combustion of petroleum, though national experts are encouraged to improve upon this assumption if better data is available. As a result, carbon mass balances for light-duty gasoline cars and trucks have been analyzed to asse ss what would be the most appropriate carbon oxidation fraction for these vehicles. The analysis, currently under peer review, suggests that the amount of unoxidized carbon is insignificant compared to the gaseous carbon fraction, and that 1.00 should be used to represent the oxidized carbon fraction in future inventories for gasoline fueled light-duty vehicles. Upon further peer review, the revised factor is expected to be used in future invent ories. A further examination into diesel fueled vehicles is also planned.

• The 0.99 oxidation factor for coal will be further investigated in order to verify or revise this value.

• Efforts will be taken to work with EIA and other agencies to improve the quality of the U.S. territories data.

These improvements are not all-inclusive, but are part of an ongoing analysis and efforts to continually improve the CO 2 from fossil fuel combustion estimates.



### 3.2. Carbon Emitted from Non-Energy Uses of Fossil Fuels (IPCC Source Category 1A)

In addition to being combusted for energy, fossil fuels are also consumed for non-energy uses (NEU). These fuels are used in the industrial and transportation end-use sect ors and are quite diverse, including natural gas, liquid petroleum gases (LPG), asphalt (a viscous liquid mixture of heavy crude oil distillates), petroleum coke (manufactured from heavy oil), and coal coke (manufactur ed from coking coal). The non-energy fuel uses are equally diverse, and include application as solvents, lubri cants, and waxes, or as raw materials in the manufacture of plastics, rubber, and synthetic fibers.

Carbon dioxide emissions arise from non-energy uses via several pathways. Emissions may occur during the manufacture of a product, as is the case in producing plastic s or rubber from fuel-derived feedstocks. Additionally, emissions may occur during the product’s lifetime, such as during solvent use. Overall, throughout the time series and across all uses, about 65 percent of the total carbon c onsumed for non-energy purposes is stored in products, and not released to the atmosphere; the remaining 35 percent is emitted.

There are several areas in which non-energy uses of fossil fuels relates closely to other parts of the inventory. For example, some of the NEU products release CO 2 at the end of their commercial lif e when they are combusted; these emissions are reported separately within this sector in the Waste Combustion source category. In addition, there is some overlap between fossil fuels consumed for non-energy uses and the fossil-derived CO 2 emissions accounted for in the Industrial Processes sector. To avoid double-counting, the “raw” non-energy fuel consumption data reported by EIA are modified to account for these overlaps, resulting in the ad justed consumption values shown in Table 3-12. There are also net exports of petrochemicals that are not completely account ed for in the EIA data, and these affect the mass of carbon in non-energy applications; th e effects of these adjustments are also shown in Table 3-11.

As shown in Table 3-11, fossil fuel emissions in 2003 from the non-energy uses of fossil fuels were 118.0 Tg CO 2 Eq., which constituted 2 percent of overall fossil fuel emi ssions, approximately the same proportion as in 1990. In 2003, the consumption of fuels for non-energy uses (aft er the adjustments described above) was 5,264 TBtu, an increase of 24 percent since 1990 (see Table 3-12). About 66.1 Tg of the C (242.5 Tg CO 2 Eq.) in these fuels was stored, while the remaining 32.2 Tg C (118.0 Tg CO 2 Eq.) was emitted. The proportion of C emitted has remained about constant since 1990, at about 31 to 35 percent of total non-energy consumption (see Table 3-13).

Table 3-11: CO 2 Emissions from Non-Energy Use Fossil Fuel Consumption (Tg CO 2 Eq.)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 70 Year 1990 1997 1998 1999 2000 2001 2002 2003 Potential Emissions 299.3 348.3 373.3 395.0 365.8 357.8 360.9 360.5 Carbon Stored 191.4 228.0 238.0 253.4 241.1 237.7 242.1 242.5 Emissions 108.0 120.3 135.4 141.6 124.7 120.1 118.8 118.0 

### Methodology

The first step in estimating carbon stored in products wa s to determine the aggregat e quantity of fossil fuels consumed for non-energy uses. The carbon content of these feedstock fuels is equivalent to potential emissions, or the product of consumption and the fuel-specific carbon cont ent values. Both the non-energy fuel consumption and carbon content data were supplied by the EIA (2003) (see Anne x 2.1). Consumption of natural gas, LPG, pentanes plus, naphthas, other oils, and special naphtha were adjusted to account for net exports of these products that are not reflected in the raw data from EIA. Consumption values for industrial coking coal, petroleum coke, other oils, and natural gas in Table 3-12 and Table 3-13, have been adjust ed to subtract non-energy uses that are included in the source categories of the Industrial Processes sector. 34

For the remaining non-energy uses, the amount of C stored was estimated by multiplyi ng the potential emissions by a storage factor. For several fuel types—petrochemical feedstocks (natural gas for non-fertilizer uses, LPG, pentanes plus, naphthas, other oils, still gas, special naphtha, and i ndustrial other coal), asphalt and road oil, lubricants, and waxes—U.S. data on C stocks and flows were used to develop C storage factors, calculated as the ratio of (a) the C stored by the fuel’s non-energy products to (b) the total C content of the fuel consumed. A lifecycle approach was used in the development of these factors in order to account for losses in the production process and during use. Because losses associated with municipal solid waste manageme nt are handled separately in this sector under the Waste Combustion source categor y, the storage factors do not account for losses at the disposal end of the life cycle. For i ndustrial coking coal and distillate fuel o il, storage factors were taken from the IPCC Guidelines for National Greenhouse Gas Inventories , which in turn draws from Marland and Rotty (1984). For the remaining fuel types (petroleum coke, miscella neous products, and other petr oleum), IPCC does not provide guidance on storage factors, and assumptions were made based on the potential fate of carbon in the respective NEU products.

34 These source categories include Iron and Steel Production, Ammonia Manufacture, Carbon Black Manufacture (included in Petrochemical Production), Titanium Dioxide Production, Ferroalloy Producti on, and Aluminum Production.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 71 Table 3-12: Adjusted Consumption of Fossil Fuels for Non-Energy Uses (TBtu) Year 1990 1997 1998 1999 2000 2001 2002 2003 Industry 3,993.2 4,794.6 5,127.6 5,398.1 4,985.1 4,933.3 5,016.4 5,023.4

Industrial Coking Coal 20.5 27.6 15.4 6.3 14.8 23.7 7.0 3.0 Industrial Other Coal 8.2 11.2 10.4 11.1 12.4 11.3 12.0 11.9 Natural Gas to Chemical Plants, Other Uses 244.1 323.7 376.3 390.3 388.9 394.0 402.0 401.0

Asphalt & Road Oil 1,170.2 1,223.6 1,262.6 1,324.4 1,275.7 1,256.9 1,240.0 1,217.4 LPG 1,001.9 1,440.9 1,568.1 1,651.2 1,497.2 1,483.9 1,550.4 1,478.4 Lubricants 186.3 182.3 190.8 192.8 189.9 174.0 171.9 160.8 Pentanes Plus 69.9 260.9 185.2 239.0 214.7 193.2 164.6 162.4 Naphtha (<401 deg. F) 294.3 467.8 529.1 458.6 556.5 473.2 559.5 588.4 Other Oil (>401 deg. F) 615.4 608.8 593.8 619.5 515.5 506.1 460.9 530.0 Still Gas 21.3 2.1 0.0 16.1 12.6 35.8 57.8 133.0 Petroleum Coke 90.7 29.9 124.7 193.9 53.9 132.8 113.6 90.9 Special Naphtha 92.1 63.8 98.1 133.9 89.1 75.5 98.7 77.5 Distillate Fuel Oil 7.0 10.4 11.7 11.7 11.7 11.7 11.7 11.7 Waxes 33.3 43.7 42.4 37.4 33.1 36.3 32.2 31.0 Miscellaneous Products 137.9 97.8 119.0 111.9 119.3 124.9 134.2 126.0 Transportation 176.0 172.1 180.2 182.1 179.4 164.3 162.4 151.8

Lubricants 176.0 172.1 180.2 182.1 179.4 164.3 162.4 151.8 U.S. Territories 86.7 92.5 94.8 114.5 165.5 80.3 80.6 88.7

Lubricants 0.7 2.5 1.3 1.4 16.4 0.0 0.0 0.0 Other Petroleum (Misc. Prod.) 86.0 90.0 93.5 113.1 149.1 80.3 80.5 88.7 Total 4,255.9 5,059.3 5,402.5 5,694.6 5,330.0 5,177.9 5,259.4 5,263.9 Note: To avoid double-counting, coal coke, pe troleum coke, natural gas consumption, a nd other oils are adjusted for industrial process consumption reported in the Industrial Processes sector. Natural gas, LPG, Pentanes Plus, Naphthas, Special Naphtha, and Other Oils are adjusted to account for exports of chemical intermediates derived from these fuels. For residual oil (not shown in the table), all non-energy use is assumed to be consumed in carbon black production, which is also reported in the Industrial Processes sector. - Not applicable. Note: Totals may not sum due to independent rounding.

Table 3-13: 2003 Adjusted Non-Energy Use Fossil Fuel Consumption, Storage, and Emissions Sector/Fuel Type Adjusted Consumption Carbon Content Stora g e Factor Carbon Stored Carbon Emissions Carbon Emissions (TBtu) (Tg C) (Tg C) (Tg C) (Tg CO 2 Eq.) Industry 5,023.0 93.5

- 65.7 27.8 101.8

Industrial Coking Coal 3.0 0.1 0.75 0.1 0.0 0.1 Industrial Other Coal 11.9 0.3 0.65 0.2 0.1 0.4 Natural Gas to Chemical Plants 401.0 5.8 0.65 3.8 2.0 7.4 Asphalt & Road Oil 1,217.4 25.1 1.00 25.1 0.0 0.0 LPG 1,478.4 24.9 0.65 16.2 8.7 31.9 Lubricants 160.8 3.3 0.09 0.3 3.0 10.8 Pentanes Plus 162.4 3.0 0.65 1.9 1.0 3.8 Naphtha (<401 deg. F) 588.4 10.7 0.65 6.9 3.7 13.7 Other Oil (>401 deg. F) 530.0 10.6 0.65 6.9 3.7 13.5 Still Gas 133.0 2.3 0.65 1.5 0.8 3.0 Petroleum Coke 90.9 2.5 0.50 1.3 1.3 4.6 Special Naphtha 77.5 1.5 0.65 1.0 0.5 2.0 Distillate Fuel Oil 11.7 0.2 0.50 0.1 0.1 0.4 Waxes 31.0 0.6 0.58 0.4 0.3 0.9 Miscellaneous Products 126.0 2.5 0.00 0.0 2.5 9.3 Transportation 151.8 3.1

- 0.3 2.8 10.2

Lubricants 151.8 3.1 0.09 0.3 2.8 10.2Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 72 U.S. Territories 88.7 1.8

- 0.2 1.6 5.9

Lubricants 0.0 0.0 0.09 0.0 0.0 0.0 Other Petroleum (Misc. Prod.) 88.7 1.8 0.10 0.2 1.60 5.9 Total 5,263.9 98.3 66.1 32.2 118.0

a To avoid double-counting, coal coke, petroleum coke, natural gas consumption, and other oils are adjusted for industrial process consumption reported in the Industrial Processes sector. Natural gas, LPG, Pentanes Plus, Naphthas, Special Naphtha, and Other Oils are adjusted to account for exports of chemical intermediates derived from these fuels. For residual oil (not shown in the table), all non-energy use is assumed to be consumed in carbon black production, which is also reported in the Industrial Processes sector. - Not applicable. Note: Totals may not sum due to independent rounding.

Lastly, emissions were estimated by subtracting the carbon stored from the potential emissions (see Table 3-11). More detail on the methodology for calcu lating storage and emissions from each of these sources is provided in Annex 2.3.

Where storage factors were calculated specifically for the Un ited States, data were obtained on fuel products such as asphalt, plastics, synthetic rubber, synthetic fibers, car bon black, personal cleansers, pesticides, and solvents, and industrial releases including VOC, solvent, and non-combus tion CO emissions, TRI releases, refinery wastewater, hazardous waste incineration, and energy recovery. Data were taken from a variety of industry sources, government reports, and expert communications. Sources include EPA’s compilations of air emission factors (EPA 1995, 2001), National Air Quality and Em issions Trends Report data (EPA 2004a), Toxics Release Inventory, 1998 (2000a), Biennial Reporting System data (EPA 2004b), pesticide sales and use estimates (EPA 1998, 1999, 2002) and hazardous waste data (EPA 2004b); the EIA Manufacture r’s Energy Consumption Su rvey (MECS) (EIA 1994, 1997, 2001b); the National Petrochemical & Refiners A ssociation (NPRA 2001); the National Asphalt Pavement Association (Connolly 2000); the Emissions Inventory Improvement Program (EIIP 1998, 1999); the U.S. Bureau of the Census (1999, 2003); the American Plastics Council (APC 2000, 2001, 2003; Eldredge-Roebuck 2000); the Society of the Plastics Industry (SPI 2000); the Rubber Manufacturers’ Association (RMA 2002; STMC 2003); the International Institute of Synthetic Rubber Products (IISRP 2000); the Fibe r Economics Bureau (FEB 2001); the; Material Safety Data Sheets (Miller 1999); and the Chemical Manufactur er’s Association (CMA 1999); Specific data sources are listed in full detail in Annex 2.3.


### Uncertainty

A Tier 2 Monte Carlo analysis was performed using @RISK software to determine the level of uncertainty surrounding the estimates of emissions and storage factors from non-energy uses. The Tier 2 analysis was performed to allow the specification of probability density functions for key variables, within a computational structure that mirrors the calcula tion of the inventory estimate.

As noted above, the non-energy use analysis is based on U.S.-specific storage factors for (1) feedstock materials (natural gas, LPG, pentanes plus, na phthas, other oils, still gas, special na phthas, and other i ndustrial coal), (2) asphalt, (3) lubricants, and (4) waxes. For the remaining fu el types (the “other” categor y), the storage factors were taken directly from the IPCC Guidelines for National Greenhouse Gas Inventories , where available, and otherwise assumptions were made based on the potential fate of carbon in the respective NEU products

. To characterize uncertainty, five separate analyses were conducted, corresponding to each of the five categories. In all cases, statistical analyses or expert judgments of uncertainty we re not available directly from the information sources for all the activity variables; thus, uncertainty estimates were determined using assumptions based on source category knowledge.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-14 (emissions) and Table 3-15 (storage factors). Carbon emitted from non-energy uses of fossil fuels in 2003 was estimated to be between 97.5 and 130.9 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Simulations). This indicates a range of 17 percent below to 11 percent above the 2003 emission estimate of 118.0 Tg CO 2 Eq. The uncertainty in the emission estimates are a function of uncertainty in both the quantity of fuel used for non-energy purposes and the storage factor.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 73 Table 3-14: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Non-Energy Uses of Fossil Fuels (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Rela tive to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Feedstocks CO 2 75.3 61.0 90.5 -19% +20% Asphalt CO 2 0.0 0.2 0.9 NA NA Lubricants CO 2 21.1 17.4 24.4 -17% +16% Waxes CO 2 0.9 0.7 1.5 -24% +54% Other CO 2 20.9 8.9 23.2 -57% +11% Total CO 2 118.0 97.5 130.9 -17% +11%

a Range of emission estimates predic ted by Monte Carlo Simulation for a 95 percent confidence interval. NA (Not Applicable)

Table 3-15: Tier 2 Quantitative Uncertainty Estimates for Storage Factors of Non-Energy Uses of Fossil Fuels (Percent)

Source Gas 2003 Storage Factor Uncertainty Range Relative to Inventory Factor a (%) (%) (%, Relative) Lower Bound Upper Bound Lower Bound Upper Bound Feedstocks CO 2 65% 63% 67% -3% +3% Asphalt CO 2 100% 99% 100% -1% +0% Lubricants CO 2 9% 4% 18% -58% +90% Waxes CO 2 58% 44% 69% -24% +19% Other CO 2 24% 18% 67% -24% +180% Total CO 2 65% 63% 67% -3% +3%

a Range of emission estimates predic ted by Monte Carlo Simulation for a 95 percent confidence interval.

In Table 3-15, feedstocks and asphalt contribute least to overall storage factor uncertainty. Although the feedstocks category—the largest use category in terms of total carbon flows—appears to have tight confidence limits, this is to some extent an artifact of th e way the uncertainty analysis was structured. As discussed in Annex 2.3, the storage factor for feedstocks is based on an analysis of five fates that result in long-term storage (e.g., plastics production), and ten that result in emissions (e .g., volatile organic compound emissions). Rather than modeling the total uncertainty around all 15 of these fate processes, the current analysis addresses only the storage fates, and assumes that all C that is not stored is emitted. As the producti on statistics that drive the stor age values are relatively wellcharacterized, this approach yields a result that is probably biased toward understating uncertainty.

As is the case with the other uncertainty analyses discussed throughout this document, the uncertainty results above address only those factors that can be readily quantified. More details on the uncertainty analysis are provided in Annex 2.3.



### QA/QC and Verification

A source-specific QA/QC plan for non-energy uses of fossil fuels was developed and implemented. This effort included a Tier 1 analysis, as well as portions of a Tier 2 analysis for non-energy uses involving petrochemical feedstocks. The Tier 2 procedures that were implemen ted involved checks specifically focusing on the activity data and methodology for estimating the fate of C (in terms of storage and emissions) across the various end-uses of fossil carbon. Emission and storage totals for the different subcategories were compared, and trends across the time series were carefully analyzed to de termine whether any corrective actions we re needed. Corrective actions were taken to rectify minor errors and to improve the transparency of the calculations, facilitating future QA/QC.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 74 

### Recalculations Discussion

This year’s methodology reflects several refinements and im provements. First and most fundamentally, this year the NEU analysis is presented as its own source category. In the past, the NEU component of this category was described in the context of a calculation sequence that first determined potential emissions (based on total fuel consumption for all purposes), and then deducted (1) C not oxidized (e.g., in ash) and (2) C put into long-term storage as a result of NEUs. In this context, the focu s of the NEU section was previously on carbon storage rather than emissions. This year, the presentation within this source category emphasizes emissions, though the storage factors (i.e., fraction of C stored rather than emitted) ar e still presented to facilitate comparison with IPCC guidance.

Several substantive changes also appear in this year’s inve ntory. First, a U.S.-specifi c storage factor (58 percent) was developed for waxes. Previously, the IPCC storage factor for wax (100 percent stored) had been used.

In addition, the methodology for calculating emissions and stor age for feedstocks has been revised in several ways. First, three additional fuel types have been added as i nputs to the system covered by the feedstocks mass balance calculations: other industrial coal, still ga s, and special naphthas. The other significant improvement for feedstocks is that the estimates of U.S. plastics consumption have b een revised: in previous years, the consumption data for some of the plastic resins in the dataset included consum ption in Canada and Mexico. By adjusting the data to reflect U.S. (rather than North Ameri can) consumption for those resins, the accu racy of the estimate for feedstocks has improved. In addition, several minor adjustments we re made (e.g., the calculati ons for storage now include synthetic rubber in durable and non-durable goods other than tires, and the calculations for emissions include losses due to abrasion/ oxidation of rubber from tires).

As noted in the beginning of the section, there are several areas where the boundaries of the NEU analysis adjoin the systems covered within the Industrial Processes s ector. Carbon black production has been removed from the NEU analysis, as it is now addressed as a subcategory of IP-petrochemical emissions (if it was retained in NEU, there would be double-counting). As a result of this change, residual oil—which is an input to carbon black production, and had been among the fuels covered in the NE U section in previous years—no longer appears in the list of fuels in this section. A portion of other oils is also assumed to be used in the production of carbon black, and therefore other oils consumption is adjusted to account for the amount of fuel used in the C black calculation.

The storage factor for miscellaneous products also changed. In prior years, a value of 100 percent was used; in this year’s inventory, based on a review of the specific appli cations of these products, there is now assumed to be no storage at all from these products.

There have been several updates to the data used to calcu late storage factors, not only by adding information for 2003 (where available) but also for updating data sets for earlie r years. For example, the results reflect new data for hazardous waste incineration (1999 through 2001) and fiber production (2001 through 2002).


### Planned Improvements

There are several improvements planned for the future:

• Collecting additional information on energy recovery from Manufacturing Energy Consumption Surveys. An effort is planned to carefully examine the “microdata” from these surveys to determine the nature and quantity of materials initially identified as be ing destined for “non-energy use” that are actually combusted for energy recovery.

• Improving the uncertainty analysis. Most of the input parameter distributions are based on professional judgment rather than rigorous statistical characterizations of uncertainty.

• Better characterizing flows of fossil carbon. Additional “fates” may be researched, including: the fossil carbon load in organic chemical wastewat ers; an expanded import and export an alysis (i.e., evaluating additional commodities); and improving the characterization of cleansers (to exclude an y potential biogenic carbon sources).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 75 Finally, although U.S.-specific storage factors have been de veloped for feedstocks, asphalt, lubricants, and waxes, default values from IPCC are still used for two of the non- energy fuel types (industria l coking coal and distillate oil), and broad assumptions are being used for the rema ining fuels (petroleum coke, miscellaneous products, and other petroleum). Over the long term, there are plans to improve these storage factors by conducting analyses of C fate similar to those described in Annex 2.3.



### 3.3. Stationary Co mbustion (excluding CO 2 

### ) (IPCC Source Category 1A)

Stationary combustion encompasses all fuel combustion activities from fixed sources (versus mobile combustion). Other than CO 2 , which was addressed in the previous section, gases from stationary combustion include the greenhouse gases CH 4 and N 2 O and the ambient air pollutants NO x , CO, and NMVOCs. 35 Emissions of these gases from stationary combustion sources depend upon fuel characteristics, size and vintage, along with combustion technology, pollution control equipment, and ambient environmental c onditions. Emissions also vary with operation and maintenance practices.

Nitrous oxide and NO x emissions from stationary co mbustion are closely related to air-fuel mixes and combustion temperatures, as well as the characteristics of any pollution control equipment that is employed. Carbon monoxide emissions from stationary combustion are generally a function of the efficiency of combustion; they are highest when less oxygen is present in the air-fu el mixture than is necessary for comp lete combustion. These conditions are most likely to occur during start-up, shutdown and during fuel switching (e.g., the switching of coal grades at a coal-burning electric utility plant). Methane and NMVOC emissions from stationary combustion are primarily a function of the CH 4 and NMVOC content of the fu el and combustion efficiency.

Emissions of CH 4 decreased 15 percent overall to 6.7 Tg CO 2 Eq. (319 Gg) in 2003. This decrease in CH 4 emissions was primarily due to lower wood consumption in the residential sector. Conversely, N 2 O emissions rose 13 percent since 1990 to 13.8 Tg CO 2 Eq. (45 Gg) in 2003. The largest source of N 2 O emissions was coal combustion by electricity generators, which alone accounted for 63 percent of total N 2 O emissions from stationary combustion in 2003. Overall, however, stationary combustion is a small source of CH 4 and N 2 O in the United States.

In contrast, stationary combustion is a significant source of NO x emissions, though a smaller source of CO and NMVOCs. In 2003, emissions of NO x from stationary combustion represented 39 percent of national NO x emissions, while CO and NMVOC emissions from stati onary combustion contributed approximately 5 and 7 percent, respectively, to the national totals. From 1990 to 2003, emissions of NO x and CO from stationary combustion decreased by 27 and 11 percent, respectively, and emissions of NMVOCs increased by 10 percent.

The decrease in NO x emissions from 1990 to 2003 are mainly due to decreased emissions from electric power. The decrease in CO and increase in NMVOC emissions over this time period can largely be attributed to apparent changes in residential wood use, which is the most significant source of these pollutants from stationary combustion. Table 3-16 through Table 3-19 provide CH 4 and N 2 O emission estimates from stationary combustion by sector and fuel type. Estimates of NO x , CO, and NMVOC emissions in 2003 are given in Table 3-20. 36

Table 3-16: CH 4 Emissions from Stationary Combustion (Tg CO 2 Eq.) Sector/Fuel Type 1990 1997 1998 1999 2000 2001 2002 2003 Electric Power 0.6 0.6 0.7 0.7 0.7 0.7 0.7 0.7

Coal 0.3 0.4 0.4 0.4 0.4 0.4 0.4 0.4 Fuel Oil 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Natural gas 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

35 Sulfur dioxide (SO 2 ) emissions from stationary combus tion are addressed in Annex 6.3. 36 See Annex 3.1 for a complete time series of ambient air pollutant emission estimates for 1990 through 2003.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 76 Wood 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Industrial 2.1 2.4 2.3 2.2 2.3 2.1 2.1 2.1

Coal 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 Fuel Oil 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Natural gas 0.8 0.9 0.9 0.9 0.9 0.8 0.8 0.8 Wood 0.9 1.0 1.0 1.0 1.0 0.9 0.9 0.9 Commercial 0.7 0.8 0.8 0.8 0.8 0.7 0.7 0.8

Coal + + + + + + + + Fuel Oil 0.2 0.1 0.1 0.1 0.2 0.2 0.2 0.2 Natural gas 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 Wood 0.2 0.3 0.3 0.3 0.3 0.2 0.3 0.3 Residential 4.4 3.5 3.1 3.4 3.5 3.1 2.8 3.1

Coal 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Fuel Oil 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 Natural Gas 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 Wood 3.5 2.6 2.3 2.5 2.6 2.2 1.9 2.1 U.S. Territories + 0.1 0.1 0.1 0.1 0.1 0.1 0.1

Coal + + + + + + + + Fuel Oil + 0.1 0.1 0.1 + 0.1 0.1 0.1 Natural Gas + + + + + + + + Wood + + + + + + + + Total 7.8 7.4 6.9 7.1 7.3 6.7 6.4 6.7 + Does not exceed 0.05 Tg CO 2 Eq. Note: Totals may not sum due to independent rounding.

Table 3-17: N 2 O Emissions from Stationary Combustion (Tg CO 2 Eq.) Sector/Fuel Type 1990 1997 1998 1999 2000 2001 2002 2003 Electric Power 7.6 8.6 8.9 8.9 9.3 9.0 9.1 9.3

Coal 7.1 8.2 8.3 8.3 8.7 8.5 8.6 8.7 Fuel Oil 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 Natural Gas 0.1 0.1 0.1 0.1 0.2 0.2 0.2 0.2 Wood 0.2 0.2 0.2 0.2 0.2 0.1 0.2 0.2 Industrial 3.2 3.5 3.3 3.3 3.3 3.1 3.2 3.2

Coal 0.7 0.7 0.7 0.6 0.6 0.6 0.6 0.6 Fuel Oil 0.5 0.5 0.5 0.5 0.5 0.6 0.6 0.6 Natural Gas 0.2 0.3 0.3 0.3 0.3 0.2 0.2 0.2 Wood 1.7 2.0 1.9 1.9 1.9 1.7 1.8 1.8 Commercial 0.4 0.3 0.3 0.3 0.3 0.3 0.3 0.3

Coal 0.1 0.1 + + + + + + Fuel Oil 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Natural Gas 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Wood + 0.1 0.1 0.1 0.1 + + + Residential 1.1 0.9 0.8 0.9 1.0 0.9 0.8 0.9

Coal + + + + + + + + Fuel Oil 0.3 0.3 0.2 0.3 0.3 0.3 0.3 0.3 Natural Gas 0.1 0.2 0.1 0.1 0.2 0.1 0.1 0.2 Wood 0.7 0.5 0.5 0.5 0.5 0.4 0.4 0.4 U.S. Territories 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

Coal + + + + + + + + Fuel Oil 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Natural Gas + + + + + + + + Wood + + + + + + + + Total 12.3 13.5 13.4 13.5 14.0 13.5 13.5 13.8 + Does not exceed 0.05 Tg CO 2 Eq.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 77 Note: Totals may not sum due to independent rounding.

Table 3-18: CH 4 Emissions from Stationary Combustion (Gg) Sector/Fuel Type 1990 1997 1998 1999 2000 2001 2002 2003 Electric Power 27 29 31 31 32 32 32 33

Coal 16 19 19 19 20 19 20 20 Fuel Oil 4 3 4 4 3 4 3 4 Natural Gas 3 4 4 5 5 5 5 5 Wood 4 4 4 4 4 4 4 5 Industrial 101 115 108 107 108 100 102 100

Coal 17 16 15 14 15 14 13 13 Fuel Oil 6 6 5 5 6 6 6 6 Natural Gas 37 44 43 41 42 38 39 37 Wood 41 49 46 46 47 41 44 43 Commercial 35 38 36 37 39 35 35 36

Coal 1 1 1 1 1 1 1 1 Fuel Oil 10 7 7 7 8 7 7 8 Natural Gas 13 16 15 15 16 15 15 15 Wood 11 14 14 15 15 12 12 12 Residential 209 167 150 160 167 148 132 146

Coal 8 5 4 4 4 4 3 4 Fuel Oil 14 14 13 15 16 15 15 15 Natural Gas 21 24 22 23 24 23 24 25 Wood 166 123 110 118 123 105 89 102 U.S. Territories 2 2 2 2 2 3 3 4

Coal + + + + + + + + Fuel Oil 2 2 2 2 2 3 3 3 Natural Gas + + + + + + + + Wood + + + + + + + + Total 373 351 328 338 349 318 305 319 + Does not exceed 0.5 Gg Note: Totals may not sum due to independent rounding.

Table 3-19: N 2 O Emissions from Stationary Combustion (Gg) Sector/Fuel Type 1990 1997 1998 1999 2000 2001 2002 2003 Electricity Generation 24 28 29 29 30 29 29 30

Coal 23 26 27 27 28 27 28 28 Fuel Oil 1 1 1 1 1 1 1 1 Natural Gas + + + + 1 1 1 + Wood + 1 1 1 1 + 1 1 Industrial 10 11 11 11 11 10 10 10

Coal 2 2 2 2 2 2 2 2 Fuel Oil 2 2 2 2 2 2 2 2 Natural Gas 1 1 1 1 1 1 1 1 Wood 5 7 6 6 6 5 6 6 Commercial 1 1 1 1 1 1 1 1

Coal + + + + + + + + Fuel Oil 1 + + + + + + + Natural Gas + + + + + + + + Wood + + + + + + + + Residential 4 3 3 3 3 3 3 3

Coal + + + + + + + + Fuel Oil 1 1 1 1 1 1 1 1 Natural Gas + + + + + + + +Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 78 Wood 2 2 1 2 2 1 1 1 U.S. Territories + + + + + + + +

Coal + + + + + + + + Fuel Oil + + + + + + + + Natural Gas + + + + + + + + Wood + + + + + + + + Total 40 44 43 43 45 43 44 45 + Does not exceed 0.5 Gg Note: Totals may not sum due to independent rounding.

Table 3-20: NO x , CO, and NMVOC Emissions from Stationary Combustion in 2003 (Gg) Sector/Fuel Type NO x CO NMVOC Electric Generation 4,045 480 50

Coal 3,447 240 24 Fuel Oil 135 30 4 Natural gas 301 101 11 Wood 34 NA NA Other Fuels a NA 35 2 Internal Combustion 127 73 10 Industrial 2,516 1,249 154

Coal 522 138 10 Fuel Oil 154 50 8 Natural gas 920 402 52 Wood NA NA NA Other Fuels a 116 353 28 Internal Combustion 803 307 55 Commercial/Institutional 244 149 29

Coal 19 13 1 Fuel Oil 49 17 3 Natural gas 155 82 13 Wood NA NA NA Other Fuels a 21 37 11 Residential 417 2,575 773

Coal b NA NA NA Fuel Oil b NA NA NA Natural Gas b NA NA NA Wood 20 2,358 748 Other Fuels 397 217 25 Total 7,222 4,454 1,007 NA (Not Available)

a Includes LPG, waste oil, coke oven gas, and coke (EPA 2003), (EPA 2004a). b Residential coal, fuel oil, and natural gas emissions are included in “Other Fuels” (EPA 2003), (EPA 2004a). Note: Totals may not sum due to independent roundi ng. See Annex 3.1 for emissions in 1990 through 2003.



### Methodology

Methane and N 2 O emissions were estimated by multiplying foss il fuel and wood consump tion data by emission factors (by sector and fuel type). National coal, natural gas, fuel oil, and wood cons umption data were grouped by
sector : industrial, commercial, residential, electric power, and U.S. territories. For the CH 4 and N 2 O estimates, fuel consumption data for the United States were obtained from EIA’s Monthly Energy Review and unpublishedInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 79 supplemental tables on petroleum product detail (EIA 2004). Because the United States doe s not include territories in its national energy statistics, fuel consumption data for territories were provided separately by the Grillot (2004). 37 Fuel consumption for the industrial sector was adjust ed to subtract out construction and agricultural use, which is reported under mobile sources. 38 Construction and agricultural fuel use was obtained from EPA (2004b). Estimates for wood biomass consumption for fuel combus tion do not include wood wastes, liquors, municipal solid waste, tires, etc. that are re ported as biomass by EIA.

Emission factors for the four end-use sectors were provided by the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997). U.S. territories’ emission factors were estimated using the U.S. emission factors for the primary sector in which each fuel was combusted.

Emission estimates for NO x , CO, and NMVOCs in this section were obtained from preliminary data (EPA 2004a) and disaggregated based on EPA (2003), which, in its fi nal iteration, will be published on the National Emission Inventory (NEI) Air Pollutant Emission Trends web site. The major categories included in this section are those reported in EPA (2003) and EPA (2004a): coal, fuel oil, na tural gas, wood, other fuels (including LPG, coke, coke oven gas, and others), and stationary internal combustion. The EPA estimates emissions of NO x , CO, and NMVOCs by sector and fuel source using a "bottom-up" es timating procedure. In other words, emissions were calculated either for individual sources (e.g., industrial boilers) or for mu ltiple sources combined, using basic activity data as indicators of emissions. Depending on the source category, these basic activity data may include fuel consumption, fuel deliveries, tons of refuse burned, raw material processed, etc.

The overall emission control efficiency of a source cat egory was derived from published reports, the 1985 National Acid Precipitation and Assessment Program (NAPAP) emissi ons inventory, and other EPA databases. The U.S. approach for estimating emissions of NO x , CO, and NMVOCs from stationary co mbustion, as described above, is consistent with the methodology recommended by the IPCC (IPCC/UNEP/OECD/IEA 1997).

More detailed information on the methodology for calculating emissions from stationary combustion, including emission factors and activity data, is provided in Annex 3.1.


### Uncertainty

Methane emission estimates from stationary sources exhibit high uncertainty, primarily due to difficulties in calculating emissions from wood com bustion (i.e., fireplaces and wood stoves). The estimates of CH 4 and N 2 O emissions presented are based on broad indicators of emi ssions (i.e., fuel use multiplied by an aggregate emission factor for different sectors), rather than specific emi ssion processes (i.e., by combustion technology and type of emission control).

An uncertainty analysis was performed by primary fuel type for each end- use sector, using the IPCC-recommended Tier 2 uncertainty estimation methodology, Monte Carlo Simulation technique, with @RISK software.

The uncertainty estimation model for this source category was developed by integrating the CH 4 and N 2 O stationary source inventory estimation models with the model for CO 2 from fossil fuel combustion to realistically characterize the interaction (or endogenous correlation) between the variables of these three models. A total of 115 input variables were simulated for the uncertainty analysis of this source category (85 from the CO 2 emissions from fossil fuel combustion inventory estimation model and 30 from the stationary source inventory models).

37 U.S. territories data also include combustion from mobile ac tivities because data to allocate territories’ energy use were unavailable. For this reason, CH 4 and N 2 O emissions from combustion by U.S. territo ries are only included in the stationary combustion totals. 38 Though emissions from construction and farm use occur due to both stationary and mobile sources, detailed data was not available to determine the magnitude from each. Currently, thes e emissions are assumed to be predominantly from mobile

sources.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 80 In developing the uncertainty estimation model, uniform distribution was assumed for all activity-related input variables and N 2 O emission factors, based on the SAIC/EIA (2001) report. 39 For these variables, the uncertainty ranges were assigned to the input variables ba sed on the data reported in SAIC/EIA (2001). 40 However, the CH 4 emission factors differ from those used by EIA. Since these factors were obtained from IPCC/UNEP/OECD/IEA (1997), uncertainty ranges were assigned based on IP CC default uncertainty estimates (IPCC Good Practice Guidance 2000).

The uncertainty ranges for the activity-related input variables and N 2 O emission factors were typically asymmetric around their inventory estimates. The uncertainty ranges for the non-biomass-related CH 4 emission factors were symmetric around their inventory estimates; for biomass, they were asymmetric around their emission factor estimates. Bias (or systematic uncertainties) associated with these variables accounted for much of the uncertainty associated with the activity data and N 2 O emission factor variables. 41 For purposes of this uncertainty analysis, each input variable was si mulated 10,000 times through Monte Carlo sampling.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-21. Stationary combustion CH 4 emissions in 2003 ( including biomass) were estimated to be between 4.8 and 13.4 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Simulations). This indicates a range of 28 percent below to 99 percent above the 2003 emission estimate of 6.7 Tg CO 2 Eq. 42 Stationary combustion N 2 O emissions in 2003 ( including biomass) were estimated to be between 10.9 and 39.5 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Simulations). This indicates a range of 22 percent below to 184 percent above the 2003 emissions estimate of 13.8 Tg CO 2 Eq.

Table 3-21: Tier 2 Quantitative Uncertainty Estimates for CH 4 and N 2 O Emissions from Energy -Related Stationary Combustion, Including Biomass (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Rela tive to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Stationary Combustion CH 4 6.7 4.8 13.4 -28% +99% Stationary Combustion N 2 O 13.8 10.9 39.5 -22% +184%

a Range of emission estimates pred icted by Monte Carlo Simulation for a 95 percent confidence interval.
The uncertainties associ ated with the emission estimates of CH 4 and N 2 O are greater than t hose associated with estimates of CO 2 from fossil fuel combustion, which mainly rely on the carbon content of the fuel combusted. Uncertainties in both CH 4 and N 2 O estimates are due to the fact that emissions are estimated based on emission factors representing only a limited subset of combustion conditions. For the ambient air pollutants, uncertainties are

39 SAIC/EIA(2001) characterizes the underlying probability density function for the input variables as a combination of uniform and normal distributions (the former dist ribution to represent the bias component and the latter to represent the random component). However, for purposes of the current uncertainty analysis, it was determ ined that uniform distribution was more appropriate to characterize the probability dens ity function underlying each of these variables. 40 In the SAIC/EIA (2001) report, the quan titative uncertainty estimates were develope d for each of the three major fossil fuels used within each end-use sector; the variati ons within the sub-fuel types within each end-use sector were not modeled. However, for purposes of assigning uncertainty estimates to the sub-fuel type categories within each end-use sector in the current uncertainty analysis, SAIC/EIA (2001)-reported uncertainty estimates were extrapolated. 41 Although, in general, random uncertainties are the main focus of statistical uncertainty an alysis, when the uncertainty estimates are elicited from experts, their estimates include both random and systematic uncertainties. Hence, both these types of uncertainties are represented in this uncertainty analysis. 42 The low emission estimates reported in this section have been rounded down to the nearest integer values and the high emission estimates have been rounded up to the nearest integer values.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 81 partly due to assumptions concerning combustion technology types, age of equipment, emission factors used, and activity data projections.



### QA/QC and Verification

A source-specific QA/QC plan for stationary combustion wa s developed and implemented. This effort included a Tier 1 analysis, as well as portions of a Tier 2 analysis. The Tier 2 procedures that were implemented involved checks specifically focusing on the activity data and emission factor sources and methodology used for estimating CH 4 , N 2 O, and the ambient air pollutants from stationary combustion in the United States. Emission totals for the different sectors and fuels were compar ed and trends were investigated.

A few corrective actions were taken. It was determined that emissions from construction and farm use had beenpreviously estimated in both this source category (in the industrial sector) and for mobile sources. To avoid doublecounting, these emissions are now repor ted only under mobile sources. Therefor e, it was necessary to subtract out energy consumption from construction and agriculture from th e industrial sector. Also, a small error was corrected in the conversion of natural gas and wood energy consump tion from gross calorific value to net calorific value.



### Recalculations Discussion

Historical CH 4 and N 2 O emissions from stationary sources (excluding CO 2 ) were revised due to several changes. First, industrial sector energy consumption was adjusted downward to avoid double-counting of emissions from construction and agriculture. Second, the conversion of natural gas and wood energy consumption from gross calorific value to net calorific value wa s corrected. These adjustments have been explained in the previous section. Third, slight changes to emission estimates for the other sectors are due to revised data from EIA (2004). This latter revision is explained in greater detail in the section on CO 2 Emissions from Fossil Fuel Combustion within this sector. The combination of the methodological and historical data changes resulted in an average annual decrease of 0.4 Tg CO 2 Eq. (5.2 percent) in CH 4 emissions from stationary combustion and an average annual decrease of 0.4 Tg CO 2 Eq. (3.2 percent) in N 2 O emissions from stationary combustion for the period 1990 through 2002.


### Planned Improvements

Several items are being evaluated to improve the CH 4 and N 2 O emission estimates from stationary source combustion and to reduce uncertainty. Efforts will be taken to work with EIA and other agencies to improve the quality of the U.S. territories data. Because these data are not broken out by stationary and m obile uses, further research will be aimed at trying to allocate consumption appropriately. In addition, the uncertainty of biomass emissions will be further investigated . Currently, the exclusion of bioma ss increases the uncertainty, although it was expected to reduce the uncertainty. These improvements are not all-inclusive, but are part of an ongoing analysis and efforts to continually improve these stationary estimates.



### 3.4. Mobile Combustion (excluding CO 2 

### ) (IPCC Source Category 1A)

Mobile combustion emits greenhouse gases other than CO 2 , including CH 4 , N 2 O, and the ambient air pollutants NO x , CO, and NMVOCs. While air conditioners and refrigera ted units in vehicles also emit hydrofluorocarbons (HFCs), these gases are covered in Chapter 3, Industria l Processes, under the section entitled Substitution of Ozone Depleting Substances. As with stationary combustion, N 2 O and NO x emissions are closely related to fuel characteristics, air-fuel mixes, combustion temperatures, as well as usage of pollution control equipment. Nitrous oxide, in particular, can be formed by the catalytic processes used to control NO x , CO, and hydrocarbon emissions. Carbon monoxide emissions from mobile combustion are significantly affected by combustion efficiency and the presence of post-combustion emission controls. Carbon monoxide emissions are highest when air-fuel mixtures have less oxygen than required for complete combustion. These emissions occur especially in idle, low speed, and cold start conditions. Methane and NMVOC emissions from motor vehicles are a function of the CH 4 content of the motor fuel, the amount of hydrocarbons passing uncombuste d through the engine, and any post-combustion control of hydrocarbon emissions, such as catalytic converters.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 82 Emissions from mobile combustion were estimated by transpor t mode (e.g., highway, air, ra il), fuel type (e.g. motor gasoline, diesel fuel, jet fuel), and vehicle type (e.g. pa ssenger cars, light-duty trucks). Road transport accounted for the majority of mobile source fuel consumption, and hence, the majority of mobile combustion emissions. Table 3-22 and Table 3-23 provide CH 4 and N 2 O emission estimates, respectively, in Tg CO 2 Eq.; Table 3-24 and Table 3-25 present these estimates in Gg of each gas. Estimates of NO x , CO, and NMVOC emissions are given in Table 3-26 through Table 3-28. 43

Mobile combustion was responsible for a small portion of national CH 4 emissions (0.5 percent) but was the second largest source of N 2 O (11.2 percent) in the United States. From 1990 to 2003, CH 4 emissions declined by 44 percent, to 2.7 Tg CO 2 Eq. (128 Gg), due largely to control technologies employed on highway vehicles in the United States that reduce CO, NO x , NMVOC, and CH 4 emissions. The same technologies, however, resulted in higher N 2 O emissions, causing a 27 percent increase in N 2 O emissions from mobile sources between 1990 and 1998. Nitrous oxide emissions have subsequently declin ed 24 percent as improvements in the emission control technologies installed on new vehicles have reduced emission rates of both NO x and N 2 O per vehicle mile traveled. As a result, N 2 O emissions in 2003 were 4 percent lower than in 1990, at 42.1 Tg CO 2 Eq. (136 Gg) (see Figure 3-17). Overall, CH 4 and N 2 O emissions were predominantly from gaso line-fueled passenger cars and light-duty gasoline trucks.

Figure 3-17: Mobile Source CH 4 and N 2 O Emissions

Table 3-22: CH 4 Emissions from Mobile Combustion (Tg CO 2 Eq.) Fuel Type/Vehicle Type a 1990 1997 1998 1999 2000 2001 2002 2003 Gasoline Highway 4.3 3.5 3.3 3.0 2.7 2.4 2.2 2.0

Passenger Cars 2.6 1.9 1.8 1.7 1.5 1.4 1.2 1.1 Light-Duty Trucks 1.4 1.3 1.3 1.1 1.0 0.9 0.8 0.8 Heavy-Duty Vehicles 0.3 0.2 0.2 0.2 0.1 0.1 0.1 0.1 Motorcycles + + + + + + + + Diesel Highway + + + + + + + +

Passenger Cars + + + + + + + + Light-Duty Trucks + + + + + + + + Heavy-Duty Vehicles + + + + + + + + Alternative Fuel Highway + 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Non-Highway 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5

Ships and Boats 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Locomotives 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Farm Equipment 0.2 0.2 0.1 0.2 0.2 0.1 0.1 0.1 Construction Equipment 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Aircraft + 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Otherb + + + + + + 0.1 0.1 Total 4.8 4.0 3.9 3.6 3.4 3.1 2.9 2.7 + Less than 0.05 Tg CO 2 Eq. Note: Totals may not sum due to independent rounding.

a See Annex 3.2 for definitions of highway vehicle types. b “Other" includes snowmobiles and other recreational equipment, logging equipment, lawn and garden equipment, railroad equipment, airport equipment, commercia l equipment, and industrial equipment.
Table 3-23: N 2 O Emissions from Mobile Combustion (Tg CO 2 Eq.) Fuel Type/Vehicle Type 1990 1997 1998 1999 2000 2001 2002 2003 Gasoline Highway 40.3 51.5 51.7 50.8 49.1 45.0 41.6 38.0

43 See Annex 3.2 for a complete time series of emission estimates for 1990 through 2003.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 83 Passenger Cars 25.5 26.7 26.7 25.9 24.7 23.1 21.6 19.8 Light-Duty Trucks 14.1 23.7 23.7 23.6 23.0 20.6 18.6 16.7 Heavy-Duty Vehicles 0.7 1.1 1.3 1.3 1.3 1.4 1.4 1.4 Motorcycles + + + + + + + + Diesel Highway 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.3

Passenger Cars + + + + + + + + Light-Duty Trucks + + + + + + + + Heavy-Duty Vehicles 0.2 0.2 0.3 0.3 0.3 0.3 0.3 0.3 Alternative Fuel Highway + 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Non-Highway 3.2 3.3 3.3 3.4 3.7 3.5 3.6 3.6

Ships and Boats 0.4 0.3 0.3 0.3 0.5 0.3 0.5 0.5 Locomotives 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 Farm Equipment 1.7 1.7 1.8 1.8 1.9 1.8 1.7 1.7 Construction Equipment 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.3 Aircraft 0.3 0.4 0.4 0.4 0.4 0.4 0.4 0.5 Other* 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.3 Total 43.7 55.2 55.3 54.6 53.2 49.0 45.6 42.1 + Less than 0.05 Tg CO 2 Eq. Note: Totals may not sum due to independent rounding. *“Other" includes snowmobiles and other recreational equipment, logging equipment, lawn and garden equipment, railroad equipment, airport equipment, commercia l equipment, and industrial equipment.
Table 3-24: CH 4 Emissions from Mobile Combustion (Gg) Fuel Type/Vehicle Type 1990 1997 1998 1999 2000 2001 2002 2003 Gasoline Highway 205 166 158 143 130 116 105 95

Passenger Cars 125 91 87 82 73 65 59 53 Light-Duty Trucks 65 64 60 52 49 44 40 38 Heavy-Duty Vehicles 13 10 10 9 7 6 5 5 Motorcycles 1 1 1 1 1 1 1 1 Diesel Highway 1 1 1 1 1 1 1 1

Passenger Cars + + + + + + + + Light-Duty Trucks + + + + + + + + Heavy-Duty Vehicles 1 1 1 1 1 1 1 1 Alternative Fuel Highway 1 3 3 4 4 5 5 6 Non-Highway 22 23 23 24 26 25 26 26

Ships and Boats 4 3 3 3 5 3 4 4 Locomotives 3 3 3 3 3 3 3 3 Farm Equipment 7 7 7 7 7 7 7 7 Construction Equipment 4 5 5 5 5 6 6 6 Aircraft 2 3 3 3 3 3 3 3 Other* 2 2 2 2 2 2 2 2 Total 228 193 185 172 161 147 138 128 + Less than 0.5 Gg Note: Totals may not sum due to independent rounding. * “Other" includes snowmobiles and other recreational equipment, logging equipment, lawn and garden equipment, railroad equipment, airport equipment, commercia l equipment, and industrial equipment.
Table 3-25: N 2 O Emissions from Mobile Combustion (Gg) Fuel Type/Vehicle Type 1990 1997 1998 1999 2000 2001 2002 2003 Gasoline Highway 130 166 167 164 158 145 134 123

Passenger Cars 82 86 86 84 80 74 70 64 Light-Duty Trucks 46 76 76 76 74 66 60 54 Heavy-Duty Vehicles 2 4 4 4 4 4 5 5 Motorcycles + + + + + + + + Diesel Highway 1 1 1 1 1 1 1 1

Passenger Cars + + + + + + + +Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 84 Light-Duty Trucks + + + + + + + + Heavy-Duty Vehicles 1 1 1 1 1 1 1 1 Alternative Fuel Highway + + + + + + + + Non-Highway 10 11 11 11 12 11 12 12

Ships and Boats 1 1 1 1 2 1 2 1 Locomotives 1 1 1 1 1 1 1 1 Farm Equipment 6 6 6 6 6 6 6 5 Construction Equipment 1 1 1 1 1 1 1 1 Aircraft 1 1 1 1 1 1 1 1 Other* 1 1 1 1 1 1 1 1 Total 141 178 179 176 171 158 147 136 + Less than 0.5 Gg Note: Totals may not sum due to independent rounding. * “Other" includes snowmobiles and other recreational equipment, logging equipment, lawn and garden equipment, railroad equipment, airport equipment, commercia l equipment, and industrial equipment. Mobile sources comprise the single largest source category of CO, NO x , and NMVOC emissions in the United States. In 2003, mobile combustion contributed 89 percent of CO emissions, 56 percent of NO x emissions, and 46 percent of NMVOC emissions. Since 1990, emissions of NMVOCs from mobile combustion decreased by 42 percent, CO emissions decreased 37 percent, and emissions of NO x decreased by 14 percent.

Table 3-26: NO x Emissions from Mobile Combustion (Gg) Fuel Type/Vehicle Type 1990 1997 1998 1999 2000 2001 2002 2003 Gasoline Highway 5,746 4,268 4,090 3,924 3,812 3,715 3,519 3,527

Passenger Cars 3,847 2,447 2,316 2,158 2,084 2,027 1,920 1,924 Light-Duty Trucks 1,364 1,334 1,294 1,268 1,303 1,285 1,217 1,220 Heavy-Duty Vehicles 515 475 467 485 411 390 369 370 Motorcycles 20 13 13 13 13 14 13 13 Diesel Highway 2,956 3,708 3,729 3,671 3,803 3,338 3,162 3,169

Passenger Cars 39 13 11 10 7 6 6 6 Light-Duty Trucks 20 10 9 8 6 5 5 5 Heavy-Duty Vehicles 2,897 3,685 3,709 3,653 3,791 3,326 3,151 3,158 Alternative Fuel Highway a IE IE IE IE IE IE IE IE Non-Highway 3,432 3,792 3,772 3,705 3,780 3,770 3,707 3,722

Ships and Boats 953 963 919 818 966 971 954 958 Locomotives 857 962 973 910 908 907 891 895 Farm Equipment 63 75 83 84 80 73 72 72 Construction Equipment 437 487 487 497 484 480 472 474 Aircraft b 641 708 706 765 697 690 678 681 Other c 480 597 604 632 645 650 639 642 Total 12,134 11,768 11,592 11,300 11,395 10,823 10,389 10,418 IE (Included Elsewhere) Note: Totals may not sum due to independent rounding.

a NO x emissions from alternative fuel highway vehicles ar e included under gasoline and diesel highway vehicles. b Aircraft estimates include only emissions related to landing and take-off (LTO) cycles, and therefore do not include cruise altitude emissions.

c "Other" includes gasoline- and diesel-pow ered recreational, industrial, lawn and garden, light commercial, logging, airport service, and other equipment.

Table 3-27: CO Emissions from Mobile Combustion (Gg) Fuel Type/Vehicle Type 1990 1997 1998 1999 2000 2001 2002 2003 Gasoline Highway 98,328 67,509 65,246 61,210 60,657 56,716 55,541 52,544

Passenger Cars 60,757 36,825 35,686 32,921 32,867 31,600 30,945 29,275 Light-Duty Trucks 29,237 25,748 24,754 23,343 24,532 22,574 22,107 20,914 Heavy-Duty Vehicles 8,093 4,787 4,642 4,782 3,104 2,411 2,361 2,234Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 85 Motorcycles 240 150 163 164 154 131 129 122 Diesel Highway 1,696 1,301 1,202 1,122 1,088 869 851 805

Passenger Cars 35 13 10 10 7 6 6 5 Light-Duty Trucks 22 13 12 9 6 5 5 5 Heavy-Duty Vehicles 1,639 1,276 1,179 1,103 1,075 858 840 795 Alternative Fuel Highway a IE IE IE IE IE IE IE IE Non-Highway 19,459 21,474 21,493 21,152 21,935 22,387 22,181 22,177

Ships and Boats 1,679 1,948 1,943 2,121 1,946 1,952 1,934 1,934 Locomotives 85 89 83 98 90 90 89 89 Farm Equipment 217 250 274 285 245 233 231 231 Construction Equipment 582 636 633 630 626 621 615 615 Aircraft b 1,090 1,098 1,081 1,074 1,047 1,041 1,032 1,031 Other c 15,807 17,453 17,478 16,943 17,981 18,449 18,280 18,276 Total 119,482 90,284 87,940 83,484 83,680 79,972 78,574 75,526 IE = Included Elsewhere Note: Totals may not sum due to independent rounding.

a CO emissions from alternative fuel highway vehicles are included under ga soline and diesel highway vehicles. b Aircraft estimates include only emissions related to landing and take-off (LTO) cycles, and therefore do not include cruise altitude emissions.

c "Other" includes gasoline- and diesel-pow ered recreational, industrial, lawn and garden, light commercial, logging, airport service, and other equipment.

Table 3-28: NMVOC Emissions from Mobile Combustion (Gg) Fuel Type/Vehicle Type 1990 1997 1998 1999 2000 2001 2002 2003 Gasoline Highway 8,110 5,167 5,067 4,924 4,615 4,285 3,931 3,832

Passenger Cars 5,120 2,928 2,895 2,810 2,610 2,393 2,195 2,140 Light-Duty Trucks 2,374 1,882 1,812 1,734 1,750 1,664 1,527 1,488 Heavy-Duty Vehicles 575 336 335 351 232 206 189 184 Motorcycles 42 22 25 28 23 22 20 20 Diesel Highway 406 263 249 230 216 207 190 185

Passenger Cars 16 6 5 5 3 3 3 3 Light-Duty Trucks 14 8 7 6 4 4 3 3 Heavy-Duty Vehicles 377 249 237 219 209 201 184 179 Alternative Fuel Highway a IE IE IE IE IE IE IE IE Non-Highway 2,416 2,498 2,427 2,432 2,398 2,379 2,438 2,333

Ships and Boats 608 766 763 769 744 730 748 716 Locomotives 33 35 33 38 35 35 36 35 Farm Equipment 28 32 35 38 24 19 20 19 Construction Equipment 85 83 81 81 76 72 74 71 Aircraftb 149 142 137 141 130 125 128 123 Otherc 1,513 1,441 1,378 1,366 1,390 1,397 1,432 1,370 Total 10,933 7,928 7,742 7,586 7,230 6,872 6,560 6,351 IE (Included Elsewhere) Note: Totals may not sum due to independent rounding.

a NMVOC emissions from alternative fuel highway vehicles are included under gasoline and diesel highway vehicles. b Aircraft estimates include only emissions related to landing and take-off (LTO) cycles, and therefore do not include cruise altitude emissions.

c "Other" includes gasoline- and diesel-pow ered recreational, industrial, lawn and garden, light commercial, logging, airport service, and other equipment.



### Methodology

Estimates of CH 4 and N 2 O emissions from mobile combustion were calculated by multiplying emission factors by measures of activity for each fuel a nd vehicle type (e.g., light -duty gasoline trucks). Depending upon the category, activity data included such information as fuel consumption, and vehicle miles traveled (VMT). The activity dataInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 86 and emission factors used are described in the subsections that follow. A complete discussion of the methodology used to estimate emissions from mobile combustion a nd the emission factors used in the calculations is provided in Annex 3.2.

EPA (2003) provided emissions estimates of NO x , CO, and NMVOCs for eight categories of highway vehicles, 44 aircraft, and seven categories of non-highway vehicles. 45 These emission estimates were provided from preliminary EPA data, which, in its final iteration, will be publishe d on the National Emission Inve ntory (NEI) Air Pollutant Emission Trends web site. The methodology used to deve lop these estimates can be found on EPA’s Air Pollutant Emission Trends website, at <http://www. epa.gov/ttn/chief/trends/index.html>.

Highway Vehicles
Emission estimates for gasoline and diesel highway vehicl es were based on VMT and emission factors by vehicle type, fuel type, model year, and control technology. Emissions from alternative fuel vehicles (AFVs) 46 were based on VMT by vehicle and fuel type.

Emission factors for gasoline and diesel highway vehicles were developed by ICF (2004). These factors were based on EPA and California Air Resources Board (CARB) laborat ory test results of different vehicle and control technology types. The EPA and CARB tests were designe d following the Federal Test Procedure (FTP), which covers three separate driving segments, since vehicl es emit varying amounts of GHGs depending on the driving segment. These driving segments are: (1) a transient driving cycle that includes cold start and running emissions, (2) a cycle that represents running emissions only, and (3) a transient driving cycle that includes hot start and running emissions. For each test run, a ba g was affixed to the tailpipe of the vehicle and the exhaust was collected; the content of this bag was then analyzed to determine quantities of gases present. The emission characteristics of segment 2 was used to define running emissions, and subtracted from the total FTP emissions to determine start emissions. These were then recombined based upon the ra tio of start to running emi ssions for each vehicle class from MOBILE6.2 to approximate aver age driving characteristics.

Emission factors for AFVs were developed after c onsulting a number of sources, including Argonne National Laboratory’s GREET 1.5–Transportati on Fuel Cycle Model (Wang 1999), Lipman and Delucchi (2002), the Auto/Oil Air Quality Improvement Research Program ( CRC 1997), the California Air Resources Board (Brasil and McMahon 1999), and the University of California Riverside (Norbeck, et al., 1998). The primary approach taken was to calculate CH 4 emissions from actual test data and determine N 2 O emissions from NO x emissions from the same tests. While the formation of N 2 O is highly dependent on the type of catalyst used and the catalyst temperature, tailpipe N 2 O is likely to increase as engine out NO x emissions increase. Thus, as a first approximation, the NO x to N 2 O emission ratio will likely be constant for a given emission control group. A complete discussion of the data source and methodology used to determine emission factors from AFVs is provided in Annex 3.2.

Annual VMT data for 1990 through 2003 were obtained fro m the Federal Highway Administration’s (FHWA) Highway Performance Monitoring System database as reported in Highway Statistics (FHWA 1996 through 2004). VMT was then allocated from FHWA’s vehicle categories to fuel-specific vehicle cate gories based on estimates of fuel consumption by fuel ty pe for each vehicle category, developed using info rmation on shares of vehicle fuel use for each vehicle category by fuel ty pe reported in DOE (2004) and inform ation on total motor vehicle fuel

44 These categories included: gasoline passenger cars, diesel pa ssenger cars, light-duty gasoline trucks less than 6,000 pounds i n weight, light-duty gasoline trucks betw een 6,000 and 8,500 pounds in weight, light-duty diesel trucks, heavy-duty gasoline trucks and buses, heavy-duty diesel trucks and buses, and motorcycles. 45 These categories included: locomotives, ma rine vessels, farm equipment, construc tion equipment, other off-highway liquid fuel (e.g. recreational vehicles and lawn and garden equipmen t), and other off-highway gaseous fuel (e.g., other off-highway equipment running on compressed natural gas). 46 Alternative fuel and advanced technology ve hicles are those that can operate using a motor fuel other than gasoline or diesel. This includes electric or other bifuel or dual fuel vehicles that may be partially powered by gasoline or diesel.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 87 consumption by fuel type from FHWA (1996 to 2004). VMT for AFVs were taken from Browning (2003). The age distributions of the U.S. vehicle fleet were obtaine d from EPA (2004b) and EPA (2000), and the average annual age-specific vehicle mileage accumulation of U. S. vehicles were obt ained from EPA (2000).

Control technology and standards data for highway vehicl es were obtained from the EPA’s Office of Transportation and Air Quality (EPA 2004a, 2004d, 2000, 1998, and 1997). These technologies and standards are defined in Annex 3.2, and were compiled from EPA (1993), EP A (1994a), EPA (1994b), EPA (1998), EPA (1999), and IPCC/UNEP/OECD/IEA (1997).

Preliminary estimates for NO x , CO, and NMVOCs were obtained from EP A (2004e) and disaggregated based on EPA (2003), which, in its final iteration, will be publishe d on the National Emission Inve ntory (NEI) Air Pollutant Emission Trends web site.

Non-Highway
Fuel consumption data were employed as a measure of activity for non-highway vehicles, and then fuel-specific emission factors were applied. 47 Activity data were obtained from AAR (2004), BEA (1991 through 2004), Benson (2002 through 2004), DOE (1993 through 2004), DESC (2004), DOC (1991 through 2004), DOT (1991 through 2004), EIA (2002a), EIA (2002b), EIA (2004a), EIA (2004b), EIA (2003 through 2004), EIA (1991 through 2004), EPA (2004c), and FAA (2004). Emission factors for non- highway modes were taken from IPCC/UNEP/OECD/IEA (1997)

. 

### Uncertainty

This section discusses the uncertainty of the emissions estimates for CH 4 and N 2 O. Uncertainty was analyzed separately for highway vehicles and non-highway vehicles , due to differences in their characteristics and their contributions to total mobile source emissions.

Uncertainty analyses were not conducted for CO, NO x , or NMVOC emissions. Emission factors for these gases have been extensively researched, si nce these gases are regulated emissions from motor vehicles in the United States, and the uncertainty of these emissions estimates is believed to be relatively low. A much higher level of uncertainty is associated with CH 4 and N 2 O emission factors, since emissions of these gases are not regulated in the United States, and unlike CO 2 emissions, the emission pathways of CH 4 and N 2 O are also highly complex.

Highway Vehicles
A quantitative uncertainty analysis wa s conducted for the highway portion of the mobile source sector using the IPCC-recommended Tier 2 uncertainty estimation methodology, Monte Carlo Simulation technique, using @RISK software. The uncertainty analysis was performed on 2003 estimates of CH 4 and N 2 O emissions, incorporating probability distribution f unctions associated with the ma jor input variables. For the purposes of this analysis, the uncertainty was modeled for the following two major sets of input variables: (1) vehicle mile traveled (VMT) data, by vehicle and fuel type and (2) emission factor da ta, by vehicle, fuel, and control technology type.

Mobile combustion emissions of CH 4 and N 2 O per vehicle mile traveled vary significantly due to fuel type and composition, technology type, operating speeds and conditions, type of emi ssion control equipment, equipment age, and operating and maintenance practices. The primary activity data, VMT, are collected and analyzed each year by government agencies.

47 The consumption of international bunker fuels is not included in these activity data, but is estimated separately under the International Bunker Fuels source category.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 88 To determine the uncertainty associated with the activity data used in the calculations of CH 4 and N 2 O emissions, the agencies and the experts that supply the data were contacted. Because few of these sources were able to provide quantitative estimates of uncertainty, e xpert quantitative judgments were used to assess the uncerta inty associated with the activity data.

The emission factors for highway vehicles used in the Inventory were obtained from ICF (2004). These factors were based on laboratory testing of vehicles. While th e controlled testing environment simulates real driving conditions, emission results from such testing can only approximate real world conditions and emissions. For some vehicle and control technology types, the testing did not yi eld statistically significant results within the 95 percent confidence interval, requiring expert judgments to be used in developing the emission factors. In those cases, the emission factors were developed based on comparisons of fuel consumption between similar vehicle and control technology categories.

The estimates of VMT for highway vehicles by vehicle type in the United States were provided by FHWA (1996 through 2004), and were generated though the cooperation of FHWA and state and local governments. These estimates are subject to several possible sources of error, such as unregistered vehicles, unreported fuel sales to avoid fuel taxes, differences in achieved versus estimat ed fuel economy, and measurement and estimation errors. These VMT were apportioned by fuel type, and then allocat ed to individual model years using temporal profiles of both the vehicle fleet by age and vehicle usage by model year in the United States provided by EPA (2004b) and EPA (2000). While the uncertainty associated with total U.S. VMT is believed to be low, the uncertainty within individual source categories was assumed to be higher gi ven uncertainties associated with apportioning total VMT into individual vehicle categories, by technology type, and equipment age. The uncertainty of individual estimates was assumed to relate to the magnitude of estimated VMT (i.e., it was assumed smaller sources had greater percentage uncertainty). A further source of uncertainty occurs since FHWA and EPA use different definitions of vehicle type and estimates of VMT by vehicle type (pr ovided by FHWA) are broken down by fuel type using EPA vehicle categories.

A total of 69 highway data input variables were simulated through Monte Carlo Simulation technique using @RISK software. Variables included VMT and emission factors for individual vehicle categories and technologies. In developing the uncertainty estimation model, a normal distribution was assumed for all activity-related input variables (e.g., VMT) except in the case of buses, in which a triangular distribution was used. The dependencies and other correlations among the activity data were incorporat ed into the model to ensure consistency in the model specification and simulation. Emission factors were a ssigned uniform distributions, with upper and lower bounds assigned to input variables based on 97.5 percent confidence in tervals of laboratory test data. In cases where data did not yield statistically significant results within the 95 percent confidence interval, estimates of upper and lower bounds were made using expert judgment. The bounds for th e emission factor-related input variables were typically asymmetrical around their inventory estimates. Bias (or systematic uncertainties) associated with the emission factors was incorporated into the analysis when expert judgments were applied to the laboratory test results in determining the uncertainty characteristics and/or the bounds of the emission factors. 48 The results of this analysis are reported in the section below, titled Quantitative Estimates of Uncertainty

. Non-Highway
Emissions from non-highway vehicles are a small portion of total emissions from mobiles sources, representing 20 percent of CH 4 emissions from mobile sources and 9 percent of N 2 O emissions from mobile sources in 2003. Since they comprise a small share of mobile source emissions, even large uncertainties in th ese estimates would have a relatively small impact on the total emission estimate for mobile sources. As a result, a quantitative analysis of uncertainty of emissions from non-highway vehicles has not been performed. However, sources of uncertainty for

48 Random uncertainties are the main focus of statistical uncertainty analysis. Un certainty estimates elicited from experts include both random and systematic uncertainty. Hence, both thes e types of uncertainty are repr esented in this uncertainty analysis.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 89 non-highway vehicles are being investigated by examining the underlying uncertainty of emission factors and fuel consumption data.

Overall, a significant amount of uncertainty is associat ed with the emission estimates for non-road sources. A primary cause is a large degree of uncertainty surrounding emission factors. The IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories reports that CH 4 emissions from aviation and marine sources may be uncertain by a factor of two, while N 2 O emissions may be uncertain by an order of magnitude for marine sources and seve ral orders of magnitude for aviation. No information is provided on the uncertainty of emission factors for other non-highway sources.

Fuel consumption data have a lower uncertainty than emission factors, though large uncertainties do exist for individual sources. Fuel cons umption for off-highway vehicl es (i.e., equipment used fo r agriculture, construction, lawn and garden, railroad, airport ground support, etc., as well as recreational vehicles) was generated by EPA’s NONROAD model (EPA 2004c). This model estimates fuel consumption based on estimated equipment/vehicle use (in hours) and average fuel consumed per hour of use. Since the fuel estimates are not based upon documented fuel sales or consumption, a fair degree of uncertainty accompan ies these estimates.

Distillate consumption for ships and boats was obtained from sales estimates from EIA’s Fuel Oil and Kerosene Sales (EIA 1991 through 2004). The estimates for distillate c onsumption have associated uncertainty, as EIA’s estimates are based on sales to economic sectors, and it can be difficult to determine how much of the fuel sold in each sector is used by mobile or stati onary sources and to further attribute th is consumption to specific final users. For example, some fuel purchased by the marine sect or may be used for operating heavy equipment or even generators, instead of being used entirely by ships and boats . This distinction between mobile and stationary fuel users is not made by EIA.

EIA does provide coefficients of variation to estimate sa mpling error, which occurs due to the fact that these estimates are based on a sample set. However, as EIA poi nts out, these coefficients do not take into account all the sources of potential bias, which includes incomplete inform ation, misinterpretation of survey questions, and other factors that may cause estimates of fuel sales to be different from actual sales. In addition, diesel for ships and boats is adjusted for bunker fuel consumption, which introduces an additional (and much higher) level of uncertainty.

Domestic consumption for residual fuel consumption by ships and boats is obtained from EIA (2004a). These estimates fluctuate widely from year to year. Such fluctua tions cannot be fully explained without further analysis of the underlying activity data sets and, as such, the estimates are believed to be highly uncertain. The estimate of domestic consumption is then adjusted downward to account for international bunker fuels, which represents the primary use of residual fuel by ships and boats. As the international bunker fuel data are considered to have a moderate level of uncertainty, 49 the overall uncertainty of the domestic ships and boats estimate for residual fuel consumption is considered high.

Domestic jet fuel and aviation gasoline consumption data are obtained from EIA (2004a). Like diesel and residual marine fuel consumption, jet fuel consumption for av iation is adjusted downward to account for international bunker fuels. The international bunker fuel estimates in troduce a significant amount of uncertainty. Additionally, all jet fuel consumption in the transportation sector is assu med to be consumed by aircraft. Some fuel purchased by airlines is not used in aircraft, but instead used to power auxiliary power units, in ground equipment, and to test engines. Some jet fuel may also be used for other purpos es such as blending with diesel fuel or heating oil.

In calculating CH 4 emissions from aircraft, an averag e emission factor is applied to total jet fuel consumption. This average emission factor takes into account the fact that CH 4 emissions occur only during the landing and take-off

49 This is discussed in the sec tion on International Bunker Fuels.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 90 (LTO) cycles, with no CH 4 being emitted during the cruise cycle. However, a better approach would be to apply emission factors based on the number of LTO cycles.

Finally, U.S. aircraft em ission estimates for CO, NO x , and NMVOCs from EPA (2004e and 2003) are based on LTO cycles and only estimate near ground-level emissions, which are more relevant fo r air quality evaluations. These estimates also include both domes tic and international flights. Ther efore, estimates presented here may overestimate IPCC-defined domestic CO, NO x , and NMVOC emissions by including LTO cycles by aircraft on international flights but underestimate total emissions because they exclude emissions from aircraft on domestic flight segments at cruising altitudes.

Quantitative Estimates of Uncertainty
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-29. Mobile combustion CH 4 emissions in 2003 were estimated to be between 2.5 and 2.8 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Simulations). This indicates a range of 9 percent below to 4 percent above the 2003 emission estimate of 2.7 Tg CO 2 Eq. Also at a 95 percent confidence level, mobile combustion N 2 O emissions in 2003 were estimated to be between 35.2 and 52.8 Tg CO 2 Eq., indicating a range of 16 percent below to 26 percent above the 2003 emission estimate of 42.1 Tg CO 2 Eq.

Table 3-29: Tier 2 Quantitative Uncertainty Estimates for CH 4 and N 2 O Emissions from Mobile Sources (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Rela tive to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bo und Lower Bound Upper Bound Mobile Sources CH 4 2.7 2.5 2.8 -9% +4% Mobile Sources N 2 O 42.1 35.2 52.8 -16% +26%

a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval. This uncertainty analysis is a continuation of a multi-year process for developing credible quantitative uncertainty estimates for this source category using the IPCC Tier 2 appr oach to uncertainty analysis. In the upcoming years, the type and the characteristics of th e actual probability density functions underlying the input variables will be identified and more credibly characterized. Accordingly, the quantitative uncertainty estimates reported in this section should be considered as preliminary and illustrative.



### QA/QC and Verification

A source-specific QA/QC plan for mobile combustion was developed and implemented. This effort included a Tier 1 analysis, as well as portions of a Tier 2 analysis. The Tier 2 procedures focused on the emission factor and activity data sources, as well as the methodology used fo r estimating emissions. Becau se significant changes were made to highway vehicle emission factors and non-highw ay fuel consumption estimates (see Recalculations Discussion below), QA/QC effo rts were focused in particular on emissi ons impacted by these changes. These procedures included a qualitative assessment of the emission estimates to determine whether they appear consistent with the most recent activity data and em ission factors available. A comparison of historical emissions between this year’s and last year’s Inve ntories was also conducted, and was qualitativel y assessed to ensure that the changes in estimates were consistent with the changes in activity data and emission factors.



### Recalculations Discussion

In order to ensure the highest quality estimates, the methodology is con tinuously revised ba sed on comments from internal and external reviewers. Th is year, adjustments were made to emission factors and activity data to incorporate new research and additional data sources.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 91 The most significant changes in this year’s Inventory are the revisions to the highway emission factors for CH 4 and N 2 O. The previous emission factors had been derived usi ng methodology similar to that outlined in IPCC/UNEP/OECD/IEA (1997). However, preliminary tests suggested that these emission factors may not have been representative of actual emissions. EPA sponsored laboratory testing that resulted in the new emission factors used in this report. The emission factors changed notab ly, ranging from a decrease of 97 percent to an increase of 114 percent for individual vehicle/fuel type/technology types; the combined effect of these changes in emission factors significantly lowered CH 4 and N 2 O emissions from highway vehicles. Given the large contribution of highway vehicles to the mobile totals, these new emission factors were major drivers behind the changes in CH 4 and N 2 O estimates. However, because thes e emission factors do not impact CO 2 emissions, their impact is less significant when considering total m obile source emissions of all GHGs.

Additionally, the methodology for estimating VMT by ve hicle/fuel type category (e.g., LDGV, LDDV, LDGT, LDDT, etc.) was revised. The purpose of this revision was to ensure that the VMT estim ates for individual vehicle categories match up with VMT estimates by vehicle type from FHWA (1996 through 2004), which is the recognized source of national VMT estimates. The new methodology apportions FHWA’s estimate of VMT for each vehicle category (e.g., light-duty ve hicles, light-duty trucks, buses, heavy- duty trucks) to fuel-based vehicle categories based on estimates of gasoline and diesel fuel consumption for each vehicl e category, drawn from DOE (2004). This change had a small impact on emissions.

The vehicle age distribution values for highway vehicles we re also revised. Previously, the Inventory relied on one vehicle age distribution acro ss 25 model years from EPA (2000), which was applied for each year. For the current Inventory, that same distribution was applied for years 1990 through 1998, and annually variable vehicle age distributions were applied for years 1999 through 2003 ba sed on data obtained from EPA’s MOVES model (EPA 2004b). The annually variable ag e distributions more accurately reflect changes in the ve hicle stock, and include 31 model years.

Emissions from gasoline- and diesel-electric hybrid vehi cles are now included under gasoline and diesel vehicles instead of alternative fuel/advanced technology category, since these ve hicles only run on traditional motor gasoline. This change did not have an impact on total emissions.

EPA’s NONROAD model is now used as the primary data s ource for fuel consumption by off-highway equipment (e.g., construction, agricultural, lawn and gard en equipment), rather than data from FHWA’s Highway Statistics (FHWA 1996 through 2004), EIA’s Fuel Oil and Kerosene Sales (EIA 1991 through 2004), and several other sources. The NONROAD model is also used to estimate fuel consumption by recreational boats, rather than data from FHWA’s Highway Statistics. Some of the individual sources used in the previous Inventory had not been updated for several years, while others had updated their methodologi es, resulting in large variations in estimates from year to year. Use of the NONROAD Model for all of these estimates is believed to provide more accurate, upto-date, and consistent estimates.

Other changes include minor revisions to historical airc raft fuel consumption estimates in FAA (2004) and rail consumption provided from Benson (2004). These revisi ons were not significant, and the overall impact on emissions estimates is small.

Overall, these changes resulted in an average annual decrease of 0.6 Tg CO 2 Eq. (14 percent) in CH 4 emissions from mobile combustion and an average annual decrease of 6.2 Tg CO 2 Eq. (11 percent) in N 2 O emissions from mobile combustion for the period 1990 through 2002.


### Planned Improvements

While the data used for this report represent the most accurate information availabl e, three areas have been identified that could potentially be improved in the short term given resource availability:

1) Reconcile Fuel Consumption Estimates used for Calculating N 2 O/CH 4 and CO 2 – Estimates of transportation fuel consumption by fuel type from EIA are used as the basis for estimating CO 2 emissions from the transportation sector. These estimates are then apportioned to mode and vehicle category based on “bottom up” estimates of fuelInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 92 consumption from sources such as FHWA’s Highway Statistics (FHWA 1996 through 2004) and DOE’s Transportation Energy Data Book (DOE 1993 through 2004). These sources are also used to develop N 2 O and CH 4 estimates. The EIA fuel consumption estimates, however , differ from the estimates derived using “bottom up” sources. For certain vehicle categories this leads to CO 2 emissions trends that conflict with those of the “bottom up” sources. Potential improvements include reconciling fuel consumption estimates from EIA and other data sources, and revising the current process of allocating CO 2 emissions to reflect trends from the more detailed vehicle category estimates of fuel consumption.

2) Improve consideration of emissions from trucks used off-road – Some light- and heavy-duty trucks travel for a portion of their mileage off-road. N 2 O and CH 4 estimates for highway vehicles are developed based on vehicle mileage data from FHWA’s Highway Statistics , which in turn, are drawn from the Highway Performance Monitoring System (HPMS). These emissions estimates do not address travel by trucks off-road. Gasoline fuel consumed by trucks used off-road for construction, agricu lture, and other industrial/commercial uses is reported in Highway Statistics , and is included as part of the non-road agricultu re and construction categories. However, diesel fuel consumed by trucks used off-road is not addresse d in the current Inventory, and further work should be conducted to develop estimates of off-road truck use of diesel fuel. In add ition, default emission factors from IPCC are applied to the off-highway modes. As a result, the emissions factors fo r agricultural equipment are applied both to equipment and trucks used in agriculture, and emissi ons factors for construction equipment are applied both to equipment and trucks used in construction. Emission estimates would be improved through an investigation of more appropriate emission f actors for off-road trucks.

3) Improve estimation of VMT by vehicle/fuel type category – The current Inventory process for estimating VMT by vehicle/fuel type category involves apportioning VMT by vehicle type to each fu el type on the basis of fuel consumption. While this is a reasonable simplification, this approach implicitly assumes the same average fuel economy for gasoline and diesel vehicl es. A more accurate apportionment fo r VMT by fuel ty pe for light-duty trucks and medium/heavy-duty trucks could potentially be developed using data on vehicle travel from the Vehicle Inventory and Use Survey and other publications, or usi ng VMT breakdowns by vehicle/fuel type combinations from the MOBILE6 or MOVES models. These sources should be investigated in order to develop a more robust apportionment method.



### 3.5. Coal Mining (IPCC Source Category 1B1a)

Three types of coal mining related activities release CH 4 to the atmosphere: underground mining, surface mining, and post-mining (i.e., coal-h andling) activities. Underground coal mi nes contribute the largest share of CH 4 emissions. All 101 gassy underground coal mines em ploy ventilation systems to ensure that CH 4 levels remain within safe concentrations. These systems can exhaust significant amounts of CH 4 to the atmosphere in low concentrations. Additionally, twenty -one U.S. coal mines supplement ve ntilation systems with degasification systems. Degasification syst ems are wells drilled from the surface or borehol es drilled inside the mine that remove large volumes of CH 4 before, during, or after mining. In 2003, ten coal mines collected CH 4 from degasification systems and sold this gas to a pipeline, thus reducing emissi ons to the atmosphere. In addition, one coal mine used CH 4 from its degasification system to heat mine ventilation air on site. Surface coal mines also release CH 4 as the overburden is removed and the coal is exposed, but the level of emissions is much lower than from underground mines. Finally, some of the CH 4 retained in the coal after mining is released during processing, storage, and transport of the coal.

Total CH 4 emissions in 2003 were estimated to be 53.8 Tg CO 2 Eq. (2,561 Gg), a decline of 34 percent since 1990 (see Table 3-30 and Table 3-31). Of this amount, unde rground mines accounted for 70 percent, surface mines accounted for 16 percent, and post-mining emi ssions accounted for 14 percent. In 1993, CH 4 generated from underground mining dropped, primarily due to labor strike s at many large underground mines. In 1994 and 1995, CH 4 emissions increased due to resume d production at high emitting mines after the labor strike. The decline in CH 4 emissions from underground mines from 1996 to 2002 wa s the result of the reduction of overall coal production, the mining of less gassy coal, and an increase in CH 4 recovered and used. CH 4 emissions increased slightly in 2003 due to additional gas drainage being vented to th e atmosphere and a reduction in CH 4 recovery. Surface mine emissions and post- mining emissions remained rela tively constant from 1990 to 2003.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 93 Table 3-30: CH 4 Emissions from Coal Mining (Tg CO 2 Eq.) Activity 1990 1996 1997 1998 1999 2000 2001 2002 2003 Underground Mining 62.1 45.3 44.3 44.4 41.6 39.4 38.1 35.8 37.6

Liberated 67.6 59.8 55.7 58.6 54.4 54.0 54.2 53.3 53.6 Recovered & Used (5.6) (14.5) (11.4) (14.2) (12.7) (14.6) (16.1) (17.5) (16.1) Surface Mining 10.4 9.2 9.3 9.4 9.0 8.8 9.2 8.8 8.4 Post-Mining (Underground) 7.7 7.2 7.4 7.4 6.8 6.7 6.8 6.4 6.4 Post-Mining (Surface) 1.7 1.5 1.5 1.5 1.5 1.4 1.5 1.4 1.4 Total 81.9 63.2 62.6 62.8 58.9 56.2 55.6 52.4 53.8 Note: Totals may not sum due to independent rounding.

Table 3-31: CH 4 Emissions from Coal Mining (Gg) Activity 1990 1996 1997 1998 1999 2000 2001 2002 2003 Underground Mining 2,956 2,158 2,111 2,117 1,982 1,876 1,816 1,705 1,788

Liberated 3,220 2,850 2,654 2,791 2,589 2,573 2,580 2,538 2,554 Recovered & Used (265) (692) (543) (674) (607) (697) (765) (833) (766) Surface Mining 497 438 445 448 428 417 438 420 402 Post-Mining (Underground) 367 341 354 352 325 317 323 304 305 Post-Mining (Surface) 81 71 72 73 69 68 71 68 65 Total 3,900 3,008 2,983 2,989 2,805 2,677 2,647 2,497 2,561 Note: Totals may not sum due to independent rounding.



### Methodology

The methodology for estimating CH 4 emissions from coal mining consists of two parts. The first part involves estimating CH 4 emissions from underground mines. Because of the availability of ventilation system measurements, underground mine emissions can be estimated on a mine-by-mine basis and then summed to determine total emissions. The s econd step involves estimating emissi ons from surface mines and post-mining activities by multiplying basin-specific coal pr oduction by basin-specifi c emission factors.

Underground mines . Total CH 4 emitted from underground mines was estimated as the sum of CH 4 liberated from ventilation systems and CH 4 liberated by means of degasification systems, minus CH 4 recovered and used. The Mine Safety and Heath Administration (MSHA) samples CH 4 emissions from ventilation systems for all mines with detectable 50 CH 4 concentrations. These mine-by-mine measurements are used to estimate CH 4 emissions from ventilation systems.

Some of the higher-emitting underground mines also use de gasification systems (e.g., wells or boreholes) that remove CH 4 before, during, or after mining. This CH 4 can then be collected for use or vented to the atmosphere. Various approaches were employed to estimate the quantity of CH 4 collected by each of the twenty-one mines using these systems, depending on available data. For example, some mines report to EPA the amount of CH 4 liberated from their degasification systems. For mines that sell recovered CH 4 to a pipeline, pipeline sales data published by state petroleum and natural gas agencies were used to es timate degasification emissions. For those mines for which no other data are available, default recovery efficien cy values were developed, depending on the type of degasification system employed.

Finally, the amount of CH 4 recovered by degasification systems and then used (i.e., not vented) was estimated. This calculation was complicated by the fact that most CH 4 is not recovered and used during the same year in which the particular coal seam is mined. In 2003, ten active coal mines sold recovered CH 4 into the local gas pipeline

50 MSHA records coal mine methane readings with concentrations of greater than 50 ppm (parts per million) methane. Readings below this threshold are considered non-detectable.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 94 networks, while one coal mine used recovered CH 4 on site. Emissions avoided for these projects were estimated using gas sales data reported by various state agencies. For most mines with recovery systems, companies and state agencies provided individual well production information, whic h was used to assign gas sales to a particular year. For the few remaining mines, coal mine operators supplied information regarding the number of years in advance of mining that gas recovery occurs.

Surface Mines and Post-Mining Emissions . Surface mining and post-mining CH 4 emissions were estimated by multiplying basin-specific coal pr oduction, obtained from the Energy Information Administration’s Coal Industry Annual (see Table 3-32) (EIA 2003), by ba sin-specific emission factors. Su rface mining emission factors were developed by assuming that surface mines emit two times as much CH 4 as the average in situ CH 4 content of the coal. Revised data on in situ CH 4 content and emissions factors are taken from EPA (1996) and AAPG (1984). This calculation accounts for CH 4 released from the strata surrounding the coal seam. For post-mining emissions, the emission factor was assumed to be 32.5 percent of the average in situ CH 4 content of coals mined in the basin.

Table 3-32: Coal Production (Thousand Metric Tons)

Year Underground Surface Total 1990 384,250 546,818 931,068 1991 368,635 532,656 901,291 1992 368,627 534,290 902,917 1993 318,478 539,214 857,692 1994 362,065 575,529 937,594 1995 359,477 577,638 937,115 1996 371,816 593,315 965,131 1997 381,620 607,163 988,783 1998 378,964 634,864 1,013,828 1999 355,433 642,877 998,310 2000 338,173 635,592 973,765 2001 345,305 676,142 1,021,446 2002 324,219 667,619 991,838 2003 320,047 651,251 971,297 

### Uncertainty

The emission estimates from underground ventilation systems were based on act ual measurement data, which are believed to have relatively low uncertainty. A degree of imprecision was introduced because the measurements were not continuous but rather an average of quarterly instantaneous readings. Additionally, the measurement equipment used possibly resulted in an aver age of 10 percent overestimation of annual CH 4 emissions (Mutmansky and Wang 2000). Estimates of CH 4 liberated and recovered by degasifica tion systems are also relatively certain because many coal mine operators provided information on i ndividual well gas sales and mined through dates. Many of the recovery estimates use data on wells within 100 feet of a mined area. A level of uncertainty currently exists concerning the radius of influence of each well. The number of wells count ed, and thus the avoided emissions, may increase if the drainage area is found to be larger than currently estimated.

Compared to underground mines, there is considerably mo re uncertainty associated with surface mining and postmining emissions because of the diffi culty in developing accurate emission factors from field measurements. However, since underground emissions comprise the majority of total coal mining emissions, the uncertainty associated with underground emissions is the primary factor that determines overall uncertainty. The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-33. Coal mining CH 4 emissions in 2003 were estimated to be between 51.9 and 55.7 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Simulations). This indicates a range of 4 percent below to 4 percent above the 2003 emission estimate of 53.8 Tg CO 2 Eq.

Table 3-33: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Coal Mining (Tg CO 2 Eq. and Percent)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 95 Source Gas 2003 Emission Estimate Uncertainty Range Rela tive to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Coal Mining CH 4 53.8 51.9 55.7 -4% +4%

a Range of emission estimates predic ted by Monte Carlo Simulation for a 95 percent confidence interval.



### Recalculations Discussion

In-situ gas content is the principal variable used to determine post-mining methane emissions of mined coal. Previously, in-situ values used were based on average CH 4 content values summarized in Exhibit 3-4 of the U.S. EPA publication, EPA/400/9-90/008; Methane Emissions From C oal Mining, Issues and O pportunities, September 1990 . The original source of information is derived from three primary sources: 1986 USBM Circular 9067, Results of the Direct Method Determination of the Gas Contents of U.S. Coal Basins , 1983 U.S. DOE Report (DOE/METC/83-76), Methane Recovery from Coalbeds: A Potential Energy Source , and a series of 1986-88 Gas Research Institute Topical Reports called A Geologic Assessment of Natural Gas from Coal Seams. No data was available for eight of the coal mining states and therefore default values fro m other coal basins were assigned to those states.

Since Circular 9067 contained only a portion of the gas content data compiled by USBM, the complete dataset, published in 1996 Evaluation and Analysis of Gas Content and Coal Properties of Major Coal Bearing Regions of the United States , EPA/600/R-96-065, is now the basis of new in-situ gas content value. In addition, gas content data from the U.S. DOE Methane Recovery from Coalbed Projects (MRCP), which was the original source of data for the GRI Topical Reports noted above , was utilized. (Condensed versions of the original MRCP reports for 13 U.S. coal basins are compiled in Coalbed Methane Resources of the United States, AAPG St udies in Geology Series #17 , published in 1984).

The compiled gas content data for each of the coal basins wa s sorted by depth to determ ine in-situ values for surface and underground mines, separately . Overburden depths of surf ace mines were analyzed using Keystone Coal Industry Manuals from 1991 through 2003 and found that the maximum depth was 250 feet. Therefore, gas content data from samples taken less than 250 feet deep were assigned to surface mines and the samples collected from deeper depths to underground mines. The combination of these changes resulted in an average annual decrease of 0.2 Tg CO 2 Eq. (0.3 percent) in CH 4 emissions from coal mining for the period 1990 through 2002.


### Planned Improvements

To reduce the uncertainty associ ated with the radius of influence of each well, the appropriate drainage radius will be investigated for future inventories. Since the number of wells counted may increase if the drainage area is found to be larger than currently estimated, additional mines may be included in future estimates of recovery.



### 3.6. Abandoned Underground Coal Mines (IPCC Source Category 1B1a)

All underground and surface coal mining liberates CH 4 as part of the normal mining operations. The amount of CH 4 liberated depends on the amount that resides in the coal (“ in situ ”) and surrounding strata when mining occurs. The in-situ CH 4 content depends upon the amount of CH 4 created during the coal form ation (i.e., coalification) process, and the geologic characteristics of the coal seams. During coalification, more deeply buried deposits tend to generate more CH 4 and retain more of the gas after uplift to minable depths. Deep underground coal seams generally have higher CH 4 contents than shallow co al seams or surface deposits.

Underground coal mines contribute the largest share of CH 4 emissions, with active underground mines the leading source of underground emissions. However, mines also continue to release CH 4 after closure. As mines mature and coal seams are mined through, mines close and are abandoned. Many are sealed and some flood through intrusion of groundwater or surface water into the void. Shafts or portals are generally filled with gravel and capped with aInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 96 concrete seal, while vent pipes and bor eholes are plugged in a manner similar to oil and gas wells. Some abandoned mines are vented to the atmosphere to prevent the buildup of CH 4 that may find its way to surface structures through overburden fractures. As work stops within the mines, the CH 4 liberation decreases but it does not stop completely. Following an initial decline, abandoned mines can liberate CH 4 at a near-steady rate over an extended period of time, or, if flooded, produce gas for only a few years. The gas can migrate to th e surface through the conduits described above, particularly if they have not been sealed adequately. In addition, diffuse emissions can occur when CH 4 migrates to the surface through cracks and fissures in the strata overlying the coal mine. The following factors influence abandoned mine emissions:

• Time since abandonment;

• Gas content and adsorption characteristics of coal;

• Methane flow capacity of the mine;

• Mine flooding;

• Presence of vent holes; and

• Mine seals. Gross abandoned mine methane emissions ranged from 6.1 to 9.6 Tg CO 2 Eq. from 1990 through 2003, varying as much as 1.3 Tg CO 2 Eq. from year to year. Fluctuations were due mainly to the number of mines closed during a given year as well as the magnitude of the emissions from those mines when active. Abandoned mine emissions peaked in 1996 (8.6 Tg CO 2 Eq.) due to the large number of mine closures from 1994 to 1996 (70 gassy mines closed during the three-year period). In spite of this rapid rise, abandoned mine emi ssions have been generally on the decline since 1996 (with slight increases in 1999 and 2000). There were fewer than thirteen gassy mine closures during each of the years from 1998 through 2003. By 2003, ab andoned mine emissions were reduced to 6.4 Tg CO 2 Eq. (see Table 3-34 and Table 3-35).

Table 3-34: CH 4 Emissions from Abandoned Coal Mines (Tg CO 2 Eq.) Activity 1990 1997 1998 1999 2000 2001 2002 2003 Abandoned Underground Mines 6.1 9.6 8.8 9.0 9.3 8.5 8.0 7.9

Recovered & Used 0 1.5 1.7 1.6 1.5 1.5 1.6 1.5 Total 6.1 8.1 7.1 7.3 7.7 6.9 6.4 6.4 Note: Totals may not sum due to independent rounding.

Table 3-35: CH 4 Emissions from Abandoned Coal Mines (Gg) Activity 1990 1997 1998 1999 2000 2001 2002 2003 Abandoned Underground Mines 288 458 421 426 441 403 380 377

Recovered & Used - 74 80 78 73 73 77 72 Total 288 385 341 349 369 331 303 306 Note: Totals may not sum due to independent rounding.



### Methodology

Estimating CH 4 emissions from an abandoned coal mine requires predicting the emissions of a mine from the time of abandonment through the inventory year of interest. The flow of CH 4 from the coal to the mine void is primarily dependent on mine’s emissions when active and the exte nt to which the mine is flooded or sealed. The CH 4 emission rate before abandonment reflects the gas content of the coal, rate of coal mining, and the flow capacity of the mine in much the same way as th e initial rate of a water-free conventional gas well reflects the gas content of the producing formation and the flow capacity of the well. Existing data on abandoned mine emissions through time, although sparse, appear to fit the hyperbolic type of d ecline curve used in forecas ting production from natural gas wells.

In order to estimate CH 4 emissions over time for a given mine, it is necessary to apply a decline function, initiated upon abandonment, to that mine. In the analysis, mines were grouped by coal basin with the assumption that they will generally have the same initial pressures, permeability and isotherm. As CH 4 leaves the system, the reservoir pressure, P r , declines as described by the isotherm. The emi ssion rate declines because the mine pressure (P w ) is essentially constant at atmospheric pressure, for a vented mine, and the PI term is essentially constant at theInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 97 pressures of interest (atmospheric to 30 psia). A rate-tim e equation can be generated that can be used to predict future emissions. This decline through time is hyperbo lic in nature and can be empirically expressed as:

q = q i (1+bD i t) (-1/b)

Where:

• q is the gas rate at time t in mcf/d

• q i is the initial gas rate at time zero (t o ) in million cubic feet per day (mcfd)

• b is the hyperbolic exponent, dimensionless

• D i is the initial decline rate, 1/yr

• t is elapsed time from to in years This equation is applied to mines of various initial emission rates that have similar initial pressures, permeability and adsorption isotherms (EPA 2003).

The decline curves are also affected by both sealing and flooding. Based on field measurement data, it was assumed that most U.S. mines prone to flooding will become comple tely flooded within 8 years and therefore no longer have any measurable CH 4 emissions. Based on this assumption, an average decline rate for flooding mines was established by fitting a decline curve to emissions from field measurements. An exponential equation was developed from emissions data measured at eight abandoned mines known to be filling with water located in two of the five basins. Using a least squa res, curve-fitting algorithm, emissions data were matched to the exponential equation shown below. There was not enough data to es tablish basin-specific equations as was done with the vented, non-flooding mines (EPA 2003).

q = q i e (-Dt)

Where:

• q is the gas flow rate at time t in mcf/d

• q i is the initial gas flow rate at time zero (t o ) in mcfd

• D is the decline rate, 1/yr

• t is elapsed time from t o in years Seals have an inhibiting effect on the rate of flow of CH 4 into the atmosphere compared to the rate that would be emitted if the mine had an open vent. The total volum e emitted will be the same, but will occur over a longer period. The methodology, therefore, treats the emissions prediction from a sealed mine similar to emissions from a vented mine, but uses a lower initial rate depending on the degree of sealing. The computational fluid dynamics simulator was again used with the conceptual abandoned mine model to predict the decline curve for inhibited flow. The percent sealed is defined as 100 × (1 - initial emissi ons from sealed mine / emission rate at abandonment prior to sealing). Significant differences ar e seen between 50 percent, 80 percent a nd 95 percent closure. These decline curves were therefore used as the high, middle, and low values for emissions from sealed mines (EPA 2003).

For active coal mines, those mines producing over 100 mcfd account for 98 percent of all CH 4 emissions. This same relationship is assumed for abandoned mines. It was determined that 434 abandoned mines closing after 1972 produced emissions greater than 100 mcfd when active. Further, the status of 256 of the 434 mines (or 59 percent) is known to be either 1) vented to the atmosphere, 2) sealed to some degree (either earthen or concrete seals), or 3) flooded (enough to inhibit methane flow to the atmosphere). The remaining 41 percent of the mines were placed in one of the three categories by applyi ng a probability distribution analysis ba sed on the known status of other mines located in the same coal basin (EPA 2003).

Inputs to the decline equation require the average emission rate and the date of abandonment. Generally this data is available for mines abandoned after 1972; however, such data are largely unknown for mines closed before 1972. Information that is readily available such as coal production by state and county are helpful, but do not provide enough data to directly employ the methodology used to calculate emissions from mines abandoned after 1971. It isInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 98 assumed that pre-1972 mines are governed by the same physical, geologic, and hydrologic constraints that apply to post-1972 mines; thus, their emissions may be characterized by the same decline curves.

During the 1970s, 78 percent of CH 4 emissions from coal mining came from seventeen counties in seven states. In addition, mine closure dates were obtained for two states, Colorado and Illinois, throughout the 20 th century. The data was used to establish a frequency of mine closure hi stogram (by decade) and applie d to the other five states with gassy mine closures. As a result, basin-specific d ecline curve equations were applied to 145 gassy coal mines estimated to have closed between 1920 and 1971 in the United States, representing 78 percent of the emissions. State-specific, initial emission rates were used based on average coal mine methane emissions rates during the 1970s (EPA 2003).

Abandoned mines emission estimates are based on a ll closed mines known to have active mine CH 4 ventilation emission rates greater than 100 mcfd at the time of abandonment. For example, for 1990 the analysis included 145 mines closed before 1972 and 259 mi nes closed between 1972 and 1990. Initial emission rates based on MSHA reports, time of abandonment, and basin-specific decline curv es influenced by a number of factors were used to calculate annual emissions for each mine in the database. Coal mine degasification data are not available for years prior to 1990, thus the initial emission rates used reflect ventilation emissions only fo r pre-1990 closures. Methane degasification amounts were added to ventilation data for the total CH 4 liberation rate for fourteen mines that closed between 1992 and 2003. Since the sample of gassy mines (with active mine emissions greater than 100 mcfd) is assumed to account for 78 percent of the pre-1971 and 98 percent of the post-1971 abandoned mine emissions, the modeled results were multiplied by 1.22 and 1.02 to account for all U.S. abandoned mine emissions. Once the 1991 through 2003 totals were calculated, they were downwardly adjusted to reflect abandoned mine CH 4 emissions avoided from those mines. The inventory totals were not adjusted for abandoned mine reductions in 1990 through 1992, because no data was reported fo r abandoned coal mining methane rec overy projects during that time.


### Uncertainty

The parameters for which values must be estimated for each mine in order to predict its decline curve are: 1) the coal's adsorption isotherm; 2) CH 4 flow capacity as expressed by permeab ility; and 3) pressure at abandonment. Because these parameters are not available for each mine , an approach was used that generates a probability distribution of potential outcomes base d on the most likely value and the probable range of values for each parameter. The range of values is not meant to capture th e extreme values, but values that represent the highest and lowest quartile of the cumulative probability density function of the parameter. Once the low, mid, and high values are selected, they are applied to a probability density function.

The emission estimates from underground ventilation systems were based on act ual measurement data, which are believed to have relatively low uncertainty. A degree of imprecision was introduced because the measurements were not continuous, but rather an average of quarterly instantaneous readings. Additionally, the measurement equipment used possibly resulted in an aver age of 10 percent overestimation of annual CH 4 emissions (Mutmansky and Wang 2000). Estimates of CH 4 liberated and recovered by degasifica tion systems are also relatively certain because many coal mine operators provided information on i ndividual well gas sales and mined through dates.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-36. Abandoned coal mines CH 4 emissions in 2003 were estimated to be between 5.4 and 7.8 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Simulations). This indicates a range of 16 percent below to 22 percent above the 2003 emission estimate of 6.4 Tg CO 2 Eq. One of the reasons for the relatively narrow range is that mine-specific data is used in the methodology. The largest degree of uncertainty is associated with the unknown status mines (which account for 41 percent of the mines), with a ±50 percent uncertainty.

Table 3-36: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Abandoned Underground Coal Mines (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Rela tive to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 99 Lower Bound Upper Bound Lower Bound Upper Bound Abandoned Coal Mines CH 4 6.4 5.4 7.8 -16% +22%

a Range of emission estimates predic ted by Monte Carlo Simulation for a 95 percent confidence interval.



### QA/QC and Verification

As part of a Tier 2 analysis, the United States undertook an effort to verify the model results used in the U.S. Inventory with field measurements. Field measurements were used to test the accuracy of the mathematical decline curves to be used for basin-specific emissions estimates. A series of field measurements were conducted at abandoned mine vent locations across the United Stat es. Between November 1998 and February 2000, EPA recorded measurements at five mines that were not floode d. Measurements were recorded at two abandoned mines located in Ohio and Virginia continuously for 6 to 12 hours. As the methodology was finalized, EPA measured emissions from three additional mines located in Illinois a nd Colorado. These measurements were recorded hourly for 3 to 4 days and were normalized to average barometric pressures. Prior to these measurements, EPA’s Office of Research and Development initiated a field research pr ogram in the early 1990s. Data for 21 abandoned mines located throughout the Northern and Cent ral Appalachian, Black Warrior, and I llinois Basins were collected using similar techniques.

Measurements for all field data recorded were plotted against predicted emissions as part of the two studies from 1991 through 2000. Emission rates from nine of the ten mines that were measured fall very close to the predicted mid-case decline rate for their respective basins. For the exponential decline curve fit to the flooding mines, six of nine measurements fall within a 95 percent pr edictive confidence interv al of the mean.

Of the abandoned mines in the database, only about 13 per cent of the mines maintain vents to the atmosphere. Therefore, it is difficult to obtain field data. Additional field measurements, however, would be beneficial to further calibrate the equations defined above. Furthermore, it would be useful to extend measurements of diffuse emissions from sealed mines, since they compri se 43 percent of total mines.



### Recalculations Discussion

In 2003, all methane emissions from abandoned coal mines we re recalculated using: 1) an updated mine list based on 1985 and 1988 USBM records (adding 41 mi nes to the inventory), 2) update d coal seam permeabilities based on a 2004 EPA study, and 3) revised closure dates for 43 of the mines based on MSHA’s data retrieval system. The combination of these changes resulted in an average annual increase of 2.8 Tg CO 2 Eq. (64.5 percent) in CH 4 emissions from abandoned coal mines for the period 1990 through 2002.



### 3.7. Petroleum Systems (I PCC Source Category 1B2a)

Methane emissions from petroleum systems are primarily a ssociated with crude oil production, transportation, and refining operations. During each of these activities, CH 4 is released to the atmosphere as fugitive emissions, vented emissions, emissions from operational upsets, and emissions from fuel combustion. Total CH 4 emissions from petroleum systems in 2003 were 17.1 Tg CO 2 Eq. (815 Gg). Since 1990, emissions declined due to a decline in domestic oil production and industry efforts to make emi ssions reductions (see Table 3-37 and Table 3-38). The various sources of emissions are detailed below.

Production Field Operations . Production field opera tions account for over 95 percent of total CH 4 emissions from petroleum systems. Vented CH 4 from field operations account for approximately 83 percent of the emissions from the production sector, fugitive emissions account for six percent, combustion emissions ten percent, and processupset emissions barely one percent. The most dominant sources of vented emissions are field storage tanks, naturalgas-powered pneumatic devices (low bleed, high bleed, and chemical injection pumps). These four sources alone emit 79 percent of the production field operations emissions. Emissions from storage tanks occur when the CH 4 entrained in crude oil under pressure vola tilizes once the crude oil is put into st orage tanks at atmospheric pressure. Emissions from high and low-bleed pneumatics occur when pre ssurized gas that is used for control devices is bledInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 100 to the atmosphere as they cycle up and down to modulate the system. Emissions from chemical injection pumps occur as high-pressure gas that is used to drive the pum ps is vented to the atmosphere. Two additional large sources, oil well heads and gas engines, together account for 12 percent of emissions from the production sector. The remaining nine percent of the emissions are dist ributed among 33 additional ac tivities within these four categories.

Crude Oil Transportation. Crude oil transportation activities account for less than one percent of total CH 4 emissions from the oil industry. Venting from tanks a nd marine vessel loading opera tions accounts for 65 percent of CH 4 emissions from crude oil transportation. Fugitive emissions, almost entirely from floating roof tanks, account for 18 percent. The remaining 17 percent is di stributed among 4 additional sources within these two categories.

Crude Oil Refining . Crude oil refining processes and systems account for only three percent of total CH 4 emissions from the oil industry b ecause most of the CH 4 in crude oil is removed or escapes before the crude oil is delivered to the refineries. There is an insignificant amount of methan e in all refined products. Within refineries, vented emissions account for about 87 percen t of the emissions, while fugitive and combustion emissions account for approximately six and seven percent respectively. Refine ry system blowdowns for maintenance and the process of asphalt blowing

⎯ with air, to harden the asphalt

⎯ are the primary venting contributors. Most of the fugitive emissions from refineries are from leak s in the fuel gas system. Refinery combustion emissions include small amounts of unburned CH 4 in process heater stack emissions and from unburned CH 4 in engine exhausts and flares.

Table 3-37: CH 4 Emissions from Petroleum Systems (Tg CO 2 Eq.) Activit y 1990 1997 1998 1999 2000 2001 2002 2003 Production Field Operations 19.3 18.1 17.8 17.1 16.9 16.8 16.4 16.4 Pneumatic device venting 11.5 10.8 10.6 10.3 10.0 10.0 9.8 9.8 Tank Venting 3.8 3.4 3.4 3.2 3.2 3.2 3.2 3.2 Combustion & process upsets 2.2 2.0 2.0 1.9 1.9 1.9 1.8 1.8 Misc. venting & fugitives 1.4 1.3 1.3 1.3 1.2 1.2 1.2 1.2 Wellhead fugitives 0.5 0.5 0.5 0.5 0.5 0.5 0.4 0.4 Crude Oil Transportation 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Refining 0.5 0.6 0.6 0.6 0.6 0.6 0.6 0.6 Total estimated emissions 20.0 18.8 18.5 17.8 17.6 17.4 17.1 17.1

Table 3-38: CH 4 Emissions from Petroleum Systems (Gg) Activit y 1990 1997 1998 1999 2000 2001 2002 2003 Production Field Operations 920 862 846 815 803 799 783 782 Pneumatic device venting 545 515 504 488 478 475 465 465 Tank Venting 179 164 162 153 154 154 151 151 Combustion & process upsets 103 96 94 90 89 89 87 86 Misc. venting & fugitives 66 62 61 60 59 59 58 57 Wellhead fugitives 26 25 25 24 22 22 21 21 Crude Oil Transportation 7 6 6 6 5 5 5 5 Refining 25 27 27 27 28 27 27 27 Total estimated emissions 951 895 879 848 836 831 815 815



### Methodology

The methodology for estimating CH 4 emissions from petroleum systems is a bottom-up approach, based on a comprehensive study of CH 4 emissions from U.S. petroleum systems (EPA 1999, Radian 1996e). These studies combined emission estimates from 70 activities occurring in petroleum systems from th e oil wellhead through crude oil refining, including 39 activities for crude oil produc tion field operations, 11 for crude oil transportation activities, and 20 for refining operations. Annex 3.5 provides greater detail on the emission estimates for these 70Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 101 activities. The estimates of CH 4 emissions from petroleum systems do not include emissions downstream of oil refineries because these emissions are very small compared to CH 4 emissions upstream of oil refineries.

The methodology for estimating CH 4 emissions from the 70 oil industry activ ities employs emission factors initially developed by EPA (1999) and activity factors that are ba sed on EPA (1999) and Radian (1996e) studies. Emissions are estimated for each activity by multiplying emission f actors (e.g., emission rate per equipment item or per activity) by their corresponding activity factor (e.g., equipm ent count or frequency of activity). The report provides emission factors and activity factors fo r all activities except those related to offshore oil production. For offshore oil production, an emission factor was calculated by dividing an emission estimate from the Minerals Management Service (MMS) by the number of platforms (MMS 2004b). Emission factors were held constant for the period 1990 through 2003.

Activity factors for years 1990 through 2003 were collected from a wide variety of statistical resources. For some years, complete activity factor data were not available. In such cases, one of three approaches was employed. Where appropriate, the activity factor was calculated from related statistics using ratios developed for Radian (1996e). For example, Radian (1996e) found that the number of heater treaters (a source of CH 4 emissions) is related to both number of producing wells and annual production. To estimate the activity factor for heater treaters, reported statistics for wells and production were used, along w ith the ratios developed for Radian (1996e). In other cases, the activity factor was held constant from 1990 through 2003 based on EPA (1999). Lastly, the previous year’s data were used when data fo r the current year were unavailable. See Annex 3.5 for additional detail.

Nearly all emission factors were taken from Radian (1996e) and EPA (1999). The remaining emission factors were taken from the following sources: EPA default values, MMS reports (MMS 1995), the Exploration and Production (E&P) Tank model (DB Robinson Research Ltd. 1997), and the consensus of industry peer review panels.

Among the more important references used to obtain activity factors are the Energy Information Administration annual and monthly reports (EIA 1990-2003, 1995-2003a-b), the API Basic Petroleum Data Book (API 2003), Methane Emissions from the Natural Gas Industry by the Gas Research Institute and EPA (Radian 1996a-d)

, consensus of industry peer review panels, MMS reports (MMS 1995, 2000, 2004a-b), and the Oil & Gas Journal (OGJ 2003a-b). Forecasts of activity factors for petrol eum systems were developed using production and refining capacity data from the EIA Annual Energy Outlook (EIA 2004) as well as offshore activity projections from MMS (2001 and 2004a). Annex 3.5 provides a complete list of references.


### Uncertainty

The detailed, bottom-up inventory analysis used to evaluate U.S. petroleum systems reduces the uncertainty related to the CH 4 emission estimates in comparison with a top-down approach. However, some uncertainty still remains. Emission factors and activity factors are based on a combination of measurements, equipment design data, engineering calculations and studies, surveys of selected f acilities and statistical reporting. Statistical uncertainties arise from natural variation in measurements, equipment types, operational variability and survey and statistical methodologies. Published activity factor s are not available every year for a ll 70 activities analyzed for petroleum systems; therefore, some are estim ated. Because of the dominance of six major sources, which account for 90 percent of the total emissions, the uncertainty surrounding these six sources has been estimated most rigorously, and serves as the basis for determining the overall uncertainty of petroleum systems emission estimates.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-39. Petroleum systems CH 4 emissions in 2003 were estimated to be between 11.9 and 51.4 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Simulations). This indicates a range of 30 percent below to 200 percent above the 2003 emission estimate of 17.1 Tg CO 2 Eq.

Table 3-39: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Petroleum Systems (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Rela tive to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 102 Lower Bound Upper Bound Lower Bound Upper Bound Petroleum Systems CH 4 17.1 11.9 51.4 -30% +200%

a Range of emission estimates predic ted by Monte Carlo Simulation for a 95 percent confidence interval.



### Recalculations Discussion

Estimates of CH 4 from petroleum systems contain two changes with respect to previous inventories. First, the emission factor for CH 4 emissions from oil tanks in the production sector was modified to remove venting from condensate tanks and only account for venting from crude oil tanks. The previous methodol ogy included an emissions factor that was averaged from the API E&P Tank Calc runs on both oil and condensate tanks. The new calculation is averaged from API E&P Tank Calc runs (DB Robinson Research Ltd. 1997) for API gravity of 44 degrees and below. The adjustment has been made so that vented emissions from condensate tanks can be moved into the emissions from natural gas systems, where they are more relevant. The second change was the development of a new activity factor for offshore Gulf of Mexico platform venting in the production sector. Previously, the activity factor was obtained through MMS, the total number of Gulf of Mexico platforms, and an assumption of what percentage were oil producing platforms. The number of Gulf of Mexico platforms, platform data, and field data is now available on an annual basis from MMS (2000, 2004b, 2004c). From the field and platform data, a new estimate was developed for the percenta ge of oil producing platforms. This change results in the model reflecting the trend towards more natural gas production than oil production in the Gulf of Mexico. A change in the Gulf of Mexico platform activity resulted in an indirect change in th e emissions factor that is calculated from the known base-year emissions value.

The combination of these changes resulted in an average annual decrease of 7.1 Tg CO 2 Eq. (27.4 percent) in CH 4 emissions from petroleum systems for the period 1990 through 2002. Oil tank ven ting accounted for virtually all of the decrease while Gulf of Mexico platform venting and fugitives remained relatively unchanged.


### Planned Improvements

Several improvements to the emission estimates are being evaluated that fine-tune and better track changes in emissions. These include, but are not limited to, some activity factors that are also accounted for in the Natural Gas STAR Program emission reductions, some emission factors for consistency between emission estimates from Petroleum Systems and Natural Gas Syst ems, and new data from recent studies that bear on both emission factors and activity factors. The growing body of data in the Natural Gas STAR Program, coupled with an increasing number of oil and gas companies doing internal greenhouse gas emissions inventories, provides an opportunity to reevaluate emission and activity factors, as well as the methodology currently used to project emissions from the base year.



### 3.8. Natural Gas Systems (IPCC Source Category 1B2b)

The U.S. natural gas system encompasses hundreds of t housands of wells, hundreds of processing facilities, and over a million miles of transmission a nd distribution pipelines. Overall, natural gas systems emitted 125.9 Tg CO 2 Eq. (5,998 Gg) of CH 4 in 2003, a slight decrease over 1990 emissions (see Table 3-40 and Table 3-41). Improvements in management practices and technology, along with the repl acement of older equipment, have helped to stabilize emissions (EPA 2002).

Methane emissions from natural gas systems are generally process related, with normal operations, routine maintenance, and system upsets being the primary contri butors. Emissions from normal operations include: natural gas combusting engines and turbine exhaust, bleed and discharge emissions from pneumatic devices, and fugitive emissions from system components. Routine maintenance emissions originate from pipelines, equipment, and wells during repair and maintenance activities. Pressure surg e relief systems and accidents can lead to system upset emissions. Below is a characterization of the four major st ages of the natural gas system . Each of the stages is described and the different factors affecting CH 4 emissions are discussed.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 103 Field Production . In this initial stage, wells are used to withdraw raw gas fro m underground formations. Emissions arise from the wells themselves, gathering pipelines, and well-site gas treatment facilities such as dehydrators and separators. Fugitive emissions and emissions from pneumatic devices account for the majority of emissions. Emissions from field produc tion accounted for approximately 34 percent of CH 4 emissions from natural gas systems in 2003.

Processing . In this stage, natural gas liquids and various other constituents from the raw gas are removed, resulting in “pipeline quality” gas, which is injected into the transmission system. Fugitive emissions from compressors, including compressor seals, are the primary emission source from this stage. Processing plants account for about 12 percent of CH 4 emissions from natural gas systems.

Transmission and Storage . Natural gas transmission involves high pressure, large diameter pipelines that transport gas long distances from field production and processing areas to distribution systems or large volume customers such as power plants or chemical plants. Compressor station facilities, which contain large reciprocating and turbine compressors, are used to m ove the gas throughout the United Stat es transmission system. Fugitive emissions from these compressor stations and from metering and regulating stations account for the majority of the emissions from this stage. Pneumatic devices and engine exhaust are also sources of emissions from transmission facilities.

Natural gas is also injected and stored in underground fo rmations, or liquefied and stored in above ground tanks, during periods of low demand (e.g., summer), and withdraw n, processed, and distributed during periods of high demand (e.g., winter). Compressors and dehydrators are the primary contributors to emissions from these storage facilities. Methane emissions from transmission and st orage sector account for a pproximately 32 percent of emissions from natural gas systems.

Distribution . Distribution pipelines take the high-pressure gas from the transmission system at “city gate” stations, reduce the pressure and distribute the gas through primar ily underground mains and service lines to individual end users. There were over 978,000 miles of distribution mains in 2003, an increase from just over 789,500 miles in 1990 (OPS 2002a). Distribution system emissions, which acc ount for approximately 22 pe rcent of emissions from natural gas systems, result mainly fro m fugitive emissions from gate stati ons and non-plastic piping (cast iron, steel). 51 An increased use of plastic piping, which has lower emissions than other pipe materials, has reduced the growth in emissions from this stage. Distribution system emissions in 2003 were 10 percent lower than 1990 levels.

Table 3-40: CH 4 Emissions from Natural Gas Systems (Tg CO 2 Eq.)* Stage 1990 1997 1998 1999 2000 2001 2002 2003 Field Production 36.3 40.4 41.2 37.5 41.0 44.5 44.5 43.4 Processing 14.8 14.9 14.7 14.6 14.9 15.1 14.6 14.5 Transmission and Storage 46.8 46.1 44.7 43.4 43.4 40.2 42.0 40.6 Distribution 30.5 32.4 31.2 31.9 32.8 32.1 29.5 27.4 Total 128.3 133.6 131.8 127.4 132.1 131.8 130.6 125.9 *Including CH 4 emission reductions achieved by the Natural Gas STAR program. Note: Totals may not sum due to independent rounding.

Table 3-41: CH 4 Emissions from Natural Gas Systems (Gg)* Stage 1990 1997 1998 1999 2000 2001 2002 2003 Field Production 1,731 1,921 1,962 1,785 1,953 2,117 2,121 2,068 Processing 704 708 702 696 708 717 693 691 Transmission and Storage 2,226 2,193 2,127 2,068 2,067 1,914 2,002 1,933 Distribution 1,450 1,541 1,484 1,517 1,560 1,530 1,405 1,305

51 The percentages of total emissions from each stage may not add to 100 because of independent rounding.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 104 Total 6,112 6,363 6,276 6,066 6,289 6,277 6,221 5,998 *Including CH 4 emission reductions achieved by the Natural Gas STAR program. Note: Totals may not sum due to independent rounding.



### Methodology

The basis for estimates of CH 4 emissions from the U.S. natural gas industry is a detailed study by the Gas Research Institute and EPA (EPA/GRI 1996). The EPA/GRI study developed over 100 emission and activity factors to characterize emissions from the various components within the operating stages of the U.S. natural gas system. The study was based on a combination of process engineering studies and measurements at representative gas facilities. From this analysis, a 1992 emission estimate was developed using the emission and activity factors. For other years, a set of industry activity factor drivers was developed that can be used to update activity factors. These drivers include statistics on gas production, number of wells , system throughput, miles of various kinds of pipe, and other statistics that characterize the changes in the U.S. natural gas system infrastructure and operations.

See Annex 3.4 for more detailed information on the methodology and data used to calculate CH 4 emissions from natural gas systems.

Activity factor data were taken from the following sources: American Gas Association (AGA 1991-1998); American Petroleum Institute (API 2002, 2003); Annual En ergy Review (EIA 2002f); Historical Natural Gas Annual (EIA 2003e); Minerals and Management Service (MMS 1998, 1999, 2000, 2001, 2002a-b, 2003, 2004a-d); Monthly Energy Review (EIA 2004d); Natural Gas Annual (EIA 1993, 1996a , 1997a, 1998a-b, 2001a, 2002a, 2003a); Natural Gas Liquids Reserves Report (E IA 1996b, 1997b, 1998c, 1999, 2000, 2001c, 2002d); Natural Gas Monthly (EIA 2001b, 2002b-c, 2003b-d, 2004a-c,); the Natural Gas STAR Program annual emissions savings (EPA 2004); Oil and Gas Journal (OGJ 1999 - 2004); Office of Pi peline Safety (OPS 2004a-b) other Energy Information Administration publications (EIA 2002e, 2004e-f). The Gas Sy stems Analysis model was used to aid in collecting data for non-associated and associated wells (GSAM 1997). Data from a program for estimating emissions from hydrocarbon production tanks is incorporated (DB Robinson Research Ltd. 1997). Coalbed Methane well activity factors were taken from the Wyoming Oil and Gas Conservation Commission (Wyoming 2004) and the Alabama State Oil and Gas Board (Alabama 2004). Other state well data was taken from : American Association of Petroleum Geologists (AAPG 2204); Brookhaven College (B rookhaven 2004); Kansas Geological Survey (Kansas 2004); Rocky Mountain Production Report (Lippman (2003); Montana Board of Oil and Gas Conservation (Montana 2004); Oklahoma Geological Survey (Oklahoma 2004); Utah Division of Oil, Gas and Mining (Utah 2004). Emissions factors were taken from EPA/GRI (1996).


### Uncertainty

The heterogeneous nature of the natural gas industry ma kes it difficult to sample facilities that are completely representative of the entire industry. Because of this, scaling up from model facilities introduces a degree of uncertainty. Additionally, highly variable emission rates were measured among many system components, making the calculated average emission rates uncertain. The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-42. Natural gas systems CH 4 emissions in 2003 were estimated to be between 87.1 and 166.7 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Simulations). This indicates a range of 31 percent below to 32 percent above the 2003 emission estimate of 125.9 Tg CO 2 Eq.

Table 3-42: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Natural Gas Systems (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Natural Gas CH 4 125.9 87.1 166.7 -31% +32%Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 105 Systems

a Range of emission estimates pred icted by Monte Carlo Simulation for a 95 percent confidence interval.



### Recalculations Discussion

Emissions with Natural Gas STAR Program reductions were updated using new Gas STAR emissions reduction data from the iSTAR database. Gas STAR reductions re ported retroactively for the years 1990 to 1992 are assumed to be characterized in the GRI/EPA 1996 study for the base year 1992. Therefore, to avoid double counting, those emissions reductions are not counted in th e inventory. Gas STAR reductions are also subject to sunsetting rules that prevent perpetual crediting of all reductions. The inventor y assumes that once an emissions reducing technology is put in place, it will continue to provide emissions savings and thus the sunsetti ng rule is not be implemented in the inventory.

Three new sources of emissions in the production sector of the natural gas systems were added this year:

• Gas condensate stored in tanks vents methane and ot her hydrocarbons to the atmosphere. Emissions from condensate tanks can be divided into two categories: tanks with control devices such as vapor recovery units or flares, and tanks that have no control devices . Condensate tanks contributed an estimated 52.3 Gg of methane emissions that represents 0.87 percent of total methane emissions from natural gas systems in 2003. In 1990, Condensate tanks were estimated to c ontribute 39.9 Gg of emissions or about 0.65 percent of total emissions from natural gas systems.

• Another source added to the production sector fo r the 2003 reporting year was unconventional gas well fugitives. Wells in this source were previously treated as conventional we lls in the rest of U.S. (western) geographic region. Unconventional well fugitives include fugitive emissions from coal bed CH 4 and shale wells. From 1990 through 2003, unconventional well fug itives accounted for a small amount of emissions from natural gas systems.

• The production sector also had flaring from offshore Gu lf of Mexico operations added, using a 2 percent uncombusted hydrocarbon factor. This source contributed to less than 0.1 percent to the emissions from the entire time series. A second Gulf of Mexico source added to the production sector was Gulf of Mexico offshore well venting. This contributed about 2.4 pe rcent of the 2003 emissions and about 2.6 percent in 1990.

The combination of these methodological and historical data changes resulted in an average annual increase of 6.7 Tg CO 2 Eq. (5.3 percent) in CH 4 emissions from natural gas systems for the period 1990 through 2002.


### Planned Improvements

Several improvements to the emission estimates are being evaluated that fine-tune and better track changes in emissions. These include, but are not limited to, some activity factors that are also accounted for in the Natural Gas STAR Program emission reductions, some emission factors for consistency between emission estimates from the Petroleum Systems and Natural Gas Syst ems source categories, and new data from recent studies that bear on both emission factors and activity factors. The growing body of data in the Natural Gas STAR Program, coupled with an increasing number of oil and gas companies doing internal greenhouse gas emissions inventories, provides an opportunity to reevaluate emission and activity factors, as well as the methodology currently used to project emissions from the base year. Two improvements that are of particular note are in the production and processing sector. Recent data has suggested that the emission factor for well clean-ups in the production sector is low, and additional data sources are being investigated to produce a more robust emission factor. In the processing sector, improvements are being considered across the entire sector based on studies completed and near completion at five or more processing plants. These studies suggest the n eed for changing several emission factors as well as adding some additional sources within the processing sector.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 106 

### 3.9. Municipal Solid Waste Com bustion (IPCC Source Category 1A5)

Combustion is used to manage about 7 to 17 percent of th e municipal solid wastes generated in the United States, depending on the source of the estimate and the scope of materials included in the definition of solid waste (EPA 2000c, Goldstein and Matdes 2001, Kaufman et al. 2004). Almost all combustion of municipal solid wastes in the United States occurs at waste-to-energy facilities where energy is recovered, and thus emissions from waste combustion are accounted for in the Energy chapter. Combustion of municipal solid wastes results in conversion of the organic inputs to CO 2 . According to the IPCC Guidelines, when the CO 2 emitted is of fossil origin, it is counted as a net anthropogenic emission of CO 2 to the atmosphere. Thus, the emissions from waste combustion are calculated by estimating the quantity of waste combusted and the fraction of the wast e that is carbon derived from fossil sources.

Most of the organic materials in municipal solid wastes are of biogenic origin (e.g., paper, yard trimmings), and have their net carbon flows accounted for under the Land-Use Change and Fo restry chapter (see Box 3-3). However, some components—plastics, synthetic rubber, sy nthetic fibers, and carbon black—are of fossil origin. Plastics in the U.S. waste stream are primarily in the form of containers, packaging, and durable goods. Rubber is found in durable goods, such as carpets, and in non-durable goods, such as clothing and footwear. Fibers in municipal solid wastes are predominantly from clothing and home furnishings. Tires (which contain rubber and carbon black) are also considered a “non-hazardous” wast e and are included in the municipal solid waste combustion estimate, though waste disposal practices for tires differ from the rest of municipal solid waste.

[Begin Text Box]

Box 3-3: Biogenic Emissions and Sinks of Carbon For many countries, CO 2 emissions from the combustion or degradation of biogenic materials are important because of the significant amount of energy they derive from biomass (e.g., burning fuelwood). The fate of biogenic materials is also important when evaluating waste management emissions (e.g., the decomposition of paper). The carbon contained in paper was originally stored in trees during photosynthes is. Under natural conditions, this material would eventually degrade and cycle back to the atmosphere as CO 2 . The quantity of carbon that these degradation processes cycle through the Earth’s atmosphere, waters, soils, and biota is much greater than the quantity added by anthropogenic gree nhouse gas sources. However, the focus of the UNFCCC is on emissions resulting from human activities and subject to human control, because it is these emissions that have the potential to alter the climate by disrupting the natural balances in carbon's biogeochemical cycle, and enhancing the atmosphere’s natural greenhouse effect.

Carbon dioxide emissions from the com bustion or decomposition of biogenic ma terials (e.g., paper, wood products, and yard trimmings) grown on a sustainable basis are considered to mimic the closed loop of the natural carbon cycle

⎯ that is, they return to the atmosphere CO 2 that was originally removed by photosynthesis. However, CH 4 emissions from landfilled waste occur due to th e man-made anaerobic conditions conducive to CH 4 formation that exist in landfills, and are consequently included in this inventory.

The removal of carbon from the natural cycling of car bon between the atmosphere and biogenic materials

⎯ which occurs when wastes of biogenic origin are deposited in landfills

⎯ sequesters carbon. When wastes of sustainable, biogenic origin are landfilled, and do not completely decompose, the carbon th at remains is effectively removed from the global carbon cycle. Landfilling of forest products, yard trimmings, and food scraps resulted in net longterm storage of 10.1 Tg CO 2 Eq. in 2003, as described in the Land-Use Change and Forestry chapter.

[End Box]

Approximately 24 million metric tons of municipal solid wastes were combus ted in the United States in 2003. Carbon dioxide emissions from combustion of municipal solid wastes rose 72 percent since 1990, to an estimated 18.8 Tg CO 2 Eq. (18,781 Gg) in 2003, as the volume of plastics and other fossil carbon-containing materials in MSW increased (see Table 3-43 and Table 3-44). Waste combustion is also a source of N 2 O emissions (De SoeteInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 107 1993). Nitrous oxide emissions from municipal solid waste combustion were estimated to be 0.5 Tg CO 2 Eq. (1 Gg) in 2003, and have not changed significantly since 1990.

Table 3-43: CO 2 and N 2 O Emissions from Municipal Solid Waste Combustion (Tg CO 2 Eq.) Gas/Waste Product 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 10.9 17.8 17.1 17.6 18.0 18.8 18.8 18.8

Plastics 8.0 11.9 11.4 12.0 12.1 12.7 12.7 12.7 Synthetic Rubber in Tires 0.2 0.9 0.9 0.9 0.9 0.9 0.9 0.9 Carbon Black in Tires 0.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 Synthetic Rubber in MSW 1.3 1.7 1.6 1.6 1.7 1.8 1.8 1.8 Synthetic Fibers 1.2 2.1 2.0 2.0 2.1 2.2 2.2 2.2 N 2 O 0.4 0.4 0.3 0.3 0.4 0.5 0.5 0.5 Total 11.3 18.1 17.4 18.0 18.3 19.2 19.2 19.2

Table 3-44: CO 2 and N 2 O Emissions from Municipal Solid Waste Combustion (Gg) Gas/Waste Product 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 10,919 17,761 17,094 17,632 17,979 18,781 18,781 18,781

Plastics 7,953 11,914 11,427 11,950 12,145 12,718 12,718 12,718 Synthetic Rubber in Tires 191 891 887 890 893 895 895 895 Carbon Black in Tires 249 1,165 1,160 1,164 1,167 1,170 1,170 1,170 Synthetic Rubber in MSW 1,330 1,725 1,627 1,612 1,689 1,810 1,810 1,810 Synthetic Fibers 1,196 2,065 1,992 2,016 2,086 2,187 2,187 2,187 N 2 O 1 1 1 1 1 1 1 1

Ambient air pollutants are also emitted during waste incineration and open burning, as shown in Table 3-45. These emissions are a relatively small portion of the overall ambient air pollutant emissions, comprising less than 5 percent for each gas over the entire time series.

Table 3-45: NO x , CO, and NMVOC Emissions from Municipal Solid Waste Combustion (Gg) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 NO x 82 140 145 143 114 114 134 121

Waste Incineration 44 48 49 48 38 38 45 41 Open Burning 38 92 96 95 76 76 89 80 CO 978 2,668 2,826 2,725 1,670 1,672 1,672 1,674

Waste Incineration 337 68 69 66 40 41 41 41 Open Burning 641 2,600 2,757 2,659 1,630 1,631 1,631 1,633 NMVOCs 222 313 326 302 257 258 281 263

Waste Incineration 44 23 23 19 15 16 18 16 Open Burning 178 290 303 284 242 242 264 246 Note: Totals may not sum due to independent rounding.



### Methodology

Emissions of CO 2 from MSW combustion include CO 2 generated by the combustion of plastics, synthetic fibers, and synthetic rubber, as well as the combustion of synthe tic rubber and carbon black in tires. These emissions were calculated by multiplying the amount of each material combusted by the car bon content of the material and the fraction oxidized (98 percent). Plastics combusted in muni cipal solid wastes were cate gorized into seven plastic resin types, each material ha ving a discrete carbon content. Similarly, synthetic rubber is categorized into three product types, and synthetic fi bers were categorized into four product ty pes, each having a discrete carbon content. Scrap tires contain several types of sy nthetic rubber, as well as carbon black. Each type of synthetic rubber has a discrete carbon content, and carbon black is 100 percent carbon. Emissions of CO 2 were calculated based on theInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 108 number of scrap tires used for fuel and the synthetic rubbe r and carbon black content of the tires. More detail on the methodology for calculating emi ssions from each of these waste combustion sources is provided in Annex 3.6.

For each of the methods used to calculate CO 2 emissions from municipal solid waste combustion, data on the quantity of product combusted and the carbon content of the product are needed. For plastics, synthetic rubber, and synthetic fibers, the amount of material in municipal so lid wastes and its portion combusted were taken from the Characterization of Municipal Solid Waste in the United States (EPA 2000c, 2002a, 2003). For synthetic rubber and carbon black in scrap tires, this information was provided by the U.S. Scrap Tire Markets 2001 (RMA 2002) and Scrap Tires, Facts and Figures (STMC 2000, 2001, 2002, 2003). Data were not available for 2002 or 2003, so the values for these years were assumed to equal the value for 2001.

Average carbon contents for the “Other” plastics category, synthetic rubber in municipal solid wastes, and synthetic fibers were calculated from 1998 production statistics, which divide their respective markets by chemical compound. For synthetic rubber in scrap tires informa tion about scrap tire compositi on was taken from the Scrap Tire Management Council’s internet site (STMC 2003).

The assumption that 98 percent of organic carbon is oxidized (which applies to all municipal solid waste combustion categories for CO 2 emissions) was reported in the EPA’s life cycle analysis of greenhouse gas emissions and sinks from management of solid waste (EPA 2002b).

Combustion of municipal solid waste also results in emissions of N 2 O. These emissions were calculated as a function of the total estimated mass of municipal solid waste combusted and an emission factor. The N 2 O emission estimates are based on different data sources. As noted above, N 2 O emissions are a function of total waste combusted in each year; for 1990 through 2002, these data were derived from the information published in BioCycle (Kaufman et al 2004). As for the activity data for CO 2 emissions, data on total waste combusted was not available for 2003, so the value for this year was assumed to e qual the most recent value available (2002). Table 3-46 provides data on municipal solid waste generation and pe rcentage combustion for the total waste stream. The emission factor of N 2 O emissions per quantity of municipal solid waste combusted is an average of values from IPCC’s Good Practice Guidance (2000).

Table 3-46: Municipal Solid Waste Generation (Metric Tons) and Percent Combusted Year Waste Generation Combusted (%) 1990 266,365,714 11.5 1991 254,628,360 10.0 1992 264,668,342 11.0 1993 278,388,835 10.0 1994 292,915,829 10.0 1995 296,390,405 10.0 1996 297,071,712 10.0 1997 308,870,755 9.0 1998 339,865,243 7.5 1999 347,089,277 7.0 2000 371,071,109 7.0 2001 404,002,786 a 7.4 a 2002 436,934,464 7.7 2003 436,934,464 b 7.7 b

a Interpolated between 2000 and 2002 values. b Assumed equal to 2002 value.

EPA (2003) provided emission estimates for NO x , CO, and NMVOCs from waste incineration and open burning, which were determined using industry published producti on data and applying average emission factors.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 109 

### Uncertainty

A Tier 2 Monte Carlo analysis was performed to determine the level of uncertainty surrounding the estimates of CO 2 emissions and N 2 O emissions from municipal solid waste combus tion. IPCC Tier 2 analysis allows the specification of probability density functions for key variables within a computational structure that mirrors the calculation of the inventory estimate. Uncertainty estimates and distributions for waste generation variables (i.e., plastics, synthetic rubber, and textiles generation) were obt ained through a conversation w ith one of the authors of the Municipal Solid Waste in the United States reports. Statistical analyses or expert judgments of uncertainty were not available directly from the information sources for th e other variables; thus, uncer tainty estimates for these variables were determined using assumptions base d on source category knowledge and the known uncertainty estimates for the waste generation variables. The highest levels of uncertainty surround the variables that are based on assumptions (e.g., percent of clothing and footwear co mposed of synthetic rubber); the lowest levels of uncertainty surround variables that we re determined by quantitative measur ements (e.g., combustion efficiency, carbon content of carbon black).

The results of the 2003 uncertainty analysis of CO 2 emissions are the same as the 2002 results, given that the data for the two years is identical (no data updated for 2003 we re available). The results of the Tier 2 quantitative uncertainty analysis are summa rized in Table 3-47. Municipal solid waste combustion CO 2 emissions in 2003 were estimated to be between 15.2 and 21.6 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Simulations). This indicates a range of 19 percent below to 15 percent above the 2003 emission estimate of 18.8 Tg CO 2 Eq. Also at a 95 percent confidence level, municipal solid waste combustion N 2 O emissions in 2003 were estimated to be between 0.13 and 1.34 Tg CO 2 Eq. This indicates a range of 71 percent below to 192 percent above the 2003 emission estimate of 0.5 Tg CO 2 Eq.

Table 3-47: Tier 2 Quantitative Uncertainty Estimates for CO 2 and N 2 O from Municipal Solid Waste Combustion (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Municipal Solid Waste Combustion CO 2 18.8 15.2 21.6 -19% +15% Municipal Solid Waste Combustion N 2 O 0.5 0.13 1.34 -71% +192%

a Range of emission estimates predic ted by Monte Carlo Simulation for a 95 percent confidence interval. The uncertainties in the waste combustion emission estimates arise from both the assumptions applied to the data and from the quality of the data.

• MSW Combustion Rate. A source of uncertainty affecting both fossil CO 2 and N 2 O emissions is the estimate of the MSW combustion rate. The EPA (2000c, 2002a, 2003) es timates of materials generated, discarded, and combusted carry considerable uncertainty associated with the material flows methodology used to generate them. Similarly, the BioCycle (Glenn 1999, Goldstein and Matdes 2000, Goldstein and Matdes 2001, Kaufman et al. 2004) estimate of total waste combustion

⎯ used for the N 2 O emissions estimate

⎯ is based on a survey of state officials, who use differing definitions of solid waste and who draw from a variety of sources of varying reliability and accuracy. The survey methodology changed signi ficantly and thus the results reported for 2002 are not directly comparable to the earlier results (Kaufman et al. 2004), introducing further uncertainty. Despite the differences in methodology and data sources, the two references

⎯ the EPA’s Office of Solid Waste (EPA 2000a, 2002b, 2003) and the BioCycle series

⎯ provide estimates of total solid waste combusted that are relatively consistent (see Table 3-48).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 110 Table 3-48: U.S. Municipal Solid Waste Combusted, as Reported by EPA and BioCycle (Metric Tons)

Year EPA BioCycle 1990 28,855,809 30,632,057 1991 27,773,783 25,462,836 1992 29,568,442 29,113,518 1993 28,696,188 27,838,884 1994 29,532,844 29,291,583 1995 32,182,194 29,639,040 1996 32,831,450 29,707,171 1997 33,597,844 27,798,368 1998 31,205,358 25,489,893 1999 30,859,134 24,296,249 2000 30,512,946 25,974,978 2001 30,569,746 29,694,205 a 2002 NA 33,643,954 2003 NA NA NA (Not Available)

a Interpolated between 2000 and 2002 values.

• Fraction Oxidized. Another source of uncertainty for the CO 2 emissions estimate is fraction oxidized. Municipal waste combustors vary consid erably in their efficiency as a func tion of waste type, moisture content, combustion conditions, and other factors. Despite this variability in oxidation rates, a value of 98 percent was assumed for this analysis.

• Missing Data on Municipal Solid Waste Composition. Disposal rates have been inte rpolated when there is an incomplete interval within a time series. Where data are not available for years at the end of a time series (1990, 2003), they are set equal to the most r ecent years for which estimates are available.

• Average Carbon Contents. Average carbon contents were applied to the mass of “Other” plastics combusted, synthetic rubber in tires and municipal solid waste, and synthetic fibers. These average values were estimated from the average carbon content of the known products recently produced. The tr ue carbon content of the combusted waste may differ from this estimate depending on differences in the chem ical formulation between the known and unspecified materials, a nd differences between the composition of the material disposed and that produced. For rubber, this uncertainty is probably small since the major elastomers’ carbon contents range from 77 to 91 percent; for plastics, where carbon contents range from 29 to 92 percent, it may be more significant. Overall, this is a small source of uncertainty.

• Synthetic/Biogenic Assumptions. A portion of the fiber and rubber in municipal solid waste is biogenic in origin. Assumptions have been made concerning the a llocation between synthetic and biogenic materials based primarily on expert judgment.

• Combustion Conditions Affecting N 2 O Emissions. Because insufficient data exis t to provide detailed estimates of N 2 O emissions for individual combustion facilities, the estimates presented exhibit high uncertainty. The emission factor for N 2 O from municipal solid waste combustion facilities used in the analysis is an average of default values used to estimate N 2 O emissions from facilities worldw ide (Johnke 1999, UK: Environment Agency 1999, Yasuda 1993). These factors span an orde r of magnitude, reflecting c onsiderable variability in the processes from site to site. Due to a lack of information on the control of N 2 O emissions from MSW combustion facilities in the United States, the estimate of zero percent for N 2 O emissions control removal efficiency also exhibits uncertainty.



### Recalculations Discussion

The N 2 O emissions estimates for 2001 and 2002 are slightly differe nt from those reported in last year’s inventory because newly-available data (Kaufman et al. 2004) were used for the tonnage of waste burned in municipal solidInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 111 waste combustion for those years. The change resulted in 2001 and 2002 N 2 O emissions from municipal solid waste combustion that increas ed by less than 0.1 Tg CO 2 Eq. (14.7 percent and 26.4 percent, respectively).

The NO x , CO, and NMVOC emissions estimates for 1999 through 2002 also vary slightly from last year’s inventory due to revised criteria pollutant data from EPA. Th e change constituted less than a 1687 Gg decrease in NO x , CO, and NMVOC emissions in 2002.



### 3.10. Natural Gas Flaring and Ambient Ai r Pollutant Emissions from Oil and Gas Activities (IPCC Source Category 1B2)

The flaring of natural gas from on- and o ff-shore oil wells is a small source of CO 2 . In addition, oil and gas activities also release small amounts of NO x , CO, and NMVOCs. This source accounts for only a small proportion of overall emissions of each of these gases. Emissions of NO x , and CO from petroleum and natural gas production activities were both less than 1 percent of national totals, while NMVOC and SO 2 emissions were roughly 2 percent of national totals.

The flaring (i.e. combustion) and venting of natural ga s during petroleum production result in the release of CO 2 and CH 4 emissions, respectively. Barns and Edmonds (1990) noted that of total reported U.S. venting and flaring, approximately 20 percent may be vented, with the remaining 80 percent flared, but it is now believed that flaring accounts for an even greater proportion. Studies indicate thatthe percentage of natural gas that is flared from offshore U.S. production is considerably lower (approximately 30 percent in 2003), due in part to differences in the legislation governing on- and off-shore natural gas production. Meth ane emissions from venting are accounted for in the Petroleum Systems source category. For 2003, total CO 2 emissions from flaring activities were estimated to be 5.9 Tg CO 2 Eq. (5,970 Gg), an increase of 3 percent from 1990 levels. On-shore flaring activities accounted for 5.7 Tg CO 2 Eq. (5,743 Gg), or 96 percent, of the total flari ng emissions, while off-shore flaring constituted 0.2 Tg CO 2 Eq. (227 Gg), or 4 percent, of the total (see Table 3-49).

Table 3-49: CO 2 Emissions from On-Shore and Off-S hore Natural Gas Flaring (Tg CO 2 Eq.) 1990 1997 1998 1999 2000 2001 2002 2003 On-Shore Flaring 5.5 7.6 6.3 6.7 5.5 5.9 6.0 5.7 Off-Shore Flaring 0.3 0.3 0.3 0.3 0.2 0.2 0.2 0.2 Total Flaring 5.8 7.9 6.6 7.0 5.8 6.1 6.2 5.9 Note: Totals may not sum due to independent rounding.
Table 3-50: CO 2 Emissions from On-Shore and Off-S hore Natural Gas Flaring (Gg) 1990 1997 1998 1999 2000 2001 2002 2003 On-Shore Flaring 5,514 7,565 6,250 6,679 5,525 5,858 6,006 5,743 Off-Shore Flaring 296 309 316 264 244 236 227 227 Total Flaring 5,810 7,874 6,566 6,943 5,769 6,094 6,233 5,970 Note: Totals may not sum due to independent rounding. In addition, oil and gas activities, including production, tran sportation, and storage, result in the release of small amounts of NO x , CO, and NMVOCs. Ambient air pollutant emissions from this source from 1990 to 2003 are presented below (see Table 3-51).

Table 3-51: NO x , NMVOCs, and CO Emissions from Oil and Gas Activities (Gg)

Year NO x CO NMVOCs 1990 139 302 555

1996 126 321 433 1997 130 333 442 1998 130 332 440 1999 109 145 414 2000 111 146 389 2001 113 147 400Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 112 2002 135 116 340 2003 124 125 345



### Methodology

Estimates of CO 2 emissions from on- and off-shore natural gas flari ng were prepared using an emission factor of 54.71 Tg CO 2 Eq./QBtu of flared gas, and an assumed flaring efficiency of 100 percent. Ambient air pollutant emission estimates for NO x , CO, and NMVOCs were determined usi ng industry-published production data and applying average emission factors.

Total on-shore natural gas vented and flared was taken from EIA’s Natural Gas Annual (EIA 2004); however, there is a discrepancy in the time series. One facility in Wyoming had been incorrectly reporting CO 2 vented as CH 4 . EIA noted and corrected these data in the Natural Gas Annual 2000 (EIA 2001) for the years 1998 and 1999 only. Data for 1990 through 1997 were adjusted by assuming a proportionate share of CO 2 in the flare gas for those years as for 1998 and 1999. The adjusted values are provided in Ta ble 3-52. It was assumed that all reported vented and flared gas was flared. This assumption is consistent with that used by EIA in prep aring their emission estimates, under the assumption that many states require flaring of natural gas (EIA 2000b). The emission and thermal conversion factors were also provided by EIA (2001) and are included in Table 3-52.

The total off-shore natural gas vented and flared was obtained from the Minerals Ma nagement Service’s OGOR-B reports (MMS 2003). The percentage of natural gas flar ed was estimated using data from a 1993 air quality study and emissions inventory of the Gulf of Mexico (MOADS) and a 2000 emissions inventory conducted for the Breton National Wilderness Area Management Plan (BOADS). See Table 3-53

Emission estimates for NO x , CO, and NMVOCs from petroleum refining, petroleum product storage and transfer, and petroleum marketing operations were obtained from preliminary data (EPA 2003), which, in its final iteration, will be published on the National Emission Inventory (NEI) Air Pollutant Emission Tre nds web site. Included are gasoline, crude oil and distillate fuel oil storage and transfer operations, gasoline bulk terminal and bulk plants operations, and retail gasoline service stations operations.

Table 3-52: Total Natural Gas Reported Vented and Flared (Million Ft 3 ) and Thermal Conversion Factor (Btu/Ft 3 )

Year Vented and Flared (original) Vented and Flared (revised) * Thermal Conversion Factor 1990 150,415 91,130 1,105 1991 169,909 92,207 1,108 1992 167,519 83,363 1,110 1993 226,743 108,238 1,106 1994 228,336 109,493 1,105 1995 283,739 144,265 1,106 1996 272,117 135,709 1,109 1997 256,351 124,918 1,107 1998 103,019 103,019 1,109 1999 110,285 110,285 1,107 2000 91,232 91,232 1,107 2001 96,913 96,913 1,105 2002 99,173 99,173 1,107 2003 94,929 94,929 1,106

* Wyoming venting and flaring estimates were re vised. See text for further explanation. Table 3-53: Volume Flared Offshore (MMcf) and Fraction Vented and Flared (Percent) 1990 1997 1998 1999 2000 2001 2002 2003 Total Gulf of Mexico (GOM)

Vented & Flared (MMcf) 13,610 15,440 16,280 14,057 12,971 12,990 12,487 12,487Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 113 Estimated Flaring Fraction of GOM

Vented & Flared 36% 33% 32% 31% 31% 30% 30% 30% Total 4,900 5,095 5,210 4,358 4,021 3,897 3,746 3,746



### Uncertainty

Uncertainties in CO 2 emission estimates primarily arise from assumpti ons concerning the flari ng efficiency and the correction factor applied to 1990 through 1997 venting and flaring data. Uncertainties in ambient air pollutant emission estimates are partly due to the accuracy of the emission factors used and projections of growth.



### Recalculations Discussion

The historical data for natural gas flaring was adjusted slightly, which resulted in an average annual increase in CO 2 emissions from flaring of 0.1 Tg CO 2 Eq. (2.3 percent) for the period 1990 through 2002.



### 3.11. International Bunker Fuels (IPCC Source Category 1: Memo Items)

Emissions resulting from the combustion of fuels used for international transport activities, termed international bunker fuels under the UNFCCC, are currently not included in national emission totals, but are reported separately based upon location of fuel sales. The decision to re port emissions from international bunker fuels separately, instead of allocating them to a par ticular country, was made by the Inte rgovernmental Negotiating Committee in establishing the Framework Convention on Climate Change. 52 These decisions are reflected in the Revised 1996 IPCC Guidelines , in which countries are requested to report emissions from ships or aircraft that depart from their ports with fuel purchased within national boundaries and are engaged in international transport separately from national totals (IPCC/UNEP/OECD/IEA 1997). 53

Greenhouse gases emitted from the combustion of internati onal bunker fuels, like other fossil fuels, include CO 2 , CH 4 , N 2 O, CO, NO x , NMVOCs, particulate matter, and SO 2 . 54 Two transport modes are addressed under the IPCC definition of international bunker fuels: aviation and marine. 55 Emissions from ground transport activities

⎯ by road vehicles and trains

⎯ even when crossing international borders are allocated to the country where the fuel was loaded into the vehicle and, therefore, are not counted as bunker fuel emissions.

The IPCC Guidelines distinguish between different modes of air traffic. Civil aviation comprises aircraft used for the commercial transport of passengers and freight, military aviation comprises aircraft under the control of national armed forces, and general aviation applies to recreational a nd small corporate aircraft. The IPCC Guidelines further define international bunker fuel use from civil aviation as the fuel combusted for civil (e.g., commercial) aviation purposes by aircraft arriving or depar ting on international flight segments. However, as mentioned above, and in keeping with the IPCC Guidelines, only th e fuel purchased in the United States and used by aircraft taking-off (i.e.,

52 See report of the Intergovernmental Negotiating Committee fo r 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. 1c). 53 Note that the definition of international bunker fuels used by the UNFCCC differs from that used by the International Civil Aviation Organization. 54 Sulfur dioxide emissions from jet aircra ft and marine vessels, although not estimated here, are mainly determined by the sulfur content of the fuel. In the United States, jet fuel, dis tillate diesel fuel, and residual fuel oil average sulfur conten ts of 0.05, 0.3, and 2.3 percent, respectively. These percen tages are generally lower than global averages. 55 Most emission related international avia tion and marine regulations are under the r ubric of the International Civil Aviation Organization (ICAO) or the International Maritime Organizati on (IMO), which develop interna tional codes, recommendations, and conventions, such as the International Conventi on of the Prevention of Pollution from Ships (MARPOL).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 114 departing) from the United States are reported here. The st andard fuel used for civil aviation is kerosene-type jet fuel, while the typical fuel used for general aviation is aviation gasoline. 56

Emissions of CO 2 from aircraft are essentia lly a function of fuel use. Methane, N 2 O, CO, NO x , 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 th e product of incomplete combustion and occur mainly during the landing and take-off phases. In jet engines, N 2 O and NO x are primarily produced by the oxidation of atmospheric nitrogen, and the majority of emissions occur during the cruise phase. The impact of NO x on atmospheric chemistry depends on the altitude of the actual emission. The cruising altitude of supersonic aircraft, near or in the ozone layer, is higher than that of subsonic aircraft. At this higher altitude, NO x emissions contribute to stratospheric ozone depletion. 57 At the cruising altitudes of subsonic aircraft, however, NO x emissions contribute to the formation of tropospheric ozone. At these lower a ltitudes, the positive radiative fo rcing effect of ozone has enhanced the anthropogenic greenhouse gas forcing. 58 The vast majority of aircraft NO x emissions occur at these lower cruising altitudes of commerc ial subsonic aircraft (NASA 1996). 59

International marine bunkers comprise emissions from fuels burned by ocean -going ships of all flags that are engaged in international transport. Ocean-going ships are generally classi fied as cargo and passenger carrying, military (i.e., Navy), fishi ng, and miscellaneous support ships (e.g., tugboats). For the purpose of estimating greenhouse gas emissions, international bunker fuels are so lely related to cargo and passenger carrying vessels, which is the largest of the four categories, and military vessels. Two main types of fuels are used on sea-going vessels: distillate diesel fuel and residual fuel oil. Carbon dioxide is the primary greenhouse gas emitted from marine shipping. In comparison to aviation, the atmospheric impacts of NO x from shipping are relatively minor, as the emissions occur at ground level.

Overall, aggregate greenhouse gas emissions in 2003 from the combustion of international bunker fuels from both aviation and marine activities were 85.1 Tg CO 2 Eq., or 26 percent below emissions in 1990 (see Table 3-54). Although emissions from international flights departing from the United States have increased significantly (29 percent), emissions from international shipping voyages de parting the United States have decreased by 63 percent since 1990. The majority of these emissions were in the form of CO 2 ; however, small amounts of CH 4 and N 2 O were also emitted. Emissions of NO x by aircraft during idle, take-off, landing and at cruising altitudes are of primary concern because of their effects on gr ound-level ozone formation (see Table 3-55).

Table 3-54: Emissions from International Bunker Fuels (Tg CO 2 Eq.) Gas/Mode 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 113.5 109.9 114.6 105.3 101.4 97.9 89.5 84.2

Aviation 46.2 55.9 56.7 58.9 60.5 59.4 61.8 59.6 Marine 67.3 54.0 57.9 46.4 40.9 38.5 27.7 24.6 CH 4 0.2 0.1 0.2 0.1 0.1 0.1 0.1 0.1

Aviation + + + + + + + + Marine 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 N 2 O 1.0 1.0 1.0 0.9 0.9 0.9 0.8 0.8

Aviation 0.5 0.5 0.6 0.6 0.6 0.6 0.6 0.6 Marine 0.5 0.4 0.4 0.4 0.3 0.3 0.2 0.2 Total 114.6 111.0 115.7 106.4 102.4 98.9 90.4 85.1 + Does not exceed 0.05 Tg CO 2 Eq.

56 Naphtha-type jet fuel was used in the past by the military in turbojet and turboprop aircraft engines. 57 Currently there are only around a dozen civilian supersonic aircra ft in service around the world that fly at these altitudes, however. 58 However, at this lower altitude, ozone does little to shield the earth from ultraviolet radiation. 59 Cruise altitudes for civilian subsoni c aircraft generally range from 8.2 to 12.5 km (27,000 to 41,000 feet).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 115 Note: Totals may not sum due to independent roundi ng. Includes aircraft cruise altitude emissions.

Table 3-55: Emissions from International Bunker Fuels (Gg) Gas/Mode 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 113,503 109,858 114,557 105,294 101,404 97,865 89,489 84,193

Aviation 46,230 55,899 56,657 58,865 60,545 59,388 61,787 59,558 Marine 67,272 53,960 57,900 46,429 40,859 38,477 27,701 24,635 CH 4 8 7 7 6 6 5 4 4

Aviation 1 2 2 2 2 2 2 2 Marine 7 5 6 5 4 4 3 2 N 2 O 3 3 3 3 3 3 3 2

Aviation 1 2 2 2 2 2 2 2 Marine 2 1 1 1 1 1 1 1 CO 115 124 127 124 124 120 118 113

Aviation 76 92 93 97 100 98 102 98 Marine 39 32 34 27 24 23 16 15 NO x 1,985 1,668 1,778 1,478 1,334 1,266 988 900

Aviation 182 221 224 233 240 235 245 236 Marine 1,803 1,446 1,554 1,245 1,095 1,031 743 664 NMVOC 59 52 55 48 44 42 35 32

Aviation 11 14 14 15 15 15 15 15 Marine 48 38 41 33 29 27 20 18 Note: Totals may not sum due to independent roundi ng. Includes aircraft cruise altitude emissions.



### Methodology

Emissions of CO 2 were estimated by applying of carbon content and fraction oxidized factors to fuel consumption activity data. This approach is analogous to that described under CO 2 from Fossil Fuel Combustion. Carbon content and fraction oxidized factors for jet fuel, distillate fuel oil, and residual fuel oil were taken directly from the EIA and are presented in Annex 2.1, Annex 2.2, and Annex 3.7. Heat content and dens ity conversions were taken from EIA (2004) and USAF (1998). A complete description of the methodology and a listing of the various factors employed can be found in Annex 2.1. See Annex 3.7 for a specific discussion on the methodology used for estimating emissions from international bunker fuel use by the U.S. military.

Emission estimates for CH 4 , N 2 O, CO, NO x , and NMVOCs were calculated by multiplying emission factors by measures of fuel consumption by fuel type and mode. Emission factors used in the calculations of CH 4 , N 2 O, CO, NO x , and NMVOC emissions were obtained from the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). For aircraft emissions, the following values, in units of grams of pollutant per kilogram of fuel consumed (g/kg), were employed: 0.09 for CH 4 , 0.1 for N 2 O, 5.2 for CO, 12.5 for NO x , and 0.78 for NMVOCs. For marine vessels consuming either distillate diesel or residual fuel oil the following values, in the same units, except where noted, were employed: 0.32 for CH 4 , 0.08 for N 2 O, 1.9 for CO, 87 for NO x , and 0.052 g/MJ for NMVOCs. Activity data for aviation included solely jet fuel consumption statistics, while the marine mode included both distillate diesel and residual fuel oil.

Activity data on aircraft fuel consumption were collected from three government agencies. Jet fuel consumed by U.S. flag air carriers for international flight segments was supplied by the Bureau of Transportation Statistics (DOT 1991 through 2004). It was assumed that 50 percent of the fu el used by U.S. flagged carriers for international flights

⎯ both departing and arriving in the United States

⎯ was purchased domestically for flights departing from the United States. In other words, only one-half of the total annual fuel consumption estimate was used in the calculations. Data on jet fuel expenditures by foreign flagged carriers departing U.S. airports was taken from unpublished data collected by the Bureau of Economic Analysis (BEA) under the U.S. Department of Commerce (BEA 1991 through 2004). Approximate average fuel prices paid by air carriers for aircraft on international flights was taken from DOT (1991 through 2004) and used to convert the BEA expenditure data to gallons of fuel consumed. Data on U.S. Department of Defense (DoD) aviation bunker fuels and total jet fuel consumed by theInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 116 U.S. military was supplied by the Office of the Under Secr etary of Defense (Installations and Environment), DoD. Estimates of the percentage of each Se rvices’ total operations that were inte rnational operations were developed by DoD. Military aviation bunkers include d international operations, operations conducted from naval vessels at sea, and operations conducted from U.S. insta llations principally over international water in direct support of military operations at sea. Military aviation bunker fuel emissions were estimated us ing military fuel and operations data synthesized from unpublished data by the Defense Energy Support Center, under DoD’s Defense Logistics Agency (DESC 2004). Together, the data allow the quantity of fuel us ed in military international operations to be estimated. Densities for each jet fuel type were obtained from a report from the U.S. Ai r Force (USAF 1998). Final jet fuel consumption estimates are presented in Table 3-56. See Annex 3.7 for additional discussion of military data.

Activity data on distillate diesel and residual fuel oil consumption by cargo or passenger carrying marine vessels departing from U.S. ports were taken from unpublished data collected by the Foreign Trade Division of the U.S. Department of Commerce’s Bureau of the Census ( DOC 1991 through 2004). Activity data on distillate diesel consumption by military vessels depar ting from U.S. ports were provided by DESC (2004). The total amount of fuel provided to naval vessels was reduced by 13 percen t to account for fuel used while the vessels were notunderway (i.e., in port). Data on the percentage of steaming hours underway versus not-underway were provided by the U.S. Navy. These fuel consumpti on estimates are presented in Table 3-57.

Table 3-56: Aviation Jet Fuel Consumption for International Transport (Million Gallons) Nationality 1990 1997 1998 1999 2000 2001 2002 2003 U.S. Carriers 1,954 2,457 2,462 2,625 2,737 2,619 2,495 2,418 Foreign Carriers 2,051 2,939 3,009 3,093 3,166 3,118 3,537 3,388 U.S. Military 862 496 502 488 480 524 482 473 Total 4,867 5,892 5,973 6,206 6,384 6,261 6,515 6,280 Note: Totals may not sum due to independent rounding.

Table 3-57: Marine Fuel Consumption for International Transport (Million Gallons) Fuel Type 1990 1997 1998 1999 2000 2001 2002 2003 Residual Fuel Oil 4,781 3,843 3,974 3,272 2,967 2,846 1,937 1,597 Distillate Diesel Fuel & Other 617 421 627 308 290 204 158 137 U.S. Military Naval Fuels 522 484 518 511 329 318 348 459 Total 5,920 4,748 5,119 4,091 3,586 3,368 2,443 2,193 Note: Totals may not sum due to independent rounding.



### Uncertainty

Emission estimates related to the consumption of international bunker fuels are subject to the same uncertainties as those from domestic aviation and marine mobile combustion emissions; however, additional uncertainties result from the difficulty in collecting accurate fuel consumption activity data for inte rnational transport activities separate from domestic transport activities. 60 For example, smaller aircraft on shorte r routes often carry sufficient fuel to complete several flight segments without refueling in order to minimize time spent at the airport gate or take advantage of lower fuel prices at particular airports. This practice, called tankering, when done on international flights, complicates the use of fuel sales data for estimating bunker fuel emissions. Tankering is less common with the type of large, long-range aircraft that make many in ternational flights from the United States, however. Similar practices occur in the marine shipping industry where fuel costs represent a significant portion of overall operating costs and fuel prices vary from port to port, leading to some tankering from ports with low fuel costs.

60 See uncertainty discussions under Carbon Dioxi de Emissions from Fossil Fuel Combustion.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 117 Particularly for aviation, the DOT (1991 through 2004) interna tional flight segment fuel data used for U.S. flagged carriers does not include smaller air carriers and unfortunately defines flights departing to Canada and some flights to Mexico as domestic instead of international. As for the BEA (1991 through 2004) data on foreign flagged carriers, there is some uncertainty as to the average fuel price, a nd to the completeness of the data. It was also not possible to determine what portion of fuel purchased by foreign carriers at U.S. airports was actually used on domestic flight segments; this error, however, is believed to be small. 61

Uncertainties exist with regard to the total fuel used by military aircraft and ships, and in the activity data on military operations and training that were used to estimate percentages of total fuel use reported as bunker fuel emissions. Total aircraft and ship fu el use estimates were developed from DoD records, which document fuel sold to the Navy and Air Force from the Defense Logistics Ag ency. These data may slightly over or under estimate actual total fuel use in aircraft and sh ips because each Service may have procur ed fuel from, and/or may have sold to, traded with, and/or given fuel to other ships, aircraft, govern ments, or other entities. There are uncertainties in aircraft operations and training activity data. Estimates for the quantity of fuel actually used in Navy and Air Force flying activities reported as bunker fuel em issions had to be estimated based on a combination of available data and expert judgment. Estimates of marine bunker fuel emi ssions were based on Navy vessel steaming hour data, which reports fuel used while underway and fuel used while not underway. This approach does not capture some voyages that would be classified as domestic for a commercial vessel. Conversely, emissions from fuel used while not underway preceding an international voyag e are reported as domestic rather than international as would be done for a commercial vessel. There is uncertainty associated with ground fuel estimates for 1997 through 2001. Small fuel quantities may have been used in vehicles or equipment other than that which was a ssumed for each fuel type.

There are also uncertainties in fuel end-uses by fuel-type, em issions factors, fuel densities, diesel fuel sulfur content, aircraft and vessel engine characteristics and fuel efficien cies, and the methodology used to back-calculate the data set to 1990 using the original set from 1995. The data were adjusted for trends in fuel use based on a closely correlating, but not matching, data set. All assumpti ons used to develop the estimate were based on process knowledge, Department and Component data , and expert judgments. The magnitude of the potential errors related to the various uncertainties has not been calculated, but is believed to be small. The uncertainties associated with future military bunker fuel emission estimates coul d be reduced through add itional data collection.

Although aggregate fuel consumption data have been used to estimate emissions from aviation, the recommended method for estimating emissions of gases other than CO 2 in the Revised 1996 IPCC Guidelines is to use data by specific aircraft type (IPCC/UNEP/OECD /IEA 1997). The IPCC also recommends that cruise altitude emissions be estimated separately using fuel consumption data, while landing and take-off (LTO) cycle data be used to estimate near-ground level emissions of gases other than CO 2 . 62

There is also concern as to the reliability of the existing DOC (1991 th rough 2004) data on marine vessel fuel consumption reported at U.S. customs stations due to the significant degree of inter-annual variation.

61 Although foreign flagged air carriers are prevented from providi ng domestic flight services in the United States, passengers may be collected from multiple airports before an aircraft actua lly departs on its international flight segment. Emissions fro m these earlier domestic flight segments should be classified as domestic, not internati onal, according to the IPCC. 62 U.S. aviation emission estimates for CO, NO x , and NMVOCs are reported by EPA’s Na tional Emission Inventory (NEI) Air Pollutant Emission Trends web site, and re ported under the Mobile Combustion section. It should be noted th at these estimates are based solely upon LTO cycles and consequently only capture near ground-level emissions, which are more relevant for air quality evaluations. These estimat es also include both domestic and internationa l flights. Therefore, estimates reported unde r the Mobile Combustion section overe stimate IPCC-define d domestic CO, NO x , 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 aircra ft on domestic flight segments at cruising altitudes. The estimates in Mobile Combustion are also likely to include emissions fro m ocean-going vessels departing from U.S. ports on international voyages.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 118 

### QA/QC and Verification

A source-specific QA/QC plan for international bunker fuels was developed and implemented. This effort included a Tier 1 analysis, as well as portions of a Tier 2 analysis. The Tier 2 procedures that were implemented involved checks specifically focusing on the activity data and emission factor sources and methodology used for estimating CO 2 , CH 4 , and N 2 O from international bunker fuels in the United States. Emission totals for the different sectors and fuels were compared and trends were inves tigated. No corrective actions were necessary.



### Recalculations Discussion

Historical activity data for aviation was slightly revised fo r both U.S. and foreign carriers. These changes were due to revisions to international fuel cost for foreign carriers and in ternational jet fuel consumption for U.S. carriers, provided by DOT (1991 through 2004). These historical data changes resulted in minimal changes to the emission estimates for 1990 through 2002, which averaged to an annual increase in emissions from international bunker fuels of less than 0.1 Tg CO 2 Eq. (0.1 percent) in CO 2 emissions, annual increase of less than 0.1 Tg CO 2 Eq. (less than 0.1 percent) in CH 4 emissions, and annual increase of less than 0.1 Tg CO 2 Eq. (0.1 percent) in N 2 O emissions.



### 3.12. Wood Biomass and Ethanol Cons umption (IPCC Source Category 1A)

The combustion of biomass fuels

⎯ such as wood, charcoal, and wood waste

⎯ and biomass-based fuels

⎯ such as ethanol from corn and woody crops

⎯ generates CO 2 . However, in the long run the CO 2 emitted from biomass consumption does not increase atmospheric CO 2 concentrations, assuming the bi ogenic carbon emitted is offset by the uptake of CO 2 resulting from the growth of new biomass. As a result, CO 2 emissions from biomass combustion have been estimated separately from fossil fuel-based emissions and are not included in the U.S. totals. Net carbon fluxes from changes in biogenic carbon reservoirs in wooded or crop lands are accounted for in the Land-Use Change and Forestry chapter.

In 2003, total CO 2 emissions from the burning of woody biomass in the industrial, residential, commercial, and electricity generation sectors were approximately 201.0 Tg CO 2 Eq. (201,042 Gg) (see Table 3-58 and Table 3-59). As the largest consumer of woody biomass, the indus trial sector was responsible for 71 percent of the CO 2 emissions from this source. The residential sector wa s the second largest emitter, constituting 18 percent of the total, while the commercial and electricity generation sectors accounted for the remainder.

Table 3-58: CO 2 Emissions from Wood Consumption by End-Use Sector (Tg CO 2 Eq.) End-Use Sector 1990 1997 1998 1999 2000 2001 2002 2003 Industrial 135.3 162.4 150.5 152.0 153.6 135.4 143.7 143.1 Residential 59.9 44.6 39.9 42.7 44.7 38.2 32.3 37.0 Commercial 4.0 5.0 5.0 5.4 5.5 4.2 4.3 4.4 Electricity Generation 13.3 14.1 14.1 14.2 13.9 13.0 15.5 16.6 Total 212.5 226.3 209.5 214.3 217.6 190.8 195.8 201.0 Note: Totals may not sum due to independent rounding.

Table 3-59: CO 2 Emissions from Wood Consumption by End-Use Sector (Gg) End-Use Sector 1990 1996 1997 1998 1999 2000 2001 2002 Industrial 135,347 162,447 150,510 152,019 153,559 135,413 143,694 143,084 Residential 59,911 44,650 39,920 42,677 44,685 38,153 32,276 37,019 Commercial 4,037 5,042 4,963 5,394 5,481 4,175 4,319 4,369 Electricity Generation 13,252 14,126 14,097 14,233 13,851 13,034 15,487 16,570 Total 212,547 226,265 209,490 214,323 217,577 190,776 195,775 201,042 Note: Totals may not sum due to independent rounding.

Biomass-derived fuel consumption in the United States c onsisted primarily of ethanol use in the transportation sector. Ethanol is primarily produced from corn grown in the Midwest, and was used mostly in the Midwest andInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 119 South. Pure ethanol can be combusted, or it can be mixe d 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 vehi cles such as buses, or centra lly fueled fleet vehicles. These fuels burn cleaner than gasoline (i.e., lower in NO x and hydrocarbon emissions), and have been employed in urban areas with poor air quality. However, because ethanol is a hydrocarbon fuel, its combustion emits CO 2 . In 2003, the United States consumed an estimated 239 trillion Btus of ethanol, and as a result, produced approximately 15.8 Tg CO 2 Eq. (15,771 Gg) (see Table 3-60) of CO 2 emissions. Ethanol production and consumption has grown steadily every year since 1990, with the exception of 1996 due to short corn supplies and high prices in that year.

Table 3-60: CO 2 Emissions from Ethanol Consumption

Year Tg CO 2 Eq. Gg 1990 4.2 4,155

1997 7.0 6,978 1998 7.7 7,711 1999 8.0 8,017 2000 9.2 9,188 2001 9.7 9,701 2002 11.5 11,473 2003 15.8 15,771 

### Methodology

Woody biomass emissions were estimated by taking U.S. consumption data (EIA 2004) (see Table 3-61), provided in energy units for the industrial, residential, commerc ial, and electric generation sectors, and applying two EIA gross heat contents (Lindstrom 2003). One heat content (16.953114 MMBtu/MT Wood & Wood Waste) was applied to the industrial sector’s consumption, while the other heat content (15.432359 MMBtu/MT Wood & Wood Waste) was applied to the consumption data for the other sectors. An EIA emission factor of 0.434 MT C/MT Wood (Lindstrom 2003) was then applied to the resulting quantities of woody biomass to obtain CO 2 emissions estimates. It was assumed that the woody biomass cont ains black liquor and other wood wastes, has a moisture content of 12 percent, and is converted into carbon dioxide with 100 percent efficiency. The emissions from ethanol consumption were calculated by applying an EIA emission factor of 17.99 Tg C/QBtu (Lindstrom 2003) to U.S. ethanol consumption data that were provi ded in energy units (EIA 2004) (see Table 3-62).

Table 3-61: Woody Biomass Cons umption by Sector (Trillion Btu)

Year Industrial Residential Co mmercial Electricity Generation 1990 1,442 581 39 129

1997 1,731 433 49 137 1998 1,603 387 48 137 1999 1,620 414 52 138 2000 1,636 433 53 134 2001 1,443 370 40 126 2002 1,531 313 42 150 2003 1,524 359 42 161

Table 3-62: Ethanol Consumption

Year Trillion Btu 1990 63

1997 106 1998 117Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 120 1999 122 2000 139 2001 147 2002 174 2003 239



### Uncertainty

It is assumed that the combustion efficiency for woody biomass is 100 percent, which is believed to be an overestimate of the efficiency of wood combustion processes in the United States. Decreasing the combustion efficiency would increase emission estimates. Additionally, the heat content applied to the consumption of woody biomass in the residential, commercia l, and electric power sectors is un likely to be a completely accurate representation of the heat content for all the different ty pes of woody biomass consumed within these sectors. Emission estimates from ethanol production are more certain than estimates from woody biomass consumption due to better activity data collection met hods and uniform combustion techniques.



### Recalculations Discussion

The historical data for wood biomass consumption was adjusted slightly, which resulted in an average annual decrease in emissions from wood biomass and ethanol consumption of 0.3 Tg CO 2 Eq. (0.1 percent) from 1990 through 2002.

[BEGIN BOX]

Box 3-4: Formation of CO 2 through Atmospheric CH 4 Oxidation

Methane emitted to the atmosphere will eventually oxidize into CO 2 , which remains in the atmosphere for up to 200 years. The global warming potential (GWP) of CH 4 , however, does not account for the radiative forcing effects of the CO 2 formation that results from this CH 4 oxidation. The IPCC Guidelines for Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997) do not explicitly reco mmend a procedure for accounting for oxidized CH 4 , but some of the resulting CO 2 is, in practice, included in the inventory estimates because of the intentional “doublecounting” structure for estimating CO 2 emissions from the combustion of fossil fuels. According to the IPCC Guidelines, countries should estimate emissions of CH 4 , CO, and NMVOCs from fossil fuel combustion, but also assume that these compounds eventually oxidize to CO 2 in the atmosphere. This is accomplished by using CO 2 emission factors that do not factor out carbon in the fuel that is released as in the form of CH 4 , CO, and NMVOC molecules. Therefore, the carbon in fossil fuel is intentionally double counted, as an atom in a CH 4 molecule and as an atom in a CO 2 molecule. 63 While this approach does account for the full radiative forcing effect of fossil fuelrelated greenhouse gas emissions, the timing is not accu rate because it may take up to 12 years for the CH 4 to oxidize and form CO 2 . There is no similar IPCC approach to account for the oxidation of CH 4 emitted from sources other than fossil fuel combustion (e.g., landfills, livestock, and coal mining). Methane from biological system s contains carbon that is part of a rapidly cycling biological system, and therefore any carbon created from oxidized CH 4 from these sources

63 It is assumed that 100 percent of the CH 4 emissions from combustion sources are accounted for in the overall carbon emissions calculated as CO 2 for sources using emission factors and carbon mass ba lances. However, it may be the case for some types of combustion sources that the oxidation factors used for calculating CO 2 emissions do not accurately account for the full mass of carbon emitted in gaseous form (i.e., partially oxidized or still in hydrocarbon form).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 121 is matched with carbon removed from the atmosphere by biological systems

⎯ likely during the same or subsequent year. Thus, there are no additional radiative forcing effects from the oxidation of CH 4 from biological systems. For example, the carbon content of CH 4 from enteric fermentation is derived from plant matter, which itself was created through the conversion of atmospheric CO 2 to organic compounds.

The remaining anthropogenic sources of CH 4 (e.g., fugitive emissions from coal mining and natural gas systems, industrial process emissions) do increase the long-term CO 2 burden in the atmosphere, and this effect is not captured in the inventory. The following tables provide estimates of the equivalent CO 2 production that results from the atmospheric oxidation of CH 4 from these remaining sources. The estimates for CH 4 emissions are gathered from the respective sections of this report, and are presented in Table 3-63. The CO 2 estimates are summarized in Table 3-64.

Table 3-63: CH 4 Emissions from Non-Combustion Fossil Sources (Gg) Source 1990 1997 1998 1999 2000 2001 2002 2003 Coal Mining 3,900 2,983 2,989 2,805 2,677 2,647 2,497 2,561 Abandoned Coal Mines 288 385 341 349 369 331 303 306 Natural Gas Systems 6,112 6,363 6,276 6,066 6,289 6,277 6,221 5,998 Petroleum Systems 951 895 879 848 836 831 815 815 Petrochemical Production 56 78 80 81 80 68 72 72 Silicon Carbide Production 1 1 1 1 1 + + +

Iron and Steel Production 63 60 57 56 57 51 48 49 Total 11,371 10,765 10,622 10,205 10,308 10,206 9,956 9,801 Note: These emissions are accounted for under their respective source categories. Totals may not sum due to independent rounding.
Table 3-64: Formation of CO 2 through Atmospheric CH 4 Oxidation (Tg CO 2 Eq.) Source 1990 1997 1998 1999 2000 2001 2002 2003 Coal Mining 10.7 8.2 8.2 7.7 7.4 7.3 6.9 7.0 Abandoned Coal Mines 0.8 1.1 0.9 1.0 1.0 0.9 0.8 0.8 Natural Gas Systems 16.8 17.5 17.3 16.7 17.3 17.3 17.1 16.5 Petroleum Systems 2.6 2.5 2.4 2.3 2.3 2.3 2.2 2.2 Petrochemical Production 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 Silicon Carbide Production + + + + + + + + Iron and Steel Production 0.2 0.2 0.2 0.2 0.2 0.1 0.1 0.1 Total 31.3 29.6 29.2 28.1 28.3 28.1 27.4 27.0 Note: Totals may not sum due to independent rounding. + Does not exceed 0.05 Tg CO 2 Eq.
The estimates of CO 2 formation are calculated by applying a factor of 44/16, which is the ratio of molecular weight of CO 2 to the molecular weight of CH 4 . For the purposes of the calculation, it is assumed that CH 4 is oxidized to CO 2 in the same year that it is emitted. As discusse d above, this is a simplifi cation, because the average atmospheric lifetime of CH 4 is approximately 12 years.

Carbon dioxide formation can also result from the oxidation of CO and NMVOCs. However, the resulting increase of CO 2 in the atmosphere is explicitly included in the mass balance used in calculating the storage and emissions from non-energy uses of fossil fuels, with the carbon components of CO and NMVOC counted as CO 2 emissions in the mass balance. 64

[END BOX]

64 See Annex 2.3 for a more detailed discussion on acc ounting for indirect emissions from CO and NMVOCs.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 122Fi g ure 3-1: 2003 Ener gy Sector Greenhouse Gas Sources 5,551.6

0 20 40 60 80 100 120 140 Natural Gas Flaring Petroleum Systems Waste Combustion Stationary Sources Coal Mining Mobile Sources Natural Gas Systems Fossil Fuel Combustion

Tg CO 2 Eq. Energy as a Portion

of all Emissions

86.6%Figure 3-3: 2003 U.S. Energy Consumption by Energy Source

Figure 3-4: U.S. Energy Consumption (Quadrillion Btu) Note: Expressed as gross calorific values. 6.1% Renewable

8.0% Nuclear

22.8% Coal

39.1% Petroleum 22.5% Natural Gas

Fossil Fuels Total Energy

Renewable & Nuclear

0 20 40 60 80 100 120

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Energy Consumption (QBtu)Figure 3-5: 2003 CO 2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type Note: The electricity generation sector also includes emissions of less than 0.01 Tg CO 2 Eq. from g eothermal-based electricit y g eneration 0 500 1,000 1,500 2,000ResidentialCommercialIndustrialTransportationElectricityGenerationU.S.TerritoriesTg CO2Eq Natural Gas
Petroleum
Coal Relative Contribution by Fuel TypeFi g ure 3-6. Annual Deviations from Normal Heatin g De g ree Da y s for the United States ( 1949-2003 ) Note: Climatolo g ical normal data are hi g hli g hted. Statistical confidence interval for "normal" climatolo gy period of 1961 throu g h 1990.

Fi g ure 3-7: Annual Deviations from Normal Coolin g De g ree Da y s for the United States ( 1949-2003 ) Note: Climatolo g ical normal data are hi g hli g hted. Statistical confidence interval for "normal" climatolo gy period of 1961 throu g h 1990. 99% Confidence

-15 -10 -5 0 5 10 15

1950 1954 1958 1962 1966 1970 1974 1978 1982 1986 1990 1994 1998 2002Index Normal = 100(Deviation from Normal) Normal (4,576 Heating Degree Days)

99% Confidence

-20 -10

0 10 20

1950 1954 1958 1962 1966 1970 1974 1978 1982 1986 1990 1994 1998 2002Index Normal = 100(Deviation from Normal)

N lFi g ure 3-8: A gg re g ate Nuclear and H y droelectric Power Plant Capacit y Factors in the United States ( 1973-2003 )

Figure 3-9: 2003 End-Use Sector Emissions of CO 2 from Fossil Fuel Combustion

Fi g ure 3-10: Motor Gasoline Retail Prices ( Real ) Cents per Gallon

Cents per VMT

75 80 85 90 95 100 105 110

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Index (1990 = 100) 0 200 400 600 800 1000 1200 1400 1600 1800 2000

R

e s i d e n t i a l
C o m

m

e r c i a l

I n d

u s t r i a l

T

r a n s p o r t a t i o n

U

.

S

. T e r r i t o r i e sTg CO2Eq From Electricity Consumption From Direct Fossil Fuel Combustion Nuclear Hydro

0 20 40 60 80 1001973197519771979198119831985198719891991199319951997199920012003Capacity FactorFi g ure 3-11: Motor Vehicle Fuel Efficienc y Passenger Cars

All Motor Vehicles

14 16 18 20 22 24

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Miles per GallonFi g ure 3-12: Industrial Production Indexes ( Index 1997=100 ) Primary Metals Petroleum Refineries

70 90 11019901991199219931994199519961997199819992000200120022003 Paper Foods

80 100 120

70 90 110 130 Total excluding Computers, Communications Equip., and Semiconductors Total Industrial Index

Chemicals

70 90 110

Stone, Clay & Glass ProductsFi g ure 3-13: Heatin g De g ree Da y s Note: Excludes Alaska and Hawaii

Fi g ure 3-14: Coolin g De g ree Da y s Note: Excludes Alaska and Hawaii

Fi g ure 3-15: Electric Generation Retail Sales b y End-Use Secto r Note: The transportation end-use sector consumes minor quanties of electricit y

. R

e s i d e n t i a l

C

o m

m

e r c i a l I n

d

u s t r i a l

400 600 800 1,000 1,200 1,400

1973 1978 1983 1988 1993 1998 2003Billion Kwh 80 90 100 110 12019901991199219931994199519961997199819992000200120022003Index (Normal = 100) Normal ( 5

, 424 Heatin g De g ree Da y s )

80 90 100 110 12019901991199219931994199519961997199819992000200120022003Index (Normal = 100) Normal ( 1

, 215 Coolin g De g ree Da y s )Figure 3-16: U.S. Energy Consumption and Energy-Related CO 2 Emissions Per Capita and Per Dollar GDP

Figure 3-17: Mobile Source CH 4 and N 2 O Emissions CH 4 N 2 O

0 10 20 30 40 50 60

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Tg CO2Eq. CO 2 /Energy Consumption CO 2 /capita

CO 2 /$GDP

75 79 83 87 91 95 99 103

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003Index (1990 = 100)

Energy Consumption/$GDP Energy Consumption/ capitaInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 123 

## 4. Industrial Processes

Greenhouse gas emissions are produced as a by-product of va rious non-energy-related industrial activities. That is, these emissions are produced from an industrial process its elf and are not directly a result of energy consumed during the process. For example, raw materials can be ch emically transformed from one state to another. This transformation can result in the release of greenhouse gases such as carbon dioxide (CO 2 ), methane (CH 4 ), or nitrous oxide (N 2 O). The processes addressed in this chapter include iron and steel production, cement manufacture, ammonia manufacture and urea application, lime manufacture, limestone and dolomite use (e.g., flux stone, flue gas desulfurization, and glass manufacturing), soda ash manufacture and use, titanium dioxide production, phosphoric acid production, ferroalloy production, CO 2 consumption, aluminum production, petrochemical production, silicon carbide production, nitric acid production, and adipic acid production (see Figure 4-1).

Figure 4-1: 2003 Industrial Processes Chapter Greenhouse Gas Sources

In addition to the three greenhouse gases listed above, there are also industrial sources of man-made fluorinated compounds called hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF 6 ). The present contribution of these gases to the radiative forcing effect of a ll anthropogenic greenhouse gases is small; however, because of their extremely long lifetimes, many of them will continue to accumulate in the atmosphere as long as emissions continue. In addition, many of these gases ha ve high global warming potentials; SF 6 is the most potent greenhouse gas the IPCC has evaluated. Usage of HFCs for the substitution of ozone depleting substances is growing rapidly, as they are the primary substitutes for ozone depleting substances (ODSs), which are being phased-out under the Montreal Protocol on Substances that Deplete the Ozone Layer . In addition to ODS substitutes, HFCs, PFCs, SF 6 , and other fluorinated compounds are empl oyed and emitted by a number of other industrial sources in the United States. These industries include aluminum production, HCFC-22 production, semiconductor manufacture, electric power transmission and distribution, and magnesium metal production and processing.

In 2003, industrial processes generated emissions of 308.6 teragrams of CO 2 equivalent (Tg CO 2 Eq.), or 4.5 percent of total U.S. greenhouse gas emissions. Carbon di oxide emissions from all industrial processes were 147.2 Tg CO 2 Eq. (147,172 Gg) in 2003. This amount acc ounted for only 2.5 percent of national CO 2 emissions. Methane emissions from petrochemical, silicon carbide, a nd iron and steel production re sulted in emissions of approximately 2.5 Tg CO 2 Eq. (121 Gg) in 2003, which was 0.5 percent of U.S. CH 4 emissions. Nitrous oxide emissions from adipic acid and nitric acid production were 21.8 Tg CO 2 Eq. (71 Gg) in 2003, or 5.8 percent of total U.S. N 2 O emissions. In 2003, combined emissions of HFCs, PFCs and SF 6 totaled 137.0 Tg CO 2 Eq. Overall, emissions from industrial processes increased by 2.9 percent from 1990 to 2003 despite decreases in emissions from several industrial processes, such as iron and steel, electrical transmission and distribution, HCFC-22 production, and aluminum production. The increase in overall emissions was driven by a rise in the emissions originating from cement manufacture and, primarily, the emissions from the use of substitutes for ozone depleting substances.

Table 4-1 summarizes emissions for the Industrial Processes chapter in units of Tg CO 2 Eq., while unweighted native gas emissions in gigagrams (Gg) are provided in Table 4-2.

Table 4-1: Emissions from Industrial Processes (Tg CO 2 Eq.) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 173.1 170.9 169.4 165.9 164.7 151.8 151.5 147.2

Iron and Steel Production 85.4 71.9 67.4 64.4 65.7 58.9 55.1 53.8 Cement Manufacture 33.3 38.3 39.2 40.0 41.2 41.4 42.9 43.0 Ammonia Manufacture & Urea Application 19.3 20.7 21.9 20.6 19.6 16.7 18.6 15.6 Lime Manufacture 11.2 13.7 13.9 13.5 13.3 12.8 12.3 13.0 Limestone and Dolomite Use 5.5 7.2 7.4 8.1 6.0 5.7 5.9 4.7 Aluminum Production 6.3 5.6 5.8 5.9 5.7 4.1 4.2 4.2Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 124 Soda Ash Manufacture and Consumption 4.1 4.4 4.3 4.2 4.2 4.1 4.1 4.1 Petrochemical Production 2.2 2.9 3.0 3.1 3.0 2.8 2.9 2.8 Titanium Dioxide Production 1.3 1.8 1.8 1.9 1.9 1.9 2.0 2.0 Phosphoric Acid Production 1.5 1.5 1.6 1.5 1.4 1.3 1.3 1.4 Ferroalloy Production 2.0 2.0 2.0 2.0 1.7 1.3 1.2 1.4 Carbon Dioxide Consumption 0.9 0.8 0.9 0.8 1.0 0.8 1.0 1.3 CH 4 2.5 2.9 2.9 2.9 2.9 2.5 2.5 2.5

Petrochemical Production 1.2 1.6 1.7 1.7 1.7 1.4 1.5 1.5 Iron and Steel Production 1.3 1.3 1.2 1.2 1.2 1.1 1.0 1.0 Silicon Carbide Production + + + + + + + + N 2 O 33.0 31.5 26.9 25.6 25.6 20.8 23.1 21.8

Nitric Acid Production 17.8 21.2 20.9 20.1 19.6 15.9 17.2 15.8 Adipic Acid Production 15.2 10.3 6.0 5.5 6.0 4.9 5.9 6.0 HFCs, PFCs, and SF 6 91.2 121.7 135.7 134.8 138.9 129.5 138.3 137.0

Substitution of Ozone Depleting Substances 0.4 46.5 56.6 65.8 75.0 83.3 91.5 99.5

HCFC-22 Production 35.0 30.0 40.1 30.4 29.8 19.8 19.8 12.3 Electrical Transmission and Distribution 29.2 21.7 17.1 16.4 15.6 15.4 14.7 14.1 Aluminum Production 18.3 11.0 9.1 9.0 9.0 4.0 5.2 3.8 Semiconductor Manufacture 2.9 6.3 7.1 7.2 6.3 4.5 4.4 4.3 Magnesium Production and Processing 5.4 6.3 5.8 6.0 3.2 2.6 2.6 3.0 Total 299.9 327.1 334.9 329.2 332.1 304.7 315.4 308.6 + Does not exceed 0.05 Tg CO 2 Eq. Note: Totals may not sum due to independent rounding.

Table 4-2: Emissions from Industrial Processes (Gg) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 173,122 170,884 169,425 165,908 164,657 151,835 151,506 147,172

Iron and Steel Production 85,413 71,863 67,428 64,376 65,693 58,887 55,082 53,763 Cement Manufacture 33,278 38,323 39,218 39,991 41,190 41,357 42,898 43,030 Ammonia Manufacture & Urea Application 19,306 20,650 21,934 20,615 19,616 16,719 18,571 15,560

Lime Manufacture 11,238 13,685 13,914 13,466 13,315 12,823 12,304 12,983 Limestone and Dolomite Use 5,533 7,242 7,449 8,057 5,959 5,733 5,885 4,720 Aluminum Production 6,315 5,621 5,792 5,895 5,723 4,114 4,220 4,219 Soda Ash Manufacture and Consumption 4,141 4,354 4,325 4,217 4,181 4,147 4,139 4,082 Petrochemical Production 2,221 2,919 3,015 3,054 3,004 2,787 2,857 2,777 Titanium Dioxide Production 1,308 1,836 1,819 1,853 1,918 1,857 1,997 2,013 Phosphoric Acid Production 1,529 1,544 1,593 1,539 1,382 1,264 1,338 1,382 Ferroalloy Production 1,980 2,038 2,027 1,996 1,719 1,329 1,237 1,374 Carbon Dioxide Consumption 860 808 912 849 957 818 978 1,267 CH 4 120 139 138 138 138 119 120 121

Petrochemical Production 56 78 80 81 80 68 72 72 Iron and Steel Production 63 60 57 56 57 51 48 49 Silicon Carbide Production 1 1 1 1 1 + + + N 2 O 107 102 87 83 83 67 75 70

Nitric Acid Production 58 68 67 65 63 51 56 51 Adipic Acid Production 49 33 19 18 19 16 19 19 HFCs, PFCs, and SF 6 M M M M M M M M

Substitution of Ozone Depleting

Substances M M M M M M M M

HCFC-22 Production a 3 3 3 3 3 2 2 1 Electrical Transmissi on and Distribution b 1 1 1 1 1 1 1 1 Aluminum Production M M M M M M M MInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 125 Semiconductor Manufacture M M M M M M M M Magnesium Production and Processing b + + + + + + + + NO x 591 629 637 595 626 656 630 648 CO 4,124 3,153 3,163 2,156 2,217 2,339 2,308 2,431 NMVOCs 2,426 2,038 2,047 1,813 1,773 1,769 1,725 1,711 + Does not exceed 0.5 Gg M (Mixture of gases)

a HFC-23 emitted b SF 6 emitted Note: Totals may not sum due to independent rounding.

In order to ensure the quality of the emission estimates fro m industrial processes, Tier 1 procedures and checks have been performed on all industrial process sources. If perfo rmed, Tier 2 procedures focused on the emission factor and activity data sources and methodology used for estimating emissions proce dures, and will be described within the QA/QC and Verification Discussion of that source descri ption. In addition to the national QA/QC plan, a more detailed plan was developed specifically for the CO2 and CH4 industrial processes sources. This plan was based on the U.S. strategy, but was tailored to include specific procedures recommended for these sources.

The general method employed to estimate emissions for industrial processes, as recommended by the Intergovernmental Panel on Climate Change (IPCC), involves multiplying pr oduction data (or activity data) for each process by an emission factor per unit of production. The uncertainty of the emission estimates is therefore generally a function of a combination of the uncertainties surrounding the production and emission factor variables. Uncertainty of activity data and th e associated probability density f unctions for industrial processes CO 2 sources were estimated based on expert assessment of available qualitative and quantitative information. Uncertainty estimates and probability density functions for the emission factors used to calculate emissions from this source were devised based on IPCC recommendations.

Activity data is obtained through a survey of manufacturer s conducted by various organizations (specified within each source); the uncertainty of the activity data is a function of the relia bility of plant-level production data and is influenced by the completeness of the survey response. The emission factors used were either derived using calculations that assume precise and efficient chemical reactions, or were based upon empirical data in published references. As a result, uncertainties in the emission coefficients can be attributed to, among other things, inefficiencies in the chemical reactions associated with each production process or to the use of empirically-derived emission factors that are biased; theref ore, they may not represent U.S. national averages. Additional assumptions are described within each source.

The uncertainty analysis performed to quantify uncerta inties associated with the 2003 inventory estimates from industrial processes continues a multi-year process for de veloping credible quantitative uncertainty estimates for these source categories using the IPCC Tier 2 approach. As the process continues, the type and the characteristics of the actual probability density func tions underlying the input variables are identified and better characterized (resulting in development of more relia ble inputs for the model, including accu rate characterization of correlation between variables), based primarily on expert elicitation. Accordingly, the quantitative uncertainty estimates reported in this section should be considered illustrativ e and as iterations of ongoing efforts to produce accurate uncertainty estimates. The correlation among data used for estimating emissions for different sources can influence the uncertainty analysis of each indi vidual source. While the uncertainty analysis recognizes very significant connections among sources, a more comprehensive approach that accounts for all linkages will be identified as the uncertainty analysis moves forward.



### 4.1. Iron and Steel Production (IPCC Source Category 2C1)

In addition to being an energy intensive process, the production of iron and steel also generates process-related emissions of CO 2 and CH 4 . Iron is produced by first reducing iron oxide (iron ore) with metallurgical coke in a blast furnace to produce pig iron (impur e iron containing about 3 to 5 percen t carbon by weight). Metallurgical coke is manufactured in a coke plant using coking coal as a raw material. Iron may be introduced into the blastInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 126 furnace in the form of raw iron ore, pellets, briquettes, or sinter. Pig iron (containi ng about 0.4 percent carbon by weight) is used as a raw material in the production of steel. Pig iron is also used as a raw material in the production of iron products in foundries. The pig iron production process produces CO 2 emissions and fugitive CH 4 emissions.

The production of metallurgical coke from coking coal and the consumption of the metallurgical coke used as a reducing agent in the blast furnace are considered in the inventory to be non-energy (industrial) processes, not energy (combustion) processes. Coal coke is produced by heating coking coal in a coke oven in a low-oxygen environment. The process drives off the volatile compone nts of the coking coal and produces coal coke. Coke oven gas and coal tar are carbon by-products of the coke ma nufacturing process. Coke oven gas is generally burned as a fuel within the steel mill. Coal tar is used as a raw material to produce anodes used for primary aluminum production and other electrolytic processes, and also used in the production of other coal tar products. The coke production process produces CO 2 emissions and fugitive CH 4 emissions.

Sintering is a thermal process by which fine iron-bearing particles, such as air emission control system dust, are baked, which causes the material to agglomerate into roughly one-inch pellets that are then recharged into the blast furnace for pig iron production. Iron ore particles may also be formed into larger pellets or briquettes by mechanical means, and then agglomerat ed by heating prior to being charged into the blast furnace. The sintering process produces CO 2 emissions and fugitive CH 4 emissions.

The metallurgical coke is a reducing agent in the blast furnace. Carbon dioxide is produced as the metallurgical coke used in the blast furnace process is oxidized. St eel (containing less than 2 pe rcent carbon by weight) is produced from pig iron in a variety of speciali zed steel making furnaces. The majority of CO 2 emissions from the iron and steel process come from the use of coke in the production of pig iron, with smaller amounts evolving from the removal of carbon from pig iron used to produce steel. Some carbon is also stored in the finished iron and steel products.

Emissions of CO 2 and CH 4 from iron and steel production in 2003 were 53.8 Tg CO 2 Eq. (53,763 Gg) and 1.0 Tg CO 2 Eq. (48.7 Gg), respectively (see Table 4-3 and Table 4-4). Emissions have fluctuated significantly from 1990 to 2003 due to changes in domestic economic conditions and changes in product imports and exports. In 2003, domestic production of pig iron and coal coke increased by 2.2 and 2.4 percent, respectively. Despite these increases, domestic pig iron and coke production have d eclined since the 1990s. Pig iron production in 2003 was 15 percent lower than in 2000 and 19 percent below 1995 levels. Coke production in 2003 was 17 percent lower than in 2000 and 38 percent below 1990 levels. A slowdown in the domestic and worldwide economy and the availability of low-priced imports limit growth in domestic production (USGS 2002).

Table 4-3: CO 2 and CH 4 Emissions from Iron and Steel Production (Tg CO 2 Eq.) Year 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 85.4 71.9 67.4 64.4 65.7 58.9 55.1 53.8 CH 4 1.3 1.3 1.2 1.2 1.2 1.1 1.0 1.0 Total 86.7 73.1 68.6 65.5 66.9 60.1 56.1 54.8

Table 4-4: CO 2 and CH 4 Emissions from Iron and Steel Production (Gg)

Year 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 85,413 71,863 67,428 64,376 65,693 58,887 55,082 53,763 CH 4 63 60 57 56 58 51 48 49



### Methodology

Since coke is consumed as a reduci ng agent during the manufacture of pig ir on, the corresponding quantity of coal consumed during coking ope rations was identified. This quantity of co al is considered a non-energy use. Data were also collected on the amount of imported coke consumed in the blast furnace process. These data were converted to their energy equivalents. The carbon conten t of the combusted coal and imported coke was estimated by multiplying their energy consump tion by material specifi c carbon-content coefficients. The carbon content coefficients used are presented in Annex 2.1.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 127 Emissions from the re-use of scrap steel and imported pi g iron in the steel production process were calculated by assuming that all the associated carbon-content of these ma terials are released during combustion. Steel has an associated carbon-content of approximately 0.4 percent, while pig iron is assumed to contain 4 percent carbon by weight.

Emissions from carbon anodes, used duri ng the production of steel in electri c arc furnaces (EAF), were also estimated. Emissions of CO 2 were calculated by multiplying the annual production of steel in electric arc furnaces by an emission factor (4.4 kg CO 2 /ton steel EAF ). It was assumed that the carbon anodes used in the production of steel in electric arc furnaces are compos ed of 80 percent petroleum coke and 20 percent coal tar pitch (DOE 1997). Since coal tar pitch is a by-product of the coking process and its carbon-related emissions have already been accounted for earlier in the iron and steel emissions calculation as part of the coking process, the emission factor was reduced by 20 percent to avoid doubl e counting. Additionally, emissions fro m the coal tar pitch component of carbon anodes consumed during the produc tion of aluminum, which are accounted for in the aluminum production section of this chapter, have been subtracted from the total coal tar emissions that were calculated above.

Carbon storage was accounted for by a ssuming that all domestically manufactur ed steel had a carbon content of 0.4 percent. Furthermore, any pig iron that was not consumed during steel production, but fabricated into finished iron products, was assumed to have a by-weight carbon content of 4 percent.

The production processes for coal coke, sinter, and pig iron resu lt in fugitive emissions of CH 4 , which are emitted via leaks in the production equipment rather than through the emission stacks or vents of the production plants. The fugitive emissions were calculated by applying emission factors taken from the 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) (see Table 4-5) to annual domes tic production data for coal coke, sinter, and pig iron.

Table 4-5: CH 4 Emission Factors for Coal Coke, Sinter, and Pig Iron Production (g/kg) Material Produced g CH 4 /kg produced Coal Coke 0.5 Pig Iron 0.9 Sinter 0.5 Source: IPCC/UNEP/OECD/IEA 1997 Data relating to the amount of coal consumed at coke plants, for the production of coke for domestic consumption in blast furnaces, as well as the quantity of coke imported for iron production were taken from the Energy Information Admini stration (EIA), Quarterly Coal Report January through December 2003 (EIA 2004); U.S. Coal Domestic and International Issues (EIA 2001); Mineral Yearbook: Iron and Steel (USGS 1993, 1995a, 1997, 1999, 2000a, 2001a, 2002a) and the American Ir on and Steel Institute (AISI), Annual Statistical Report (AISI 2001, 2002, 2003, 2004). Scrap steel and imported pig iron cons umption data for 1990 through 2003 were obtained from Annual Statistical Reports (AISI 1995, 2001, 2002, 2003, 2004) (see Table 4-6). Crude steel production, as well as pig iron use for purposes other than steel production, was also obtained from Annual Statistical Reports (AISI 1996, 2001, 2002, 2004). Carbon content percentages for pig iron and crude steel and the CO 2 emission factor for carbon anode emissions from steel production were obtained from IPCC Good Practice Guidance and Uncertainty Management (IPCC 2000). Aluminum production data for 1990 through 2003 were obtained from Mineral Industry Surveys: Aluminum Annual Report (USGS 1995b, 1998, 2000b, 2001b, 2002b, 2003, 2004a). Annual consumption of iron ore used in sinter production for 1990 through 2003 were obtained from the USGS Iron Ore yearbook (USGS 1994, 1995c, 1996, 1997b, 1998b, 1999b, 2000c, 2001c, 2002c, 2004b). The CO 2 emission factor for carbon anode emissions from aluminum production was taken from the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). Estimates for the compositi on of carbon anodes used dur ing steel and aluminum production were obtained from Energy and Environmental Profile of the U.S. Aluminum Industry (DOE 1997).

Table 4-6: Production and Consumption Data for the Calculation of CO 2 and CH 4 Emissions from Iron and Steel Production (Thousand Metric Tons) Gas/Activity Data 1990 1997 1998 1999 2000 2001 2002 2003 CO 2

Coal Consumption at Coke Plants 35,289 27,400 25,573 25,499 26,253 23,655 21,460 21,997Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 128 Coke Consumption for Pig Iron 24,946 22,100 19,800 18,700 19,215 17,129 15,850 15,379 Domestic Pig Iron Production for Steel 49,061 48,676 47,470 45,677 47,399 41,740 39,600 40,487 Basic Oxygen Furnace Steel Production 56,227 55,386 54,146 52,364 53,964 47,359 45,463 45,873 Electric Arc Furnace Steel Production 33,517 43,098 44,513 45,063 47,859 42,743 46,124 47,803 CH 4

Coke Production 25,054 20,063 18,181 18,240 18,877 17,190 15,220 15,579 Iron Ore Consumption for Sinter 12,239 11,426 10,791 11,072 10,784 9,234 9,018 8,984 Domestic Pig Iron Production for Steel 49,061 48,676 47,470 45,677 47,399 41,740 39,600 40,487



### Uncertainty

The time series data for production of coal coke, sinter, pig iron, steel, and aluminum and import and export data upon which the calculations are based are considered to be consistent for the entire time series. The estimates of CO 2 emissions from the production and u tilization of coke are based on ener gy consumption data, average carbon contents, and the fraction of carbon oxi dized. These data and factors produ ce a relatively accurate estimate of CO 2 emissions. However, there are uncerta inties associated with each of these factors. For example, carbon oxidation factors may vary depending on inefficiencies in the combus tion process, where varying degrees of ash or soot can remain unoxidized.

Simplifying assumptions were made concerning the com position of carbon anodes (80 percent petroleum coke and 20 percent coal tar). For example, within the aluminum industry, the coal tar pitch content of anodes can vary from 15 percent in prebaked anodes to 24 to 28 percent in S oderberg anode pastes (DOE 1997). An average value was assumed and applied to all carbon anodes utilized during al uminum and steel production. The assumption is also made that all coal tar used during anode production origin ates as a by-product of the domestic coking process. Similarly, it was assumed that all pig iron and crude st eel have carbon contents of 4 percent and 0.4 percent, respectively. The carbon content of pig iron can vary betw een 3 and 5 percent, while crude steel can have a carbon content of up to 2 percent, although it is typically less than 1 percent (IPCC 2000).

There is uncertainty in the most accurate CO 2 emission factor for carbon anode consumption in aluminum production. Emissions vary depending on the specific technol ogy used by each plant (Pre bake or Soderberg). The Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) provide CO 2 emission factors for each technology type. Consistent with the assumptions used in the Aluminum Production source, it was assumed that production was split 80 percent prebake and 20 percent Soderberg fo r the whole time series. Similarly, the carbon anode emission factor for steel production can vary between 3.7 and 5.5 kg CO 2 /ton steel (IPCC 2000). For this analysis, the upper bound value was used.

For the purposes of the CH 4 calculation it is assumed that none of the CH 4 is captured in stacks or vents and that all of the CH 4 escapes as fugitive emissions. Additionally, the CO 2 emissions calculation is not corrected by subtracting the carbon content of the CH 4 , which means there may be a slight double counting of carbon as both CO 2 and CH 4 . The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-7. Iron and Steel CO 2 emissions were estimated to be between 32.0 and 76.4 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indi cates a range of approximately 41 percent below and 42 percent above the emission estimate of 53.8 Tg CO 2 Eq. Iron and Steel CH 4 emissions were estimated to be between 0.9 Tg CO 2 Eq. and 1.1 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 11 percent below and 11 percent above the emission estimate of 1.0 Tg CO 2 Eq.

Table 4-7: Tier 2 Quantitative Uncertainty Estimates for CO 2 and CH 4 Emissions from Iron and Steel Production (Tg. CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 129 Lower Bound Upper Bo und Lower Bound Upper Bound Iron and Steel CO 2 53.8 32.0 76.4 -41% +42% Iron and Steel CH 4 1.0 0.9 1.1 -11% +11%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.



### Recalculations Discussion

Estimates of CO 2 from iron and steel production increased due to revised production data found in American Iron and Steel Institute’s 2003 Annual Statistical Report (AISI 2004) and EIA’s 2003 Quarterly Coal Report (EIA 2004). These changes resulted in an average increase of 0.2 Tg CO 2 Eq. (0.5 percent) in CO 2 emissions from iron and steel production for 2001 and 2002.

Estimates of CH 4 2002 were revised due to revised sinter producti on data provided by the U.S. Geological Survey’s Iron and Steel Report 2003 (USGE 2004b). This change resulted in an increase of less than 0.1 Tg CO 2 Eq. (0.8 percent) in CH 4 emissions from iron and steel production for 2002.



### 4.2. Cement Manufacture (I PCC Source Category 2A1)

Cement manufacture is an energy and raw material intensive process that results in the generation of CO 2 from both the energy consumed in making the cem ent and the chemical process itself. 1 Cement production has accounted for about 2.4 percent of total global industrial and energy-related CO 2 emissions, and the United States is the world’s third largest cement producer (IPCC 1997, USGS 2003). Cement is manufactured in nearly 40 states. Carbon dioxide emitted from the chemical process of cement producti on represents one of the largest sources of industrial CO 2 emissions in the United States.

During the cement production process, calcium carbonate (CaCO 3 ) is heated in a cement k iln at a temperature of about 1,300 o C (2,400 o F) to form lime (i.e., calcium oxide or CaO) and CO 2 . This process is known as calcination or calcining. Next, the lime is combined with silica-containing materials to produce clinker (an intermediate product), with the earlier by-product CO 2 being released to the atmosphere. The cli nker is then allowed to cool, mixed with a small amount of gypsum, and used to make portland cement. The production of masonry cement from portland cement requires additional lime and, thus, results in additional CO 2 emissions. However, this additional lime is already accounted for in the Lime Manuf acture source category in this chapter; therefore, the additional emissions from making masonry cement from clinker are not counted in this source category’s total. They are presented here for informational purposes only.

In 2003, U.S. clinker production

⎯ including Puerto Rico

⎯ totaled 83,214 thousand metric tons (Van Oss 2004). The resulting emissions of CO 2 from 2003 cement production were estimated to be 43.0 Tg CO 2 Eq. (43,030 Gg) (see Table 4-8). Emissions from masonry production fro m clinker raw material ar e accounted for under Lime Manufacture.

Table 4-8: CO 2 Emissions from Cement Production (Tg CO 2 Eq. and Gg)*

Year Tg CO 2 Eq. Gg 1990 33.3 33,278

1997 38.3 38,323 1998 39.2 39,218 1999 40.0 39,991

1 The CO 2 emissions related to the cons umption of energy for cement manufacture are accounted for under CO 2 from Fossil Fuel Combustion in the Energy chapter.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 130 2000 41.2 41,190 2001 41.4 41,357 2002 42.9 42,898 2003 43.0 43,030 * Totals exclude CO 2 emissions from making masonry cem ent from clinker, which are account ed for under Lime Manufacture. After falling in 1991 by two percent from 1990 levels, cement production emissions have grown every year since. Overall, from 1990 to 2003, emissions increased by 29 percent. Cement is a critical co mponent of the construction industry; therefore, the av ailability of public construction funding, as well as overall economic growth, have had considerable influence on cement production.


### Methodology

Carbon dioxide emissions from cement manufacture are cr eated by the chemical r eaction of carbon-containing minerals (i.e., calcining limestone). While in the kiln, limestone is broken down into CO 2 and lime with the CO 2 released to the atmosphere. The quantity of the CO 2 emitted during cement production is directly proportional to the lime content of the clinker. During calcination, each mole of CaCO 3 (i.e., limestone) heated in the clinker kiln forms one mole of lime (CaO) and one mole of CO 2 :

CaCO 3 + heat → CaO + CO 2
Carbon dioxide emissions were estimated by applying an emission factor, in tons of CO 2 released per ton of clinker produced, to the total amount of clinker produced. The emission factor used in this analysis is the product of the average lime fraction for clinker of 64.6 percent (IPCC 2000) and a constant reflecting the mass of CO 2 released per unit of lime. This calculation yields an emission factor of 0.507 tons of CO 2 per ton of clinker produced, which was determined as follows:

clinker /ton 2 CO tons 507

. 0 CaO g/mole 08

. 56 2 CO g/mole 01

. 44 CaO 646

. 0 Clinker = × = 

### ⎥ ⎥ ⎦ ⎤ ⎢ ⎢ ⎣ ⎡ EF

During clinker production, some of the clinker precursor ma terials remain in the kiln as non-calcinated, partially calcinated, or fully calcinated cement kiln dust (CKD). The emissions attributable to the calcinated portion of the CKD are not accounted for by the cli nker emission factor. The IPCC reco mmends that these additional CKD CO 2 emissions should be estimated as two percent of the CO 2 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, nonplasticizer additives such as lime, slag, and shale are added to the cement, increasing its weight by approximately five percent. Lime accounts for appr oximately 60 percent of this added we ight. Thus, the additional lime is equivalent to roughly 2.86 percent of the starting amount of the product, since:

0.6 × 0.05/(1 + 0.05) = 2.86%

An emission factor for this added lime can then be calculated by multiplying this 2.86 percent by the molecular weight ratio of CO 2 to CaO (0.785) to yield 0.0224 metric tons of additional CO 2 emitted for every metric ton of masonry cement produced.

As previously mentioned, the CO 2 emissions from the additional lime added during masonry cement production are accounted for in the section on CO 2 emissions from Lime Manufacture. Thus, the activity data for masonry cement production are shown in this chapter for informational purposes only, and are not included in the cement emission totals.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 131 The 1990 through 2003 activity data for clinker and mas onry cement production (see Table 4-9) was obtained through a personal communication with Hendrick Van Oss (Van Oss 2004) of the USGS and through the USGS Mineral Yearbook: Cement (USGS 1992 through 2003). Data for 2003 masonry cement production were unavailable and were assumed to equal 2002 data. The data were compiled by USGS through questionnaires sent to domestic clinker and cement manufacturing plants.

Table 4-9: Cement Production (Gg)

Year Clinker Masonry 1990 64,355 3,209 1991 62,918 2,856 1992 63,415 3,093 1993 66,957 2,975 1994 69,786 3,283 1995 71,257 3,603 1996 71,706 3,469 1997 74,112 3,634 1998 75,842 3,989 1999 77,337 4,375 2000 79,656 4,332 2001 79,979 4,450 2002 82,959 4,449 2003 83,214 4,449



### Uncertainty

The uncertainties contained in these estimates are primarily due to uncertainties in the lime content of clinker and in the percentage of CKD recycled inside the clinker kiln. Th ere is also an uncertainty in the amount of lime added to masonry cement, but it is accounted for under the Lime Manufacture source category. The lime content of clinker varies from 64 to 66 percent. CKD loss can range from 1.5 to eight percent depending upon plant specifications. Additionally, some amount of CO 2 is reabsorbed when the cem ent is used for construction. As cement reacts with water, alkaline substances such as calcium hydroxide are formed. During this curing process, these compounds may react with CO 2 in the atmosphere to create calcium carbonate. This reaction only occurs in roughly the outer 0.2 inches of surface area. Because the amount of CO 2 reabsorbed is thought to be minimal, it was not estimated.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-10. Cement Manufacture CO 2 emissions were estimated to be between 39.7 and 46.3 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 8 percent below and 8 percent above the emission estimate of 43.0 Tg CO 2 Eq.

Table 4-10: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Cement Manufacture (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bo und Lower Bound Upper Bound Cement Manufacture CO 2 43.0 39.7 46.3 -8% +8%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.



### QA/QC and Verification

Based on the results of the Tier 2 uncertainty analysis conducted on the cement emissions estimate for the 2004 U.S. GHG Inventory, the United States decided to conduct Tier 2 QA procedures on two elements of the cement emissions estimate for the current inventory submission: the CaO content of clinker and emissions from productionInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 132 of CKD. The United States currently uses the IPCC de fault values for these input values and the current investigation seeks to determine whether these default valu es are reflective of U.S. circumstances. We are currently in the process of conducting a form of expert elicitation on these values. Preliminary results suggest that the default values seem appropriate for the U.S. cement industry however there may be small differences. We are currently investigating any differences and will include any results in future inventories, if appropriate.



### 4.3. Ammonia Manufacture and Urea App lication (IPCC Source Category 2B1)

Emissions of CO 2 occur during the production of synthetic ammonia, primarily through the use of natural gas as a feedstock. One ammonia production plant located in Kansas is producing ammonia from petroleum coke feedstock. The natural gas-based, naphtha-based, and petroleum coke-based processes produce CO 2 and hydrogen (H 2 ), the latter of which is used in the production of ammonia. In some plants the CO 2 produced is captured and used to produce urea. The brine electrolysis process for production of ammonia does not lead to CO 2 emissions.

There are five principal process steps in synthetic ammonia production from natural gas feedstock. The primary reforming step converts CH 4 to CO 2 , carbon monoxide (CO), and H 2 in the presence of a catalyst. Only 30 to 40 percent of the CH 4 feedstock to the primary reformer is converted to CO and CO 2 . The secondary reforming step converts the remaining CH 4 feedstock to CO and CO 2 . The CO in the process gas from the secondary reforming step (representing approximately 15 percent of the process gas) is converted to CO 2 in the presence of a catalyst, water, and air in the shift conversion step. Carbon dioxide is removed from the process gas by the shift conversion process, and the hydrogen gas is combined with the nitrogen (N 2 ) gas in the process gas during the ammonia synthesis step to produce ammonia. The CO 2 is included in a waste gas stream with other process impurities and is absorbed by a scrubber solution. In regenerating the scrubber solution, CO 2 is released.

The conversion process for conventional steam reforming of CH 4 , including primary and secondary reforming and the shift conversion processes, is approximately as follows: (catalyst)

0.88 CH 4 + 1.26 Air + 1.24 H 2 O — → 0.88 CO 2 + N 2 + 3 H 2

N 2 + 3 H 2 → 2 NH 3
To produce synthetic ammonia from petroleum coke, the petroleum coke is gasified and converted to CO 2 and H 2 . These gases are separated, and the H 2 is used as a feedstock to the ammoni a production process, where it is reacted with N 2 to form ammonia.

Not all of the CO 2 produced in the production of ammonia is emitted di rectly to the atmosphere. Both ammonia and carbon dioxide are used as raw materials in the production of urea [CO(NH 2 ) 2 ], which is another type of nitrogenous fertilizer that contains carbon as well as nitrogen. The chemical reaction that produces urea is:

2 NH 3 + CO 2 → NH 2 COONH 4 → CO(NH 2 ) 2 + H 2 O

The carbon in the urea that is produced and assumed to be subsequently applied to agricultural land as a nitrogenous fertilizer is ultimately released into the environment as CO 2 ; therefore, the CO 2 produced by ammonia production and subsequently used in the produc tion of urea does not change overall CO 2 emissions. However, the CO 2 emissions are allocated to the ammonia and urea producti on processes in accordance to the amount of ammonia and urea produced.

Net emissions of CO 2 from ammonia manufacture in 2003 were 9.1 Tg CO 2 Eq. (9,097 Gg), and are summarized in Table 4-11 and Table 4-12. Emissions of CO 2 from urea application in 2003 totaled 6.5 Tg CO 2 Eq. (6,463Gg), and are summarized in Table 4-11 and Table 4-12.

Table 4-11: CO 2 Emissions from Ammonia Manufacture and Urea Application (Tg CO 2 Eq.) Source 1990 1997 1998 1999 2000 2001 2002 2003Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 133 Ammonia Manufacture 12.6 14.0 14.2 12.9 12.1 9.3 10.6 9.1 Urea Application 6.8 6.6 7.7 7.7 7.5 7.4 8.0 6.5 Total 19.3 20.7 21.9 20.6 19.6 16.7 18.6 15.6

Table 4-12: CO 2 Emissions from Ammonia Manufacture and Urea Application (Gg) Source 1990 1997 1998 1999 2000 2001 2002 2003 Ammonia Manufacture 12,553 14,028 14,215 12,948 12,128 9,321 10,561 9,097 Urea Application 6,753 6,622 7,719 7,667 7,488 7,398 8,010 6,463



### Methodology

The calculation methodology for non-combustion CO 2 emissions from production of nitrogenous fertilizers from natural gas feedstock is based on a CO 2 emission factor published by the European Fertilizer Manufacturers Association (EFMA). The CO 2 emission factor (1.2 metric tons CO 2 /metric ton NH 3 ) is applied to the percent of total annual domestic ammonia production from na tural gas feedstock. Emissions of CO 2 from ammonia production are then adjusted to account for the use of some of the CO 2 produced from ammonia production as a raw material in the production of urea. For each ton of urea produced, 8.8 of every 12 tons of CO 2 are consumed and 6.8 of every 12 tons of ammonia are consumed. The CO 2 emissions reported for ammonia production are therefore reduced by a factor of 0.73 multiplied by total annual dom estic urea production, and that amount of CO 2 emissions is allocated to urea fertilizer application. Total CO 2 emissions resulting from nitrogenous fe rtilizer production do not change as a result of this calculation, but some of the CO 2 emissions are attributed to ammonia production and some of the CO 2 emissions are attributed to urea application.

The calculation of the total non-combustion CO 2 emissions from nitrogenous fertilizers accounts for CO 2 emissions from the application of imported and dom estically produced urea. For each ton of imported urea applied, 0.73 tons of CO 2 are emitted to the atmosphere. The amount of importe d urea applied is calculated based on the net of urea imports and exports.

All ammonia production and subsequent urea production are assumed to be from the same process—conventional catalytic reforming of natural gas feedstock, with the exception of ammonia production from petroleum coke feedstock at one plant located in Kansas. The CO 2 emission factor for production of ammonia from petroleum coke is based on plant specific data, wherein all carbon contained in the petroleum coke feedstock that is not used for urea production is assumed to be emitted to the atmosphere as CO 2 (Bark 2004). Ammonia and urea are assumed to be manufactured in the same manufacturing complex, as both the raw materials needed for urea production are produced by the ammonia production process. The CO 2 emission factor (3.57 metric tons CO 2 /metric ton NH 3 ) is applied to the percent of total annual domestic a mmonia production from petroleum coke feedstock.

The emission factor of 1.2 metric ton CO 2 /metric ton NH 3 for production of ammonia from natural gas feedstock was taken from the European Fertili zer Manufacturers Association Best Available Techniques publication, Production of Ammonia (EFMA 1995). The EFMA reported an emission factor range of 1.15 to 1.30 metric ton CO 2 /metric ton NH 3 , with 1.2 metric ton CO 2 /metric ton NH 3 as a typical value. The EF MA reference also indicates that more than 99 percent of the CH 4 feedstock to the catalytic reforming process is ultimately converted to CO 2 . The emission factor of 3.57 metric ton CO 2 /metric ton NH 3 for production of ammonia from petroleum coke feedstock was developed from plant-sp ecific ammonia production da ta and petroleum coke feedstock utilization data for the ammonia plant located in Kansas (Bark 2004). Ammonia and urea production data (see Table 4-13 and Table 4-14, respectively) were obtained from the Census Bu reau of the U.S. Department of Commerce (U.S. Census Bureau 1991 through 2004) as reported in Current Industrial Reports Fertilizer Materials and Related Products annual and quarterly reports. Import and export data for 2003 were unavaila ble and were assumed to equal 2002 data (see Table 4-15). These data were obtained from the U.S. Census Bureau Current Industrial Reports Fertilizer Materials and Related Products annual reports (U.S. Census Bureau) fo r 1997 through 2002, The Fertilizer Institute (TFI 2002) for 1993 through 1996, and the United States International Trade Commission Interactive Tariff and Trade DataWeb (U.S. ITC 2002) for 1990 through 1992.

Table 4-13: Ammonia Production (Gg)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 134 Year Gg 1990 15,425 1991 15,576 1992 16,261 1993 15,599 1994 16,211 1995 15,788 1996 16,260 1997 16,231 1998 16,761 1999 15,728 2000 14,342 2001 11,092 2002 12,577 2003 10,468

Table 4-14: Urea Production (Gg) Year Gg 1990 8,124 1991 7,373 1992 8,142 1993 7,557 1994 7,584 1995 7,363 1996 7,755 1997 7,430 1998 8,042 1999 8,080 2000 6,969 2001 6,080 2002 7,038 2003 5,783 Table 4-15: Urea Net Imports (Gg) Year Gg 1990 1,086 1991 648 1992 656 1993 2,305 1994 2,249 1995 2,055 1996 1,051 1997 1,600 1998 2,483 1999 2,374 2000 3,241 2001 4,008 2002 3,884 2003 3,030



### Uncertainty

The uncertainties contained in these estimates are primarily due to how accurately the emission factor used represents an average across all amm onia plants using natural gas feedstock. The EFMA reported an emissionInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 135 factor range of 1.15 to 1.30 ton CO 2 /ton NH 3 , with 1.2 ton CO 2 /ton NH 3 reported as a typical value. The actual emission factor depends upon the amount of air used in the ammonia production process, with 1.15 ton CO 2 /ton NH 3 being the approximate stoichiometric minimum that is achievable for the conventional reforming process. By using natural gas consumption data for each a mmonia plant, more accurate estimates of CO 2 emissions from ammonia production could be calculated. However, these consumption data are often considered confidential. Also, natural gas is consumed at ammonia plants both as a feedstock to the reforming process and for generating process heat and steam. Natural gas consumption data, if available, would need to be divided into feedstock use (non-energy) and process heat and steam (fuel) use, as CO 2 emissions from fuel use and non-energy use are calculated separately. 2

Natural gas feedstock consumption data for the U.S. a mmonia industry as a whole is available from the Energy Information Admi nistration (EIA) Manufacturers Energy Consumption Survey (MECS) for the years 1985, 1988, 1991, 1994 and 1998 (EIA 1994; EIA 1998). These feedstock consumption data collectively correspond to an effective average emission factor of 1.0 ton CO 2 /ton NH 3 , which appears to be below the stoichiometric minimum that is achievable for the conventional steam reforming pro cess. The EIA data for natural gas consumption for the years 1994 and 1998 correspond more closely to the CO 2 emissions calculated using the EFMA emission factor than do data for previous years. The 1994 and 1998 data alone yield an effective emission factor of 1.1 ton CO 2 /ton NH 3 , corresponding to CO 2 emissions estimates that are approximately 1.5 Tg CO 2 Eq. below the estimates calculated using the EFMA emission factor of 1.2 ton CO 2 /ton NH 3 . Natural gas feedstock consumption data are not available from EIA for other years, and data for 1991 and previous years may underestimate feedstock natural gas consumption, and therefore the EFMA emission factor was used to estimate CO 2 emissions from ammonia production, rather than EIA data.

All ammonia production and subsequent urea production was assumed to be from the same process—conventional catalytic reforming of natural gas feedstock, with the exception of one ammonia production plant located in Kansas that is manufacturing ammonia from petroleum coke feedstock. Research indicates that there is only one U.S. plant that manufactures ammonia from petroleum coke. CO 2 emissions from this plant are explicitly accounted for in the Inventory estimates. No data for ammonia plants using naphtha or other feedstocks other than natural gas have been identified. Therefore, all other CO 2 emissions from ammonia plants are cal culated using the emission factor for natural gas feedstock. However, actual emissions may differ because pr ocesses other than catalytic steam reformation and feedstocks other than natural gas may have been used for ammonia production. Urea is also used for other purposes than as a nitrogenous fertilizer. It was assumed that 100 percent of the urea production and net imports are used as fertilizer or in otherwise emissive us es. It is also assumed that ammonia and urea are produced at collocated plants from the same natural gas raw material.

Such recovery may or may not affect the overall estimate of CO 2 emissions from that sector depending upon the end use to which the recovered CO 2 is applied. For example, research has identified one ammonia production plant that is recovering byproduct CO 2 for use in EOR. Such CO 2 would be assumed to remain sequestered [see the section of

2 It appears that the IPCC emission fact or for ammonia production of 1.5 ton CO 2 per ton ammonia may include both CO 2 emissions from the natural gas feed stock to the process and some CO 2 emissions from the natural ga s used to generate process heat and steam for the process. Table 2-5, Ammonia Pr oduction Emission Factors, in Vo lume 3 of the Revised 1996 IPCC Guidelines for National Greenhouse Gas I nventories Reference Manual (IPCC 1997) incl udes two emission factors, one reported for Norway and one reported for Canada. The footnotes to the ta ble indicate that the factor for Norway does not include natura l gas used as fuel but that it is unclear whether the factor for Canada includes natural gas used as fuel. However, the factors for Norway and Canada are nearly identical (1.5 and 1.6 tons CO 2 per ton ammonia, respectively) and it is likely that if one value does not include fuel use, the other value also does not. Fo r the conventional steam reformi ng process, however, the EFMA reports an emission factor range for feedstock CO 2 of 1.15 to 1.30 ton per ton (with a typical value of 1.2 ton per ton) and an emission factor for fuel CO 2 of 0.5 tons per ton. This corresponds to a total CO 2 emission factor for the ammonia production process, including both feedstock CO 2 and process heat CO 2 , of 1.7 ton per ton, which is clos er to the emission factors reported in the IPCC 1996 Reference Guidelines than to the feedstock-only CO 2 emission factor of 1.2 ton CO 2 per ton ammonia reported by the EFMA. Because it appears that the emission factors cited in the IPCC Guidelines may actually include natural gas used as fuel, we use the 1.2 tons/ton emissi on factor developed by the EFMA.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 136 this chapter on Carbon Dioxide Consumption] however, time series data for the amount of CO 2 recovered from this plant is not available a nd therefore all of the CO 2 produced by this plant is assumed to be emitted to the atmosphere and allocated to Ammonia Manufacture. Further res earch is required to determine whether byproduct CO 2 is being recovered from other ammonia pr oduction plants for applicati on to end uses that are not accounted for elsewhere.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-16. Ammonia CO 2 emissions were estimated to be between 7.7 and 10.4 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 15 percent below and 15 percent above the emission estimate of 9.1 Tg CO 2 Eq. Urea CO 2 emissions were estimated to be between 6.0 and 7.0 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 8 percent below and 8 percent above the emission estimate of 6.5 Tg CO 2 Eq.

Table 4-16: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Ammonia Manufacture and Urea Application (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate (Tg CO 2 Eq.) Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (%) Lower Bound Upper Bo und Lower Bound Upper Bound Ammonia CO 2 9.1 7.7 10.4 -15% +15% Urea CO 2 6.5 6.0 7.0 -8% +8%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.



### Recalculations Discussion

Estimates of CO 2 emissions from ammonia manufacture for the years 2000, 2001, and 2002 were updated to reflect revisions made to the methodology to include ammonia manufactured from petroleum coke. The plant, located in Kansas, began ammonia production in 2000. This cha nge resulted in an average annual increase in CO 2 emissions from ammonia manufacture of 0.5 Tg CO 2 Eq. (2.7 percent) for the years 2000 through 2002.


### Planned Improvements

The United States recognizes that the Tier 2 methodology is preferred for estimating CO 2 emissions from ammonia manufacture. Historically, efforts have been made to ac quire feedstock data for this source category however the relevant data were not available. In addition to some of the future work noted in the Uncertainty section, additional planned improvements for this source category include developing a plan to determine the feasibility of acquiring the relevant data for the Tier 2 assessment. If successful, the results will be included in future inventory submissions



### .


### 4.4. Lime Manufacture (IP CC Source Category 2A2)

Lime is an important manufactured product with many industrial, chemical, and environmental applications. Its major uses are in steel making, flue gas desulfuriza tion (FGD) systems at coal-fi red electric power plants, construction, and water purification. Lime has historica lly ranked fifth in total production of all chemicals in the United States. For U.S. operations, the term “lime” actually refers to a variety of chemical compounds. These include calcium oxide (CaO), or high-calcium quicklime; calcium hydroxide (Ca(OH) 2 ), or hydrated lime; dolomitic quicklime ([CaO•MgO]); and dolomitic hydrate ([Ca(OH) 2 •MgO] or [Ca(OH) 2 •Mg(OH) 2 ]).

Lime production involves three main processes: stone prepar ation, calcination, and hydration. Carbon dioxide is generated during the calcination stage, when limestone

⎯ mostly calcium carbonate (CaCO 3 )

⎯ is roasted at high temperatures in a kiln to produce CaO and CO 2 . The CO 2 is given off as a gas and is normally emitted to theInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 137 atmosphere. Some of the CO 2 generated during the producti on process, however, is recovered at some facilities for use in sugar refining and precipitated calcium carbonate (PCC) 3 production. It is also important to note that, for certain applications, lime reabsorbs CO 2 during use (see Uncertainty, below).

Lime production in the United States

⎯ including Puerto Rico

⎯ was reported to be 19,164 thousand metric tons in 2003 (USGS 2004). This resulted in estimated CO 2 emissions of 13.0 Tg CO 2 Eq. (or 12,983 Gg) (see Table 4-17 and Table 4-18).

Table 4-17: Net CO 2 Emissions from Lime Manufacture (Tg CO 2 Eq.)

Year Tg CO 2 Eq. 1990 11.2

1997 13.7 1998 13.9 1999 13.5 2000 13.3 2001 12.8 2002 12.3 2003 13.0

Table 4-18: CO 2 Emissions from Lime Manufacture (Gg) Year Potential Recovered* Net Emissions 1990 11,730 (493) 11,238

1997 14,649 (964) 13,685 1998 14,975 (1,061) 13,914 1999 14,655 (1,188) 13,466 2000 14,548 (1,233) 13,315 2001 13,941 (1,118) 12,823 2002 13,355 (1,051) 12,304 2003 14,132 (1,149) 12,983 * For sugar refining and precipita ted calcium carbonate production. Note: Totals may not sum due to independent rounding.

At the turn of the 20 th Century, over 80 percent of lime consumed in the United States went for construction uses. The contemporary quicklime market is di stributed across four end-use categories as follows: metallurgical uses, 35 percent; environmental uses, 28 percent; chemical and indus trial uses, 23 percent, construction uses, 13 percent; and refractory dolomite, one percent. In the construction sector, hydrated lime is still used to improve durability in plaster, stucco, and mortars. The use of hydrated lime fo r traditional building increased by nearly seven percent in 2003 (USGS 2004). Lime production in 2003 increased by nearly seven percent from 2002, the first increase in production in five years. Overall, from 1990 to 2003, lime production has increased by 17 percent. The increase in production is attributed in part to growth in demand for environmental applications, especially flue gas desulfurization technologies. In 1993, EPA completed regulations under the Clean Air Act capping sulfur dioxide (SO 2 ) emissions from electric utilities. Lime scrubbers’ high efficienci es and increasing affordability have allowed the flue gas desulfurization end-use to expand significantly over the years. Ph ase II of the Clean Air Act Amendments , which went into effect on January 1, 2000, remains the driving force behind the growth in the flue gas desulfurization market (USGS 2003).

3 Precipitated calcium carbonate is a specialty filler used in premium-quality coated and uncoated papers.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 138 

### Methodology

During the calcination stage of lime manufacture, CO 2 is given off as a gas and normally exits the system with the stack gas. To calculate emissions, the amounts of hi gh-calcium and dolomitic lime produced were multiplied by their respective emission factors. The emission factor is the product of a constant reflecting the mass of CO 2 released per unit of lime and the average calcium plus magnesium oxide (CaO + MgO) content for lime (95 percent for both types of lime). The emission factors were calculated as follows:

For high-calcium lime: [(44.01 g/mole CO 2 ) ÷ (56.08 g/mole CaO)] × (0.95 CaO/lime) = 0.75 g CO 2 /g lime

For dolomitic lime: [(88.02 g/mole CO 2 ) ÷ (96.39 g/mole CaO)] × (0.95 CaO/lime) = 0.87 g CO 2 /g lime

Production is adjusted to remove the mass of chemically combined water found in hydrated lime, using the midpoint of default ranges provided by the IPCC Good Practice Guidance (IPCC 2000). These factors set the chemically combined water content to 27 percent for high-calcium hydrated lime, and 24 percent for dolomitic hydrated lime.

Lime production in the United States was 19,164 thousand metric tons in 2003 (USGS 2004), resulting in potential CO 2 emissions of 14.1 Tg CO 2 Eq. Some of the CO 2 generated during the production process, however, was recovered for use in sugar refining and precipitate d calcium carbonate (PCC) production. Combined lime manufacture by these producers was 1,926 thousand metric tons in 2003. It was assumed that approximately 80 percent of the CO 2 involved in sugar refi ning and PCC was recovered, resulting in actual CO 2 emissions of 13.0 Tg CO 2 Eq.

The activity data for lime manufacture and lime cons umption by sugar refining and PCC production for 1990 through 2003 (see Table 4-19) were obtained from USGS (1992 through 2004). Hydrated lime production is reported separately in Table 4-20. The CaO and CaO•MgO contents of lime were obtained from the IPCC Good Practice Guidance (IPCC 2000). Since data for the individual lim e types (high calcium and dolomitic) was not provided prior to 1997, total lime production for 1990 th rough 1996 was calculated according to the three year distribution from 1997 to 1999. For sugar refining and PCC, it was assumed that 100 percent of lime manufacture and consumption was high-calcium, based on communicati on with the National Lime Association (Males 2003).

Table 4-19: Lime Production and Lime Use for Sugar Refining and PCC (Gg)

Year High-Calcium Production a Dolomitic Production a,b Use for Sugar Refining and PCC 1990 12,947 2,895 826 1991 12,840 2,838 964 1992 13,307 2,925 1,023 1993 13,741 3,024 1,279 1994 14,274 3,116 1,374 1995 15,193 3,305 1,503 1996 15,856 3,434 1,429 1997 16,120 3,552 1,616 1998 16,750 3,423 1,779 1999 16,110 3,598 1,992 2000 15,850 3,621 2,067 2001 15,630 3,227 1,874 2002 14,900 3,051 1,762 2003 16,040 3,124 1,926

a Includes hydrated lime. b Includes dead-burned dolomite.

Table 4-20: Hydrated Lime Production (Gg)

Year High-Calcium Hydrate Dolomitic Hydrate 1990 1,781 319Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 139 1991 1,841 329 1992 1,892 338 1993 1,908 342 1994 1,942 348 1995 2,027 363 1996 1,858 332 1997 1,820 352 1998 1,950 383 1999 2,010 298 2000 1,550 421 2001 2,030 447 2002 1,500 431 2003 2,140 464



### Uncertainty

The uncertainties contained in these estimat es can be attributed to slight diffe rences in the chemical composition of these products. Although the methodology accounts for various form ulations of lime, it does not account for the trace impurities found in lime, such as iron oxide, alumina, and silica. Due to differences in the limestone used as a raw material, a rigid specifica tion of lime material is impossible. As a result, few plants manufacture lime with exactly the same properties.

In addition, a portion of the CO 2 emitted during lime manufacture will actually be reabsorbed when the lime is consumed. As noted above, lime has many different ch emical, industrial, environmental, and construction applications. In many processes, CO 2 reacts with the lime to create calcium carbonate (e.g., water softening). Carbon dioxide reabsorption rates vary, however, depending on the application. For example, 100 percent of the lime used to produce precipitated calcium carbonate reacts with CO 2 ; whereas most of the lime used in steel making reacts with impurities such as silica, sulfur, and aluminum compounds. A detailed accounting of lime use in the United States and further research into the associated processes are required to quantify the amount of CO 2 that is reabsorbed. 4

In some cases, lime is generated from calcium carbonate by-products at pulp mills a nd water treatment plants. 5 The lime generated by these processes is not included in th e USGS data for commercial lime consumption. In the pulping industry, mostly using the Kraft (sulfate) pulping pro cess, lime is consumed in order to causticize a process liquor (green liquor) composed of sodium carbonate and sodium sulfide. The green liquor results from the dilution of the smelt created by combustion of the black liquor wh ere biogenic carbon is present from the wood. Kraft mills recover the calcium carbonate “mud” after the causticizi ng operation and most sulfat e mills recover the waste calcium carbonate after the causticizing operation and calcine it back into lime

⎯ thereby generating CO 2 ⎯ for reuse in the pulping process. Although this re-generation of lime could be considered a lime manufacturing process, the CO 2 emitted during this process is mostly biogenic in origin, and therefore is not included in Inventory totals.

In the case of water treatment plants, lim e is used in the softening process. Some large water treatment plants may recover their waste calcium carbonate and calcine it into quicklime for reuse in the softening process. Further

4 Representatives of the National Lime Association estimate that CO 2 reabsorption that occurs from the use of lime may offset as much as a quarter of the CO 2 emissions from calcination (Males 2003). 5 Some carbide producers may also regenerate lime from thei r calcium hydroxide by-products, which does not result in emissions of CO 2 . 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 wast e calcium hydroxide (hydrated lime) [CaC 2 + 2H 2 O → C 2 H 2 + Ca(OH) 2 ], not calcium carbonate [CaCO 3 ]. Thus, the calcium hydroxide is heated in the kiln to simply expel the water [Ca(OH) 2 + heat → CaO + H 2 O] and no CO 2 is released.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 140 research is necessary to determine the degree to which lime recycling is practiced by water treatment plants in the United States.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-21. Lime CO 2 emissions were estimated to be between 12.0 and 14.1 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 8 percent below and 8 percent above the emission estimate of 13.0 Tg CO 2 Eq.

Table 4-21: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Lime Manufacture (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Lime Manufacture CO 2 13.0 12.0 14.1 -8% +8%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.



### 4.5. Limestone and Dolomite Use (IPCC Source Category 2A3)

Limestone (CaCO 3 ) and dolomite (CaCO 3 MgCO 3 ) 6 are basic raw materials used by a wide variety of industries, including construction, agriculture, chemical, metallurgy, glass manufacture, and environmental pollution control. Limestone is widely distributed throughout the world in deposits of varying sizes and degrees of purity. Large deposits of limestone occur in nearly every state in the United States, and significant quantities are extracted for industrial applications. For some of these applications, limestone is sufficiently heated during the process to generate CO 2 as a by-product. Examples of such applications include limestone used as a flux or purifier in metallurgical furnaces, as a so rbent in flue gas desulfurization systems fo r utility and industrial plants, or as a raw material in glass manufacturing and magnesium production.

In 2003, approximately 8,074 thousand metric tons of limes tone and 2,446 thousand metric tons of dolomite were consumed for these applications. Overall, usage of limestone and dolomite resulted in aggregate CO 2 emissions of 4.7 Tg CO 2 Eq. (4,720 Gg) (see Table 4-22 and Table 4-23). Emissions in 2003 decreased 20 percent from the previous year and have decreased 15 percent overall from 1990 through 2003.

Table 4-22: CO 2 Emissions from Limestone & Dolomite Use (Tg CO 2 Eq.) Activity 1990 1997 1998 1999 2000 2001 2002 2003 Flux Stone 3.0 5.0 5.1 6.0 2.8 2.5 2.4 2.1 Glass Making 0.2 0.3 0.2 0 0.4 0.1 0.1 0.3 FGD 1.4 1.4 1.2 1.2 1.8 2.6 2.8 1.9 Magnesium Production 0.1 0.1 0.1 0.1 0.1 0.1 0.0 0.0 Other Miscellaneous Uses 0.8 0.4 0.9 0.7 0.9 0.5 0.7 0.4 Total 5.5 7.2 7.4 8.1 6.0 5.7 5.9 4.7 Notes: Totals may not sum due to indepe ndent rounding. Other miscellaneous uses in clude chemical stone, mine dusting or acid water treatment, acid neutrali zation, and sugar refining.

Table 4-23: CO 2 Emissions from Limestone & Dolomite Use (Gg) Activity 1990 1997 1998 1999 2000 2001 2002 2003 Flux Stone 2,999 5,023 5,132 6,030 2,829 2,514 2,405 2,072

6 Limestone and dolomite are collectively re ferred to as limestone by the industry, and intermediate varieties are seldom distinguished.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 141 Limestone 2,554 3,963 4,297 4,265 1,810 1,640 1,330 904 Dolomite 446 1,060 835 1,765 1,020 874 1,075 1,168 Glass Making 217 319 157 0 368 113 61 337

Limestone 189 319 65 0 368 113 61 337 Dolomite 28 0 91 0 0 0 0 0 FGD 1,433 1,426 1,230 1,240 1,773 2,551 2,766 1,932 Magnesium Production 64 73 73 73 73 53 0 0 Other Miscellaneous Uses 819 401 858 713 915 501 652 380 Total 5,533 7,242 7,449 8,057 5,959 5,733 5,885 4,720 Notes: Totals may not sum due to indepe ndent rounding. Other miscellaneous uses in clude chemical stone, mine dusting or acid water treatment, acid neutrali zation, and sugar refining.



### Methodology

Carbon dioxide emissions were calculate d by multiplying the quantity of limes tone or dolomite consumed by the average carbon content, approximately 12.0 percent for limestone and 13.2 percent for dolomite (based on stoichiometry). This assumes that all carbon is oxidized and released. This methodology was used for flux stone, glass manufacturing, flue gas desulfurization systems, chemical stone, mine dusting or acid water treatment, acid neutralization, and sugar refi ning and then converting to CO 2 using a molecular weight ratio.

Traditionally, the production of magnesium metal was the only other use of limestone and dolomite that produced CO 2 emissions. At the start of 2001, there were two magnesium production plants operating in the United States and they used different pr oduction methods. One plant produced magnesi um metal using a dolomitic process that resulted in the release of CO 2 emissions, while the other plant produced magnesium from magnesium chloride using a CO 2 -emissions-free process called electrolytic reduction. However, the plant utilizing the dolomitic process ceased its operations prior to the end of 2001, so beginni ng in 2002 there were no emissions from this particular sub-use.

Consumption data for 1990 through 2003 of limestone and dol omite used for flux stone, glass manufacturing, flue gas desulfurization systems, chemical stone, mine dusti ng or acid water treatment, acid neutralization, and sugar refining (see Table 4-24) were obtained from personal communication with Valentine Tepordei of the USGS regarding data in the Minerals Yearbook: Crushed Stone Annual Report (Tepordei 2002, 2003, 2004 and USGS 1993, 1995a, 1995b, 1996a, 1997a, 1998a, 1999a , 2000a, 2001a, 2002a, 2003a). The production capacity data for 1990 through 2003 of dolomitic magnesium metal (see Ta ble 4-25) also came from the USGS (1995c, 1996b, 1997b, 1998b, 1999b, 2000b, 2001b, 2002b, 2003b, 2004). During 1990 and 1992, the USGS did not conduct a detailed survey of limestone and dolomite consumption by end-use. Consumption for 1990 was estimated by applying the 1991 percentages of total limestone and dol omite use constituted by th e individual limestone and dolomite uses to 1990 total use. Similarly, the 1992 c onsumption figures were approximated by applying an average of the 1991 and 1993 percentages of total limes tone and dolomite use cons tituted by the individual limestone and dolomite uses to the 1992 total.

Additionally, each year the USGS withholds data on certain limestone and dolomite end-uses due to confidentiality agreements regarding company proprietary data. For the purposes of this analysis, emissive end-uses that contained withheld data were estimated using one of the following tec hniques: (1) the value for all the withheld data points for limestone or dolomite use was distributed evenly to all withheld end-uses; (2) the average percent of total limestone or dolomite for the withheld end-use in the preceding a nd succeeding years; or (3) th e average fraction of total limestone or dolomite for the end-use over the entire time period.

Finally, there is a large quantity of crushed stone reporte d to the USGS under the category “unspecified uses.” A portion of this consumption is believed to be limestone or dolomite used for emissive end uses. The quantity listedInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 142 for “unspecified uses” was, therefore, allocated to each reported end-use accord ing to each end uses fraction of total consumption in that year. 7

Table 4-24: Limestone and Dolomite Consumption (Thousand Metric Tons) Activity 1990 1997 1998 1999 2000 2001 2002 2003 Flux Stone 6,738 11,226 11,514 13,390 6,248 5,558 5,275 4,501

Limestone 5,804 9,007 9,767 9,694 4,113 3,727 3,023 2,055 Dolomite 933 2,219 1,748 3,696 2,135 1,831 2,252 2,466 Glass Making 489 725 340 0 836 258 139 765

Limestone 430 725 149 0 836 258 139 765 Dolomite 59 0 191 0 0 0 0 0 FGD 3,258 3,242 2,795 2,819 4,030 5,798 6,286 4,390 Other Miscellaneous Uses 1,835 898 1,933 1,620 2,080 1,138 1,483 863 Total 12,319 16,091 16,582 17,830 13,194 12,751 13,183 10,520 Note: "Other miscellaneous uses" includes chemical stone, mine dusting or acid water treatment, acid neutralization, and sugar refining.

Table 4-25: Dolomitic Magnesium Me tal Production Capacity (Metric Tons) Year Production Capacity 1990 35,000 1991 35,000 1992 14,909 1993 12,964 1994 21,111 1995 22,222 1996 40,000 1997 40,000 1998 40,000 1999 40,000 2000 40,000 2001 29,167 2002 0 2003 0 Note: Production capacity for 2002 and 2003 amount to zero because the last U.S. production plant employing the dolomitic process shut down mid-2001 (USGS 2002).



### Uncertainty

Uncertainties in this estimate are due, in part, to variations in the chemical composition of limestone. In addition to calcium carbonate, limestone may contain smaller amounts of magnesia, silica, a nd sulfur. The exact specifications for limestone or dolomite used as flux stone vary with the pyrometallurgical process, the kind of ore processed, and the final use of the slag. Similarly, the quality of the limestone used for glass manufacturing will depend on the type of glass being manufactured.

Uncertainties also exist in the activity data. Much of the limestone consumed in the United States is reported as “other unspecified uses;” ther efore, it is difficult to accura tely allocate this unspecifiedquantity to the correct enduses. Also, some of the limestone reported as “limest one” is believed to actually be dolomite, which has a higher carbon content. Additionally, there is significant inherent uncertainty associ ated with estimating withheld data points for specific end uses of limestone and dolomite. Lastly, the uncertainty of the estimates for limestone used in

7 This approach was recommended by USGS.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 143 glass making is especially high. Large fluctuations in re ported consumption exist, reflecting year-to-year changes in the number of survey responders. The uncertainty resulti ng from a shifting survey popula tion is exacerbated by the gaps in the time series of reports. However, since gl ass making accounts for a small percent of consumption, its contribution to the overall emissions estimate is low.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-26. Limestone and Dolomite Use CO 2 emissions were estimated to be between 4.4 and 5.1 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 7 percent below and 8 percent above the emission estimate of 4.7 Tg CO 2 Eq.

Table 4-26: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Limestone and Dolomite Use (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Limestone and Dolomite Use CO 2 4.7 4.4 5.1 -7% +8%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.



### Recalculations Discussion

A spreadsheet error was corrected for the limestone a nd dolomite use emission estimate for 2002. The change resulted in an increase of less than 0.1 Tg CO 2 Eq. (0.8 percent) in CO 2 emissions from limestone and dolomite use for that year.



### 4.6. Soda Ash Manufacture and Cons umption (IPCC Source Category 2A4)

Soda ash (sodium carbonate, Na 2 CO 3 ) is a white crystalline solid that is readily soluble in water and strongly alkaline. Commercial soda ash is used as a raw material in a variety of industrial processes and in many familiar consumer products such as glass, soap a nd detergents, paper, textiles, and food. It is used primarily as an alkali, either in glass manufacturing or simply as a material that reacts with and ne utralizes acids or acidic substances. Internationally, two types of soda ash are produced

⎯ natural and synthetic. The United States produces only natural soda ash and is the largest soda ash-producing country in the world. Trona is the principal ore from which natural soda ash is made.

Only three states produce natural soda ash: Wyoming, California, and Colorado. Of these three states, only net emissions of CO 2 from Wyoming were calculated. This difference is a result of the production processes employed in each state. 8 During the production process used in Wyoming, trona ore is treated to produce soda ash. Carbon dioxide is generated as a by-p roduct of this reaction, and is eventually emitted into the atmosphere. In addition, CO 2 may also be released when soda ash is consumed.

In 2003, CO 2 emissions from the manufacture of soda ash from trona were approximately 1.5 Tg CO 2 Eq. (1,509 Gg). Soda ash consumption in the United States generated 2.6 Tg CO 2 Eq. (2,573 Gg) in 2003. Total emissions from soda ash manufacture in 2003 were 4.1 Tg CO 2 Eq. (4,082 Gg) (see Table 4-27 and Table 4-28). Emissions

8 In California, soda ash is manufactured using sodium carbonate-bearing brines instead of trona ore. To extract the sodium carbonate, the complex brines are first treated with CO 2 in carbonation towers to convert the sodium carbonate into sodium bicarbonate, which then precipitates from the brine solution. Th e precipitated sodium bicarbonate is then calcined back into sodium carbonate. Although CO 2 is generated as a by-product, the CO 2 is recovered and recycled for use in the carbonation stage and is not emitted.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 144 have fluctuated since 1990. These fluctuations were str ongly related to the behavior of the export market and the U.S. economy. Emissions in 2003 decreased by approximately 1 percent from the previous year, and have decreased overall by approximately 1 percent since 1990.

Table 4-27: CO 2 Emissions from Soda Ash Manufacture and Consumption (Tg CO 2 Eq.)

Year Manufacture Consumption Total 1990 1.4 2.7 4.1

1997 1.7 2.7 4.4 1998 1.6 2.7 4.3 1999 1.5 2.7 4.2 2000 1.5 2.7 4.2 2001 1.5 2.6 4.1 2002 1.5 2.7 4.1 2003 1.5 2.6 4.1 Note: Totals may not sum due to independent rounding.

Table 4-28: CO 2 Emissions from Soda Ash Manufacture and Consumption (Gg)

Year Manufacture Consumption Total 1990 1,431 2,710 4,141

1997 1,665 2,689 4,354 1998 1,607 2,718 4,325 1999 1,548 2,668 4,217 2000 1,529 2,652 4,181 2001 1,500 2,648 4,147 2002 1,470 2,668 4,139 2003 1,509 2,573 4,082 Note: Totals may not sum due to independent rounding.

The United States has the world’s largest deposits of trona and represents about one-third of total world soda ash output. The distribution of soda ash by end-use in 2003 was glass making, 49 percent; chemical production, 26 percent; soap and detergent manufacturing, 11 percent; distri butors, five percent; flue gas desulfurization, pulp and paper production, two percent each; water treatment, one percent; and miscellaneous, four percent (USGS 2004).

Although the United States continues to be the major supp lier of world soda ash, China’s soda ash manufacturing capacity is rapidly increasing and is expected to surpass that of the United States. This will likely cause greater competition in Asian markets in the future. The world market for soda ash is expected to grow 1.5 to 2 percent annually (USGS 2004).


### Methodology

During the production process, trona ore is calcined in a rotary kiln and chemically transformed into a crude soda ash that requires further processing. Carbon dioxide a nd water are generated as by-products of the calcination process. Carbon dioxide emissions from the calcination of trona can be estimated based on the following chemical reaction:

2(Na 3 H(CO 3 ) 2 ⋅ 2H 2 O) → 3Na 2 CO 3 + 5H 2 O + CO 2

[trona] [soda ash]Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 145 Based on this formula, approximately 10.27 metric tons of trona are required to generate one metric ton of CO 2 . Thus, the 15.5 million metric tons of trona mined in 2003 for soda ash production (USGS 2004) resulted in CO 2 emissions of approximately 1.5 Tg CO 2 Eq. (1,509 Gg).

Once manufactured, most soda ash is consumed in glass and chemical production, with minor amounts in soap and detergents, pulp and paper, flue gas desulfurization and water treatment. As soda ash is consumed for these purposes, additional CO 2 is usually emitted. In these applications, it is assumed that one mole of carbon is released for every mole of soda ash used. Thus, approximately 0.113 metric tons of carbon (or 0.415 metric tons of CO 2 ) are released for every metric ton of soda ash consumed.

The activity data for trona production and soda ash c onsumption (see Table 4-29) were taken from USGS (1994 through 2004). Soda ash manufacture and consumption data were collected by the USGS from voluntary surveys of the U.S. soda ash industry.

Table 4-29: Soda Ash Manufacture and Consumption (Gg) Year Manufacture* Consumption 1990 14,700 6,530 1991 14,700 6,280 1992 14,900 6,320 1993 14,500 6,280 1994 14,600 6,260 1995 16,500 6,500 1996 16,300 6,390 1997 17,100 6,480 1998 16,500 6,550 1999 15,900 6,430 2000 15,700 6,390 2001 15,400 6,380 2002 15,100 6,430 2003 15,500 6,200 * Soda ash manufactured from trona ore only. 

### Uncertainty

Emission estimates from soda ash manufacture are consider ed to have low associated uncertainty. Both the emission factor and activity data are reliable. Howeve r, emissions from soda ash consumption are dependent upon the type of processing employed by each end-use. Specific information ch aracterizing the emissions from each enduse is limited. Therefore, there is uncertainty surrounding the emission factors from the consumption of soda ash.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-30. Soda Ash Manufacture and Consumption CO 2 emissions were estimated to be between 3.9 and 4.2 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations ). This indicates a range of approximately 4 percent below and 4 percent above the emission estimate of 4.1 Tg CO 2 Eq.

Table 4-30: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Soda Ash Manufacture and Consumption (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Soda Ash Manufacture and Consumption CO 2 4.1 3.9 4.2 -4% +4%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 146 

### Planned Improvements

Emissions from soda ash production in Co lorado, which is produced using the nahcolite production process, will be investigated for inclusion in future inventories.



### 4.7. Titanium Dioxide Producti on (IPCC Source Category 2B5)

Titanium dioxide (TiO 2 ) is a metal oxide manufactured from titanium ore, and is principally used as a pigment. Titanium dioxide is a principal ingredient in white paint, and TiO 2 is also used as a pigment in the manufacture of white paper, foods, and other products. There are two processes for making TiO 2 , the chloride process and the sulfate process. Carbon dioxide is emitted from the chloride process, which uses petrol eum coke and chlorine as raw materials and emits process-related CO 2 . The sulfate process does not use petroleum coke or other forms of carbon as a raw material and does not emit CO 2 . The chloride process is based on the following chemical reactions:

2 FeTiO 3 + 7 Cl 2 + 3 C → 2 TiCl 4 + 2 FeCl 3 + 3 CO 2

2 TiCl 4 + 2 O 2 → 2 TiO 2 + 4 Cl 2

The carbon in the first chemical reacti on is provided by petroleum coke, whic h is oxidized in the presence of the chlorine and FeTiO 3 (the Ti-containing ore) to form CO 2 . The majority of U.S. TiO 2 was produced in the United States through the chloride process, and a special grade of petroleum coke is manufactured specifically for this purpose. Emissions of CO 2 from titanium dioxide produc tion in 2003 were 2.0 Tg CO 2 Eq. (2,013 Gg), an increase of less than one percent from the previous year and 54 percent from 1990, due to increasing production within the industry (see Table 4-31).

Table 4-31: CO 2 Emissions from Titanium Dioxide (Tg CO 2 Eq. and Gg) Year Tg CO 2 Eq. Gg 1990 1.3 1,308

1997 1.8 1,836 1998 1.8 1,819 1999 1.9 1,853 2000 1.9 1,918 2001 1.9 1,857 2002 2.0 1,997 2003 2.0 2,013



### Methodology

Emissions of CO 2 from titanium dioxide producti on were calculated by multiply ing annual titanium dioxide production by chlorine process-specific emission factors.

Data were obtained for the total amount of titanium dioxide produced each year , and it was assumed that 97 percent of the total production in 2003 was produced using the chloride process. It was assume d that titanium dioxide was produced using the chloride process and the sulfate process in the same ratio as the ratio of the total U.S. production capacity for each process. An emission fact or of 0.4 metric tons C/metric ton TiO 2 was applied to the estimated chloride process production. It was assumed that all titanium dioxide produ ced using the chloride process was produced using petroleum coke , although some titanium dioxide may have been produced with graphite or other carbon inputs. The amount of petroleu m coke consumed annually in titani um dioxide producti on was calculated based on the assumption that petroleum coke used in the process is 90 percent carbon and 10 percent inert materials.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 147 The emission factor for the titanium dioxide chloride process was taken from the report, Everything You’ve Always Wanted to Know about Petroleum Coke (Onder and Bagdoyan 1993). Titanium dioxide production data for 1990 through 2003 (see Table 4-32) were obtained from pe rsonal communication with Joseph Gambogi, USGS Commodity Specialist, of the USGS (Gambogi 2004) and through the Minerals Yearbook: Titanium Annual Report (USGS 1991 through 2003). Data for the percentage of th e total titanium dioxide pr oduction capacity that is chloride process for 1994 through 2002 were also taken from the USGS Minerals Yearbook and from Joseph Gambogi for 2003. Percentage chloride process data were not available for 1990 through 1993, and data from the 1994 USGS Minerals Yearbook were used for these years. Because a sulfate-process plant closed in September 2001, the chloride process percentage for 2001 was estimat ed based on a discussion with Joseph Gambogi (2002). By 2002, only one sulfate plant remained online in the United States. The composition data for petroleum coke were obtained from Onder and Bagdoyan (1993).

Table 4-32: Titanium Dioxide Production (Gg) Year Gg 1990 979 1991 992 1992 1,140 1993 1,160 1994 1,250 1995 1,250 1996 1,230 1997 1,340 1998 1,330 1999 1,350 2000 1,400 2001 1,330 2002 1,410 2003 1,420



### Uncertainty

Although some titanium dioxide may be produced using graphite or other carbon inputs, information and data regarding these practices were not available. Titani um dioxide produced using graphite inputs may generate differing amounts of CO 2 per unit of titanium dioxide produced compared to the use of petroleum coke. The most accurate method for these estimates w ould be basing calculations on the amount of reducing agent used in the process, rather than the amount of titanium dioxide produced. These data were not available, however.

Also, annual titanium production is not reported by USGS by the type of production process used (chloride or sulfate). Only the percentage of to tal production capacity is reported. It was assumed that titanium dioxide was produced using the chloride process and the sulfate process in the same ratio as the ratio of the total U.S. production capacity for each process. This assumes that the chloride process plants and sulfate process plants operate at the same level of utilization. Finally, th e emission factor was applied uniformly to all chloride process production, and no data were available to account for differences in pr oduction efficiency among chloride process plants. In calculating the amount of petroleum coke consumed in chlo ride process titanium dioxide production, literature data were used for petroleum coke composition. Certain grades of petroleum coke are manuf actured specifically for use in the titanium dioxide chloride process; however, this composition information was not available.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-33. Titanium Dioxide Consumption CO 2 emissions were estimated to be between 1.7 and 2.3 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations ). This indicates a range of approximately 16 percent below and 16 percent above the emission estimate of 2.0 Tg CO 2 Eq.

Table 4-33: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Titanium Dioxide Production (Tg CO 2 Eq. and Percent)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 148 Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a

(Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Titanium Dioxide Production CO 2 2.0 1.7 2.3 -16% +16%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.



### 4.8. Phosphoric Acid Production (IPCC Source Category 2A7)

Phosphoric acid [H 3 PO 4 ] is a basic raw material in the production of phosphate-based fertilizers. Phosphate rock is mined in Florida, North Carolina, Idaho, Utah, and other areas of the United States and is used primarily as a raw material for phosphoric acid production. The production of phosphoric acid from phosphate rock produces byproduct gypsum [CaSO 4 -2H 2 O], referred to as phosphogypsum.

The composition of natural phosphate rock varies de pending upon the location where it is mined. Natural phosphate rock mined in the United States generally cont ains inorganic carbon in the form of calcium carbonate (limestone) and also may contain or ganic carbon. The chemical compositi on of phosphate rock (francolite) mined in Florida is:

Ca 10-x-y Na x Mg y (PO 4 ) 6-x (CO 3 ) x F 2+0.4x
The calcium carbonate component of the phosphate rock is integral to the phosphate rock chemistry. Phosphate rock can also contain organic carbon that is physically incorporated into the mined rock but is not an integral component of the phosphate rock chemistry. Phosphoric acid production from natural phosphate rock is a source of CO 2 emissions, due to the chemical reaction of the inorganic carbon (calcium carbonate) component of the phosphate rock.

The phosphoric acid production proce ss involves chemical reaction of the calcium phosphate (Ca 3 (PO 4 ) 2 ) component of the phosphate rock with sulfuric acid (H 2 SO 4 ) and recirculated phosphoric acid (H 3 PO 4 ) (EFMA 1997). The primary chemical reactions for the pr oduction of phosphoric acid fro m phosphate rock are:

Ca 3 (PO 4 ) 2 + 4H 3 PO 4 → 3Ca(H 2 PO 4 ) 2
3Ca(H 2 PO 4 ) 2 + 3H 2 SO 4 + 6H 2 O → 3CaSO 4 6H 2 O + 6H 3 PO 4
The limestone (CaCO 3 ) component of the phosphate rock reacts w ith the sulfuric acid in the phosphoric acid production process to produce calcium sulfate (phosphogypsum) and carbon dioxide. The chemical reaction for the limestone–sulfuric acid reaction is:

CaCO 3 + H 2 SO 4 + H 2 O → CaSO 4 2H 2 O + CO 2
Total marketable phosphate rock production in 2003 was 38. 7 million metric tons. Approximately 86 percent of domestic phosphate rock production was mined in Florida a nd North Carolina, while approximately 14 percent of production was mined in Idaho and Utah. Florida alone re presented more than 75 percent of domestic production. In addition, 2.4 million metric tons of crude phosphate rock was imported fo r consumption in 2003. Marketable phosphate rock production, including domestic producti on and imports for consumption, increased by approximately 3.7 percent between 2002 and 2003. Howe ver, over the 1990 to 2003 period, production decreased by 12 percent. The 35.3 million metric tons produced in 2001 was the lowest production level recorded since 1965 and was driven by a worldwide decrease in demand for phosphate fertilizers. Total CO 2 emissions from phosphoric acid production were 1.4 Tg CO 2 Eq. (1,382 Gg) in 2003 (see Table 4-34).

Table 4-34: CO 2 Emissions from Phosphoric Acid Production (Tg CO 2 Eq. and Gg)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 149 Year Tg CO 2 Eq. Gg 1990 1.5 1,529

1997 1.5 1,544 1998 1.6 1,593 1999 1.5 1,539 2000 1.4 1,382 2001 1.3 1,264 2002 1.3 1,338 2003 1.4 1,382



### Methodology

Carbon dioxide emissions from producti on of phosphoric acid from phosphate rock is calculated by multiplying the average amount of calcium carbonate contained in the natural phosphate rock by the amount of phosphate rock that is used annually to produce phosphoric acid, accounting for domestic production a nd net imports for consumption.

The USGS reports in the Minerals Yearbook, Phosphate Rock, the aggregate amount of phosphate rock mined annually in Florida and North Carolina and the aggregat e amount of phosphate rock mined annually in Idaho and Utah, and reports the annual amounts of phosphate rock e xported and imported for consumption (see Table 4-35). Data for domestic production of phosphate rock, exports of phosphate rock, and imports of phosphate rock for consumption for 1990 through 2003 were obtained from US GS Mineral Yearbook, Phosphate Rock (USGS 1994 through 2004).

The carbonate content of phosphate rock varies depending upon where the material is mined. Composition data for domestically mined and imported phosphate rock were provided by the Florid a Institute of Phosphate Research (FIPR 2003). Phosphate rock mined in Florida contai ns approximately 3.5 percent inorganic carbon (as CO 2 ), and phosphate rock imported from Morocco contains approximately 5 percent inorganic carbon (as CO 2 ). Calcined phosphate rock mined in North Carolina and Idaho contains approximately 1.5 percent and 1.0 percent inorganic carbon (as CO 2 ), respectively (see Table 4-36).

Carbonate content data for phosphate rock mined in Florida are used to calculate the CO 2 emissions from consumption of phosphate rock mined in Florida and North Carolina (86 percent of domestic production) and carbonate content data for phosphate rock mined in Morocco are used to calculate CO 2 emissions from consumption of imported phosphate rock. The CO 2 emissions calculation is based on the assumption that all of the domestic production of phosphate rock is used in uncalcined form. The USGS reported that one phosphate rock producer in Idaho is producing calcined phosphate rock; however, no pr oduction data were available for this single producer (USGS 2003). Carbonate content data for uncalcined phospha te rock mined in Idaho and Utah (14 percent of domestic production) were not available, and carbonate c ontent was therefore estimated from the carbonate content data for calcined phosphate rock mined in Idaho.

The CO 2 emissions calculation methodology is based on the assumption that all of the inorganic carbon (calcium carbonate) content of the phosphate rock reacts to CO 2 in the phosphoric acid production process and is emitted with the stack gas. The methodology also assumes that none of the organic carbon content of the phosphate rock is converted to CO 2 and that all of the organic carbon content remains in the phosphoric acid product.

Table 4-35: Phosphate Rock Domestic Production, Exports, and Imports (Gg) Location/Year 1990 1997 1998 1999 2000 2001 2002 2003 U.S. Production

FL & NC 42,494 36,604 38,000 35,900 31,900 28,100 29,800 31,300 ID & UT 7,306 5,496 5,640 5,540 5,470 4,730 4,920 5,100 Exports - FL & NC 6,240 335 378 272 299 9 62 64 Imports - Morocco 451 1,830 1,760 2,170 1,930 2,500 2,700 2,400 Total U.S. Consumption 44,011 43,595 45,022 43,338 39,001 35,321 37,358 38,746Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 150 Source: USGS 2004, 2003, 2002, 2001, 2000, 1999, 1998, 1997, 1996, 1995.

Table 4-36: Chemical Composition of Phosphate Rock (percent by weight)

Composition Central Florida North Florida North Carolina (calcined) Idaho (calcined) Morocco Total Carbon (as C) 1.60 1.76 0.76 0.60 1.56 Inorganic Carbon (as C) 1.0 0.93 0.41 0.27 1.46 Organic Carbon (as C) 0.60 0.83 0.35 — 0.1 Inorganic Carbon (as CO 2 ) 3.67 3.43 1.50 1.0 5.0 Source: FIPR 2003 (—): Assumed equal to zero. 

### Uncertainty

Phosphate rock production data used in the emission calcu lations are developed by the USGS through monthly and semiannual voluntary surveys of the eleven companies that owned phosphate rock mines during 2003. The phosphate rock production data ar e not considered to be a significant source of uncertainty, because all eleven of the domestic phosphate rock producers are reporting their annual production to the USGS. Data for imports for consumption and exports of phosphate rock used in the emission calculation are based on international trade data collected by the U.S. Census Bureau. These U.S. government economic data are not considered to be a significant source of uncertainty.

One source of potentially significant uncertainty in the calculation of CO 2 emissions from phosphoric acid production is the data for the carbonate composition of phos phate rock. The composition of phosphate rock varies depending upon where the material is mined, and may also vary over time. Only one set of data from the Florida Institute of Phosphate Research was available for th e composition of phosphate ro ck mined domestically and imported, and data for uncalcined phosphate rock mined in North Carolina and Idaho were unavailable. Inorganic carbon content (as CO 2 ) of phosphate rock could vary ±1 percent from the data included in Table 4-36, resulting in a variation in CO 2 emissions of ±20 percent. Another source of uncertainty is the disposition of the organic carbon content of the phosphate rock. A representative of the FIPR indicated that in the phosphoric acid production process the organic carbon content of the mined phosphate rock generally remains in the phosphoric acid product, which is what produces the color of the phosphoric acid product (FIPR 2003a). Organic carbon is therefore not included in the calculation of CO 2 emissions from phosphoric acid production. However, if, for example, 50 percent of the organic carbon content of th e phosphate rock were to be emitted as CO 2 in the phosphoric acid production process, the CO 2 emission estimate would increase by on the order of 50 percent.

A third source of uncertainty is the assumption that all domestically-produced phosphate rock is used in phosphoric acid production and used without first being calcined. Calc ination of the phosphate rock would result in conversion of some of the organic carbon in the phosphate rock into CO 2 . However, according to the USGS, only one producer in Idaho is currently calcining phosphate rock, and no data were available concerning the annual production of this single producer (USGS 2003). Total production of phosphate rock in Utah and Idaho combined amounts to approximately 14 percent of total domestic production in 2003. If it is assumed that 100 percent of the reported domestic production of phosphate rock for Idaho and Utah wa s first calcined, and it is assumed that 50 percent of the organic carbon content of the total production for Idaho and Utah was converted to CO 2 in the calcination process, the CO 2 emission estimate would increase on the order of 10 percent.

Finally, USGS indicated that 5 percent of domestically-p roduced phosphate rock is used to manufacture elemental phosphorus and other phosphorus-based chemicals, rather than phosphoric acid (USGS 2003a). According to USGS, there is only one domestic producer of elementa l phosphorus, in Idaho, and no data were available concerning the annual production of this single producer. Elemental phosphorus is produced by reducing phosphate rock with coal coke, and it is theref ore assumed that 100 percent of the carbona te content of the phosphate rock will be converted to CO 2 in the elemental phosphorus production process. The calculation for CO 2 emissions is based on the assumption that phosphate rock consumption, for purposes other than phosphoric acid production, results in CO 2 emissions from 100 percent of the inorganic carbon content in phosphate rock, but none from the organic carbon content. This phosphate rock, consumed for othe r purposes, constitutes approximately 5 percent of totalInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 151 phosphate rock consumption. If it were assumed that th ere are zero emissions from other uses of phosphate rock, CO 2 emissions would fall 5 percent.

The results of the Tier 2 quantitativ e uncertainty analysis are summarized in Table 4-37. Phosphoric acid production CO 2 emissions were estimated to be between 1.1 and 1.6 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 18 percent below and 18 percent above the emission estimate of 1.4 Tg CO 2 Eq.

Table 4-37: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Phosphoric Acid Production (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Phosphoric Acid Production CO 2 1.4 1.1 1.6 -18% +18%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.



### Recalculations Discussion

The historical activity data used to calculate the emissions from phosphoric acid production were updated for the year 2002. The change resulted in a decrease of less than 0.1 Tg CO 2 Eq. (less than 0.1 percent) in CO 2 emissions from phosphoric acid production for that year.


### Planned Improvements

The estimate of CO 2 emissions from phosphoric acid production could be improved th rough collection of additional data. Additional data is being collected concerning th e carbonate content of uncalcined phosphate rock mined in various locations in the United States. Additional resear ch will also be conducted con cerning the disposition of the organic carbon content of the phosphate rock in the phosphoric acid production process. Only a single producer of phosphate rock is calcining the product, and only a single producer is manufacturing elemental phosphorus. Annual production data for these single producer s will probably remain unavailable.



### 4.9. Ferroalloy Production (IPCC Source Category 2C2)

Carbon dioxide is emitted from the producti on of several ferroalloys. Ferroallo ys are composites of iron and other elements such as silicon, manganese, and chromium. When incorporated in alloy steels, ferroalloys are used to alter the material properties of the steel. Estimates from two types of ferrosilicon (25 to 55 percent and 56 to 95 percent silicon), silicon metal (about 98 percent silicon), and misce llaneous alloys (36 to 65 percent silicon) have been calculated. Emissions from the producti on of ferrochromium and ferromanganese are not included here because of the small number of manufacturers of these materials in the United States. Subsequently, government information disclosure rules prevent the publication of production data for these produc tion facilities. Similar to emissions from the production of iron and steel, CO 2 is emitted when metallurgical coke is oxidized during a high-temperature reaction with iron and the selected alloying element. Due to the strong reducing environment, CO is initially produced, and eventually oxidized to CO 2 . A representative reaction equation for the production of 50 percent ferrosilicon is given below:

7CO 2FeSi 7C 2SiO O Fe 2 3 2 + → + +

Emissions of CO 2 from ferroalloy production in 2003 were 1.4 Tg CO 2 Eq. (1,374 Gg) (see Table 4-38), an 11 percent increase from the previous year and a 31 percent reduction since 1990.

Table 4-38: CO 2 Emissions from Ferroalloy Production (Tg CO 2 Eq. and Gg)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 152 Year Tg CO 2 Eq. Gg 1990 2.0 1,980

1997 2.0 2,038 1998 2.0 2,027 1999 2.0 1,996 2000 1.7 1,719 2001 1.3 1,329 2002 1.2 1,237 2003 1.4 1,374



### Methodology

Emissions of CO 2 from ferroalloy production were calculated by multiplying annual ferroalloy production by material-specific emission factors. Emission factors taken from the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) were applied to ferroalloy pr oduction. For ferrosilicon a lloys containing 25 to 55 percent silicon and miscellaneous alloys (including primarily magnesium-ferrosilicon, but also including other silicon alloys) containing 32 to 65 percent silicon, an emission factor for 50 percent silicon ferrosilicon (2.35 tons CO 2 /ton of alloy produced) was applied. Additionally, for ferrosilicon alloys containing 56 to 95 percent silicon, an emission factor for 75 percent silicon ferrosilicon (3.9 tons CO 2 per ton alloy produced) was applied. The emission factor for silicon metal was assumed to be 4.3 tons CO 2 /ton metal produced. It was assumed that 100 percent of the ferroalloy production was produced using petroleu m coke using an electric arc furnace process (IPCC/UNEP/OECD/IEA 1997), although some ferroalloys may have been produced with coking coal, wood, other biomass, or graphite carbon inputs. The amount of petroleum coke consumed in ferroalloy production was calculated assuming that the petroleum coke used is 90 percent carbon and 10 percent inert material.

Ferroalloy production data for 1990 through 2003 (see Table 4-39) were obtained from the USGS through personal communications with Lisa Corathers (2004), th e Silicon Commodity Specialist, and through the Minerals Yearbook: Silicon Annual Report (USGS 1991, 1992, 1993, 1994, 1995, 1996, 1997, 1998, 1999, 2000, 2001, 2002, 2003). Until 1999, the USGS reported production of ferros ilicon containing 25 to 55 pe rcent silicon separately from production of miscellaneous alloys containing 32 to 65 percent silicon; beginning in 1999, the USGS reported these as a single category (see Table 4-39). The compositi on data for petroleum coke was obtained from Onder and Bagdoyan (1993).

Table 4-39: Production of Ferroalloys (Metric Tons)

Year Ferrosilicon 25%-55% Ferrosilicon 56%-95% Silicon Metal Misc. Allo y s (32-65%) 1990 321,385 109,566 145,744 72,442

1997 175,000 147,000 187,000 106,000 1998 162,000 147,000 195,000 99,800 1999 252,000 145,000 195,000 NA 2000 229,000 100,000 184,000 NA 2001 167,000 89,000 137,000 NA 2002 156,000 98,600 113,000 NA 2003 113,000 75,800 189,000 NA NA (Not Available)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 153 

### 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. Emissi ons from ferroalloys produced with wood or other biomass would not be counted under this source becau se wood-based carbon is of biogenic origin. 9 Even though emissions from ferroalloys produced with coking coal or graphite i nputs would be counted in national trends, they may be generated with varying amounts of CO 2 per unit of ferroalloy produced. The most accurate method for these estimates would be to base calculations on the amount of reducing agent used in the process, rather than the amount of ferroalloys produced. These data, however, were not available.

Also, annual ferroalloy production is now reported by the US GS in three broad categories: ferroalloys containing 25 to 55 percent silicon (including miscellaneous alloys), ferroalloys containing 56 to 95 percent silicon, and silicon metal. It was assumed that the IPCC emission factors apply to all of the ferroalloy production processes, including miscellaneous alloys. Finally, production data for silver y pig iron (alloys containing less than 25 percent silicon) are not reported by the USGS to avoid disclosing company proprietary data. Emissions from this production category, therefore, were not estimated.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-40. Ferroalloy Production CO 2 emissions were estimated to be between 1.3 and 1.4 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 3 percent below and 3 percent above the emission estimate of 1.4 Tg CO 2 Eq.

Table 4-40: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Ferroalloy Production (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Ferroalloy Production CO 2 1.4 1.3 1.4 -3% +3%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.



### 4.10. Carbon Dioxide Consumpti on (IPCC Source Category 2B5)

Carbon dioxide (CO 2 ) is used for a variety of commercial applications, including food processing, chemical production, carbonated beverage producti on, and refrigeration, and is also used in petroleum production for enhanced oil recovery (EOR). Carbon dioxide used for EO R is injected into the underground reservoirs to increase the reservoir pressure to enable additional petroleum to be produced.

For the most part, CO 2 used in non-EOR applications will eventually be released to the atmosphere, and for the purposes of this analysis CO 2 used in commercial applications other than EOR is assumed to be emitted to the atmosphere. Carbon dioxide used in EOR applications is c onsidered for the purposes of this analysis to remain sequestered in the underground formations into which the CO 2 is injected.

It is unclear to what extent the CO 2 used for EOR will be re-released to th e atmosphere. Carbon dioxide used in EOR applications is compressed at the CO 2 production source, transported by pipeline to the EOR field, and injected into wellheads. Potential CO 2 leakage pathways from CO 2 production, transportation, and injection process include fugitive emissions from the compressors, pipeline equipment, and wellheads. Also, the CO 2 used for EOR may show up at the wellhead after a few years of injecti on (Hangebrauk et al. 1992) or may be partially recovered

9 Emissions and sinks of biogenic carbon are accounted fo r in the Land-Use Change and Forestry chapter.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 154 as a component of crude oil produced from the wells (Denbury Resources 2003a). This CO 2 may be recovered and re-injected into the wellhead or separated from the petr oleum produced and vented to the atmosphere. More research is required to determine the amount of CO 2 that may escape from EOR operations through leakage from equipment, as a component of the crude oil produced, or as leakage directly from the reservoir through geologic faults and fractures or through improperly plugged or im properly completed wells. For the purposes of this analysis, it is assumed that all of the CO 2 produced for use in EOR applications is injected into reservoirs (i.e., there is no loss of CO 2 to the atmosphere during CO 2 production, transportation, or injection for EOR applications) and that all of the injected CO 2 remains sequestered within the reservoirs.

Carbon dioxide is produced from naturally occurring CO 2 reservoirs, as a by-product from the energy and industrial production processes (e.g., ammonia production, fossil fuel combustion, ethanol production), and as a by-product from the production of crude oil and natural gas, which contain naturally occurring CO 2 as a component. Carbon dioxide produced from naturally occurring CO 2 reservoirs and used in industrial applications other than EOR is included in this analysis. Neither by-product CO 2 generated from energy or industrial production processes nor CO 2 separated from crude oil and natural gas are include d in this analysis for a number of reasons.

Depending on the raw materials that are used, by-product CO 2 generated during energy and industrial production processes may already be accounted for in the CO 2 emission estimates from fossil fuel consumption (either from fossil fuel combustion or from non-energy uses of fossil fu els). For example, ammonia is primarily manufactured using natural gas as both a feedstock and energy source. Carbon dioxide emissions from natural gas combustion for ammonia production are accounted for in the CO 2 from Fossil Fuel Combustion source category of the Energy sector and, therefore, are not included under Carbon Dioxide Consumption. Likewise, CO 2 emissions from natural gas used as feedstock for ammonia production are accounted for in this chapter under the Ammonia Manufacture source category and, therefore, are not included here. 10

Carbon dioxide is produced as a by-product of crude oil and natural gas production. This CO 2 is separated from the crude oil and natural gas using gas processing equipment, and may be emitted directly to the atmosphere, or captured and reinjected into underground formations, used fo r EOR, or sold for other commercial uses. The amount of CO 2 separated from crude oil and natural gas has not been estimated. 11 Therefore, the only CO 2 consumption that is accounted for in this analysis is CO 2 produced from natural wells other th an crude oil and natural gas wells that is used in commercial applications other than EOR.

There are currently two facilitie s, one in Mississippi and one in New Mexico, producing CO 2 from natural CO 2 reservoirs for use in both EOR and in other commerc ial applications (e.g., chemical manufacturing, food production). There are other naturally occurring CO 2 reservoirs, mostly located in the western U.S. Facilities are producing CO 2 from these natural reservoirs, but they are only producing CO 2 for EOR applications, not for other commercial applications (Allis, R. et al. 2000). In 2003, the amount of CO 2 produced by the Mississippi and New Mexico facilities for commercial applications and subsequently emitted to the atmosphere were 1.3 Tg CO 2 Eq. (1,267 Gg) (see Table 4-41). This amount represents an increase of 29 percent from the previous year and an increase of 47 percent from emissions in 1990. This incr ease was due to an increase in the Mississippi facility’s reported production for use in other commercial applications.

Table 4-41: CO 2 Emissions from Carbon Dioxide Consumption (Tg CO 2 Eq. and Gg)

Year Tg CO 2 Eq. Gg

10 One ammonia manufacturer located in Oklahoma is reporte dly capturing approximately 35 MMCF/day (0.67 Tg/yr) of byproduct CO 2 for use in EOR applications. According to the me thodology used in this an alysis, this amount of CO 2 would be considered to be sequestered and not emitted to the atmo sphere. However, time series data for the amount of CO 2 captured from the ammonia plant for use in EOR applications are not available, and therefore all of the CO 2 produced by the ammonia plant is assumed to be emitted to the atmosphere and is acc ounted for in this chapter under Ammonia Manufacture. 11 The United States is in the process of developing a methodology to account for CO 2 emissions from natural gas systems and petroleum systems for inclusion in future Inventor y submissions. For more information see Annex 5.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 155 1990 0.9 860

1997 0.8 808 1998 0.9 912 1999 0.8 849 2000 1.0 957 2001 0.8 818 2002 1.0 979 2003 1.3 1,267 

### Methodology

Carbon dioxide emission estimates fo r 2001, 2002, and 2003 were based on pr oduction data for the two facilities currently producing CO 2 from naturally-occurring CO 2 reservoirs. Some of the CO 2 produced by these facilities is used for EOR and some is used in other commercial app lications (e.g., chemical manufacturing, food production). Carbon dioxide produced from these two facilities that was us ed for EOR is assumed to remain sequestered and is not included in the CO 2 emissions totals. It is assumed that 100 percent of the CO 2 production used in commercial applications other than EOR is eventually released into the atmosphere.

Carbon dioxide production da ta for the Jackson Dome, Mississippi facility in 2001, 2002, and 2003 and the percentage of total production that was used for EOR a nd in non-EOR applications were obtained from the Annual Reports for Denbury Resources, the operator of the f acility (Denbury Resources 2002, Denbury Resources 2003b, Denbury Resources 2004). Denbury Resources reported the average CO 2 production in units of MMCF CO 2 per day for 2001, 2002, and 2003, and reported the percentage of the total average annual production that was used for EOR. Carbon dioxide production data for the Bravo Dome, New Mexico facility were obtained from the New Mexico Bureau of Geology and Mineral Resources for the years 1990 through 2001 (Broadhead 2003). According to the New Mexico Bureau, the amount of CO 2 produced from Bravo Dome for use in non-EOR applications is less than one percent of total production (Broadhead 2003). Production data for 2002 and 2003 were not available for Bravo Dome, so it is assumed that the production values for those years are equal to the 2001 value.

Denbury Resources acquired the Jackson Dome facility in 2001 and CO 2 production data for the Jackson Dome facility are not available for years prior to 2001. Therefore, for 1990 through 2000, CO 2 emissions from CO 2 consumption in commercial applications other than EOR are estimated based on the total annual domestic consumption of CO 2 in commercial applications other than EOR in 2001 multiplied by the percentage of the total CO 2 consumed in commercial applications other than EOR that originated from CO 2 production at the Jackson Dome and Bravo Dome facilities in 2001. The total domestic commercial consumption of CO 2 in commercial applications other than EOR as reported by the U.S. Cens us Bureau was about 11,414 thousand metric tons in 2001. The total non-EOR CO 2 produced from the Jackson Dome and Bravo Dome natural reservoirs in 2001 was about 820 thousand metric tons, corresponding to 7.2 percent of the total domestic non-EOR commercial CO 2 consumption. This 7.2 percent factor was applied to the annual non-EOR commercial CO 2 consumption data for the years 1990 through 2000 to estimate annual CO 2 emissions from non-EOR commercial consumption of CO 2 produced from naturally occurring CO 2 reservoirs. The remaining 92.8 percent of the total annual non-EOR commercial CO 2 consumption is assumed to be accounted for in the CO 2 emission estimates from other categories (e.g., Ammonia Manufacture, CO 2 from Fossil Fuel Combustion, Wood Biomass and Ethanol Consumption).

Non-EOR commercial CO 2 consumption data (see Table 4-42) for years 1991 and 1992 were obtained from Industry Report 1992 (U.S. Census 1993). Consumption data are not available for 1990, and therefore CO 2 consumption data for 1990 is assumed to be equal to that for 1991. Consumption data for 1993 and 1994 were obtained from U.S. Census Bureau Manufacturing Profile, 1994 (U.S. Census 1995). Consumption data for 1996 through 2003 were obtained from the U.S. Census Bureau’s Industry Report, 1996, 1998, 2000, 2002, and 2003 (U.S. Census 1997, 1999, 2001, 2003, 2005).

Table 4-42: Carbon Dioxide Consumption (Metric Tons)

Year Metric Tons 1990 11,997,726Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 156 1997 11,268,219 1998 12,716,070 1999 11,843,386 2000 13,354,262 2001 11,413,889 2002 11,313,478 2003 11,103,777 

### Uncertainty

Uncertainty exists in the assumption that 92.6 percent of the total domestic CO 2 production for commercial consumption other than EOR from 1990 through 2000 came from energy and industrial production processes, while 7.4 percent came from naturally occurring CO 2 reservoirs. The allocation for thes e years is assumed to be the same allocation as for 2001, the last year for which data are available to calculate the allocation.

Uncertainty also exists with respect to the number of facilitie s that are currently producing CO 2 from naturally occurring reservoirs for commercial uses other than EOR, and for which the CO 2 emissions are not accounted for elsewhere. Research indicates that there are only two such facilities, which are in New Mexico and Mississippi, however, additional facilities may exist that have not been identified. In addition, it is possible that CO 2 recovery exists in particular production and end- use sectors that are not accounted for el sewhere. Such recovery may or may not affect the overall estimate of CO 2 emissions from that sector depending upon the end use to which the recovered CO 2 is applied. For example, res earch has identified one ammonia produc tion facility that is recovering CO 2 for use in EOR. Such CO 2 would be assumed to remain sequestered, however , time series data for the amount of recovered is not available and therefore all of the CO 2 produced by this plant is assumed to be emitted to the atmosphere and is allocated to Ammonia Manufacture. Recovery of CO 2 from ammonia production facilities for use in EOR is further discussed in this chapter under Ammonia Manufacture. Further research is required to determine whether CO 2 is being recovered from other facilities fo r application to end uses that are not accounted for elsewhere.

Uncertainty also exists in the assumption that 100 percent of the CO 2 used for EOR is sequestered. Operating experience with EOR systems indicates that 100 percent of the CO 2 used in EOR applications does not remain sequestered, but rather that it may be emitted to the atmosphere as leakage from equipment and reservoirs or recovered as a component of the crude oil produced. Potential sources of CO 2 emissions from EOR applications include leakage from equipment used to produ ce, transport, compress, and inject the CO 2 , leakage from equipment used to process the crude oil produced, separate the CO 2 from the crude oil and reco mpress and recycle [reinject] the CO 2 recovered from the crude oil. Other potential sources of CO 2 emissions from EOR applications include leakage from the reservoir itself, either through migration of the injected CO 2 beyond the boundaries of the reservoir, chemical interac tions between the injected CO 2 and the reservoir rock, and leakage via faults, fractures, oil and gas well bores, and water wells.

The results of the Tier 2 quantitativ e uncertainty analysis are summarized in Table 4-43. Carbon dioxide consumption CO 2 emissions were estimated to be between 1.2 and 1.3 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations ). This indicates a range of approximately 5 percent below to 5 percent above the emission estimate of 1.3 Tg CO 2 Eq.

Table 4-43: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Carbon Dioxide Consumption (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Carbon Dioxide Consumption CO 2 1.3 1.2 1.3 -5% +5%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 157 

### Recalculations Discussion

Carbon dioxide consumption values were updated for 2001 for the Bravo Dome, and for both 2001 and 2002 for the Jackson Dome. For the Bravo Dome, updated values ar e based on new production data from the facility. For Jackson Dome, previous production data was based on f ourth quarter reporting by Denbury Resources, which was annualized for the entire year. Updated production valu es are based on annual produc tion numbers reported by Denbury Resources. For 2001, updated production values resu lted in a 4 percent decrease in emissions, and for 2002 updated production values resulti ng in a 23 percent decrease in emissions. Based on updated 2001 consumption values for Jackson Dome, the percent of CO 2 emissions from CO 2 consumption in commercial applications other than EOR applied to years 1990 through 2000 decreased by 0.2 percent relative to the percent previously assumed. These changes resu lted in an average annual decrease in CO 2 emissions from CO 2 consumption of less than 0.1 Tg CO 2 Eq. (5.1 percent) for the years 1990 through 2002.



### 4.11. Petrochemical Production (IPCC Source Category 2B5)

The production of some petrochemicals results in the release of small amounts of CH 4 and CO 2 emissions. Petrochemicals are chemicals isolated or derived from petroleum or natural gas. Methane emissions are presented here from the production of carbon black, ethylene, ethylene dichloride, styrene, and methanol, while CO 2 emissions are presented here for only carbon black production. The CO 2 emissions from petrochemical processes other than carbon black are currently included in the Carbon Stored in Products from Non-Energy Uses of Fossil Fuels Section of the Energy chapter. The CO 2 from carbon black production is included here to allow for the direct reporting of CO 2 emissions from the process and direct accounting of the feedstocks used in the process.

Carbon black is an intensely black powder generated by the incomplete combustion of an aromatic petroleum or coal-based feedstock. Most carbon black produced in the United States is added to rubber to impart strength and abrasion resistance, and the tire industry is by far the la rgest consumer. Ethylene is consumed in the production processes of the plastics industry including polymers such as high, low, and linear low density polyethylene (HDPE, LDPE, LLDPE), polyvinyl chloride (PVC), ethylene dichloride, ethylene oxide, and ethylbenzene. Ethylene dichloride is one of the first manufactured chlorinated hydrocarbons with reported production as early as 1795. In addition to being an important intermediate in the synthesis of chlorinated hydrocarbons, ethylene dichloride is used as an industrial solvent and as a fuel additive. Styrene is a common precursor for many plastics, rubber, and resins. It can be found in many construction products, such as fo am insulation, vinyl flooring, and epoxy adhesives. Methanol is an alternative transportation fuel as well as a principle ingredient in windshield wiper fluid, paints, solvents, refrigerants, and disinfectants. In addition, me thanol-based acetic acid is used in making PET plastics and polyester fibers. The United States produces close to one quarter of the world’s supply of methanol.

Emissions of CO 2 and CH 4 from petrochemical production in 2003 were 2.8 Tg CO 2 Eq. (2,777 Gg) and 1.5 Tg CO 2 Eq. (72 Gg), respectively (see Table 4-44 and Table 4-45). While emissions of CO 2 from carbon black production in 2003 decreased by three percent from the previous year, there has been an overall increase in CO 2 emissions from carbon black production of 25 percent since 1990. Methane emissions from petrochemical production decreased by less than one percent from the previous year and increased 30 percent since 1990.

Table 4-44: CO 2 and CH 4 Emissions from Petrochemical Production (Tg CO 2 Eq.) Year 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 2.2 2.9 3.0 3.1 3.0 2.8 2.9 2.8 CH 4 1.2 1.6 1.7 1.7 1.7 1.4 1.5 1.5 Total 3.4 4.6 4.7 4.8 4.7 4.2 4.4 4.3

Table 4-45: CO 2 and CH 4 Emissions from Petrochemical Production (Gg) Year 1990 1997 1998 1999 2000 2001 2002 2003 CO 2 2,221 2,919 3,015 3,054 3,004 2,787 2,857 2,777 CH 4 56 78 80 81 80 68 72 72Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 158 

### Methodology

Emissions of CH 4 were calculated by multiplying annual estimates of chemical production by the appropriate emission factor, as follows: 11 kg CH 4 /metric ton carbon black, 1 kg CH 4 /metric ton ethylene, 0.4 kg CH 4 /metric ton ethylene dichloride, 12 4 kg CH 4 /metric ton styrene, and 2 kg CH 4 /metric ton methanol. Although the production of other chemicals may also result in CH 4 emissions, there were not sufficien t data available to estimate their emissions.

Emission factors were taken from the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). Annual production data for 1990 (see Table 4-46) were obtaine d from the Chemical Manufacturer’s Association Statistical Handbook (CMA 1999). Production data for 1991 through 2003 were obtained from the American Chemistry Council’s Guide to the Business of Chemistry (2003).

Table 4-46: Production of Selected Petrochemicals (Thousand Metric Tons) Chemical 1990 1997 1998 1999 2000 2001 2002 2003 Carbon Black 1,307 1,719 1,775 1,798 1,769 1,641 1,682 1,635 Ethylene 16,542 23,088 23,474 25,118 24,971 22,521 23,623 22,957 Ethylene Dichloride 6,282 10,324 11,080 10,308 9,866 9,294 9,288 9,952 Styrene 3,637 5,171 5,183 5,410 5,420 4,277 4,974 5,239 Methanol 3,785 5,743 5,860 5,303 4,876 3,402 3,289 3,166 Almost all carbon black in the United States is produced from petroleum-based or coal-based feedstocks using the “furnace black” process (European IPPC Bureau 2004). The furnace black pro cess is a partial combustion process in which a portion of the carbon black feedstock is combusted to provide energy to the process. Carbon black is also produced in the United States by the thermal cracking of acetylene-c ontaining feedstocks (“acetylene black process”) and by the thermal cracking of other hydrocarbons (“thermal black process”). One U.S. carbon black plant produces carbon black using the thermal black process, and one U.S. carbon black plant produces carbon black using the acetylene black pr ocess (The Innovation Group 2004).

The furnace black process produces carbon black from “carbon black feedstock” (also re ferred to as “carbon black oil”), which is a heavy aromatic oil that may be derived as a byproduct of either the petroleum refining process or the metallurgical (coal) coke production process. For the production of both petroleum-derived and coal-derived carbon black, the “primary feedstock” (i.e ., carbon black feedstock) is injected into a furnace that is heated by a “secondary feedstock” (generally natural gas). Both th e natural gas secondary feedstock and a portion of the carbon black feedstock are oxidized to provide heat to the production process and pyrolyze the remaining carbon black feedstock to carbon black. The “tail gas” from the furnace black process contains CO 2 , carbon monoxide, sulfur compounds, CH 4 , and non-methane volatile organic compounds. A por tion of the tail gas is generally burned for energy recovery to heat the downstream carbon black product dryers. The remaining tail gas may also be burned for energy recovery, flared, or vented uncontrolled to the atmosphere.

The calculation of the carbon lost during the production process is the basis for determining the amount of CO 2 released during the process. The carbon content of national carbon black production is subtracted from the total amount of carbon contained in primary and secondary carbon black feedstock to find the amount of carbon lost during the production process. It is a ssumed that the carbon lost in this pro cess is emitted to the atmosphere as either CH 4 or CO 2 . The carbon content of the CH 4 emissions, estimated as described above, is subtracted from the total carbon lost in the process to cal culate the amount of carbon emitted as CO 2 . The total amount of primary and secondary carbon black feedstock consumed in the process (see Table 4-47) is estimated using a primary feedstock consumption factor and a secondary feedstock consumpti on factor estimated from U.S. Census Bureau (1999 and 2004) data. The average carbon black feedstock consumption factor for U.S. carbon black production is 1.43 metric

12 The emission factor obtained from IPCC/UNEP/OECD/IEA (1997), page 2.23 is assumed to have a misprint; the chemical identified should be ethylene dichloride (C 2 H 4 Cl 2 ) rather than dichloroethylene (C 2 H 2 Cl 2 ).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 159 tons of carbon black feedstock consumed per metric ton of carbon black produced. The average natural gas consumption factor for U.S. carbon black production is 341 nor mal cubic meters of natural gas consumed per metric ton of carbon black produced. The amount of carbon contained in the primary and secondary feedstocks is calculated by applying the respective carbon contents of the feedstocks to the respective levels of feedstock consumption.

Table 4-47: Carbon Black Feedstock (Primary Feedstoc k) and Natural Gas Feedstock (Secondary Feedstock) Consumption (Thousand Metric Tons) Activity 1990 1997 1998 1999 2000 2001 2002 2003 Primary Feedstock 1,864 2,450 2,530 2,563 2,521 2,339 2,398 2,331 Secondary Feedstock 302 378 397 410 415 408 379 388 For the purposes of emissions estimation, 100 percent of the primary carbon black feedstock is assumed to be derived from petroleum refining byproducts. Carbon black feedstock derived from metallurgical (coal) coke production (e.g., creosote oil) is also used for carbon black production; however, no data are available concerning the annual consumption of coal-derived carbon black feedstock. Carbon black feedstock derived from petroleum refining byproducts is assumed to be 89 percent elemental carbon (Srivastava et al. 1999). It is assumed that 100 percent of the tail gas produced from the carbon black production process is combusted and that none of the tail gas is vented to the atmosphere uncontrolled. The furnace black process is assumed to be the only process used for the production of carbon black because of the lack of data concerning the relatively small amount of carbon black produced using the acetylene black and thermal black processes. The carbon black produced from the furnace black process is assumed to be 97 percent elemental carbon (Othmer et al. 1992).


### Uncertainty

The CH 4 emission factors used for petrochemical production are based on a limited number of studies. Using plantspecific factors instead of av erage factors could increase th e accuracy of the emission es timates; however, such data were not available. There may also be other significant sources of CH 4 arising from petrochemical production activities that have not been included in these estimates.

The results of the quantitative uncertainty analysis for the CO 2 emissions from carbon black production calculation are based on feedstock consumption, import and export da ta, and carbon black production data. The composition of carbon black feedstock varies depending upon the specifi c refinery production process, and therefore the assumption that carbon black feedstock is 89 percent carbon gives rise to uncertainty. Also, no data are available concerning the consumption of coal-derived carbon black feedstock, so CO 2 emissions from the utilization of coalbased feedstock are not included in the emission estimate. In addition, other data sources indicate that the amount of petroleum-based feedstock used in carbon black produc tion may be underreported by the U.S. Census Bureau. Finally, the amount of carbon black produced from the ther mal black process and acetyl ene black process, although estimated to be a small percentage of the total production, is not known. Therefore, there is some uncertainty associated with the assumption that all of the carbon black is produced using the furnace black process.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-48. Petrochemical production CH 4 emissions were estimated to be between 1.4 and 1.6 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 7 percent below to 7 percent above the emission estimate of 1.5 Tg CO 2 Eq. Petrochemical production CO 2 emissions were estimated to be between 2.8 and 3.1 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 10 percent below to 10 percent above the emission estimate of 2.8Tg CO 2 Eq.

Table 4-48: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Petrochemical Production and CO 2 Emissions from Carbon Black Production (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 160 Lower Bound Upper Bound Lower Bound Upper Bound Petrochemical Production CH 4 1.5 1.4 1.6 -7% +7% Petrochemical Production CO 2 2.8 2.5 3.1 -10% +10%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.



### Recalculations Discussion

In previous inventories, CO 2 emissions from carbon black production were not calculated and reported separately in the Industrial Processes sector, but were included in the Carbon Stored in Products from Non-Energy Uses of Fossil Fuels in the Energy sector. Although the CH 4 emissions from petrochemical production did not change for 1990 through 2002 compared to the previous Inventory, the addition of CO 2 emissions from carbon black production caused a large increase in petrochemical production emissions for every year of the time series. Overall, the change resulted in an average annual increase of 2.7 Tg CO 2 Eq. (183 percent) in combined CO 2 and CH 4 emissions from petrochemical production for the period 1990 through 2002.



### 4.12. Silicon Carbide Production (IPCC Source Category 2B4)

Methane is emitted from the production of silicon carbide, a ma terial used as an industrial abrasive. To make silicon carbide (SiC), quartz (SiO 2 ) is reacted with carbon in the form of petroleum coke. During this reaction, methane is produced from volatile compounds in the petroleum coke. While CO 2 is also emitted from the production process, the requisite data were unavailable for these calculations. CO 2 emissions associated with the use of petroleum coke in the silicon carbide process ar e accounted for in the Non-en ergy Uses of Fossil Fuels section in the Energy Chapter. Emissions of CH 4 from silicon carbide production in 2003 were 0.4 Gg CH 4 (0.01 Tg CO 2 Eq.) (see Table 4-49).

Table 4-49: CH 4 Emissions from Silicon Carbide Production (Tg CO 2 Eq. and Gg)

Year Tg CO 2 Eq. Gg 1990 + 1

1997 + 1 1998 + 1 1999 + 1 2000 + 1 2001 + + 2002 + + 2003 + + + Does not exceed 0.05 Tg CO 2 Eq. or 0.5 Gg


### Methodology

Emissions of CH 4 were calculated by multiplying annual silicon car bide production by an em ission factor (11.6 kg CH 4 /metric ton silicon carbide). This emission factor was derived empirically from measurements taken at Norwegian silicon carbide plan ts (IPCC/UNEP/OECD/IEA 1997).

Production data for 1990 through 2003 (see Table 4-50) were obtained from the Minerals Yearbook: Volume IMetals and Minerals, Manufactured Abrasives (USGS 1991, 1992, 1993, 1994, 1995, 1996, 1997, 1998, 1999, 2000, 2001, 2002, 2003, 2004).

Table 4-50: Production of S ilicon Carbide (Metric Tons) Year Metric Tons 1990 105,000 1991 78,900Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 161 1992 84,300 1993 74,900 1994 84,700 1995 75,400 1996 73,600 1997 68,200 1998 69,800 1999 65,000 2000 45,000 2001 40,000 2002 30,000 2003 35,000 

### Uncertainty

The emission factor used for silic on carbide production was ba sed on one study of Norwegian plants. The applicability of this factor to average U.S. practices at silic on carbide plants is uncertain. An alternative would be to calculate emissions based on the quantity of petroleum coke used during the production process rather than on the amount of silicon carbide produced. Howeve r, these data were not available.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-51. Silicon carbide production CO 2 emissions were estimated to be between 0.008 and 0.01Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This i ndicates a range of approximately 10 percent below to 10 percent above the emission estimate of 0.009 Tg CO 2 Eq.

Table 4-51: Tier 2 Quantitative Uncertainty Estimates for CO 2 Emissions from Silicon Carbide Production (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Silicon Carbide Production CO 2 + + + -10% +10%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval. + Does not exceed 0.05 Tg CO 2 Eq. or 0.5 Gg.



### 4.13. Nitric Acid Production (IPCC Source Category 2B2)

Nitric acid (HNO 3 ) 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, N 2 O is formed as a by-product and is released from reactor vents into the atmosphere.

Currently, the nitric acid industry controls for NO and NO 2 (i.e., NO x ). As such, the industry uses a combination of non-selective catalytic reduction (NSCR) and selective catal ytic reduction (SCR) technologies. In the process of destroying NO x , NSCR systems are also very effective at destroying N 2 O. However, NSCR units are generally not preferred in modern plants because of high energy costs and asso ciated high gas temperatur es. NSCRs were widely installed in nitric plants built between 1971 and 1977. A pproximately 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 N 2 O emissions.

Nitrous oxide emissions from this source were estimated to be 15.8 Tg CO 2 Eq. (51.1 Gg) in 2003 (see Table 4-52). Emissions from nitric acid production have decreased by 11 percent since 1990, with the trend in the time series closely tracking the changes in production.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 162 Table 4-52: N 2 O Emissions from Nitric Acid Production (Tg CO 2 Eq. and Gg)

Year Tg CO 2 Eq. Gg 1990 17.8 58

1997 21.2 68 1998 20.9 67 1999 20.1 65 2000 19.6 63 2001 15.9 51 2002 17.2 56 2003 15.8 51 

### Methodology

Nitrous oxide emissions were calculated by multip lying nitric acid producti on by the amount of N 2 O emitted per unit of nitric acid produced. The emission factor was determined as a weighted average of 2 kg N 2 O / metric ton HNO 3 for plants using non-selective catalytic reduction (NSCR) systems and 9.5 kg N 2 O / metric ton HNO 3 for plants not equipped with NSCR (Choe et al. 1993). In the process of destroying NO x , NSCR systems destroy 80 to 90 percent of the N 2 O, which is accounted for in the emission factor of 2 kg N 2 O / metric ton HNO 3 . An estimated 20 percent of HNO 3 plants in the United States are equipped with NSCR (Choe et al. 1993). Hence, the emission factor is equal to (9.5 × 0.80) + (2 × 0.20) = 8 kg N 2 O per metric ton HNO 3 . Nitric acid production data for 1990 (see Table 4-53) was obtained from Chemical and Engineering News , “Facts and Figures” (C&EN 2001). Nitric acid production data for 1991 through 1992 (see Table 4-53) were obtained from Chemical and Engineering News , “Facts and Figures” (C&EN 2002). Nitric acid production data for 1993 through 2003 were obtained from Chemical and Engineering News , “Facts and Figures” (C&EN 2004). The emission factor range was taken from Choe et al. (1993).

Table 4-53: Nitric Acid Production (Gg) Year Gg 1990 7,196 1991 7,191 1992 7,379 1993 7,486 1994 7,904 1995 8,018 1996 8,349 1997 8,556 1998 8,421 1999 8,113 2000 7,898 2001 6,416 2002 6,939 2003 6,388



### Uncertainty

The uncertainties contained in these estim ates are primarily due to the current organization within the nitric acid industry. A significant degree of uncerta inty exists in nitric acid production fi gures because nitric acid plants are often part of larger production facilities, such as fertilizer or explosives manufacturing. As a result, only a small quantity of nitric acid is sold on the market, making pr oduction quantities difficult to tr ack. Emission factors are also difficult to determine because of the large number of plants using a diverse range of technologies.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 163 The results of the Tier 1 quantitative uncertainly analysis are summarized in Table 4-54. Nitric acid production N 2 O emissions were estimated to be between 13.2 and 18.5 Tg CO 2 Eq. at the 95 percent confidence level. This indicates a range of 17 percent above to below the 2003 emission estimate of 15.8 Tg CO 2 Eq.

Table 4-54: Tier 1 Quantitative Uncertainty Estimates for N 2 O Emissions from Nitric Acid Production (Tg CO 2 Eq. and Percent)

Source Gas Year 2003 Emissions (Tg CO 2 Eq.) Uncertainty (%) Uncertainty Range Relative to 2003 Emission Estimate (Tg CO 2 Eq.) Lower Bound Upper Bound Nitric Acid Production N 2 O 15.8 17% 13.2 18.5



### Recalculations Discussion

The nitric acid production values for all years 1993 through 2002 were updated using newly published figures (C&EN 2004). Published figures remained consistent for all years of the historical time series except 2002. The updated production data for 2002 resulted in an increase of 0.5 Tg CO 2 Eq. (2.8 percent) in N 2 O emissions from nitric acid production for that year.


### Planned Improvements

Planned improvements are focused on assessing the plant-by-plant implementation of NO x abatement technologies to more accurately match plant production capacities to appr opriate emission factors, in stead of using a national profiling of abatement implementation. Also, any large scale updates to abatement configurations would be useful in revising the national profile.



### 4.14. Adipic Acid Production (IPCC Source Category 2B3)

Adipic acid production is an anthropogenic source of N 2 O emissions. Worldwide, few adipic acid plants exist. The United States is the major producer, with three companies in four locations accounting for approximately one-third of world production. Adipic acid is a white crystalline solid used in the manufacture of sy nthetic fibers, coatings, plastics, urethane foams, elastomers, and synthetic lubricants. Commercially, it is the most important of the aliphatic dicarboxylic acids, which are used to manufacture polyesters. Approximately 90 percent of all adipic acid produced in the United States is used in the production of nylon 6,6 (CMR 2001). Food grade adipic acid is also used to provide some foods with a “tangy” flavor (Thiemens and Trogler 1991).

Adipic acid is produced through a two-stage process during which N 2 O is generated in the second stage. The first stage of manufacturing usually involves the oxidation of cyclohexane to form a cyclohexanone/cyclohexanol mixture. The second stage involves oxidizing this mixture with nitric acid to produce adipic acid. Nitrous oxide is generated as a by-product of the nitr ic acid oxidation stage and is emitted in the waste gas stream (Thiemens and Trogler 1991). Process emissions from the production of adipic acid vary with the types of technologies and level of emission controls employed by a facility. In 1990, two of the thr ee major adipic acid-producing plants had N 2 O abatement technologies in place and, as of 1998, the three major adipic acid production facilities had control systems in place. 13 Only one small plant, representing approxima tely two percent of production, does not control for N 2 O (Reimer 1999).

Nitrous oxide emissions from this adipic acid production were estimated to be 6.0 Tg CO 2 Eq. (19.4 Gg) in 2003 (see Table 4-55).

13 During 1997, the N 2 O emission controls installed by the third plant operated for approximately a quarter of the year.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 164 Table 4-55: N 2 O Emissions from Adipic Acid Production (Tg CO 2 Eq. and Gg)

Year Tg CO 2 Eq. Gg 1990 15.2 49

1997 10.3 33 1998 6.0 19 1999 5.5 18 2000 6.0 20 2001 4.9 16 2002 5.9 19 2003 6.0 19

National adipic acid production has increased by approxi mately 28 percent over the period of 1990 through 2003, to approximately one million metric tons. At the same time, emissions have been significantly reduced due to the widespread installation of pollution control measures.


### Methodology

For two production plants, 1990 to 2002 emission estimates were obtained directly from the plant engineer and account for reductions due to control sy stems in place at these plants duri ng the time series (Childs 2002, 2003). These estimates were based on continuous emissions monitoring equipment insta lled at the two facilities. Measured estimates for 2003 were unavailable and, thus, were calcu lated by applying a 1.8 percent production growth rate representative of the industry (see discussion below on sour ces of production data). For the other two plants, N 2 O emissions were calculated by multiplying adipic acid production by an em ission factor (i.e., N 2 O emitted per unit of adipic acid produced) and adjusting for the actual percentage of N 2 O released as a result of plant-specific emission controls. On the basis of experiments, the overall reaction stoichiometry for N 2 O production in the preparation of adipic acid was estimated at approximately 0.3 MT of N 2 O per MT of product (Thiemens and Trogler 1991). Emissions are estimated using the following equation:

N 2 O emissions = [production of adipic acid (MT of adipic acid)] × [0.3 MT N 2 O / mt adipic acid] × [1 – (N 2 O destruction factor × abatement system utility factor) ]

The “N 2 O destruction factor” represents the percentage of N 2 O emissions that are dest royed by the installed abatement technology. The “abatement sy stem utility factor” represents the pe rcentage of time th at the abatement equipment operates during the annual production period. Over all, in the United States, two of the plants employ catalytic destruction, one plant employs thermal destruction, and the smallest plant uses no N 2 O abatement equipment. The N 2 O abatement system destruction factor is assume d to be 95 percent for catalytic abatement and 98 percent for thermal abatement (Reimer et al. 1999, Reimer 1999). For the one plant that uses thermal destruction and for which no reported plant-specific emissions are available, the abatement system utility factor is assumed to be 98 percent.

In order to calculate emissions for th e two plants where direct emissions m easurements were not available, plantspecific production data needed to be es timated since it was unavailable due to reasons of confidentiality. In order to calculate plant-specific production for the two plants, national adipic acid production was allocated to the plant level using the ratio of their known plan t capacities to total national capacity for all U.S. plants. The estimated plant production for the two plants was then used for calculating emissions as described above.

National adipic acid production data (see Table 4-56) for 1990 through 2002 were obtained from the American Chemistry Council (ACC 2003). Production Data for 2003 were estimated based on an abstract from a Chemical Economics Handbook report entitled “ Adipic Acid ” indicating that production will in crease by an annual average of 1.8 percent from year 2002 to 2006. Plant capacity data for 1990 through 1994 were obtained from Chemical and Engineering News , “Facts and Figures” and “Production of Top 50 Chemicals” (C&EN 1992, 1993, 1994, 1995). Plant capacity data for 1995 and 1996 were kept the same as 1994 data. The 1997 plant capacity data were taken from Chemical Market Reporter “Chemical Profile: Adipic Acid” (CMR 1998). The 1998 plant capacity data for all four plants and 1999 plant capacity data for three of the plants were obtained from Chemical Week, ProductInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 165 focus: adipic acid/adiponitrile (CW 1999). Plant capacity data for 2000 for three of the plants were updated using Chemical Market Reporter , “Chemical Profile: Adipic Acid” (CMR 2001). For 2001 through 2003, the plant capacities for these three plants were kept the same as the year 2000 capacities. Plant capacity data for 1999 to 2003 for the one remaining plant was kept the same as 1998.

Table 4-56: Adipic Acid Production (Gg)

Year Gg 1990 735 1991 708 1992 724 1993 769 1994 821 1995 830 1996 839 1997 871 1998 862 1999 907 2000 925 2001 835 2002 921 2003 937



### Uncertainty

The emission factor for adipic acid was based on experiments (Thiemens and Trogler 1991) that attempt to replicate the industrial process and, thereby, m easure the reaction stoichiometry for N 2 O production in the preparation of adipic acid. However, the extent to which the lab results are representative of actual industrial emission rates is not known.

The allocation of national production data for the two facilities where direct emission measurements were unavailable creates a degree of uncertainty in the adipic acid production data as all plants are assumed to operate at equivalent utilization levels as represented by their capacities. Also, plant capacity reference data is inconsistently available from year to year, which can affect the uncertainty of the allocated production through the time series.

A 5 percent uncertainty level was associated with the activity data available for the two plants that reported emissions. For the remaining two plants, a 20 percent uncertainty level was assumed for production. The emission factor uncertainty for each of these two plants was estimated separately to acc ount for the differences in the use of abatement technologies. For the plant that uses no abatement technology, a 10 percent IPCC-default emission factor uncertainty was assumed appropriate. The abatement factor uncertainty used for the second plant was based on a 5 percent IPCC estimate for the N 2 O destruction factor and an assumed 5 per cent uncertainty in th e abatement system utility factor (IPCC 2000). These two estim ates result in an overall uncertainty associated with abatement potential of 7 percent. This abatement uncerta inty, combined with the 10 percent IPCC default uncertainty value associated with the emissions factor for unabated emissions, results in an overall 12 percent emission factor uncertainty. Combining the reporting plants emissions uncertainty with the activity data uncertainty and the emission factor uncertainty for the remaining two plants yields an overall uncertainty for the inventory estimate equal to 9 percent of 2003 emissions (see Table 4-57).

The results of the Tier 1 quantitative uncertainly analysis are summarized in Table 4-57. Adipic acid production N 2 O emissions were estimated to be between 5.5 and 6.5 Tg CO 2 Eq. at the 95 percent confidence level. This indicates a range of 9 percent above to below the 2003 emission estimate of 6.0 Tg CO 2 Eq.

Table 4-57: Tier 1 Quantitative Uncertainty Estimates for N 2 O Emissions from Adipic Acid Production (Tg CO 2 Eq. and Percent) Source Gas Year 2003 Uncertainty Uncertainty Range Relative toInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 166 Emissions (Tg CO 2 Eq.) (%) 2003 Emission Estimate (Tg CO 2 Eq.) Lower Bound Upper Bound Adipic Acid Production N 2 O 6.0 9% 5.5 6.5



### QA/QC and Verification

In addition to performing Tier 1 level QA/QC and verificati on, trends in the production of the synthetic nylon fibers industry were compared to trends in adipic acid production to confirm a reasonable agreement, since almost 90 percent of the adipic acid produced in the United States is used in the production of nylon 6,6.


### Planned Improvements

Improvement efforts will be focused on obtaining direct measurement data from the remaining two plants when and if they become available. If they become available, cross verification with top-down approaches will provide a useful Tier 2 level QA check. Also, additional informa tion on the actual performance of the latest catalytic and thermal abatement equipment at plants with continuous emission monitoring may support the re-evaluation of current default abatement values.



### 4.15. Substitution of Ozone Depleti ng Substances (IPCC Source Category 2F)

Hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs) are used as alternatives to several classes of ozonedepleting substances (ODSs) that are being phased out under the terms of the Montreal Protocol and the Clean Air Act Amendments of 1990. 14 Ozone depleting substances

⎯ chlorofluorocarbons (CFCs), halons, carbon tetrachloride, methyl chloroform, and hydrochlorofluorocarbons (HCFCs)

⎯ are used in a variety of industrial applications including re frigeration and air cond itioning equipment, solvent cleaning, foam production, sterilization, fire extinguishing, and aerosols. Although HFCs and PFCs, are not harmful to the stratospheric ozone layer, they are potent greenhouse gases. Emission estimates for HFCs and PFCs used as substitutes for ODSs are provided in Table 4-58 and Table 4-59.

Table 4-58: Emissions of HFCs and PFCs from ODS Substitution (Tg CO 2 Eq.) Gas 1990 1997 1998 1999 2000 2001 2002 2003 HFC-23 + + + 0.1 0.1 0.1 0.1 0.1 HFC-32 + 0.2 0.3 0.3 0.3 0.3 0.3 0.4 HFC-125 + 7.0 8.8 10.0 11.2 12.3 13.4 14.7 HFC-134a + 31.4 36.7 42.2 48.0 52.7 56.9 60.5 HFC-143a + 3.5 5.2 6.6 8.2 10.1 12.2 14.6 HFC-236fa + 0.1 0.4 0.9 1.4 1.8 2.1 2.3 CF 4 + + + + + + + + Others* 0.4 4.2 5.2 5.7 5.9 6.1 6.5 6.9 Total 0.4 46.5 56.6 65.8 75.0 83.3 91.5 99.5 + Does not exceed 0.05 Tg CO 2 Eq. * Others include HFC-152a, HFC-227ea, HFC-245fa, HFC-4310mee, and PFC/PFPEs, th e latter being a proxy for a diverse collection of PFCs and perfluoropolyethers (PFPEs) employed for solvent applications. For es timating purposes, the GWP value used for PFC/PFPEs was based upon C 6 F 14 . Note: Totals may not sum due to independent rounding.

Table 4-59: Emissions of HFCs and PFCs from ODS Substitution (Mg)

14 [42 U.S.C § 7671, CAA § 601]Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 167 Gas 1990 1997 1998 1999 2000 2001 2002 2003 HFC-23 + 3 4 4 5 5 6 6 HFC-32 + 289 430 439 441 459 492 541 HFC-125 + 2,516 3,134 3,571 4,004 4,385 4,777 5,246 HFC-134a + 24,136 28,202 32,491 36,888 40,512 43,798 46,559 HFC-143a + 926 1,369 1,738 2,162 2,647 3,203 3,834 HFC-236fa + 9 64 142 214 281 341 369 CF 4 + + 1 1 1 1 2 2 Others* M M M M M M M M M (Mixture of Gases) + Does not exceed 0.5 Mg * Others include HFC-152a, HFC-227ea, HFC-245fa, HFC-4310mee and PFC/PFPEs, the latter being a proxy for a diverse collection of PFCs and perfluoropolyethers (PFPE s) employed for solvent applications.

In 1990 and 1991, the only significant emi ssions of HFCs and PFCs as substitutes to ODSs were relatively small amounts of HFC-152a

⎯ a component of the refrigerant blend R-500 used in chillers

⎯ and HFC-134a in refrigeration end-uses. Beginning in 1992, HFC-134a was used in growing amounts as a refrigerant in motor vehicle air-conditioners and in refri gerant blends such as R-404A. 15 In 1993, the use of HFCs in foam production and as an aerosol propellant began, and in 1994 these compounds also found applications as solvents and sterilants. In 1995, ODS substitutes for halons entered widespread use in the United States as halon production was phasedout.

The use and subsequent emissions of HFCs and PFCs as ODS substitutes has been increasing from small amounts in 1990 to 99.5 Tg CO 2 Eq. in 2003. This increase was in large part the result of efforts to phase out CFCs and other ODSs in the United States. In the short term, this trend is expected to continue, a nd will likely accelerate over the next decade as HCFCs, which are interim substitutes in many applications, are them selves phased-out under the provisions of the Copenhagen Amendments to the Montreal Protocol . Improvements in the technologies associated with the use of these gases and the introduction of altern ative gases and technologies, however, may help to offset this anticipated increase in emissions

. 

### Methodology

A detailed Vintaging Model of ODS-containing equipm ent and products was used to estimate the actual

⎯ versus potential

⎯ emissions of various ODS substitutes, including HFCs and PFCs. The name of the model refers to the fact that the model tracks the use and emissions of vari ous compounds for the annual “vintages” of new equipment that enter service in each end-use. This Vintaging Model predicts ODS and ODS substitute use in the United States based on modeled estimates of the quantity of equipment or products sold each year c ontaining 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 a pplying annual leak rates and release pr ofiles, which account for the lag in emissions from equipment as they leak over time. By aggregating the data fo r more than 40 different end-uses, the model produces estimates of annual use and emissions of each compound. Further in formation on the Vintaging Model is contained in Annex 3.8.


### Uncertainty

Given that emissions of ODS substitute s occur from thousands of different kinds of equipment and from millions of point and mobile sources throughout the United States, emission estimates must be made using analytical tools such as the Vintaging Model or the methods outlined in IPCC/UNEP/OECD/IEA (1997). Though the model is more comprehensive than the IPCC default me thodology, significant uncertainties still exis t with regard to the levels of

15 R-404A contains HFC-125, HFC-143a, and HFC-134a.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 168 equipment sales, equipment characteristics, and end-use emissions profiles that were used to estimate annual emissions for the various compounds.

The Vintaging Model estimates emissions from over 40 end- uses, but the uncertainty estimation was performed on only the top 14 end-uses, which account for 95 percent of emissions from this source category. In order to calculate uncertainty, functional forms were developed to simplify so me of the complex “vintaging” aspects of some end-use sectors, especially with respect to refrigeration and ai r-conditioning, and to a lesser degree, fire extinguishing. These sectors calculate emissions based on the entire lifetime of equipment, not just equipment put into commission in the current year, which necessitated these simplifying equations. The functional forms used variables that included growth rates, emission factors, transition from ODSs, change in charge size as a result of the transition, disposal quantities, disposal emission rates, and either st ock for the current year or original ODS consumption. Uncertainty was estimated around each vari able within the functional forms ba sed on expert judgment, and a Monte Carlo analysis was performed.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-60. Substitution of ozone depleting substances HFC and PFC emissions were estimated to be between 89.9 and 108.4 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 10 percent below to 10 percent above the emission estimate of 99.5 Tg CO 2 Eq.

Table 4-60: Tier 2 Quantitative Uncertainty Estimates for HFC and PFC Emissions from ODS Substitution (Tg CO 2 Eq. and Percent)

Source Gases 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a

(Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Substitution of Ozone Depleting Substances HFCs and PFCs 99.5 89.9 108.4 -10% +9%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval. 

### Recalculations Discussion

An extensive review of the chemical substitution trends, market sizes, growth rates, and charge sizes, together with input from industry representatives, resulted in updated a ssumptions for the Vintaging Model. These changes resulted in an average annual net increase of less than 0.1 Tg CO 2 Eq. (4.1 percent) in HFC and PFC emissions from the substitution of ozone depleting s ubstances for the period 1990 through 2002.



### 4.16. HCFC-22 Production (IP CC Source Category 2E1)

Trifluoromethane (HFC-23 or CHF 3 ) is generated as a by-product during the manufacture of chlorodifluoromethane (HCFC-22), which is primarily employed in refrigeration and air conditioning systems and as a chemical feedstock for manufacturing synthetic polymers. Between 1990 and 2000, U.S. production of HCFC-22 rose significantly as HCFC-22 replaced chlorofluorocarbons (C FCs) in many applications. Si nce 2000, however, U.S. production has declined to levels near those of the early to mid 1990s. Because HCFC- 22 depletes stratospheric ozone, its production for non-feedstock uses is scheduled to be phased out by 2020 under the U.S. Clean Air Act. 16 Feedstock production, however, is pe rmitted to continue indefinitely.

16 As construed, interpreted, and app lied in the terms and conditions of the Montreal Protocol on Substances that Deplete the Ozone Layer . [42 U.S.C. §7671m(b), CAA §614]Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 169 HCFC-22 is produced by the reaction of chloroform (CHCl 3 ) and hydrogen fluoride (HF) in the presence of a catalyst, SbCl 5 . The reaction of the catalyst and HF produces SbCl x F y , (where x + y = 5), which reacts with chlorinated hydrocarbons to replace chlo rine atoms with fluorine. The HF and chloroform are introduced by submerged piping into a conti nuous-flow reactor that contai ns the catalyst in a hydro carbon mixture of chloroform and partially fluorinated intermediates. The vapors leaving the reactor contain HC FC-21 (CHCl 2 F), HCFC-22 (CHClF 2 ), HFC-23 (CHF 3 ), HCl, chloroform, and HF. The under-fluorinated intermediates (HCFC-21) and chloroform are then condensed and returned to the reactor, along with residual catalyst, to undergo further fluorination. The final vapors leaving the condenser ar e primarily HCFC-22, HFC-23, HCl and residual HF. The HCl is recovered as a useful byproduct, and the HF is removed. Once separated from HCFC-22, the HFC-23 is generally vented to the atmosphere as an unwanted by-p roduct, or may be captured for use in a limited number of applications.

Emissions of HFC-23 in 2003 were estimated to be 12.3 Tg CO 2 Eq. (1.1 Gg). This quantity represents a 38 percent decline from 2002 emissions and a 65 percent decline from 1990 emissions. Both declines are primarily due to the steady decline in the emission rate of HFC-23 (i.e., the amount of HFC-23 emitted per kilogram of HCFC-22 manufactured). Three HCFC-22 production plants operated in the United States in 2003, two of which used thermal oxidation to significantly lower their HFC-23 emissions.

Table 4-61: HFC-23 Emissions from HCFC-22 Production (Tg CO 2 Eq. and Gg) Year Tg CO 2 Eq. Gg 1990 35.0 3

1997 30.0 3 1998 40.1 3 1999 30.4 3 2000 29.8 3 2001 19.8 2 2002 19.8 2 2003 12.3 1 

### Methodology

The methodology employed for estimating emissions is based upon measurements at individual HCFC-22 production plants. Plants using thermal oxidation to abate their HFC-23 emissions monitor the performance of their oxidizers to verify that the HFC-23 is almost completely destroyed. The other plants periodically measure HFC-23 concentrations in the output stream using gas chromatography. This information is combined with information on quantities of critical feed components (e.g., HF) and/or products (HCFC-22) to estimate HFC-23 emissions using a material balance approach. HFC-23 concentrations are dete rmined at the point the gas leaves the chemical reactor; therefore, estimates also include fugitive emissions.

Production data and emission estimates were prepared in cooperation with the U.S. manufacturers of HCFC-22 (ARAP 1997, 1999, 2000, 2001, 2002, 2003, 2004; RTI 1997). Annual estimates of U.S. HCFC-22 production are presented in Table 4-62.

Table 4-62: HCFC-22 Production (Gg)

Year Gg 1990 138.9 1991 142.7 1992 149.6 1993 132.4 1994 146.8 1995 154.7 1996 166.1 1997 164.5 1998 182.8Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 170 1999 165.5 2000 186.9 2001 152.4 2002 144.2 2003 138.0 

### Uncertainty

A high level of confidence has been a ttributed to the HFC-23 concentration data employed because measurements were conducted frequently a nd accounted for day-to-day and process va riability. The results of the Tier 1 quantitative uncertainly analysis ar e summarized in Table 4-63. HCFC -22 production HFC-23 emissions were estimated to be between 11.1 and 13.6 Tg CO 2 Eq. at the 95 percent confidence level. This indicates a range of 10 percent above and below the 2003 emission estimate of 12.3 Tg CO 2 Eq.

Table 4-63: Tier 1 Quantitative Un certainty Estimates for HFC-23 Emi ssions from HCFC-22 Production (Tg CO 2 Eq. and Percent)

Source Gas Year 2003 Emissions (Tg CO 2 Eq.) Uncertainty (%) Uncertainty Range Relative to 2003 Emission Estimate (Tg CO 2 Eq.) Lower Bound Upper Bound HCFC-22 Production HFC-23 12.3 10% 11.1 13.6



### Recalculations Discussion

The historical time series was adjust ed to fully reflect reports from the Alliance for Responsible Atmospheric Policy. These changes resulted in an aver age annual decrease of less than 0.1 Tg CO 2 Eq. (0.01 percent) in HFC emissions from HCFC-22 through the period 1990 through 2002.



### 4.17. Electrical Transmi ssion and Distribution (IP CC Source Category 2F7)

The largest use of SF 6 , both in the United States and internationally, is as an electrical insulator and interrupter in equipment that transmits and distributes electricity (RAND 2002). The gas has been employed by the electric power industry in the United States since the 1950s because of its dielectric strength and arc-quenching characteristics. It is used in gas-insulated substations, circuit breakers, and other switchgear. Sulfur hexafluoride has replaced flammable insulating oils in many applications and allows for mo re compact substations in dense urban

areas.
Fugitive emissions of SF 6 can escape from gas-insulated substations and switch gear through seals, especially from older equipment. The gas can also be released duri ng equipment manufacturing, installation, servicing, and disposal. Emissions of SF 6 from electrical transmission and distribution systems were estimated to be 14.1 Tg CO 2 Eq. (0.6 Gg) in 2003. This quantity represents a 52 pe rcent decrease from the estimate for 1990 (see Table 4-64 and Table 4-65). This decrease, which is reflected in the atmospheric record (Maiss and Brenninkmeijer 2000), is believed to be a response to increases in the price of SF 6 during the 1990s and to growing awareness of the environmental impact of SF 6 emissions, through programs such as the EPA’s SF 6 Emission Reduction Partnership for Electric Power Systems.

Table 4-64: SF 6 Emissions from Electric Power Systems and Original Equipment Manufactures (Tg CO 2 Eq.) Year Electric Power Systems Original Equipment Manufacturers Total

1990 28.9 0.3 29.2

1997 21.3 0.3 21.7 1998 16.7 0.4 17.1 1999 15.8 0.6 16.4Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 171 2000 15.0 0.7 15.6 2001 14.7 0.7 15.4 2002 14.0 0.7 14.7 2003 13.4 0.7 14.1

Table 4-65: SF 6 Emissions from Electric Power Systems and Original Equipment Manufacturers (Gg) Year Emissions 1990 1.2

1997 0.9 1998 0.7 1999 0.7 2000 0.7 2001 0.6 2002 0.6 2003 0.6 

### Methodology

The estimates of emissions from electric transmission a nd distribution are comprised of emissions from electric power systems and emissions from the manufacture of electrical equipment. The methodologies for estimating both sets of emissions are described below.

1999 to 2003 Emissions from Electric Power Systems
Emissions from electric power syst ems from 1999 to 2003 were estimated based on (1) repor ting from utilities participating in EPA’s SF 6 Emissions Reduction Partnership for Electric Power Systems, which began in 1999, and (2) utilities’ transmission miles as repor ted in the 2001 and 2004 Utility Data Ins titute (UDI) Directories of Electric Power Producers and Distributors (UDI 2001, 2004). (Transmi ssion miles are defined as the miles of lines carrying voltages above 34.5 kV.) Between 1999 and 2003, partic ipating utilities represented between 31 percent and 35 percent of total U.S. transmission mile s. The emissions reported by particip ating utilities each year were added to the emissions estimated for non-reporting utilities in th at year. Emissions fro m non-reporting utilities were estimated using the results of a regression analysis that showed that the emissions of reporting utilities were most strongly correlated with their transmission miles. As described further below, the transmission miles of the various types of non-reporting utilities were multiplied by the appropriate regression coefficients, yielding an estimate of emissions. Transmission miles are cl early physically related to emissions, since in the United States, SF 6 is contained primarily in transmission equipment rated at or above 34.5 kV.

The regression equations reflect two distinctions among non-repor ting utilities: (1) between small and large utilities (i.e., with less or more than 10,000 transmission miles, re spectively), and (2) between u tilities that do not participate in the SF 6 Emission Reduction Partnership (non-partners) and those that participate but that have not reported in a given year (non-reporting partners). (Historically, these non-reporting partners have accounted for 5 percent or less of total estimated partner emissions.) The distinc tion between small and large utilities was made because the regression analysis showed that the relationship between emissions and transmission miles differed for small and large facilities. The distinction between non-partners and non-reporting partners was made because the emission trends of these two groups were belie ved to be different. Reporting partne rs have reduced their emission rates significantly since 1999. The emission trend of non-reporting partners was believed to be similar to that of the reporting partners, because all partners commit to reducing SF 6 emissions through technically and economically feasible means. However, non-partners were assumed not to have implemented any changes that would have reduced emissions over time.

To estimate emissions from non-partners in every year si nce 1999, the following regression equations were used. These equations were de veloped based on the 1999 SF 6 emissions reported by 49 partner utilities (representing approximately 31 percent of U.S. transmission miles), and 2000 transmission mileage data obtained from the 2001 UDI Directory of Electric Power Producers and Distributors (UDI 2001):Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 172 Non-partner small utilities (less than 10, 000 transmission miles, in kilograms):

Emissions = 0.874 × Transmission Miles

Non-partner large utilities (m ore than 10,000 transmission miles, in kilograms):

Emissions = 0.558 × Transmission Miles

To estimate emissions from non-reporting partners in each year, the regressi on equations based on the emissions reported by partners in that year were used. To es timate non-reporting partner emissions in 2003, the regression equations were based on the 2003 SF 6 emissions reported by 51 partner utilities, a nd updated 2003 transmission mileage data obtained from the 2004 UDI Directory of Electric Power Producers and Distributors (UDI 2004). The resulting equations for 2003 are:

Non-reporting partner small utilitie s (less than 10,000 transmission miles, 2003, in kilograms):

Emissions = 0.398 × Transmission Miles

Non-reporting partner la rge utilities (more than 10,000 transmission miles, 2003, in kilograms):

Emissions = 0.387 × Transmission Miles

As indicated from the 2001 and 2004 UDI Directories of Electric Power Producers and Distributors (UDI 2001, 2004), the U.S. transmission system has grown by over 14,000 miles between 2000 and 2003. To reflect the fact that this increase probably occurred gradually, transmission mileage was assumed to increase exponentially at an annual rate of approximately 0.7 percent during the 2000 to 2003 time period.

For each year, total emissions were then determined by summing the part ner-reported emissions, the non-reporting partner emissions (determined with that year’s regressi on equation for the partners), and the non-partner emissions (determined using the 1999 regression equation).

1990 to 1998 Emissions from Manuf acture of Electric Equipment
Because most participating utilities reported emissions only for 1999 through 2003, modeling SF 6 emissions from electric power systems for the years 1990 through 1998 was necessary. To do so , it was assumed that during this period, U.S. emissions followed the same trajectory as global emissions from this source. To estimate global emissions, the RAND survey of global SF 6 sales to electric utilities was used, together with the following equation, which is derived from the equation for emissions in the IPCC report, Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2001):

Emissions (kilograms) = SF 6 purchased to refill existing equipment (kilograms) + nameplate capacity of retiring equipment (kilograms)

Note that the above equation holds whet her the gas from retiring equipment is re leased or recaptured; if the gas is recaptured, it is used to refill existing equipment, lowering the amount of SF 6 purchased by utilities for this purpose.

Sulfur hexaflouride purchased to refill existing equipment in a given year was assumed to be approximately equal to the SF 6 purchased by utilities in that year. Gas purch ases by utilities and equi pment manufacturers from 1961 through 2001 are available from the RAND (2002) survey. To estimate the quantity of SF 6 released from retiring equipment, the nameplate capacity of retiring equipment in a given year was assumed to equal 77.5 percent of the amount of gas purchased by electrical equipment manufacturers 30 years previous (e.g., in 1990, the nameplate capacity of retiring equipment was assumed to equal 77.5 percent of the gas purchased in 1960). The remaining 22.5 percent was assumed to have been emitted at the time of manufacture. The 22.5 percent emission rate is an average of IPCC SF 6 emission rates for Europe and Japan for years before 1996 (IPCC 2001). The 30-year lifetime for electrical equipment is also drawn from IPCC (2001). The results of the two components of the above equation were then summed to yield estimates of global SF 6 emissions from 1990 through 1998.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 173 To estimate U.S. emissions for 1990 through 1998, estim ated global emissions fo r each year from 1990 through 1998 were divided by the estimated global emissions from 1999. The result was a time series of factors that express each year’s global emissions as a multiple of 1999 global em issions. To estimate histor ical U.S. emissions, the factor for each year was multiplied by the estimated U.S. emissions of SF 6 from electric power systems in 1999 (estimated to be 15.8 Tg CO 2 Eq.).

1990 to 2003 Emissions from Manufact ure of Electrical Equipment
The 1990 to 2003 emissions estimates for original equipment manufacturers (OEMs) were derived by assuming that manufacturing emissions equal 10 percent of the quantity of SF 6 charged into new equipment. The quantity of SF 6 charged into new equipment was estimated based on statistics compiled by the National Electrical Manufacturers Association (NEMA). These statistics were provided for 1990 to 2000; the quantities of SF 6 charged into new equipment for 2001 to 2003 were assumed to equal that ch arged into equipment in 2000. The 10 percent emission rate is the average of the “ideal ” and “realistic” manufacturing emission rates (4 percent and 17 percent, respectively) identified in a paper prepared under the auspices of the International Council on Large Electric Systems (CIGRE) in February 2002 (O’Connell et al. 2002).


### Uncertainty

For electric power systems, individual part ner-reported SF 6 data was assumed to have an uncertainty of 10 percent. This uncertainty was assumed to incorporate potential errors associated with the weighing of SF 6 cylinders and the tracking of SF 6 purchases and use. Using erro r propagation, the cumulative uncerta inty of all partner-reported data was estimated to be 5 percent.

There are two sources of uncertainty a ssociated with the regression equations used to extrapolate U.S. emissions from participant reports: 1) uncertainty in the coefficients (as defined by the regression standard error estimate); and 2) the uncertainty in total transmission miles for non-part ners and non-reporting partners, which is assumed to be 10 percent. In addition, there is also uncertainty in the basic assumption that all non-reporting partners will follow the trend defined by reporting partners in a specific year, as we ll as uncertainty that the emission factor used for utilities that were not participants, which account ed for approximately 65 percent of U.S. transmission miles, will remain at levels defined by partners who reported in 1999. Ho wever, neither of these uncertainties was modeled.

For OEMs, uncertainty estimates are based on the assumption that SF 6 statistics obtained from NEMA have an uncertainty of 10 percent. Additionally, the OEMs SF 6 emissions rate has an uncertainty bounded by the proposed “actual” and “ideal” emission ra tes defined in O’Connell, et al. (2002). That is, the uncertainty in the emission rate is approximately 65 percent.

A Monte Carlo analysis was applied to estimate th e overall uncertainty of the emission estimate for SF 6 from electrical transmission and di stribution. For each define d parameter (i.e., equation coefficient, transmission mileage, and partner-specific SF 6 emissions data for elect ric power systems; and SF 6 emission rate and statistics for OEMs), random variables were selected from probability density functions, all assumed to have normal distributions about the mean. The results of the Ti er 2 quantitative uncertainty analysis ar e summarized in Table 4-67. Electrical Transmission and Distribution SF 6 emissions were estimated to be between 12.3 and 16.1 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 13 percent below and 14 percent above the emission estimate of 14.1 Tg CO 2 Eq.

Table 4-66: Simulated Variables for Tier 2 Uncertainty Analysis

Parameter Probability Distribution Uncertainty a (%) Total Partner-Reported SF 6 Data (kg SF 6 ) Normal 5 Coefficient – Small Utilities, Non-Partners Normal 11 Coefficient – Large Utilities, Non-Partners Normal 21 Coefficient – Small Utilities, Non-Reporting Partners Normal 21 Coefficient – Large Utilities, Non-Reporting Partners Normal NA b Transmission Miles – Small Utilities, Non-Partners Normal 10Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 174 Transmission Miles – Large Utilities, Non-Partners Normal 10 Transmission Miles – Small Utilities, Non-Reporting Partners Normal 10 Transmission Miles – Large Utilities, Non-Reporting Partner Normal NA b OEM SF 6 Emission Rate (percent) Normal 65 SF 6 Charged to Equipment (kg SF 6 ) Normal 10

a Reflects a 95 percent confidence interval. b Not applicable. In 2003, all large utility partners reported to the SF 6 Emission Reduction Partnership.

Table 4-67: Tier 2 Quantitative Uncertainty Estimates for SF 6 Emissions from Electri cal Transmission and Distribution (Tg CO 2 Eq. and Percent) Uncertainty Range Relative to 2003 Emission Estimate a

Source Gas 2003 Emission Estimate (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%)

Lower Bound Upper Bound Lower Bound Upper Bound Electrical Transmission and Distribution SF 6 14.1 12.3 16.1 -13% +14%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.



### Recalculations Discussion

Electric power system emission estimates for the years 2000, 2001 and 2002 were recalculated based on a combination of additional historical partner data and the incorporation of more up-to-date transmission mileage data. For historical part ner submissions, the regressi on equations for each respectiv e year were updated and new extrapolations to non-reporti ng partners were made. Additionally, recalculations were conducted using updated transmission mileage data, which reflect the growth of the U.S. transmission system. Previously-reported 2001 and 2002 emission estimates had utilized th e 2001 UDI Directory of Electric Powe r Producers and Distributors (UDI 2001) for transmission mileage data (i.e., 2000 data). As mentioned above, transmission mileage data for 2001 and 2002 were adjusted to account for increases in transmissi on mileage during this period. These adjustments have been incorporated in non-reporting partner regression equa tion re-calculations, resulting in revised estimates of nonpartner and non-reporting partner emissions. The combina tion of these changes resulted in an average annual decrease of less than 0.1 Tg CO 2 Eq. (0.2 percent) in SF 6 emissions from electrical transmission and distribution for the period 2000 through 2002.



### 4.18. Aluminum Production (I PCC Source Category 2C3)

Aluminum is a light-weight, malleable, and corrosion-resistant metal that is used in many manufactured products, including aircraft, automobiles, bicycles, and kitchen utensils. In 2003, the United States was the third largest producer of primary aluminum, with 10 percent of the world total (USGS 2004). The United States was also a major importer of primary aluminum. The production of primary aluminum

⎯ in addition to consuming large quantities of electricity

⎯ results in process-related emissions of CO 2 and two perfluorocarbons (PFCs): perfluoromethane (CF 4 ) and perfluoroethane (C 2 F 6 ).

Carbon dioxide is emitted during th e aluminum smelting process wh en alumina (aluminum oxide, Al 2 O 3 ) is reduced to aluminum using the Hall-Heroult reduction process. The reduction of the alumina occurs through electrolysis in a molten bath of natural or synthetic cryolite (Na 3 AlF 6 ). The reduction cells contain a carbon lining that serves as the cathode. Carbon is also contained in the anode, which can be a carbon mass of paste, coke briquettes, or prebaked carbon blocks from petroleum coke. During reduction, most of this carbon is oxidized and released to the atmosphere as CO 2 .

Process emissions of CO 2 from aluminum production were estimated to be 4.2 Tg CO 2 Eq. (4,219 Gg) in 2003 (see Table 4-68). The carbon anodes consumed during aluminum production consist of petroleum coke and, to a minor extent, coal tar pitch. The petroleum coke portion of the total CO 2 process emissions from aluminum production isInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 175 considered to be a non-energy use of petroleum coke, and is accounted for here and not under the CO 2 from Fossil Fuel Combustion source category of the Energy sector. Similarly, the coal tar pitch portion of these CO 2 process emissions is accounted for here rather than in the Iron and Steel source category of the Industrial Processes sector.

Table 4-68: CO 2 Emissions from Aluminum Production (Tg CO 2 Eq. and Gg) Year Tg CO 2 Eq. Gg 1990 6.3 6,315

1997 5.6 5,621 1998 5.8 5,792 1999 5.9 5,895 2000 5.7 5,723 2001 4.1 4,114 2002 4.2 4,220 2003 4.2 4,219

In addition to CO 2 emissions, the aluminum production industry is also a source of PFC emissions. During the smelting process, when the alumina ore content of the electrolytic bath falls below critical levels required for electrolysis, rapid voltage increases occur, termed “a node effects.” These anode effects cause carbon from the anode and fluorine from the dissociated molten cryolite bath to combine, thereby produc ing fugitive emissions of CF 4 and C 2 F 6 . In general, the magnitude of emissions for a given level of production de pends on the frequency and duration of these anode effects. As the frequency and dura tion of the anode effects increase, a corresponding rise in emission levels occurs.

Emissions of PFCs from primary aluminum production are estimated to have declined 79 percent since 1990. Since 1990, emissions of CF 4 and C 2 F 6 have declined 80 percent and 77 percent, respectively, to 3.3 Tg CO 2 Eq. of CF 4 (0.5 Gg) and 0.5 Tg CO 2 Eq. of C 2 F 6 (0.1 Gg) in 2003, as shown in Table 4-69 and Table 4-70. This decline was due both to reductions in domestic alum inum production and to ac tions taken by aluminum smelting companies to reduce the frequency and duration of anode effects.

Table 4-69: PFC Emissions from Aluminum Production (Tg CO 2 Eq.) Year CF 4 C 2 F 6 Total 1990 16.1 2.3 18.3

1997 9.8 1.2 11.0 1998 8.1 1.0 9.1 1999 8.0 0.9 9.0 2000 8.1 0.9 9.0 2001 3.5 0.5 4.0 2002 4.5 0.7 5.2 2003 3.3 0.5 3.8 Note: Totals may not sum due to independent rounding.

Table 4-70: PFC Emissions from Aluminum Production (Gg) Year CF 4 C 2 F 6 1990 2.5 0.2

1997 1.5 0.1 1998 1.2 0.1 1999 1.2 0.1 2000 1.2 0.1 2001 0.5 0.1 2002 0.7 0.1 2003 0.5 0.1Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 176 U.S. primary aluminum production for 2003—totaling 2.7 million metric tons—remained similar to 2002 production levels. Due to high electric power costs in various regions of the country, aluminum production has been curtailed at several U.S. smelters, which resulted in current production levels that were nearly 26 percent lower than 2000 levels in 2003. The transportation industry remained the largest domestic consumer of primary aluminum, accounting for about 35 percent of U.S. consumption (USGS 2004).


### Methodology

Carbon dioxide is generate d during alumina reduction to aluminum metal following the reaction below:

2Al 2 O 3 + 3C → 4Al + 3CO 2

The CO 2 emission factor employed was estimated from the production of primary aluminum metal and the carbon consumed by the process. Emissions vary depending on the specifi c technology used by each plant (e.g., Prebake or Soderberg). The Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) provide CO 2 emission factors for each technology type. Du ring alumina reduction in a prebake anode cell pr ocess, approximately 1.5 metric tons of CO 2 are emitted for each metric ton of aluminum pr oduced (IPCC/UNEP/OECD/IEA 1997). Similarly, during alumina reduction in a Soderberg cell process, approximately 1.8 metric tons of CO 2 are emitted per metric ton of aluminum produced (IPCC/UNEP/OECD/IEA 1997). Based on information gathered by EPA’s Voluntary Aluminum Industrial Partne rship (VAIP) program, production was assume d to be split 80 percent prebake and 20 percent Soderberg for the whole time series.

PFC emissions from aluminum production were estimated using a per-unit production emission factor that is expressed as a function of opera ting parameters (anode effect fre quency and duration), as follows:

PFC (CF 4 or C 2 F 6 ) kg/metric ton Al = S × Anode Effect Minutes/Cell-Day

where, S = Slope coefficient (kg PFC/metric ton Al/(Anode Effect minutes/cell day)) Anode Effect Minutes/Cell-Day = Anode Effect Frequency/Cell-Day × Anode Effect Duration (minutes)

Smelter-specific slope coefficients that are based on field measurements yield the most accurate results. To estimate emissions between 1990 and 2002, smelter-specific coefficients were available and were used for 12 out of the 23 U.S. smelters. To estimate 2003 emissions, smelter-specific co efficients were available and were used for 6 out of the 17 operating U.S. smelters. For the remaining 11 ope rating smelters, technology-specific slope coefficients from Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2001) were applied. The slope coefficients were combined with smelter-specific anode effect data, collected by aluminum companies and reported to the VAIP, to estimate emission factors over time. In 2003, smelter-specific anode effect data was available for 15 of the 17 operating smelters. Wher e smelter-specific anode effect data were not available (i.e., 2 out of 17 smelters in 2003, 2 out of 23 smelters between 1990 and 2002), industry averages were used. For all smelters, emission factors were multiplied by annual produc tion to estimate annual emissions at the smelter level. In 2003, smelter-specific production data was available fo r 16 of the 17 operating smelters; production at the one remaining smelter was estimated based on national alum inum production and capacity data (USGS). Between 1990 and 2003, production data has been provided by 21 of the 23 U. S. smelters. Emissions were then aggregated across smelters to estimate national emissions. The methodology used to estimate emissions is consistent with the methodologies recommended by the Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2001).

National primary aluminum production data for 1990 th rough 2001 (see Table 4-71) were obtained from USGS, Mineral Industry Surveys: Aluminum Annual Report (USGS 1995, 1998, 2000, 2001, 2002). For 2002 and 2003, national aluminum production data were obtained from the United States Aluminum Association’s PrimaryInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 177 Aluminum Statistics (USAA 2004). The CO 2 emission factors were taken from the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).

Table 4-71: Production of Primary Aluminum (Gg)

Year Gg 1990 4,048 1991 4,121 1992 4,042 1993 3,695 1994 3,299 1995 3,375 1996 3,577 1997 3,603 1998 3,713 1999 3,779 2000 3,668 2001 2,637 2002 2,705 2003 2,705



### Uncertainty

The overall uncertainty associated with the 2003 CO 2 , CF 4 , and C 2 F 6 emission estimates were calculated using the IPCC Good Practice Guidance Tier 2 methodology. Uncertainty associated with the parameters used to estimate CO 2 emissions included that associated with production data, with the share of U.S. aluminum production attributable to each smelter type, and with the emission factors applied to pr oduction data to calculate emissions. Uncertainty surrounding production data was assumed to be ch aracterized as described below, and other variables were modeled assuming triangular distributions. Emission f actors were determined through expert elicitation to be 50 percent certain at a 95 percent confidence level, while the share of production attributed to smelter types were determined to be associated with a 25 percent uncertainty. A Monte Carlo analysis was applied to estimate the overall uncertainty of the emissions estimate for the U.S. aluminum industry as a whole and the results are provided below.

In determining uncertainty associated with emissions of CF 4 and C 2 F 6 , for each smelter, uncerta inty associated with the quantity of aluminum produced and the frequency and duration of anode e ffects was estimated. A Monte Carlo analysis was then applied to estimate the overall uncertainty of the emissions estimate for each smelter and for the U.S. aluminum industry as a whole. Data on anode e ffect frequency and duration a nd production data are assumed to be characterized by a normal distribution. The uncertainty of aluminum production estimates was assumed to be 1 percent or 25 percent, depending on whether a smelter’s production was reported or estimated. The uncertainty of the anode effect frequency was assumed to be 2 percent if the data was reported; however, if the data was estimated, the uncertainty ranged from 33 to 78 percent, depending on the smelter technology type. Similarly, the uncertainty in anode effect duration was assumed to be 5 percent for data that was reported, but between 28 and 70 percent for data that was estimated. The uncertainty ranges for estimated technology-specific anode effect frequency and duration are based on the standard deviation of reported anode-effect frequency and dura tion in the International Aluminum Institute’s anode effect survey (IAI 2000).

Additionally, for CF 4 and C 2 F 6 emission estimates, uncertainties associated w ith slope coefficients were calculated. Data for the slope coefficients are assu med to be characterized by a normal dist ribution. For the three smelters that participated in the 2003 EPA-funded measurement study, CF 4 and C 2 F 6 slope coefficient uncertainties were calculated to be 10 percent. For the remaining smelters, given the limited uncertainty data on site-specific slope coefficients (i.e., those developed using IPCC Tier 3b me thodology), the overall uncertainty associated with the slope coefficients is conservatively assumed to be si milar to that given by the IPCC guidance for technologyspecific slope coefficients. Consequently, the uncertainty assigned to the slope coefficients ranged between 10 percent and 35 percent, depending upon the gas and the sm elter technology type. In general, where preciseInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 178 quantitative information was not availa ble on the uncertainty of a paramete r, a conservative (upper-bound) value was used.

The results of this Tier 2 quantitativ e uncertainty analysis are summarized in Table 4-72. Aluminum production CO 2 emissions were estimated to be between 2.8 and 5.9 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 34 percent below to 40 percent above the emission estimate of 4.2 Tg CO 2 Eq. Also at the 95 percent confidence interval, aluminum production CF 4 emissions were estimated to be between 2.9 and 3.7 Tg CO 2 Eq. at the 95 percent confidence level. This indicates a range of approximately 11 percent below to 11 percent above the emission estimate of 3.3 Tg CO 2 Eq. Finally aluminum production C 2 F 6 emissions were estimated to be between 0.46 and 0.59 Tg CO 2 Eq. at the 95 percent confidence level. This indicates a range of appr oximately 12 percent below to 13 percent above the emission estimate of 0.5 Tg CO 2 Eq.

Table 4-72: Tier 2 Quantitative Un certainty Estimates for PFC Emissi ons from Aluminum Production (Tg CO 2 Eq. and Percent) Uncertainty Range Relative to 2003 Emission Estimate a

Source Gas 2003 Emission Estimate (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Aluminum Production CO 2 4.2 2.8 5.9 -34% +40% Aluminum Production CF 4 3.3 2.9 3.7 -11% +11% Aluminum Production C 2 F 6 0.5 0.5 0.6 -12% +13%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.

Occasionally, SF 6 may be used by the aluminum industry as a cover gas or a fluxing and degassing agent in experimental and specialized casting operations . In its application as a cover gas, SF 6 is mixed with nitrogen or CO 2 and injected above the surface of molten alum inum. As a fluxing a nd degassing agent, SF 6 is mixed with argon, nitrogen, and/or chlorine and blown through molten aluminum. These practices are not employed extensively by primary aluminum producers and are generally isolated to secondary casting firms. The aluminum industry in the United States and Canada has been estimated to use 230 metric tons of SF 6 per year (Maiss and Brenninkmeijer 1998); however, this estimate is highly uncertain.

Historically, SF 6 from aluminum activities has been omitted from estimates of global SF 6 emissions, with the explanation that any emissions would be insignificant (Ko et al. 1993, Victor and MacDonald 1998). Emissions are considered to be insignificant, given that the concentration of SF 6 in the mixtures is small and a portion of the SF 6 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 SF 6 from aluminum fluxing and degassing have not been estimated. Uncertainties exist as to the quantity of SF 6 used by the aluminum industry and its rate of de struction in its uses as a degassing agent or cover gas.


### Recalculations Discussion

The smelter-specific emission factors used for estimating PFC emissions, as well as aluminum production levels, were revised to reflect recently-reporte d data concerning smelter operating pa rameters, as well as measurements conducted at three U.S. aluminum smelters. The measurements were part of an EPA-funded study to determine facility-specific slope coefficients. Consequently, these coe fficients were used instead of IPCC defaults to calculate smelter-specific emission factors. These data were provide d in cooperation with participants in the VAIP program. The combination of these changes resulted in an average annual increase of less than 0.1 Tg CO 2 Eq. (0.2 percent) in PFC emissions from aluminum production for the period 1990 through 2002.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 179 Carbon dioxide emission estimates from aluminum production for 2002 were updated to include aluminum production data from the USAA. Previous CO 2 emission estimates for 2002 were based on aluminum production data from the USGS. This cha nge resulted in a decrease in CO 2 emissions from aluminum production of less than 0.1 Tg CO 2 Eq. (less than -0.1 percent) for 2002.



### 4.19. Semiconductor Manufacture (IPCC Source Category 2F6)

The semiconductor industry uses multiple long-lived fluorin ated gases in plasma etch ing and plasma enhanced chemical vapor deposition (PECVD) processes to produ ce semiconductor products. The gases most commonly employed are trifluoromethane (HFC-23 or CHF 3 ), perfluoromethane (CF 4 ), perfluoroethane (C 2 F 6 ), nitrogen trifluoride (NF 3 ), and sulfur hexafluoride (SF 6 ), although other compounds such as perfluoropropane (C 3 F 8 ) and perfluorocyclobutane (c-C 4 F 8 ) are also used. The exact combination of compounds is specific to the process employed.

A single 300 mm silicon wafer that yiel ds between 400 to 500 semiconductor products (devices or chips) may require as many as 100 distinct fluorinated-gas-using process steps, principally to deposit and pattern dielectric films. Plasma etching (or patterning) of dielectric films, such as silicon dioxide and silicon nitride, is performed to provide pathways for conducti ng material to connect indi vidual circuit components in each device. The patterning process uses plasma-generated fluorine atoms, which chemically react with e xposed dielectric film, to selectively remove the desired portions of the film. The material re moved as well as undissociated fluorinated gases flow into waste streams and, unless emission abat ement systems are employed, into the atmosphere. PECVD chambers, used for depositing dielectric films, are cleaned periodically using fluorinated and other gases. During the cleaning cycle the gas is converted to fluorine atoms in a plasma, which etches away residual material from chamber walls, electrodes, and chamber hardware. Undissociated fluorin ated gases and other products pass from the chamber to waste streams and, unless abatement sy stems are employed, into the atmosphe re. In addition to emissions of unreacted gases, some fluorinated compounds can also be transformed in the plasma processes into different fluorinated compounds which are then exhausted, unless abated, into the atmosphere. For example, when C 2 F 6 is used in cleaning or etching, CF 4 is generated and emitted as a process by-p roduct. Besides dielectric film etching and PECVD chamber cleaning, much smaller quantities of fluorinated gases are used to etch polysilicon films and refractory metal films like tungsten.

For 2003, total weighted emissions of all fluorinated greenhouse gases by the U.S. semiconductor industry were estimated to be 4.3 Tg CO 2 Eq. Combined emissions of all fluorinated greenhouse gases are presented in Table 4-73 and Table 4-74 below. The rapid growth of this industry and the increasing complexity of semiconductor products which use more PFCs in the production process have led to an increase in emissions of 48 percent since 1990. The emissions growth rate began to slow after 1997, and emissions declined by 40 percent between 1999 and 2003. This decline is due both to a drop in production (with a continuing decline in silicon consumption) and to the initial implementation of PFC emission reduction methods such as process optimization.

Table 4-73: PFC, HFC, and SF 6 Emissions from Semiconductor Manufacture (Tg CO 2 Eq.) Year 1990 1997 1998 1999 2000 2001 2002 2003 CF 4 0.7 1.6 1.8 1.8 1.8 1.3 1.1 1.0 C 2 F 6 1.5 3.2 3.6 3.7 3.0 2.1 2.2 2.1 C 3 F 8 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 C 4 F 8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 HFC-23 0.2 0.4 0.4 0.4 0.3 0.2 0.2 0.2 SF 6 0.5 1.1 1.3 1.3 1.1 0.8 0.7 0.8 NF 3 * 0.0 0.1 0.1 0.1 0.1 0.1 0.3 0.2 Total 2.9 6.3 7.1 7.2 6.3 4.5 4.4 4.3 Note: Totals may not sum due to independent rounding. * NF 3 emissions are presented for inform ational purposes, using a GWP of 8,000, and are not included in totals.

Table 4-74: PFC, HFC, and SF 6 Emissions from Semiconductor Manufacture (Mg) Year 1990 1997 1998 1999 2000 2001 2002 2003Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 180 CF 4 115 245 277 281 281 202 175 161 C 2 F 6 160 347 391 397 324 231 244 228 C 3 F 8 0 0 0 0 17 14 9 13 C 4 F 8 0 0 0 0 0 0 5 8 HFC-23 15 33 37 37 23 16 15 17 SF 6 22 48 54 55 46 31 28 35 NF 3 3 8 9 9 11 12 32 30



### Methodology

Emissions from semiconductor manufacturi ng were estimated using three distin ct methods, one each for the periods 1990 through 1994, 1995 through 1999, and 2000 and beyond. For 1990 through 1994, emissions were estimated using the most recent version of EPA’s PFC Emissi ons Vintage Model (PEVM) (Burton & Beizaie 2001). 17 PFC emissions per square centimeter of silicon increase as th e number of layers in semiconductor devices increases. Thus, PEVM incorporates information on the two attribut es of semiconductor devices that affect the number of layers: (1) linewidth technology (the smallest feature size, which decreases as layers increase), and (2) product type (memory vs. logic). PEVM derives historical consump tion of silicon (i.e., square centimeters) by linewidth technology from published data on annual wafer starts and average wafer size (VLSI 2003a,b,c). For each linewidth technology, a weighted average number of layers is estimated using VLSI product-specific worldwide silicon demand data in conjunction with complexity factors (i.e., the number of layers per IC) specific to product type (International SEMATECH 1998-2003). The distribu tion of memory/logic devices ranges over the period covered from 52 percent logic devices in 1995 to 59 percent logic devices in 2000. These figures were used to determine emission factors that express emissions per average layer per unit of area of silicon consumed during product manufacture. The per-layer emission factor was based on the total annual emissions reported by participants in EPA’s PFC Reduction/Climate Partnership for the Semiconductor Industry in 1995 and later years.

For 1995 through 1999, total U.S. emissions were extrapolated from the total annual emissions reported by the Partnership participants (Burton & Lieberman 2004). The em issions reported by the participants were divided by the ratio of the total layer-weighted capacity of the plants operated by the participants and the total layer-weighted capacity of all of the semiconductor plants in the United States; this ratio represents the share of layer-weighted capacity attributable to partnership participants. The layer-weighted capacity of a plant (or group of plants) consists of the silicon capacity of that plant multip lied by the number of layers used to fa bricate products at that plant. This method assumes that participants and non-participants ha ve similar capacity utilizati ons and per-layer emission factors.

The U.S. estimate for the years 2000 through 2003—the peri od during which partners began the consequential application of PFC-reduction measures—used a different estimation method. The emissions reporting by Partnership participants for each year were accepted as the quantity emitted from the share of the industry represented by those Partners. Remaining emissions (those from non-partners), however, were estimated using PEVM and the method described above. (Non-partners are assumed not to have implemented any PFC-reductionmeasures, and PEVM models emissions without such measures.) The portion of the U.S. total attributed to nonPartners is obtained by mu ltiplying PEVM’s total U.S. figure by the non-partner share of total layer-weighted silicon capacity for each year (as desc ribed above). Annual updates to PEVM reflect published figures for actual silicon consumption from VLSI Research, Inc. as well as revisions and additions to the world population of semiconductor manufacturing plants.

Two different approaches were also used to estimate the distribution of emissions of specific PFCs. Before 1999, when there was no consequential adoption of PFC-reducing m easures, a fixed distribution was assumed to apply to the entire U.S. industry. This distribution was based upon the average PFC purchases by semiconductor

17 The most recent version of this model is v.3.1.0306.0304r, completed in March 2004.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 181 manufacturers during this period and th e application of IPCC default emissi on factors for each gas. For the 2000 through 2003 period, the 1990 through 1999 distribution was a ssumed to apply to the non-Partners. Partners, however, began to report gas-specific emissions during this period. Thus, gas specific emissions for 2000 through 2003 were estimated by adding the emissions reported by th e Partners to those estimated for the non-Partners.

Partners estimate their emissions using a range of methods. For 2003, most participants cited a method at least as accurate as the IPCC’s Tier 2c Methodology, recommended in Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2000). The partners with relatively high emissions typically use the more accurate IPCC 2b or 2a methods, mu ltiplying estimates of their PFC consumption by processspecific emission factors that they have either measured or obtained from tool suppliers.

Data used to develop emission estimates were prepared in cooperation with the Partnership. Estimates of operating plant capacities and characteristics for participants and non-participants were derived from the Semiconductor Equipment and Materials International (SEMI) World Fab Watch (formerly International Fabs on Disk ) database (1996 to 2003). Estimates of silicon consumed by line-width from 1990 thr ough 2003 were derived from information from VLSI Research (2003d), and the number of layers per line-width was obtained from International SEMATECH’s International Technology Roadmap: 1998 – 2003.


### Uncertainty

Quantitative uncertainty of this source category was performed using the IPCC-recommended Tier 2 uncertainty estimation methodology, Monte Carlo Stochastic Simulation technique. Uncertainty is associated with the emission estimates reported by the Partners, with the estimated share of total layer-weighted silicon capacity in 2003 attributable to the Partners, and with the total U.S. PFC emissions estimate as determined by PEVM.

The Monte Carlo analysis presented below relied on estimates of uncertainty attributed to these three variables. Estimates of uncertainty for the three variables were in turn developed using the estimated uncertainties associated with the individual inputs to each variab le, error propagation analys is, and expert judgment. For the first variable, the aggregate PFC emissions data supplied to the partnership, EPA estimated an uncertainty of ±10 percent(representing a 95 percent confidence interval). This value accounts for uncertainty in partners’ estimates of gasvolume usage, and was calculated usi ng 2003 Partnership submittals. Through e xpert judgment and review of the emission reports submitted by companie s under the Partnership agreement, th e relative uncertainties were assumed to be the same for each submittal in 2003, equal to ±29 pe rcent of the individual Partne r’s reported value. Under that assumption, uncertainty propagated across all Partners resulted in a combined relative uncertainty equal to about 10 percent of the aggregate emissions reports under th e Partnership. For the second variable, the share of U.S. layer-weighted silicon capacity acc ounted for by non-Partners, an uncerta inty of ±36 percent was estimated based on the variability of the shar e over the period 1995 through 2003.

For the third variable, the relative error associated with the PEVM estimate in 2003, EPA estimated an uncertainty of ±44 percent, using the calculus of error propagation and considering the aggregate average emission factor, world silicon consumption, the U.S. share of layer-weighted silicon capacity, and the number of layers. The uncertainty associated with the aggregate average emission factor wa s estimated to be 15 percent based on the variability exhibited by the emission factor from 1996 through 1999. The uncer tainty associated with the U.S. share of capacity was estimated to be 10 percent based on information from the firm that compiled the database; the principal source of errors was determined to be incomplete e-mail and telephone surveys of manufacturers (SMA 2003). The uncertainty associated with silicon consumption data was estimat ed to be 10 percent, based on the reliability of industry surveys of worl d silicon consumption by t echnology node. Finally, the uncertainty associated with the number of layers was estimated to be 39 percent.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-75. The emissions estimate for total U.S. PFC emissions from semiconductor manufacturing were estimated to be between 3.7 and 5.7 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of 20 percent below to 23 percent above the emissions estimate of 4.6 Tg CO 2 Eq. It should be noted that this range and the associated percentages apply to the estimate of total emissions rather than those of individual gases.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 182 Uncertainties associated with individual gases will be somewhat higher than the aggregate, but were not explicitly modeled.

Table 4-75: Tier 2 Quantitative Uncertainty Estimates for HFC, PFC, and SF 6 Emissions from Semiconductor Manufacture (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate a Uncertainty Range Relative to Emission Estimate b (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Semiconductor Manufacture HFC, PFC, and SF 6 4.6 3.7 5.7 -20% +23%

a Because the uncertainty analysis covered all emissions (including NF 3 ), the emission estimate presented here does not match that shown in Table 4-73.
b Range of emissions estimates predicted by Monte Carlo Stochastic Si mulation for a 95 percent confidence interval

. 

### Planned Improvements

The method by which non-partner related emissions are estimated (i.e., PEVM) is not expected to change (with the exception of possible future updates to emission factors and added technology nodes). Future improvements to the national emission estimates will primarily be associated with determining the portion of national emissions to attribute to partner report totals (about 80 percent in recent years). As the nature of the partner reports change through time and industry-wide reduction efforts increase, consideration will be given to what emission reduction efforts—if any—are likely to be o ccurring at non-partner facilities (curren tly none are assumed to occur.)



### 4.20. Magnesium Production and Pro cessing (IPCC Source Category 2C4)

The magnesium metal production and casting industry uses sulfur hexafluoride (SF 6 ) as a cover gas to prevent the oxidation of molten magnesium in the presence of air. A dilute gaseous mixture of SF 6 with dry air and/or CO 2 is blown over molten magnesium metal to induce and stabilize the formation of a protective crust. A small portion of the SF 6 reacts with the magnesium to form a thin molecu lar film of mostly magne sium oxide and magnesium fluoride. The amount of SF 6 reacting in magnesium production and processi ng is assumed to be negligible and thus all SF 6 used is emitted into the atmosphere. Sulfur hexafluor ide has been used in this application around the world for the last twenty years. It has largely replaced salt fluxes and SO 2 , which are more toxic and corrosive than SF 6 . The magnesium industry emitted 3.0 Tg CO 2 Eq. (0.1 Gg) of SF 6 in 2003 (see Table 4-76). This represents a 12 percent increase from 2002. The increase is attributable to a 1.5 percent rise in production and casting levels and to a 10.5 percent increase in the weighted-average SF 6 usage rate at these facilities. There are no significant plans for expansion of primary magnesium production in the United States, but demand for magnesium metal by U.S. casting companies has grown as auto manufacturers design more lightweight magnesium parts into vehicle models. In the last ten years, the quantity of magnesium used in No rth American-produced vehicl es has doubled (USGS 2004a). Foreign magnesium producers are expected to meet the growing U.S. demand for primary magnesium (USGS 2004a).

Table 4-76: SF 6 Emissions from Magnesium Production and Processing (Tg CO 2 Eq. and Gg) Year Tg CO 2 Eq. Gg 1990 5.4 0.2

1997 6.3 0.3 1998 5.8 0.2 1999 6.0 0.3 2000 3.2 0.1 2001 2.6 0.1Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 183 2002 2.6 0.1 2003 3.0 0.1 

### Methodology

Emission estimates for the magnesium industry incorporate information provided by industry participants in EPA’s SF 6 Emission Reduction Partnership for the Magnesium Industr y. The partnership started in 1999 and, currently, participating companies represent 100 percent of U.S. pr imary production and over 80 percent of the casting sector (i.e., die, gravity, wrought, and anode casting). Emissions for 1999 through 2003 from primary production, some secondary production (i.e., recycling), and a large fraction of die casting were reported by participants. The 1999 through 2003 emissions from the remain ing secondary production and casting were estimated by multiplying industry emission factors (kg SF 6 per metric ton of Mg produced or processed) by the amount of metal produced or consumed in the five major processes (other than primary production) that require SF 6 melt protection: 1) secondary production; 2) die casting; 3) gravity casting; 4) wrought products; and 5) anodes. The emission factors are provided below in Table 4-77. Becau se only one primary producer existed in the United States in 2003, the emission factor for primary production is withheld to protect production information. However, the emission factor has not risen above the 1995 value of 1.1 kg SF 6 per metric ton.

Die casting emissions for 1999 through 2003, whic h accounted for 48 to 75 percent of all SF 6 emissions from U.S. casting and recycling processes during this period, were estimated based on information supplied by industry partners. From 2000 to 2003, partners accounted for all U.S. die casting th at was tracked by USGS. In 1999, partners did not account for all die casting tracked by USGS, and, therefore, it was nece ssary to estimate the emissions of die casters who were not partners. Die caste rs who were not partners were assumed to be similar to partners who cast small parts. Due to process requirements, these casters consume larger quantities of SF 6 per metric ton of processed magnesium than casters that process large parts. Consequently, emissions estimates from this group of die casters were developed using an average emission factor of 5.2 kg SF 6 per metric ton of magnesium. The emission factors for the other industry sectors (i.e., secondary production, gravity, wrought, and anode casting) were based on discussions with industry representatives.

Table 4-77: SF 6 Emission Factors (kg SF 6 per metric ton of magnesium) Year Secondary Die Casting Gravity Wrought Anodes 1999 1 2.14 a 2 11 2000 1 0.73 2 1 1 2001 1 0.77 2 1 1 2002 1 0.70 2 1 1 2003 1 0.84 2 1 1

a The 1999 factor is a weighted average that incl udes an estimated emission factor of 5.2 kg SF 6 per metric ton of magnesium for die casters that do not participate in the Partnership. Data used to develop these emission estimates were provi ded by the magnesium partnership participants and the USGS. U.S. magnesium metal production (primary a nd secondary) and consumption (casting) data from 1990 through 2003 were available from the USGS (USGS 2002, 2003, 2004b). Emission factors from 1990 through 1998 were based on a number of sources. Emission fact ors for primary production were available from U.S. primary producers for 1994 and 1995, and an emission factor for die casting of 4.1 kg per metric ton was available for the mid-1990s from an international survey (Gjestland & Magers 1996).

To estimate emissions for 1990 through 1998, industry emi ssion factors were multiplied by the corresponding metal production and consumption (casting) statistics from USGS . The primary production emission factors were 1.2 kg per metric ton for 1990 through 1993, and 1.1 kg per metric ton for 1994 through 1996. For die casting, an emission factor of 4.1 kg per metric ton was used for the period 1990 through 1996. For 1996 through 1998, the emission factors for primary production and die casting were assume d to decline linearly to the level estimated based on partner reports in 1999. This assumption is consistent with the trend in SF 6 sales to the magnesium sector that is reported in the RAND survey of major SF 6 manufacturers, which shows a decline of 70 percent from 1996 to 1999 (RAND 2002). The emission factors for the other processe s (i.e., secondary production, and gravity, wrought, and anode casting), about which less is known, were assumed to remain constant at levels defined in Table 4-65.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 184 

### Uncertainty

An uncertainty of 5 percent was assigned to the SF 6 emissions data reported by each participant in the SF 6 Emission Reduction Partnership. These data have low uncertainty since they are prepared through facility -specific tracking of SF 6 cylinder purchases, usage, and returns. If partners did not report emissions data during the current reporting year, SF 6 emissions data were estimated using available em ission factor and production information reported in prior years. For example, to estimate 2003 emission factors, the average change in emission factor from 2002 to 2003 for reporting partners was applied to the 2002 emission factor of the non-reporting partner. The uncertainty associated with the extrapolated emission factor was assumed to be 25 percent. For production data, if estimates were unavailable for the current reporting year, data from the last reported year was applied.

For 2003, the uncertainty associated with this approach was assumed to be 30 percent. Between 1999 and 2003, non-reporting partners have accounted for between 0 and 17 percent of total estimated sector emissions. For those industry processes that are not represented in EPA’s pa rtnership, such as gravity, anode, and wrought casting, SF 6 emissions were estimated using production and consumption statistics reported by USGS and an estimated processspecific emission factor (see Table 4-78). The uncertainty associated with USGS-reported statistics and emission factors were assumed to be 25 percent and 75 percent, respectively. In general, where precise quantitative information was not available on the uncertainty of a parameter, a conservative (upper-bound) value was used.

Table 4-78: Simulated Variables for Tier 2 Uncertainty Analysis

Parameter Probability Distribution Uncertainty a (%) Partner-Reported SF 6 Data (kg SF 6 ) Normal 5 SF 6 Emission Factor for Non-Reporting Partners (kg SF 6 /metric ton Mg) Normal 25 Production Data for Non-Reporting Partners (metric ton Mg) Normal 30 USGS Production Data for Gravity, A node, Wrought Casting and Secondary Production (metric ton Mg) Normal 25 SF 6 Emission Factor for Gravity, Anode, Wrought Casting and Secondary Production (kg SF 6 /metric ton Mg) Normal 75

a Reflects a 95 percent confidence interval. Additional uncertainties exist in these estimates, such as the basic assumption that SF 6 neither reacts nor decomposes during use. The melt surface reactions and hi gh temperatures associated with molten magnesium could potentially cause some gas degradation. R ecent measurement studies have identified SF 6 cover gas degradation at hot-chambered die casting machines on the order of 10 percent (Bartos et al. 2003). As is the case for other sources of SF 6 emissions, total SF 6 consumption data for magnesium production and processing in the United States were not available. Sulfur hexafluoride may also be used as a cover gas for the casting of molten aluminum with high magnesium content; however, to what extent this technique is used in the United States is unknown.

A Monte Carlo analysis was applied to estimate the ove rall uncertainty of the emission estimate for the U.S. magnesium industry. Random variables were selected from the probability de nsity functions for each parameter, which were assumed to be characterized by normal distribu tions. In the cases of estimates developed from partners and non-reporting partners, probability density functions were applied to parameters (i.e., SF 6 emissions data, emission factors and production da ta) at the facility-specific level. The re sults of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-79. Magnesium production and processing SF 6 emissions were estimated to be between 2.6 and 3.3 Tg CO 2 Eq. at the 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 11 percent below to 13 percent above the emission estimate of 3.0 Tg CO 2 Eq.

Table 4-79: Tier 2 Quantitative Uncertainty Estimates for SF 6 Emissions from Magnesium Production and Processing (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to 2003 Emission Estimate a

(Tg CO 2 Eq.) (Tg CO 2 Eq.) (%)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 185 Lower Bound Upper Bound Lower Bound Upper Bound Magnesium Production and Processing SF 6 3.0 2.6 3.3 -11% +13%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval. 

### Recalculations Discussion

The emission estimates for 2000, 2001, and 2002 were adjusted upward slightly from the previously reported values. This revision reflects an update to historical data supplied by partnership participants and the USGS. The changes resulted in an average annual increase of less than 0.1 Tg CO 2 Eq. (4.1 percent) in SF 6 emissions from magnesium production and processing for the period 2000 through 2002.


### Planned Improvements

As more work assessing the degree of cover gas degr adation and associated byproducts is undertaken and published, results could potentially be used to refine the emission estimates, which currently assume (per IPCC Good Practice Guidance 2001) that all SF 6 utilized is emitted to the atmosphere. EPA-funded measurements of SF 6 in hot chamber die casting have indicated that the latter assumption may be incorrect, with observed SF 6 degradation on the order of 10 percen t (Bartos et al. 2003). More recent EPA-funded measurement studies have confirmed this observation for cold chamber die casting (EPA 2004). Another issue that will be addressed in future inventories is the likely adoption of alternate cover ga ses by U.S. magnesium producers and processors. These cover gases, which include Am-CoverTM (containing HF C-134a) and NovecTM 612, have lower GWPs than SF 6 , and tend to quickly decompose during their exposure to the mo lten metal. Additionally, as more companies join the partnership, in particular those from sectors not currently represented, such as gravity and anode casting, emission factors will be refined to incorporate these additional data.

[BEGIN BOX]

Box 4-1: Potential Emission Estimates of HFCs, PFCs, and SF 6 Emissions of HFCs, PFCs and SF 6 from industrial processes can be estimated in two ways, either as potential emissions or as actual emissions. Emi ssion estimates in this chapter are “act ual emissions,” which are defined by the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997) as estimates that take into account the time lag between consumption and emissions. In contrast, “potential emissions” are defined to be equal to the amount of a chemical consumed in a country, minus the amount of a chemical recovered for destruction or export in th e year of consideration. Potential em issions will generally be greater for a given year than actual emissions, since some amount of chemical consumed will be stored in products or equipment and will not be emitted to the atmosphere until a later date, if ever. Although actual emissions are considered to be the more accurate estimation approach for a single y ear, 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 CF 4 and C 2 F 6 from aluminum production and of HFC-23 from HCFC-22 produc tion, the distinction between potential and actual emissions is not relevant.

• Potential emissions that equal actual emissions . For some sources, such as magnesium production and processing, no delay between consumption and emission is assumed and, consequently, no destruction of the chemical takes place. In this case, actual emissions equal potential emissions.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 186 Table 4-80 presents potential emission estimates for HFCs and PFCs from the substitution of ozone depleting substances, HFCs, PFCs, and SF 6 from semiconductor manufacture, and SF 6 from magnesium production and processing and electrical transmission and distribution. 18 Potential emissions associated with the substitution for ozone depleting substances were calculated using the EP A’s Vintaging Model. Estimates of HFCs, PFCs, and SF 6 consumed by semiconductor manufacture were developed by dividing chemical-by-chemical emissions by the appropriate chemical-specific emission factors from the IPCC Good Practice Guidance (Tier 2c). Estimates of CF 4 consumption were adjusted to account for the conversion of other chemicals into CF 4 during the semiconductor manufacturing process, again using the default factor s from the IPCC Good Practice Guidance. Potential SF 6 emissions estimates for electrical tran smission and distribution were developed using U.S. utility purchases of SF 6 for electrical equipment. From 1999 th rough 2003, estimates were obtained from reports submitted by participants in EPA’s SF 6 Emission Reduction Program for Electric Powe r Systems. U.S. utility purchases of SF 6 for electrical equipment from 1990 through 1998 were backcasted based on world sales of SF 6 to utilities. Purchases of SF 6 by utilities were added to SF 6 purchases by electrical equipmen t manufacturers to obtain total SF 6 purchases by the electrical equipment sector.

Table 4-80: 2003 Potential and Actual Emissions of HFCs, PFCs, and SF 6 from Selected Sources (Tg CO 2 Eq.) Source Potential Actual Substitution of Ozone Deple ting Substances 181.0 99.5 Aluminum Production - 3.8 HCFC-22 Production - 12.3 Semiconductor Manufacture 6.6 4.3 Magnesium Production and Processing 3.0 3.0 Electrical Transmission and Distribution 21.8 14.1 - Not applicable.

[END BOX]



### 4.21. Industrial Sources of Ambient Air Pollutants

In addition to the main greenhouse gases addressed above, ma ny industrial processes generate emissions of ambient air pollutants. Total emissions of nitrogen oxides (NO x ), carbon monoxide (CO), and nonmethane volatile organic compounds (NMVOCs) from non-energy industrial processes from 1990 to 2003 are reported in Table 4-81.

Table 4-81: NO x , CO, and NMVOC Emissions from Industrial Processes (Gg) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 NO x 591 629 637 595 626 656 630 648

Chemical & Allied Product Manufacturing 152 115 117 93 95 97 95 92 Metals Processing 88 81 81 78 81 86 76 83 Storage and Transport 3 15 15 13 14 15 14 14 Other Industrial Processes 343 417 424 409 434 457 442 457 Miscellaneous* 5 1 1 2 2 1 3 2 CO 4,124 3,153 3,163 2,156 2,217 2,339 2,308 2,431

Chemical & Allied Product Manufacturing 1,074 971 981 317 327 338 306 299 Metals Processing 2,395 1,551 1,544 1,138 1,175 1,252 1,174 1,290 Storage and Transport 69 64 65 148 154 162 195 219 Other Industrial Processes 487 528 535 518 538 558 576 575 Miscellaneous* 101 38 38 35 23 30 57 49

18 See Annex 5 for a discussion of sources of SF 6 emissions excluded from the actual emissions estimates in this report.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 187 NMVOCs 2,426 2,038 2,047 1,813 1,773 1,769 1,725 1,711

Chemical & Allied Product Manufacturing 575 352 357 228 230 238 194 198 Metals Processing 111 71 71 60 61 65 62 65 Storage and Transport 1,356 1,205 1,204 1,122 1,067 1,082 1,093 1,069 Other Industrial Processes 364 397 402 398 412 381 369 374 Miscellaneous* 20 13 13 6 3 4 7 5 * Miscellaneous includes the following categor ies: catastrophic/accidental release, othe r combustion, health services, cooling towers, and fugitive dust. It does not include agricultural fi res or slash/prescribed burning, which are accounted for under t he Field Burning of Agricultural Residues source. Note: Totals may not sum due to independent rounding.



### Methodology

These emission estimates were obtained from prelimin ary data (EPA 2004), and disaggregated based on EPA (2003), which, in its final iteration, will be published on the National Emission Inve ntory (NEI) Air Pollutant Emission Trends web site. Emissions were calculated either for individual categories or for many categories combined, using basic activity data (e.g., the amount of raw material processed) as an indicator of emissions. National activity data were collected for individual cate gories from various agencies. Depending on the category, these basic activity data may include data on production, fuel deliveries, raw material processed, etc.

Activity data were used in conjunction with emission factors, which together relate the quantity of emissions to the activity. Emission factors are ge nerally 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 repor ts, the 1985 National Acid Precipitation and Assessment Program emissions inventory, and other EPA databases.


### Uncertainty

Uncertainties in these estimates are par tly due to the accuracy of the emission factors used and accurate estimates of activity data. A quantitative uncertainty analysis was not performed.Fi g ure 4-1: 2003 Industrial Processes Chapter Greenhouse Gas Sources <0.05

0 20 40 60 80 100 120 Silicon Carbide Production Carbon Dioxide Consumption Ferroalloys Phosphoric Acid Production Titanium Dioxide Production Magnesium Production and Processing Soda Ash Manufacture and Consumption Petrochemical Production Semiconductor Manufacture Limestone and Dolomite Use Adipic Acid Aluminum Production

HCFC-22 Production

Lime Manufacture Electrical Transmission and Distribution Ammonia Production and Urea Application Nitric Acid Cement Manufacture Iron and Steel Production Substitution of Ozone Depleting Substances

Tg CO 2 Eq. Industrial Processes as a Portion of all Emissions

4.5%Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 189 

## 5. Solvent and Other Product Use

Greenhouse gas emissions are produced as a by-product of various solvent and other product uses. In the United States, emissions from Nitrous Oxide (N 2 O) Product Usage, the only source of greenhouse gas emissions from this sector, accounted for less than 0.1 percent of total U.S. anthropogenic greenhouse gas emissions on a carbon equivalent basis in 2003 (see Table 5-1). Ambient air pollu tant emissions also result from solvent and other product use, and are presented in Table 5-2.

Table 5-1: N 2 O Emissions from Solvent and Other Product Use (Tg CO 2 Eq. and Gg) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 Nitrous Oxide Product Usage

Tg CO 2 Eq. 4.3 4.8 4.8 4.8 4.8 4.8 4.8 4.8 Gg 13.9 15.4 15.4 15.4 15.4 15.4 15.4 15.4

Table 5-2: Ambient Air Pollutant Emissions from Solvent and Other Product Use (Gg) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 NO x 1 3 3 3 3 3 5 4 CO 4 1 1 46 46 45 46 65 NMVOCs 5,217 5,100 4,671 4,569 4,384 4,547 4,256 4,138



### 5.1. Nitrous Oxide Product Usage (IPCC Source Category 3D)

Nitrous oxide is a clear, colorless, oxidizing liquefied gas, with a slightly sweet odor. Nitrous oxide is produced by thermally decomposing ammonium nitrate (NH 4 NO 3 ), a chemical commonly used in fertilizers and explosives. The decomposition creates steam (H 2 O) and N 2 O through a low-pressure, low-temperature (500 ° F) reaction. Once the steam is removed through condensation, the remaining N 2 O is purified, compressed, dried, and liquefied for storage and distribution. Two companies operate a total of five N 2 O production facilities in the United States (CGA 2002).

Nitrous oxide is primarily used in carrier gases with oxy gen to administer more potent inhalation anesthetics for general anesthesia and as an anesthetic in various dental and veterinary applications. As such, it is used to treat short-term pain, for sedation in minor elective surgeries and as an induction anesthetic. The second main use of N 2 O is as a propellant in pressure and aerosol products, the largest application being pressure-packaged whipped cream. Small quantities of N 2 O also are used in the following applications:

• Oxidizing agent and etchant used in semiconductor manufacturing;

• Oxidizing agent used, with acetylene, in atomic absorption spectrometry;

• Production of sodium azide, which is used to inflate airbags;

• Fuel oxidant in auto racing; and

• Oxidizing agent in blowtorches used by jewelers and others (Heydorn 1997).

Production of N 2 O in 2003 was approximately 17 Gg. Nitrous oxide emissions were 4.8 Tg CO 2 Eq. (15.4 Gg) in 2003 (see Table 5-3). Production of N 2 O has stabilized over the past decade because medical markets have found other substitutes for anesthetics, and more medical procedures are being performed on an outpatient basis using local anesthetics that do not require N 2 O. The use of N 2 O as a propellant for whipped cream has also stabilized due to the increased popularity of cream products packaged in reusable plastic tubs (Heydorn 1997).

Table 5-3: N 2 O Emissions from Nitrous Oxide Product Usage (Tg CO 2 Eq. and Gg) Year Tg CO 2 Eq. Gg 1990 4.3 13.9

1997 4.8 15.4 1998 4.8 15.4Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 190 1999 4.8 15.4 2000 4.8 15.4 2001 4.8 15.4 2002 4.8 15.4 2003 4.8 15.4 

### Methodology

Emissions from N 2 O product usage were calculated by fi rst multiplying the total amount of N 2 O produced in the United States by the share of the total quantity of N 2 O that is used by each sector. This value was then multiplied by the associated emissions rate for each sector. After the emissions were calculated for each sector, they were added together to obtain a total estimate of N 2 O product usage emissions. Emissions were determined using the following equation:

Nitrous Oxide Product Usage Emissions = ∑ i [Total U.S. Production of Nitrous Oxide] × [Share of Total Quantity of N 2 O Usage by Sector i] × [Emissions Ra te for Sector i], where i = sector.

The share of total quantity of N 2 O usage by subcategory represents the share of national N 2 O produced that is used by the specific subcategory (i.e., anesthesia, food processing, etc.). In 2002, and also assumed for 2003, the medical/dental industry used an estimated 86 percent of total N 2 O produced, followed by food processing propellants at 6.5 percent. All other categories combined used the remainder of the N 2 O produced (Tupman 2002). This subcategory breakdown has changed only slightly over the past decade. For instance, the small share of N 2 O usage in the production of sodium azide has declined significantly during the decade of the 1990s. Due to the lack of information on the specific time period of the phase-out in this market subcategory, most of the N 2 O usage for sodium azide production is assumed to ha ve ceased after 1996, with the majority of its small share of the market assigned to the larger medical/dental consumption subcategory. Once the N 2 O is allocated across these subcategories, a usage emissions rate is then a pplied for each sector to estimate the amount of N 2 O emitted. Only the medical/dental and food propellant subcategories are estimated to release emissions into the atmosphere, and therefore these subcategories are the only usage subcategories with emission rates. For the medical/dental subcategory, due to the poor solubility of N 2 O in blood and other tissues, approximately 97.5 percent of the N 2 O is not metabolized during anesthesia and quickly leaves the body in exhaled breath. Therefore, an emission factor of 97.5 percent is used for this subcategory (Tupman 2002). For N 2 O used as a propellant in pressurized and aerosol food products, none of the N 2 O is reacted during the process and all of the N 2 O is emitted to the atmosphere, resulting in an emissions factor of 100 percent for this subcategory (Heydorn 1997). For the remaining subcategories, all of the N 2 O is consumed/reacted during the process, and therefore the emissions rate is considered to be zero percent (Tupman 2002). The 1990 through 1992 and 1996 N 2 O production data were obtai ned from SRI Consulting’s Nitrous Oxide, North America report (Heydorn 1997). These data were provided as a range. For example, in 1996, Heydorn (1997) estimates N 2 O production to range between 13.6 and 18.1 thousa nd metric tons. Tupman (2003) was able to provide a narrower range for 1996 that falls within the production bounds described by Heydorn (1997). These data are considered more industry specific and current. Th e midpoint of the narrower production range (15.9 to 18.1 thousand metric tons) was used to estimate N 2 O emissions for years 1993 through 2002 (Tupman 2003). Production data for 2003 was assumed to equal 2002 data.

The 1996 share of the total quantity of N 2 O used by each subcategory wa s obtained from SRI Consulting’s Nitrous Oxide, North America report (Heydorn 1997). The 1990 through 1995 share of total quantity of N 2 O used by each subcategory was kept the same as the 1996 number provi ded by SRI Consulting. The 1997 through 2002 share of total quantity of N 2 O usage by sector was obtained from communication with a N 2 O industry expert (Tupman 2003). Share of total quantity of N 2 O usage data for 2003 was assumed to equal that of 2002. The emissions rate for the food processing propellant indus try was obtained from SRI Consulting’s Nitrous Oxide, North America report (Heydorn 1997), and confirmed by a N 2 O industry expert (Tupman 2002). The emissions rate for all other subcategories was obtained from communication with a N 2 O industry expert (Tupman 2002). The emissions rate for the medical/dental subcategory was substantiated by the Encyclopedia of Ch emical Technology (Othmer 1990).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 191 Table 5-4: N 2 O Production (Gg) Year Gg 1990 16.3 1991 15.9 1992 15.0 1993 17.0 1994 17.0 1995 17.0 1996 17.0 1997 17.0 1998 17.0 1999 17.0 2000 17.0 2001 17.0 2002 17.0 2003 17.0 

### Uncertainty

Since plant-specific N 2 O production data is confidential, emissions are based on national production statistics acquired as ranges through reports and interviews with industry experts Heydorn (1997) and Tupman (2002). Based on these ranges, the uncertainty associated with the production estimate that was used to develop industry emissions in 2003 was calculated. Information regarding the industry-specific use of N 2 O is confidential. Thus, the predicted share of the total quantities of N 2 O used by each subcategory is somewh at uncertain because they are also based on industry expert opinion.

While the level of certainty differs by industry, the minimum and maximum market shares, expressed as a percent of N 2 O usage, are within 2 to 3 percentage points of the estimated market share. The emissions rate for the medical/dental industry, an estimate also based on industry opinion, carries an uncertainty level of 3 percent. Unquantified areas of uncertainty include the schedule of the market decline of sodium azide production.

An uncertainty analysis, based on the Tier 1 methods found in IPCC’s Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories, was conducted for all inputs to the N 2 O Product Usage source category analysis, including activ ity data, subcategory shares of N 2 O consumption, and emission factors. The results of the Tier 1 quantitative uncertainly analysis are summarized in Table 5-5. N 2 O Product Usage N 2 O emissions were estimated to be between 4.4 and 5.1 Tg CO 2 Eq. at the 95 percent confiden ce level. This indicates a range of 7 percent above and below the 2003 emission estimate of 4.8 Tg CO 2 Eq.

Table 5-5: Tier 1 Quantitative Uncertainty Estimates for N 2 O Emissions from Nitrous Oxide Product Usage (Tg CO 2 Eq. and Percent)

IPCC Source Category Gas Year 2003 Emissions (Tg CO 2 Eq.) Uncertainty (%) Uncertainty Range Relative to 2003 Emission Estimate (Tg CO 2 Eq.) Lower Bound Upper Bound N 2 O Product Usage N 2 O 4.8 7% 4.4 5.1



### Planned Improvements

Planned improvements include a continued evaluation of a lternative production statistics for cross verification and a reassessment of subcategory usage to accurately re present the latest trends in the product usage.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 192 

### 5.2. Ambient Air Pollutants from Solvent Use

The use of solvents and other chemical products can resu lt in emissions of various ozone precursors (i.e., ambient air pollutants). 1 Nonmethane volatile organic compounds (NM VOCs), commonly referred to as “hydrocarbons,” are the primary gases emitted from most processes employing organic or petroleum based solvents. As some of industrial applications also employ thermal incineration as a control technology, combustion by-products, such as carbon monoxide (CO) and nitrogen oxides (NOx), are also reported with this source category. Surface coatings accounted for approximately 41 percent of NMVOC emissions from solvent use in 2003, while “non-industrial” 2 uses accounted for about 38 percent and degreasing applications for 7 percent. Overall, solvent use accounted for approximately 28 percent of total U.S. emissions of NMVOCs in 2003; NMVOC emissions from solvent use have decreased 21 percent since 1990.

Although NMVOCs are not considered direct greenhouse gases, their role as precursors to the formation of

ozone

⎯ which is a greenhouse gas

⎯ results in their inclusion in a greenhouse gas inventory. Emissions from solvent use have been reported separately by the United States to be consistent with the inventory reporting guidelines recommended by the IPCC. These guidelines iden tify 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 mol ecules in the solvents escape into the atmosphere. The evaporation process varies depending on di fferent solvent uses and solvent types. The major categories of solvent uses include: degreasing, graphic arts, surface coating, other industrial uses of solvents (i.e., electronics, etc.), dry cleaning, and non-industrial uses (i.e., uses of paint thinner, etc.).

Total emissions of NO x , NMVOCs, and CO from 1990 to 2003 are reported in Table 5-6.

Table 5-6: Emissions of NO x , CO, and NMVOC from Solvent Use (Gg) Activity 1990 1997 1998 1999 2000 2001 2002 2003 NO x 1 3 3 3 3 3 5 4

Degreasing + + + + + + + + Graphic Arts + 1 1 + + + + + Dry Cleaning + + + + + + + + Surface Coating 1 2 2 3 3 3 5 4 Other Industrial Processes a + + + + + + + + Non-Industrial Processes b + + + + + + + + Other NA + + + + + + + CO 4 1 1 46 46 45 46 65

Degreasing + + + + + + + + Graphic Arts + + + + + + + + Dry Cleaning + + + + + + + + Surface Coating + 1 1 46 46 45 46 65 Other Industrial Processes a 4 + + + + + + + Non-Industrial Processes b + + + + + + + + Other NA + + + + + + + NMVOCs 5,217 5,100 4,671 4,569 4,384 4,547 4,256 4,138

Degreasing 675 566 337 363 316 331 310 301 Graphic Arts 249 266 272 224 222 229 214 208 Dry Cleaning 195 148 151 267 265 272 254 247

1 Solvent usage in the United States al so results in the emission of small am ounts 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, a nd other miscellaneous applications.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 193 Surface Coating 2,289 2,228 1,989 1,865 1,767 1,863 1,744 1,695 Other Industrial Processes a 85 100 101 95 98 103 97 94 Non-Industrial Processes b 1,724 1,790 1,818 1,714 1,676 1,707 1,598 1,554 Other + 3 3 40 40 42 40 38

a Includes rubber and plastics manufacturing, and other miscellaneous applications. b Includes cutback asphalt, pesticide app lication adhesives, consumer solvents, and other miscellaneous applications. Note: Totals may not sum due to independent rounding. + Does not exceed 0.5 Gg.



### Methodology

Emissions were calculated by aggregating solvent use da ta based on information relating to solvent uses from different applications such as degreas ing, graphic arts, etc. Emission fact ors 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 applyi ng the appropriate solvent-speci fic emission factors to the amount of solvents used for surface co atings, an estimate of emissions was obtained. Emissions of CO and NO x result primarily from thermal and catalytic incineration of solvent-laden gas streams from painting booths, printing operations, and oven exhaust.

These emission estimates were obtained from prelimin ary data (EPA 2004), and disaggregated based on EPA (2003), which, in its final iteration, will be published on the National Emission Inve ntory (NEI) Air Pollutant Emission Trends web site. Emissions were calculated either for individual categories or for many categories combined, using basic activity data (e.g., the amount of solvent purchased) as an indicator of emissions. National activity data were collected for individual applications from various agencies.

Activity data were used in conjunction with emission factors, which together relate the quantity of emissions to the activity. Emission factors are ge nerally 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 repor ts, the 1985 National Acid Precipitation and Assessment Program emissions inventory, and other EPA data bases.


### Uncertainty

Uncertainties in these estimates are par tly due to the accuracy of the emissi on factors used and the reliability of correlations between activity data and actual emissions.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 195 

## 6. Agriculture

Agricultural activities contribute directly to emissions of greenhouse gases thr ough a variety of processes. This chapter provides an assessment of non-carbon dioxide emissions from the following source categories: enteric fermentation in domestic livestock, livestock manure management, rice cultivation, agricultural soil management, and field burning of agricultural residues (see Figure 6-1). Carbon dioxide (CO 2 ) emissions and removals from agriculture-related land-use activities, such as conversion of grassland to cultivated land, are presented in the LandUse Change and Forestry sector. Ca rbon dioxide emissions from on-farm ener gy use are accounted in the Energy chapter.

Figure 6-1: 2003 Agriculture Chapter Greenhouse Gas Emission Sources

In 2003, the agricultural sector was responsible for emissions of 433.3 Tg CO 2 Eq., or 6.3 percent of total U.S. greenhouse gas emissions. Methane (CH 4 ) and nitrous oxide (N 2 O) were the primary greenhouse gases emitted by agricultural activities. Meth ane emissions from enteric fermentation a nd manure management represent about 21 percent and 7 percent of total CH 4 emissions from anthropogenic activities, re spectively. Of all domestic animal types, beef and dairy cattle were by far the largest emitters of CH 4 . Rice cultivation and agricultural crop residue burning were minor sources of CH 4 . Agricultural soil management activities such as fertilizer application and other cropping practices were the largest source of U.S. N 2 O emissions, accounting for 67 percent. Manure management and field burning of agricultural residues were also small sources of N 2 O emissions.

Table 6-1 and Table 6-2 present emission estimates for the Agriculture sector. Between 1990 and 2003, CH 4 emissions from agricultural activities increased by 3.2 percent while N 2 O emissions increased by 0.7 percent. In addition to CH 4 and N 2 O, field burning of agricultural residues was also a minor source of the ambient air pollutants carbon monoxide (CO) and nitrogen oxides (NO x ).

Table 6-1: Emissions from Agriculture (Tg CO 2 Eq.) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CH 4 156.9 163.0 164.2 164.6 162.0 161.9 161.5 161.8

Enteric Fermentation 117.9 118.3 116.7 116.8 115.6 114.5 114.6 115.0 Manure Management 31.2 36.4 38.8 38.8 38.1 38.9 39.3 39.1 Rice Cultivation 7.1 7.5 7.9 8.3 7.5 7.6 6.8 6.9 Field Burning of Agricultural

Residues 0.7 0.8 0.8 0.8 0.8 0.8 0.7 0.8 N 2 O 269.6 269.8 285.6 261.3 282.1 275.6 270.9 271.5

Agricultural Soil Management 253.0 252.0 267.7 243.4 263.9 257.1 252.6 253.5 Manure Management 16.3 17.3 17.4 17.4 17.8 18.0 17.9 17.5 Field Burning of Agricultural

Residues 0.4 0.4 0.5 0.4 0.5 0.5 0.4 0.4 Total 426.5 432.8 449.8 425.9 444.1 437.5 432.4 433.3 Note: Totals may not sum due to independent rounding.

Table 6-2: Emissions from Agriculture (Gg) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CH 4 7,470 7,760 7,821 7,838 7,713 7,708 7,689 7,705

Enteric Fermentation 5,612 5,634 5,557 5,561 5,505 5,454 5,458 5,475 Manure Management 1,485 1,733 1,850 1,846 1,813 1,853 1,873 1,864 Rice Cultivation 339 356 376 395 357 364 325 328 Field Burning of Agricultural

Residues 33 37 38 37 38 37 34 38 N 2 O 870 870 921 843 910 889 874 876Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 196 Agricultural Soil Management 816 813 864 785 851 829 815 818 Manure Management 52 56 56 56 57 58 58 57 Field Burning of Agricultural

Residues 1 1 1 1 1 1 1 1 CO 689 767 789 767 790 770 706 794 NO x 28 34 35 34 35 35 33 33 Note: Totals may not sum due to independent rounding.



### 6.1. Enteric Fermentation (IPCC Source Category 4A)

Methane is produced as part of normal digestive processes in animals. During digestion, microbes resident in an animal’s digestive system ferment food consumed by the animal. This microbial fermentation process, referred to as enteric fermentation, produces CH 4 as a by-product, which can be exhaled or eructated by the animal. The amount of CH 4 produced and excreted by an individual animal depends primarily upon the animal's digestive system, and the amount and type of feed it consumes.

Among domesticated animal types, rumi nant animals (e.g., cattle, buffalo, sh eep, goats, and camels) are the major emitters of CH 4 because of their unique digestive system. Rumina nts possess a rumen, or large "fore-stomach," in which microbial fermentation breaks down the feed they consume into products that can be absorbed and metabolized. The microbial fermentation th at occurs in the rumen enables them to digest coarse plant material that non-ruminant animals cannot. Ruminant anim als, consequently, have the highest CH 4 emissions among all animal types.

Non-ruminant domesticated animals (e.g., swine, horses, and mules) also produce CH 4 emissions through enteric fermentation, although this microbial fermentation occurs in the large intestine. These non-ruminants emit significantly less CH 4 on a per-animal basis than ruminants because the capacity of the larg e intestine to produce CH 4 is lower.

In addition to the type of digestive system, an animal’s feed quality and feed intake also affect CH 4 emissions. In general, lower feed quality or higher feed intake lead to higher CH 4 emissions. Feed intake is positively related to animal size, growth rate, and production (e.g., milk production, wool growth, pregnancy, or work). Therefore, feed intake varies among animal types as well as among differe nt management practices for individual animal types.

Methane emission estimates from enteric fermentation are pr ovided in Table 6-3 and Table 6-4. Total livestock CH 4 emissions in 2003 were 115 Tg CO 2 Eq. (5,475 Gg), increasing very slightly since 2002 due to minor increases in some animal populations and dairy cow milk producti on in some regions. Beef cattle remain the largest contributor of CH 4 emissions from enteric fermentation, accounting for 72 percent in 2003. Emissions from dairy cattle in 2003 accounted for 24 percent, and the remaining emissions were from horses, sheep, swine, and goats.

From 1990 to 2003, emissions from enteric fermentation have decreased by 2 percent. Generally, emissions have been decreasing since 1995, mainly due to decreasing populations of both beef and dairy cattle and improved feed quality for feedlot cattle. During this timeframe, populations of sheep and goats have also decreased, while horse populations increased and the populations of swine fluctuated.

Table 6-3: CH 4 Emissions from Enteric Fermentation (Tg CO 2 Eq.) Livestock Type 1990 1997 1998 1999 2000 2001 2002 2003 Beef Cattle 83.2 86.6 85.0 84.9 83.4 82.4 82.3 82.5 Dairy Cattle 28.9 26.4 26.3 26.6 27.0 26.9 27.1 27.3 Horses 1.9 2.0 2.0 2.0 2.0 2.0 2.0 2.0 Sheep 1.9 1.3 1.3 1.2 1.2 1.2 1.1 1.1 Swine 1.7 1.8 2.0 1.9 1.9 1.9 1.9 1.9 Goats 0.3 0.2 0.2 0.2 0.2 0.2 0.2 0.2 Total 117.9 118.3 116.7 116.8 115.6 114.5 114.6 115.0 Note: Totals may not sum due to independent rounding.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 197 Table 6-4: CH 4 Emissions from Enteric Fermentation (Gg) Livestock Type 1990 1997 1998 1999 2000 2001 2002 2003 Beef Cattle 3,961 4,124 4,047 4,045 3,973 3,923 3,919 3,930 Dairy Cattle 1,375 1,255 1,251 1,265 1,283 1,282 1,290 1,300 Horses 91 93 94 93 94 95 95 95 Sheep 91 64 63 58 56 56 53 50 Swine 81 88 93 90 88 88 90 90 Goats 13 10 10 10 10 10 10 10 Total 5,612 5,634 5,557 5,561 5,505 5,454 5,458 5,475 Note: Totals may not sum due to independent rounding.



### Methodology

Livestock emission estimates fall into two categories: cattle and other domesticated animals. Cattle, due to their large population, large size, and pa rticular digestive characteristics, account for the majority of CH 4 emissions from livestock in the United States. A more detailed methodology (i.e., IPCC Tier 2) was therefore applied to estimating emissions for all cattle except for bulls. Emission estimates for other domesticated animals (horses, sheep, swine, goats, and bulls) were handled using a less detailed approach (i.e., IPCC Tier 1).

While the large diversity of animal management practices cannot be precisely characterized and evaluated, significant scientific literature exists that describes the quantity of CH 4 produced by individual ruminant animals, particularly cattle. A detailed model that incorporates th is information and other anal yses of livestock population, feeding practices and production char acteristics was used to estimate emissions from cattle populations.

National cattle population statistics were disaggreg ated into the following cattle sub-populations: Dairy Cattle

• Calves

• Heifer Replacements

• Cows

Beef Cattle

• Calves

• Heifer Replacements

• Heifer and Steer Stockers

• Animals in Feedlots (Heifers and Steers)

• Cows

• Bulls Calf birth rates, end-of-year population statistics, detailed feedlot placemen t information, and sl aughter weight data were used to model cohorts of individual animal types and their specific emission profiles. The key variables tracked for each of the cattle population categories are described in Annex 3.9. These variables include performance factors such as pregnancy and lactation, as well as average we ights and weight gain. Annual cattle population data were obtained from the U.S. Department of Agriculture’s National Agricultural Statistics Service (1995a,b, 1999a,c,d,f, 2000a,c,d,f, 2001a,c,d,f, 2002a,c,d,f, 2003a,c,d,f, 2004a,c,d,f).

Diet characteristics were estimated by region for U.S. dairy, beef, and feedlot cattle. These estimates were used to calculate Digestible Energy (DE) values and CH 4 conversion rates (Y m ) for each population category. The IPCC recommends Y m values of 3.5 to 4.5 percent for feedlot cattle and 5.5 to 6.5 percent for other well-fed cattle consuming temperate-climate feed types. Given the availa bility of detailed diet information for different regions and animal types in the United States, DE and Y m values unique to the United States were developed, rather than using the recommended IPCC values. The diet characterizations and estimation of DE and Y m values were based on information from state agricultural extension specialists , a review of published forage quality studies, expertInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 198 opinion, and modeling of anim al physiology. The diet characteristics for dairy cattle were from Donovan (1999), while beef cattle were derived from NRC (2000). DE and Y m for dairy cows were calculated from diet characteristics using a model simulati ng ruminant digestion in growing and/or lact ating cattle (Donovan and Baldwin 1999). For feedlot animals, DE and Y m values recommended by Johnson (1999) were used. Values from EPA (1993) were used for dairy replacement heifers. For grazing beef cattle, DE va lues were based on diet information in NRC (2000) and Y m values were based on Johnson (2002). Weight data were estimated from Feedstuffs (1998), Western Dairyman (1998), and expert opinion. See Annex 3.9 for more details on the method used to characterize cattle diets in the United States.

To estimate CH 4 emissions from cattle, the population was divided into region, age, sub-type (e.g., calves, heifer replacements, cows, etc.), and production (i .e., pregnant, lactating, etc.) groupings to more fu lly capture differences in CH 4 emissions from these animal types. Cattle diet charact eristics were used to develop regional emission factors for each sub-category. Tier 2 equations from IPCC (2000) were used to produce CH 4 emission factors for the following cattle types: dairy cows, beef cows, dairy replacements, beef replacemen ts, steer stockers, heifer stockers, steer feedlot animals, and heifer feed lot animals. To estimate emissions from cattle, population data were multiplied by the emission factor for each cattle type. More details are provided in Annex 3.9. Emission estimates for other animal types were base d on average emission factor s representative of entire populations of each animal type. Me thane emissions from these animals acc ounted for a minor portion of total CH 4 emissions from livestock in the United States from 1990 th rough 2003. Also, the variability in emission factors for each of these other animal types (e .g., variability by age, production syst em, and feeding practice within each animal type) is less than that for ca ttle. Annual livestock population data fo r these other livestock types, except horses, as well as feedlot placement information were obtai ned from the U.S. Department of Agriculture’s National Agricultural Statistics Service (USDA 1994a-b, 1995a-b, 1998a-b, 1999a-c, 2000a-g , 2001a-f, 2002a-f, 2003a-f, 2004a-f). Horse population data were obtained from the FAOSTAT databa se (FAO 2004), because USDA does not estimate U.S. horse populations annually. Goat population data were obtained from the Census of Agriculture (USDA 1999g). Methane emissions from sheep, goats, swine, and horses were estimated by using emission factors utilized in Crutzen et al. (1986, cited in IPCC/UNEP/OE CD/IEA 1997). These emission factors are representative of typical animal sizes, feed intakes, and feed characteristics in developed countries. The methodology is the same as that recommended by IPCC (IPCC/UNEP/OECD/IEA 1997, IPCC 2000). See Annex 3.9 for more detailed information on the methodology and data used to calculate CH 4 emissions from enteric fermentation.


### Uncertainty

Uncertainty estimates were developed for the emission estimates presented in EPA (2003). No significant changes occurred in the method of data collection, data estimation methodology, or other factors that influence the uncertainty ranges around the 2003 activity data and emission factor input variables. Consequently, the EPA (2003) uncertainty estimates were directly applied to the 2003 emission estimates.

A total of 185 primary input variables (178 for cattle and 8 for non-cattle) were identified as key input variables for the uncertainty analysis. A normal distribution was assu med for almost all activity- and emission factor-related input variables. A triangular distribution was assigned for three input variables (specifically cow-birth ratios for the current and the past two years). For some key input variables, the uncertainty ranges around their estimates (used for inventory estimation) were collected from published documents and other public sources. In addition, both endogenous and exogenous correla tions between selected primary input variables were modeled. The exogenous correlation coefficients between the probability distributions of selected activity-related variables were developed as educated estimates.

The uncertainty ranges associated with the activity-related input variables were no larger in magnitude than plus or minus 10 percent. However, for many emission fact or-related input variables, the lower- and/or upper-bound uncertainty estimates were over 20 percent. The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 6-5. Enteric fermentation CH 4 emissions in 2003 were estimated to be between 102.3 and 135.7 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of 11 percent below to 18 percent above the 2003 emission estimate of 115.0 Tg CO 2 Eq. AmongInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 199 the individual sub-source categories, beef cattle accounts for the largest amount of CH 4 emissions as well as the largest degree of uncertainty in the emission estimates. Consequently, the cattle sub-source categories together contribute to the largest degree of uncertainty to the estimates of CH 4 emissions from livestock enteric fermentation. Among non-cattle, horses account for the largest degree of uncertainty in the emission estimates.

Table 6-5: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Enteric Fermentation (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Enteric Fermentation CH 4 115.0 102.3 135.7 -11% +18%

a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.



### QA/QC and Verification

In order to ensure the quality of the emission estimates from enteric fermentation, the IPCC Tier 1 and Tier 2 Quality Assurance/Quality Control (QA/QC) procedures were implemented consistent with the U.S. QA/QC plan. Tier 2 QA procedures include d independent peer review of emission estimates. Par ticular emphasis was placed on cattle population and growth data, and on evaluating the effects of data updates as described in the recalculations discussion below.



### Recalculations Discussion

While there were no changes in the methodologies used for estimating CH 4 emissions from enteric fermentation, emissions were revised slightly due to changes in hist orical data. USDA published revised population estimates in 2004 for some cattle statistics; these include population, livestock placements , and slaughter statistics for 2000, 2001, and 2002. Emission estimates change d for these years for both beef and dairy cattle as a result of revised inputs that reflect USDA updates.

The rate of weight gain for growing steers and heifers was increased for the modeling of 2000 through 2003. The model uses the weight gain data to estimate the number of cattle (steers and heifers) available to be placed into feedlots (by weight class). These estimates were comp ared to the USDA statistics on actual feedlot placements (by weight class). The updated USDA data show increases in feedlot placements in the heavy weight classes, and required an increase in the rate of weight gain in the m odeled population in order to match the observed statistics. Additionally, the distribution of cattle by weight at the start of the year was adjusted to reflect the larger portion of heavier animals.

In 2000, both beef and dairy cattle emissions changed less than 3 Gg (0.1 percent) as a result of the recalculations. In 2001, beef cattle CH 4 emissions increased 12 Gg (0.3 percent), while dairy cattle emissions decreased 1 Gg (0.1 percent). In 2002, beef cattle CH 4 emissions increased 8 Gg (0.2 percent), while dairy cattle emissions increased less than 1 Gg (0.03 percent). For other livestock types, a slight upward revision in the swine population for 2002 resulted in an increase in CH 4 emissions of less than 1 Gg (0.06 percent) in that year. Overa ll, the changes resulted in an average annual increase of less than 0.1 Tg CO 2 Eq. (0.04 percent) in CH 4 emissions from enteric fermentation for the period 1990 through 2002.


### Planned Improvements

The revised and updated USDA data disc ussed above highlight the need to re-examine several model inputs. Although the enteric fermentation model was constructed to identify the imbalances men tioned in the recalculations discussion, the current inventory presents the first effort to address such differences by making adjustments to model inputs. The updates are based both on expert opinion and on equations published by the American Society of Agricultural Engineers (ASAE) that predict weight versus age statistics for steers and imply growth rates larger thanInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 200 those used in previous years (ASAE 1999). In additi on, in 2001, USDA reported increased rates of gains for yearlings (USDA 2001g). While these two sources provide s upport for the updates, further research is necessary to verify the changes and to understand wh at changes over time may be necessary in future inventory analyses.



### 6.2. Manure Management (IPCC Source Category 4B)

The management of livestock manure can produce anthropogenic CH 4 and N 2 O emissions. Methane is produced by the anaerobic decomposition of manure. Nitrous oxide is produced as part of the nitrogen cycle through the nitrification and denitrification of the organic nitrogen in livestock manure and urine.

When livestock or poultry manure are st ored or treated in systems that pr omote anaerobic conditions (e.g., as a liquid/slurry in lagoons , ponds, tanks, or pits), the decomposition of materials in the manure tends to produce CH 4 . When manure is handled as a solid (e.g., in stacks or p its) or deposited on pasture, ra nge, or paddock lands, it tends to decompose aerobically and produce little or no CH 4 . A number of other factors related to how the manure is handled also affect the amount of CH 4 produced. Ambient temperature, moisture, and manure storage or residency time affect the amount of CH 4 produced because they influence the grow th of the bacteria responsible for CH 4 formation. For example, CH 4 production generally increases with rising temperature and residency time. Also, for non-liquid-based manure systems, mois t conditions (which are a function of rainfall and humidity) favor CH 4 production. Although the majority of manur e is handled as a solid, producing little CH 4 , the general trend in manure management, particularly for large dairy and swine producers, is one of increasing use of liquid systems. In addition, use of daily spread systems at smaller dairies is decreasing, due to new regulations limiting the application of manure nutrients, which has resulted in an increase of manure managed and stored on site at these smaller dairies.

The composition of the manure also affects the amount of CH 4 produced. Manure composition varies by animal type, including the animal’s digestive system and diet. In general, the greater the ener gy content of the feed, the greater the potential for CH 4 emissions. For example, feedlot cattle fed a high-energy grain diet generate manure with a high CH 4 -producing capacity. Range cattle fed a low energy diet of forage material produce manure with about 50 percent of the CH 4 -producing potential of feedlot cattle manure. However, some higher energy feeds also are more digestible than lower quality forages, which can result in less overall waste excreted from the animal. Ultimately, a combination of diet types and the growth rate of the animals will affect the quantity and characteristics of the manure produced.

A very small portion of the total nitrogen excreted is expected to convert to N 2 O in the waste management system. The production of N 2 O from livestock manure depends on the composition of the manure and urine, the type of bacteria involved in the process, and the amount of oxygen and liquid in the manure system. For N 2 O emissions to occur, the manure must first be handled aerobically where a mmonia or organic nitrogen is converted to nitrates and nitrites (nitrification), and then handled anaerobically wher e the nitrates and nitrites are reduced to nitrogen gas (N 2 ), with intermediate production of N 2 O and nitric oxide (NO) (denitrification) (Groffman et al. 2000). These emissions are most likely to occur in dry manure handling systems that have aerobic conditions, but that also contain pockets of anaerobic conditions due to saturation. For example, manure at cattle drylots is deposited on soil, oxidized to nitrite and nitrate, and has the potential to encounter satura ted conditions following rain events.

Certain N 2 O emissions are accounted for and discussed in the Agricultural Soil Management source category within the Agriculture sector. These are emissions from livestock manure and urine deposited on pasture, range, or paddock lands, as well as emissions from manure and urine that is spread onto fields either directly as “daily spread” or after it is removed from manure management systems (e.g., lagoon, pit, etc.).

Table 6-6 and Table 6-7 provide estimates of CH 4 and N 2 O emissions from manure management by animal category. Estimates for CH 4 emissions in 2003 were 39.1 Tg CO 2 Eq. (1,864 Gg), 25 percent higher than in 1990. The majority of this increase was from swine and dairy cow manure, where emissions increased 30 and 38 percent, respectively. The increase in emissions from these animal types is primarily attributed to shifts by the swine and dairy industries towards larger facilities. Larger swine and dairy farms tend to use liquid systems to manage (flush or scrape) and store manure. Thus the shift toward larger facilities is translated into an increasing use of liquid manure management systems, which have higher potential CH 4 emissions than dry systems. This shift wasInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 201 accounted for by incorporating state-specific weighted CH 4 conversion factor (MCF) values in combination with the 1992 and 1997 farm-size distribution data reported in the Census of Agriculture (USDA 1999e). From 2002 to 2003, there was a 0.5 percent decrease in CH 4 emissions, due to minor shifts in the animal populations and the resultant effects on manure management system allocations . A description of the emission estimation methodology is provided in Annex 3.10.

Total N 2 O emissions from manure management systems in 2003 were estimated to be 17.5 Tg CO 2 Eq. (57 Gg). The 8 percent increase in N 2 O emissions from 1990 to 2003 can be partially attributed to a shift in the poultry industry away from the use of liquid ma nure management systems, in favor of litter-based systems and high-rise houses. In addition, there was an overall increase in the population of poultry and swine from 1990 to 2002, although swine populations periodically declined slightly throughout the time series. Nitrous oxide emissions showed a 2 percent decrease from 2002 to 2003, due to minor shifts in animal population.

The population of beef cattle in feed lots increased over the period of 1990 to 2003, resulting in increased N 2 O emissions from this sub-category of cattle. Although dair y cow populations decreased overall for the period 1990 to 2003, the population of dairies managing and storing ma nure on-site—as opposed to using pasture, range, or paddock or daily spread systems—increased. Over the same period, dairies also experienced a shift to more liquid manure management systems at large operations, which result in lower N 2 O emissions then dry systems. The net result is a slight decrease in dairy cattle N 2 O emissions over the period 1990 to 2003. As stated previously, N 2 O emissions from livestock manure deposited on pasture, ra nge, or paddock land and manure immediately applied to land in daily spread systems are accounted for in the Agricultural Soil Management source category of the Agriculture sector.

Table 6-6: CH 4 and N 2 O Emissions from Manure Management (Tg CO 2 Eq.) Gas/Animal Type 1990 1997 1998 1999 2000 2001 2002 2003

CH 4 31.2 36.4 38.8 38.8 38.1 38.9 39.3 39.1

Dairy Cattle 11.4 13.4 13.9 14.7 14.5 15.0 15.2 15.7 Beef Cattle 3.2 3.2 3.1 3.1 3.1 3.1 3.1 3.1 Swine 13.1 16.4 18.4 17.6 17.1 17.4 17.7 17.0 Sheep 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Goats + + + + + + + + Poultry 2.7 2.7 2.7 2.6 2.6 2.7 2.7 2.7 Horses 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 N 2 O 16.3 17.3 17.4 17.4 17.8 18.0 17.9 17.5

Dairy Cattle 4.3 4.0 3.9 4.0 4.0 3.9 3.9 3.9 Beef Cattle 4.9 5.4 5.5 5.5 5.9 6.1 5.9 5.6 Swine 0.4 0.4 0.5 0.4 0.4 0.4 0.4 0.4 Sheep 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Goats + + + + + + + + Poultry 6.4 7.2 7.2 7.2 7.2 7.3 7.4 7.3 Horses 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 Total 47.4 53.7 56.2 56.2 55.9 57.0 57.3 56.7 + Does not exceed 0.05 Tg CO 2 Eq. Note: Totals may not sum due to independent rounding.

Table 6-7: CH 4 and N 2 O Emissions from Manure Management (Gg) Gas/Animal Type 1990 1997 1998 1999 2000 2001 2002 2003

CH 4 1,485 1,733 1,850 1,846 1,813 1,853 1,873 1,864

Dairy Cattle 545 639 662 700 692 715 722 748 Beef Cattle 153 152 149 150 149 148 147 146 Swine 622 780 874 837 812 826 843 808 Sheep 9 6 6 6 5 5 5 5Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 202 Goats 1 1 1 1 1 1 1 1 Poultry 128 127 130 125 125 129 126 127 Horses 27 28 28 28 28 29 29 29 N 2 O 52 56 56 56 57 58 58 57

Dairy Cattle 14 13 13 13 13 13 13 13 Beef Cattle 16 17 18 18 19 20 19 18 Swine 1 1 1 1 1 1 1 1 Sheep + + + + + + + + Goats + + + + + + + + Poultry 21 23 23 23 23 24 24 24 Horses 1 1 1 1 1 1 1 1 + Does not exceed 0.5 Gg. Note: Totals may not sum due to independent rounding.



### Methodology

The methodologies presented in Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2000) form the basis of the CH 4 and N 2 O emission estimates for each animal type. The calculation of emissions requires the following information:

• Animal population data (by animal type and state);

• Amount of nitrogen produced (excretion rate by animal type times animal population);

• Amount of volatile solids produced (excretion rate by animal type times animal population);

• Methane producing potential of the vol atile solids (by animal type);

• Extent to which the CH 4 producing potential is realized for each type of manure management system (by state and manure management system, including the impacts of any biogas collection efforts);

• Portion of manure managed in each manure manageme nt system (by state a nd animal type); and

• Portion of manure deposited on pasture, range, or paddock or used in daily spread systems.

This section presents a summary of the methodologies used to estimate CH 4 and N 2 O emissions from manure management for this inventory. See Annex 3.10 for more detailed information on the methodology and data used to calculate CH 4 and N 2 O emissions from manure management.

Both CH 4 and N 2 O emissions were estimated by first determining activity data, including animal population, waste characteristics, and manure management system usage. For swine and dairy cattle, manure management system usage was determined for different farm size cate gories using data from USDA (USDA 1996b, 1998d, 2000h) and EPA (ERG 2000a, EPA 2001a, 2001b). For beef cattle and poultr y, manure management system usage data was not tied to farm size (ERG 2000a, USDA 2000i, UEP 1999). For other animal types, manure management system usage was based on previous estimates (EPA 1992).

Next, MCFs and N 2 O emission factors were determined for all manure management systems. MCFs for dry systems and N 2 O emission factors for all systems were set equal to default IPCC factors for temperate climates (IPCC 2000). MCFs for liquid/slurry, anaer obic lagoon, and deep pit systems were cal culated based on the forecast performance of biological systems relative to temp erature changes as predicted in the van’t Hoff-Arrhenius equation (see Annex 3.10 for detailed information on MCF derivations for liquid systems). The MCF calculations model the average monthly ambient temperature, a minimum system temperature, the carryover of volatile solids in the system from month to month due to long storage times exhibited by anaerobic lagoon syst ems, and a factor to account for management and design practices that result in the loss of volatile solids from lagoon systems.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 203 For each animal group, the base emission factors were then weighted to incorporate the distribution of management systems used within each state and ther eby to create an overall state-specific we ighted emission factor. To calculate this weighted factor, the percent of manure for each animal group managed in a particular system in a state was multiplied by the emission factor for that system and state, and then summed for all manure management systems in the state.

Methane emissions were estimated using the volatile solid s (VS) production for all lives tock. For poultry and swine animal groups, for example, volatile solids production was calcu lated using a national average volatile solids production rate from the Agricultural Waste Management Field Handbook (USDA 1996a), which was then multiplied by the average weight of th e animal and the state-specific animal population. For most cattle groups, regional animal-specific volatile solids produc tion rates that are related to the diet of the animal for each year of the inventory were used (Lieberman et al., 2004). The resulting volatile solids fo r each animal group was then multiplied by the maximum CH 4 producing capacity of the waste (B o ) and the state-specific CH 4 conversion factors.

Nitrous oxide emissions were estimated by determining total Kjeldahl nitrogen (TKN) 1 production for all livestock wastes using livestock population data and nitrogen excreti on rates based on measurements of excreted manure. For each animal group, TKN production was calculated using a national average nitrogen excretion rate from the Agricultural Waste Management Field Handbook (USDA 1996a), which was then multiplied by the average weight of the animal and the state-specific animal population. State-specific weighted N 2 O emission factors specific to the type of manure management system were then applied to total nitrogen production to estimate N 2 O emissions.

The data used to calculate the inventory estimates were based on a variety of sources. Animal population data for all livestock types, except horses and goats, were obtaine d from the U.S. Department of Agriculture’s National Agricultural Statistics Service (USDA 1994a-b, 1995a-b, 1998a-b, 1999a-c, 2000a-g , 2001a-f, 2002a-f, 2003a-f, 2004a-f). Horse population data were obtained from the FAOSTAT databa se (FAO 2004), because USDA does not estimate U.S. horse populations annually. Goat population data were obtained from the Census of Agriculture (USDA 1999d). Information regarding poultry turnover (i .e., slaughter) rate was obtained from state Natural Resource Conservation Service (NRCS) personnel (Lange 2000). Dairy cow and swine population data by farm size for each state, used for the weighted MCF and emissi on factor calculations, were obtained from the Census of Agriculture , which is conducted every five years (USDA 1999e).

Manure management system usage data for dairy and swine operations were obtained from USDA’s Centers for Epidemiology and Animal Health (USDA 1996b, 1998d, 2000h) for small operations and from preliminary estimates for EPA’s Office of Water regulatory effort for large operations (ERG 2000a; EPA 2001a, 2001b). Data for layers were obtained from a voluntary United Egg Producers’ survey (UEP 1999), previous EPA estimates (EPA 1992), and USDA’s Animal Plant Health Inspection Service (USDA 2000i). Data for beef feedlots were also obtained from EPA’s Office of Water (ERG 2000a; EPA 2001a, 2001b). Manure management system usage data for other livestock were taken from previous estimates (E PA 1992). Data regarding the use of daily spread and pasture, range, or paddock systems for dairy cattle were obtained fro m personal communications with personnel from several organizations, and data pr ovided by those personnel (Poe et al . 1999). These organizations include state NRCS offices, state extension services, state uni versities, USDA National Agriculture Statistics Service (NASS), and other experts (Deal 2000, Johnson 2000, Miller 2000, Stettler 2000, Sweeten 2000, and Wright 2000). Additional information regarding the percent of beef steer and heifers on feedlots was obtained from contacts with the national USDA office (Milton 2000).

Methane conversion factors for liquid systems were calculated based on average ambient temperatures of the counties in which animal populations were located. The average county and state temperature data were obtained from the National Climate Data Center (NOAA 2004), and the county population data were calculated from statelevel population data from NASS and county-state distri bution data from the 1992 and 1997 Census data (USDA 1999e). County population distribution data for 1990 and 1991 were assumed to be the same as 1992; county

1 Total Kjeldahl nitrogen is a measure of organically bound nitrogen and ammonia nitrogen.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 204 population distribution data for 1998 through 2003 were assu med to be the same as 1997; and county population distribution data for 1993 through 1996 were ex trapolated based on 1992 and 1997 data.

The maximum CH 4 producing capacity of the volatile solids, or B o , was determined based on data collected in a literature review (ERG 2000b). B o data were collected for each animal ty pe for which emissions were estimated.

Nitrogen excretion rate data from the USDA Agricultural Waste Management Field Handbook (USDA 1996a) were used for all livestock except sheep, goats, and horses. Data from the Am erican Society of Ag ricultural Engineers (ASAE 1999) were used for these animal types. Volatile solids excretion rate data from the USDA Agricultural Waste Management Field Handbook (USDA 1996a) were used for swine, poultry, bulls, and calves not on feed. In addition, volatile solids production rates from Lieberman et al. (2004) were used for dairy and beef cows, heifers, and steer for each year of the inventory. Nitrous oxide emission factors and MCFs for dry systems were taken from Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2000).


### Uncertainty

An analysis was conducted for the manure management emission estimates presented in EPA (2003) to determine the uncertainty associated with estimating N 2 O and CH 4 emissions from livestock manure management. Because no substantial modifications were made to the inventory me thodology since the development of these estimates, it is expected that this analysis is appli cable to the uncertainty a ssociated with the current manure management emission estimates.

The EPA (2003) quantitative uncertainty analysis for this source cate gory was performed through the IPCCrecommended Tier 2 uncertainty estimation methodology, Monte Carlo Stochastic Simulation technique. The uncertainty analysis was developed based on the methods used to estimate N 2 O and CH 4 emissions from manure management systems. A normal probability distribution was assume d for each source data category. The series of equations used were condensed into a single equation for each animal type and state. The equations for each animal group contained four to five variables around which the uncertainty an alysis was performed for each state.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 6-8. Manure management CH 4 emissions in 2003 were estimated to be between 32.1 and 47.0 Tg CO 2 Eq. at a 95 percent confidence level (or 19 of 20 Monte Carlo Stochastic Simulations). This indicates a range of 18 percent below to 20 percent above the 2003 emission estimate of 39.1 Tg CO 2 Eq. At the 95 percent confidence level, N 2 O emissions were estimated to be between 14.7 and 21.7 Tg CO 2 Eq. (or approximately 16 percent below and 24 percent above the 2003 emission estimate of 17.5 Tg CO 2 Eq.).

Table 6-8: Tier 2 Quantitative Uncertainty Estimates for CH 4 and N 2 O Emissions from Manure Management (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Manure Management CH 4 39.1 32.1 47.0 -18% +20% Manure Management N 2 O 17.5 14.7 21.7 -16% +24%

a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.

The primary factors that contribute to th e uncertainty in emission estimates are a lack of information on the usage of various manure management systems in each regional location and the exact CH 4 generating characteristics of each type of manure management system. B ecause of significant shifts in the sw ine and dairy sectors toward larger farms, it is believed that increasing amounts of manure are being managed in liquid manure management systems. The existing estimates reflect these shifts in the weighted MCFs based on the 1992 and 1997 farm-size data. However, the assumption of a direct relationship between farm size and liquid system usage may not apply in all cases and may vary based on geographi c location. In addition, the CH 4 generating characteristics of each manureInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 205 management system type are based on relatively few laboratory and field measurements, and may not match the diversity of conditions under which manure is managed nationally.

Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2000) published a default range of MCFs for anaerobic lagoon system s of 0 to 100 percent, which reflects the wide range in performance that may be achieved with these systems. There exist relatively few data points on which to determine country-specific MCFs for these systems. In the United States, many livestock waste treatment systems classified as anaerobic lagoons are actually holding ponds that are substantially organically overloaded and therefore not producing CH 4 at the same rate as a properly designed la goon. 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 treatme nt to occur. Rather th an setting the MCF for all anaerobic lagoon systems in the United States based on data available from optimized lagoon systems, a MCF methodology was develope d that more closely matches observed system performance and accounts for the affect of temperature on system performance.

However, there is uncertainty related to this methodology. The MCF methodology used in the inventory includes a factor to account for management and de sign 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 inte nded to account for systems acr oss a range of management practices. Future work in gatheri ng measurement data from animal wast e lagoon systems across the country will contribute to the verificati on and refinement of this methodology. It will also be evaluated whether lagoon temperatures differ substantially from ambient temperatures and whether the lower bound estimate of temperature established for lagoons and other liquid systems shoul d be revised for use with this methodology.

The IPCC provides a suggested MCF for poultry waste manageme nt operations of 1.5 percen t. Additional study is needed in this area to dete rmine if poultry high-rise houses promote suffi cient aerobic conditions to warrant a lower MCF.

The default N 2 O emission factors published in Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2000) were derived using limited information. The IPCC factors are global averages; U.S.-specific emission factors may be significantly different. Manure and urine in anaerobic lagoons and liquid/slurry management systems produce CH 4 at different rates, and would in all likelihood produce N 2 O at different rates, although a single N 2 O emission factor was used for both system types. In addition, there are little data available to determine the extent to which nitrification-denitrification occurs in animal waste management systems. Ammonia concentrations that are present in poultry and swine systems suggest that N 2 O emissions from these systems may be lower than predicted by the IPCC default factors. At this time, there are insufficient data available to develop U.S.-specific N 2 O emission factors; however, this is an area of on-going research, and warrants further study as more data become available.

Uncertainty also exists with the maximum CH 4 producing potential of volatile solid s excreted by different animal groups (i.e., B o ). The B o values used in the CH 4 calculations are published values fo r U.S. animal waste. However, there are several studies that provide a range of B o values for certain animals, including dairy and swine. The B o values chosen for dairy assign separate values for dairy cows and dairy heifers to better represent the feeding regimens of these animal groups. For example, dairy he ifers do not receive an abundan ce of high energy feed and consequently, dairy heifer manure will not produce as much CH 4 as manure from a milking cow. However, the data available for B o values are sparse, and do not necessarily reflect the rapid changes that have occurred in this industry with respect to feed regimens.



### QA/QC and Verification

Tier 1 and Tier 2 QA/QC activities were conducted consistent with the U.S. QA/QC plan. Tier 2 activities focused on comparing estimates for the 2002 and 2003 Inventories for N 2 O emissions from managed systems and CH 4 emissions from livestock manure. All errors identified were corrected. Order of ma gnitude checks were also conducted, and corrections made where needed. Manure nitr ogen data were quality assure d by comparing state-level data with bottom up estimates derived at the county level and summed to the state level. Similarly, a comparisonInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 206 was made by animal and waste management system type for the full time series, between national level estimates for nitrogen excreted and the sum of county estimates for the full time series. Effort s also continue to transition various components of the manure management inventory into a database to facilitate current and future QA checks.



### Recalculations Discussion

No changes have been incorporated into the overall methodology for the manure management emission estimates; however, changes were made to the calculation of CH 4 emissions from sheep, goats, and horses. Changes were also made to address errors and updates in the population and waste management system data from previous inventory submittals. Additionally the population di stribution of horses and poultry were ad justed, the typical animal mass for sheep was adjusted, and the temperature estimations were changed to reflect a refined methodology. Each of these changes is described in detail below.

• Methane emission estimation from sheep, goats, and horses. The sheep, goats, and horses emission methodologies were changed to be consistent with the methodologies used for the other animal groups. Previously, the sheep, goat, and horse methane estimat es were scaled based on population data and earlier estimates of methane emissions (EPA 1992).

• Population. All USDA data from 1998 through the present year underwent review pursuant to USDA NASS annual review procedures. The population data in these years reflect some adjustments due to this review. For horses, state-level populations were es timated using the national FAO population data and the state distributions from the 1992 and 1997 Census of Agriculture. For poultry, populations for states reporting non-disclosed populations were estimated by di stributing population values attributed to “other”
states.

• Waste management system. The waste management system data for poultry were adjusted based on more recent data. Previously, layers were estimated to be 99 percent managed (EPA 1992). More recent WMS data available from USDA's Animal Plant and Health Inspection Service Layers '99 study (USDA 2000i) and the United Egg Producers Study (UEP 1999) indicate that layers are 100 percent managed. Therefore, the layer WMS estimates have been updated accordingly. Also, the waste manage ment system distribution for dairy cows was adjusted to correct rounding errors.

• Typical animal mass. The typical animal mass for sh eep were reevaluated and ad justed. Typical animal mass of sheep was adjusted from 27 kg to 68.6 kg (see Annex 3.10 for details).

• Temperature data: Temperature data are not available for every county with animal populations. Previously, counties without temperat ure data were not accounted for in the estimate of average weighted temperature. This methodology was changed to use the state average temperature for counties without temperature data available.

The combination of these changes resulted in an average annual increase of 0.1 Tg CO 2 Eq. (0.3 percent) in CH 4 emissions and an average annual increase of 0.1 Tg CO 2 Eq. (0.4 percent) in N 2 O emissions from manure management for the period 1990 through 2002.


### Planned Improvements

Currently, temperate zone MCFs are used for non-liquid wa ste management systems, including pasture, range, and paddock, daily spread, solid storage, and drylot operations. However, there are some states that have an annual average temperature that would fall be low 15°C (i.e., “cool”). Therefore, CH 4 emissions from certain non-liquid waste management systems may be overestimated; however, th e difference is expected to be relatively small due to the low MCFs for all “dry” management systems. The use of both cool and temperate MCFs for non-liquid waste management systems will be investigated for future inventories.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 207 Although an effort was made to introdu ce the variability in volatile solids produc tion due to differences in diet for beef and dairy cows, heifers, and steer, further research is needed to confirm and track diet changes over time. A methodology to assess variability in swin e volatile solids production would be usef ul in future inventory estimates.

The American Society of Agricultural Engineers is pub lishing new standards for manure production characteristics in 2004. These data will be investigated and eval uated for incorporation into future estimates.

The development of the National Ammonia Emissions Inventory for the United States (EPA 2004) used similar data sources to the current estimates of emissions from manur e management, and through the course of development of the ammonia inventory, updated waste mana gement distribution data were identif ied. Future estimates will attempt to reflect these updated data.

The methodology to calculate MCFs fo r liquid systems will be examined to determine how to account for a maximum temperature in the liquid systems. Additionally, available research will be investigated to develop a relationship between ambient air temperature and temperature in liquid waste management systems in order to improve that relationship in the MCF methodology.

Research will be initiated into the estimation and validation of the maximum CH 4 -producing capacity of animal manure (B o ), for the purpose of obtaining more accura te data to develop emission estimates.

The 2002 Census of Agriculture became available in mid-2004. These data will be used to update assumptions that previously relied on the 1992 and 1997 Census of Agriculture.



### 6.3. Rice Cultivation (I PCC Source Category 4C)

Most of the world’s rice, and all rice in the United States, is grown on flooded fields. When fields are flooded, aerobic decomposition of organic material gradually depletes the oxygen present in the soil and floodwater, causing anaerobic conditions in the soil to develop. Once the environment becomes anaerobic, CH 4 is produced through anaerobic decomposition of soil organic matter by methanogenic bacteria. As much as 60 to 90 percent of the CH 4 produced is oxidized by aerobic methanotrophic bacteria in the soil (Holzapfel-Pschorn et al. 1985, Sass et al. 1990). Some of the CH 4 is also leached away as dissolved CH 4 in floodwater that percolates from the field. The remaining un-oxidized CH 4 is transported from the submerged soil to the atmosphere primarily by diffusive transport through the rice plants. Minor amounts of CH 4 also escape from the soil via diffusion and bubbling through floodwaters.

The water management system under which rice is grown is one of the most important factors affecting CH 4 emissions. Upland rice fields are not flooded, and therefore are not believed to produce CH 4 . 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 CH 4 transport pathway to the atmosphere is blocked. The quantities of CH 4 released from deepwater fields, therefore, are believed to be significantly less than the quantities released from areas with more shallow flooding depths. Some flooded fields are drained periodica lly during the growing season, either intentionally or accidentally. If water is drained and soils are allowed to dry sufficiently, CH 4 emissions decrease or stop entirely. This is due to soil aeration, which not only causes existing soil CH 4 to oxidize but also inhibits further CH 4 production in soils. All rice in the United States is grown under continuously floode d conditions; none is grown under deepwater conditions. Mid-season drainage does not occur except by acci dent (e.g., due to levee breach).

Other factors that influence CH 4 emissions from flooded rice fi elds include fertilization pr actices (especially the use of organic fertilizers), soil temperature, soil type, rice variety, and cultivation practices (e.g., tillage, seeding and weeding practices). The factors that determine the amount of organic material that is available to decompose (i.e.,Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 208 organic fertilizer use, soil type, rice variety, 2 and cultivation practices) are the most important variables influencing the amount of CH 4 emitted over an entire growing seas on because the total amount of CH 4 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 CH 4 production. However, although temperature controls the amount of time it takes to convert a given amount of organic material to CH 4 , that time is short relative to a growing season, so the dependence of total emissions over an entire growing season on soil temperature is weak. The application of synthe tic fertilizers has also b een found to influence CH 4 emissions; in particular, both nitrate and sulfate fertilizers (e.g., ammonium nitrate, and ammonium sulfate) appear to inhibit CH 4 formation.

Rice is cultivated in eight states: Arkansas, California, Florida, Louisiana, Mississippi, Missouri, Oklahoma, and Texas. Soil types, rice varieties, and cultivation practices for rice vary from state to state, and even from farm to farm. However, most rice farmers utilize organic fertilizer s in the form of rice residue from the previous crop, which is left standing, disked, or rolled into the fields. Most farmers also apply synthetic fertilizer to their fields, usually urea. Nitrate and sulfate fertilizers are not comm only used in rice cultivation in the United States. In addition, the climatic conditions of Arka nsas, southwest Louisiana, Texas, and Florida allow for a second, or ratoon, rice crop. Methane emissions from ratoon crops have been found to be considerably higher than those from the primary crop. This second rice crop is produced from regrowth of the stubble after the first crop has been harvested. Because the first crop’s stubble is left behind in ratooned fields, and there is no time delay between cropping seasons (which would allow for the stubble to decay aerobically), the am ount of organic material that is available for decomposition is considerably higher than with the first (i.e., primary) crop.

Rice cultivation is a small source of CH 4 in the United States (Table 6-9 and Table 6-10). In 2003, CH 4 emissions from rice cultivation were 6.9 Tg CO 2 Eq. (328 Gg)

. Although annual emissions fluctuated unevenly between the years 1990 and 2003, ranging from an annual decrease of 11 per cent to an annual increase of 17 percent, there was an overall decrease of 3 percent over the thirteen-year period, due to an overall decrease in ratoon crop area. 3 The factors that affect the rice acreage in any year vary from state to state, although the price of rice relative to competing crops is the primary controlling variable in most states. Price is the primary factor affecting rice area in Arkansas, as farmers will plant more of what is most lucrative amongst soybeans, rice, and cotton. Government support programs have also been influential by affecti ng the price received for a rice crop (Slaton 2001b, Mayhew 1997). California rice area is primarily influenced by price and government programs, but is also affected by water availability (Mutters 2001). In Florida, rice acreage is largely a function of th e price of rice relative to sugarcane and corn. Most rice in Florida is rotated with sugarcane, but sometimes it is more profitable for farmers to follow their sugarcane crop with sweet corn or more sugarcane instead of rice (Schueneman 1997, 2001b). In Louisiana, rice area is influenced by government support programs, the price of rice relative to cotton, soybeans, and corn, and in some years, weather (Saichuk 1997, Linscombe 2001b). For example, a drought in 2000 caused extensive saltwater intrusion along the Gulf Coast, making over 32,000 hectares unplantable. The dramatic decrease in ratooned area in Louisiana in 2002 was the result of hurricane damage to that state’s rice-cropped area. In Mississippi, rice is usually rotated with soybeans, but if soyb ean prices increase relative to rice prices, then some of the acreage that would have been planted in rice, is instead planted in soybeans (Street 1997, 2001). In Missouri, rice acreage is affected by weather (e.g ., rain during the planting season may prevent the planting of rice), the price differential between rice and soybeans or cotton, and government support programs (Stevens 1997, Guethle 2001). In Oklahoma, the state having the smalle st harvested rice area, rice acreage is lim ited to the areas in the state with the right type of land for rice cultivation. Acreage is limited to growers who can afford the equipment, labor, and land for this intensive crop (Lee 2003). Texas rice area is affected mainly by the price of rice, government support programs, and water availability (Klosterboer 1997, 2001b).

Table 6-9: CH 4 Emissions from Rice Cultivation (Tg CO 2 Eq.)

2 The roots of rice plants shed organic material, which is refe rred to as “root exudate.” The amount of root exudate produced by a rice plant over a growing seas on varies among rice varieties. 3 The 11 percent decrease occurred between 1992 and 1993; the 17 percent increase happened between 1993 and 1994.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 209 State 1990 1997 1998 1999 2000 2001 2002 2003 Primary 5.1 5.6 5.8 6.3 5.5 5.9 5.7 5.4

Arkansas 2.1 2.5 2.7 2.9 2.5 2.9 2.7 2.6 California 0.7 0.9 0.8 0.9 1.0 0.8 0.9 0.9 Florida + + + + + + + + Louisiana 1.0 1.0 1.1 1.1 0.9 1.0 1.0 0.8 Mississippi 0.4 0.4 0.5 0.6 0.4 0.5 0.5 0.4 Missouri 0.1 0.2 0.3 0.3 0.3 0.4 0.3 0.3 Oklahoma + + + + NA + + + Texas 0.6 0.5 0.5 0.5 0.4 0.4 0.4 0.3 Ratoon 2.1 1.9 2.1 2.0 2.0 1.7 1.1 1.5

Arkansas + + + + + + + + Florida + 0.1 0.1 0.1 0.1 + + + Louisiana 1.1 1.2 1.2 1.2 1.3 1.1 0.5 1.0 Texas 0.9 0.7 0.8 0.7 0.7 0.6 0.5 0.5 Total 7.1 7.5 7.9 8.3 7.5 7.6 6.8 6.9 + Less than 0.05 Tg CO 2 Eq. NA (Not Available) Note: Totals may not sum due to independent rounding.

Table 6-10: CH 4 Emissions from Rice Cultivation (Gg CH 4 ) State 1990 1997 1998 1999 2000 2001 2002 2003 Primary 241 265 279 300 260 283 274 255

Arkansas 102 118 126 138 120 138 128 124 California 34 44 39 43 47 40 45 43 Florida 1 2 2 2 2 1 1 1 Louisiana 46 50 53 52 41 46 45 38 Mississippi 21 20 23 27 19 22 22 20 Missouri 7 10 12 16 14 18 15 15 Oklahoma + + + + NA + + + Texas 30 22 24 22 18 18 18 15 Ratoon 98 91 98 95 97 81 52 73

Arkansas + + + + + + + + Florida 2 3 3 4 2 2 2 2 Louisiana 52 55 59 58 61 52 25 50 Texas 45 33 36 33 34 27 24 22 Total 339 356 376 395 357 364 325 328 + Less than 0.5 Gg NA (Not Available) Note: Totals may not sum due to independent rounding. 

### Methodology

The Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) recommends utilizing harvested rice areas and area-based seasonally integrated emission factors (i.e., amount of CH 4 emitted over a growing season per unit harvested area) to estimate annual CH 4 emissions from rice cultivation. This methodology is followed with the use of U.S.-specific emission factors derived from rice field measurements. Seasonal emissions have been found to be much higher for ratooned crops than for primary crops, so emissions from ratooned and primary areas are estimated separately using emission factors that are representative of the particular growing season. This approach is consistent with IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2000).

The harvested rice areas for the primary and ratoon crops in each state are presented in Table 6-11. Primary crop areas for 1990 through 2003 for all states except Florida and Oklahoma were taken from U.S. Department of Agriculture’s Field Crops Final Estimates 1987-1992 (USDA 1994), Field Crops Final Estimates 1992-1997Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 210 (USDA 1998), Crop Production 2000 Summary (USDA 2001), Crop Production 2001 Summary (USDA 2002), Crop Production 2002 Summary (USDA 2003), and Crop Production 2003 Summary (USDA 2004). Harvested rice areas in Florida, which are not reported by US DA, were obtained from Tom Schueneman (1999b, 1999c, 2000, 2001a) and Arthur Kirstein (2003), Florida agricultural extension agents, Dr. Chris Deren (2002) of the Everglades Research and Education Centre at the University of Florida, and Gaston Cantens (2004), Vice President of Corporate Relations of the Florida Crystals Company. Harvested rice areas for Oklahoma, which also are not reported by USDA, were obtained from Danny Lee of the Oklahoma Farm Services Agency (Lee 2003, 2004). Acreages for the ratoon crops were deri ved from conversations with the agricultu ral extension agents in each state. In Arkansas, ratooning occurred only in 1998 and 1999, when the ratooned area was less than 1 percent of the primary area (Slaton 1999, 2000, 2001a). In Florida, the ratooned area was 50 percent of the primary area from 1990 to 1998 (Schueneman 1999a), about 65 percent of the primary area in 1999 (Schueneman 2000), around 41 percent of the primary area in 2000 (Schueneman 2001a), about 60 percent of the primary area in 2001(Deren 2002), about 54 percent of the primary area in 2002 (Kirstein 2003) and about 100 percent of the primary area in 2003 (Kirsetin 2004). In Louisiana, the percentage of the primary area that was ratooned was constant at 30 percent over the 1990 to 1999 period, increased to approximately 40 percent in 2000, returned to 30 percent in 2001, dropped to 15 percent in 2002, and rose to 35 pe rcent in 2003 (Linscombe 1999a, 2001a, 2002, 2003, 2004 and Bollich 2000). In Texas, the percentage of the primary area that was ratoone d was constant at 40 percent over the entire 1990 to 1999 period and in 2001, but increased to 50 percent in 2000 due to an early primary crop; it then decreased to 40 percent in 2001, 37 percent in 2002, and 38 percent in 2003 (Klosterboer 1999, 2000, 2001a, 2002, 2003, Stansel 2004).

Table 6-11: Rice Areas Harvested (Hectares) State/Crop 1990 1997 1998 1999 2000 2001 2002 2003 Arkansas Primary 485,633 562,525 600,971 657,628 570,619 656,010 608,256 588,830 Ratoon* NO NO 202 202 NO NO NO NO California 159,854 208,822 185,350 204,371 221,773 190,611 213,679 205,180 Florida Primary 4,978 7,689 8,094 7,229 7,801 4,562 5,077 2,315 Ratoon 2,489 3,845 4,047 4,673 3,193 2,752 2,734 2,315 Louisiana Primary 220,558 235,937 250,911 249,292 194,253 220,963 216,512 182,113 Ratoon 66,168 70,781 75,273 74,788 77,701 66,289 32,477 63,739 Mississippi 101,174 96,317 108,458 130,716 88,223 102,388 102,388 94,699 Missouri 32,376 47,349 57,871 74,464 68,393 83,772 73,654 69,203 Oklahoma 617 12 19 220 NA 265 274 53 Texas Primary 142,857 104,816 114,529 104,816 86,605 87,414 83,367 72,845 Ratoon 57,143 41,926 45,811 41,926 43,302 34,966 30,846 27,681 Total Primary 1,148,047 1,263,468 1,326,203 1,428,736 1,237,668 1,345,984 1,303,206 1,215,237

Total Ratoon 125,799 116,552 125,334 121,589 124,197 104,006 66,056 93,735 Total 1,273,847 1,380,020 1,451,536 1,550,325 1,361,864 1,449,991 1,369,262 1,308,972 * Arkansas ratooning occurred only in 1998 and 1999. NO (Not Occurring) NA (Not Available) Note: Totals may not sum due to independent rounding.
To determine what seasonal CH 4 emission factors should be used for the primary and ratoon crops, CH 4 flux information from rice field measurements in the United States was collected. Experiments which involved atypical or nonrepresenative management practices (e.g., the applicati on of nitrate or sulfate fertilizers, or other substancesInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 211 believed to suppress CH 4 formation), as well as experiments in whic h measurements were not made over an entire flooding season or floodwaters were drained mid-season, were excluded from the analysis. The remaining experimental results 4 were then sorted by season (i.e., primary and ratoon) and type of fer tilizer amendment (i.e., no fertilizer added, organic fertilizer added, and synthetic and organic fertilizer added). The experimental results from primary crops with added synthetic and organic fertilizer (Bossio et al. 1999, Cicerone et al. 1992, Sass et al. 1991a and 1991b) were averaged to derive an emission factor for the primary crop, and the experimental results from ratoon crops with added synt hetic fertilizer (Lindau and Bollich 1993, Linda u et al. 1995) were averaged to derive an emission factor for the ratoon crop. The resultant emission factor for the primary crop is 210 kg CH 4 /hectareseason, and the resultant emission factor for the ratoon crop is 780 kg CH 4 /hectare-season.


### Uncertainty

The largest uncertainty in the calculation of CH 4 emissions from rice cultivation is associated with the emission factors. Seasonal emissions, derived from field measurements in the United States, vary by more than one order of magnitude. This inherent variability is due to differences in cultivation practices, in particular, fertilizer type, amount, and mode of applicati on; differences in cultivar type; and differe nces in soil and climatic conditions. A portion of this variability is accounted for by separating primary from ratoone d areas. However, even within a cropping season or a given management regime, measured emissions may vary significantly. Of the experiments used to derive the emission factors applied here, primary emissions ranged from 22 to 479 kg CH 4 /hectare-season and ratoon emissions ranged from 481 to 1,490 kg CH 4 /hectare-season. From these ra nges, an uncertainty for the emission factors of 109 percent for primary crops and 65 percent for ratoon was calculated. In order to perform a Tier 2 Monte Carlo uncertainty analysis, some information regarding the statistical distribution of the uncertainty is required. Variability about the rice em ission factor means were not normally distributed for either primary or ratooned crops, but rather skewed, with a tail trailing to the right of the mean , therefore a lognormal-type statistical distribution was applied. The bounds of the distribution were set at 0 (indicating that CH 4 absorption was unlikely given this management system) and three times the emission factor.

Uncertainty regarding primary cropping ar ea is an additional consideration. Uncertainty associat ed with primary rice-cropped area for each state was obtai ned from expert judgment, and ranged from 1 percent to 5 percent of the mean area. A triangular distribution of uncertainty was assumed about the mean for areas, which was bounded at half and one and a half times the estimated area.

Another source of uncertainty lies in the ratooned areas , which are not compiled regul arly. Ratooning accounts for less than 8 percent of the total rice-cropped area, though it is responsible for a proportionately larger portion of emissions. Based on expert judgment, the uncertainty asso ciated with ratooned areas is between 1 percent and 5 percent. A triangular distribution of uncertainty was assumed, and bound at half and one and a half times the estimated proportion of ratooned area.

A final source of uncertainty is in the practice of flooding outside of the normal rice season. According to agricultural extension agents, all of the rice-growing states practice this on some part of their rice acreage. Estimates of these areas range from 5 to 68 percent of the rice acreage. Fields are flooded for a variety of reasons: to provide habitat for waterfowl, to pr ovide ponds for crawfish pr oduction, and to aid in ri ce straw decomposition. To date, however, CH 4 flux measurements have not been undertaken over a sufficient geographic range or under representative conditions to account for this source or its associated uncertainty adequate for inclusion in the emission estimates or uncertainty evaluations presented here.

4 In some of these remaining experiments, measurements from individual plots were excluded from the analysis because of the reasons just mentioned. In add ition, one measurement from the ratoone d fields (i.e., the flux of 2.041 g/m 2 /day in Lindau and Bollich 1993) was excluded since this emission rate is unusually hi gh compared to other flux measur ements in the United States, as well as in Europe and Asia (IPCC/UNEP/OECD/IEA 1997).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 212 To quantify the uncertainties for emissions from rice cultivation, a Monte Carlo (Tier 2) uncertainty analysis was performed using the information provide d above. The results of the Tier 2 quantitative uncertain ty analysis are summarized in Table 6-12. Rice cultivation CH 4 emissions in 2003 were estimated to be between 2.9 and 13.9 Tg CO 2 Eq. at a 95 percent confidence level (or 19 of 20 Monte Carlo Stochastic Simulations). This indicates a range of 58 percent below to 101 percent above the 2003 emission estimate of 6.9 Tg CO 2 Eq.

Table 6-12: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Rice Cultivation (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Rela tive to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Rice Cultivation CH 4 6.9 2.9 13.9 -58% +101%

a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.



### Planned Improvements

In performing a Monte Carlo-type uncertainty analysis, a higher level Tier 2 type emission mean is calculated incidentally. One would expect ther e to be a difference in the emission means calculated by these different methods, because under the IPCC default Tier 2 method used here to estimate CH 4 emissions, the statistical distribution of all parameters (i.e., activity data and emission factors) is implicitly considered to be normal. As described above, that is not the case with the uncertainty analysis, which allows for several asymmetrical statistical distributions. Here, the lower and upper bounds have been reported, directly from the Monte Carlo analysis. However, the percentages for the upper and lower bounds of the range have been calculated based on the reported emission mean rather than that mean cal culated by the Monte Carlo software (as is the case with all reported Tier 2 analyses). Because that mean may represent an improvement to the cu rrent Tier 2 met hodology, including the higher level Tier 2 estimate in future inventories is being investigated.



### 6.4. Agricultural Soil Management (IPCC Source Category 4D)

Nitrous oxide is produced naturally in soils through the mi crobial processes of nitrification and denitrification. 5 A number of agricultural activities add nitr ogen (N) to soils, thereby increasing th e amount available for nitrification and denitrification, and ultimatel y the amount of nitrous oxide (N 2 O) emitted. These activities may add N to soils either directly or indirectly (see Figure 6-2). Direct additions occur through various soil management practices and from the deposition of manure on soils by animals on past ure, range, and paddock (PRP) (i.e., by animals whose manure is not managed). Soil management practices that add N to soils include fertilizer use, application of managed livestock manure and sewage sludge, production of N -fixing crops and forages, retention of crop residues, and cultivation of histosols (i.e., so ils with a high organic matter conten t, otherwise known as organic soils). 6 Only direct emissions from agricultural lands (i.e., croplands and grasslands), along with emissions from PRP manure are included in this section. The direct emissions from forest lands and settlements are presented within the LUCF sector. Indirect nitrous oxide emissions from all land us e types resulting from N additions to croplands, grasslands, forestlands, and settlements are also included in this section. These indirect emissions occur through two

5 Nitrification and denitrification are two processes within the N cycle that are brought about by certain microorganisms in soil s. Nitrification is the aerobic micr obial oxidation of ammonium (NH 4 ) to nitrate (NO 3 ), and denitrification is the anaerobic microbial reduction of nitrate to N 2 . Nitrous oxide is a gaseous intermediate produc t in the reaction sequence of denitrification, which leaks from microbial cells into the soil and then into th e atmosphere. Nitrous oxide is also produced during nitrificatio n, although by a less well understood mechanism (Nevison 2000). 6 Cultivation of histosols does not, per se , “add” N to soils. Instead, the process of cultivation enhances mineralization of N-rich organic matter that is present in histosols, thereby enhancing N 2 O emissions from histosols.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 213 mechanisms: 1) volatilization and subsequent atmospheric deposition of applied N; 7 and 2) surface runoff and leaching of applied N into groundwater and surface water. Other agricultural soil mana gement activities, such as irrigation, drainage, tillage practices, and fallowing of land, can affect fluxes of N 2 O (as well as other greenhouse gases) to and from soils and are partially accounted for in the analysis.

Figure 6-2: Direct N 2 O Emissions Pathways from Cropland and Grassland Soils, and Indirect N 2 O Emissions Pathways from All Sources.

Agricultural soils are responsible for the majority of U.S. N 2 O emissions. Estimated emissions from this source in 2003 were 253.5 Tg CO 2 Eq. (818 Gg N 2 O) (see Table 6-13 and Table 6-14). Annual agricultural soil management N 2 O emissions fluctuated between 1990 and 2003; however, ove rall emissions were 0.2% greater in 2003 than in 1990. Year-to-year fluctuations are largely a reflection of annual variati ons in climate, synthetic fertilizer consumption, and crop production.

Table 6-13: N 2 O Emissions from Agricultural Soils (Tg CO 2 Eq.) 1990 1997 1998 1999 2000 2001 2002 2003 Direct 140.4 155.9 158.6 151.1 156.3 154.5 159.9 155.3

Agricultural Soils 100.1 113.6 116.5 111.0 116.4 113.0 118.5 114.8 Pasture, Range & Paddock Livestock

Manure 40.2 42.2 42.1 40.1 39.8 41.5 41.4 40.5 Indirect (All Land Use Types)* 112.6 96.2 109.1 92.3 107.6 102.6 92.7 98.2 Total 253.0 252.0 267.7 243.4 263.9 257.1 252.6 253.5 Note: Totals may not sum due to independent rounding. *Includes cropland, grassland, forest land and settlements.

Table 6-14: N 2 O Emissions from Agricultural Soils (Gg) 1990 1997 1998 1999 2000 2001 2002 2003 Direct 453 503 512 487 504 498 516 501

Agricultural Soils 323 367 376 358 376 365 382 370 Pasture, Range & Paddock Livestock

Manure 130 136 136 129 129 134 134 131 Indirect (All Land Use Types)* 363 310 352 298 347 331 299 317 Total 816 813 864 785 851 829 815 818 Note: Totals may not sum due to independent rounding. *Includes cropland, grassland, forest land and settlements.

Estimated direct and indirect N 2 O emissions by sub-source category are provided in Table 6-15, Table 6-16, and Table 6-17.

Table 6-15: Direct N 2 O Emissions from Agricultural Soils (Tg CO 2 Eq.) Activity 1990 1997 1998 1999 2000 2001 2002 2003 Mineral Agricultural Soils 97.3 110.8 113.7 108.2 113.6 110.1 115.6 111.9 Histosol Cultivation 2.8 2.9 2.9 2.9 2.9 2.9 2.9 2.9

7 These processes entail volatilization of applied N as ammonia (NH 3 ) and oxides of N (NO x ), transformations of these gases within the atmosphere (or upon deposition), and deposition of th e N primarily in the form of particulate ammonium (NH 4 ), nitric acid (HNO 3 ), and oxides of N.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 214 Pasture, Range & Paddock Livestock

Manure 40.2 42.2 42.1 40.1 39.8 41.5 41.4 40.5 Total 140.4 155.9 158.6 151.1 156.3 154.5 159.9 155.3 Note: Totals may not sum due to independent rounding. Ex cludes sewage sludge and livesto ck manure used as commercial fertilizers.

Table 6-16: Direct N 2 O Emissions from PRP Livestock Manure (Tg CO 2 Eq.) Animal Type 1990 1997 1998 1999 2000 2001 2002 2003 Beef Cattle 34.9 37.8 37.6 35.7 35.5 37.1 37.0 36.1 Dairy Cows 1.9 1.4 1.4 1.3 1.3 1.3 1.3 1.3 Swine 0.5 0.2 0.2 0.2 0.2 0.2 0.2 0.2 Sheep 0.4 0.3 0.3 0.3 0.3 0.3 0.2 0.2 Goats 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 Poultry 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Horses 2.2 2.3 2.3 2.3 2.3 2.3 2.3 2.3 Total 40.2 42.2 42.1 40.1 39.8 41.5 41.4 40.5

Table 6-17: Indirect N 2 O Emissions from all Land Use Types* (Tg CO 2 Eq.) 1990 1997 1998 1999 2000 2001 2002 2003 Volatilization and Atm. Deposition 15.6 16.5 16.4 16.4 16.8 16.4 16.6 16.5 Surface Leaching & Run-Off 97.1 79.6 92.7 75.9 90.8 86.3 76.1 81.8 Total 112.6 96.2 109.1 92.3 107.6 102.6 92.7 98.2 Note: Totals may not sum due to independent rounding. *Includes cropland, grassland, forest land and settlements.



### Methodology

The methodology used to estimate emissions from agricultural soil management is consistent with the Tier 3 approach of the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997), as amended by the IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2000) and Good Practice Guidance for Land Use, Land-Use Change and Forestry (IPCC 2003). Current methods divide this N 2 O source category into three components: 1) direct emissi ons from managed soils due to applied N and the cultivation of histosols; 2) direct emissions from soils due to the deposition of manure by livestock on PRP lands; and 3) indirect emissions from soils or water induced by additions of fertilizers, se wage sludge, and livestock manure (both managed and unmanaged) to soils of all land use types.

Annex 3.11 provides more detailed information on th e methodologies and data used to calculate N 2 O emissions from each of the components.

The methodology applied in this Inventory is a hybrid approach for estimating N 2 O emissions from mineral agricultural soils. This involves using the process-ba sed model DAYCENT to estimate emissions from major crops on mineral (i.e., non-histosol) soils, and the IPCC methodol ogy for non-major crops on mineral soils, PRP manure, as well as all emissions from histosols.

Direct N 2 O Emissions from Mineral Agricultural Soils
Different methodologies were used in quantifying direct N 2 O emissions from mineral agricultural soils with major crop types and those with non-major crop types as described below.



### Major Crop Types
The DAYCENT ecosystem model (Del Grosso et al. 2001, Parton et al. 1998) was used to estimate direct soil N 2 O emissions from mineral agricultural soils cropped with major crop types. DAYCENT has been parameterized toInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 215 simulate most of the major cropping systems (corn, soybean, wheat, alfalfa hay, other hay, sorghum, and cotton) in the United States. These cropping systems simulated by DAYCENT represent approximately 90 percent of total cropped land in the United States. DAYCENT simulate s crop growth, soil organic matter decomposition, greenhouse gas fluxes, N deposited by grazing animals, a nd other biogeochemical processes using daily climate data, land management information, and soil physical properties as model inputs. The scale of DAYCENT simulations is dictated by the scale of available input data. Soil and climate inputs were available for every county with more than 100 acres of agricultural land. Therefore, a single parameter value (e.g., maximum temperature for a particular day) is applied at the county-level for those variables. Land management data (e.g., timing of planting, harvesting, applying fertilizer, intensity of cultivation, rate of fertilizer application) were available at the agricultural region level as defined by the Agricultural Sector Model (McCarl el al. 1993). There are 63 regions in the contiguous United States; most states correspond to one region, except for states that are divided into two or more regions if there is sufficient variab ility in cropping practices within the st ate. Although vari ous cropping systems were simulated for each county, the parameters cont rolling management activities (e.g., when crops were planted/harvested, amount of fe rtilizer added), did not change within an agricultural region.

Nitrous oxide emissions estimated by DAYCENT account for N additions, crop type , irrigation, and other factors. However, because DAYCENT is a process-base d model that simulates the N cycle, N 2 O emissions cannot be partitioned into the contribution of N 2 O from different N inputs (e.g., N 2 O emissions from synthetic fertilizer applications cannot be dis tinguished from those emissions resulting from manure applications). Therefore, it was not possible to separate out these individual contributors to N 2 O flux, as is suggested in the IPCC Guidelines

. In addition to simulating N 2 O emissions from mineral agricultural soils cropped with major crop types, a DAYCENT simulation was performed of those same areas as though they were covered by native vegetation, so that anthropogenic emissions could be isolated from natural background emissions. Emissions from managed agricultural lands are the result of complex and interactive processes, practices, and inputs arising from anthropogenic intervention. Because removing inputs alone w ould not reflect the fu ll anthropogenic greenhouse gas signature, managed soil emissions have been compared to those soils under native vegetation as a means of identifying the anthropogenic contribution. The reported estimates of emissions from managed soils therefore represent the difference between simulated emissions fro m native vegetation and emissions from cropland soils. Estimates of direct N 2 O emissions from N applications were based on the total amount of N applied to soils annually through the following practices: 1) the application of synthetic and or ganic commercial fertilizers, 2) the application of livestock manure through both daily spread operations and through the eventual application of manure that had been stored in manure management systems, 3) the application of sewage sludge, 4) the production of N-fixing crops and forages, and 5) the retention of crop residues (i.e., leaving residues in the field after harvest). For each of these practices, annual N applica tions were obtained from the following sources:

• Crop-specific N-fertilization rates : Alexander and Smith (1990), Anonymous (1924), Battaglin and Goolsby (1994), Engle and Makela (1947), ERS (1994, 2003), Fraps and Asbury (1931), Ibach and Adams (1967), Ibach et al. (1964), NFA (1946), NRIAI (2003), Ross and Mehring (1938), Skinner (1931), Smalley et al. (1939), Taylor (1994), USDA (1966, 1957, 1954, 1946).

• Manure management information was obtained from Poe et al. (1999), Safley et al. (1992), and personal communications with agricultural experts (Ande rson 2000, Deal 2000, Johns on 2000, Miller 2000, Milton 2000, Stettler 2000, Sweeten 2000, Wri ght 2000). Livestock weight data were obtained from Safely (2000), USDA (1996, 1998d), and ASAE (1999); daily ra tes of N excretion from ASAE (1999) and USDA (1996). Comparisons of estimates of managed manure production (i.e. non-PRP manure) with estimates of the amount of manure actually consumed by soils s howed that manure consumed by soils accounted for approximately one-third of managed manure production) . Values for manure consumption (Kellogg et al. 2000; Edmonds et al. 2003) were subtracted from valu es of managed manure production. Only consumed manure N was applied to agricultural soils. The rema inder was assumed to have volatized during storage and transport. In contrast to the IPCC methodology that only consider s volatilization of manure that was applied to soils, the manure that was assumed to volatilize during transport and storage was included in the volatilization component of indirect N 2 O emissions. Instead of assuming that 10 percent of synthetic and 20 percent of organic N applied to soils is volatili zed and 30 percent of applied N was leached/runoff asInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 216 with IPCC methodology, volatilization and N leaching/runoff were intern ally calculated by the processbased model.

• Sewage sludge: Bastian (2002); USDA (1998a); EPA (1993, 1999); Metcalf and Eddy (1991).

• Nitrogen-fixing crops and forages and retention of crop residue. Using the IPCC approach, these are considered activity data. However, when using DAYC ENT, they should not be considered activity data because they are internally generated by the model. In other words, DAYCENT accounts for the influence of N fixation and retention of crop residue on N 2 O emissions, but these are not model inputs.

• Historical and modern crop rotation and management information (e.g., timing and type of cultivation, timing of planting/harvest, etc.): Hurd (1930, 1929), Latta (1938), Iowa State College Staff Members (1946), Bogue (1963), Hurt (1994), USDA (2004), USDA (2000h), as extracted by Eve (2001), and revised by Ogle (2002), CTIC (1998), Piper et al. (1924), Hardies and Hume (1927), Holmes (1902, 1929), Spillman (1902, 1905, 1907, 1908), Chilcott (1910), Smith (1911), Kezer ca. (1917), Hargreaves (1993), ERS (2002), Warren (1911), Langtson et al. (1922), Russell et al. (1922), Elliot and Tapp (1928), Elliot (1933), Ellsworth (1929), Garey (1929), Holmes (1929) , Hodges et al. (1930), Bonnen and Elliot (1931), Brenner et al. (2002, 2001), Smith et al. (2002).

Applied N was subject to volatiliza tion and leaching/runoff according to the climatic conditions, soil type and condition, crop type, and land management practices such as cultivation and i rrigation, as simulated by DAYCENT. These amounts were then applied in the calculation of indirect emissions as described below. The remaining applied soil N was then added to the applied N from N-fixi ng crops and crop residues to yield total soil N additions for the DAYCENT simulation of direct N 2 O emissions from soils cropped with major crop types. Because the model is sensitive to actual interannual va riability in those factors to which N 2 O emissions are sensitive (e.g., climate), emissions vary through time rather than demonstrate a linear, monotonic response.



### Non-Major Crop Types
For lands cropped with non-major crop types, the IPCC emission factor methodology was used to estimate N 2 O emissions from mineral agricultural soils, as described below.

Estimates of direct N 2 O emissions from N applications to non-major crop types were based on the amount of N applied to soils annually through the fo llowing practices: 1) the application of synthetic commercial fertilizers, 2) the production of N-fixing crops and forages, and 3) the rete ntion of crop residues. No organics were considered here because 100 percent of these were assumed to be a pplied to crops simulated by DAYCENT. This assumption is reasonable because DAYCENT simulated the 6 major croppi ng systems (corn, hay, pasture, sorghum, soybean, wheat) that receive the vast majority (approximately 95 percent) of manur e applications (K ellogg et al. 2000, Edmonds et al. 2003).

Yearly synthetic fertilizer N additions to non-major crop types were calculated by process of elimination. For each year, fertilizer accounted for by th e cropping systems simulate d by DAYCENT (approximately 75 percent of the U.S. total), fertilizer estimated to be applied to forests (le ss than 1 percent of the U.S. total), and fertilizer estimated to be applied in settlements (approximately 10 percent of the U.S. total) were summed and subtracted from total fertilizer used in the United States

. This difference was assumed to be applied to non-major crop types and accounted for approximately 15 percent of total N fertilizer used in the United States. Non-major crop types include fruits, nuts, and vegetables, which account for approximately 5 percent of U.S. N fertilizer use (TFI 2000) and other crops not simulated by DAYCENT (barley, oats, tobacco, sugar cane, sugar beets, sunflower, millet, peanuts, etc.) which account for approximately 10 percent of total U. S. fertilizer use. The non-volatilized proportion was obtained by reducing total a pplications by the default IPCC volatiliza tion fraction (IPCC 1997, 2000). In addition to synthetic fertilizer-N applied to non-major crop types, N in soils due to the cultivation of non-major N-fixing crops (e.g., edible legumes) was included in these estimat es. Finally, crop residue N retention was derived from information about which residues are typically left on the field, the fractions that remain, annual crop production,Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 217 mass ratios of aboveground residue to crop product, and dry ma tter fractions and N contents of the residues. For each of these practices, annual N applicati ons were obtained from the following sources :

• Mass ratios of aboveground residue to crop product, dr y matter fractions, and N contents for N-fixing crops: Strehler and Stützle (1987), Barnard and Kristoferson (1985), Karkosh (2000), Ketzis (1999), IPCC/UNEP/OECD/IEA (1997).

• Annual production statistics for crops whose residues are left on the field: USDA (1994a, 1998b, 2000i, 2001a, 2002a, 2003a), Schueneman (1999, 2001), Deren (2002), Schuenema n and Deren (2002), Cantens (2004), Lee (2003, 2004).

• Aboveground residue to crop mass ratios, residue dry matte r fractions, and residue N contents: Strehler and Stützle (1987), Turn et al. (1997), Ketzis (1999), Barnard and Kristoferson (1985), Karkosh (2000).

The net amount of N remaining on the soil from applied fe rtilizer was added to the N from N-fixing crops and crop residues to yield total unvolatilized app lied N, which was multiplied by the IPCC default emission factor to derive an estimate of cropland N 2 O emissions from non-major crop types.

Total annual emissions from major crops and other crops were summed to obtain total emissions from cropped mineral soils (see Table 6-13 and Table 6-14).

Direct N 2 O Emissions from Histosols

Estimates of annual N 2 O emissions from histosol cultivation were based on estimates of the total U.S. acreage of histosols cultivated annually for each of two climatic zones: 1) temperate, a nd 2) sub-tropical. Histosol area was obtained from the Natural Resources Inventory (USDA 2000h, as extracted by Eve 2001, and revised by Ogle 2002). To estimate annual emissions, the total temperate area was multiplied by the IPCC default emission factor for temperate regions, and the total sub-tropical area was multiplied by the average of the IPCC default emission factors for temperate and tropical regions.



### Total Direct N 2 

### O Emissions from Nitrogen Applications to Agricultural Soils

Total annual N 2 O emissions from N applications to mineral agricultural soils and annual N 2 O emissions from histosol cultivation were then summed to estimate total direct N 2 O emissions from agricultural soils.

Direct N 2 O Emissions from Pasture, Range, and Paddock Livestock Manure

As with N 2 O from major row crops, dual methodologies incorporating the process-based simulation model DAYCENT and IPCC methods were applied in tandem to estimate total emissions from PRP manure. For DAYCENT simulations, annual county-level pasture area data were not available so county-level pasture area estimates from Kellogg et al. (2000) and Edmonds et al. (2003) were used. DAYCENT does not simulate paddocks and no county level area data for range land were available so IPCC methodology was used to estimate emissions from these sources. Because DAYCENT simulated only pa stures and not paddocks or rangeland, the amount of manure accounted for by DAYCENT (manure N added to soil is an output variable in DAYCENT) was subtracted from annual estimates of total PRP manure and assumed that this manure contributed to emissions from paddocks and rangeland.

Estimates of N 2 O emissions from PRP livestock manure are based on the amount of N in the manure that is deposited annually on soils by livestock on PRP. Estimates of annual manure N from these livestock were derived from animal population and weight statistics; information on the fraction of the total population of each animal type that is on pasture, range, or paddock; and annual N excretion rates for each animal type. The amount of manure N from each animal type was summed over all animal types to yield total PRP manure N. Nitrous oxide emissions resulting from manure deposited on pastures by livestock was simulated by DAYCENT in each county. The emissions were obtained by multip lying DAYCENT emissions (in g N 2 O-N m -2 ) by the total reported pasture area for each county, and summing across all counties to achieve a nationwide value. All of the manure accounted for byInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 218 DAYCENT was assumed to come from cattle because DAYC ENT has been parameterized to simulate cattle manure, and cattle are responsible for approximately 90 percent of total PRP manure. The PRP manure N from paddocks and rangeland not accounted for by DAYCENT in the pastur e component was multiplied by the IPCC default emission factor to estimate N 2 O emissions from paddock and rangeland manure depos ition. Emissions from the three types of PRP manure were summed to provide total national emissions from PRP manure in the United States.

Indirect N 2 O Emissions from Managed Soils of All Land Use Types
This section describes the method for estimating indirect N 2 O emissions from managed soils of all land use types (i.e., cropland, grassland, forest land a nd settlements). Indirect emissions of N 2 O are composed of two parts, which are estimated separately and then summed. These pa rts are 1) emissions resulti ng from volatilization of non-N 2 O gases (i.e., NO x and NH 3 ) from synthetic fertilizer and manure additions to managed soils and from managed manure during storage, treatment and transport that are subsequently deposited onto ot her areas and eventually emitted to the atmosphere as N 2 O, and 2) leaching and runoff of N (in the form of NO 3 - ) from all soils where N additions have been made that is eventually denitrified and emitted as N 2 O from a water body. Regardless of the original source or eventual land use type where these indirect N 2 O emissions actually occur, all indirect N 2 O emissions are accounted for in this section of the Inventory.

A mix of approaches was used to obtain the necessary information required to estimate indirect N 2 O emissions. While DAYCENT simulates NO x and NH 3 volatilization as well as NO 3 leaching/runoff, it does not model their transport or subsequent off-site conversion to N 2 O. Therefore, DAYCENT was used to simulate N volatilization and leaching/runoff losses for majo r crop types. Volatilized and leached/runoff N from non-major crops, settlements and forest lands were obtained by applying the IPCC default fractions to total fertilizer applications to those crops and/or land areas. The volatilization and leaching/ runoff components of indi rect emissions for PRP manure were obtained by using a combination of DAYCENT genera ted outputs for manure deposited on pasturelands and applying IPCC defaults to manure de posited on paddocks and rangela nds. Manure from managed systems assumed to be volatilized during storage, treatment and transport was included in the indirect emission calculations as well. In contrast to the IPCC approach that has been used in the past, DAYCENT simulations for major crops, where all managed manure is assumed to be applied, do not assume that 100 percent of the N in managed manure is available to be applied to soils. According to data in Kellogg et al. (2000) and Edmonds et al. (2003), more than 50 percent of the N in managed manure is lost to volatilization, spillage and leaching/runoff during storage, treatment and transport. Consequently, manure N applied to soils, based on data from Kellogg et al. (2000) and Edmonds et al. (2003), is subtracted from total managed manur e N and assumed to volatilize during storage, treatment, and transport where it is then included in the volatilizati on component of indi rect emissions. Results from this mix of approaches described above were then summed for the appropriate indirect N 2 O emission pathway as described below.



### Voltilized Indirect Emissions

Volatilized N emissions for settlements, forest lands, PRP manure, major crops, non-major crops, and volatilized managed manure prior to land application were summed. The IPCC default emission factor for indirect N 2 O was applied to the total to give total indirect N 2 O emissions from N volatilization from soils of all land use types and volatilized managed manure.



### Leaching/Runoff Indirect Emissions

The amounts of leached/runoff N from settlements, forest lands, PRP manure, major and non-major crop types were summed and multiplied by the IPCC defa ult emission factor for leached/runoff N.



### Total Indirect Emissions from Volatilization and Leaching/Runoff

Total indirect emissions from volatili zation and from leaching/r unoff were summed to estimate total indirect emissions of N 2 O from croplands (Table 6-17).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 219 

### Uncertainty

The DAYCENT biogeochemical ecosystem model was used to calculate N 2 O emissions from major crop types. There are two broad classes of uncertainty in such analyses: that inherent in the activity data and emission factors, and structural uncertainty inherent to the model used to estimate emissions. Consistent with the United States' uncertainty management plan, uncertainty inherent to the DAYCENT model was not quantified as part of the IPCC Tier 1 approach described below.

Three types of approaches were taken for estimating differe nt types of emissions in this chapter: 1) Direct emissions calculated by DAYCENT; 2) Di rect emissions not calculated by DAYC ENT; and 3) Indirect emissions. Uncertainty was estimated diffe rently for each category.

For direct emissions calculated by DAYCENT (99.3 of the total direct 155.3 Tg CO 2 Eq.), uncertainty in national totals for N inputs and uncertainty in how N application rates change with crop type, year, and agricultural region contribute to total uncertainty in the N application activity data. Total uncertainty in N inputs was estimated at 20 percent (Mosier 2004). Other activity data include climat e data, for which uncertainty was estimated to be 19 percent, and soil type, which was estimated to have an uncertainty of 12 percent (Del Grosso 2005a). Their combined uncertainty, accordi ng to the sum-of-squares method, is approxi mately 30.1 percent. To estimate the uncertainty associated with the effective emission factor, DAYCENT outputs were compared with N 2 O measurements from various cropped soils over the annual cycle (Del Grosso et al. in press). Through this method, the uncertainty associated with the effective emission factor was estimated at 57 percent (Del Grosso 2005b). Through the calculus of error propagation, overall uncertainty for direct emissions calculated by DAYCENT was 64 percent.

Direct N 2 O emissions not calculated by DAYCENT were assumed to mainta in the 64 percent uncertainty.

Finally, indirect emissions were calculated according to the default IP CC methodology, as has been performed in past Inventories. Consequently, the maximum uncertainty calculated for last year’s indirect N 2 O emissions from agricultural soil management of 286 percent (U.S. EPA 2004) was applied to conservatively address the uncertainty in indirect emissions here.

The results of the Tier 1 quantitative uncertainty analysis are summarized in Table 6-18. Agricultural soil management N 2 O emissions in 2003 were estimated to be between 45.2 and 461.8 Tg CO 2 Eq. at a 95 percent confidence level. This indicates a range of 82 per cent above and below the 2003 emission estimate of 253.5 Tg CO 2 Eq.

Table 6-18: Tier 1 Quantitative Uncertainty Estimates of N 2 O Emissions from Agricultural Soil Management in 2003 (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate (Tg CO 2 Eq.) Uncertainty (%) Uncertainty Range Relative to Emission Estimate (Tg CO 2 Eq.) Lower Bound Upper Bound Agricultural Soil Management N 2 O 253.5 82% 45.2 461.8



### Recalculations Discussion

Differences in the present report comp ared to previous years exist for tw o reasons: differences in sources and differences in methodologies. In prev ious Inventories, fertilizer applied to forests and settlements were included in the agricultural sector. For the current Inventory, for the direct emissions, these fertilizer additions were included in the LUCF sector, and therefore approximately 15 percent less synthetic fertilizer is counted in the agricultural sector than in previous Inventories. Also in previous Inventories, the default Tier 1 IPCC methodology was used to estimate emissions from this sector. That methodology relied sole ly on N inputs, and did not account for effects of climate, soil type, and other factors that influence N 2 O emissions. To account for some of these additional factors and increase confidence in estimates, a Tier 3 method, the DAYCENT ecosystem model, was used to account forInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 220 N 2 O emissions from major cropping systems. Overall, the changes resulted in an average annual decrease of 31.2 Tg CO 2 Eq. (11 percent) in N 2 O emissions from agricultural soil management for the period 1990 through 2002.

The IPCC emission factor methodology is an example of a Tier 1 approach. This approach is activity driven, i.e., total N from different sources (e.g. synthetic fertilizer, manure, N fixation, etc.) is used to estimate N 2 O from these sources. The Tier 3 approach in this case uses a process-based model (i.e., DAYCENT) and is area driven, i.e., it is necessary to know the annual area of major crop types and th e N amendment rates for each of these crops. With the Tier 3 approach, emissions cannot be separated by N inputs because once N is in the plant/soil system, the model does not distinguish its source according to IPCC categorizations (e.g., whether the N 2 O emitted was synthetic fertilizer-derived or derived from manure) . Because the Tier 3 approach was used for approximately 90 percent of fertilized soils in the United States, N 2 O emissions are not partitioned into th e IPCC’s N-input categories, as has been done in the past.

The Tier 3 approach requires some of the same activity data as the Tier 1 approach, plus additional information. Like the Tier 1 approach, the Tier 3 approach requires na tional totals for N amendments, but it also requires data on N amendment rates for different cropping systems. Consequently, the total amounts of N fertilizer and organic N additions were identical to previous years but assumptions regarding the fate of these am endments are different. For example, in previous years, 100 percent of managed manure was assumed to be applied to cropped soils, though here approximately 64 percent of manure N was lost to volatilization during transport and storage before it was applied to soil. This manure that was assumed to volatilize before soil application was included with indirect emissions, which is different than previous years. In addition to N amendments, the Tier 3 approach requires area data for different cropping sy stems. The Tier 3 approach distinguish es different cropping sy stems because crops vary in growth rates, fertilization rates, biomass N concentration, and timing for planting, harvesting, and cultivating. These crop system specific factors are important because they in fluence N availability in soil, which controls N 2 O emissions.

An important difference between Tier 1 and Tier 3 approach es relates to assumptions regarding N cycling. Tier 1 assumes that N added to a system in one year completely cycles during that year; e.g., N added as fertilizer or through fixation contributes to N 2 O emission for that year, but cannot be stored in soil or biomass and be recycled and contribute to N 2 O emission in subsequent years. In contrast, the process-based models used in the Tier 3 approach include legacy effects such that N added to the system in one year may be taken up by vegetation and returned to the soil in organic form during that year, then re-mineralized and emitted as N 2 O during subsequent years. In addition to previous years’ fertilizer additions, other long-term mana gement practices that affect current soil organic matter (SOM) levels (e.g., intensive cultivation, summer fallow) also affect current N 2 O emission, because in process based models, N from internal cy cling (mineralization of SOM) contributes to N 2 O emission. Thus, while Tier 1 estimates are influenced only by the current year’s N inputs, Tier 3 emissions are also influenced by management in previous years.

Another difference in me thodologies is that the Tier 1 method assumes that 10 percent of synthetic fertilizer and 20 percent of applied manure are volatilized, and 30 percent of applied N is leached or run-off. DAYCENT, however, calculates N volatilization and N leached and run-off internally based on sp ecific climatic, environmental, and management conditions.

Consideration of N-fixation highlights another difference in the approaches. In the Tier 1 approach, a certain portion of aboveground fixed N is assume d to be emitted as direct soil N 2 O. In the Tier 3 approach, N fixation is calculated by the model and fixed N can be harvested, lost as N 2 O, lost in some other form (e.g., leached NO 3 ), or stored in the plant/soil system.

The Tier 1 approach also assumes that only N from fertilizer and organic matter additions contributes to indirect N 2 O emissions whereas the Tier 3 approach assumes that once N is in the plant/s oil system, it can be cycled and lost thorough various pathways, regardless of its source. Simila r to N fixation, N deposited on soil by pasture and range animals and N added to soils from crop residue are simu lated by DAYCENT. More N from manure was assumed to volatilize before application to soils and hence less N from manure was availabl e for leaching than previous years. However, total N volatilization and leach ing/runoff were both still higher than pr evious years. This is because IPCCInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 221 methodology considers only N fro m synthetic and organic fertilizer to c ontribute to indirect emissions whereas other sources of N (e.g., fixation, crop residue) contribute to volatilization and N leach ing/runoff in DAYCENT.

The methodology used here estimated total N 2 O emissions to be approximately 5 to 10 percent less than estimates based on the IPCC methodology due to changes in th e calculation method, as well as accounting for N 2 O from fertilization of forest and settlement so ils within the LUCF sector. The cu rrent method estimates lower direct N 2 O emissions Table 6-19, but higher indirect N 2 O emissions (Table 6-20) than the IPCC method. Differences in total N 2 O emissions are shown in Table 6-21. Direct emissions were lower because of different assu mptions regarding the cycling of fixed N and lower manure N applications to the major crop types under the current methodology compared with that used in the past. Indirect emissions, on the other hand, were larger because more contributors to N volatilization and leaching/ runoff are accommodated by the simulation (by including crop resi due applications, for example). Mean direct emissions from non-N fixing crops differed by approximately one percent, whereas direct emissions from N fixing crops were approximately 30 percent less with hybrid than IPCC methodology. Interestingly, total N fixation with the hybrid approach was only approximately two percent lower than with IPCC methodology and the implied emission factor for direct N 2 O emissions from fixation is approximately 0.9 percent using hybrid methodology; i.e., these DAYCENT simulations suggest that the 1.25 percent emissions factor used for direct N 2 O emissions from N fixation is too high. This is consistent with field data showing that IPCC methodology may overestimate N 2 O emissions from soybean and alfalfa cropping (Del Grosso et al. in press, Rochette et al. 2004).

Table 6-19. Comparison of Direct Soil N 2 O Emission Estimates for IPCC versus Current Methodologies (Tg CO 2 Eq.). Method 1990 1997 1998 1999 2000 2001 2002 2003 IPCC 191.2 214.9 216.1 213.9 213.0 213.2 210.1 205.8 Current Simulation* 146.0 162.3 165.1 157.7 162.6 160.7 166.3 161.7 Difference 45.2 52.6 51.0 56.2 50.4 52.5 43.8 44.1 * Unlike Table 6-13, emissions due to N applied to forest lands and settlements are included here, to be consistent with IPCC estimates used in previous reports.

Table 6-20. Comparison of Indirect Soil N 2 O Emission Estimates for IPCC versus Current Methodologies (Tg CO 2 Eq.) Method 1990 1997 1998 1999 2000 2001 2002 2003 IPCC 72.6 79.0 78.8 78.8 77.4 76.0 77.2 77.3 Current Simulation 112.6 96.2 109.1 92.3 107.6 102.6 92.7 98.2 Difference -40.0 -17.2 -30.3 -13.5 -30.2 -26.6 -15.5 -20.9

.
Table 6-21. Comparison of Total Soil N 2 O Emission Estimates for IPCC versus Current Methodologies (Tg CO 2 Eq.) Method 1990 1997 1998 1999 2000 2001 2002 2003 IPCC 263.8 293.9 294.9 292.8 290.4 289.2 287.2 283.1 Current Simulation* 258.6 258.4 274.2 250.0 270.2 263.3 259.0 259.9 Difference 5.2 35.4 20.7 42.7 20.2 25.9 28.2 23.2 * Unlike Table 6-13, emissions due to N applied to forest land and settlements are included here, to be consistent with IPCC estimates used in previous reports. Compared with the IPCC methodology used in the past, the current methodology shows a smaller increase in total N 2 O emissions from 1990 through 2003. The current methodology takes into acc ount climate patterns as well as annual fluctuations in N additions. The linear regressi on between emissions estimated with the new method and time shows a trend toward increasing emissions of approximately 0.39 percent per year. During this time period, synthetic N fertilizer applications increased by nine percent, manure additions increased by 11 percent, and N fixation increased by about 17 percent. Soybean cropped ar ea increased by 27 percent, corn area increased by six percent, and wheat area decreased by 20 percent. The increase in soybean area is largely responsible for the increase in fixation. Because total non-legume cropped area decreased and total fertilizer applied to major cropsInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 222 increased, the average rate of fer tilizer applied to major crops increas ed by 32 percent from 1990 through 2003. The current method accounts for each of th ese variables plus the effects of c limate variability, whereas the previous method accounted only for changes in fer tilizer and manure additions. Climate in teracts with N additions to control emissions with the new methodology. Total N additions from fertilizer are important with the IPCC methodology, while the current method accounts for total N additions, th e area that receives the N are important, as well as environmental and management conditions. As a result, simulated N 2 O emission estimates may increase or decrease non-linearly, whereas emissions always increase linearly with N applications when using the IPCC methodology.


### Planned Improvements

The presented uncertainty estimate is incomplete in that uncertainty in model activity data besides N inputs (county level weather and soil type) was not in cluded. Because county level soil and climate data are applied across the entire county, within which a great deal of variability may occur, there is inhe rent uncertainty in assuming that soil type and climate do not vary within a county. Future estimates of uncertain ty will include sensitivity analyses so that the response of model N 2 O output to variations in climate, soil type, and N inputs can be quantified. Also, a more appropriate methodology th an Tier 1 will also be used in future uncertainty estimates. Future efforts at characterizing uncertainty will work toward the inclusion of all agricultural soil management subsource categories in a Monte Carlo style calculation.



### 6.5. Field Burning of Agricultural Residues (IPCC Source Category 4F)

Large quantities of agricultural crop residue s are produced by farming activities. A variety of ways exist to dispose of these residues. For example, agricultural residues can be left on or plowed back into the field, composted and then applied to soils, landfilled, or burned in the field. Alternatively, they can be collected and used as fuel, animal bedding material, or supplemental animal feed. Field burning of crop residues is not considered a net source of CO 2, because the carbon released to the atmosphere as CO 2 during burning is assumed to be reabsorbed during the next growing season. Crop residue burning is, however, a net source of CH 4 , N 2 O, CO, and NO x , which are released during combustion.

Field burning is not a common method of agricultural residue disposal in the United States; therefore, emissions from this source are minor. The primary crop types whose residues are typically burned in the United States are wheat, rice, sugarcane, corn, barley, so ybeans, and peanuts. Of these residue s, less than 5 percent is burned each year, except for rice. 8 Annual emissions from this source over the period 1990 through 2003 have remained relatively constant, averaging approximately 0.7 Tg CO 2 Eq. (35 Gg) of CH 4 , 0.4 Tg CO 2 Eq. (1 Gg) of N 2 O, 737 Gg of CO, and 32 Gg of NO x (see Table 6-22 and Table 6-23).

Table 6-22: Emissions from Field Burning of Agricultural Residues (Tg CO 2 Eq.) Gas/Crop Type 1990 1997 1998 1999 2000 2001 2002 2003 CH 4 0.7 0.8 0.8 0.8 0.8 0.8 0.7 0.8

Wheat 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Rice 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Sugarcane + + + + + + + + Corn 0.3 0.3 0.3 0.3 0.4 0.3 0.3 0.4 Barley + + + + + + + + Soybeans 0.1 0.2 0.2 0.2 0.2 0.2 0.2 0.2 Peanuts + + + + + + + + N 2 O 0.4 0.4 0.5 0.4 0.5 0.5 0.4 0.4

Wheat + + + + + + + +

8 The fraction of rice straw burned each year is significantly higher than that for other crops (see “Methodology” discussion below).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 223 Rice + + + + + + + + Sugarcane + + + + + + + + Corn 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Barley + + + + + + + + Soybeans 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.2 Peanuts + + + + + + + + Total 1.1 1.2 1.2 1.2 1.2 1.2 1.1 1.2 + Does not exceed 0.05 Tg CO 2 Eq. Note: Totals may not sum due to independent rounding.

Table 6-23: Emissions from Field Burning of Agricultural Residues (Gg)* Gas/Crop Type 1990 1997 1998 1999 2000 2001 2002 2003 CH 4 33 37 38 37 38 37 34 38

Wheat 7 6 6 5 5 5 4 6 Rice 4 3 3 4 4 4 3 5 Sugarcane 1 1 1 1 1 1 1 1 Corn 13 16 17 16 17 16 15 17 Barley 1 1 1 + 1 + + 0 Soybeans 7 10 10 10 10 11 10 9 Peanuts + + + + + + + 0 N 2 O 1 1 1 1 1 1 1 1

Wheat + + + + + + + + Rice + + + + + + + + Sugarcane + + + + + + + + Corn + + + + + + + + Barley + + + + + + + + Soybeans 1 1 1 1 1 1 1 1 Peanuts + + + + + + + + CO 689 767 789 767 790 770 706 794

Wheat 137 124 128 115 112 98 81 117 Rice 86 72 65 76 76 77 60 96 Sugarcane 18 21 22 23 24 23 23 23 Corn 282 328 347 336 353 338 320 360 Barley 16 13 13 10 12 9 8 10 Soybeans 148 207 211 204 212 222 211 186 Peanuts 2 2 2 2 2 3 2 3 NO x 28 34 35 34 35 35 33 33

Wheat 4 3 3 3 3 3 2 3 Rice 3 3 2 3 3 3 2 3 Sugarcane + + + + + + + + Corn 7 8 8 8 8 8 8 9 Barley 1 + + + + + + + Soybeans 14 20 20 19 20 21 20 18 Peanuts + + + + + + + + * Full molecular weight basis. + Does not exceed 0.5 Gg Note: Totals may not sum due to independent rounding.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 224 

### Methodology

The methodology for estimating greenhouse gas emissions from field burning of agricultural residues is consistent with the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) 9 . In order to estimate the amounts of carbon and nitrogen released during burning, the following equations were used: 10
Carbon Released = (Annual Crop Production) × (Residue/Crop Product Ratio)

× (Fraction of Residues Burned in situ ) × (Dry Matter Content of the Residue)

× (Burning Efficiency) × (Carbon Content of the Residue) × (Combustion Efficiency) 11

Nitrogen Released = (Annual Crop Production) × (Residue/Crop Product Ratio)

× (Fraction of Residues Burned in situ ) × (Dry Matter Content of the Residue)

× (Burning Efficiency) × (Nitrogen Content of the Residue) × (Combustion Efficiency)

Emissions of CH 4 and CO were calculated by multiplying the am ount of carbon released by the appropriate IPCC default emission ratio (i.e., CH 4 -C/C or CO-C/C). Similarly, N 2 O and NO x emissions were calculated by multiplying the amount of nitrogen released by th e appropriate IPCC default emission ratio (i.e., N 2 O-N/N or NO x N/N).

The crop residues that are burned in the United States were determined from various state-level greenhouse gas emission inventories (ILENR 1993, Oregon Department of Energy 1995, Wisconsin Department of Natural Resources 1993) and publications on agricultural burning in the United States (Jenkins et al. 1992, Turn et al. 1997, EPA 1992).

Crop production data for all crops except rice in Florida and Oklahoma were taken from the USDA’s Field Crops, Final Estimates 1987-1992, 1992-1997 (USDA 1994, 1998), Crop Production 1999 Summary (USDA 2000), Crop Production 2000 Summary (USDA 2001), Crop Production 2001 Summary (USDA 2002), Crop Production 2002 Summary (USDA 2003) and Crop Production 2003 Summary (USDA 2004). Rice production data for Florida and Oklahoma, which are not collected by USDA, were estimated by applying average primary and ratoon crop yields for Florida (Schueneman and Deren 2002) to Florida acreages (Schueneman 1999b, 2001; Deren 2002; Kirstein 2003, 2004; Cantens 2004) and Oklahoma acreages 12 (Lee 2003, 2004). The production data for the crop types whose residues are burned are presented in Table 6-24.

The percentage of crop residue burned was assumed to be 3 percent for all crops in all years, except rice, based on state inventory data (ILENR 1993, Oregon Department of Energy 1995, Noller 1996, Wisconsin Department of Natural Resources 1993, and Cibrowski 1996). Estimates of the percentage of rice residue burned were derived from state-level estimates of the percentage of rice ar ea burned each year, which were multiplied by state-level, annual rice production statistics. The annual percentages of rice area burned in each st ate were obtained from the agricultural extension agents in each state and reports of the Californi a Air Resources Board (CARB) (Bollich 2000; Deren 2002; Guethle 1999, 2000, 2001, 2002, 2003, 2004; Fife 1999; California Air Resources Board 1999, 2001;

9 The IPCC Good Practice Guidance (IPCC 2000) provided no upda tes the methodology for estimating field burning of agricultural residues. 10 Note: As is explained later in this s ection, the fraction of rice residues burned va ries among states, so these equations were applied at the state level for rice. These equations were applied at the national level for all other crop types. 11 Burning Efficiency is defined as the fraction of dry biomass exposed to burning that actually burns. Combustion Efficiency is defined as the fraction of carbon in the fi re that is oxidized completely to CO 2 . In the methodology recommended by the IPCC, the “burning efficiency” is assumed to be contained in the “fr action 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. Therefo re, a “burning efficiency factor” was added to the calculations. 12 Rice production yield data are not available for Okla homa so the Florida values are used as a proxy.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 225 Klosterboer 1999a, 1999b, 2000, 2001, 2002, 2003; Lindbe rg 2002, 2003, 2004; Linscombe 1999a, 1999b, 2001, 2002, 2003, 2004; Mutters 2002, 2003; Najita 2000, 2001; Schueneman 1999a, 1999b, 2001; Slaton 1999a, 1999b, 2000; Stansel 2004; Street 1999a, 1999b, 2000, 2001, 2002, 2003; Walker 2004; Wilson 2001, 2002, 2003, 2004) (see Table 6-25 and Table 6-26). The estimates provided for Florida remained constant over the entire 1990 through 2003 period, while the estimates for all other states varied over the time series. For California, the annual percents of rice area burned in the Sacr amento Valley are assumed to be repres entative of burning in the entire state, because the Sacramento Valley accounts for over 95 percen t of the rice acreage in Ca lifornia (Fife 1999). These values declined between 1990 and 2003 because of a legisl ated reduction in rice stra w burning (Lindberg 2002) (see Table 6-26).

All residue/crop product mass ratios except sugarcane were obtained from Strehler and Stützle (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). So ybean dry matter content was obtained from Strehler and Stützle (1987). Peanut dry matter content was obtained through personal communications with Jen Ketzis (1999), who accessed Cornell University’s Department of Animal Science’s computer model, Cornell Net Carbohydrate and Protein System. The residue carbon contents and nitrogen contents for all crops except soybeans and peanuts are from Turn et al. (1997). The residue carbon content for soybeans and peanuts is the IPCC default (IPCC/UNEP/OECD/IEA 1997). The nitrogen content of soybeans is from Barnard and Kristoferson (1985). The nitrogen content of peanuts is from Ketzis (1999). These data are listed in Table 6-27. The burning efficiency was assumed to be 93 percent, and the combustion efficiency was assumed to be 88 percent, for all crop types (EPA 1994). Emission ratios for all gases (see Table 6-28) were taken from the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).

Table 6-24: Agricultural Crop Production (Gg of Product) Crop 1990 1997 1998 1999 2000 2001 2002 2003 Wheat 74,292 67,534 69,327 62,569 60,758 53,262 43,992 63,590 Rice 7,113 8,346 8,578 9,391 8,703 9,794 9,601 9,050 Sugarcane 25,525 28,766 30,896 32,023 32,762 31,377 32,597 31,178 Corn* 201,534 233,864 247,882 239,549 251,854 241,485 228,805 256,905 Barley 9,192 7,835 7,667 6,103 6,939 5,430 4,940 6,011 Soybeans 52,416 73,176 74,598 72,223 75,055 78,671 74,291 65,795 Peanuts 1,635 1,605 1,798 1,737 1,481 1,940 1,506 1,880 *Corn for grain (i.e., excludes corn for silage).

Table 6-25: Percentage of Rice Area Burned by State State Percent Burned 1990-1998 Percent Burned 1999 Percent Burned 2000 Percent Burned 2001 Percent Burned 2002 Percent Burned 2003 Arkansas 13 13 13 13 16 22 California variable a 27 27 23 13 14 Florida b 0 0 0 0 0 0 Louisiana 6 0 5 4 3 3 Mississippi 10 40 40 40 8 65 Missouri 5 5 8 5 5 4 Oklahoma 3 3 3 3 3 0 Texas 1 2 0 0 0 0

a Values provided in Table 6-26. b Although rice is cultivated in Florida, crop residue burning is ille gal. Therefore, emissions remain 0 throughout the time ser ies.

Table 6-26: Percentage of Rice Area Burned in California Year California 1990 75 1991 75 1992 66 1993 60Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 226 1994 69 1995 59 1996 63 1997 34 1998 33

Table 6-27: Key Assumptions for Estimating Emissions from Field Burning of Agricultural Residues Crop Residue/Crop Ratio Fraction of Residue Burned Dry Matter Fraction Carbon Fraction Nitrogen Fraction Burning Efficiency Combustion Efficiency Wheat 1.3 0.03 0.93 0.4428 0.0062 0.93 0.88 Rice 1.4 variable 0.91 0.3806 0.0072 0.93 0.88 Sugarcane 0.8 0.03 0.62 0.4235 0.0040 0.93 0.88 Corn 1.0 0.03 0.91 0.4478 0.0058 0.93 0.88 Barley 1.2 0.03 0.93 0.4485 0.0077 0.93 0.88 Soybeans 2.1 0.03 0.87 0.4500 0.0230 0.93 0.88 Peanuts 1.0 0.03 0.86 0.4500 0.0106 0.93 0.88

Table 6-28: Greenhouse Gas Emission Ratios Gas Emission Ratio CH 4 a 0.005 CO a 0.060 N 2 O b 0.007 NO x b 0.121

a Mass of carbon compound released (units of C) relative to mass of total carbon released from burning (units of C). b Mass of nitrogen compound released (units of N) relative to mass of total nitrogen released from burning (units of N).



### Uncertainty

One source of uncertainty in the calculation of non-CO 2 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 y ear, are not collected at either the na tional 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 inform ation collected by state agencies and in published literature. Based on expert judgment, uncertainty in the fraction of crop residue burned ranged from zero to 100 percent, depending on the state and crop type.

Based on expert judgment, the uncertainty in production for a ll crops considered here is estimated to be 5 percent.

Residue/crop product ratios can vary among cultivars. For all crops except sugarcane, generic residue/crop product ratios, rather than ratios specific to the United States, have been used. An uncertainty of 10 percent was applied to the residue/crop product ratios for all crops.

Based on the range given for measurements of soybean dr y matter fraction (Strehler and Stützle 1994), residue dry matter contents were assigned an uncertainty of 3.1 percent for all crop types.

Burning and combustion efficiencies were assigned an uncertainty of 5 percent based on expert judgment.

The N 2 O emission ratio was estimated to have an uncertainty of 28.6 percent based on the range reported in IPCC (2000). The uncertainty estimated for the CH 4 emission ratio was 40 percent based on the range of ratios reported in IPCC (2000).

The results of the Tier 1 quantitative uncertainty analysis are summarized in Table 6-29. Field burning of agricultural residues CH 4 emissions in 2003 were estimated to be between 0.2 and 1.3 Tg CO 2 Eq. at a 95 percentInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 227 confidence level. This indicates a range of 69 percen t above and below the 2003 emission estimate of 0.8 Tg CO 2 Eq. Also at the 95 percent confidence level, N 2 O emissions were estimated to between 0.1 and 0.7 Tg CO 2 Eq. (or approximately 68 percent above and below the 2003 emission estimate of 0.4 Tg CO 2 Eq.).

Table 6-29: Tier 1 Quantitative Uncertainty Estimates for CH 4 and N 2 O Emissions from Field Burning of Agricultural Residues (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate (Tg CO 2 Eq.) Uncertainty (%) Uncertainty Range Relative to 2003 Emission Estimate (Tg CO 2 Eq.) Lower Bound Upper Bound Field Burning of

Agricultural Residues CH 4 0.8 69% 0.2 1.3 Field Burning of

Agricultural Residues N 2 O 0.4 68% 0.1 0.7



### Recalculations Discussion

For the current Inventory, a transcription error was fixed for the 1998 rice production data for California from the USDA 2000 Crop Production Summary Report (2001). The change resulted in increases of less than 0.1 Tg CO 2 Eq. (0.1 percent) in CH 4 and N 2 O emissions from the field burning of agri cultural residues for 1998. Additionally, the 2002 rice production data was updated from the USDA 2003 Crop Production Summary Report (2004). The change resulted in increases of less than 0.1 Tg CO 2 Eq. (0.2 and 0.4 percent, respectively) in CH 4 and N 2 O emissions from the field burning of agricultural residues for that year.s

Fi g ure 6-1: 2003 A g riculture Chapter GHG Sources 1.2

0 50 100 150 200 250 300 Agricultural Residue Burning Rice Cultivation Manure Management

Enteric Fermentation Agricultural Soil

Management

Tg CO 2 Eq A griculture as a Portion of all

Emissions

6.3%N Inputs

Direct N 0 Emissions 2

Geophysical Processes
Indirect N 0 Emissions 2

GroundwaterDeposition

Histosol Cultivation

Surface Water V olatilization

R u n o f f

L e a c h i n g N Flows:

Animal Wastes Livestock & Poultry Managed

Unmanaged

Sewage Sludge Commercial Fe rtilizer Application

Crop Residues N-fixing Crops

This graphic illustrates the sources and pathways of nitrogen that
result in direct and indirect N 2 O emissions from agricultural soils in the United States. Sources of nitrogen applied to, or deposited on, soils are respresented with arrows on the left-hand side of the graphic. Emissions pathways are also shown with arrows. On the lower right-hand side is a cut-away view of a representative section of a managed soil; histosol cultivation is represented here. 

### Direct and Indirect N 2 

### O Emissions from Agricultural Soils Figure 6 -2Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 229 

## 7. Land-Use Change and Forestry

This chapter provides an assessment of the net greenhouse gas flux 1 resulting from forest lands, croplands, and settlements. IPCC Good Practice Guidance for Land Use, Land-Use Change and Forestry (IPCC 2003) recommends reporting fluxes according to ch anges within and conversions between these land use types, as well as grassland and wetlands. However, consistent datasets are not available for the entire United States to allow results to be partitioned in this way. Therefore, greenhouse ga s flux has been estimated for the following categories: 1) forest land remaining forest land 2) croplands remaining croplands, and 3) settlements remaining settlements. This categorization provides additional s ources of information regarding N 2 O emissions by major land use type.

It should be noted that other land-use and land-use change activities result in fluxes of non-CO 2 greenhouse gases to and from soils that are not comprehensively accounted for currently. These fluxes include emissions of CH 4 from managed forest soils, as well as CH 4 emissions from artificially flooded lands , which result from activities such as dam construction. Aerobic (i.e., non-flooded) soils are a sink for CH 4 , so soil drainage can result in soils changing from a CH 4 source to a CH 4 sink, but if the drained soils are used for agriculture, fertilization and tillage disturbance can reduce the ability of soils to oxidize CH 4 . The non-CO 2 emissions and sinks from these other land use and landuse change activities were not assessed due to scientific uncertainties about the greenhouse gas fluxes that result from these activities.

The greenhouse gas flux from forest land remaining forest la nd is reported using estimates of changes in forest carbon stocks and the application of nitrous oxide (N 2 O) fertilizers to forest soils. Seven components of forest carbon stocks are analyzed: aboveground biomass, belowground biomass, dead wood, litter, soil organic carbon, harvested wood products in use, and harvested wood pr oducts in landfills. The estimated carbon dioxide (CO 2 ) flux from each of these forest components wa s derived from U.S. fore st inventory data, usi ng methodologies that are consistent with LULUCF Good Practice Guidance (IPCC 2003) and the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). In addition, this year, according to the new LULUCF Good Practice Guidance (IPCC 2003), N 2 O emissions from fertilized forest soils are accounted for utilizing a default methodology.

Croplands remaining croplands emission estimates are a re flection of the changes in agricultural soil carbon stocks on both cropland and grazing land since the necessary datasets were not available to sepa rate cropland and grassland fluxes. Changes in agricultural soil carbon stocks include mineral and organic soil carbon stock changes due to use and management of cropland and grazing land, and emissions of CO 2 due to the application of crushed limestone and dolomite to agricultural soils (i.e., soil liming). The methods used to estimate all three components of flux in agricultural soil carbon stocks are consistent with the Revised 1996 IPCC Guidelines and th e LULUCF Good Practice Guidance (IPCC 2003)

. Fluxes resulting from settlements remaining settlements incl ude landfilled yard trimmings and food scraps, urban trees, and soil N 2 O emissions from fertilization. Changes in yard trimming and food scrap carbon stocks in landfills are estimated using analysis of life-cycle greenhouse gas emissions and sinks associated with solid waste management (EPA 1998). Changes in carbon stocks in urba n trees are estimated based on field measurements in ten U.S. cities and data on national urban tree c over, using a methodology consistent with the LULUCF Good Practice Guidance (IPCC 2003). Finally, this year, according to the new LULUCF Good Practice Guidance (IPCC 2003), N 2 O emissions from fertilized settlement soils are account ed for according to a default methodology. Note that the chapter title “Land-Use Change and Forestry” has been used here to maintain consistency with the IPCC reporting structure for nationa l greenhouse gas inventories; however, the chapter covers land-use activities, in addition to land-use change and forestry activities. Therefore, except in table titles, the term “land use, land-use change, and forestry” will be used in the remainder of this chapter.

1 The term “flux” is used here to en compass both emissions of greenhouse gases to the atmosphere, and removal of carbon from the atmosphere. Removal of carbon from the atmosphe re is also referred to as “carbon sequestration.”Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 230 Unlike the assessments in other sectors, which are based on annual activity data, the flux estimates in this chapter, with the exception of those from wood products, ur ban trees, liming, and settlement and forest N 2 O emissions, are based on periodic activity data in the form of forest, land- use, and municipal solid waste surveys. Carbon dioxide fluxes from forest carbon stocks (except the wood product components) and from agricultural soils (except the liming component) are calculated on an average annual basis from data collected in intervals ranging from 1 to 10 years. The resulting annual averages ar e applied to years between surveys. Because state surveys are collected at different times, using this data structure, the estimated CO 2 fluxes from forest carbon stocks differ at the national level from year to year. Agricultural soil carbon flux calculations are constant over multi-year intervals, with large discontinuities between intervals; how ever, fluxes after 1997 are inconsistent due to the method of accounting for the application of manure and sewage sludge amendments to mineral soils after 1997. For the landfilled yard trimmings and food scraps source, periodic solid waste su rvey data were interpolated so that annual storage estimates could be derived. In additi on, because the most recent national fore st, land-use, and municipal solid waste surveys were completed prior to 2003, the estimates of CO 2 flux from forests, agricultural soils, and landfilled yard trimmings and food scraps are based in part on modeled projections or extrapolation. Carbon dioxide flux from urban trees is based on neither annual data nor periodic su rvey data, but instead on data collected over the period 1990 through 1999. This flux has been applied to the entire time series.

Land use, land-use change, and forestry activities in 2003 resulted in a net carbon sequestration of 828 Tg CO 2 Eq. (226 Tg C) (Table 7-1and Table 7-2). This represents an offset of approximately 14 percent of total U.S. CO 2 emissions. Total land use, land-use change, and forest ry net carbon sequestration declined by approximately 21 percent between 1990 and 2003. This decline was primarily due to a decline in the rate of net carbon accumulation in forest carbon stocks. Annual carbon accumulation in landf illed yard trimmings and food scraps also slowed over this period, as did annual carbon accumulation in agricultural soils. As described above, the constant rate of carbon accumulation in urban trees is a reflection of limited underlyi ng data (i.e., this rate represents an average for 1990 through 1999).

Table 7-1: Net CO 2 Flux from Land-Use Change and Forestry (Tg CO 2 Eq.) Sink Category 1990 1997 1998 1999 2000 2001 2002 2003 Forest Land Remaining Forest Land (949.3) (851.0) (805.5) (751.7) (747.9) (750.9) (751.5) (752.7)

Changes in Forest Carbon Stocks (949.3) (851.0) (805.5) (751.7) (747.9) (750.9) (751.5) (752.7) Cropland Remaining Cropland (8.1) (7.4) (4.3) (4.3) (5.7) (7.1) (6.2) (6.6)

Changes in Agricultural Soil Carbon

Stocks (8.1) (7.4) (4.3) (4.3) (5.7) (7.1) (6.2) (6.6) Settlements Remaining Settlements (84.7) (71.6) (71.2) (70.0) (68.9) (68.9) (68.8) (68.7)

Urban Trees (58.7) (58.7) (58.7) (58.7) (58.7) (58.7) (58.7) (58.7) Landfilled Yard Trimmings and Food

Scraps (26.0) (12.9) (12.5) (11.4) (10.2) (10.3) (10.2) (10.1) Total (1042.0) (930.0) (881.0) (826.1) (822.4) (826.9) (826.5) (828.0) Note: Parentheses indicate net se questration. Totals may not sum due to independent rounding.
Table 7-2: Net CO 2 Flux from Land-Use Change and Forestry (Tg C) Sink Category 1990 1997 1998 1999 2000 2001 2002 2003 Forest Land Remaining Forest Land (259) (232) (220) (205) (204) (205) (205) (205)

Changes in Forest Carbon Stocks (259) (232) (220) (205) (204) (205) (205) (205) Cropland Remaining Cropland (2) (2) (1) (1) (2) (2) (2) (2)

Changes in Agricultural Soil Carbon

Stocks (2) (2) (1) (1) (2) (2) (2) (2) Settlements Remaining Settlements (23) (20) (19) (19) (19) (19) (19) (19)

Urban Trees (16) (16) (16) (16) (16) (16) (16) (16) Landfilled Yard Trimmings and Food

Scraps (7) (4) (3) (3) (3) (3) (3) (3) Total (284) (254) (240) (225) (224) (226) (225) (226) Note: 1 Tg C = 1 teragram carbon = 1 million metric tons carbon. Parentheses indicate net sequest ration. Totals may not sum due to independent rounding.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 231 Land use, land-use change, and forestry activitie s in 2003 resulted in a net flux of 6.4 Tg CO 2 Eq. of N 2 O (20.7 Gg) (Table 7-3 and Table 7-4). Total N 2 O emissions from the application of fertilizers to forests and settlements increased by approximately 14 percent between 1990 and 2003.

Table 7-3: Net N 2 O Emissions from Land-Use Change and Forestry (Tg CO 2 Eq.) Sink Category 1990 1997 1998 1999 2000 2001 2002 2003 Forest Land Remaining Forest Land 0.1 0.3 0.4 0.5 0.4 0.4 0.4 0.4

N 2 O Fluxes from Soils 0.1 0.3 0.4 0.5 0.4 0.4 0.4 0.4 Settlements Remaining Settlements 5.5 6.1 6.1 6.2 6.0 5.8 6.0 6.0

N 2 O Fluxes from Soils 5.5 6.1 6.1 6.2 6.0 5.8 6.0 6.0 Total 5.6 6.4 6.5 6.6 6.3 6.2 6.4 6.4 Note: Totals may not sum due to independent rounding.

Table 7-4: Net N 2 O Emissions from Land-Use Change and Forestry (Gg) Sink Category 1990 1997 1998 1999 2000 2001 2002 2003 Forest Land Remaining Forest Land 0.2 1.0 1.1 1.5 1.1 1.3 1.3 1.3

N 2 O Fluxes from Soils 0.2 1.0 1.1 1.5 1.1 1.3 1.3 1.3 Settlements Remaining Settlements 17.9 19.8 19.8 19.9 19.3 18.7 19.4 19.4

N 2 O Fluxes from Soils 17.9 19.8 19.8 19.9 19.3 18.7 19.4 19.4 Total 18.1 20.7 20.9 21.4 20.4 20.0 20.7 20.7 Note: Totals may not sum due to independent rounding.



### 7.1. Forest Land Remaining Forest Land Changes in Forest Carbon Stocks (IPCC Source Category 5A1)

For estimating carbon (C) stocks or stock change (flux), C in forest ecosystems can be divided into the following five storage pools (IPCC 2003):

• Aboveground biomass, all living biomass above the soil including stem, stump, branches, bark, seeds, and foliage. This category includes live understory.

• Belowground biomass, all living biomass of coarse living roots greater than 2 mm diameter.

• Dead wood, including all non-living woody biomass either standing, lying on the ground (but not including litter), or in the soil.

• Litter, including the litter, fumic, and humic layers, a nd all non-living biomass with a diameter less than 7.5 cm at transect intersection, lying on the ground.

• Soil organic carbon (SOC), including all organic material in soil to a depth of 1 meter but excluding the coarse roots of the above pools. In addition, there are two harvested wood pools al so necessary for estimating C flux, which are:

• Harvested wood products in use.

• Harvested wood products in landfills. Carbon is continuously cycled among these storage pools and between forest ecosystems and the atmosphere as a result of biological processes in fore sts (e.g., photosynthesis, growth, morta lity, decomposition, and disturbances such as fires or pest outbreaks) and anthropogenic activities (e.g., harvesting, th inning, clearing, a nd replanting). As trees photosynthesize and grow, C is removed from the atmosphe re and stored in living tree biomass. As trees age, they continue to accumulate C until they reach maturity, at which point they stor e a relatively constant amount of C. As trees die and otherwise deposit litter and debris on the forest floor, C is released to the atmosphere or transferred to the soil by organisms that facilitate decomposition.

The net change in forest C is not equivalent to the net flux between forests and the atmosphere because timber harvests do not cause an immediate flux of C to the atmosphere. Instead, harvesting transfers C to a "product pool." Once in a product pool, the C is emitted over time as CO 2 when the wood product combusts or decays. The rate ofInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 232 emission varies considerably among different product pools. For example, if timber is harvested to produce energy, combustion releases C immediately. Conversely, if timber is harvested and used as lumber in a house, it may be many decades or even centuries before the lumber decays and C is released to the atmosphere. If wood products are disposed of in landfills, the C contained in the wood may be released many years or decades later, or may be stored almost permanently in the landfill.

This section quantifies the net changes in C stocks in th e five forest C pools and two harvested wood pools. The net change in stocks for each pool is estimated, and then th e changes in stocks are summed over all pools to estimate total net flux. Thus, the focus on C implies that all C- based greenhouse gases are included, and the focus on stock change suggests that specific ecosystem fluxes are not separately itemized in this report. Disturbances from forest fires and pest outbreaks are implicitly included in the net ch anges. For instance, an i nventory conducted after fire counts only trees left. The change between inventories t hus counts the carbon changes due to fires; however, it may not be possible to attribute the changes to the disturbance specifically. The IPCC LULUCF Good Practice Guidance (IPCC 2003) recommends reporting C stocks accordi ng to several land use types and conversions, specifically forest land remaining forest land, nonfores t land becoming forest, and forest becoming non-forest. Currently, consistent datasets are not available for the entire United States to allow results to be partitioned in this way. Instead, net changes in all forest-related land, including non-forest land converted to forest and forests converted to non-forest are reported here.

Forest C storage pools, and the flows between them via emissions, sequestration, and transfers, are shown in Figure 7-1. In the figure, boxes represent forest C storage pools and arrows represent flows between storage pools or between storage pools and the atmosphere. Note that the boxes are not identical to the storage pools identified in this chapter. The storage pool s identified in this chapter ha ve been altered in this gr aphic to better illustrate the processes that result in transfers of C from one pool to a nother, and emissions to the atmosphere as well as uptake from the atmosphere.

Figure 7-1: Forest Sector Carbon Pools and Flows.

Note: Boxes represent forest C storage pools and arrows repres ent flows between storage pools or between storage pools and the atmosphere.

Approximately 33 percent (303 million hectares) of the U.S. land area is forested (Smith et al. 2004b). From the early 1970s to the early 1980s, forest land declined by approximately 2.4 million hect ares. During the 1980s and 1990s, forest area increased by about 3. 7 million hectares. These net change s in forest area represent average annual fluctuations of only about 0.1 percent. Given the low rate of change in U.S. forest land area, the major influences on the current net C flux fro m forest land are management activitie s and the ongoing impacts of previous land-use changes. These activities affect the net flux of C by altering the amount of C stor ed in forest ecosystems. For example, intensified management of forests can increase both the rate of growth and the eventual biomass density 2 of the forest, thereby increasing the uptake of C. Harvesting forests removes much of the aboveground C, but trees can grow on this area again and sequester C. The reversion of cropland to forest land increases C storage in biomass, forest floor, and soils. The net effects of forest management and the effects of land-use change involving forest lands are captured in the estimates of C stocks and fluxes presented in this chapter.

In the United States, improved forest management practices, the regeneration of previously cleared forest areas, as well as timber harvesting and use have resulted in net uptake (i.e., net sequestrati on) of C each year from 1990

2 The term “biomass density” refers to the ma ss of vegetation per unit area. It is usua lly measured on a dry-weight basis. D ry biomass is about 50 percent carbon by weight.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 233 through 2003. Due to improvements in U.S. agricultural pr oductivity, the rate of forest clearing for crop cultivation and pasture slowed in the late 19th century, and by 1920 this practice had a ll but ceased. As farming expanded in the Midwest and West, large areas of previously cultivated land in the East were taken out of crop production, primarily between 1920 and 1950, and were a llowed to revert to forests or were actively reforested. The impacts of these land-use changes still affect C fluxes from forests in the East. In addition, C fluxes from eastern forests have been affected by a trend toward managed growth on privat e land. Collectively, these changes have nearly doubled the biomass density in eastern forests since the early 1950s. More recently, the 1970s and 1980s saw a resurgence of federally-sponsored forest management programs (e.g ., the Forestry Incentive Program) and soil conservation programs (e.g., the Conservation Reserve Program), which have focused on tree planting, improving timber management activities, combating soil eros ion, and converting margin al cropland to forests. In addition to forest regeneration and management , forest harvests have also affected net C fluxes. Because most of the timber harvested from U.S. forests is used in wood pr oducts, and many discarded wood products are disposed of in landfills rather than by incineration, significant quantitie s of C in harvested wood are transfe rred to long-term storage pools rather than being released rapidly to the atmosphere (Skog a nd Nicholson 1998). The size of these long-term C storage pools has increased during the last century.

Changes in C stocks in U.S. forests and harvested w ood were estimated to account for an average annual net sequestration of 832 Tg CO 2 Eq. (227 Tg C) over the period 1990 through 2003 (Table 7-5, Table 7-6, and Figure 7-2). In addition to the net accumulati on of C in harvested wood pools, sequest ration is a reflection of net forest growth and increasing forest area over this period, particul arly before 1997. The increase in forest sequestration is due more to an increasing C density per area than to the increase in area of forestland. Forestland in the conterminous United States was a pproximately 246, 250, and 251 million hectares for 1987, 1997, and 2002, respectively, only a 2 percent increase over the period (Smith et al. 2004b). Continuous, regular annual surveys are not available over the period for each stat e; therefore, estimates for non-survey years were derived by interpolation between known data points. Survey years vary from state to state. National estimates are a composite of individual state surveys. Total sequestration declined by 21 percent between 1990 and 2003. This decline was primarily due to a decline in the estimated rate of sequestration in fore st soils. Inventory derived estimates of soil C stocks are based solely on forest area and type. Thus, changes in soil C over time are directly the result of changes in total forest area or changes in forest type from forest inventory data.

Table 7-5. Net Annual Changes in Carbon Stocks (Tg CO 2 Eq. yr -1 ) in Forest and Harvested Wood Pools Carbon Pool 1990 1997 1998 1999 2000 2001 2002 2003 Forest (739) (638) (599) (537) (537) (537) (537) (537)

Aboveground Biomass (396) (457) (437) (400) (400) (400) (400) (400) Belowground Biomass (77) (89) (85) (78) (78) (78) (78) (78) Dead Wood (74) (53) (51) (45) (45) (45) (45) (45) Litter (67) (31) (28) (26) (26) (26) (26) (26) Soil Organic Carbon (125) (8) 1 12 12 12 12 12 Harvested Wood (210) (213) (206) (215) (211) (214) (214) (216)

Wood Products (48) (58) (52) (62) (59) (59) (59) (60) Landfilled Wood (162) (155) (154) (153) (152) (155) (155) (155) Total Net Flux (949) (851) (806) (752) (748) (751) (751) (753) Note: Parentheses indicate net C sequestration (i.e., a net removal of C from the at mosphere). Total net flux is an estimate o f the actual net flux between the total forest C pool and the atmosphere . Forest estimates are based on interpolation and extrapolat ion of inventory data as described in the te xt and in Annex 3.12. Harvested wood estim ates are based on results from annual survey s and models. Totals may not sum due to independent rounding.

Table 7-6. Net Annual Changes in Carbon Stocks (Tg C yr -1 ) in Forest and Harvested Wood Pools Carbon Pool 1990 1997 1998 1999 2000 2001 2002 2003 Forest (202) (174) (163) (146) (146) (146) (146) (146)

Aboveground Biomass (108) (125) (119) (109) (109) (109) (109) (109) Belowground Biomass (21) (24) (23) (21) (21) (21) (21) (21) Dead Wood (20) (14) (14) (12) (12) (12) (12) (12) Litter (18) (9) (8) (7) (7) (7) (7) (7)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 234 Soil Organic Carbon (34) (2) 0 3 3 3 3 3 Harvested Wood (57) (58) (56) (59) (57) (58) (58) (59)

Wood Products (13) (16) (14) (17) (16) (16) (16) (16) Landfilled Wood (44) (42) (42) (42) (41) (42) (42) (42) Total Net Flux (259) (232) (220) (205) (204) (205) (205) (205) Note: Parentheses indicate net C sequestration (i.e., a net removal of C from the at mosphere). Total net flux is an estimate o f the actual net flux between the total forest C pool and the atmosphere . Forest estimates are based on interpolation and extrapolat ion of inventory data as described in the te xt and in Annex 3.12. Harvested wood estim ates are based on results from annual survey s and models. Totals may not su m due to independent rounding.

Stock estimates for forest and harvested wood C storage pools are presented in Table 7-7. Together, the aboveground live and forest soil pools account for a large proportion of total fore st C stocks. C stocks in all nonsoil pools increased over time. Therefore, C sequestration wa s greater than C emissions from forests, as discussed above. Figure 7-3 shows the average carbon density in forests by state, estimated for 2004.

Table 7-7. Carbon Stocks (Tg C) in Forest and Harvested Wood Pools Carbon Pool 1990 1997 1998 1999 2000 2001 2002 2003 2004 Forest 39,498 40,812 40,986 41,149 41,296 41,442 41,589 41,735 41,882

Aboveground Biomass 14,114 14,928 15,053 15,172 15,281 15,390 15,499 15,608 15,717 Belowground Biomass 2,805 2,963 2,987 3,011 3,032 3,053 3,074 3,095 3,117 Dead Wood 2,444 2,572 2,587 2,600 2,613 2,625 2,638 2,650 2,662 Litter 4,496 4,598 4,606 4,614 4,621 4,628 4,636 4,643 4,650 Soil Organic Carbon 15,640 15,750 15,752 15,752 15,749 15,745 15,742 15,738 15,735 Harvested Wood 1,915 2,307 2,365 2,421 2,480 2,537 2,595 2,654 2,713

Wood Products 1,134 1,232 1,248 1,262 1,279 1,295 1,311 1,327 1,344 Landfilled Wood 781 1,074 1,117 1,159 1,200 1,242 1,284 1,327 1,369 Total Carbon Stock 41,414 43,119 43,351 43,570 43,775 43,979 44,184 44,389 44,594 Note: Forest C stocks do not include forest stocks in Alaska, Hawaii, or U.S. terr itories, or trees on non-forest land (e.g., u rban trees). Wood product stocks include exports, even if the logs are processed in othe r countries, and exclude imports. Forest estimates are based on interpolation and extra polation of inventory data as described in the text and in Annex 3.12. Harvested wood estimates are based on results from annual surveys and m odels. Totals may not sum due to independent rounding. Inventories are assumed to represent stocks as of January 1 of the inventory year. Flux is the net annual change in stock. Thu s, an estimate of flux for 2003 requires es timates of C stocks for 2003 and 2004.

Figure 7-2: Estimates of Net Annual Changes in Carbon Stocks for Major Carbon Pools (Tg C yr -1 )

Note: Estimates for harvested wood are based on the same methodology and data as the previous U.S. Inventory (EPA 2004). Estimates for all pools are based on measured forest inventory data as described in the text. Total Net includes all forest po ols: biomass, dead wood, litter, forest soils, wood products, and landfilled wood.

Figure 7-3: Average Carbon Density in the Forest Tree Pool in the Conterminous U.S. During 2004.

Methodology
The methodology described herein is consistent with LULUCF Good Practice Guidance (IPCC 2003) and the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). Estimates of net C flux from Land-Use Change and Forestry, including all pools except harvested wood, we re derived from periodic and annualized inventories ofInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 235 forest stocks. Net changes in C stocks were interpolat ed between survey years. Carbon emissions from harvested wood were determined by accounting for the variable rate of decay of harv ested wood according to its disposition (e.g., product pool, landfill, combustion). 3 Different data sources were used to estimate the C stocks and stock change in (1) forests (aboveground and belowground biomass, dead wood, a nd litter), (2) forest soils, and (3) harvested wood products. Therefore, these pools are described separately below.



### Live Biomass, Dead Wood, and Litter Carbon

The estimates of non-soil forest C stocks are based on data derived from forest inventory surveys. Forest survey data were obtained from the USDA Fore st Service, Forest Inventory and Analysis (FIA) program (Frayer and Furnival 1999, Smith et al. 2001). Surveys provide estimates of the merchantable volume of wood and other variables that are used to estimate C stocks. Estimates of temporal change such as growth, mortality, harvests, or area change are derived from repeated surveys, which were conducted every 5 to 14 years, depending on the state. Historically, the FIA program did not conduct detailed surveys of all forest land, but instead focused on land capable of supporting timber production (timberland 4 ). However, over time individual state surveys gradually started to include reserved and less productive forest lands. The C stock estimates provided here include all forest land, see Annex 3.12 for discussion of how past data gaps on these lands were filled.

Temporal and spatial gaps in surveys were addressed with the new national plot design and annualized sampling (Miles et al. 2001, Alerich et al. 2004), which were recently introduced by FIA. Annualized sampling means that a portion of plots throughout each state is sampled each year, with the goal of m easuring all plots once each 5 years. Sampling is designed such that partial inventory cycles provi de usable, unbiased samples of forest inventory. Thus, many states have relatively recent partial inventories, ye t not all states are currently surveyed this way. All annualized surveys initiated since 1998 have followed the new national plot design fo r all forestlands, including reserved and less productive lands. Inventories are assumed to represent stocks as of January 1 of the inventory year.
For each periodic or annualized inventory in each state, each C pool wa s estimated using coefficients from the FORCARB2 model (Birdsey and Heath 1995, Birdsey and Heath 2001, Heath et al. 2003, Smith et al. 2004a). Estimates of C stocks made by the FORCARB2 coefficients at the plot level are organized somewhat differently than the standard IPCC pools reported in Table 7-7. However, the estimators are compatible with reorganizing the pools following IPCC LULUCF Good Practice Guidance (2003). For example, the biomass pools here include the FORCARB2 pools of live trees and understory vegetation, each of which are divided into aboveground versus belowground portions. Calculations for the tree porti on of the aboveground biomass C pool were made using volume-to-biomass conversion factors for different types of forests as presented in Smith et al. (2003). Biomass was converted to C mass by divi ding by two because dry biomass is approximately 50 percent C (IPCC/UNEP/OECD/IEA 1997). The other portion of abovegr ound biomass, live understory C, was estimated from inventory data using tables presente d in Birdsey (1996). Litter C was estim ated from inventory data using the equations presented in Smith and Heath (2002). Down dead wood was estimated using a FORCARB2 simulation and U.S. forest statistics (Smith et al. 2001).

3 The wood product stock and flux estimates presented here use the production approach, meaning that they do not account for C stored in imported wood products, but do include C stored in exports , even if the logs are proce ssed in other countries. This approach is used because it follo ws the precedent established in pr evious reports (Heath et al. 1996). 4 Forest land in the U.S. includes land that is at least 10 per cent stocked with trees of any size. Timberland is the most productive type of forest land, which is on unreserved land and is producing or capable of producing crops of industrial wood. Productivity is at a minimum rate of 20 cubic feet of industria l wood per acre per year. The remaining portion of forest land is classified as either reserved forest land, which is forest la nd withdrawn from timber use by stat ute or regulation, or other fo rest land, which includes less productive forests on which timber is growing at a rate less th an 20 cubic feet per acre per year. I n 2002, there were about 199 million hectares of timberland in the conterminous U.S., which represented 79 percent of all forest lands over the same area (Smith et al. 2004b).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 236 

### Forest Soil Carbon
Estimates of soil organic carbon stocks are based solely on forest area and on average soil C density for each broad forest type group. Thus, any changes in soil C stocks are due to changes in total forest area or the distribution of forest types within that area. Estimates of the organic C content of soils are based on the national STATSGO spatial database (USDA 1991) and follow methods of Amichev and Galbraith (2004). These data were overlaid with FIA survey data to estimate soil C on forest lands by broad forest type group.



### Forest Carbon Stocks and Fluxes
The overall approach for determining forest C stock change was to estimate forest C stocks based on data from two forest surveys conducted several years apart. Carbon stocks were calculate d separately for each state based on inventories available since 1990 and for the most recent inventory prior to 1990. Thus, the number of separate stock estimates for each state was one less than the number of available inventories. Fo r each pool in each state in each year, C stocks were estimated by linear interpolation between survey year s. Similarly, fluxes were estimated for each pool in each state by dividing the difference between two successi ve stocks by the number of intervening years between surveys. Note that inventories are assumed to represent stocks as of January 1 of the inventory year; thus, stocks in 1989 and 1993 can be used to estimate fl ux for 1989 through 1992, for example. Stocks and fluxes since the most recent survey were ba sed on extrapolating estimates from the last two surveys. C stock and flux estimates for each pool were summed over all states to fo rm estimates for the conterminous United States. Data sources and methods for estimating individual C pools are described more fully in Annex 3.12.



### Harvested Wood Carbon
Estimates of C stock changes in wood products and w ood discarded in landfills were based on the methods described by Skog and Nicholson (1998) . Carbon stocks in wood products in use and wood products stored in landfills were estimated from 1910 onwar d based on historical data from th e USDA Forest Service (USDA 1964, Ulrich 1989, Howard 2001), and historical data as implemented in the framework underlying the North American Pulp and Paper (NAPAP, Ince 1994) and the Timber Assessment Market and the Aggregate Timberland Assessment System Timber Inventory models (TAMM/ATLAS, Hayn es 2003, Mills and Kincaid 1992). Beginning with data on annual wood and paper production, the fate of C in harvested wood was tracked for each year from 1910 through 2003, and included the change in C stocks in wood produc ts, the change in C in landfills, and the amount of C emitted to the atmosphere (CO 2 and CH 4 ) both with and without energy rec overy. To account for imports and exports, the production approach was used, meaning that C in exported wood was counted as if it remained in the United States, and C in imported wood was not counted.

Uncertainty
The forest survey data that underlie the forest C estimates are based on a statistical sample designed to represent the wide variety of growth conditions present over large territo ries. However, forest survey data that are currently available generally exclude timber stocks on most forest land in Alaska, Hawaii, and U.S. territories. For this reason, estimates have been developed only for the cont erminous United States. Within the conterminous United States, the USDA Forest Service mandate s that forest area data are accurate within 3 percent at the 67 percent confidence level (one standard error) per 405,000 ha of forest land (Miles et al. 2001). For larger areas, the uncertainty in area is concomitantly smaller. For volume data, the accuracy is targeted to be 5 percent for each 28,300 m 3 at the same confidence level. An analysis of uncertainty in growing stock volume data for timber producing lands was undertaken for five states: Florida, Georgia, North Carolina, South Carolina, and Virginia (Phillips et al. 2000). Nearly all of th e uncertainty was found to be due to sampling rather than the regression equations used to estimate volume from tree height and di ameter. Standard errors for growing stock volume ranged from 1 to 2 percent for individual states and less than 1 per cent for the 5-state region. However, the total standard error for the change in growing stock volume was estimat ed to be 12 to 139 percent for individual states, and 20 percent for the 5-state region. The high relative uncertainty for growing stock volume change in some states was due to small net changes in growing stock volume. Howeve r, the uncertainty in volume change may be smaller than was found in this study because estimates from samples ta ken at different times on pe rmanent survey plots areInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 237 correlated, and such correlation reduces the uncertainty in estimates of changes in volume or C over time (Smith and Heath 2000). Based on these accuracy guidelines and these re sults for the Southeastern United States, forest area and volume data for the conterminous Un ited States are expected to be r easonably accurate, although estimates of small changes in growing stock volume may have substantial uncertainty.

In addition to uncertainty in growing stock volume, there is uncertainty associated with the estimates of C stocks in other ecosystem pools. Estimates for these pools are derived fro m extrapolations of site-specific studies to all forest land since survey data on these pools are not generally available. Such extra polation introduces uncertainty because available studies may not adequately represent regional or national averages. Uncertainty may also arise due to (1) modeling errors, for example relying on coefficients or re lationships that are not well known, and (2) errors in converting estimates from one reporting unit to another (Birdsey and Heath 1995). An important source of uncertainty is that there is little consensus from available data sets on the effect of land use change and forest management activities (such as harvest) on soil C stocks. For example, while Johnson and Curtis ( 2001) f ound little or no net change in soil C following harvest, on average, across a number of studies, many of the individual studies did exhibit differences. Heath and Smith (2000b) noted th at the experimental design in a number of soil studies limited their usefulness for determining effects of harvesting on soil C. Because soil C stocks are large, estimates need to be very precise, since even small relative changes in soil C sum to large differences when integrated over large areas. The soil C stock and stock change estimates presented herein are based on the assumption that soil C density for each broad forest type gr oup stays constant over time. As more information becomes available, the effects of land use and of changes in land use and forest management will be better accounted for in estimates of soil C (see “Planned Improvements,” below).

Recent studies have begun to quantify the uncertainty in national-level fo rest C budgets based on the methods adopted here. Smith and Heath (2000) and Heath and Smith (2000a) report on an uncertainty analysis they conducted on C sequestration in privately owned timberla nds throughout the conterminous United States. These studies are not directly comparable to the estimates in this ch apter because they used an older version of the FORCARB model and are based on older data. However, the relative magnitudes of the uncertainties are informative. For the period 1990 through 1999, the true mean C flux was estimated to be within 15 percent of the reported mean at the 80 percent confidence level. The corresponding true mean C stock estimate for 2000 was within approximately 5 percent of the reported mean value at the 80 percent confidence le vel. The relatively greater uncertainty in flux estimates compared to stock estimates is roughly similar to that found for estimates of growing stock volume discussed above (Phillips et al. 2000). In both analyses, ther e are greater relative uncertainties associated with smaller estimates of fl ux. Uncertainty in the estimates presented in this inventory may be greater than those presented by Heath and Smith (2000a) for several reasons. Most importantly, their analysis did not include uncertainty in growing stock volume data or uncer tainties in stocks and fluxes of C from harvested wood.

The uncertainty analysis was performed using the IPCC-recommended Tier 2 uncertainty estimation methodology, Monte Carlo Simulation technique. The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 7-8. The 2003 flux estimate for forest C stocks is estimated to be between (1,120.5) and (383.5) Tg CO 2 Eq. at a 95 percent confidence level (or 19 of 20 Monte Carlo Stochastic Simulations). This indicates a range of 49 percent below to 49 percent above the 2003 flux estimate of (752.7) Tg CO 2 Eq.

Table 7-8: Tier 2 Quantitative Uncertainty Estimates for CO 2 Net Flux from Forest Land Remaining Forest Land: Changes in Forest Carbon Stocks (Tg CO 2 Eq. and Percent)

Source Gas 2003 Flux Estimate Uncertainty Range Relative to 2003 Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Forests Remaining Forests: Changes in Forest Carbon Stocks CO 2 (752.7) (1,120.5) (383.5) -49% +49%

a Range of flux estimates predicted by Monte Carlo Stocha stic Simulation for a 95 percent confidence interval.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 238 QA/QC and Verification
As discussed above, the USDA Forest Service Forest I nventory and Analysis program has conducted consistent forest surveys based on extensive statistically-based sampling of most of the forest land in the conterminous United States since 1952. The main purpose of the Forest Inve ntory and Analysis program has been to estimate areas, volume of growing stock, and timber pr oducts output and utilization factors. The Forest Inventory and Analysis program includes numerous quality assurance and quality control procedures, incl uding calibration among field crews, duplicate surveys of some plots, and systematic checking of recorded data . Because of the statistically-based sampling, the large number of survey plots, and the quality of the data, the survey databases developed by the Forest Inventory and Analysis program form a strong foundation for C stock estimates. Field sampling protocols, summary data, and detailed inventory databases are archived and are publicly available on the Internet (FIA Homepage).

Many key calculations for estimating current forest C stoc ks based on FIA data are based on coefficients from the FORCARB2 model (see additional discussion in the Methods section above and in Annex 3.12). The model has been used for many years to produce national assessments of forest C stocks and stock changes. General quality control procedures were used in performing calculations to estimate C stocks based on survey data. For example, the derived C datasets, which include inventory variables su ch as areas and volumes, were compared with standard inventory summaries such as Resources Planning Act (RPA) Forest Resource Tables or selected population estimates generated from the FIADB, which are available at an FIA Internet site (FIA Database Retrieval System). Agreement between the C datasets and th e original inventories is important to verify accuracy of the data used. Forest Inventory and Analysis data and some model proj ections are given in English units, but C stock estimates were developed using metric units. To avoid unit conversion errors, a standard conversion table in electronic form was used (Appendix B of Smith et al. 2001). Finally, C stock estimates were compared with previous inventory report estimates to assure that any differences could be e xplained by either new data or revised calculation methods (see the “Recalculations” discussion below).

Recalculations Discussion
The overall scheme for developing annualized estimates of C stocks based on the individual state surveys is similar to that presented in the previous Inventory (EPA 2003). Methods for estimating soil organic carbon are new for the current Inventory; differences are in the interpretation of STATSGO data and their relationship with FIA survey data as described by Amic hev and Galbraith (2004)—see Annex 3.12 for a dditional information. Similar to that reported in the previous Inventory, estimates of forest C stocks and fluxes are based on forest inventory data from individual states rather than regions, and the data collected in states were assigned an av erage survey inventory plot date rather than simply assigned the year for which the database was compiled. However, the selection and compilation of survey data was implemented differently fo r the current Inventory, and there were some important differences in the underlying data.

Three differences in methods can affect the non-soil forest C estimates. First, the selection of the datasets representing individual state surveys was independent of la st year’s selections. Both RPA and the newer FIADB datasets were considered, whereas last year only RP A data were used. The RPA data represent specific compilations of survey data and include some older data not currently available in the FIADB. Using both ensured the most recent data were used, yet older data were ava ilable as needed. Inventory data—even older surveys—are occasionally modified so that RPA and FI ADB data of ostensibly the same surv ey may have some slight differences that can affect the C estimates. This is likely to have a very minor effect on recalculation of C stocks. Another minor change in method is that fluxes were separately determined from the or iginal survey data for each state for each pool; in contrast, last year stocks were interpolated and summed to a na tional total for each year before flux was calculated. Finally, separate stocks and fluxes were determined for National Forest lands where, in the past, independent surveys were conducted at distinctly different times.

Pool definitions have changed for the cu rrent Inventory, as suggested by IPCC LULUCF Good Practice Guidance (IPCC 2003). In previous Inventories, the pools were trees , understory, forest floor, down dead wood, and forest soils. The forest soil pool is now soil organic carbon; fore st floor is called litter. Th e previous tree pool included both above- and belowground biomass and mass of standing d ead trees. The mass of standing dead trees was addedInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 239 to the down dead wood pool and is called dead wood. The remainder of the tree pool, live biomass, as well as the understory pool, was split into above- and belowground portions. The above ground tree and understory pools were summed into the aboveground biomass pool; the belowground portions of these pools were added to create the belowground biomass pools.

Two changes in the use of data are also likely to affect the recalculation of C. The equations used to estimate tree C from forest inventory data have been revised slightly; the ne t effect is that total tree C (live plus standing dead trees, which are part of both the biomass and dead wood pools as summarized here) calculated for the 2002 RPA database (Smith et al. 2004b) was 0.3 percent greater with the new set of equations relative to those used last year. Perhaps the largest effect on C recalculations is that for the previous Inventory the fina l C stocks were modeled. This year, however, values are simply extrapolated . The principal reason for eliminating the projections was the difficulty in establishing projections consistent with the available forest inventory data.

Overall, these changes resulted in an average annual increase of 103.3 Tg CO 2 Eq. (16 percent) in forest carbon stocks for the period 1990 through 2002.

Planned Improvements
The Forest Inventory and Analysis pr ogram has adopted a new annualized desi gn, such that a portion of each state will be surveyed each year (Gillespie 1999). The annualized survey also includes measuring attributes that are needed to estimate C in various pools, such as soil C and forest floor C, on a subset of the plots. During the next several years, the use of annual data, including new dataon soil and forest floor C stocks, and new data on nontimberlands, will improve the precision and accuracy of estimates of forest C stocks and fluxes.

As more information becomes available about historical land use, the ongoing effects of changes in land use and forest management will be better accounted for in estimat es of soil C (Birdsey and Lewis 2003). Currently, soil C estimates are based on the assumption that soil C density depends only on broad forest type group, not on land use history. However, many forests in the Eastern United States are re-growing on abandoned agricultural land. During such regrowth, soil and forest floor C stocks often in crease substantially over many years or even decades, especially on highly eroded agricultural land. In addition, w ith deforestation, soil C stocks often decrease over many years. A new methodology is being developed to account for these cha nges in soil C over time. This methodology includes estimates of area changes among land uses (especially forest and agriculture), estimates of the rate of soil C stock gain with afforestation, and estimates of the rate of soil C stock loss with deforestation over time. This topic is important because soil C stocks are large, and soil C flux estimates contribute substantially to total forest C flux, as shown in Table 7-6 and Figure 7-2.

The estimates of C stored in harvested wood products are currently being revised using more detailed wood products production and use data, a nd more detailed parameters on di sposition and decay of products.



### N 2 

### O Fluxes from Soils (IPCC Source Category 5.A.1)

Of the fertilizers applied to soils in the United States, no more than one percent is applied to forest soils. Application rates are similar to those occurring on cropped soils, but in any given year, only a small proportion of total forested land receives fertilizer. This is because forests are typica lly fertilized only twice during their approximately 40 year growth cycle (once at planting and once at approximately 20 years). Thus, although the rate of fertilizer application for the area of forests that receives fertilizer in any given year is relatively high, average annual applications, inferred by dividing all forest land by the amount of fertilizer added to forests in a given year, is quite low. Nitrous oxide (N 2 O) emissions from forest soils for 2003 were almost 7 times higher than the baseline year (1990). The trend toward increasing N 2 O emissions is a result of an increase in fertilized area of pine plantations in the southeastern United States. Total 2003 forest soil N 2 O emissions are roughly equivalent to 3.3 percent of the total forest soil carbon flux, and 0.07 percen t of the total sequestration in standing forests, and are summarized in Table 7-9.

Table 7-9. N 2 O Fluxes from Soils in Forests Remaining Forests (Tg CO 2 Eq. and Gg) Forests Remaining Forests: N 2 O Fluxes 1990 1997 1998 1999 2000 2001 2002 2003Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 240 from Soils Tg CO 2 Eq. 0.06 0.30 0.35 0.47 0.35 0.39 0.39 0.39 Gg 0.19 0.96 1.14 1.50 1.14 1.26 1.26 1.26

Methodology
According to U.S. Forest Service statistics for 1996 (USDA Forest Service 2001), approximately 75 percent of trees planted for timber, and about 60 percent of national to tal harvested forest area are in the southeastern United States. Consequently, it was assumed that southeastern pine plantations represent the vast majority of fertilized forests in the United States. Th erefore, estimates of direct N 2 O emissions from fertilizer applications to forests were based on the area of pine plantations r eceiving fertilizer in the southeastern Un ited States and estimated application rates (North Carolina Sate Forest Nutrition Cooperative 2002). Not accounting for fertilizer applied to non-pine plantations is justified because fertiliza tion is routine for pine forests but rare for hardwoods (Bi nkley et al. 1995). For each year, the area of pine receiving N fertilizer wa s multiplied by the midpoint of the reported range of N fertilization rates (150 lbs. N per acre). Data for areas of forests receiving fertilizer out side the southeastern United States were not available, so N additions to non-south eastern forests are not included here; however, it should be expected that emissions from the small ar eas of fertilized forests in other regi ons would be insubstantial because the majority of trees planted and harvested for timber are in the southeastern United St ates (USDA Forest Service 2001). Area data for pine plantations receiving fertilizer in the southeast we re not available for 2002 and 2003, so data from 2001 were substituted for these years. The proporti on of N additions that vola tilized from forest soils was assumed to be 10 percent of total amendments, according to the IPCC’s default. Th e unvolatilized N applied to forests was then multiplied by the IPCC default emission factor of 1.25 percent to estimate direct N 2 O emissions. The volatilization and leaching/ runoff fractions, calculated according to th e IPCC default factors of 10 percent and 30 percent, respectively, were included with all sources of indirect emissions in the Agricultural Soil Management source category of the Agriculture sector.

Uncertainty

The amount of N 2 O emitted from forests depends not only on N inputs, but also on a large number of variables, including organic carbon availability, O 2 partial pressure, soil moisture content, pH, temperature, and tree planting/harvesting cycles. The effect of the combined inter action of these variables on N 2 O flux is complex and highly uncertain. The IPCC default methodology used here does not incorporate any of these variables and only accounts for variations in estimated fertilizer applicati on rates and estimated areas of forested land receiving fertilizer. All forest soils are treated equivalently under this methodology. Furthermore, only synthetic fertilizers are captured, so applications of organi c fertilizers are not accounted for here.

Uncertainties exist in the fer tilizer application rates, the area of forest ed land receiving fertilizer, and the emission factors used to derive emission estimates. Uncertain ty was calculated according to a modified IPCC Tier 1 methodology. The 95 percent confidence in terval of the IPCC default emission f actor for synthetic fertilizer applied to soil, according to Chapter 4 of IPCC (2000), ranges from 0. 25 to 6 percent. While a Tier 1 analysis should be generated from a symmetrical distribution of uncertainty around the emission factor, an asymmetrical distribution was imposed here to account for the fact that the emission used was not the mean of the range given by IPCC. Therefore, an upper bound of 480 percent and a lower bound of 80 percent were assigned to the emission factor. The higher uncertainty percentage is shown below, but the lower bound reflects a truncated distribution. The uncertainties in the area of fo rested land receiving fertilizer and fertilizati on rates were conservatively estimated to be ±54 percent (Binkley 2004). The resu lts of the Tier 1 quantitative uncertain ty analysis are summarized in Table 7-10. N 2 O fluxes from soils were estimated to be between 0.01 and 2.3 Tg CO 2 Eq. at a 95 percent confidence level. This indicates a range of 96 percent below a nd 483 percent above the 2003 emission estimate of 0.4 Tg CO 2 Eq.

Table 7-10: Tier 1 Quantitative Uncertainty Estimates of N 2 O Fluxes from Forest Soils (Tg CO 2 Eq. and Percent)

IPCC Source Category Gas Year 2003 Emissions (Tg CO 2 Eq.) Uncertainty (%) Uncertainty Range Relative to 2003 Emission Estimate (Tg CO 2 Eq.)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 241 Lower Bound Upper Bound Forests Remaining

Forests: N 2 O Fluxes from Soils N 2 O 0.4 96 to 483% 0.01 2.3

Recalculations Discussion
The current Inventory reports N 2 O emissions from soils in forested areas sepa rately for the first time. In previous Inventories, N 2 O emissions from this source were implicitly included with N 2 O emissions from agricultural soils. The net effect of separating forest so ils from agricultural soils for the current Inventory is to reduce emissions reported from the agricultural sector by a very small am ount. However, because the methods for reporting that source have changed significantly this year, it is impossible to isolate the magnitude of change caused by this recalculation alone on the overall differences in N 2 O emissions from agricultural soils. The 2003 direct emission estimate for N 2 O from forest soils amounts to an offset of total forest carbon sequestration of approximately 0.5 percent (including standing forests and wood products).



### 7.2. Land Converted to Forest Land (Source Category 5A2)

Land-use change is constantly occurring, and areas unde r a number of differing land use types are converted to forest each year, just as forest lands are converted to other uses. However, the magnitude of these changes is not currently known. Given the paucity of available land us e information relevant to this particular IPCC source category, it is not possible to quantify CO 2 or N 2 O fluxes from land converted to forest land at this time.



### 7.3. Croplands Remaining Croplands Changes in Agricultural Soil Carbon Stocks (IPCC Source Category 5B1)

Soils contain both organic and inorganic forms of carbon (C) that contribute to the total soil carbon stock. It is the organic soil carbon (SOC) stocks in mineral and organic soils that may respond to management practices by producing or sequestering greenhouse gases. The IPCC methodology for estimating impacts of agriculturalpractices on soil C stocks (IPCC/UNEP/OECD/IEA 1997) is divided into three categories of land-use/landmanagement activities: 1) agricultural land-use and land-management activities on mineral soils; 2) agricultural land-use and land-management activities on organic soils; and 3) liming of soils. Nitrous oxide emissions from agricultural soils are presented within the Agriculture sector. Mineral soils contain comparatively low amounts of organic C, much of which is concentrated near the soil surface. Typical well-drained mineral surface so ils contain from 1 to 6 percent or ganic C (by weight), although some mineral soils that experience long-term saturation during the year may contain significantly more C (NRCS 1999). Mineral subsoils contain even lower amounts of orga nic C (NRCS 1999, Brady and Weil 1999). When mineral soils undergo conversion from their native state to agricultural use, as much as half the SOC can be lost to the atmosphere. The rate and ultimate magnitude of C lo ss will depend on native vegeta tion, conversion method and subsequent management practices, climate, and soil type. In the tropics, 40 to 60 percent of the C loss generally occurs within the first 10 years following conversion; after that, C stocks continue to decline but at a much slower rate. In temperate regions, C loss can continue for several decades. Eventually , the soil will reach a new equilibrium that reflects a balance between C accumulation from plant bioma ss and C loss through oxidation. Any changes in land-use or management practices that resu lt in increased organic inputs or decreased oxidation of organic C (e.g., improved crop rotations, cover crops, a pplication of organic amendments and manure, and reduction or elimination of tillage) will result in a net accumulation of SOC until a new equilibrium is achieved. Organic soils, also referred to as histosols, include all so ils with more than 12 to 20 percent organic C by weight, depending on clay content (NRCS 1999, Brady and Weil 1999). The organic layer of these soils is also typically extremely deep. Organic soils form under waterlogged conditions, in which minimal decomposition of plant residue occurs. When organic soils are cultivated, they are first drained which, together with tilling or mixing of the soil, aerates the soil, a nd thereby accelerates the rate of decomposition and CO 2 generation. Because of the depth and richness of the organic layers, C loss from cultivated organic soils can continue over long periods of time.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 242 When organic soils are disturbed for cultivation purposes, which invariably include drainage, the rate at which organic matter decomposes and CO 2 emissions are generated, is determined primarily by climate, composition (i.e., decomposability) of the organic matter, and the specific land- use practices undertaken. The use of organic soils for annual crop production results in greater C loss than conversi on to pasture or forests, due to deeper drainage and more intensive management practices (Armentano and Verhoeven 1990, as cited in IPCC/UNEP/OECD/IEA 1997).

The last category of the IPCC methodology addresses emissions from lime (in the form of crushed limestone (CaCO 3 )) and dolomite (CaMg(CO 3 ) 2 ) additions to agricultural soils. Lime and dolomite are added by land managers to ameliorate acidification. When these compounds come in contact with acid soils, they degrade, thereby generating CO 2 . Complete degradation of applied limestone and dol omite could take several years, but it could also take significantly less time, depending on the soil conditions and the type of mineral applied.

The estimates in this section include management impact s on mineral and organic soil C stocks for croplands and grasslands. Due to limited data availability, it is impossible to differentiate between the stock changes resulting from management practices on croplands or grasslands a nd those resulting from conversions between the two (i.e., statistics have been developed in a manner that only net ch anges in conversions are determined with no tracking of the total amount of land converted between cropland and grassland uses).

Total SOC stock depends on the balance between inputs of or ganic material (e.g., decayed plant matter, roots, and organic amendments such as manure and crop residues) and loss of C through decomposition. The quantity and quality of organic matter inputs and thei r rate of decomposition are determined by the combined interaction of climate, soil properties, and land use. Agricultural practices such as clearing, drainage, tillage, planting, grazing, crop residue management, fertilization, and flooding, can modify both organic matter input s and decomposition, and thereby result in a net flux of C to or from soils.

Of the three activities (those associated with mineral soils, organic soils, and liming of soils) land use and management of mineral soils was the most important component of total flux during the 1990 through 2003 period. C sequestration in mineral soils in 2003 was estimated to be approximately 51.7 Tg CO 2 Eq. (14 Tg C), while emissions from organic soils were estimated to be 35.6 Tg CO 2 Eq. (10 Tg C), and emissions from the practice of liming were estimated at 9.5 Tg CO 2 Eq. (3 Tg C). Together, the three activities accounted for net sequestration of approximately 6.6 Tg CO 2 Eq. (2 Tg C) in 2003. Total annual net CO 2 flux was negative (i.e., net sequestration occurred) each year over the inventory period, although the net C storage in so ils did decline by 18 percent between 1990 and 2003. Net sequestration was largely due to a nnual cropland enrolled in the Conservation Reserve Program, cropland converted to permanent pastures a nd hay production, a reduction in the frequency of summerfallow use in semi-arid areas, and some increase in the adoption of conservation tillage (i.e., reduced and no till practices). The decline in net sequestration was attribut ed to two management practices. First, the amount of organic soils that were drained for agricultural production increased during the time period, thus leading to higher emissions. Second, manure production declined over the inventory period, particularly during the last few years, and this decline reduced the amount of crop and grazing la nds receiving organic amendmen ts, and thus there was a small decline in C sequestration attributed to this activity.

The spatial variability in annual CO 2 flux for mineral and organic soils is displayed in Figure 7-4 through Figure 7-7. The highest rates of sequestration occur mostly in th e southern and northern Great Plains, southern portions of the corn-belt in the Midwest, and the lower Mississippi River Valley. Sequestration rates are also relatively high in the southeastern United States. These regions eith er have high Conservation Reserve Program enrollment (particularly the Great Plains region), a nd/or have adopted conserva tion tillage at a higher rate than other regions of the country. The greatest organic soil emission rates are from drained peatlands along the southeastern coastal region, in the northeast central United States surrounding the Great Lakes, and along the central and northern portions of the west coast.

Table 7-11: Net CO 2 Flux from Agricultural Soils (Tg CO 2 Eq.) Soil Type 1990 1997 1998 1999 2000 2001 2002 2003 Mineral Soils (52.4) (51.7) (49.5) (48.9) (50.0) (51.6) (51.9) (51.7) Organic Soils 34.8 35.6 35.6 35.6 35.6 35.6 35.6 35.6 Liming of Soils 9.5 8.7 9.6 9.1 8.8 9.0 10.1 9.5Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 243 Total Net Flux (8.1) (7.4) (4.3) (4.3) (5.7) (7.1) (6.2) (6.6) Note: Parentheses indicate net se questration. Shaded areas indicate values ba sed on a combination of historical data and projections. All other values are based on historical data only. Estimates include the change in C storage resulting from the annual application of sewage sludge and th e change in manure amendments or Cons ervation Reserve Program enrollment after 1997.

Table 7-12: Net Carbon Flux from Agricultural Soils (Tg C) Soil Type 1990 1997 1998 1999 2000 2001 2002 2003 Mineral Soils (14.3) (14.1) (13.5) (13.3) (13.6) (14.1) (14.1) (14.1) Organic Soils 9.5 9.7 9.7 9.7 9.7 9.7 9.7 9.7 Liming of Soils 2.6 2.4 2.6 2.5 2.4 2.4 2.8 2.6 Total Net Flux (2.2) (2.0) (1.2) (1.2) (1.5) (1.9) (1.7) (1.8) Note: Parentheses indicate net se questration. Shaded areas indicate values ba sed on a combination of historical data and projections. All other values are based on historical data only. Estimates include the change in C storage resulting from the annual application of sewage sludge and th e change in manure amendments or Cons ervation Reserve Program enrollment after 1997.

Figure 7-4 

### : Net Annual CO 2 Flux, per Hectare, From Mineral Soils Under Agricultural Management, 1990-1992

Figure 7-5 

### : Net Annual CO 2 Flux, per Hectare, From Mineral Soils Under Agricultural Management, 1993-2003

Figure 7-6 

### : Net Annual CO 2 Flux, per Hectare, From Organic Soils Under Agricultural Management, 1990-1992

Figure 7-7 

### : Net Annual CO 2 Flux, per Hectare, From Organic Soils Under Agricultural Management, 1993-2003

The flux estimates presented here are restricted to CO 2 fluxes associated with the use and management of agricultural soils. Agricultural soils are also important sources of other greenhouse gases, particularly N 2 O from application of fertilizers, manure, and crop residues and from cultivation of legumes, as well as methane (CH 4 ) from flooded rice cultivation. These emissions ar e accounted for under the Agriculture sector. 5


### Methodology
The methodologies used to calculate net CO 2 flux from use and management of mineral and organic soils and from liming follow the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997, Ogle et al. 2002, Ogle et al. 2003), except where noted below. Additional details on the methodology and data us ed to estimate flux from mineral and organic soils are described in Annex 3.13.

Mineral and Organic Soils

Mineral SOC stocks were estimated for 1982, 1992, and 1997, as well as CO 2 emissions from organic soils, for the conterminous United States and Hawaii using U.S. data on climate, soil types, land use and land management activity data, reference C stocks (for agricultural soils rather than native soils) and field studies addressing management effects on SOC storage. National-scale da ta on land-use and management changes over time were obtained from the 1997 National Resources Inventory (USDA-NRCS 2000). The 1997 National Resources Inventory provides land use/management data and soils info rmation for more than 400,000 locations in U.S. agricultural lands. Two other sources were used to supplement the land-use information from the 1997 National

5 Nitrous oxide emissions from agricultura l soils and methane emissions from rice fi elds are addressed under the Agricultural Soil Management and Rice Cultivation sections, respectively, of the Agriculture sector.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 244 Resources Inventory . The Conservation Technology Information Center (CTIC 1998) provided data on tillage activity, with adjustments for long- term adoption of no-till agriculture (Towery 2001), and Euliss and Gleason (2002) provided activity data on wetland restoration of Conservation Reserve Program Lands. Manure N production was derived from USDA livestock populati on data (USDA 1994a,b; 1995a ,b; 1998a,b; 1999a-e; 2000ag; 2001a-f; 2002a-f; 2003a-f), the FAOSTAT database (FAO 2003), and Lange (2000). Manure management information was obtained from Poe et al. (1999), Safl ey et al. (1992), and personal communications with agricultural experts (Anderson 2000, Deal 2000, Johnson 2000, Miller 2000, Milton 2000, Stettler 2000, Sweeten 2000, Wright 2000). Livestock weight data were obt ained from Safley (2000), USDA (1996, 1998c), and ASAE (1999); daily rates of N excretion from ASAE (1999) a nd USDA (1996); and information about the fraction of poultry litter used as a feed suppl ement from Carpenter (1992).

For estimating the emissions from both mineral and organi c soils, Major Land Resource Areas were used as the base spatial unit for mapping climate regions in the Unite d States. Each Major Land Resource Area represents a geographic unit with relatively similar soils, climate, water resources, and land uses (NRCS 1981). 6 Major Land Resource Areas were classified into climate zones accord ing to the IPCC categories using the Parameter-Evaluation Regressions on Independent Slopes Model (PRISM) c limate-mapping program of Daly et al. (1994).

For mineral soils, reference C stocks were estimated using the National Soil Survey Characterization Database (NRCS 1997) with cultivated cropland as the reference cond ition, rather than native ve getation as used in the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). Changing th e reference condition was necessary because soil measurements under agricultural management are much more common and easily identified in the National Soil Survey Characterization Database (NRCS 1997) than those which are not considered cultivated cropland. U.S. management factors 7 were derived from published literature to determine the impact of management practices on SOC storage, including changes in tillage, cr opping rotations and intensif ication, land-use change between cultivated and uncultivated cond itions, as well as C loss rates associat ed with drainage of organic soils under agricultural management (Ogle et al. 2003, Ogle et al. in review). U.S. management factors associated with organic matter amendments and improving grazing lands were not estimated becau se of few studies analyzing those impacts. Instead, IPCC factors from LULUCF Good Practice Guidance (IPCC 2003) formed the basis for quantifying the effect of those activities. Euliss and Gleas on (2002) provided the data for computing the change in SOC storage resulting from restoration of Conservation Reserve Program lands (Olness et al. in press, Euliss et al. in prep).

Combining information from these data sources, SOC stoc ks for mineral soils were estimated 50,000 times for 1982, 1992, and 1997, using a Monte Carl o simulation approach and the proba bility density functions for U.S.- specific management factors, reference C stocks, and land-use activity data (Ogle et al. 2003, Ogle et al. 2002). The annual C flux for 1990 through 1992 was determined by calcu lating the annual change in stocks between 1982 and 1992; annual C flux for 1993 through 2003 was determined by calculating the annual change in stocks between 1992 and 1997. Annual C flux estimates for mineral soils between 1990 and 2003 were adjusted to account for additional C sequestration from sewage sl udge applications, as well as gains or losses in C sequestration after 1997 due to changes in Conservation Reserve Program enrollment and manure N production. For the entire inventory period, the amount of land amended with sewage sludge was estimated from N application data from the Soil Management section of the Agriculture chapter of this volume, and an assumed application rate derived from Kellogg et al. (2000). To estimate the impact of manure amendments after 1997, the change in manure N production was determined relative to the amount produced in 1997, and then similar to sewage sludge calculations, the production values were multiplied by the assumed applica tion rate to determine the change in land area that was amended with manure. Carbon storage rate was estimated at 0.22 metric tons C per hectare per year for both the manure and sewage sludge amendments. To estimate the impact of enrollment in the Conservation Reserve

6 The polygons displayed in Figure 6-5 through Figure 6-8 are the Major Land Resource Areas. 7 Management factors have been derived from published litera ture to reflect changes in tillage, cropping rotations and intensification, land-use change between cultivated and uncultivated conditions, as well as drainage of organic soils.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 245 Program after 1997, the change in enrollment acreage relative to 1997 was derived based on Barbarika (2004), and the differences in mineral soil areas were multiplied by 0.5 metric tons C per hectare per year.

Annual C emission estimates from organic so ils between 1990 and 2002 were derived using Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997), except that U.S.-specific C loss rates were used in the calculations rather than default IPCC rates (Ogle et al. 2003). Similar to mineral soils, the final estimates included a measure of uncertainty as determined from the Monte Carlo simulation with 50,000 iterations. Emissions were based on the 1992 and 1997 land areas from the 1997 National Resources Inventory (USDA-NRCS 2000). The annual flux estimated for 1992 was applied to 1990 through 1992, and the annual flux estimated for 1997 was applied to 1993 through 2003.

Liming
Carbon dioxide emissions from degradation of limestone a nd dolomite applied to agricultural soils were calculated by multiplying the annual amounts of limestone and dolomite applied (see Table 7-13) by CO 2 emission factors (0.120 metric ton C/metric ton limestone, 0.130 metric ton C/metric ton dolomite) (IPCC 2003). 8 These emission factors are based on the assumption that all of the C in these materials evolves as CO 2 in the same year in which the minerals are applied. The annual application rates of limestone and dolomite were derived from estimates and industry statistics provided in the Minerals Yearbook and Mineral Industry Surveys (Tepordei 1993, 1994, 1995, 1996, 1997, 1998, 1999, 2000, 2001, 2002, 2003, 2004; USGS 2002, 2003, 2004). To develop these data, USGS (U.S. Bureau of Mines prior to 1997) obtained producti on and use information by surveying crushed stone manufacturers. Because some manufacturer s were reluctant to provide informa tion, the estimates of total crushed limestone and dolomite production and us e were divided into three components: 1) production by end-use, as reported by manufacturers (i.e., “specified” production); 2) production reported by manufacturers without end-uses specified (i.e., “unspecified” producti on); and 3) estimated additional pr oduction by manufactur ers who did not respond to the survey (i.e., “estimated” production).

To estimate the “unspecified” and “estimated” amounts of crushed limestone and dolomite applied to agricultural soils, the fractions of “unspecified” and “estimated” producti on that were applied to agricultural soils in a specific year were assumed to be equal to the fraction of “specifi ed” production that was applied to agricultural soils in that same year. In addition, data were not available fo r 1990, 1992, and 2003 on the fractions of total crushed stone production that were limestone and dolomite, and on the fr actions of limestone and dolomite production that were applied to soils. To estimate the 1990 and 1992 data, a set of average fractions were calculated using the 1991 and 1993 data. These average fractions were applied to the qua ntity of "total crushed stone produced or used" reported for 1990 and 1992 in the 1994 Minerals Yearbook (Tepordei 1996). To estimate 2003 data, the previous year’s fractions were applied to a 2003 estimate of total crushed stone presented in the USGS Mineral Industry Surveys: Crushed Stone and Sand and Gravel in the First Quarter of 2004 (USGS 2004).

The primary source for limestone and dolomite activity data is the Minerals Yearbook , published by the Bureau of Mines through 1994 and by the U.S. Geological Survey from 1995 to the present. In 1994, the “Crushed Stone” chapter in Minerals Yearbook began rounding (to the nearest thousand) quantities for total crushed stone produced or used. It then reported revised (rounded) quantities for each of the years from 1990 to 1993. In order to minimize the inconsistencies in the activity data, these revised produc tion numbers have been used in all of the subsequent calculations.

Table 7-13: Quantities of Applied Minerals (Thousand Metric Tons) Mineral 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

8 T he default emission factor for dolomite provided in the Workbook volume of the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) and the Good Practice Guidance for Land Use, Land-Use Change, and Forestry (IPCC 2003) is incorrect. The value provided is 0.122 metric ton carbon/metr ic ton of dolomite; the correct value is 0.130 metric ton carbon/metric ton of dolomite.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 246 Limestone 19,012 20,312 17,984 15,609 16,686 17,297 17,479 16,539 14,882 16,894 15,863 16,097 20,449 19,163 D Dolomite 2,360 2,618 2,232 1,740 2,264 2,769 2,499 2,989 6,389 3,420 3,812 3,951 2,353 2,205



### Uncertainty
Uncertainties for mineral and organic soils were quan tified using a Monte Carlo Approach by constructing probability distribution func tions (PDF) for inputs to the IPCC equa tions, including management factors, C emission rates for organic soils, and land use and management activity data, and then simulating a range of values using the Monte Carlo framework (Ogle et al. 2003, Annex 3.13). Uncertainty estimates do not include sewage sludge impacts on SOC storage for any year in the inventory period, or contributions of changing manure management and enrollment in the Conservation Reserve Pr ogram after 1997. PDFs for management factors were derived from a synthesis of 91 published studies, which a ddressed the impact of management on SOC storage. Uncertainties in land use and management activity data were also derived from a statistical analysis. The National Resources Inventory (NRI) has a two-stage sampling desi gn that allowed PDFs to be constructed assuming a multivariate normal distribution accounting for dependencies in activity data. PDFs for the tillage activity data, as provided by the Conservation Technology and Informa tion Center, were constructed on a bivariate normal distribution with a log-ratio scale, accounting for th e negative dependence among the proportions of land under conventional and conservation tillage practices. PDFs for the crop and grazing land area receiving manure amendments were based on the data sources given for manure amendments in the methodology section, and a statistical relationship between pr oduction and the amount of land area th at is amended according to manure management information derived from the USDA Census of Agriculture (Edmonds et al. 2003). Lastly, enrollment in wetland restoration programs was estimated from contract agreements, but due to a lack of information, PDFs were constructed assuming a nominal ± 50 percent uncertainty range.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 7-14. CO 2 flux from mineral and organic agricultural soil carbon stocks in 2003 was estimated to be between -40.0 and +5.9 Tg CO 2 Eq. at a 95 percent confidence level (or 19 of 20 Monte Carlo Stochastic Simulations). This indicates a range of 148 percent below to 136 percent above the 2003 flux estimate of -16.1 Tg CO 2 Eq.

Table 7-14: Tier 2 Quantitative Uncertainty Estimates for CO 2 Flux from Mineral and Organic Agricultural Soil Carbon Stocks (Tg CO 2 Eq. and Percent) Uncertainty Range Relative to Flux Estimate a (Tg CO 2 Eq.) (%)

Source Gas 2003 Flux Estimate (Tg CO 2 Eq.) Lower Bound Upper Bound Lower Bound Upper Bound Mineral and Organic Soil Uncertainty CO 2 (16.1) (40.0) 5.9 -148% +136%

a Includes mineral and organic soils only; estimates do not incl ude the change in C storage resulting from the annual applicatio n of sewage sludge, or the change in manure amendments or Conservation Reserve Pr ogram enrollment after 1997. b Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.

The time-series calculations were consis tent for each reporting year of the i nventory in terms of methodology, with the only difference in reported values stemming from the changes in land use and management activities across U.S. agricultural lands. In addition, the same management f actors (i.e., emission factors) were used each year for calculating the impact of land use and management on SOC stocks. There is no evidence that changing management practices has a quantitatively different impact on SOC stocks over the inventory period. For example, changing from conventional to no-till mana gement in 1990 is assumed to have the same impact on soil C stocks over the course of this first year as it is over the course of each year in the 20 year period following the management change.

Although the mineral and organic soil estimates have been improved during the last two years using a Monte Carlo approach with the incorporation of U.S.-specific reference C stocks management factor values, and a more comprehensive accounting of manure amendment impacts on SOC storage, several limitations remain in the analysis. First, minimal data exist on where and how mu ch sewage sludge has been applied to U.S. agriculturalInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 247 lands and the accounting of this activity appears to be much more difficult than the related-activity of using manure to amend agricultural soils. Consequently, uncertainties ha ve not been estimated for the change in SOC storage resulting from sludge applications. Second, due to the IPCC requirement that inventories include all land areas that are potentially subject to land-use change, the 1997 National Resources Inventory dataset includes some points designated as non-agricultural land-uses if the points we re once categorized as agricultural land use and their designation changed during the period from 1992 to 1997. Th e non-agricultural land uses are urban, water, and miscellaneous non-cropland (e.g., roads and barren areas). The impact on SOC storage that results from converting cropland to non-agricultural uses is not well-understood, and therefore, those points were not included in the calculations for mineral soils (emissions from organic soils, however, were computed for those points in the years that they were designated as an agricultural use). Third, the current estimates may underestimate losses of C from organic soils because the 1997 National Resources Inventory was not designed as a soil survey and organic soils frequently occur as relatively small inclusions within majo r soil types. Lastly, this methodology does not take into account changes in SOC stocks due to pre-1982 land use and land-use change.

Uncertainties in the estimates of emissions from liming result from both the methodology and the activity data. The IPCC method assumes that all inorganic C in the applied minerals evolves to CO 2 , and that this degradation occurs in the same year that the minerals are applied. Howeve r, recent research has shown th at liming can either be a C source or a sink, depending upon weatheri ng reactions, which are pH dependent (Hamilton et al. 2002). Moreover, it can take several years for agriculturally applied limestone and dolomite to degrade completely. However, application rates are fairly constant over the entire time series, so this latter assumption may not contribute significantly to overall uncertainty.

There are several sources of uncertainty in the limestone and dolomite activity data. When reporting data to the USGS (or U.S. Bureau of Mines), some producers do not distinguish between limestone and dolomite. In these cases, data are reported as limestone, so this reporting could lead to an overestimation of limestone and an underestimation of dolomite. In addition, the total quantity of crushed stone listed each year in the Minerals Yearbook excludes American Samoa, Guam, Puerto Rico, and the U.S. Virgin Islands.

Uncertainty regarding lime applications was estimated at 15 percent (Tepordei 2003). While IPCC provides no uncertainty values for the emission factor from this subsource, there is uncertainty stemming primarily from the inherent assumption that all applications are converted to CO 2 within the year of application. In fact, limestone may persist in the soil for 3 to 4 years following application (Nardozzi 2004), indicating that emissions may continue throughout that period of time. Taking th is into account, the resulting uncertainty in the emission factor is estimated to be 75 percent. The preliminary results of the Tier 1 quantitative uncertainty analysis are summarized in Table 7-15. Liming of agricultural soils CO 2 emissions in 2003 were estimated to be between 2.2 and 10.9 Tg CO 2 Eq. at the 95 percent confidence level. This indicates a range of 76 percent above and below the 2003 emission estimate of 9.5 Tg CO 2 Eq.

Table 7-15: Tier 1 Quantitative Uncertainty Estimates for CO 2 Emissions from Liming of Agricultural Soils (Tg CO 2 Eq. and Percent)

IPCC Source Category Gas Year 2003 Emissions (Tg CO 2 Eq.) Uncertainty (%) Uncertainty Range Relative to 2003 Emission Estimate (Tg CO 2 Eq.)

Lower Bound Upper Bound * Liming of Agricultural Soils CO 2 9.5 76% 2.2 10.9 * Because the current Inventory methodology assumes that all of the limestone and dolomite decomposes in the year of application, the emission factors could be significantly lower, but could not be highe r. Consequently, the emissions estimate may only be higher due to the uncertainty in the application da ta. Therefore, while normally, Tier 1 analyses generate a symmetrical distribution of uncertainty around the emission estimat e, an asymmetrical distribution was necessarily imposed here

. It is not currently possible to combine the results of this Tier 1 uncertainty analysis with those of the Tier 2 uncertainty analyses for CO 2 fluxes from mineral soils and histosols.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 248 

### Recalculations Discussion
The estimates of changes in agricultural SOC stocks have been modified in several ways. First, uncertainty in manure amendments was evaluated and incorporated into the general inventory calculations for agricultural soil C, using the Tier 2 IPCC methodology (IPCC/UNEP/OECD/IEA 1997). In previous Inventories, the change in SOC storage attributed to organic amendments was estimated as a post-analysis calculation using a simplistic activitybased approach. Incorporating amendment data into the IP CC analysis led to a decline in the estimated change for SOC storage attributed to manure management, relative to previous years. The activ ity-based approach assumed that all of the applied manure was l eading to an increase in SOC, while the IPCC method only accounted for the changes in organic amendments from the baseline year to estimate the impact on SOC storage. In general, the IPCC approach assumes that impacts on SOC storage are manifested in the first 20 years following a management change, and consequently, this method does not account for smaller re sidual changes in SOC storag e that can occur in later years. However, the activity-based a pproach also has limitations because it does not account for the possibility that a portion of the manure applied in a year is simply maintaining SOC storage from past applications. In fact, the production of manure has not changed to a large extent since 1982 according to USDA statistics (see Annex 3.13), and, therefore, many of the current amendments are only serving the purpose of maintaining past storage. Hence, incorporating manure management into the IPCC calculations has produced a more conservative estimate by reducing the potential for over-estimating the impact of longer-term manure amendments, but also does not capture the residual change in SOC storage occurring after the first 20 years.

Two additional revisions have been incorporated into the analysis since the previous Inventory. As part of the revision, management factors provided in the IPCC LULUCF Good Practice Guidance (IPCC 2003) now form the basis to estimate management impacts for which U.S.-specific factors have not been derived (i.e., improving grazing lands and organic amendments). Previously, defaults factor values from the Revised 1996 IPCC Guidelines formed the basis for these calculations using the IPCC method, but greater disaggregation of management factors by climate in the IPCC LULUCF Good Practice Guidance was assumed to produce more realistic estimates of those management impacts, compared to the single global values provided in the Revised 1996 IPCC Guidelines

. Lastly, emissions from organic soils have changed slightly from those reported in the previous inventory, as a result of revising the land area included in the emission calculation. In previous years, lands that were converted between agricultural and non-agricultural uses (i.e., urban, water, and miscellaneous non-cropland) were not included in the estimation of emissions from organic soils, and this led to a slight under-estimation of emissions from organic soils. Specifically, a small amount of land area under agricultural management in 1992 or 1997 was not included in the emission calculation because it had been converted from a non-agricultural use.

Estimates of CO 2 emissions from agricultural soil management have been revised due to methodological and historical data changes in the calculations of N from livestock that is applied to soils. These changes include corrections to: the typical animal ma ss value for beef cows and calves; the accounting of sheep in New England states; state broiler populations; and updated NASS animal population estimates for the years 1998 through 2001 (NASS 2000). Additionally, the factor for converting short tons to metric t ons was revised to include another significant digit, and the percent residue applied for rice in the year 2001 was corrected. In combination, these changes resulted in a minor effect on the agricultural soil C estimates with a reduction in the CO 2 sink by less than 1 percent.

The quantity of applied minerals reported in the previous inventory for 2002 has been re vised. Consequently, the reported emissions resulting from liming in 2002 have also ch anged. In the previous inventory, to estimate 2002 data, the previous year’s fractions were applied to a 2002 estimate of total crushed stone presented in the USGS Mineral Industry Surveys: Crushed Stone and Sand and Gravel in the First Quarter of 2003 (USGS 2003). Since publication of the previous inventory, the Minerals Yearbook has published actual quantities of crushed stone sold or used by producers in the United States in 2002. These va lues have replaced those used in the previous inventory to calculate the quantity of minerals applied to soil and the emissions from liming.

Overall, these changes resulted in an average annual decrease of 14.2 Tg CO 2 Eq. (67 percent) in agricultural soil carbon stocks for the period 1990 through 2002.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 249 

### Planned Improvements

A major planned improvement is curren tly underway that will enhance reporti ng of changes in agricultural soil C stocks and deals with an alternative i nventory approach to better represent be tween-year variability in annual fluxes. This new annual activity-based inventory will use the Ce ntury ecosystem simulation m odel, which relies on actual climate, soil, and land use/management databases to estimate variation in fluxes. This inventory will provide a more robust accounting of C stock changes in U.S. agricultura l lands than the more simplistic IPCC soil C accounting approach. This approach is likely to be used in the future for reporting of land use and management impacts on agricultural soil C stocks, and therefore a short description of this method compared to the IPCC approach is provided.

The Century ecosystem model has been widely tested a nd found to be successful in simulating those processes affecting SOC storage (Metherell et al. 1993, Parton et al. 1994). Simulation modeling differs from the IPCC approach in that annual changes are computed dynamically as a function of inputs of C and N to soil (e.g., crop residues, manure) and C emissions from organic matter decomposition, which are governed by climate and soil factors as well as management practices. The model dis tinguishes between all major field crops (maize, wheat and other small grains, soybean, sorghum, cotton) as well as hay and pasture (grass, alfalfa, clover). Management variables include tillage, fertilization, irrigation, drainage, and manure addition.

Input data are largely derived from the same sources as the IPCC-based method (i.e., climate variables come from the Parameter-Evaluation Regressions on Independent Slopes Models (PRISM) database; crop rotation, irrigation and soil characteristics from the National Resources Inventory (NRI); and tillage data from the Conservation Technology Information Center (CTIC)). In addition, the Century an alysis uses detailed information on crop rotation-specific fertilization and tillage implements obtained from USDA’s Econom ic Research Service. The main difference between the methods is that the climate, soil, and management data serve as driving variables in the Century simulation, whereas in the IPCC approach these data are more highly aggregated and are used for classification purposes. In the Century-based analysis, land areas having less than 5 percent of total area in crop production are excluded and several less-dominant crops (e.g ., vegetables, sugar beets and sugar cane, potatoes, tobacco, orchards, and vineyards), for which the model has not yet been parameterized, are not included. Thus, the total area included in the Century an alysis (149 million hectares) will be smaller than the corresponding area of cropland (165 million hectares) included in the IPCC estimates.

Preliminary results using the Century model suggest (as with the IPCC model) that U.S. cropland mineral soils (excluding organic soils) are currently acting as a C sink. The Century model estimates that U.S. cropland soils sequestered an average of approximately 77 Tg CO 2 Eq. annually (21 Tg C/year) for 1992 through 1997. Organic soils (which contribute large C losses) have not yet been simulated by Century.

As with the IPCC method, increases in mineral SOC stocks in the Century analysis are associated with reduced tillage, Conservation Reserve Program lands, reduced bare fallow and some increase in hay area. However, the Century analysis also includes the effect of a long-term trend in increasing residue inputs due to higher productivity on cropland in general, contributing to increasing SOC stocks . Work is underway to refine model input data and to estimate uncertainty for the dynamic model approach.

Potential advantages of a dynamic simulation-based approach include the ability to use actual observed weather, observed annual crop yields, and more detailed soils and ma nagement information to drive the estimates of soil C change. This would facilitate annual estimates of SOC stock changes and CO 2 emissions from soils that would better reflect interannual variability in cropland production and weather in fluences on C cycle processes.



### 7.4. Lands Converted to Croplands (Source Category 5B2)

Land-use change is constantly occurring, and areas unde r a number of differing land use types are converted to croplands each year, just as croplands are converted to other uses. However, while the C stocks for Land Converted to Cropland are included in the Croplands Remaining Cropl ands section, it is not possible to sub-divide it and determine the magnitude of the change at this time. Additionally, given the lack of available land use informationInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 250 relevant to this particular IPCC source category, it is not possible to quantify the N 2 O flux from Lands Converted to Cropland at this time.



### 7.5. Settlements Remaining Settlements Changes in Yard Trimming and Food Scrap Carbon Stocks in Landfills (IPCC Source Category 5E1)

As is the case with carbon in landfilled forest products , carbon contained in landfille d yard trimmings and food scraps can be stored for very long periods. In the Unite d States, yard trimmings (i.e., grass clippings, leaves, and branches) and food scraps comprise a significant portion of the municipal waste stream, and a large fraction of the collected yard trimmings and food scra ps are discarded in landfills. Howeve r, both the amount of yard trimmings and food scraps collected annually and th e fraction that is landfilled have dec lined over the last decade. In 1990, nearly 51 million metric tons (wet wei ght) of yard trimmings and food scraps were generated (i.e ., put at the curb for collection or taken to disposal or composting facilities) (EPA 2003). Since then, programs banning or discouraging disposal have led to an increase in back yard composting and the use of mulching mowers, and a consequent 20 percent decrease in the amount of yard trimmings collected. At the same time, a dramatic increase in the number of municipal composting facilities has reduced the proportion of collected yard trimmings that are discarded in landfills—from 72 percent in 1990 to 34 percen t in 2003. There is cons iderably less centralized composting of food scraps; generation has grown by 26 percent since 1990, though the proportion of food scraps discarded in landfills has decreased slightly from 81 percen t in 1990 to 77 percent in 2003. Overall, there has been a decrease in the yard trimmings and food scrap landfill dispos al rate, which has resulted in a decrease in the rate of landfill carbon storage to 10.1 Tg CO 2 Eq. in 2003 from 26.0 Tg CO 2 Eq. in 1990 (Table 7-16 and Table 7-17).

Table 7-16: Net Changes in Yard Trimmi ng and Food Scrap Stocks in Landfills (Tg CO 2 Eq.) Carbon Pool 1990 1996 1997 1998 1999 2000 2001 2002 2003 Yard Trimmings (23.2) (11.3) (10.4) (9.6) (8.5) (7.2) (7.4) (7.5) (7.5)

Grass (2.5) (1.0) (0.9) (0.8) (0.7) (0.6) (0.7) (0.7) (0.7) Leaves (11.2) (5.9) (5.4) (5.1) (4.5) (4.0) (4.0) (4.0) (4.0) Branches (9.6) (4.4) (4.0) (3.7) (3.2) (2.6) (2.7) (2.7) (2.8) Food Scraps (2.8) (2.2) (2.6) (2.9) (2.9) (3.0) (2.9) (2.7) (2.6) Total Net Flux (26.0) (13.5) (12.9) (12.5) (11.4) (10.2) (10.3) (10.2) (10.1) Note: Totals may not sum due to independent rounding.

Table 7-17: Net Changes in Yard Trimming and Food Scrap Stocks in Landfills (Tg C) Carbon Pool 1990 1996 1997 1998 1999 2000 2001 2002 2003 Yard Trimmings (6.3) (3.1) (2.8) (2.6) (2.3) (2.0) (2.0) (2.0) (2.0)

Grass (0.7) (0.3) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) (0.2) Leaves (3.0) (1.6) (1.5) (1.4) (1.2) (1.1) (1.1) (1.1) (1.1) Branches (2.6) (1.2) (1.1) (1.0) (0.9) (0.7) (0.7) (0.7) (0.8) Food Scraps (0.8) (0.6) (0.7) (0.8) (0.8) (0.8) (0.8) (0.7) (0.7) Total Net Flux (7.1) (3.7) (3.5) (3.4) (3.1) (2.8) (2.8) (2.8) (2.7) Note: Totals may not sum due to independent rounding.

Methodology
Estimates of net carbon flux resulting from landfilled yard tr immings and food scraps were developed by estimating the change in landfilled carbon stocks between inventory years. Carbon stock estim ates were calculated by determining the mass of landfilled carbon resulting from yard trimmings or food scraps di scarded in a given year; adding the accumulated landfilled carbon from previous year s; and subtracting the por tion of carbon landfilled in previous years that decomposed.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 251 To determine the total landfilled carbon stocks for a given year, the following were estim ated: 1) the composition of the yard trimmings, 2) the mass of yard trimmings and food scraps discarded in landfills, 3) the carbon storage factor of the landfilled yard trimmings and food scraps, and 4) the rate of d ecomposition of the degradable carbon. The composition of yard trimmings was assumed to be 30 percent grass clippings, 40 percent leaves, and 30 percent branches on a wet weight basis (Osh ins and Block 2000). The yard tri mmings were subdivided because each component has its own unique carbon storag e factor and rate of decomposition. The mass of yard trimmings and food scraps disposed of in landfills was estimated by mu ltiplying the quantity of yard trimmings and food scraps discarded by the proportion of discards managed in landfills. Data on discards (i.e., the amount generated minus the amount diverted to centralized compos ting facilities) for both yard trimmings and food scraps were taken primarily from Municipal Solid Waste in the United States: 2001 Facts and Figures (EPA 2003). That report provides data for 1960, 1970, 1980, 1990, 1995, and 1999 through 2001. To provide data for some of the missing years in the 1990 through 1999 period, two earlier reports were used ( Characterization of Municipal Solid Waste in the United States: 1998 Update (EPA 1999), and Municipal Solid Waste in the United States: 2000 Facts and Figures (EPA 2002)). Remaining years in the time series for which data were not provided were estimated using linear interpolation, except for 2002 and 2003, which was assumed to have the same discards as 2001. These reports do not subdivide discards of individual materials into vol umes landfilled and combusted, although they provide an estimate of the proportion of overall wastestream discards managed in landfills and co mbustors (i.e., ranging from 81 percent and 19 percent respectively in 1990, to 79 percent and 21 percent in 2001).

The amount of carbon disposed of in landfills each year, st arting in 1960, was estimated by converting the discarded landfilled yard trimmings and food scraps from a wet weight to a dry weight basis, and then multiplying by the initial (i.e., pre-decomposition) carbon content (as a fraction of dry weight). The dry we ight of landfilled material was calculated using dry weight to wet weight ratio s (Tchobanoglous et al. 1993 cited by Barlaz 1998) and the initial carbon contents were determined by Barlaz (1998) (Table 7-18).

The amount of carbon remaining in the landfill for each subs equent year was tracked based on a simple model of carbon fate. According to Barlaz (1998), a portion of th e initial carbon resists decomposition and is essentially persistent in the landfill environment; the modeling appr oach applied here builds on his findings. Barlaz (1998) conducted a series of experiments designed to measure bi odegradation of yard trimmings, food scraps, and other materials, in conditions designed to promote decomposition (i.e., by providing ample moisture and nutrients). After measuring the initial carbon content, the materials were pl aced in sealed containers along with a “seed” containing methanogenic microbes from a landfill. Once decomposition was complete, the yard trimmings and food scraps were re-analyzed for carbon content. The mass of carbon re maining, divided by the original dry weight of the material, was reported as the carbon storage factor (Table 7-18).

For purposes of simulating U.S. landfill carbon flows, th e carbon storage factors are divided by the initial carbon content to determine the proportion of initial carbon that does not decompose. The remaining portion is assumed to degrade (and results in emissions of CH 4 and CO 2 ). For example, for branches Barlaz (1998) reported the carbon storage factor as 38 percent (of dry we ight), and the initial carbon content as 49 percent (of dry weight). Thus, the proportion of initial carbon that does not decompose is 77 percent (i.e., 0.38/0.49). The remaining 23 percent degrades.

The degradable portion of the carbon is assumed to decay according to first or der kinetics. Grass and food scraps are assumed to have a half-life of 5 years; leaves and branches are assumed to have a half-life of 20 years.

For each of the four materials (grass, leaves, branches, food scraps), the st ock of carbon in landfills for any given year is calculated according to the following formula:

LFC i,t = 

## Σ W i,n * (1 - MC i ) * ICC i * {[CSF i / ICC i ] + [(1 – (CSF i / ICC i )) * e -k*(t - n) ]}

n

where, t = the year for which carbon stocks are being estimated, LFC i,t = the stock of carbon in landfills in year t , for waste i (grass, leaves, branches, food scraps)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 252 W i,n = the mass of waste i disposed in landfills in year n , in units of wet weight n = the year in which the waste was disposed, where 1960 < n < t MC i = moisture content of waste i
, ICC i = the initial carbon content of waste i
, CSF i = the carbon storage factor of waste i
, e = the natural logarithm, and k = the first order rate constant for waste i , and is equal to 0.693 divided by the half-life for decomposition. For a given year t , the total stock of carbon in landfills (TLFC t ) is the sum of stocks across all four materials. The annual flux of carbon in landfills (F t ) for year t is calculated as the change in st ock compared to the preceding year:

F t

= TLFC t - TLFC t - 1
Thus, the carbon placed in a landfill in y ear n is tracked for each year t th rough the end of the inventory period (2003). For example, disposal of f ood scraps in 1960 resulted in depositing a bout 1,140,000 metric tons of carbon. Of this amount, 16 percent (180,000 metric tons) is persistent; the remaining 84 percent (960,000 metric tons) is degradable. By 1965, half of the degradable portion (480,000 metric tons) decomposes, leaving a total of 660,000 tonnes (the persistent portion, plus the remaining half of the degradable portion).

Continuing the example, by 2003, the total food scraps carbon originally disposed in 1960 had declined to 181,000 metric tons (i.e., virtually all of the degradable carbon had decomposed). By summing the carbon remaining from 1960 with the carbon remaining from food scraps disposed in subsequent years (1961 through 2003), the total landfill carbon from food scraps in 2003 was 29.3 million metric tons. This value is then added to the carbon stock from grass, leaves, and branches to calculate the total landfill carbon stoc k in 2003, yielding a value of 241.6 million metric tons (as shown in Table 7-19). In exactly the same way total net flux is calculated for forest carbon and harvested wood products, the total net flux of landfill carbon for yard trimmings a nd food scraps for a given year (Table 7-17) is the difference in the landfill carbon stock for a given year and the stock in the preceding year. For example, the net change in 2003 shown in Table 7-17 (2.7 Tg C) is equal to the stock in 2003 (241.6 Tg C) minus the stock in 2002 (238.9 Tg C).

When applying the carbon storage factor data reported by Barlaz (1998), an adjustment was made to the reported value for leaves, because the carbon st orage factor was higher than the in itial carbon content. This anomalous result, probably due to errors in the laboratory m easurements, was addressed by applying a mass balance calculation, and assuming that (a) the initial carbon cont ent was correctly measured, and (b) the carbon storage factor was incorrect. The same experiment measured not only the persistence of carbon (i.e., the carbon storage factor), but also the yield of methan e for each of the individual waste materi als (Eleazer et al. 1997). The anaerobic decomposition process results in release of equal molar volumes of CH 4 and CO 2 . Thus, to derive a more realistic estimate of the carbon storage factor fo r leaves, the carbon released in the form of methane during decomposition was multiplied by two (to include the loss of carbon through CO 2 , which is generated in approximately equal molar amounts as CH 4 ), and then subtracted from the initial carbon c ontent of the leaves. This estimate of carbon remaining was used to derive the carbon storage factor (0.46).

Table 7-18: Moisture Content (%), Carbon Storage Factor, Initial Carbon C ontent (%), Proportion of Initial Carbon Sequestered (%), and Half-Life (years) for Landfille d Yard Trimmings and Food Scraps in Landfills Yard Trimmings Food Scraps Variable Grass Leaves Branches Moisture Content (% H 2 O) 70 30 10 70 CSF (kg C sequestered / dry kg waste) 0.32 0.46 a 0.38 0.08 Initial Carbon Content (%) 45 49 49 51 Proportion of initial carbon sequestered (%) 71 94 77 16 Half-life (years) 5 20 20 5

a Adjusted using CH 4 yields in Eleazer et al. (1997).

Table 7-19: Carbon Stocks in Yard Tri mmings and Food Scraps in Landfills (Tg C)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 253 Carbon Pool 1990 1996 1997 1998 1999 2000 2001 2002 2003 Yard Trimmings 167.8 196.5 199.3 201.9 204.2 206.2 208.2 210.2 212.3

Grass 18.8 21.7 21.9 22.2 22.4 22.5 22.7 22.9 23.1 Leaves 78.7 92.9 94.3 95.7 97.0 98.0 99.1 100.2 101.3 Branches 70.3 81.9 83.0 84.0 84.9 85.6 86.4 87.1 87.9 Food Scraps 20.3 24.0 24.7 25.5 26.3 27.1 27.9 28.6 29.3 Total Carbon Stocks 188.1 220.5 224.0 227.4 230.5 233.3 236.1 238.9 241.6 Note: Totals may not sum due to independent rounding.

Uncertainty
The estimation of carbon storage in landfills is directly re lated to the following yard trimming and food scrap data and factors: disposal in landfills pe r year (tons of carbon), initial carbon cont ent, moisture content, decomposition rate (half-life), and proportion of carbon stored. The car bon storage landfill estimates are also a function of the composition of the yard trimmings (i.e. the proportions of grass, leaves and branches in the yard trimmings mixture). There are uncerta inties associated with each of these factors.

The uncertainty ranges were assigned ba sed on expert judgment and are assumed to be uniformly distributed around the inventory estimate (e.g., + 10 percent), except for the values for decomposition rate, proportion of carbon stored, and moisture content for branches.

The uncertainty ranges associated with the input variables for the proportion of grass and leaves in yard trimmings, as well as the initial carbon content and moisture content for grass, leaves, and food scraps (all expressed as percentages in the calculations for the inventory) were pl us or minus 10 percent. For the moisture content of branches (where the inventory estimate is 10 percent), the uncertainty range was assumed to be 5 to 30 percent.

The uncertainty ranges associated with the disposal of grass, leaves, branches, and food scraps were bound at 50 percent to 150 percent times the inventory estimates. The ha lf-life of grass and food scra ps were assumed to range from 1 to 20 years, and the half-lives of leaves and branch es were assumed to range from 5 to 30 years. Finally, the proportion of carbon stored in grass, leaves, branches, and food scraps was assumed to vary by the addition of 20 percent or subtraction of 10 percent from the best es timate, with an upper bound of 100 percent and a lower bound of 0 percent.

A Monte Carlo (Tier 2) uncertainty analysis was then applied to estimate the overall uncertainty of the sequestration estimate. The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 7-20

. Total yard trimmings and food scraps CO 2 flux in 2003 was estimated to be between -17.5 and -7.0 Tg CO 2 Eq. at a 95 percent confidence level (or 19 of 20 Monte Carlo Stochastic Simulati ons). This indicates a range of 73 percent below to 31 percent above the 2003 flux estimate of -10.1 Tg CO 2 Eq.

Table 7-20: Tier 2 Quantitative Uncertainty Estimates for CO 2 Flux from Yard Trimmings and Food Scraps in Landfills (Tg CO 2 Eq. and Percent)

Source Gas 2003 Flux Estimate Uncertainty Range Re lative to Flux Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Yard Trimmings CO 2 (7.5) (11.3) (4.4) -51% +41% Food Scraps CO 2 (2.6) (8.9) (1.2) -246% +54% Total CO 2 (10.1) (17.5) (7.0) -73% +31%

a Range of flux estimates predicted by Monte Carlo Stochas tic Simulation for a 95 percent confidence interval. Negative values indicate net carbon stor age (positive values denote emissions). The uncertainty of the landfilled carbon stor age estimate arises from the disposal data and the factors applied to the following data.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 254 

### Disposal per Year (tons of carbon)
A source of uncertainty affecting CO 2 sequestration is the estimate of the tonnage of yard trimmings and food scraps which are disposed of in landfills each year. Of all the individual inputs test ed for sensitivity in the uncertainty analysis, net carbon storage in landfills is most sensitive to the estimate of the food scrap disposal rate. The estimates for yard trimming and food sc rap disposal in landfills are determ ined using data from the EPA (1999, 2002, 2003) estimates of materials generated, discarded, and combusted, which carry considerable uncertainty associated with the wastestream sampling methodology used to generate them.



### Moisture Content and Initial Carbon Content
Moisture content, and to a lesser extent carbon content, vary widely. Moisture content for a given sample of waste can be affected by the precipitation c onditions when the waste is placed at th e curb for collection, as well as the status and condition of the landfill cover. Carbon content (on a dry weight basi s) is a function of the specific waste constituents (e.g., oak leaves versus pine needles or banana peels versus bacon grease), which in turn vary temporally, geographically, and demogr aphically (i.e., characteristics of households in the wasteshed).



### Decomposition Rate
Although several investigators have made estimates of th e decomposition rate of mixed solid waste in a landfill environment, there are no known studies of decomposition ra tes for individual materials in actual landfills, and thus the inventory estimate is based on assumed values. The uncertainty analysis indicates that the results are sensitive to decomposition rates, especially the food scraps half-lif e, and thus the decomposition rates introduce considerable uncertainty into the analysis.



### Proportion of Carbon Stored
The estimate of the proportion of carbon stored is based on a set of experiments measuring the amount of carbon persisting in conditions promoting deco mposition. Because these experiment s have only used conditions conducive to decomposition, they are more likely to underestimate than to overestimate carbon storage. Thus, the uncertainty analysis used asymmetrical values (up to 10 percent less storage, up to 20 percent more storage) as inputs.

Several of the planned improvements to the analysis, desc ribed later in this section, are intended to reduce the uncertainty associated with these factors.

Recalculations Discussion
While conducting quality control procedur es, it was found that the 1994 value for the amount of discards that are landfilled (or disposed of by means other than combustion) had been incorrectly recorded. The error was corrected, resulting in reduced carbon storage values by less than 1.0 Tg C for the years 1994 through 2003. Overall, this change, in combination with historical data revisions, resulted in an average annual decrease of 0.2 Tg CO 2 Eq. (0.7 percent) in carbon sequestration from yard trimmi ng and food scraps over the period 1990 through 2002.

Planned Improvements
As noted above, the estimates presented in this section are driven by a small carbon storage factor data set, and some of these measurements (especially for leaves) dese rve close scrutiny. There are ongoing efforts to conduct a re-analysis of the leaves experiment, using the same technique s as in the original experiments cited, and future work may evaluate the potential contributi on of inorganic carbon to landfill sequest ration and to assure consistency between the estimates of carbon storage described in this chapter and the estimates of landfill CH 4 emissions described in the Waste chapter.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 255 

### Changes in Carbon Stocks in Urban Tr ees (IPCC Source Category 5E1)

Urban forests constitute a significant portion of the total U.S. tree canopy cover (Dwyer et al. 2000). Urban areas (cities, towns, and villages), which cover 3.5 percent of th e continental United States, are estimated to contain about 3.8 billion trees. With an average tree canopy cover of 27.1 percent, urban areas account for approximately 3 percent of total tree cover in the continental United States (Nowak et al. 2001). Trees in urban areas of the continental United States were estimated by Nowak and Crane (2002) to account for an average annual net sequestration of 58.7 Tg CO 2 Eq. (16 Tg C). These data were collected throughout the 1990s, and have been applied to the entire time series in this report (see Table 7-21). Annual estimates of CO 2 flux have not been developed, but are believed to be re latively constant from 1990 through 2003.

Net carbon flux from urban trees is proportionately greater on an area basis than that of forests. This trend is primarily the result of different net growth rates in urban areas versus forests—urban trees often grow faster than forest trees because of the relatively open structure of the urban forest (N owak and Crane 2002). Also, areas in each case are accounted for differently. Because urban areas contain less tree coverage than forest areas, the carbon storage per hectare of land is in fact smaller for urban areas. However, urban tree reporting occurs on a per unit tree cover basis (tree canopy area), rather than total land area. Urban trees therefore appear to have a greater carbon density than forested areas (Nowak and Crane 2002).

Table 7-21: Net C Flux from Urban Trees (Tg CO 2 Eq. and Tg C)

Year Tg CO 2 Eq. Tg C 1990 (58.7) (16)

1997 (58.7) (16) 1998 (58.7) (16) 1999 (58.7) (16) 2000 (58.7) (16) 2001 (58.7) (16) 2002 (58.7) (16) 2003 (58.7) (16) Note: Parentheses indicate net sequestration.

Methodology
The methodology used by Nowak and Crane (2002) is base d on average annual estimates of urban tree growth and decomposition, which were derived from field measurements and data from the scientific literature, urban area estimates from U.S. Census data, and urban tree cover es timates from remote sensing data. This approach is consistent with the default IPCC methodology in the IPCC LULUCF Good Practice Guidance (IPCC 2003), although sufficient data are not yet available to determine interannual changes in carbon stocks in the living biomass of urban trees.

Nowak and Crane (2002) developed estimates of annua l gross carbon sequestration from tree growth and annual gross carbon emissions from decomposition for ten U.S. citie s: Atlanta, GA; Baltimore, MD; Boston, MA; Chicago, IL; Jersey City, NJ; New York, NY; Oakland, CA; Phila delphia, PA; Sacramento, CA; and Syracuse, NY. The gross carbon sequestration estimates were derived from field data th at were collected in these ten cities during the period from 1989 through 1999, including tree measurements of stem diameter, tree height, crown height, and crown width, and information on locati on, species, and canopy condition. The field data were c onverted to annual gross carbon sequestration rates for each sp ecies (or genus), diameter class, and land-use condition (forested, parklike, and open growth) by applying allometric equations, a root-to-shoot ratio, moisture contents, a carbon content of 50 percent (dry weight basis), an adjustment factor to account for smaller aboveground biomass volumes (given a particular diameter) in urban conditions compared to forests, an adjustment factor to account for tree condition (fair to excellent, poor, critical, dying, or d ead), and annual diameter and height growth rates. The annual gross carbon sequestration rates for each species (or ge nus), diameter class, and land-use c ondition were then scaled up to city estimates using tree population informati on. The field data from the 10 cities, some of which are unpublished, areInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 256 described in Nowak and Crane (2002) and references cited therein. The allometric equations were taken from the scientific literature (see Nowak 1994, Nowak et al. 2002), and the adjustments to account for smaller volumes in urban conditions were based on informa tion in Nowak (1994). A root-to-shoot ratio of 0.26 was taken from Cairns et al. (1997), and species- or genus-sp ecific moisture contents were take n from various literature sources (see Nowak 1994). Adjustment factors to account for tree condition were based on percent crown dieback (Nowak and Crane 2002). Tree growth rates were also taken from exis ting literature. Average diameter growth was based on the following sources: estimates for trees in forest stands came from Smith and Shifley (1984); estimates for trees on land uses with a park-like structure came from deVries (1987); and estimates for more open-grown trees came from Nowak (1994). Formulas from Fleming (1988) formed the basis for average height growth calculations.

Annual gross carbon emission estimates we re derived by a pplying estimates of annual mo rtality and condition, and assumptions about whether dead trees were removed from the site, to carbon stock estimates. These values were derived as intermediate steps in the sequestration calcula tions, and different decomposition rates were applied to dead trees left standing compared with those removed from the site. The annual gross carbon emission rates for each species (or genus), diameter cla ss, and condition class were then scal ed up to city estimates using tree population information. Estimates of a nnual mortality rates by diameter cla ss and condition class were derived from a study of street-tree mortality (Now ak 1986). Assumptions about whether d ead trees would be removed from the site were based on expert judgment of the authors. Decomposition rates were based on literature estimates (Nowak and Crane 2002).

Annual net carbon sequestration estimates we re derived for seven of the ten c ities by subtracting the annual gross emission estimates from the annual gross sequestration estimates. 9 National annual net carbon sequestration by urban trees was estimated from the city estimates of gro ss and net sequestration, and ur ban area and urban tree cover data for the contiguous United States. The urban areas are based on 1990 U.S. Census data, which define “urban land” as areas having a population density greater than 1,000 people per square mile and adjacent urban places, with predefined political boundaries, having a population total greater than 2,500. Therefore, urban encompasses most cities, towns, and villages (i.e., it includes both urban a nd suburban areas). The gro ss and net carbon sequestration values for each city were divided by each city’s area of tree cover to de termine the average annual sequestration rates per unit of tree area for each city. The me dian value for gross se questration (0.30 kg C/m 2 -year) was then multiplied by an estimate of national urban tree cover area (76,151 km 2 ) to estimate national annual gross sequestration. To estimate national annual net sequestrati on, the estimate of national annual gross sequestration was multiplied by the average of the ratios of net to gross sequestration for those cities that had both estimates. The average of these ratios is 0.70. The urban tree cover area estimates for each of the 10 cities and the contiguous United States were obtained from Dwyer et al. (2000) and Nowak et al. (2001).

Table 7-22: Carbon Stocks (Metric Tons C), Annual Carbon Sequestration (Metric Tons C/yr), Tree Cover (Percent), and Annual Carbon Sequestration per Area of Tree Cover (kg C/m 2 cover-yr) for Ten U.S. Cities

City Carbon Stocks Gross Annual Sequestration Net Annual Sequestration Tree Cover Gross Annual Sequestration per Area of Tree Cover Net Annual Sequestration per Area of Tree Cover New York, NY 1,225,200 38,400 20,800 20.9 0.23 0.12 Atlanta, GA 1,220,200 42,100 32,200 36.7 0.34 0.26 Sacramento, CA 1,107,300 20,200 NA 13.0 0.66 NA Chicago, IL 854,800 40,100 NA 11.0 0.61 NA Baltimore, MD 528,700 14,800 10,800 25.2 0.28 0.20 Philadelphia, PA 481,000 14,600 10,700 15.7 0.27 0.20 Boston, MA 289,800 9,500 6,900 22.3 0.30 0.22 Syracuse, NY 148,300 4,700 3,500 24.4 0.30 0.22 Oakland, CA 145,800 NA NA 21.0 NA NA

9 Three cities did not have net estimates.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 257 Jersey City, NJ 19,300 800 600 11.5 0.18 0.13 NA = not analyzed

Uncertainty
The only quantifiable uncertainty associat ed with changes in C stocks in urban trees was sampling, as reported by Nowak and Crane (2002). The average standard deviation for urban tree carbon storage was 27 percent of the mean carbon storage on an area basis. Additionally, a 5 percen t uncertainty was associated with national urban tree covered area. These estimates are based on field data collect ed in ten U.S. cities, and uncertainty in these estimates increases as they are scaled up to the national level.

There is additional uncertainty asso ciated with the biomass equations, conversion factors, and decomposition assumptions used to calculate carbon sequestration and emission estimates (Nowak et al. 2002). These results also exclude changes in soil carbon stocks, and there may be some overlap between the urban tree carbon estimates and the forest tree carbon estimates. However, both the omission of urban soil carbon flux and the potential overlap with forest carbon are believed to be relatively minor (N owak 2002). Because these ar e inestimable, they are not quantified as part of this analysis.

The results of the Tier 1 quantitative uncertainty analysis are summarized in Table 7-23. Net C flux from changes in C stocks in urban trees was estimated to be between -80.3 and -37.0 Tg CO 2 Eq. at a 95 percent confidence level. This indicates a range of 37 percent above and below the 2003 flux estimate of -58.7 Tg CO 2 Eq.

Table 7-23: Tier 1 Quantitative Uncer tainty Estimates for Net C Flux from Changes in Carbon Stocks in Urban Trees (Tg CO 2 Eq. and Percent)

Source Gas 2003 Flux Estimate (Tg CO 2 Eq.) Uncertainty (%) Uncertainty Range Relative to 2003 Flux Estimate (Tg CO 2 Eq.) Lower Bound Upper Bound Changes in C Stocks

in Urban Trees CO 2 (58.7) 37% (80.3) (37.0) Note: Parentheses indicat e net sequestration.

QA/QC and Verification
The net carbon flux resulting from urban trees was calculate d using estimates of gro ss and net carbon sequestration estimates for urban trees and urban tree coverage area found in literature. The validity of these data for their use in this section of the Inventory was evaluated through corre spondence established with an author of the papers. Through the correspondence, the methods used to collect the urban tree sequestration and area data were further clarified and the use of these data in the Inventory was reviewed and validated (Nowak 2002).

Planned Improvements
Some sources indicate a reduction in urban tree coverage in the United States over the Inventory period of approximately 21 percent over the la st 10 years (AF 2004). However, b ecause the methods for making this assertion have not yet been made available and their defi nition of urban land is unclear, the veracity and potential application of this estimate cannot currently be establis hed. Because the magnitude of the urban tree greenhouse gas sink in the United States is not insignificant, identifying changes in this sector is considered a priority and is being actively pursued for inclusion in future Inventories. Should this dimi nishment prove to be accurate, it could mean the urban tree sink estimates will need to be significantly revised. 

### Changes in Soil Carbon Stocks (IPCC Source Category 5E1)

Given the lack of available land use information relevant to this particular IPCC source category, it is not possible to quantify the CO 2 flux from soils in Settlements Remaining Settlements at this time.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 258 

### N 2 

### O Fluxes from Soils (IPCC Source Category 5E1)

Of the fertilizers applied to soils in the United States, approximately 10 percent are applied to lawns, golf courses, and other landscaping occurring within settled areas. A pplication rates are less th an those occurring on cropped soils, and therefore account for a smaller proportion of total U.S. soil N 2 O emissions per unit area. In 2003, N 2 O emissions from this source were 6.0 Tg CO 2 Eq. (19.4 Gg N 2 O). There was an overall increase of 9 percent over the thirteen year period due to a genera l increase in the application of synthetic fertilizers. Interannual variability in these emissions is directly attributab le to interannual variability in total sy nthetic fertilizer consumption in the United States.

Emissions from this source are summarized in Table 7-24.

Table 7-24: N 2 O Fluxes from Soils in Settlements Remaining Settlements (Tg CO 2 Eq.)

Settlements Remaining Settlements: N 2 O

Fluxes from Soils 1990 1997 1998 1999 2000 2001 2002 2003 Tg CO 2 Eq. 5.5 6.1 6.1 6.2 6.0 5.8 6.0 6.0 Gg 17.9 19.8 19.8 19.9 19.3 18.7 19.4 19.4

Methodology

Estimates of direct N 2 O emissions from soils in settlements were ba sed on the amount of N applied to turf grass annually through the application of synt hetic commercial fertilizers. Nitrogen a pplications to turf grass are assumed to be 10 percent of the total synthetic fertilizer used in the United States (Qian 2004). Total synthetic fertilizer applications were derived fro m fertilizer statistics (TVA 1991, 1992, 1993, 1994; AAPFCO 1995, 1996, 1997, 1998, 1999, 2000b, 2002, 2003, 2004) and a recent AAPFCO data base (AAPFCO 2000a). Unvolatilized N applied to turf grass was multiplied by the IPCC default emission factor (1.25 percent) to estimate direct N 2 O emissions. The volatilized and leached/runoff proporti on, calculated with the IPCC default volatilization factor of 10 percent and 30 percent, respectively, for synthetic fertilizers, wa s included with the total N contributions to indirect emissions, as reported in the N 2 O Emissions from Agricultural Soil Management source category of the Agriculture
sector.
Uncertainty

The amount of N 2 O emitted from settlements depends not only on N inputs, but also on a large number of variables, including organic carbon availability, O 2 partial pressure, soil moisture content, pH, temperature, and irrigation/watering practices. The effect of th e combined interaction of these variables on N 2 O flux is complex and highly uncertain. The IPCC default methodology used here does not incorporate any of these variables and only accounts for variations in national fertilizer application rates. All settlement so ils are treated equivalently under this methodology. Furthermore, onl y synthetic fertilizers are captured, so a pplications of organic fertilizers are not accounted for here. Uncertainties exist in both the fertilizer application rates a nd the emission factors used to derive emission estimates.

The 95 percent confidence interval for the IPCC’s default emission factor for synthetic fertilizer applied to soil ranges from 0.25 to 6 percent, according to Chapter 4 of IP CC (2000). While a Tier 1 analysis should be generated from a symmetrical distribution of uncertainty around the emission factor, an asymmetrical distribution was imposed here to account for the fact that the emission used was not the mean of the range given by IPCC. Therefore, an upper bound of 480 percent and a lower bound of 80 percent were assigned to the emission factor. The higher uncertainty percentage is shown below, but the lower bound reflects a truncated distribution. The uncertainty in the amount of synthetic fertilizer N applied to settlement soils was conservatively estimated to be 50 percent (Qian 2004). The results of th e Tier 1 quantitative uncerta inty analysis are summarized in Table 7-25. N 2 O emissions from soils in settlements remaining settlement s in 2003 were estimated to be between 0.3 and 35.1 Tg CO 2 Eq. at a 95 percent confidence level. This indicates a range of 94 percent below to 483 percent above the 2003 emission estimate of 6.0 Tg CO 2 Eq.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 259 Table 7-25: Tier 1 Quantitative Uncertainty Estimates of N 2 O Emissions from Soils in Settlements Remaining Settlements (Tg CO 2 Eq. and Percent)

IPCC Source Category Gas Year 2003 Emissions (Tg CO 2 Eq.) Uncertainty (%) Uncertainty Range Relative to 2003 Emission Estimate (Tg CO 2 Eq.) Lower Bound Upper Bound Settlements Remaining

Settlements: N 2 O Fluxes from Soils N 2 O 6.0 94 to 483% 0.3 35.1

Recalculations Discussion
The current Inventory presents N 2 O emissions from soils in settlements separately for the first time. Previously, N 2 O emissions from this source were included with N 2 O emissions from agricultural soils. The net effect of separating this source from agricultural soils is to reduce emissions reported from that source. However, because the methods for reporting that source category have changed significantly this year, it is not possible to isolate the magnitude of change caused by this recalcu lation alone on the overall differences in N 2 O emissions from agricultural soils.

Planned Improvements
The process-based model DAYCENT, which was used to estimate N 2 O emissions from cropped soils this year, could also be used to simulate emissions as well as volatilization and leaching/r unoff from settlements. DAYCENT has been parameterized to simulate turf grass. State-level settlement area data is available from the National Resource Inventory. Future inventories will incl ude DAYCENT simulations to estimate emissions from settlements.



### 7.6. Lands Converted to Settlements (Source Category 5E2)

Land-use change is constantly occurring, and land under a number of uses undergoes urbanization in the United States each year. However, data on the amount of land converted to settlements is currently lacking. Given the lack of available information relevant to this particular IPCC source category, it is not possible to quantify CO 2 or N 2 O fluxes from lands converted to settlements at this time.Land-Use Change and Forestry 7-3 or decays. The rate of emission varies considerably among different product pools. For example, if timber is harvested to produce energy, combustion releases carbon immediately. Conversely, if timber is harvested and used as lumber in a house, it may be many decades or even centuries before the lumber decays and carbon is released to the atmosphere. If wood products are disposed of in landfills, the carbon contained in the wood may be released many years or decades later, or may be stored almost permanently in
the landfill. This section of the Land-Use Change and Forestry chapter quantifies the net changes in carbon stocks in five forest carbon pools and two harvested wood pools. The net change in stocks for each pool is estimated, and then the changes in stocks are summed over all pools to estimate
total net flux. Forest carbon storage pools, and the flows between them via emissions, sequestration, and transfers, are shown in Figure 7-1. In this figure, forest carbon storage pools are represented by boxes, while flows between storage pools, and between storage pools and the atmosphere, are represented by arrows. Note that the boxes are not identical to the storage pools identified in this chapter. The storage pools identified in this chapter are defined differently in this graphic to better illustrate the processes that result in transfers of carbon from one pool to another, and that result in emissions to the atmosphere as well as uptake from the atmosphere. Approximately 33 percent (747 million acres) of the U.S. land area is forested (Smith et al. 2001). From the early 1970s to the early 1980s, forest land declined by approximately 5.9 million acres. During the 1980s and 1990s, forest area increased by about 9.2 million acres. These net changes in forest area represent average annual fluctuations of only about 0.1 percent. Given the low rate of change in U.S. forest land area, the major
influences on the current net carbon flux from forest land are management activities and the ongoing impacts of previous land-use changes. These activities affect the net flux of carbon by altering the amount of carbon stored in forest ecosystems. For example, intensified management of forests can increase both the rate of growth and the eventual

Figure 7-1
Forest Sector Carbon Pools and FlowsFigure 7-2: Estimates of Net Annual Changes in Carbon Stocks for Major Carbon Pools -300 -250 -200 -150 -100

-50

0 50 1 9 9 0 1 9 9 1 1 9 9 2 1 9 9 3 1 9 9 4 1 9 9 5 1 9 9 6 1 9 9 7 1 9 9 8 1 9 9 9 2 0 0 0 2 0 0 1 2 0 0 2 2 0 0 3 YearForest Sector Net Carbon Flux (Tg/yr)
Soil

Total Net Change Forest, nonsoil Harvested Wood7-6 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2002 for harvested wood, carbon stock estimates were derived from periodic inventories of forest stocks, and net changes in carbon stocks were interpolated between survey years. Carbon emissions from harvested wood were determined by accounting for the variable rate of decay of harvested wood according to its disposition (e.g., product pool, landfill, combustion). 3 Different data sources were used to estimate the carbon stocks and stock change in (1) forests (live and dead trees, understory, forest floor, and down dead wood), (2) forest soils, and (3) harvested wood products. Therefore, these pools are described separately below.

Tree, Understory, Forest Floor and Down Dead Wood Carbon The overall approach for determining non-soil forest carbon stock change was to estimate non-soil forest carbon stocks, based on data from two forest surveys conducted several years apart, and then to subtract the estimates developed for two consecutive years to calculate the net change in carbon stocks. Forest survey data were obtained from the USDA Forest Service, Forest Inventory and Analysis program (Frayer and Furnival 1999, Smith et al. 2001). Historically, the Forest Inventory and Analysis program did not conduct detailed surveys of all forest land, but instead -300 -250 -200 -150 -100 -50

0 1988 1990 1992 1994 1996 1998 2000 2002Forest Carbon Flux (Tg) Forest Soils Harvested Wood

Trees

Total Net Figure 7-2 Estimates of Forest Carbon Flux in Major Pools

Note: Estimates for harvested wood and forest soils are based on the same methodology and data as the previous U.S. Inventory (USEPA, 2003). Estimates for all pools are based on measured forest inventor y data and modeled projections as described in the text. Total Net includes all forest pools: trees, understory, forest floor, down dead wood, forest soils, wood products, and landfilled wood.

Figure 7-3 Average Carbon Density in the Forest Tree Pool in the Conterminous U.S. During 2004

3 The product estimates in this study use the “production approach” meaning that they do not account for carbon stored in imported wood products, but do include carbon stored in exports, even if the logs are processed in other countries (Heath et al. 1996).

Note: Estimates are based on forest inventory data as described in the text.

### Net Annual CO 2 

### Flux, per Hectare, F rom Mineral Soils Under Agricultural Management, 1990-1992

metric ton CO 2 /ha < -0.5
-0.5 to -0.2 5
-0.25 to -0.01
-0.01 to 0

> 0

This map shows the spatial variability in net annual carbon dioxide flux from mineral soi ls for the year 1990 through 1992. The color assigned to each polygon represents the average annual flux per hectare for t he area of managed mineral soils in that polygon. Note: V alues greater than zero represent emissions and values less than zero represent sequestration. Map accounts only for fluxes in agricultural soils and does not include SOC storage resulting from sewage sludge amendments in any year

. Figure 7-4
Net Annual CO 2 Flux, per Hectare, From Mineral Soils Under Agricultural Management, 1990–1992metric ton CO 2 /ha < -0.3
-0.5 to -0.25
-0.25 to -0.0 1
-0.01 to 0

> 0

This map shows the spatial variability in net annual carbon dioxide flux from mineral soils for the y ear 1993 through 2003. The color assigned to each polygon represents the average annual flux per hectare for the area of m anaged mineral soils in that polygon. Note: V alues greater than zero represent emissions and values less than zero represent sequestration. Map accounts only for fluxes in agricultural soils and does not include SOC storage resulting from sewage sludge amendments in any year , or CRP enrollment and manure management af ter 1997. Figure 7-5
Net Annual CO 2 Flux, per Hectare, From Mineral Soils Under Agricultural Management, 1993–2003metric ton CO 2 /ha no organic soils
0 to 5
5 to 25
>25

This map shows the spatial variability in net annual carbon dioxide flux from organic soils for the year 1990 through 1992. The color assigned to each polygon represents the average annual flux per hectare for the area of m anaged organic soils in that polygon

. Figure 7-6
Net Annual CO 2 Flux, per Hectare, From Organic Soils Under Agricultural Management, 1990–1992metric ton CO 2 /ha no organic soils
0 to 5
5 to 25
>25

This map shows the spatial variability in net annual carbon dioxide flux from organic soils for the year 1993 through 2003. The color assigned to each polygon represents the average annual flux per hectare for the area of m anaged organic soils in that polygon. Figure 7-7
Net Annual CO 2 Flux, per Hectare, From Organic Soils Under Agricultural Management, 1993–2003Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 261 

## 8. Waste

Waste management and treatment activities are sources of greenhouse gas emissions (see Figure 8-1). Landfills were the largest source of anthropogenic methane (CH 4 ) emissions, accounting for 24 percent of total U.S. CH 4 emissions. 1 Smaller amounts of CH 4 are emitted from wastewater systems by bacteria used in various treatment processes. Wastewater treatment systems are also a potentially significant source of nitrous oxide (N 2 O) emissions; however, methodologies are not currently available to develop a complete estimate. Nitrous oxide emissions from the treatment of the human sewage component of wastewater were estimated, however, using a simplified methodology. Nitrogen oxide (NO x ), carbon monoxide (CO), and non-me thane volatile organic compounds (NMVOCs) are emitted by waste activities, and are addressed separately at the end of this chapter. A summary of greenhouse gas and ambient air pollutant emissions from the Waste chapter is presented in Table 8-1 and Table 8-2.

Figure 8-1: 2003 Waste Chapter Greenhouse Gas Sources

Overall, in 2003, waste activities generated emissions of 183.8 Tg CO 2 Eq., or 2.6 percent of total U.S. greenhouse gas emissions.

Table 8-1: Emissions from Waste (Tg CO 2 Eq.) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CH 4 197.1 179.0 171.0 167.7 165.0 160.9 162.6 167.9

Landfills 172.2 147.4 138.5 134.0 130.7 126.2 126.8 131.2 Wastewater Treatment 24.8 31.7 32.6 33.6 34.3 34.7 35.8 36.8 N 2 O 13.0 14.7 15.0 15.4 15.6 15.6 15.7 15.9

Human Sewage 13.0 14.7 15.0 15.4 15.6 15.6 15.7 15.9 Total 210.1 193.7 186.0 183.1 180.6 176.5 178.3 183.8 Note: Totals may not sum due to independent rounding.

Table 8-2: Emissions from Waste (Gg) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 CH 4 9,385 8,526 8,145 7,984 7,858 7,660 7,744 7,997

Landfills 8,202 7,017 6,595 6,382 6,223 6,010 6,039 6,246 Wastewater Treatment 1,183 1,509 1,550 1,602 1,635 1,651 1,705 1,751 N 2 O 42 47 48 50 50 50 51 51

Human Sewage 42 47 48 50 50 50 51 51 NO x + 3 3 3 2 2 2 2 CO 1 5 5 13 8 8 8 8 NMVOCs 673 157 161 140 119 122 133 125 Note: Totals may not sum due to independent rounding. 

### 8.1. Landfills (IPCC Source Category 6A1)

Landfills are the largest anthropogenic source of CH 4 emissions in the United States. In 2003, landfill CH 4 emissions were approximately 131 Tg CO 2 Eq. (6,246 Gg). Emissions from m unicipal solid waste (MSW) landfills, which received about 61 percent of the total solid wast e generated in the United St ates, accounted for about 94 percent of total landfill emissions, while industrial landf ills accounted for the remai nder. Approximately 1,800

1 Landfills also store carbon, due to incomplete degradation of organic materials such as wood products and yard trimmings, as described in the Land-Use Change and Forestry chapter.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 262 operational landfills exist in the United States (BioCycle 2004) , with the largest landfills receiving most of the waste and generating the majority of the CH 4 . After being placed in a landfill, biogenic waste (such as paper, f ood scraps, and yard trimmi ngs) is initially digested by aerobic bacteria. After the oxygen has been depleted, the remaining waste is available for consumption by anaerobic bacteria, which can break down or ganic matter into substances such as cellulose, amino acids, and sugars. These substances are further broken down through fermentati on into gases, and short-chain organic compounds that form the substrates for the growth of methanogenic bacteria. Methane-producing anaerobic bacteria convert these fermentation products into stabilized organic materials and biogas consisti ng of approximately 50 percent carbon dioxide (CO 2 ) and 50 percent CH 4 , by volume. 2 Significant CH 4 production typically begins one or two years after waste disposal in a landfill and may last from 10 to 60 years.

From 1990 to 2003, net CH 4 emissions from landfills decreased by approximately 24 percent (see Table 8-3 and Table 8-4), with small increases occurring in some interim years. This downward trend in overall emissions is the result of increases in the amount of landfill gas collected and combusted by landfill operators, which has more than offset the additional CH 4 emissions resulting from an increase in the amount of municipal solid waste landfilled.

Methane emissions from landfills are a function of several factors, including: (1) th e total amount of municipal solid waste in landfills, which is related to total munici pal solid waste landfilled annually ; (2) the characteristics of landfills receiving waste (i.e., com position of waste-in-place; size, climate); (3) the amount of CH 4 that is recovered and either flared or used for energy purposes; and (4) the amount of CH 4 oxidized in landfills instead of being released into the atmosphere. The estimated annual qua ntity of waste placed in landfills increased from about 209 Tg in 1990 to 279 Tg in 2003, an increase of 33 percent (see Annex 3.14). During this period, the estimated CH 4 recovered and combusted from landfills increased as well. In 1990, for example, approximately 935 Gg of CH 4 were recovered and combusted (i.e., used for energy or flared) from la ndfills. In 2003, the estimated quantity of CH 4 recovered and combusted increased to 5,545 Gg.

Over the next several years, the total amount of municipal solid waste generated is expected to increase slightly. The percentage of waste landfilled, however, may decline due to increased recycling and composting practices. In addition, the quantity of CH 4 that is recovered and either flared or used for energy purposes is expected to increase, as a result of a 1996 federal regulation that requires large municipal solid wa ste landfills to collect and combust landfill gas (see 40 CFR Part 60, Subparts Cc 2002), and the Landfill Methane Outreach Program (LMOP), an EPA program that encourages voluntary CH 4 recovery and use at landfills not affected by the regulation.

Table 8-3: CH 4 Emissions from Landfills (Tg CO 2 Eq.) Activity 1990 1997 1998 1999 2000 2001 2002 2003 MSW Landfills 197.2 215.9 219.1 222.3 226.5 231.9 238.6 245.0 Industrial Landfills 13.8 15.1 15.3 15.6 15.9 16.2 16.7 17.2 Recovered

Gas-to-Energy (14.0) (34.7) (42.4) (48.0) (51.9) (57.5) (59.1) (61.9) Flared (5.6) (32.6) (38.2) (41.0) (45.2) (50.5) (55.3) (54.6) Oxidized a (19.1) (16.4) (15.4) (14.9) (14.5) (14.0) (14.1) (14.6) Total 172.2 147.4 138.5 134.0 130.7 126.2 126.8 131.2 Note: Totals may not sum due to independent rounding.

a Includes oxidation at both municipal and industrial landfills.

Table 8-4: CH 4 Emissions from Landfills (Gg)

2 The percentage of CO 2 in biogas released from a landfill may be smaller because some CO 2 dissolves in landfill water (Bingemer and Crutzen 1987). Additionally, less than 1 percent of landfill gas is typically composed of non-methane volatile organic compounds (NMVOCs).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 263 Activity 1990 1997 1998 1999 2000 2001 2002 2003 MSW Landfills 9,391 10,279 10,435 10,588 10,785 11,045 11,364 11,669 Industrial Landfills 657 720 730 741 755 773 795 817 Recovered

Gas-to-Energy (669) (1,652) (2,018) (2,287) (2,472) (2,738) (2,814) (2,946) Flared (266) (1,551) (1,821) (1,951) (2,154) (2,403) (2,635) (2,599) Oxidized a (911) (780) (733) (709) (691) (668) (671) (694) Total 8,202 7,017 6,595 6,382 6,223 6,010 6,039 6,246 Note: Totals may not sum due to independent rounding.

a Includes oxidation at municipal and industrial landfills.



### Methodology

Methane emissions from landfills were estimated to equal the CH 4 produced from municipal solid waste landfills, minus the CH 4 recovered and combusted, plus the CH 4 produced by industrial landfills, minus the CH 4 oxidized before being released into the atmosphere:

CH 4,Solid Waste = [(CH 4,MSW – R) + CH 4,ind ]- Ox

Where,

CH 4 , Solid Waste = CH 4 emissions from solid waste CH 4,MSW = CH 4 generation from municipal solid waste landfills, R = CH 4 recovered and combusted, CH 4,ind = CH 4 generation from industrial landfills, and Ox = CH 4 oxidized from MSW and industrial landfills before release to the atmosphere. The methodology for estimating CH 4 emissions from municipal solid waste landfills is based on the first order decay model described in the IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories and in a background paper prepared by Je nsen and Papatti (2002). Values for the CH 4 generation potential (L 0 ) and rate constant (k) were obtained from an analysis of CH 4 recovery rates for a database of 52 landfills and from published studies of other landfills (RTI 2004; EPA 1998; SWANA 1998; Peer, Thorneloe, and Epperson 1993). The rate constant was found to increase w ith average annual rainfall; consequently, values of k were developed for 3 ra nges of rainfall. The annual quantity of wast e placed in landfills was apportioned to the 3 ranges of rainfall based on the percent of the U.S. population in each of the 3 ranges, and historical census data were used to account for the shift in population to more arid ar eas over time. For further information, see Annex 3.14.

National landfill waste generation and disposal data for 1989 through 2003 were obtained from BioCycle (2004). Because BioCycle does not account for waste generated in U.S. terr itories, waste generation for the territories was estimated using population data obtained from the U.S. Ce nsus Bureau (2004) and national per capita solid waste generation from BioCycle (2004). Estimates of the annual quantity of waste landfilled for 1960 through 1988 were obtained from EPA’s Anthropogenic Methane Emissions in the United States, Estimates for 1990: Report to Congress (EPA 1993) and an extensive landfill survey by th e EPA’s Office of Solid Waste in 1986 (EPA 1988). Although waste placed in landfills in the 1940s a nd 1950s contributes very little to current CH 4 generation, estimates for those years were included in the first or der decay model for completeness in accounting for methane generation rates and are based on the population in those y ears and the per capita rate for land disposal for the 1960s.

The estimated landfill gas recovered per year was ba sed on updated data collected from vendors of flaring equipment, a database of landfill gas-to-energy (LFG TE) projects compiled by EP A’s Landfill Methane Outreach Program (LMOP), and a database maintained by the Energy Information Administration (EIA) for the voluntary reporting of greenhouse gases (EIA 2004). The three database s were carefully compared to identify landfills that were in two or all three of the databases to avoid doubl e-counting reductions. Based on the information provided by the EIA and flare vendor databases, the CH 4 combusted by flares in operation from 1990 to 2003 was estimated. This quantity likely underestimates flar ing, because these databases do not have information on all flares inInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 264 operation. Additionally, the EIA and LMOP databases provided data on landfill gas flow and energy generation for 358 landfills with LFGTE projects. If a landfill in the EIA database was also in the LMOP and/or the flare vendor database, the emissions avoided were based on the EIA data because landfill owners or operators reported the amount recovered based on measurements of gas flow a nd concentration, and the re porting accounted for changes over time. If both flare data and LMOP recovery data were available for any of the remaining landfills (i.e., not inthe EIA database), then the emissions recovery was based on the LMOP data, which provides reported landfillspecific data on gas flow for direct use projects and project capacity (i.e., megawatts) for electricity projects. The flare data, on the other hand, only provi ded a range of landfill gas flow for a given flare size. Given that each LFGTE project was likely to also have had a flare, double counting reductions from flares and LFGTE projects in the LMOP database was avoided by subtracting emissions reductions associated with LFGTE projects for which a flare had not been identified from the emi ssions reductions associated with flares. 3

Emissions from industrial landfills were assumed to be equal to seven percent of the total CH 4 emissions from municipal landfills (EPA 1993). The amount of CH 4 oxidized by the landfill cover at both municipal and industrial landfills was assumed to be ten percent of the CH 4 generated that is not recovered (Mancinelli and McKay 1985; Czepiel et al. 1996). To calculate net CH 4 emissions, both CH 4 recovered and CH 4 oxidized were subtracted from CH 4 generated at municipal and industrial landfills.


### Uncertainty

Several types of uncertainty are a ssociated with the estimates of CH 4 emissions from landfills. The primary uncertainty concerns the char acterization of landfills. Information is not available for the waste placed in every landfill for each year of its operation—a fundamental factor that affects CH 4 production. The heterogeneity of waste disposed in landfills is uncertain as well. The approach used here assumes that the CH 4 generation potential and the rate of decay that produces CH 4 as determined from several studies of CH 4 recovery at landfills are representative of U.S. landfills and reflects this heterogeneity. Also, the approach used to estimate the contribution of industrial non-hazardous wastes to total CH 4 generation introduces uncertainty. Aside from uncertainty in estimating CH 4 generation potential, uncertainty exists in the estimates of oxidation efficiency.

The N 2 O emissions from application of sewa ge sludge on landfills are not explic itly modeled as part of greenhouse gas emissions from landfills. Nitrous oxi de emissions from sewage sludge applied to landfills would be relatively small because the microbial environment in landfills is not very conducive to the nitrif ication and denitrification processes that result in N 2 O emissions. The total nitrogen (N) in sewage sludge increased from 189 to 247 Gg total N between 1990 and 2002. The quantity of sewage sludge applied to landfills decreased from 28 to 11 percent from 1990 to 2001 (EPA 1993).

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 8-5. Landfill CH 4 emissions in 2003 were estimated to be between 84.0 and 152.2 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of 36 percent below to 16 percent above the 2003 emission estimate of 131.2 Tg CO 2 Eq.

Table 8-5: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Landfills (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Rela tive to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%)

3 Due to the differences in referencing landfills and incomple te data on the national population of flares, matching flare vendo r data with the LFGTE data was problematic and a flare could not be identified for each of the LFGTE projects. Because each LFGTE project likely has a flare, the a ggregate estimate of emissi on reductions through flaring was reduced by the LFGTE projects for which a specific flare could not be identified. This approach eliminated the potential for double counting emissi ons reductions at landfills with bot h flares and a LFGTE project.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 265 Lower Bound Upper Bound Lower Bound Upper Bound

Landfills CH 4 131.2 84.0 152.2 -36% +16%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.



### Recalculations Discussion

The estimates for the current inventory are based on the fi rst order decay model rather than the linear regression model for 30-year waste in place used for previous inventories. The firs t order decay model was recommended by U.S. landfill and landfill gas experts and is the preferred approach in the IPCC guidance. Data are now available to develop reliable estimates of the two parameters needed for the first order decay model: CH 4 generation potential and the first order decay rate constant. In the past, these parameters were considered highly va riable, thus making the first order decay met hodology less desirable.

In addition to the change in method, improved estimates of the annual quantity of waste placed in landfills were developed, particularly for the time period of 1960 th rough 1988. These two methodological improvements resulted in a reduction in the estimate of CH 4 generation of approximately 20 per cent for 1990 and 27 percent for 2002. About half of this reduction is due to the use of the fi rst order decay model to estimate emissions, while the other half is due to the improved estimates of th e annual quantity of waste placed in landfills.

Another revision was incorporating data from the EIA to improve estimates of emissions avoided by LFGTE projects and flaring. The use of the EIA data resulted in a decrease of about 11 percent in CH 4 emissions avoided (using 2002 as an example), primarily due to improved estimat es for landfills with flares. Changes were also made to the LFGTE database used to estimate emissions avoided by these projects. The cha nges included corrections to megawatt capacity and gas flow rates, adding new projects that started in 2003, and accounting for projects that shut down. These changes had only a very small effect on em issions avoided by LFGTE projects. Overall, these changes resulted in an average annual decrease of 52.9 Tg CO 2 Eq. (26 percent) in CH 4 emissions from landfills for the period 1990 through 2002.


### Planned Improvements

For the future inventories, efforts will be made to improve the estimates of CH 4 generation at industrial landfills and estimates of oxidation, especially for landfills with gas recovery systems. Improvements to the flare database will be investigated, and an effort will be made to identify additional landfills that have flares. The parameters for the first order decay model will be re-evaluat ed as more data become available.



### 8.2. Wastewater Treatment (IPCC Source Category 6B)

Wastewater from domestic (municipal sewage) and industrial sources is treated to remove soluble organic matter, suspended solids, pathogenic organisms, and chemical contaminants. Treatment may either occur off-site or on-site. For example, in the United States, appr oximately 25 percent of domestic wastewater is treated in septic systems or other on-site systems. Soluble organic matter is ge nerally removed using biological processes in which microorganisms consume the organic matter for maintena nce and growth. The resulting biomass (sludge) is removed from the effluent prior to discharge to the receiving stream. Microorgani sms can biodegrade soluble organic material in wastewater unde r aerobic or anaerobic conditions, where the latter condition produces methane. During collection and treatment, wast ewater may be accidentally or deliberately managed under anaerobic conditions. In addition, the sludge may be further biodegraded under aerobic or anaerobic conditions.

The organic content, expressed in terms of either bi ochemical oxygen demand (BOD) or chemical oxygen demand (COD), determines the methane producing potential of wastewater. BOD represents the amount of oxygen that would be required to completely consume the organic matter contained in the wastewater through aerobic decomposition processes. COD refers to the amount of oxygen consumed under sp ecified conditions in the oxidation of the organic and oxidizable inorganic matter and is a parameter typically used to characterize industrial
wastewater.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 266 In 2003, CH 4 emissions from domestic wastewater treat ment were estimated to be 19.8 Tg CO 2 Eq. (944 Gg). Emissions have increased since 1990 in response to the increase in the U.S. human population. Also, the per capita organic wastewater loading has increased. Industrial emission sources include wastewater from the pulp and paper, meat and poultry processing, and the vegetables, fruits and juices processing industry. 4 In 2003, CH 4 emissions from industrial wastewater treatment were estimated to be 16.9 Tg CO 2 Eq. (807 Gg). Table 8-6 and Table 8-7 provide emission estimates from domestic and industrial wastewater treatment.

Table 8-6: CH 4 Emissions from Domestic and Industrial Wastewater Treatment (Tg CO 2 Eq.) Activity 1990 1997 1998 1999 2000 2001 2002 2003 Domestic 11.4 15.8 16.5 17.1 17.8 18.5 19.2 19.8 Industrial* 13.5 15.9 16.1 16.5 16.5 16.2 16.7 16.9 Total 24.8 31.7 32.6 33.6 34.3 34.7 35.8 36.8 * Industrial activity includes the pulp and paper, meat and poultr y, and the vegetables, fruits and juices processing industry. Note: Totals may not sum due to independent rounding.

Table 8-7: CH 4 Emissions from Domestic and Industrial Wastewater Treatment (Gg) Activity 1990 1997 1998 1999 2000 2001 2002 2003 Domestic 543 751 783 815 848 880 912 944 Industrial* 640 758 767 787 788 771 794 807 Total 1,183 1,509 1,550 1,602 1,635 1,651 1,705 1,751 * Industrial activity includes the pulp and paper, meat and poultr y, and the vegetables, fruits and juices processing industry. Note: Totals may not sum due to independent rounding.



### Methodology

Domestic wastewater CH 4 emissions were estimated using the defa ult IPCC methodology. National population data for 1990 to 2003, used in the domestic wastewater emissions estimates, were based on data from the U.S. Census Bureau (2004). For BOD 5 for domestic wastewater, two data points were available for 1991 and 2003 (Metcalf & Eddy 1990; Metcalf & Eddy 2003). 5 The BOD loadings for intervening years were obtained by linear interpolation. The emission factor (0.6 kg CH 4 /kg BOD 5 ) was taken from IPCC Good Practice Guidance (IPCC 2000). The percent of wastewater BOD 5 that was anaerobically digested was assumed to be 16.25 percent. This value also accounts for U.S. septic systems and is based on expert j udgment and on septic system usage data from EPA (1996).

Table 8-8: U.S. Population (Millions) and Wastewater BOD 5 Produced (Gg)

Year Population BOD 5 1990 254 5,566

1997 277 7,706 1998 280 8,032 1999 283 8,363 2000 287 8,695 2001 289 9,021 2002 292 9,351 2003 295 9,685

4 Industrial wastewater emissions from petrol eum systems are included in the petroleum sy stems section in the Energy chapter. Other industrial sectors include organic chemicals, starch pr oduction, alcohol refining, creameries, and textiles, however emissions from these sectors are considered to be insignificant. 5 BOD 5 is the 5-day biochemical oxygen demand (BOD) measurement (Metcalf and Eddy 2003).Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 267 Methane emissions estimates from industrial wastewater we re developed according to th e methodology described in the IPCC (2000). Industry categories that are likely to have significant CH 4 emissions from their wastewater treatment were identified. High volumes of wastewater generated and a high organic COD wastewater load were the main criteria. The top three industries that met these criteria included pulp and paper manufacturing, meat and poultry packing, and vegetables, fruits and juices processing.

Methane emissions from these categories were estimat ed by multiplying the a nnual product output (metric tons/year) by the average outflow (m 3 /metric ton of output), the organics loading in the outflow (grams of organic BOD/m 3 ), the emission factor (grams CH 4 /grams BOD), and the percentage of organic BOD assumed to degrade anaerobically. In developing estimates for the vegetables , fruits, and juices category, COD was used instead of BOD, because no accurate BOD numbers we re available. The emission factor used for pulp and paper as well as meat and poultry wastewater is 0.6 kg CH 4 /kg BOD 5 , whereas the emission factor fo r vegetables, fruits and juices category is 0.25 kg CH 4 /kg COD (IPCC 2000). The pertinent industry-specific parameters are specified below.

Wastewater treatment for the pulp and paper industry typica lly includes neutralization, screening, sedimentation, and flotation/hydrocycloning to remove solids (Wor ld Bank 1999, Nemerow and Dasgupta 1991). The most important step is lagooning for st orage, settling, and biological tr eatment (secondary treatment).

In determining the percent that degraded anaerobically, both primary and secondary treatment were considered. Primary treatment lagoons are aerated to reduce anaerobic activity. However, the lagoons are large and zones of anaerobic activity may occur and, consequently, the primary lagoons are assumed to be 1.4 percent anaerobic. Approximately 42 percent of the BOD passes on to secondary treatment, which is less likely to be aerated (EPA 1993). It was assumed that 25 percent of the BOD in secondary treatment lagoons degrades anaerobically, while 10 percent passes through to be discharged with the effluent (EPA 1997a). Consequently, the overall percentage of wastewater organics that degrade an aerobically was determined to be 10.3 percent (i.e., 58% × 1.4% + 42% × 90% × 25%). A time series of CH 4 emissions for post-1990 years was develope d based on production figures reported in the Lockwood-Post Directory (Lockwood-Post 2002). The overall wastewater outflow was estimated to be 85

m 3 /metric ton, and the average BOD loading entering the secondary treatment lagoons was estimated to be 0.4 gram BOD/liter (EPA 1997b, EPA 1993, WorldBank 1999).

The meat and poultry processing industry makes extensive use of anaerobic lagoons in sequence with screening, fat traps and dissolved air flotation. Production data, in carca ss weight for the meat and poultry industry, were obtained from the U.S. Census (2004). EPA (2002) provided wastewater flows into the anaerobic lagoons of 7.9 and 16.6

m 3 /metric ton for meat and poultry producti on, respectively. The loadings are 2.8 and 1.5 g BOD/liter for meat and poultry, respectively, while 90 percent of organic BOD is believed to degrade anaerobically in the lagoon (EPA 1997b).

Treatment of wastewater from fruits, vegetables, and jui ces processing includes screening, coagulation/settling and biological treatment (lagooning). The flows are frequently seasonal, and robust treatment systems are preferred for on-site treatment. Effluent is suitable for discharge to th e sewer. This industry is likely to use lagoons intended for aerobic operation, but the large seasonal loadings may develop limited anaerobic zones. In addition, some anaerobic lagoons may also be used (Nemerow and Dasgupt a 1991). Consequently, 5 percent of these wastewater organics are assumed to degrade anaerobically. The USDA National Agricultural Statistics Service (USDA 2004) provided production data for the fruits, vegetables, and ju ices processing sector. Outflow data for various subsectors (canned fruit, canned vegeta bles, frozen vegetables, fruit juices, jams, baby food) were obtained from World Bank (1999) and an average wastewater outflow of 5.6 m 3 /metric ton was used. For the organics loading, a COD value of 5 g/liter was used (EPA 1997b).

Table 8-9: U.S. Pulp and Paper, Meat and Poultr y, and Vegetables, Fruits and Juices Production (Tg)

Year Pulp and Paper Meat (carcass wei g ht) Poultr y (carcass weight) Vegetables, Fruits and Juices 1990 128.9 17.9 10.6 30.2 1991 129.2 18.5 11.2 31.3 1992 134.5 18.7 12.0 33.5 1993 134.1 18.9 12.3 34.1Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 268 1994 139.3 19.2 13.2 37.3 1995 140.9 19.8 13.8 36.8 1996 140.3 19.8 14.5 36.4 1997 145.6 19.7 15.0 37.7 1998 144.0 20.5 15.1 36.5 1999 145.1 21.0 16.0 37.4 2000 142.8 21.0 16.4 38.9 2001 134.3 20.8 16.8 35.0 2002 137.5 21.5 17.3 36.7 2003 140.0 21.8 17.6 34.4



### Uncertainty

Significant uncertainties are associated with the industrial wastewater emission estimates. Wastewater outflows and organics loadings vary considerably for different plants and different sub-sectors (e .g., paper vs. board, poultry vs. beef, or baby food vs. juices). For pulp and paper indus trial wastewater, five key variables were simulated: material output, with a standard deviation of 10 percen t; wastewater outflow, with a standard deviation of 48 percent; BOD 5 concentration, with a standard deviation of 25 pe rcent; percent anaerobically treated, with a standard deviation of 50 percent; and the BOD 5 IPCC methane emission factor, with a standard deviation of 30 percent. For industrial wastewater from meat and poultry processing, five key variables were simulated: material output, with a standard deviation of 10 percent; wastewater outfl ow, with a standard deviation of 59 percent; BOD 5 concentration, with a standard deviation of 51 percent; percent anaerobica lly treated, with a standard deviation of 10 percent; and the BOD 5 IPCC methane emission factor, with a standard deviation of 30 percent. For industrial wastewater from processing fruit and vegetables, five variables were simula ted: material output, with a standard deviation of 10 percent; wastewater outflow, with a standard deviation of 55 percent; COD 5 concentration, with a standard deviation of 60 percent; percent anaerobically treated, w ith a standard deviation of 50 percent; and the BOD 5 IPCC methane emission factor, with a standard deviation of 30 percent.

In summary, uncertainties for outflows are approximately 50 percent for the different source categories and are based on a standard deviation calculati on for meat and poultry, and on expert judgment and the literature for the pulp and paper and the vegetables, fruits, and juices category (Nemerow and Dasgupta 1991; World Bank 1999). Uncertainties for organic loadings are based on the same approach and are estimated at 25, 50, and 60 percent for pulp and paper, meat and poultry, and fru its, vegetables and juices, respectively. The uncertainty associated with the degree in which anaerobic degradati on occurs in treatment systems is es timated at 50 percent for the pulp and paper and vegetables, fruits, and juices categories, while th is factor for the meat and poultry industry is 10 percent, because the flow data are from th e entrance of the anaerobic lagoons.

For domestic wastewater uncertainty, a normal probability distribution was assumed for the four key variables simulated: population, with a standard deviation of 5 percent; BOD 5 , with a standard deviation of 30 percent; percent of wastewater treated an aerobically, with a standard deviation of 25 percent; and the BOD 5 IPCC CH 4 emission factor, with a standard deviation of 30 percent.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 8-10. Wastewater treatment CH 4 emissions in 2003 were estimated to be between 25.2 and 50.3 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indi cates a range of 32 percent below to 37 percent above the 2003 emission estimate of 36.8 Tg CO 2 Eq.

Table 8-10: Tier 2 Quantitative Uncertainty Estimates for CH 4 Emissions from Wastewater Treatment (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper BoundInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 269 Wastewater Treatment CH 4 36.8 25.2 50.3 -32% +37%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.



### Recalculations Discussion

Population estimates for the United States from 1990 through 2002 have been adjusted to include U.S. territories (i.e., American Samoa, Guam, Northe rn Mariana Islands, and the Virgin Islands). Emission estimates from previous years have only considered estimates of U.S. states and Puerto Rico. On average, updated U.S. population estimates increased total annual CH 4 emissions from wastewater treatme nt by less than one percent.

The time series for domestic wastewater has been updated due to an adjustment in the per capita BOD factor. The BOD factor changed from a constant value of 0.06 kg per capita per day to an increasing value from 0.06 in 1990 to 0.09 kg per capita per day in 2003. Compared to 2002 estimates, methane emissions from domestic wastewater increased 37 percent. The time series for industrial wast ewater changed because more detailed field data became available for the meat and poultry industry (EPA 2002) that in clude new flow and organic loading data. As a result, estimates for the meat and poultry industrial subcategor ies have been separated. Organic matter loading calculations are also now based on BOD ra ther than COD estimates. The new fl ow data reflect field measurements at the anaerobic lagoon inlet, as opposed to more general plant outflow data. Industrial CH 4 emissions increased 14 percent compared to 2002 estimates, as a result of the more detailed meat and poultry data and a slight increase in pulp and paper production. The total 2002 CH 4 emissions from wastewater treat ment increased by 25 percent compared to the emissions in the previous Inventory. Ov erall, these changes resulted in an average annual increase of 3.8 Tg CO 2 Eq. (14 percent) in CH 4 emissions from wastewater treatment for the period 1990 through 2002.


### Planned Improvements Discussion

The Authors/Experts Meeting for the Preparation of 2006 IPCC National Greenhouse Gas Inventories Guidelines for the Wastewater Sector, held in November 2004, will likely generate improved methodological data. Improvements will be planned accordingly.



### 8.3. Human Sewage (Domestic Wast ewater) (IPCC Source Category 6B)

Domestic human sewage is usually mixed with other household wastewater, which includes shower drains, sink drains, washing machine effluent, etc. and transported by a co llection system to either a di rect discharge, an on-site or decentralized wastewater treatment system, or a centralized wastewater treatment system. Decentralized wastewater treatment systems are sep tic systems and package plants. Cent ralized wastewater treatment systems may include a variety of processes, ranging from lagooning to advanced tertiary treatment technology for removing nutrients. Often, centralized wastewater treatment systems also treat certain flows of industrial, commercial, and institutional wastewater. After processi ng, treated effluent is discharged to a receiving water environment (e.g., river, lake, estuary, etc.), or applied to soils, or disposed of below the surface.

Nitrous oxide may be generated during bot h nitrification and denitrification of the nitrogen present, usually in the form of urea, ammonia, and proteins. These compounds are converted to nitrate via nitrification, an aerobic process converting ammonia-nitrogen into nitrate (NO 3 - ). Denitrification occurs unde r anoxic conditions (without free oxygen), and involves the biological conversion of nitrate into dinitrogen gas (N 2 ). Nitrous oxide can be an intermediate product of both processes, but is more often associated with denitrification.

The United States identifies two distinct sources for N 2 O emissions from domestic wa stewater: emissions from centralized wastewater treatment proce sses; and emissions from effluent that has been discharged into aquatic environments. The 2003 emissions of N 2 O from wastewater treatment processe s and from effluent were estimated to be 0.3 Tg CO 2 Eq. (0.9 Gg) and 15.6 Tg CO 2 Eq. (50 Gg), respectively. Total N 2 O emissions from domestic wastewater were estimated to be 15.9 Tg CO 2 Eq. (51 Gg) (see Table 8-11). Emissions from wastewater treatment processes have gradually increased as a result of increasing U.S. population and protein consumption.

Table 8-11: N 2 O Emissions from Human Sewage (Tg CO 2 Eq. and Gg)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 270 Year Tg CO 2 Eq. Gg 1990 13.0 42

1997 14.7 47 1998 15.0 48 1999 15.4 50 2000 15.6 50 2001 15.6 50 2002 15.7 51 2003 15.9 51



### Methodology

The IPCC default methodology (IPCC/UNEP/OECD/IEA 1997) assumes that nitrogen disposal, and thus N 2 O emissions associated with land disposal , subsurface disposal, and domestic wast ewater treatment are negligible and all nitrogen is discharged directly into aquatic environments. For the United States, N 2 O emissions from domestic wastewater (human sewage) were estimated using the IPCC methodology with three modifications:

• In the United States, a certain amount of nitrogen is removed with the sewage sludge, which is land applied, incinerated or landfilled (N sludge ). The nitrogen disposal into aquatic environments is reduced to account for the sewage sludge application.

o The IPCC methodology uses annual, per capita protein consumption (kg/year). This number is likely to underestimate the amount of protein entering the sewer or septic system. Food (waste) that is not consumed is often washed down the drain, as a result of the use of garbage disposals. Also, bath and laundry water can be expected to contribute to nitrogen loadings. A factor of 1.4 is introduced to account for non-consumption nitrogen. 6 Furthermore, a significant qua ntity of industrial wastewater (nitrogen) is co-discharged with domestic wastewater. To account for this, a factor of 1.25 is introduced. 7 In summary, a factor of 1.75 (1.4 × 1.25) is used to account for the extra nitrogendischarge from kitchen, bath, and laundry wastes, as well as industrial wastewater that is codischarged into sewers, based on Metcal f & Eddy (1991) and expert judgment.

• Process emissions from wastewater treatment plants are not accounted for in the current IPCC methodology. To estimate N 2 O emissions from U.S. wastewater tr eatment plants, an overall emission factor (4 g N 2 O/person.year) was introduced. This emission factor is based on a factor of 3.2 g N 2 O/person.year (Czepiel 1995) multiplied by the 1.25 factor mentioned above, which adjusts for codischarged industrial nitrogen and is based on expert judgment. The nitrogen quantity associated with

6 Metcalf & Eddy (1991) provides an indication of the nitrogen concentration of 40 mg Total Kjeldahl Nitrogen (TKN)/liter for average wastewater from residences, which includes bathwater, laundry, and the use of garbage disposals. According to the NEEDS Survey (1996), the total volume of wastewater genera ted in the US in 1996 was 32,175 million gallons per day (MGD), serving 189,710,899 people (72 percent of popul ation, not including the septic system users). In 1996, the per capita TKN loading was: 40 [mg/l] × 32,175 × 10 6 [gal/day] × 3.8 [l/gal] × 365 days/yr × 1/(189.7 × 10 6 ) × 10 -6 = 9.4 [kg TKN/yr.person]. Average protein intake in 1996 was 41 kg/year (6.6 kg N/year), leading to a factor of 1.4 (9.4/6.6).

7 The type, composition, and quantity of th is co-discharged wastewater will vary gr eatly between municipalities. Metcalf & Eddy (1991) provide an indicative nitrogen loading of 20 to 85 mg TKN/liter (average 55) for combined residential and industrial wastewater, while residential wastewater loading was roughly estimated at 40 mg TKN/liter (see footnote 1). Until better data become available, the amount of N in wastewater was increased by 10 mg/l to account for industrial co-discharge (factor of 1.25.)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 271 these emissions (NWWT) is calculated by multiplying the N 2 O emitted by (2 × 14)/44 and is subtracted from the total quantity of nitrogen that is ultimately disposed into the aquatic environment.

With the modifications described above, N 2 O emissions from domestic wastewater were estimated using the IPCC default methodology (IPCC/UNEP/OE CD/IEA 1997). This methodol ogy is illustrated below:

N 2 O(s) = (US POP × 0.75 × EF 1 × 10 -3 ) + {[(Protein × 1.75 × Frac NPR × US POP ) – N WWT – N sludge ] × EF 2 × 44 / 28 } where, N 2 O(s) = N 2 O emissions from domestic wastewat er (“human sewage”) [kg/year] US POP = U.S. population 0.75 = Fraction of population using centralized wastewater treatment plants (as opposed to septic systems) EF 1 = Emission factor ( 4 g N 2 O/person.year) expressing emissions from the centralized wastewater treatment plants Protein = Annual per capita protein consumption [kg N/(person.year)] 1.75 = Fraction of non-consumption protein in domestic wastewater Frac NPR = Fraction of nitrogen in protein (i.e., 0.16 kg N/kg protein) N WWT = Quantity of wastewater nitrogen removed by wastewater treatment processes [(US POP × 0.75 × EF 1 × 10 -3 ) × 28 / 44 ] (kg N/year). N sludge = Quantity of sewage sludge N not entering aquatic envir onments (kg N/year) EF 2 = Emission factor (kg N 2 O-N/kg sewage-N produced) ( 44 / 28 ) = Molecular weight ratio of N 2 O to N 2 .

U.S. population data were taken from the U.S. Census Bu reau (2003). The fraction of the U.S. population using wastewater treatment plants is from the NEEDS Survey (EPA 1996). The emission factor (EF 1 ) to estimate emissions from wastewater treatment is based on Czepiel, et al. (1995). Data on annual per capita protein intake were provided by the United Nations Food and Agricu lture Organization for the 1990 to 2002 time frame (FAO 2004). Because data on protein intake were unavailable for 2003, the value of per capita protein consumption was extrapolated from previous years. Table 8-12 presents the data for U.S. population and average protein intake. An emission factor to estimate emissions from effluent (EF 2 ) has not been specifically es timated for the United States, thus the default IPCC value (0.01 kg N 2 O-N/kg sewage-N produced) was applied. The fraction of nitrogen in protein (0.16 kg N/kg protein) was also obtained from IPCC/UNEP/OECD/IEA (1997).

Table 8-12: U.S. Population (Millions) and Average Protein Intake [kg/(person.year)]

Year Population Protein 1990 254 39.2

1997 277 40.9 1998 280 41.2 1999 283 42.0 2000 287 41.9 2001 289 41.8 2002 292 41.6 2003 295 41.8 

### Uncertainty

Nitrous oxide emissions from wastewater treatment are estimated to be substantially less than emissions from effluent-surface water. Thus, this wast ewater treatment subcategory was not cons idered in the uncer tainty analysis. A triangular distribution was used to simulate land application of sludge as defined for the agricultural soil management sector. The same distri bution was assumed for landfilled sludge. The means for the distributions were the estimates used for the 2003 inventory estimate. Base d on professional judgment, the standard deviation for population was 5 percent, the standard deviation for per capita protein consumption was 5 percent, the standard deviation of the fraction of nitrogen in protein (Frac NPR ) was 2 percent, and the standard deviation of the nonconsumption protein in domestic wastewater was 25 pe rcent based on professional judgment. The standardInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 272 deviation emission factor for effluent is 80 percent base d on the range provided in IPCC (1996). For the triangular distributions, the lower bound and upper estimates for the land applied a nd landfilled sludge were 50 percent below and above the respective estimates used for the 2003 inventor y. A normal distribution was used to simulate five variables: population, per capita protein intake data, fraction of nitrogen in protein (Frac NPR ), non-consumption protein in domestic wastewater , and the IPCC emission factor.

The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 8-13. Human sewage N 2 O emissions in 2003 were estimated to be between 4.2 and 29.9 Tg CO 2 Eq. at a 95 percent confidence level (or in 19 out of 20 Monte Carlo Stochastic Simulations). This indi cates a range of 74 percent below to 88 percent above the 2003 emission estimate of 15.9 Tg CO 2 Eq.

Table 8-13: Tier 2 Quantitative Uncertainty Estimates for N 2 O Emissions from Human Sewage (Tg CO 2 Eq. and Percent)

Source Gas 2003 Emission Estimate Uncertainty Range Relative to Emission Estimate a (Tg CO 2 Eq.) (Tg CO 2 Eq.) (%) Lower Bound Upper Bound Lower Bound Upper Bound Human Sewage N 2 O 15.9 4.2 29.9 -74% +88%

a Range of emission estimates predicte d by Monte Carlo Stochastic Simulati on for a 95 percent confidence interval.



### QA/QC and Verification

An IPCC Tier 1 level QA/QC verification was performed. During the QA/QC process the values for Wastewater BOD produced per capita (kg/capita/day) were adjusted to be based on a calculated rather than estimated interpolated value between the reporte d 1990 and 2003 values. In addition, the documentation of references in the spreadsheets was improved.


### Planned Improvements

The default emission factor for N 2 O from wastewater effluent has a high uncer tainty. Future research may identify new studies that include upda ted data. The factor that accounts for non- sewage nitrogen in wastewater (bath, laundry, kitchen, industrial components) also has a high uncertainty. Several pa rameters constituting this factor are based on references that have since been updated, incl uding Needs Survey (1996) and Metcalf & Eddy (1991). The uncertainty associated w ith this factor can likely be reduced incorporating more recent data.



### Recalculations Discussion

Population estimates for the U.S. from 1990 through 2002 have been adjusted to include U.S. territories (i.e., American Samoa, Guam, Northern Mariana Islands, and th e Virgin Islands). Emission estimates from previous years have only considered estimates of U.S. states and Puerto Rico. Overa ll, the change resulted in an average annual increase of 0.2 Tg CO 2 Eq. (1.7 percent) in N 2 O emissions from wastewater treat ment processes and effluent for the period 1990 through 2002.



### 8.4. Waste Sources of Ambient Air Pollutants

In addition to the main greenhouse gases addressed above, waste generating and handling processes are also sources of ambient air pollutant emissions. Total emissions of NO x , CO, and NMVOCs from waste sources for the years 1990 through 2003 are provided in Table 8-14.

Table 8-14: Emissions of NO x , CO, and NMVOC from Waste (Gg) Gas/Source 1990 1997 1998 1999 2000 2001 2002 2003 NO x + 3 3 3 2 2 2 2

Landfills + 2 2 3 2 2 2 2Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 273 Wastewater Treatment + + + + + + + + Miscellaneous a + 1 1 + + + + + CO 1 5 5 13 8 8 8 8

Landfills 1 5 5 12 7 7 7 7 Wastewater Treatment + + + 1 1 1 1 1 Miscellaneous a + + + + + + + + NMVOCs 673 157 161 140 119 122 133 125

Landfills 58 32 33 27 23 23 25 24 Wastewater Treatment 57 62 63 59 51 53 58 54 Miscellaneous a 558 64 65 54 46 46 51 47

a Miscellaneous includes TSDFs (Treatment , Storage, and Disposal Facilities under the Resource Conservation and Recovery Act [42 U.S.C. § 6924, SWDA § 3004] ) and other waste categories. Note: Totals may not sum due to independent rounding. + Does not exceed 0.5 Gg


### Methodology and Data Sources

These emission estimates were obtained from prelimin ary data (EPA 2004), and disaggregated based on EPA (2003), which, in its final iteration, will be published on the National Emission Inve ntory (NEI) Air Pollutant Emission Trends web site. Emission estimates of thes e gases were provided by sector, using a “top down” estimating procedure

⎯ emissions were calculated either for individual sources or for many sources combined, using basic activity data (e.g., the amount of raw material processe d) as an indicator of emissions. National activity data were collected for individual source categories from vari ous agencies. Depending on the source category, these basic activity data may include data on production, fuel deliveries, raw material processed, etc.

Activity data were used in conjunction with emission factors, which relate the quantity of emissions to the activity. Emission factors are generally available from the EPA’s Compilation of Air Pollutant Emission Factors, AP-42 (EPA 1997). The EPA currently derives the overall emission control efficiency of a source category from a variety of information sources, including published reports, the 1985 National Acid Precipitation and Assessment Program emissions inventory, and other EPA databases.


### Uncertainty

No quantitative estimates of uncertainty were calculated for this source category. Uncertainties in these estimates, however, are primarily due to the accur acy of the emission factors used and accurate estimates of activity data.Figure 8-1: 2003 Waste Chapter Greenhouse Gas Sources 0 20 40 60 80 100 120 140 Human Sewage Wastewater Treatment

Landfills

Tg CO 2 Eq Waste as a Portion of all Emissions

2.7%Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 275 

## 9. Other

The United States does not report any greenhouse gas emissions under the “other” IPCC sector.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 277 

## 10. Recalculations and Improvements

Each year, emission and sink estimates are r ecalculated and revised for all years in the Inventory of U.S. Greenhouse Gas Emissions and Sinks, as attempts are made to improve both the analyses themselves, through the use of better methods or data, and the overall usefulness of th e report. In this effort, the United States follows the IPCC Good Practice Guidance (IPCC 2000), which states, regarding recalcu lations of the time series, “It is good practice to recalculate historic emi ssions when methods are changed or re fined, when new source categories are included in the national inventory, or when errors in the estimates are identified and corrected (IPCC 2000).”

The results of all methodology changes and historical data updates are presented in this section; detailed descriptions of each recalculation are contained within each source’s descrip tion contained in this report, if applicable. Table 10-1 summarizes th e quantitative effect of these change s on U.S. greenhouse gas emissions and Table 10-2 summarizes the quantitative effect on U.S. si nks, both relative to the previously published U.S. Inventory (i.e., the 1990 through 2002 report). These tables present the magnitude of these changes in units of Tg CO 2 Eq. In addition to the changes summarized by the tables below, four new sources—CO 2 emissions from nonenergy use of fossil fuels and petrochemical production and N 2 O emissions from settlements remaining settlements and forest land remaining forest land—have been added to the current Inventory.

The Recalculations Discussion s ection of each source presents the details of each recalculation. In general, when methodological changes have been implemented, the entire time series (i.e., 1990 through 2002) has been recalculated to reflect the change, per IPCC Good Practice Guidance . Changes in historical data are generally the result of changes in statistical data supplied by other agen cies. References for the data are provided for additional information.

The following emission sources, which are listed in descending order of absolute average annual change in emissions from 1990 through 2002, underwent some of the most important methodological and historical data changes. A brief summary of the recalculation and/or improvement undert aken is provided for each emission

source.

● CO 2 from Fossil Fuel Combustion . The most important change in the calculation was the revision that removed emissions from the non-energy use of fuels, which allowed them to be reported separately in the Carbon Emitted from Non-Energy Uses of Fossil Fuels source categor y. Overall, this change, along with several other alterations, resulted in an average annual decrease of 115.8 Tg CO 2 Eq. (2.2 percent) in CO 2 emissions from fossil fuel combustion for the period 1990 through 2002.

● Land-Use Change and Forestry . The most influential of the changes in the Land-Use Change and Forestry sector occurred in calculations for agricultural soil carbon stocks. These changes include: a new methodology for the evaluation and incorporation of uncertainty in manure amendments into the calculations for agricultural soil carbon, the use of new management factors provided in the IPCC LULUCF Good Practice Guidance (IPCC 2003), and revision of the land area included in the emission calculation for organic soils. Overall, these changes, in combination with adjustments in the other sources/sinks, resulted in an average annual decrease in net flux of CO 2 to the atmosphere from the land-use change and forestry sector of 89.0 Tg CO 2 Eq. (12.1 percent) for the period 1990 through 2002.

● Landfills . Revisions to the emissions calcula tion incorporated the use of a firs t order decay model rather than a linear regression model for 30-year wa ste in place figures, improved estimates of the annual quantity of waste placed in landfills, and more accurate estimates of em issions avoided by landfill gas to energy (LFGTE) projects and flaring. Overall, changes re sulted in an average annual decrease in CH 4 emissions from landfills of 52.9 Tg CO 2 Eq. (26.0 percent) for the period 1990 through 2002.

● Agricultural Soil Management . The emissions calculation changed to in corporate the reallocation of emissions from fertilizer applied to forests and urban areas from the agricultural soil management source category within the Agriculture sector to the Land-Use Change and Forestry sector and the use of a Tier 3 methodology utilizing the DAYCENT ecosystem model rather than the Tier 1 methodology used in the past. Overall,Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 278 changes resulted in an average annual decrease in N 2 O emissions from agricultural soil management of 31.2 Tg CO 2 Eq. (11.0 percent) for the period 1990 through 2002.

● Petroleum Systems . The calculation of emissions was revised to incorporate a modified emission factor for CH 4 emissions from oil tanks in the production sector and new activity factor for offshore Gulf of Mexico platform venting in the production sector. Overall, changes resulted in an average annual decrease in CH 4 emissions from petroleum systems of 7.1 Tg CO 2 Eq. (27.4 percent) for the period 1990 through 2002.

● Natural Gas Systems . The emissions calculation was revised to incorporate new Gas STAR emissions reduction data and the addition of three new emission sources in the production sector: CH 4 from gas condensate stored in tanks, unconven tional gas well fugitives, and flari ng from offshore Gulf of Mexico operations. Overall, changes resulted in an average annual increase in CH 4 emissions from natural gas systems of 6.7 Tg CO 2 Eq. (5.3 percent) for the period 1990 through 2002.

● Mobile Combustion . The most significant changes to this source were revisions to the emission factors for CH 4 and N 2 O from highway vehicles, which were generated fro m EPA-sponsored laboratory vehicle testing. Revisions to these emission factors resulted in lower emission estimates for both CH 4 and N 2 O emissions from highway vehicles. Overall, changes resulted in an average annual decrease in N 2 O emissions from mobile combustion of 6.2 Tg CO 2 Eq. (10.9 percent) and an average annual decrease in CH 4 emissions from mobile combustion of 0.6 Tg CO 2 Eq. (13.6 percent ) for the period 1990 through 2002.

● Wastewater Treatment . The most influential changes in the calcula tion were the use of an adjusted per capita BOD factor in the domestic wastewater emissions calculations and the use of more detailed field data for the meat and poultry industry in the industrial wastewater emissions calculations. Overall, changes resulted in an average annual increase in CH 4 emissions from wastewater treatment of 3.8 Tg CO 2 Eq. (14.0 percent) for the period 1990 through 2002.

● Abandoned Coal Mines . The calculation of emissions was revised to incorporate an updated mine list, updated coal seam permeabilities, and revised closure dates for 43 of the mines. Overall, changes resulted in an average annual increase in CH 4 emissions from abandoned coal mines of 2.8 Tg CO 2 Eq. (64.5 percent) for the period 1990 through 2002.

Table 10-1: Revisions to U.S. Greenhouse Gas Emissions (Tg CO 2 Eq.) Gas/Source 1990 1997 1998 1999 2000 2001 2002 CO 2 7.2 2.3 4.7 1.7 (0.8) 13.0 14.4

Fossil Fuel Combustion (102.9) (120.8) (133.7) (142.9) (128.5) (110.8) (109.5) Non-Energy Use of Fuels a 108.0 120.3 135.4 141.6 124.7 120.1 118.8 Natural Gas Flaring + NC NC NC + 0.7 0.9 Cement Manufacture NC NC NC NC NC NC NC Lime Manufacture NC NC NC NC NC NC NC Limestone and Dolomite Use NC NC NC NC NC NC + Soda Ash Manufacture and Consumption NC NC NC NC NC NC NC Carbon Dioxide Consumption + + + + + + (0.3) Waste Combustion NC NC NC NC NC NC NC Titanium Dioxide Production NC NC NC NC NC NC NC Aluminum Production NC NC NC NC NC NC + Iron and Steel Production + + + + + (0.2) 0.7 Ferroalloys NC NC NC NC NC NC NC Ammonia Manufacture & Urea Application NC NC NC NC + 0.5 0.9 Petrochemical Production a NC NC NC NC NC NC + Phosphoric Acid Production 2.2 2.9 3.0 3.1 3.0 2.8 2.9 Land-Use Change and Forestry (Sink) (84.2) (109.1) (175.2) (150.4) (132.3) (137.1) (135.8) International Bunker Fuels (0.4) + (0.5) + + + 2.6 Biomass Combustion NC NC NC NC NC (3.9) 0.2 CH 4 (37.3) (49.3) (51.0) (55.8) (60.3) (58.3) (55.6)

Stationary Sources (0.4) (0.4) (0.3) (0.4) (0.4) (0.6) (0.5)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 279 Mobile Sources (0.2) (0.6) (0.7) (0.9) (1.0) (1.2) (1.3) Coal Mining + NC + + NC + 0.2 Abandoned Coal Mines 2.7 2.5 2.4 2.9 3.3 2.7 2.2 Natural Gas Systems 6.3 7.5 7.3 6.5 6.4 6.9 8.8 Petroleum Systems (8.9) (6.7) (6.5) (5.9) (5.9) (6.0) (6.1) Petrochemical Production NC NC NC NC NC NC NC Silicon Carbide Production NC NC NC NC NC NC NC Iron and Steel Production + + + + + + + Enteric Fermentation + + + 0.2 (0.1) 0.2 0.2 Manure Management 0.2 0.1 0.1 0.1 0.1 0.1 (0.1) Rice Cultivation NC NC NC NC NC NC NC Field Burning of Agricultural Residues NC NC + NC NC NC + Landfills (37.7) (56.0) (58.1) (63.8) (68.6) (67.0) (66.2) Wastewater Treatment 0.7 4.3 4.8 5.4 6.0 6.5 7.1 International Bunker Fuels + + + + + + + N 2 O (11.2) (40.0) (24.4) (46.2) (23.9) (31.4) (35.3) Stationary Sources (0.4) (0.4) (0.4) (0.4) (0.4) (0.4) (0.5) Mobile Sources (6.9) (5.1) (4.2) (4.0) (4.2) (6.1) (7.3) Adipic Acid NC NC NC NC NC NC NC Nitric Acid NC NC NC NC NC NC 0.5 Manure Management 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Agricultural Soil Management (9.8) (41.2) (26.5) (48.7) (25.9) (31.5) (34.8) Field Burning of Agricultural Residues NC NC + NC NC NC + Human Sewage 0.2 0.2 0.3 0.3 0.3 0.2 0.1 N 2 O Product Usage NC NC NC NC NC NC NC Waste Combustion NC NC NC NC NC 0.1 0.1 Settlements Remaining Settlements a 5.5 6.1 6.1 6.2 6.0 5.8 6.0 Forest Land Remaining Forest Land a 0.1 0.3 0.4 0.5 0.4 0.4 0.4 International Bunker Fuels + + + + + + + HFCs, PFCs, and SF 6 0.3 0.1 + + (0.2) (0.2) + Substitution of Ozone Depleting Substances 0.1 0.1 + + (0.1) (0.1) (0.2) Aluminum Production 0.2 + + + 0.1 + + HCFC-22 Production NC + + + + + NC Semiconductor Manufacture NC NC NC NC NC NC NC Electrical Transmission and Distribution + + + + (0.2) (0.2) (0.1) Magnesium Production and Processing NC NC NC NC + + 0.2 Net Change in Total Emissions b (41.0) (86.9) (70.7) (100.3) (85.2) (77.0) (76.5) Percent Change (0.7%) (1.3%) (1.0%) (1.5%) (1.2%) (1.1%) (1.1%) + Absolute value does not exceed 0.05 Tg CO 2 Eq. or 0.05 percent. NC (No Change)

a New source category relative to previous inventory. b Excludes sinks from land-use change and forestry, and emissions from internati onal bunker fuels and biomass combustion. Note: Totals may not sum due to independent rounding.

Table 10-2: Revisions to Net Flux of CO 2 to the Atmosphere from Land-Use Change and Forestry (Tg CO 2 Eq.) Component 1990 1997 1998 1999 2000 2001 2002 Forest Land Remaining Forest Land (102.7) (120.9) (187.7) (163.3) (145.6) (150.7) (150.7)

Cropland Remaining Cropland 18.5 11.9 12.6 13.0 13.4 13.6 15.0 Settlements Remaining Settlements NC (0.1) (0.1) (0.1) (0.1) + + Net Change in Total Flux (84.2) (109.1) (175.2) (150.4) (132.3) (137.1) (135.8) Percent Change (8.8%) (13.3%) (24.8%) (22.2%) (19.2%) (19.9%) (19.7%) + Absolute value does not exceed 0.05 Tg CO 2 Eq. or 0.05 percent. NC (No Change)Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 280 Note: Numbers in parentheses indicate a decrease in estimated net flux of CO 2 to the atmosphere, or an increase in net sequestration. Note: Totals may not sum due to independent rounding.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 281 

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EIA (2004b) International Energy Annual, "World Petroleum Supply and Di sposition " Available online at <http://www.eia.doe.gov/iea/pet.html>. Table 3.1.

EIA (2002a) Alternative Fuels Data Tables . Energy Information Administration, U.S. Department of Energy, Washington, DC. Available online at <http://www.eia.doe.gov/fuelalternate.html>.

EIA (2002b) Personal Communication with Joel Lou. Resi dual and Distillate Fuel Oil Consumption for Vessel (Both International and Domestic) for American Samoa, U.S. Paci fic Islands, and Wake Island.

EIA (2003 through 2004) Personal Communication with Ch arles Esser. Residual and Distillate Fuel Oil Consumption for Vessel Bunkering (Both International and Domestic) for American Samoa, U.S. Pacific Islands, and Wake Island.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 292 EIA (1991 through 2004) Fuel Oil and Kerosene Sales. Energy Information Administration, U.S. Department of Energy, Washington, DC, DOE/EIA-0535-annual.

EPA (2004a) Annual Certification Test Results Report. Office of Transportation and Air Quality, U.S. Environmental Protection Agency. Available online at <http://www.epa.gov/otaq/crttst.htm>.

EPA (2004b) Motor Vehicle Emission Simulator (MOVES). Office of Tran sportation and Air Quality, U.S. Environmental Protection Agency. Available online at <http://www.epa.gov/otaq/nonrdmdl.htm>.

EPA (2004c) NONROAD Model. Office of Tr ansportation and Air Quality, U.S. Environmental Protection Agency. Available online at <http://www.epa.gov/otaq/ngm.htm>.

EPA (2004d) Confidential engine family sales data submitted to EPA by ma nufacturers. Office of Transportation and Air Quality, U.S. Environmental Protection Agency.

EPA (2004e) Air Emissions Trends - Continued Progress Through 2003. U.S. Environmental Protection Agency, Washington, DC. Available online at <http://www.epa.gov/airtrends/econ-emissions.html>.

EPA (2003) E-mail correspondence containing preliminary am bient air pollutant data between EPA OAP and EPA OAQPS. December 22, 2003.

EPA (2000) Mobile6 Vehicle Emission Modeling Software . Office of Mobile Sources, U.S. Environmental Protection Agency. Ann Arbor, Michigan.

EPA (1999) Emission Facts: The History of Reducing Tailpipe Emissions. Office of Mobile Sources, May, EPA 420-F-99-017. Available online at <http ://www.epa.gov/oms/consumer/f99017.pdf>.

EPA (1998) Emissions of Nitrous Oxide from Highway Mobile Sources: Comments on the Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks, 1990-1996 . Office of Mobile Sources, Assessment and Modeling Division, U.S. Environmental Protection Agency, August, EPA420-R-98-009. Available online at <http://www.epa.gov/oms/climate.htm>.

EPA (1997) Mobile Source Emission Factor Model (MOBILE5a) . Office of Mobile Sources, U.S. Environmental Protection Agency. Ann Arbor, Michigan.

EPA (1994a) Automobile Emissions: An Overview. Office of Mobile Sources, August, EPA 400-F-92-007. Available online at <http://www.epa.gov/otaq/05-autos.htm>.

EPA (1994b) Milestones in Auto Emissions Control. Office of Mobile Sources, August, EPA 400-F-92-014. Available online at <http://www.epa.gov/otaq/12-miles.htm>.

EPA (1993) Automobiles and Carbon Monoxide. Office of Mobile Sources, January, EPA 400-F-92-005. Available online at <http://www.epa.gov/otaq/03-co.htm>.

EPA/DOE (2001) Fuel Economy 2001 Datafile . U.S. Environmental Protection Agency, Department of Energy. Washington, DC, dataset 01guide0918. Available online at <http://www. fueleconomy.gov/feg/download.shtml>.

FAA (2004). FAA Aerospace Forecasts Fiscal Years 2000-2014 , Table 32 “General Av iation Aircraft Fuel Consumption," Federal Aviation Admini stration. Available online at < http ://apo.faa.gov/foreca02/ content_5.htm>.

FHWA (1996 through 2004) Highway Statistics . Federal Highway Administration, U.S. Department of Transportation. Washington, DC, report FHWA-PL-96-023-annual.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 293 ICF (2004) “Update of Methane and Nitrous Oxide Emission Factors for On-Highway Vehicles,” Final Report to U.S. Environmental Protection Agency, February 2004.

ICF (2001) Revised U.S. VMT estimates and N 2 O emission factors. Memorandum from ICF Consulting to Ed Coe, Office of Transportation and Air Quality, U.S. Environmental Protection Agency. December 2001.

IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Paris: Intergovernmental Panel on Climate Change, United Nati ons Environment Programme, Organization for Economic Co-Operation and Development, International Energy Agency.

Lipman, T. and M. Delucchi (2002) “Emissions of Nitrous Oxide and Methane from Conventional and Alternative Fuel Motor Vehicles,” Climate Change , Volume 53, pp.477-516. Ava ilable online at < http://istsocrates.berkeley.edu/~rael/Climatic_Change.pdf>

Norbeck, J., T. Truex, M. Smith, and T. Durbin ( 1998) "Inventory of AFVs and AFV Comparison: OEM vs. Retrofits,” CE-CERT, University of California Riverside, Final Report 98-VE-RT2W-008-FR, September 1998 Available online at <http://www.cert.ucr.edu/research/pubs/98-ve-rt2w-008-fr.pdf>.

NREL (2002) Truck Engine/Fuel System Specification Data , Center for Transportation Technologies and Systems, National Renewable Energy Laboratory, U.S. Department of Energy, Washington, DC. Available online at <http://www.ctts.nrel.gov/heavy_vehicle/emissions.html>.

Prigent, M. and G. De Soete (1989) “Nitrous oxide N 2 O in engines exhaust gases

⎯ a first appraisal of catalyst impact,” Society of Automotive Engineers, SAE Paper 890492.

Smith, L. R. and P. M. Carey (1982) “Characterization of exhaust emissions from high mileage catalyst-equipped automobiles,” Society of Automotive Engineers, SAE Paper 820783.

Unnasch, S. and L. Browning (2000) “Fuel Cycle Energy Conversion Efficiency Analysis.”

Unnasch, S., L. Browning and E. Kassoy (2001) “Refinement of Selected Fuel-Cycle Emissions Analyses, Final Report to ARB.”

Urban, C. M. and R. J. Garbe (1980) “Exhaust Em issions from Malfunctioning Three-Way Catalyst-Equipped Automobiles,” Society of Automotive Engineers, SAE Paper 800511.

Wang, M.G. (1999) “GREET 1.5 – Transportation Fuel Cycle Model” Report No. ANL/ESD-39.

Weaver, C. S. and L.-M. Chan (1996) “Mobile source emission factors for global warming gases,” Draft Final Report, 24 June, submitted to ICF, Inc. by Engine, Fuel, and Emissions Engineering, Inc., Sacramento, CA.

Coal Mining

AAPG (1984). Coalbed Methane Resources of the United States, AAPG Studi es in Geology Series #17 , 1984.

Coal Age (2002). Keystone Coal Industry Manuals 1991-2002 . Primedia Business Magazines & Media. Chicago, IL.

DOE (1983). Methane Recovery from Coalbeds: A Potential Energy Source , U.S. Department of Energy, (DOE/METC/83-76).

EIA (2003). Personal Communication on September 30, 2002, U.S. Department of Energy, Energy Information Administration, Washington, DC.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 294 EIA (2003). Coal Industry Annual 1991-2002 . U.S. Department of Energy, Energy Information Administration, Washington, DC, Table 3

. EPA (2002). 2002 Base Year Greenhouse Gas Inventory Preparation Guidelines memorandum. U.S. Environmental Protection agency, Air And Radiation, June 2003.

EPA (1996). Evaluation and Analysis of Gas Content and Coal Pr operties of Major Coal Bearing Regions of the United States , U.S. Environmental Protection Agency, EPA/600/R-96-065.

EPA (1990). Methane Emissions from C oal Mining: Issues and Opportunities for Reduction . U.S. Environmental Protection Agency, Air and Radiation, September.

GRI (1988). A Geologic Assessment of Natural Gas from Coal Seams Topical Reports, Gas Research Institute 1986- 88.

Mutmansky, Jan M. and Yanebi Wang (2000). Analysis of Potential Errors in Determination of Coal Mine Annual Methane Emissions, Mineral Resources Engineering, Vol. 9, No. 4, December 2000.

USBM (1986). Circular 9067, Results of the Direct Method Determination of the Gas Contents of U.S. Coal Basins

. U.S. Bureau of Mines.

Abandoned Coal Mines

EPA 2003, “Methane Emissions Estimates & Methodology for Abandoned Coal Mines in the U.S.,” Draft Final Report, Washington DC, June 2003.

Garcia, F., and J. Cervik 1987, Method Factors for Anemometer Measurement at Pipe Outlets, U.S. Bureau of Mines, RI 9061, Pittsburgh, PA.

Garcia, F., F. E. McCall, and M. A. Trevits 1994, Proceedings of the 7 th U.S. Mine Ventilation Symposium, A Case Study of Methane Gas Migration Through Sealed Mine Gob Into Active Mine Workings, U.S. Bureau of Mines, Pittsburgh, PA.

Irani, M. C., E. D. Thimons, T. G. Bobick, Maurice Deul, and M. G. Zabetakis 1972, Methane Emissions From U.S. Coal Mines, A Survey, U.S. Bureau of Mine s, Information Circular 8558, Pittsburgh, PA.

Kirchgessner, D.A., S.D. Piccot, and S.S. Masemore 2001, An Improved Inventory of Methane Emissions from Coal Mining in the U.S., Journal of Air and Waste Management Association, Volume 50:1904-1919, March 2001.

Krog, Robert B., 2004, National Institu te for Occupational Safety and Hea lth, MS Excel spreadsheets containing copies of 1985 & 1988 coal mine ventilation data compiled by USBM, June 23, 2004.

Masemore, S., S. Piccot, E. Ringler, and W. P. Diamond 1996, Evaluation and Analysis of Gas Content and Coal Properties of Major Coal Bearing Regions of the United States, EPA-600/R-96-065, Washington, DC.

Mutmansky, Jan M., and Yanbei Wang 2000, Analysis of Pote ntial Errors in Determination of Coal Mine Annual Methane Emissions, Pennsylvania State University, Department of Energy and Geo-Environmental Engineering, University Park, PA.

Seidle, J.P. and L.E. Arri 1990, "Use of Conventional Reservoir Models for Coalbed Methane Simulation," Paper CIM/SPE 90-118, presented at the CIM/SPE International Technical Meeting, Calgary, Alberta ,June 10-13, 1990.

U.S. Department of Labor, Mine Health & Safety Administ ration, 2004, Data Retrieval System. Available online at <http://www.msha.gov/drs/drshome.htm>.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 295 U.S. Environmental Protection Agency, 2004, Proposed Improvements to Abandoned Mine Methane Emissions Methodology Memorandum, Coal Permeability, April 23, 2004.

Petroleum Systems

API (2003) Basic Petroleum Data Book . American Petroleum Institute, Washington, DC. DB Robinson Research Ltd. (1997) API TANKCalc, Version 1.0. A Program for Estimating Emissions from Hydrocarbon Production Tanks. Prepared for API and GRI. Washington, DC. August 1997. EIA (1990-2003) Petroleum Supply Annual 1990-2003 Volume 1. Energy Information Administration, U.S. Department of Energy, Washington, DC.

EIA (1995-2003a) Annual Energy Review . Energy Information Administration, U.S. Department of Energy, Washington, DC. Available online at <www.eia.doe.gov/emeu/mer>.

EIA (1995-2003b) Monthly Energy Review . Energy Information Administration, U.S. Department of Energy, Washington, DC. Available online at <www.eia.doe.gov/emeu/mer>.

EIA (2004) Annual Energy Outlook . Energy Information Administration, U.S. Department of Energy, Washington, DC. Available online at < http://www.eia.doe.gov/oiaf/aeo/index.html>.

EPA (1995) Compilation of Air Pollutant Emi ssion Factors AP-42, Fifth Edition, Volume I: Stationary Point and Area Sources. U.S. Environmental Protection Agency. Available online at <http://www.epa.gov/ttn/chief /ap42/index.html>.

EPA (1999) Estimates of Methane Emissions from the U.S. Oil Industry (Draft Report). Office of Air and Radiation, U.S. Environmental Protection Agency. October 1999.

MMS (1995) Gulf of Mexico Air Quality Study. Minerals Management Service, U.S. Department of Interior. August 1995.

MMS (1999) Personal communication on 8/31/99. Minerals Ma nagement Service, U.S. Department of Interior, New Orleans, L.A.

MMS (2000) Field and Reserve Information. Minerals Management Service, U.S. Department of Interior. Available online at < http://www.gomr.mms.gov/homepg/offshore/fldresv/resvmenu.html>.

MMS (2001) Delineation Drilling Activities in Federal Wate rs Offshore Santa Barbara County, California. Minerals Management Service, U.S. Department of Interior. Available online at < http://www.mms.gov/itd/pubs/2001/2001- 046/TableofContents.pdf>.

MMS (2004a) Long-Term Oil and Gas Structure Installation and Removal Forecasting in the Gulf of Mexico: A Decision- and Resource-Based Approach. Minerals Management Service, U.S. Department of Interior. Available online at < http://www.enrg.lsu.edu/publications/online/2004-009_Final_Report.pdf>.

MMS (2004b) OCS Platform Activity. Minerals Management Service, U.S. Department of Interior. Available online at <http://www.mms.gov/stats>.

MMS (2004c) Platform Information and Data. Minerals Management Service, U.S. Department of Interior. Available online at < http://www.gomr.mms.gov/hom epg/pubinfo/freeasci/platform/freeplat.html>.

OGJ (2003a) Oil and Gas Journal 1990-2003 , Pipeline Economics Issue, August or September.

OGJ (2003b) Oil and Gas Journal 1990-2003 , Worldwide Refining Issue, late December.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 296 Radian (1996a) Methane Emissions from the Natural Gas Industry, V7: Blow and Purge Activities . Prepared for the Gas Research Institute and EPA. April 1996.

Radian (1996b) Methane Emissions from the Natural Gas Industry, V11: Compressor Driver Exhaust . Prepared for GRI and EPA. April 1996.

Radian (1996c) Methane Emissions from the Natural Gas Industry, V12: Pneumatic Devices . Prepared for GRI and EPA. April 1996.

Radian (1996d) Methane Emissions from the Natural Gas Industry, V13: Chemical Injection Pumps . Prepared for GRI and EPA. April 1996.

Radian (1996e) Methane Emissions from the U.S. Petroleum Industry . Draft. Prepared for GRI and EPA. June 1996.

Radian (1996f) Methane and Carbon Dioxide Emissions Estimate From U.S. Petroleum Sources . Prepared for API. July 1996.

United States Army Corps of Engineers (1995-2002) Waterborne Commerce of the United States, Part 5: National Summaries . U.S. Army Corps of Engineers, Washington, DC.

Natural Gas Systems

AAPG (2004). Shale Gas Exciting Again. American Associ ation of Petroleum Geologi sts. Available online at <http://www.aapg.org/explorer/2001/03mar/gas_shales.html>.

AGA (1991-1998) Gas Facts. American Gas Association. Washington, DC.

API (2002, 2003) “Table 12 - Section III - Producing Oil Wells in the United States by State." Basic Petroleum Data Book. American Petroleum Institute. August 2002. Volume XXII, Number 2.

Alabama (2004). Alabama State Oil and Gas Board. Available online at <h ttp://www.ogb.state.al.us>.

Brookhaven (2004). Natural Gas Field Subject of Intere st at Brookhaven College. Brookhaven College. Available online at <http://www.brookhavencollege.edu/news/releases/news1752.html>.

DB Robinson Research Ltd. (1997) API TANKCalc, Ve rsion 1.0. A Program for Estimating Emissions from Hydrocarbon Production Tanks. Prepared for API and GRI. Washington, DC. August 1997.

EIA (1993, 1996a, 1997a, 1998a). Table 1, Summary Statistics for Natural Gas in the United States. Natural Gas Annual. Energy Information Administration, Department of Energy, Washington, DC. Available online at <www.eia.doe.gov>.

EIA (2001a, 2002a) Table 5, Number of Producing Gas a nd Gas Condensate Wells by States of December 31, 1997-2002, Natural Gas Annual. Energy Information Admini stration, Department of Energy, Washington, DC. Available online at <www.eia.doe.gov>.

EIA (2003a). “Table 95 - Natural Gas Consumption in the United States, 1930-2000.” Natural Gas Annual, 2000. Energy Information Administration, Department of Energy, Washington, DC. Available online at <www.eia.doe.gov>. Gas Consumption in the Trans portation section is now labeled Vehicle Fuel.

EIA (1998b). "Table 100, Natural Gas Consumption in the United States, 1994-1998.” Natural Gas Annual, 1998. Energy Information Administration, Department of Energy, Washington, DC. Available online at <www.eia.doe.gov>.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 297 EIA (2002b, 2003b, 2004a). “Table 2 - Supply and Dispositi on of Dry Natural Gas in the United States 1999-2004.” Natural Gas Monthly. Energy Information Administration, Department of Energy, Washington, DC. Available online at <www.eia.doe.gov>.

EIA (2001b, 2003c, 2004b). “Table 3 - Natural Gas Consumpti on in the United States.” Natural Gas Monthly. Energy Information Administration, Department of Energy, Washington, DC. Available on line at <www.eia.doe.gov>.

EIA (2002c, 2003d, 2004c). “Table 7 - Marketed Production of Natural Gas by State.” Natural Gas Monthly. Energy Information Administration, Department of Energy, Washington, DC. Available online at <www.eia.doe.gov>.

EIA (2003e). “Table 6 - Number of Producing Gas and Ga s Condensate Wells by State." Historical Natural Gas Annual 1930-2000. Energy Information Administration, Department of Energy, Washington, DC. Available online at <www.eia.doe.gov>.

EIA (1996b, 1997b, 1998c, 1999, 2000, 2001c, 2002d). “Table 15, Crude Oil, Natural Gas.” Natural Gas Liquids Reserves 2002 Annual Report, Energy Information Administration, Department of Energy, Washington, DC. Available online at www.edi.doe.gov.

EIA (2004d) Table 5.2. Monthly Energy Review. Energy Information Administration, Department of Energy, Washington, DC. Available online at http://www.eia.doe.gov/emeu/mer/resource.html.

EIA (2004e) Report "US LNG Markets and Uses" Energy Information Administration, Department of Energy, Washington, DC. June 2003. Available online at <http://www.eia.doe.gov/pub/ oil_gas/natural_gas/ feature_articles/2003/lng/lng2003.pdf>.

EIA (2004f) US Imports by Country. Energy Information Administration, Department of Energy, Washington, DC. Available online at http://tonto. eia.doe.gov/dnav/ ng/ng_move_top.asp

EIA (2002f) Table 6.5 Natural Gas Consumption by Sector, 1949 – 2001. Annual Energy Review. Energy Information Administration, Department of Energy, Washington, DC. Available online at <http://www.eia.doe.gov>.

EPA (2004). Natural Gas STAR Reductions 1990-2003. Natural Gas STAR Program.

EPA/GRI (1996) Methane Emissions from the Natural Gas Industry, Prepared by Harrison, M., T. Shires, J. Wessels, and R. Cowgill, eds. Radian International LLC for National Risk Management Research Laboratory, Air Pollution Prevention and Control Division, Research Triangle Park, NC, EPA-600/R-96-080a.

GSAM (1997) Gas Systems Analysis Model. Federal Energy Technology Center, U.S. Department of Energy. Washington, DC.

Kansas (2004). Kansas Geological Survey. Oil and Ga s Production Data, All Wells. University of Kansas. Available online at < http://www. kgs.ku.edu/PRS/petroDB.html>.

Lippman (2003). Rocky Mountain Regi on Second Quarter 2003 Production Repor t. Lippman Consulting, Inc.

MMS (1998, 1999, 2000, 2001, 2002a, 2003, 2004a) OCS Platform Activity. Minerals Management Service, U.S. Department of Interior. Available online at <http://www.mms.gov/stats>.

MMS (2004b) Gulf of Mexico Region Offshore Information. Minerals Management Service, U.S. Department of Interior. Available online at < http://www.gomr.mms.gov/homepg/offshore/fldresv/resvmenu.html>.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 298 MMS (2004c). Current Facts & Figures in the Pacific OC S Region as of December 31, 2003. Minerals Management Service, U.S. Department of Interior. Available online at < http://www.mms.gov/omm/pacific/ offshore/currentfacts.htm>.

MMS (2004d) Gulf of Mexico Region Products/Free Data. Mi nerals Management Service, U.S. Department of Interior. Available online at < http://www.gomr.mms. gov/homepg/pubinfo/freeasci/pla tform/freeplat.html>.

MMS (2002b) Emission Inventories of OCF Production and Development Activitie s in the Gulf of Mexico. MMS 2002-073. Minerals Management Service, U.S. Department of Interior.

MMS (2004e) Personal communication on 10/10/2003. Minerals Ma nagement Service, U.S. Department of Interior.

Montana (2004) Personal communicati on on 08/05/2004. Montana Board of O il and Gas Conservation, Billing Office.

OGJ (1999, 2000, 2001, 2002, 2003, 2004) “Worldwide Ga s Processing.” Oil & Gas Journal. PennWell Corporation, Tulsa, OK.

Oklahoma (2004). Coalbed Methane Completions database. Oklahoma Geological Survey.

OPS (2004a). Natural Gas Transmission Pipeline Annual M ileage. Office of Pipeline Safety, Department of Transportation. Washington, DC. Available online at <http://ops.dot.gov/stats >.

OPS (2004b). Distribution Annuals Data. Office of Pipeline Safety, Department of Transportation. Washington, DC. Available online at < http://ops.dot.gov/DT98.htm>.

Utah (2004) Personal communication on 08/10/2004. Utah Division of Oil, Gas and Mining.

Wyoming (2004). Wyoming Oil and Gas Conservation Commission. Available online at <http://wogcc.state.wy.us/coalbedchart.cfm>.

Municipal Solid Waste Combustion

APC (2000) as reported in “Facts & Figures for the Chemical Industry,” Chemical and Engineering News, Vol. 78 (26), June 26, 2000. American Plastics Council. Arlington, VA. Available online at <http://www.plasticsindustry.org/industry/stat3.htm>.

De Soete, G. G. (1993) Nitrous Oxide from Combustion and Industry: Chemistry, Emissions and Control . In Van Amstel, A. R. (ed) Proc. of the International Workshop Methane and Nitrous Oxide: Methods in National Emission Inventories and Options for Control, Amersfoort (NL) 3-5 February.

DeZan, D. (2000) Personal communication between Diane De Zan of the Fiber Economics Bureau and Joe Casola of ICF Consulting, August 4, 2000.

Eldredge-Roebuck, B. (2000) Personal communication between Brandt Eldredge-Roebuck of the American Plastics Council and Joe Casola of IC F Consulting, July 11, 2000.

EIA (Energy Information Administration). 2002. AEO2002 (Annual Energy Outlook), Appendix C, High Oil Price Case, Table 2. Energy Consumption by Sector and Source. Available online at



### < http://www.eia.doe.gov/oiaf/aeo/pdf/aeo_hm.pdf>.

EPA (2003) Characterization of Municipal Solid Waste in the United States: 2001 Update. (Draft) U.S. Environmental Protection Agency, Office of Solid Waste and Emergency Response, EPA. Washington, DC.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 299 EPA (2002a) Characterization of Municipal Solid Waste in the United States: 2000 Update . U.S. Environmental Protection Agency, Office of Solid Waste and Emergency Response, EPA. Washington, DC, EPA530-R-02-001.

EPA (2002b) Solid Waste Management and Greenhouse Gases: A Life-Cycle Assessment of Emissions and Sinks. U.S. Environmental Protection Agency, Office of Solid Waste and Emergency Response, Washington, DC, EPA530-R-98-013.

EPA (2001) Municipal Solid Waste in the United States: 1999 Facts and Figures . U.S. Environmental Protection Agency, Office of Solid Waste, EPA. Washington, DC, EPA530-R-01-014.

EPA (2000a) Characterization of Municipal Solid Waste in the United States: 1999 Update Fact Sheet (and Data Tables) . U.S. Environmental Protection Agency, Office of Solid Waste, EPA. Washington, DC, EPA530-F-00- 024.

EPA (2000b) Characterization of Municipal Solid Waste in the United States: Source Data on the 1999 Update

. U.S. Environmental Protection Agency, Office of Solid Waste, EPA. Washington, DC, EPA530-F-00-024.

EPA (1999) Characterization of Municipal Solid Waste in the United States: 1998 Update. Report No. EPA530-R99-021. U.S. Environmental Protection Agency, Office of Solid Waste, EPA. Washington, DC.

EPA (1998) Characterization of Municipal Solid Waste in the United States: 1997 Update. U.S. Environmental Protection Agency, Office of Solid Waste, EPA. Washington, DC, EPA530-R-98-007.

EPA (1997) Characterization of Municipal Solid Waste in the United States: 1996 Update. U.S. Environmental Protection Agency, Office of Solid Waste, EPA. Washington, DC, EPA530-R-97-015.

EPA (1996) Characterization of Municipal Solid Waste in the United States: 1995 Update. U.S. Environmental Protection Agency, Office of Solid Waste, EPA. Washington, DC.

EPA (1995) Compilation of Air Pollutant Emission Factors, AP-42 , Fifth Edition, Volume I: Stationary Point and Area Sources, Introduction. Office of Air Quality Planning and Standa rds, U.S. EPA. Research Triangle Park, NC. October.

FEB (2000) as reported in “Facts & Figures for the Chemical Industry,” Chemical and Engineering News, Vol. 78 (26), June 26, 2000. Fiber Economics Bureau. Washington, DC. Available online at <http://www.fibersource.com/f-info/fiber%20production.htm>.

Glenn, Jim (1999) “11 th Annual BioCycle Nationwide Survey: The State of Garbage in America.” BioCycle, April 1999. JG Press, Emmaus, PA.

Goldstein, N. and C. Madtes (2001) “13th Annual BioCycle Nationwide Survey: The State of Garbage in America,” BioCycle, December 2001. JG Press, Emmaus, PA.

Goldstein, N. and C. Madtes (2000) “12th Annual BioCycle Nationwide Survey: The State of Garbage in America, Part I,” BioCycle, November 2000. JG Press, Emmaus, PA.

IISRP (2000) as reported in “Facts & Figures for the Chemical Industry,” Chemical and Engineering News, Vol. 78 (26), June 26, 2000. International Ins titute of Synthetic Rubber Producers. H ouston, Texas. Available online in IISRP’s February 18, 2000, News Release: <http://www.iisrp.com/Press%20Releases/ 2000%20Press%20Releases/ASPR2000-2004.PDF>.

IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories. Intergovernmental Panel on Climate Change, IPCC Nati onal Greenhouse Gas Inventories Programme Technical Support Unit, Kanagawa, Japan. Available online at <http://www.ipcc-nggip.iges.or. jp/public/gp/gpgaum.htm>.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 300 IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Paris: Intergovernmental Panel on Climate Change, United Nati ons Environment Programme, Organization for Economic Co-Operation and Development, International Energy Agency.

Johnke (1999), as cited in Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories , Intergovernmental Panel on Climate Change, 2000.

Kaufman, et al. “14 th Annual BioCycle Nationwide Survey: The State of Garbage in America 2004” Biocycle
, January, 2004. JG Press, Emmaus, PA.

Kaufman, et al. "Corrections to State of Garbage 2004" Biocycle , April, 2004. JG Press, Emmaus, PA.

Kearney, A.T. (1992) Scrap Tire Use/Disposal Study 1992 Update . Scrap Tire Management Council, Washington, DC.

Kearney, A.T. (1990) Scrap Tire Use/Disposal Study Final Report . Scrap Tire Management Council, Washington, DC.

Miller, T. (1999) Material Safety Data Sheet, Carbon Black . Continental Carbon Company. Published September 1, 1999. Downloaded from <http ://www.continentalcarbon.com/downloa ds/MSDS.pdf>, October 10, 2003.

RMA (2002) U.S. Scrap Tire Markets 2001 . Rubber Manufacturers Association, Washington, DC. December 2002.

STMC (2003) Scrap Tire Facts and Figures. Scrap Tire Management Council of the Rubber Manufacturers Association. Washington, DC. Downloaded from <http://www.rma.org/scrap_tires/scrap_tire_markets/facts_and_figures/> and <http://www.rma.org/scrap_tires/scrap_tire_market s/scrap_tire_characteristics/>, July 7, 2003.

STMC (2002) Scrap Tire Facts and Figures. Scrap Tire Management Council of the Rubber Manufacturers Association. Washington, DC. Do wnloaded from <http://www.rma.org/scrap tires/facts_figures.html>, October 22, 2002.

STMC (2001) Scrap Tire Facts and Figures. Scrap Tire Management Council of the Rubber Manufacturers Association. Washington, DC. Do wnloaded from <http://www.rma.org/scrap tires/facts_figures.html>, September 5, 2001.

STMC (2000) Scrap Tire Facts and Figures. Scrap Tire Management Council of the Rubber Manufacturers Association. Washington, DC. Downloaded from <http://www.rma.org/scrapfctn.html>, July 26, 2000.

STMC (1999) Scrap Tire Use/Disposal St udy 1998/1999 Update Executive Summary . Scrap Tire Management Council of the Rubber Manufacturers Association. Washington, DC. Published September 15, 1999. Downloaded from <http://www.rma.org/excsumn.html>, July 26, 2000.

STMC (1997) Scrap Tire Use/Disposal Study 1996 Update . Scrap Tire Management Council, Washington, DC.

STMC (1995) Scrap Tire Use/Disposal Study 1994 Update . Scrap Tire Management Council, Washington, DC.

UK: Environment Agency (1999), as cited in Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories , Intergovernmental Panel on Climate Change, 2000.

U.S. Census Bureau (2000) Annual Projections of the Total Resident Population as of July 1: Middle, Lowest, Highest, and Zero International Migr ation Series, 1999 to 2100, February, <http://www.census.gov/population/projections/nation/summary/np-t1.txt>.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 301 Watanabe, M., Sato, M., Miyazak i, M. and Tanaka, M. (1992) Emission Rate of N 2 O from Municipal Solid Waste Incinerators . NIRE/IFP/EPA/SCEJ 5 th International Workshop on N 2 O Emissions, July 1-3, 1992. Tsukuba, Japan, Paper 3-4.

Yasuda (1993), as cited in Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories, Intergovernmental Panel on Climate Change, 2000.

Natural Gas Flaring and Ambient Air Pollutant Emissions from Oil and Gas Activities

Barns, D. and Edmonds, J. (1990) “An Evaluation of the Relationship Between the Production and Use of Energy and Atmospheric Methane Emissions.” DOE/NBB-0088P. Pacific Northwest Laboratory. Richland, WA.

EIA (2000) Natural Gas Annual 2000 , DOE/EIA 0131(00)-annual, Energy Information Administration, U.S. Department of Energy, Washington, DC. October 2001. Available online at <http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publi cations/historical_natural_gas_annual/historical/1999/p df/table_01.pdf>.

EIA (2001) Natural Gas Annual 2001 , DOE/EIA 0131(01)-annual, Energy Information Administration, U.S. Department of Energy, Washington, DC. February 2003. Available online at <http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publi cations/historical_natural_gas_annual/historical/2000/p df/table_05.pdf>.

EIA (2004) Natural Gas Monthly, Summary of Natural Gas Production in the United States . Available online at <http://tonto.eia.doe.gov/dna v/ng/hist/n9040us2a.htm>.

EPA (2003) E-mail correspondence containing preliminary am bient air pollutant data between EPA OAP and EPA OAQPS. December 22, 2003.

MMS (2003) Emissions Inventories of OCS Production and Development Activities in the Gulf of Mexico . A report by the Minerals Management Service. MMS OCS Report 2002 –073.

International Bunker Fuels

BEA (1991 through 2004) Unpublished BE-36 survey data. Bureau of Economic Analysis (BEA). U.S. Department of Commerce, Washington, DC.

DESC (2004) Unpublished data from the Defense Fuels Automated Management System (DFAMS). Defense Energy Support Center, Defense Logistics Agency, U.S. Department of Defense, Washington, DC.

DOC (1991 through 2004) Unpublished “Report of Bunker Fuel Oil Laden on Vessels Cleared for ForeignCountries.” Foreign Trade Division, Bureau of the Census, U.S. Department of Commerce, Washington, DC. Form563.

DOT (1991 through 2004) Fuel Cost and Consumption. Airline Information, Bureau of Transportation Statistics, U.S. Department of Transportation, Washington, DC.

EIA (2004) Monthly Energy Review, July 2004 and Unpublished Supplemental Tables on Petroleum Product detail. Energy Information Administration, U.S. Department of Energy, Washington, DC, DOE/EIA-0035(2004/07).

IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories. Paris: Intergovernmental Panel on Climate Change, United Nati ons Environment Programme, Organization for Economic Co-Operation and Development, International Energy Agency.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 302 NASA (1996) Scheduled Civil Aircraft Emission Inventories for 1992: Database Development and Analysis. Prepared for Langley Research Center, NASA Contractor Report # 4700, April.

USAF (1998) Fuel Logistics Planning. U.S. Air Force pamphlet AFPAM23-221, May 1,1998.

Wood Biomass and Ethanol Consumption

EIA (1997) Renewable Energy Annual. Energy Information Administration, U.S. Department of Energy. Washington, DC. March. DOE/EIA-0603(96)

EIA (2004) Annual Energy Review 2003. Energy Information Administration, U.S. Department of Energy. Washington, DC. July. Tables 10.2a and 10.2b. DOE/EIA-0384(2003).

Lindstrom, P. (2003) Personal communication between Matth ew Stanberry of ICF Cons ulting and Perry Lindstrom of the Energy Information Administration. November 2003.



### Industrial Processes

Iron and Steel Production

AISI (2004) 2003 Annual Statistical Report, Ameri can Iron and Steel Ins titute, Washington, DC.

AISI (2003) 2002 Annual Statistical Report, Ameri can Iron and Steel Ins titute, Washington, DC.

AISI (2002) 2001 Annual Statistical Report, Ameri can Iron and Steel Ins titute, Washington, DC.

AISI (2001) 2000 Annual Statistical Report, Ameri can Iron and Steel Ins titute, Washington, DC.

AISI (1996) 1995 Annual Statistical Report, Ameri can Iron and Steel Institu te, Washington, DC.

AISI (1995) 1994 Annual Statistical Report, Ameri can Iron and Steel Ins titute, Washington, DC.

DOE (1997) Office of Industrial Technologies - Energy and Environmental Profile of the U.S. Aluminum Industry, July 1997.

EIA (2004) Quarterly Coal Report January-December 2003, En ergy Information Administ ration, U.S. Department of Energy, Washington, DC. DOE/EIA-0121

EIA (2003) Quarterly Coal Report January-December 2002, En ergy Information Administ ration, U.S. Department of Energy, Washington, DC. DOE/EIA-0121

EIA (2002) Quarterly Coal Report January-March 2002, Energy Information Administration, U.S. Department of Energy, Washington, DC. DOE/EIA-0121 (2002/1Q).

EIA (2001) U.S. Coal, Domestic and International Issues, Energy Information Administration, U.S. Department of Energy, Washington, DC, March 2001.

EIA (2000) Quarterly Coal Report October-December 2000, En ergy Information Administ ration, U.S. Department of Energy, Washington, DC. DOE/EIA-0121 (2000/4Q).

IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories
, Intergovernmental Panel on Climate Change, National Greenhouse Gas Inventories Programme, Montreal, IPCCXVI/Doc. 10 (1.IV.2000), May 2000.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 303 IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Paris: Intergovernmental Panel on Climate Change, United Nati ons Environment Programme, Organization for Economic Co-Operation and Development, International Energy Agency.

USGS (2004a) Minerals Industry Surveys: Aluminum Annual Report 2003 . U.S. Geological Survey, Reston, VA.

USGS (2004b) Minerals Yearbook: Iron and Steel Report 2003 . U.S. Geological Survey, Reston, VA.

USGS (2003) Minerals Industry Surveys: Aluminum Annual Report 2002 . U.S. Geological Survey, Reston, VA.

USGS (2002a) Minerals Yearbook: Iron and Steel Report 2001 . U.S. Geological Survey, Reston, VA.

USGS (2002b) Minerals Industry Surveys: Aluminum Annual Report 2001 . U.S. Geological Survey, Reston, VA.

USGS (2002c) Minerals Yearbook: Iron Ore Report 2001 . U.S. Geological Survey, Reston, VA.

USGS (2001a) Minerals Yearbook: Iron and Steel Annual Report 2000 . U.S. Geological Survey, Reston, VA.

USGS (2001b) Minerals Industry Surveys: Aluminum Annual Report 2000 . U.S. Geological Survey, Reston, VA.

USGS (2001c) Minerals Yearbook: Iron Ore Report 2000 . U.S. Geological Survey, Reston, VA.

USGS (2000a) Minerals Yearbook: Iron and Steel Annual Report 1999 . U.S. Geological Survey, Reston, VA.

USGS (2000b) Minerals Industry Surveys: Aluminum Annual Report 1999 . U.S. Geological Survey, Reston, VA.

USGS (2000c) Minerals Yearbook: Iron Ore Report 1999 . U.S. Geological Survey, Reston, VA.

USGS (1999) Minerals Yearbook: Iron and Steel Annual Report 1998 . U.S. Geological Survey, Reston, VA.

USGS (1999b) Minerals Yearbook: Iron Ore Report 1998 . U.S. Geological Survey, Reston, VA.

USGS (1998) Minerals Industry Surveys: Aluminum Annual Report 1997 . U.S. Geological Survey, Reston, VA.

USGS (1998b) Minerals Yearbook: Iron Ore Report 1997 . U.S. Geological Survey, Reston, VA.

USGS (1997) Minerals Yearbook: Iron and Steel Annual Report 1996 . U.S. Geological Survey, Reston, VA.

USGS (1997b) Minerals Yearbook: Iron Ore Report 1996 . U.S. Geological Survey, Reston, VA.

USGS (1996) Minerals Yearbook: Iron Ore Report 1995 . U.S. Geological Survey, Reston, VA.

USGS (1995a) Minerals Yearbook: Iron and Steel Annual Report 1994 . U.S. Geological Survey, Reston, VA.

USGS (1995b) Minerals Industries Surveys: Aluminum Annual Review 1994 . U.S. Geological Survey, U.S. Department of the Interior. Washington, DC. May.

USGS (1995c) Minerals Yearbook: Iron Ore Report 1994 . U.S. Geological Survey, Reston, VA.

USGS (1994) Minerals Yearbook: Iron Ore Report 1993 . U.S. Geological Survey, Reston, VA.

USGS (1993) Minerals Yearbook: Iron and Steel Annual Report 1992 . U.S. Geological Survey, Reston, VA.

Cement ManufactureInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 304 IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories
, Intergovernmental Panel on Climate Change, National Greenhouse Gas Inventories Programme, Montreal, IPCCXVI/Doc. 10 (1.IV.2000), May 2000.

IPCC (1996) Climate Change 1995: The Science of Climate Change , Intergovernmental Panel on Climate Change; J.T. Houghton, L.G. Meira Filho, B.A. Callander, N. Ha rris, A. Kattenberg, and K. Maskell, eds.; Cambridge University Press. Cambridge, U.K.

USGS (2003) Minerals Yearbook: Cement Annual Report 2002. U.S. Geological Survey, Reston, VA.

USGS (2002) Minerals Yearbook: Cement Annual Report 2001. U.S. Geological Survey, Reston, VA.

USGS (2001) Minerals Yearbook: Cement Annual Report 2000 . U.S. Geological Survey, Reston, VA.

USGS (2000) Minerals Yearbook: Cement Annual Report 1999 . U.S. Geological Survey, Reston, VA.

USGS (1999) Minerals Yearbook: Cement Annual Report 1998 . U.S. Geological Survey, Reston, VA.

USGS (1998) Minerals Yearbook: Cement Annual Report 1997 . U.S. Geological Survey, Reston, VA.

USGS (1997) Minerals Yearbook: Cement Annual Report 1996 . U.S. Geological Survey, Reston, VA.

USGS (1996) Minerals Yearbook: Cement Annual Report 1995 . U.S. Geological Survey, Reston, VA.

USGS (1995a) Cement: Annual Report 1993. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC. June.

USGS (1995b) Cement: Annual Report 1994. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC.

USGS (1992) Cement: Annual Report 1990. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC. April.

Van Oss (2004) Telephone Conve rsations between Rebecca LePrell of ICF Consulting and Hendrik Van Oss, Commodity Specialist, USGS, 17 August.

Ammonia Manufacture and Urea Application

Bark (2004) Coffeyville Nitrogen Plant. Available online at < http://www.gasification.org/ Docs/2003_Papers/07BARK.pdf > Accessed: Dec. 15 2004.

EIA (1998) Manufacturing Energy C onsumption Survey (MECS) U.S. Department of Energy, Energy Information Administration, Washington D.C. Available online at <http://www.eia.doe.gov/emeu/mecs/mecs98/datatables/contents.html>.

EIA (1994) Manufacturing Energy C onsumption Survey (MECS) U.S. Department of Energy, Energy Information Administration, Washington D.C.

EFMA (1995) Production of Ammonia. European Fertilizer Manufacturers Association. March 1.

EPA (1997) National Air Pollutant Emissions Trends Report, 1900-1996. U.S. Environmental Protection Agency, Office of Air Quality Planning and Sta ndards, Research Triangle Park, NC.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 305 TFI (2002) U.S. Nitrogen Imports/Exports Table, The Fertilizer Institu te. Accessed online at <http://www.tfi.org/statistics/usnexim.asp>, August 2002.

U.S. Census Bureau (2004) Current Industrial Reports Fertilizer Mate rials and Related Products: Fourth Quarter Report 2003 Summary . Available online at <http://www.census.gov/cir/www/325/mq325b.html>.

U.S. Census Bureau (2003) Current Industrial Reports Fertilizer Mate rials and Related Produc ts: Annual Reports 2002 Summary . Available online at <http://www.census.gov/cir/www/325/mq325b.html>.

U.S. Census Bureau (2002a) Current Industrial Reports Fertilizer Mate rials and Related Products: First Quarter 2002 . June 2002. Available online at <h ttp://www.census.gov/cir/ www/325/mq325b.html>.

U.S. Census Bureau (2002b) Current Industrial Reports Fertilizer Mate rials and Related Products: Fourth Quarter 2001 . March 2002. Available online at <h ttp://www.census.gov/cir/ www/325/mq325b.html>.

U.S. Census Bureau (2002c) Current Industrial Reports Fertilizer Mate rials and Related Products: Third Quarter 2001 . January 2002. Available online at <h ttp://www.census.gov/cir/ www/325/mq325b.html>.

U.S. Census Bureau (2001a) Current Industrial Reports Fertilizer Mate rials and Related Products: Second Quarter 2001 . September 2001. Available online at <http://www.census.gov/ci r/www/325/mq325b.html>.

U.S. Census Bureau (2001b) Current Industrial Reports Fertilizer Ma terials and Related Products: Annual Report 2000. Available online at <http://www.census.gov/cir/www/325/mq325b.html>.

U.S. Census Bureau (2000) Current Industrial Reports Fertilizer Ma terials and Related Products: Annual Report 1999. Available online at <http://www.census.gov/cir/www/325/mq325b.html>.

U.S. Census Bureau (1999) Current Industrial Reports Fertilizer Ma terials and Related Products: Annual Report 1998. Available online at <http://www.census.gov/cir/www/325/mq325b.html>.

U.S. Census Bureau (1998) Current Industrial Reports Fertilizer Ma terials and Related Products: Annual Report 1997. Available online at <http://www.census.gov/cir/www/325/mq325b.html>.

U.S. Census Bureau (1994) Current Industrial Reports Fertilizer Materials Annual Report 1993, Report No. MQ28B.

U.S. Census Bureau (1993) Current Industrial Reports Fertilizer Materials Annual Report 1992, Report No. MQ28B.

U.S. Census Bureau (1992) Current Industrial Reports Fertilizer Materials Annual Report 1991, Report No. MQ28B.

U.S. Census Bureau (1991) Current Industrial Reports Fertilizer Materials Annual Report 1990, Report No. MQ28B.

U.S. ITC (2002) United States International Trade Commission Interactive Tariff and Trade DataWeb, Version 2.5.0. Accessed online at <http ://dataweb.usitc.gov/scripts/user_s et.asp>. Accessed August, 2002.

Lime Manufacture

IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories
, Intergovernmental Panel on Climate Change, National Greenhouse Gas Inventories Programme, Montreal, IPCCXVI/Doc. 10 (1.IV.2000), May 2000.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 306 Males, E. (2003) Public review comments received in a memorandum from Eric Males, National Lime Association to Mr. William N. Irving & Mr. Leif Hockstad, Environm ental Protection Agency. Memorandum dated March 6, 2003.

USGS (2004) Minerals Yearbook: Lime Annual Report 2003 . U.S. Geological Survey, Reston, VA.

USGS (2003) Minerals Yearbook: Lime Annual Report 2002 . U.S. Geological Survey, Reston, VA.

USGS (2002) Minerals Yearbook: Lime Annual Report 2001 . U.S. Geological Survey, Reston, VA.

USGS (2001) Minerals Yearbook: Lime Annual Report 2000 . U.S. Geological Survey, Reston, VA.

USGS (2000) Minerals Yearbook: Lime Annual Report 1999 . U.S. Geological Survey, Reston, VA.

USGS (1999) Minerals Yearbook: Lime Annual Report 1998 . U.S. Geological Survey, Reston, VA.

USGS (1998) Minerals Yearbook: Lime Annual Report 1997 . U.S. Geological Survey, Reston, VA.

USGS (1997) Minerals Yearbook: Lime Annual Report 1996 . U.S. Geological Survey, Reston, VA.

USGS (1996) Minerals Yearbook: Lime Annual Report 1995 . U.S. Geological Survey, Reston, VA.

USGS (1995) Minerals Yearbook: Lime Annual Report 1994 . U.S. Geological Survey, Reston, VA.

USGS (1994) Lime: Annual Report 1993. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC. September.

USGS (1992) Lime: Annual Report 1991. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC. November.

Limestone and Dolomite Use

Tepordei (2004) Telephone Conve rsations between Matthew Stanberry of ICF Consulting and Valentin Tepordei, Commodity Specialist, USGS, 20 October.

Tepordei (2003) Telephone Conve rsations between Matthew Stanberry of ICF Consulting and Valentin Tepordei, Commodity Specialist, USGS, 23 October– 31 October.

Tepordei (2002) Telephone Conve rsations between Matthew Stanberry of ICF Consulting and Valentin Tepordei, Commodity Specialist, USGS, 29 October– 8 November.

USGS (2004a) Minerals Yearbook: Crushe d Stone Annual Report 2003 . U.S. Geological Survey, Reston, VA.

USGS (2004b) Minerals Yearbook: Magnesium Annual Report 2003 . U.S. Geological Survey, Reston, VA.

USGS (2003a) Minerals Yearbook: Crushe d Stone Annual Report 2002 . U.S. Geological Survey, Reston, VA.

USGS (2003b) Minerals Yearbook: Magnesium Annual Report 2002 . U.S. Geological Survey, Reston, VA.

USGS (2002a) Minerals Yearbook: Crushe d Stone Annual Report 2001 . U.S. Geological Survey, Reston, VA.

USGS (2002b) Minerals Yearbook: Magnesium Annual Report 2001 . U.S. Geological Survey, Reston, VA.

USGS (2001a) Minerals Yearbook: Crushe d Stone Annual Report 2000 . U.S. Geological Survey, Reston, VA.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 307 USGS (2001b) Minerals Yearbook: Magnesium Annual Report 2000 . U.S. Geological Survey, Reston, VA.

USGS (2000a) Minerals Yearbook: Crushe d Stone Annual Report 1999 . U.S. Geological Survey, Reston, VA.

USGS (2000b) Minerals Yearbook: Magnesium Annual Report 1999 . U.S. Geological Survey, Reston, VA.

USGS (1999a) Minerals Yearbook: Crushe d Stone Annual Report 1998 . U.S. Geological Survey, Reston, VA.

USGS (1999b) Minerals Yearbook: Magnesium Annual Report 1998 . U.S. Geological Survey, Reston, VA.

USGS (1998a) Minerals Yearbook: Crushe d Stone Annual Report 1997 . U.S. Geological Survey, Reston, VA.

USGS (1998b) Minerals Yearbook: Magnesium Annual Report 1997 . U.S. Geological Survey, Reston, VA.

USGS (1997a) Minerals Yearbook: Crushe d Stone Annual Report 1996 . U.S. Geological Survey, Reston, VA.

USGS (1997b) Minerals Yearbook: Magnesium Annual Report 1996 . U.S. Geological Survey, Reston, VA.

USGS (1996a) Minerals Yearbook: Crushe d Stone Annual Report 1995 . U.S. Geological Survey, Reston, VA.

USGS (1996b) Minerals Yearbook: Magnesium Annual Report 1995 . U.S. Geological Survey, Reston, VA.

USGS (1995a) Crushed Stone: Annual Report 1993 . U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC. January.

USGS (1995b) Crushed Stone: Annual Report 1994 . U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC.

USGS (1995c) Magnesium: Annual Report 1994 . U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC.

USGS (1993) Crushed Stone: Annual Report 1991. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC. March.

Soda Ash Manufacture and Consumption

USGS (2004) Minerals Industry Surveys: Soda Ash 2003 . U.S. Geological Survey, Reston, VA.

USGS (2003) Minerals Yearbook: Soda Ash Annual Report 2002. U.S. Geological Survey, Reston, VA.

USGS (2002) Minerals Yearbook: Soda Ash Annual Report 2001 . U.S. Geological Survey, Reston, VA.

USGS (2001) Minerals Yearbook: Soda Ash Annual Report 2000 . U.S. Geological Survey, Reston, VA.

USGS (2000) Minerals Yearbook: Soda Ash Annual Report 1999 . U.S. Geological Survey, Reston, VA.

USGS (1999) Minerals Yearbook: Soda Ash Annual Report 1998 . U.S. Geological Survey, Reston, VA.

USGS (1998) Minerals Yearbook: Soda Ash Annual Report 1997 . U.S. Geological Survey, Reston, VA.

USGS (1997) Minerals Yearbook: Soda Ash Annual Report 1996 . U.S. Geological Survey, Reston, VA.

USGS (1996) Minerals Yearbook: Soda Ash Annual Report 1995 . U.S. Geological Survey, Reston, VA.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 308 USGS (1995) Minerals Yearbook: Soda Ash Annual Report 1994 . U.S. Geological Survey, Reston, VA.

USGS (1994) Soda Ash: Annual Report 1993 . U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC. July.

Titanium Dioxide Production

Gambogi, J.(2004). Telephone conversa tion between Rebecca LePrell of IC F Consulting and Joseph Gambogi, Commodity Specialist, U.S. Geological Survey, 27 August.

Gambogi, J.(2002). Telephone conversa tion between Philip Groth of IC F Consulting and Joseph Gambogi, Commodity Specialist, U.S. Geological Survey, 13 November.

Onder, H, and E.A. Bagdoyan (1993) Everything You’ve Always Wanted to Know about Petroleum Coke. Allis Mineral Systems.

USGS (2003) Mineral Yearbook: Titanium Annual Report 2002. U.S. Geological Survey, Reston, VA.

USGS (2002) Mineral Yearbook: Titanium Annual Report 2001. U.S. Geological Survey, Reston, VA.

USGS (2001) Mineral Yearbook: Titanium Annual Report 2000. U.S. Geological Survey, Reston, VA.

USGS (2000) Mineral Yearbook: Titanium Annual Report 1999. U.S. Geological Survey, Reston, VA.

USGS (1999) Minerals Yearbook: Titanium Annual Report 1998. U.S. Geological Survey, Reston, VA.

USGS (1998) Minerals Yearbook: Titanium Annual Report 1997. U.S. Geological Survey, Reston, VA.

USGS (1997) Minerals Yearbook: Titanium Annual Report 1996. U.S. Geological Survey, Reston, VA.

USGS (1996) Minerals Yearbook: Titanium Annual Report 1995. U.S. Geological Survey, Reston, VA.

USGS (1995) Minerals Yearbook: Titanium Annual Report 1994. U.S. Geological Survey, Reston, VA.

USGS (1994) Minerals Yearbook: Titanium Annual Report 1993. U.S. Geological Survey, Reston, VA.

USGS (1993) Minerals Yearbook: Titanium Annual Report 1992. U.S. Geological Survey, Reston, VA.

USGS (1992) Minerals Yearbook: Titanium Annual Report 1991. U.S. Geological Survey, Reston, VA.

USGS (1991) Minerals Yearbook: Titanium Annual Report 1990. U.S. Geological Survey, Reston, VA.

Phosphoric Acid

EFMA (2000) European Fertilizer Manuf acturers Association Best Availabl e Techniques for Pollution Prevention and Control in the European Fertilizer Industry -- Booklet No. 4 of 8: Pr oduction of Phosphoric Acid. Available online at <http://www.efma.org/Publications/BAT%202000/Bat04/section04.asp>

FIPR (2003) Florida Institute of Phosphate Research, Anal yses of Some Phosphate Rocks, facsimile from Mr. Gary Albarelli, FIPR, Bartow, Florida, to Mr. R obert Lanza, ICF Cons ulting, July 29, 2003

FIPR (2003a) Florida Institute of Phosphate Research, personal communication of Mr. Michael Lloyd, Laboratory Manager, FIPR, Bartow, Florida, to Mr. Robert Lanza, ICF Consulting, August 2003.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 309 USGS (2004) Minerals Yearbook. Phosphate Rock Annual Report 2003. U.S. Geological Survey, Reston, VA.

USGS (2003) Electronic mail from Mr. Stephen M Jasinski, USGS Commodity Specialist, Phosphate Rock, [sjasinsk@usgs.gov] to Mr . Robert Lanza, ICF C onsulting, July 30, 2003.

USGS (2003a) Electronic mail from Mr. Stephen M Jasinski, USGS Commodity Specialist, Phosphate Rock, [sjasinsk@usgs.gov] to Mr . Robert Lanza, ICF C onsulting, August 11, 2003.

USGS (2002) Minerals Yearbook. Phosphate Rock Annual Report 2001. U.S. Geological Survey, Reston, VA.

USGS (2001) Minerals Yearbook. Phosphate Rock Annual Report 2000. U.S. Geological Survey, Reston, VA.

USGS (2000) Minerals Yearbook. Phosphate Rock Annual Report 1999. U.S. Geological Survey, Reston, VA.

USGS (1999) Minerals Yearbook. Phosphate Rock Annual Report 1998. U.S. Geological Survey, Reston, VA.

USGS (1998) Minerals Yearbook. Phosphate Rock Annual Report 1997. U.S. Geological Survey, Reston, VA.

USGS (1997) Minerals Yearbook. Phosphate Rock Annual Report 1996. U.S. Geological Survey, Reston, VA.

USGS (1996) Minerals Yearbook. Phosphate Rock Annual Report 1995. U.S. Geological Survey, Reston, VA.

USGS (1995) Minerals Yearbook. Phosphate Rock Annual Report 1994. U.S. Geological Survey, Reston, VA.

Ferroalloy Production

Corathers, L. (2004) Telephone conversation between Chri stopher Steuer of ICF Consu lting and Lisa Corathers, Commodity Specialist, U.S. Geological Survey, 21 October.

IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Paris: Intergovernmental Panel on Climate Change, United Nati ons Environment Programme, Organization for Economic Co-Operation and Development, International Energy Agency.

Onder, H, and E.A. Bagdoyan (1993) Everything You’ve Always Wanted to Know about Petroleum Coke. Allis Mineral Systems.

USGS (2003) Minerals Yearbook: Silicon Annual Report 2002. U.S. Geological Survey, Reston, VA

USGS (2002) Minerals Yearbook: Silicon Annual Report 2001. U.S. Geological Survey, Reston, VA.

USGS (2001) Minerals Yearbook: Silicon Annual Report 2000. U.S. Geological Survey, Reston, VA.

USGS (2000) Minerals Yearbook: Silicon Annual Report 1999. U.S. Geological Survey, Reston, VA.

USGS (1999) Minerals Yearbook: Silicon Annual Report 1998. U.S. Geological Survey, Reston, VA.

USGS (1998) Minerals Yearbook: Silicon Annual Report 1997. U.S. Geological Survey, Reston, VA.

USGS (1997) Minerals Yearbook: Silicon Annual Report 1996. U.S. Geological Survey, Reston, VA.

USGS (1996) Minerals Yearbook: Silicon Annual Report 1995. U.S. Geological Survey, Reston, VA.

USGS (1995) Minerals Yearbook: Silicon Annual Report 1994. U.S. Geological Survey, Reston, VA.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 310 USGS (1994) Silicon: Annual Report 1993. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC.

USGS (1993) Silicon: Annual Report 1992. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC.

USGS (1992) Silicon: Annual Report 1991. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC.

USGS (1991) Silicon: Annual Report 1990. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC.

Carbon Dioxide Consumption

Allis, R. et al. (2000) Natural CO 2 Reservoirs on the Colorado Plateau and Southern Rocky Mountains: Candidates for CO 2 Sequestration. Utah Geological Survey and Utah En ergy and Geoscience Institute, Salt Lake City, Utah.

Broadhead, R. (2003) Electronic mail from Mr. Ron Broadhead, New Mexico Bureau of Geology and Mineral Resources [ ron@gis.nmt.edu ] to Ms. Robin Petrusak, ICF Consulting, September 5, 2003.

Denbury Resources Inc. (2004) Annual Report, 2003, Page 41.

Denbury Resources Inc. (2003a) Blue Source’s Emission Re duction Credit (ERC) Protocol for Denbury Resources’ Geologic Sequestration of Recycle CO 2 for Enhanced Oil Recovery Operations, prepared by URS Corporation, November 2002.

Denbury Resources Inc. (2003b) Annual Report, 2002, Page 14.

Denbury Resources Inc. (2002) Annual Report, 2001, Page 22

. Hangebrauk, R.P., Borgwardt, R.H., and Geron, C.D. (1992) Carbon Dioxide Sequestration. U.S. Environmental.

Sim, P.H. (2001) Ammonia Shutdowns Drain CO 2 Supply and Boost Prices. Chemical Week . August 22, 2001.

U.S. Census Bureau (2004). Current Industrial Reports Industrial Gases: 2003.

U.S. Census Bureau (2003). Current Industrial Reports Industrial Gases: 2002.

U.S. Census Bureau (2001). Current Industrial Reports Industrial Gases: 2000.

U.S. Census Bureau (1999). Current Industrial Reports Industrial Gases: 1998.

U.S. Census Bureau (1997). Current Industrial Reports Industrial Gases: 1996.

U.S. Census Bureau (1995). Manufacturing Profile Industrial Gases: 1994.

U.S. Census Bureau (1993). Current Industrial Reports Industrial Gases: 1992. Data provided by Mr. Kevin Woynes of the U.S. Census Bureau.

Petrochemical Production

ACC (2003) Guide to the Business of Chemistry. American Chemistry Council. Arlington, VA.

ACC (2002) Guide to the Business of Chemistry. American Chemistry Council. Arlington, VA.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 311 CMA (1999) U.S. Chemical Industry Statistical Handbook. Chemical Manufacturer’s Association. Washington, DC.

EIA (2004) Annual Energy Review 2003. Energy Information Administration, U.S. Department of Energy, Washington, DC. DOE/EIA-0384(2003). September.

EIA (2003) Emissions of Greenhouse Gases in the United States 2002. Office of Integrated Analysis and Forecasting, Energy Information Admi nistration, U.S. Depart ment of Energy, Wash ington, DC. DOE-EIA0573(2002). February.

European IPPC Bureau (2004) Draft Reference Document on Best Available Techniques in the Large Volumen Inorganic Chemicals – Solid and Others Industry. European Commission. Page 224, Table 4.21. August 2004.

IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Paris: Intergovernmental Panel on Climate Change, United Nati ons Environment Programme, Organization for Economic Co-Operation and Development, International Energy Agency.

Johnson, G. L. (2003) Personal communication between Caren Mintz of ICF Consu lting and Greg Johnson of Liskow & Lewis, on behalf of the International Carbon Bl ack Association (ICBA). Data received in an email on November 5, 2003.

Othmer, Kirk (1992) Carbon (Carbon Black). Volume 4 . Page 1045.

Srivastava, Manoj, I.D. Singh, and Himmat Singh (1999) Structural Characterization of Petroleum Based Feedstocks for Carbon Black Production. Petroleum Science and Technology . 17(1&2), 67-80, Table-1.

The Innovation Group (2004) Carbon Black Pl ant Capacity. <http://www.the-innovationgroup.com/ChemProfiles/Carbon%20Black.htm>.

U.S. Census Bureau (2004) 2002 Economic Census: Manufacturing – Industry Series: Carbon Black Manufacturing . Department of Commerce, Washington, DC. EC02-311-325182. September 2004.

U.S. Census Bureau (1999) 1997 Economic Census: Manufacturing - Industry Series: Carbon Black Manufacturing . Department of Commerce, Washington, DC. EC97M-3251F. August 1999.

U.S. International Trade Commission (2004a) HTS – 2707995010: Carbon Black Feedstock. U.S. Domestic Exports. <http://dataweb.usitc.gov>.

U.S. International Trade Commission (2004b) HTS – 2707: Oils and Other Products of the Distillation of High Temperature Coal Tar; Similar Products in which the Weight of Aromatic Constituents Predominate. U.S. General Imports. <http://dataweb.usitc.gov>.

Silicon Carbide Production

IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Paris: Intergovernmental Panel on Climate Change, United Nati ons Environment Programme, Organization for Economic Co-Operation and Development, International Energy Agency.

USGS (2004) Minerals Yearbook: Manufactured Abrasives Annual Report 2003. U.S. Geological Survey, Reston, VA.

USGS (2003) Minerals Yearbook: Manufactured Abrasives Annual Report 2002. U.S. Geological Survey, Reston, VA.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 312 USGS (2002) Minerals Yearbook: Manufactured Abrasives Annual Report 2001. U.S. Geological Survey, Reston, VA.

USGS (2001) Minerals Yearbook: Manufactured Abrasives Annual Report 2000. U.S. Geological Survey, Reston, VA.

USGS (2000) Minerals Yearbook: Manufactured Abrasives Annual Report 1999. U.S. Geological Survey, Reston, VA.

USGS (1999) Minerals Yearbook: Manufactured Abrasives Annual Report 1998. U.S. Geological Survey, Reston, VA.

USGS (1998) Minerals Yearbook: Manufactured Abrasives Annual Report 1997. U.S. Geological Survey, Reston, VA.

USGS (1997) Minerals Yearbook: Manufactured Abrasives Annual Report 1996. U.S. Geological Survey, Reston, VA.

USGS (1996) Minerals Yearbook: Manufactured Abrasives Annual Report 1995. U.S. Geological Survey, Reston, VA.

USGS (1995) Minerals Yearbook: Manufactured Abrasives Annual Report 1994. U.S. Geological Survey, Reston, VA.

USGS (1994) Manufactured Abrasives: Annual Report 1993. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC.

USGS (1993) Manufactured Abrasives: Annual Report 1992. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC.

USGS (1992) Manufactured Abrasives: Annual Report 1991. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC.

USGS (1991) Manufactured Abrasives: Annual Report 1990. U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC.

Nitric Acid Production

C&EN (2004) “Facts and Figures in the Chemical Industry.” Chemical and Engineering News, July 5, 2004, pg 54.

C&EN (2003) “Facts and Figures in the Chemical Industry.” Chemical and Engineering News, July 27, 2003, pg 56.

C&EN (2002) “Facts and Figures in the Chemical Industry.” Chemical and Engineering News, June 24, 2002, pg 62.

C&EN (2001) “Facts and Figures in the Chemical Industry.” Chemical and Engineering News, June 25, 2001, pg 46.

Choe, J.S., P.J. Cook, and F.P. Petrocelli (1993) “Developing N 2 O Abatement Technology for the Nitric Acid Industry.” Prepared for presentation at the 1993 ANPSG Conference. Air Products and Chemicals, Inc., Allentown, PA.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 313 IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories
, Intergovernmental Panel on Climate Change, Nationa l Greenhouse Inventories Porgramme, Montreal, IPCCXVI/Doc. 10 (1.IV.2000), May 2000, pg 3.35.

EPA (1997) Compilation of Air Pollutant Emission Factors, AP-42 , U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC, October.

Adipic Acid Production

ACC (2003) “Adipic Acid Production.” Table 3.12 - Production of the Top 100 Chemicals. American Chemistry Council Guide to the Business of Chemistry, August 2003.

C&EN (1995) “Production of Top 50 Chemicals Increased Substantially in 1994.” Chemical and Engineering News . 73(15): 17. April 10, 1995.

C&EN (1994) “Top 50 Chemicals Production Rose Modestly Last Year.” Chemical & Engineering News , 72(15): 13. April 11, 1994.

C&EN (1993) “Top 50 Chemicals Production Recovered Last Year.” Chemical & Engineering News , 71(15): 11. April 12, 1993.

C&EN (1992) “Production of Top 50 Chemicals Stagnates in 1991.” Chemical and Engineering News, 70(15): 17. April 13, 1992.

Childs, D. (2003). Personal communication between Dave Childs of DuPont, USA and Duncan Rotherham of ICF Consulting, USA. August 7, 2003.

Childs, D. (2002). Personal communication between Dave Childs of DuPont, USA and Laxmi Palreddy of ICF, Consulting, USA. August 8, 2002.

CMR (2001) “Chemical Profile: Adipic Acid.” Chemical Market Reporter , July 16, 2001.

CMR (1998) “Chemical Profile: Adipic Acid.” Chemical Market Reporter , June 15, 1998.

CW (1999) “Product Focus: Adipic Acid/Adiponitrile.” Chemical Week , March 10, 1999, pg. 31.

Linak, Eric (2003) Abstract from Chemical Economics Handbook Report – Adipic Acid , March. <http://ceh.sric.sri.com/Public/Reports/608.5000/>.

IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories
, Intergovernmental Panel on Climate Change, Nationa l Greenhouse Inventories Porgramme, Montreal, IPCCXVI/Doc. 10 (1.IV.2000), May 2000, pg 3.34.

Reimer, R. (1999). Personal communication between Ron Re imer of DuPont, USA and Heike Mainhardt of ICF, Consulting. May 19, 1999.

Substitution of Ozone Depleting Substances

IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Paris: Intergovernmental Panel on Climate Change, United Nati ons Environment Programme, Organization for Economic Co-Operation and Development, International Energy Agency.

HCFC-22 ProductionInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 314 ARAP (2004). Electronic mail communica tion from Dave Stirpe, Executive Di rector, Alliance for Responsible Atmospheric Policy, to Deborah Ottinger, EPA. June 3, 2004.

ARAP (2003). Electronic mail communica tion from Dave Stirpe, Executive Di rector, Alliance for Responsible Atmospheric Policy, to Sally Rand, EPA. August 18, 2003.

ARAP (2002). Electronic mail communica tion from Dave Stirpe, Executive Di rector, Alliance for Responsible Atmospheric Policy, to Deborah Ottinger, EPA. August 7, 2002.

ARAP (2001). Electronic mail communica tion from Dave Stirpe, Executive Di rector, Alliance for Responsible Atmospheric Policy, to Deborah Ottinger, EPA. August 6, 2001.

ARAP (2000). Electronic mail communi cation from Dave Stirpe, Executive Di rector, Alliance for Responsible Atmospheric Policy, to Sally Rand, EPA. August 13, 2000.

ARAP (1999). Facsimile from Dave Stirpe, Executive Dir ector, Alliance for Responsible Atmospheric Policy, to Deborah Ottinger Schaefer, EPA. September 23, 1999.

ARAP (1997). Letter from Dave Stirpe, Director, Allian ce for Responsible Atmospheric Policy, to Elizabeth Dutrow, EPA. December 23, 1997.

Rand, S., M. Branscome, and D. Ottinger (1999) “Oppor tunities for the Reduction of HFC-23 Emissions from the Production of HCFC-22.” In: Proceedings from the Joint IPCC/TEAP Expert Meeting On Options for the Limitation of Emissions of HFCs and PFCs. Petten, the Netherlands, 26-28 May 1999.

RTI (1997). “Verification of Emission Estimates of HFC-23 from the Production of HCFC-22: Emissions from 1990 through 1996.” Report prepared by Research Triangle Institute for the Cadmus Group. November 25, 1997; revised February 16, 1998.

Electrical Transmission and Distribution

IPCC (2001), Good Practice Guidance and Uncertainty Ma nagement in National Greenhouse Gas Inventories, Intergovernmental Panel on Climate Cha nge. Available online at <http://www.ipccnggip.iges.or.jp/public/gp/pdf/3_Industry.pdf>.

M. Maiss and CAM Brenninkmeijer (2000) “A reversed trend in emissions of SF 6 to the atmosphere?” Non-CO 2 Greenhouse Gases: Scientific Underst anding, Control, and Implementati on, Proceedings of the Second International Symposium, Noordwijkerhout, The Netherlands, 8-10 September 1999, Kluwer Academic Publishers, 2000, p. 199.

O’Connell, P., F. Heil, J. Henriot, G. Mauthe, H. Morris on, L. Neimeyer, M. Pittroff, R. Probst, J.P. Tailebois (2002), SF 6 in the Electric Industry, Status 2000, Cigre, February 2002



### . RAND (2002) Katie D. Smythe, RAND Environmental Scien ce and Policy Center, “Production and Distribution of SF 6 by End-Use Application,” International Conference on SF 6 and the Environment: Emission Reduction Strategies. San Diego, CA, November 21-22, 2002.

UDI (2004) 2004 UDI Directory of Electric Power Producers and Distributors, 112 th Edition, Platts.

UDI (2001) 2001 UDI Directory of Electric Power Producers and Distributors, 109 th Edition, Platts.

Aluminum ProductionInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 315 EPA (1993) Proceedings: Workshop on Atmospheric Effects, Origins, and Options for Control of Two Potent Greenhouse Gases: CF 4 and C 2 F

6 , Sponsored by the U.S. Environmental Protection Agency, Global Change Division, Office of Air and Radiation, April 21-22.

Gariepy, B. and G. Dube (1992) “Treating Aluminum with Chlorine.” U.S. Patent 5,145,514. Issued September 8, 1992.

IAI (2000), Anode Effect Survey 1994-1997 and Perfluorocarbon Compounds Emissions Survey 1990-1997, International Aluminum Ins titute, London, United Kingdom. 2000.

IPCC (2001) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories
, Intergovernmental Panel on Climate Change, National Greenhouse Gas Inventories Programme, Montreal, IPCCXVI/Doc. 10 (1.IV.2000), May 2000.

IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Paris: Intergovernmental Panel on Climate Change, United Nati ons Environment Programme, Organization for Economic Co-Operation and Development, International Energy Agency.

Ko, M.K.W., N.D. Sze, W.-C. Wang, G. Shia, A. Goldman, F.J. Murcray, D.G. Murcray, and C.P. Rinsland (1993) “Atmospheric Sulfur Hexafluoride: Sources, Sinks, and Greenhouse Warming.” Journal of Geophysical Research, 98, 10499-10507.

MacNeal, J., T. Rack, and R. Corns (1990) “Process for Degassing Aluminum Melts with Sulfur Hexafluoride.” U.S. Patent 4,959,101. Issued September 25, 1990.

Maiss, M. and C.A.M. Brenninkmeijer (1998) “Atmospheric SF 6 : Trends, Sources and Prospects,” Environmental Science and Technology , v. 32, n. 20, pp. 3077-3086.

Ten Eyck, N. and M. Lukens (1996) “Process for Trea ting Molten Aluminum with Chlorine Gas and Sulfur Hexafluoride to Remove Impurities.” U.S. Patent 5,536,296. Issued July 16, 1996.

USAA (2004) Primary Aluminum Statistics . U.S. Aluminum Association, Washington, DC. January 2004.

USGS (2004) Mineral Commodity Summaries . U.S. Geological Survey, Reston, VA.

USGS (2003) Mineral Commodity Summaries . U.S. Geological Survey, Reston, VA.

USGS (2002) Mineral Yearbook: Aluminum Annual Report 2001. U.S. Geological Survey, Reston, VA.

USGS (2001) Minerals Yearbook: Aluminum Annual Report 2000. U.S. Geological Survey, Reston, VA.

USGS (2000) Minerals Yearbook: Aluminum Annual Report 1999. U.S. Geological Survey, Reston, VA.

USGS (1998) Minerals Yearbook: Aluminum Annual Report 1997. U.S. Geological Survey, Reston, VA.

USGS (1995) Mineral Industry Surveys: Al uminum Annual Review 1994 . U.S. Geological Survey, U.S. Department of the Interior, formerly Bureau of Mines. Washington, DC. May.

Victor, D.G. and G.J. MacDonald (1998) “A Model for Estimating Future Emissions of Sulfur Hexafluoride and Perfluorcarbons.” Interim Report for the International Institute for Applied Sy stems Analysis (IIASA), July, 1998. Downloaded from the IIASA website <http://www.iiasa.ac.at/>, May 23, 2000.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 316 Zurecki, Z. (1996) “Effect of Atmosphere Com position on Homogenizi ng Al-Mg and Al-Li Alloys.” Gas Interactions in Nonferrous Metals Processing - Proceed ings of the 1996 125th The Mine rals, Metals & Materials Society (TMS) Annual Meeting (Anaheim, CA, USA), pp. 77-93.

Semiconductor Manufacture

Burton, C.S., and R, Beizaie (2001) “EPA’s PFC Emissions Model (PEVM) v. 2.14: Description and Documentation” prepared for Office of Global Programs, U. S. Environmental Protection Agency, Washington, DC. 20001 November 2001.

Burton, C.S., and D. Lieberman (2003) “PFC Reduction/Climate Partnership: Emission and Documentation Trends,” Draft Report, prepared for Office of Atmospheric Programs, U. S. Environmental Protection Agency, Washington, DC. 2001. August 2003.

International SEMATECH. International Technology Roadmap: 2000 Update . <http://public.itrs.net>

IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories
, Intergovernmental Panel on Climate Change, National Greenhouse Gas Inventories Programme, Montreal, IPCCXVI/Doc. 10 (1.IV.2000), May 2000.

Semiconductor Equipment and Materials International. World Fab Watch , 2003 Edition.

Strategic Marketing Associates (2003) Personal comm unication September 5, 2003 between C. S. Burton and George Burns, President of Strategic Marketing Associates, PO Box 1217, Santa Cruz, CA 95061.

VLSI Research, Inc. (2003a) Document 327031, Volume D1.1, Table 2.2.2-1 - Worldwide Silicon Demand by Wafer Size. May 2003. Available onlin e at <http://www.vlsiresearch.com>.

VLSI Research, Inc. (2003b) Document 327028, Volume D1.1, Table 2.2.2-2 - Worldwide Silicon Demand by Linewidth. May 2003. Available on line at <http://www.vlsiresearch.com>.

VLSI Research, Inc. (2003c) Document 327029, Volume D1.1, Table 2.2.2-3 - Worldwide Silicon Demand by Device Type. May 2003. Available onlin e at <http://www.vlsiresearch.com>.

VSLI Research, Inc. (2003d) Personal communication September 5, 2003 between C. S. Burton and Marta Hernandez, Analyst at VLSI Research Inc., 1754 Technology Drive, Suite 117, San Jose, CA 95110.

Magnesium Production and Processing

Bartos S., J. Marks, R. Kantamaneni, C. Laush (2003) “Measured SF 6 Emissions from Magnesium Die Casting Operations,” Magnesium Technology , Magnesium Technology 2003, Proceedi ngs of The Minerals, Metals & Materials Society (TMS) Conference, March 2003.

EPA (2004). “Characterization of Cover Gas Emissions from U.S. Magnesium Die Casting”, Environmental Protection Agency, Office of Air and Radiation. EPA430-R-04-004.

Gjestland, H. and D. Magers (1996) “Practical Usage of Sulphur [Sulfur] Hexafluoride for Melt Protection in the Magnesium Die Casting Industry,” #13, 1996 Annual Conference Proceedings , Ube City, Japan, International Magnesium Association.

IPCC (2001) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories
, Intergovernmental Panel on Climate Change, National Greenhouse Gas Inventories Programme, Montreal, IPCCXVI/Doc. 10 (1.IV.2000), May 2000.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 317 RAND (2002) Katie D. Smythe, RAND Environmental Scien ce and Policy Center, “Production and Distribution of SF 6 by End-Use Application,” International Conference on SF 6 and the Environment: Emission Reduction Strategies. San Diego, CA, November 21-22.

USGS (2002). Minerals Yearbook: Magnesium Annual Report 2001. U.S. Geological Survey, Reston, VA. Avaiable on the Internet at <http ://minerals.usgs.gov/minerals/pubs/co mmodity/magnesium/index.html#mis>.

USGS (2003). Personal communication with Deborah A. Kramer

. U.S. Geological Survey, Reston, VA. August, 2003.

USGS (2004a). 2004 Magnesium Mineral Commodity Summaries , United States Geological Survey, Reston, VA. Avaiable on line at <http://minerals.usgs.gov/mine rals/pubs/commodity/magne sium/index.html#mis>.

USGS (2004b). Personal communication with Deborah A. Kramer

. U.S. Geological Survey, Reston, VA. August, 2004.

Industrial Sources of Ambient Air Pollutants

EPA (2004) Air Emissions Trends - Continued Progress Through 2003. U.S. Environmental Protection Agency, Washington DC. Available online at <http://www.epa.gov/airtrends/econ-emissions.html>. November 27, 2004.

EPA (2003) E-mail correspondence containing preliminary am bient air pollutant data between EPA OAP and EPA OAQPS. December 22, 2003.

EPA (1997) Compilation of Air Pollutant Emission Factors, AP-42 , U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC, October.



### Solvent and Other Product Use

Nitrous Oxide Product Usage

CGA (2002) “CGA/NWSA Nitrous Oxide Fact Sheet.” Compressed Gas Association. March 25, 2002. Available online at <http://www.cganet .com/N2O/factsht.htm>.

Heydorn, B. (1997) “Nitrous Oxide – North America.” Chemical Economics Handbook, SRI Consulting. May 1997.

Kirt-Otthmer (1990) “Anesthetics.” Kirk-Otthmer Encyclopedia of Chemical Technology , Volume 2, pp. 781-782.

IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories
, Intergovernmental Panel on Climate Change, Nationa l Greenhouse Inventories Porgramme, Montreal, IPCCXVI/Doc. 10 (1.IV.2000), May 2000.

Tupman, M. (2002) Personal communication between Martin Tupman of Airgas Nitrous Oxide and Laxmi Palreddy of ICF Consulting, USA. July 3, 2002.

Tupman, M. (2003) Personal communication between Mar tin Tupman of Airgas Nitrous Oxide and Daniel Lieberman of ICF Consulting, USA. August 8, 2003.

Solvent Use

EPA (2004) Air Emissions Trends - Continued Progress Through 2003. U.S. Environmental Protection Agency, Washington DC. Available online at <http://www.epa.gov/airtrends/econ-emissions.html>. November 27, 2004.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 318 EPA (2003) E-mail correspondence containing preliminary am bient air pollutant data between EPA OAP and EPA OAQPS. December 22, 2003.

EPA (1997) Compilation of Air Pollutant Emission Factors, AP-42 , U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC, October.



### Agriculture

Enteric Fermentation

American Society of Agricultural Engineers (1999) “Dimensions of Livestock and Poultry.” ASAE 2000 Standards, p. 636.

Becket, J.L. and J.W. Oltjen (1993) Estimation of the water requirement for beef production in the United States. Journal of Animal Science . 71:818-826.

Crutzen, P.J., I. Aselmann, and W. Seiler (1986) “Methane Production by Domestic Animals, Wild Ruminants, Other Herbivores, Fauna, and Humans.” Tellus 38B:271-284.

Donovan, K. (1999) Personal Communicati on between Kacey Donovan of University of California, Davis and Staff at ICF Consulting.

Donovan, K. and L. Baldwin (1999) Results of the AAMOLLY model runs for the Enteric Fermentation Model. University of California, Davis.

EPA (2003) Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001 . EPA 430-R-03-004. U.S. Environmental Protection Agency. Washington, DC. April 15, 2003.

EPA (2000) Draft Enteric Fermentation Model Documentation. U.S. Environmental Protection Agency, Office of Air and Radiation, Washington, DC. June 13, 2000.

EPA (1993) Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to Congress. Office of Air and Radiation, U.S. Environmental Protection Agency, Washington, DC.

FAO (2004) FAOSTAT Statistical Database. Food and Ag riculture Organization of the United Nations. Available online at <http://apps.fao.org>. Accessed June, 25, 2004.

Feedstuffs (1998) “Nutrient requireme nts for pregnant replacement heifers.” Feedstuffs , Reference Issue, p. 50.

IPCC (2000) G ood Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories. Chapter 4. IPCC National Greenhouse Gas Inventories Pr ogramme Technical Support Unit, Kanagawa, Japan. Data also available at <http://www.ipcc-nggip.iges.or.jp/gp/report.htm>.

IPCC/UNEP/OECD/IEA (1997). Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Paris: Intergovernmental Panel on Climate Change, United Nati ons Environment Programme, Organization for Economic Cooperation and Development, International Energy Agency.

Johnson, D. (2002) Personal Communication between Don J ohnson of Colorado State University, Fort Collins, and ICF Consulting.

Johnson, D. (1999) Personal Communication between Don J ohnson of Colorado State University, Fort Collins, and David Conneely of ICF Consulting.

NRC (1999) 1996 Beef NRC, Appendix Table 22. National Research Council.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 319 NRC (2000) Nutrient Requirements of Beef Cattle: Seve nth Revised Edition: Update 2000, Table 11-1, Appendix Table 1. National Research Council.

USDA (2004a) Cattle , U.S. Department of Agricultu re, National Agriculture Statistics Service, Washington, DC. July 1, 2004. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2004b) Hogs and Pigs , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. June 27, 2003. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2004c) Livestock Slaughter , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. July 6-7, 2004. Data also available from <h ttp://www.nass.usda.gov:81/ipedb/>.

USDA (2004d) Milk Production , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. July 1, 2004. Data also available from <h ttp://www.nass.usda.gov:81/ipedb/>.

USDA (2004e) Sheep and Goats , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 31, 2003. Data also available fro m <http://www.nass.usda.gov:81/ipedb/>.

USDA (2004f) Cattle on Feed , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. July 1, 2004. Data also available from <h ttp://www.nass.usda.gov:81/ipedb/>.

USDA (2003a) Cattle , U.S. Department of Agricultu re, National Agriculture Statistics Service, Washington, DC. January 31, 2003. Data also availabl e from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2003b) Hogs and Pigs , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. June 27, 2003. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2003c) Livestock Slaughter , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 24 – June 20, 2003. Data also availabl e from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2003d) Milk Production , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. February 14, 2003. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2003e) Sheep and Goats , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 31, 2003. Data also available fro m <http://www.nass.usda.gov:81/ipedb/>.

USDA (2003f) Cattle on Feed , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. February 14, 2003. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2002a) Cattle , U.S. Department of Agricultu re, National Agriculture Statistics Service, Washington, DC. February 1, 2002. Data also availabl e from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2002b) Hogs and Pigs , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. June 28, 2002. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2002c) Livestock Slaughter , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 25 – June 21, 2002. Data also availabl e from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2002d) Milk Production , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. February 15, 2002. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2002e) Sheep and Goats , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. February 1, 2002. Data also available from <http://www.nass.usda.gov:81/ipedb/>.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 320 USDA (2002f) Cattle on Feed , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. February 15, 2002. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2001a) Cattle , U.S. Department of Agricultu re, National Agriculture Statistics Service, Washington, DC. January 26, 2001. Data also availabl e from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2001b) Hogs and Pigs , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. December 28, 2001. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2001c) Livestock Slaughter , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 19 – December 21, 2001. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2001d) Milk Production , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. February 16, 2001. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2001e) Sheep and Goats , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 26, 2001. Data also available fro m <http://www.nass.usda.gov:81/ipedb/>.

USDA (2001f) Cattle on Feed , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. February 16, 2001. Data also available onlin e at <http://www.nass.usda.gov:81/ipedb/>.

USDA (2001g) US Cattle Supplies and Disposition , National Agriculture Statistics Service, Washington, DC. Data also available online at <http://u sda.mannlib.cornell.edu/reports/na ssr/livestock/pct- bb/specat01.txt.>.

USDA (2000a) Cattle , U.S. Department of Agricultu re, National Agriculture Statistics Service, Washington, DC. January 28, 2000. Data also availabl e from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2000b) Hogs and Pigs , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. December 28, 2000. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2000c) Livestock Slaughter , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 21 – December 22, 2000. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2000d) Milk Production , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. February 16, 2000. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2000e) Sheep and Goats , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 28. Data also av ailable from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2000f) Cattle on Feed , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. February 18, 2000. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2000g) Chicken and Eggs - Final Estimates 1988-1993 , U.S. Department of Agriculture, NationalAgriculture Statistics Service, Washington, DC. Downloaded from <http://usda.mannlib.cornell.edu/datasets/livestock/95908/sb908.txt>, May 3, 2000.

USDA (1999a) Cattle, Final Estimates 1994-1998 , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington DC. 1999. Data also available from <h ttp://www.nass.usda.gov:81/ipedb/>.

USDA (1999b) Hogs and Pigs , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. December 28, 1999. Data also available from <http://www.nass.usda.gov:81/ipedb/>.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 321 USDA (1999c) Livestock Slaughter , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 22 – December 23, 1999. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (1999d) Milk Cows and Milk Production – Final Estimates 1993-1997 , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 1999. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (1999e) Sheep and Goats, Final Estimates 1994-98 , U.S. Department of Agri culture, National Agriculture Statistics Service, Washington, DC , 1999. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (1999f) Cattle on Feed , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (1999g) Miscellaneous Livestoc k and Animal Specialties Inventory and Sales: 1997 and 1992, Table 25, U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. Accessed May 2000 <http://www.nass.usda.gov/census/census97/volume1/us-51/us2_25.pdf>.

USDA (1998a) Hogs and Pigs
, Final Estimates 1993-97 , U.S. Department of Agri culture, National Agriculture Statistics Service, Washington, DC. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (1998b) Sheep and Goats, Final Estimates 1993-97 , U.S. Department of Agri culture, National Agriculture Statistics Service, Washington, DC. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (1996) Beef Cow/Calf Health and Productivity Audit (CHAPA) : Forage Analyses from Cow/Calf Herds in 18 States, National Animal Health Monitoring System, Washington DC. March 1996. Data also available from <http://www.aphis.usda.gov/vs/ceah/cahm>.

USDA (1995a) Cattle, Final Estimates 1989-93 , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (1995b) Dairy Outlook , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. February 27. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (1994a) Hogs and Pigs, Final Estimates 1988-92 , U.S. Department of Agri culture, National Agriculture Statistics Service, Washington, DC. December. Data also available from <http ://www.nass.usda.gov:81/ipedb/>.

USDA (1994b) Sheep and Goats, Final Estimates 1988-93 , U.S. Department of Agri culture, National Agriculture Statistics Service, Washington, DC. January 31. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA:APHIS:VS (1998) Beef ‘97, National Animal Health Monitoring System , Fort Collins, CO. 1998. Data also available from <http://www.aphi s.usda.gov/vs/ceah/cahm>.

USDA:APHIS:VS (1994) Beef Cow/Calf Health and Productivity Audit. National Animal Health Monitoring System, Fort Collins, CO. Data also availa ble from <http://www.aphis. usda.gov/vs/ceah/cahm>.

USDA:APHIS:VS (1993) Beef Cow/Calf Health and Productivity Audit. National Animal Health Monitoring System, Fort Collins, CO. August. Data also available from <http://www.aphi s.usda.gov/vs/ceah/cahm>.

Western Dairyman (1998) “How Big Should Heifers Be at Calving?” The Western Dairyman, Sept. 1998, p. 12.

Manure ManagementInventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 322 Anderson, S. (2000) Telephone conversation between Lee- Ann Tracy of ERG and Steve Anderson, Agricultural Statistician, U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. 31 May.

ASAE (1999) ASAE Standards 1999 , 46 th Edition, American Society of Agri cultural Engineers, St. Joseph, MI.

Bryant, M.P., V.H. Varel, R.A. Frobish, and H.R. Isaacson (1976) In: H.G. Schlegel (ed.). Seminar on Microbial Energy Conversion . E. Goltz KG. Gottingen, Germany. 347 pp.

Deal, P. (2000) Telephone conversation between Lee- Ann Tracy of ERG and Peter B. Deal, Rangeland Management Specialist, Florida Natural Resource Conservation Service, 21 June.

EPA (2004) National Emission Inventory—Ammonia Emissions from Animal Husbandry Operations. Office of Air and Radiation, U.S. Environmental Protection Agency. Available online at <http://www.epa.gov/ttn/chief/ap42/ch09/re lated/nh3inventoryd raft_jan2004.pdf>.

EPA (2003) Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001 . EPA 430-R-03-004. U.S. Environmental Protection Agency. Washington, DC. April 15, 2003.

EPA (2001a) Cost Methodology Report for Beef and Dairy Animal Feeding Operations. EPA-821-R-01-019, January.

EPA (2001b) Development Document for the Proposed Revisi ons to the National Pollutant Discharge Elimination System Regulation and the Effluent Guidelines for Concentrated Animal Feeding Operations EPA-821-R-01-003, January.

EPA (2000) AgSTAR Digest , U.S. Environmental Protection Agency, Office of Air and Radiation. Spring.

EPA (1993) Anthropogenic Methane Emissions in the United States: Estimates for 1990, Report to Congress , U.S. Environmental Protection Agency, Office of Air and Radiation. April.

EPA (1992) Global Methane Emissions from Livestock and Poultry Manure , U.S. Environmental Protection Agency, Office of Air and Radiation, February.

ERG (2003) Methodology for Estimating Uncertainty for Manure Management Greenhouse Gas Inventory. Contract No. GS-10F-0036, Task Order 005. Memorandum to EPA from ERG. September 26, 2003.

ERG (2001) Summary of development of MDP Factor for methane conversion factor calculations. September 2001.

ERG (2000a) Calculations: Percent Distribution of Manure for Waste Management Systems. August 2000.

ERG (2000b) Summary of B o Literature Review. June 2000.

FAO (2004) Yearly U.S. total horse population data fro m the Food and Agriculture Organization of the United Nations database, <http://apps.fao .org>. Accessed April 2004.

Groffman, P.M., R. Brumme, K. Butterbach-Bahl, K.E. Dobbie, A.R. Mosier, D. Ojima, H. Papen, W.J. Parton, K.A. Smith, and C. Wagner-Riddle. (2000) “Evaluating annual nitrous oxide fluxes at the ecosystem scale.” Global Biogeochemcial Cycles, 14(4): 1061-1070.

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Hashimoto, A.G., V.H. Varel, and Y.R. Chen (1981) “U ltimate Methane Yield from Beef Cattle Manure; Effect of Temperature, Ration Constituents, Antibiotics and Manure Age.” Agricultural Wastes . 3:241-256.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 323 Hill, D.T. (1984) “Methane Productiv ity of the Major Animal Types.” Transactions of the ASAE . 27(2):530-540.

Hill, D.T. (1982) “Design of Digestion Systems for Maximum Methane Production.” Transactions of the ASAE

. 25(1):226-230.

IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories
, Intergovernmental Panel on Climate Change, NGGIP. Chapter 4, Agriculture.

Johnson, D. (2000) Telephone conversation between L ee-Ann Tracy of ERG and Dan Johnson, State Water Management Engineer, California Natural Resource Conservation Service, 23 June.

Lange, J. (2000) Telephone conversation between Lee-Ann Tracy of ERG and John Lange, Agricultural Statistician, U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. 8 May.

Lieberman, D., L. Pederson, and D. Pape. (2004) 1990-2003 Volatile Solids and Nitrogen Excretion Rates Deliverable Under EPA Contract No. GS-10F-0124J, Task Order 027-02. Memorandum to EPA from ICF Consulting. July 29,2004.

Martin, J. (2000) “A Comparison of the Performance of Three Swine Waste Stabilization Systems,” paper submitted to Eastern Research Group, Inc. October, 2000.

Miller, P. (2000) Telephone conversati on between Lee-Ann Tracy of ERG and Paul Miller, Iowa Natural Resource Conservation Service, June 12, 2000.

Milton, B. (2000) Telephone conversati on between Lee-Ann Tracy of ERG a nd Bob Milton, Chie f of Livestock Branch, U.S. Department of Agriculture, National Agriculture Statistics Service, May 1, 2000.

Morris, G.R. (1976) Anaerobic Fermentation of Animal Wastes: A Kinetic and Empirical Design Fermentation. M.S. Thesis. Cornell University.

NOAA (2004) National Oceanic and Atmos pheric Administration ( NOAA), National Climate Data Center (NCDC) Downloaded data in April 2004 from <ftp://ftp.ncdc.noaa.gov/pub/da ta/cirs/> (for all states except Alaska and Hawaii); downloaded data in July 2004 from <ftp://ftp .ncdc.noaa.gov/pub/data/globa lsod/> (for Alaska and Hawaii).

Peterson, K., and H. Jacobs (2003) 1990-2002 Volatile So lids and Nitrogen Excretion Rates Deliverable Under EPA Contract No. GS-10F-0124J, Task Order 004-02. Memorandum to EPA from ICF Consulting. August 28, 2003.

Peterson, K., J. King, and D, Johnson (2002) Methodology and Results for Revised Diet Characterization Analysis Deliverable under EPA contract no. 68-W7-0069, task or der 505-01. Memorandum to EPA from ICF Consulting. July 31, 2002.

Poe, G., N. Bills, B. Bellows, P. Crosscombe, R. Ko elsch, M. Kreher, and P. Wright (1999) Staff Paper Documenting the Status of Dairy Manure Management in New York: Current Practices and Willingness to Participate in Voluntary Programs, Department of Agri cultural, Resource, and Managerial Economics, Cornell University, Ithaca, New York, September.

Safley, L.M., Jr. and P.W. Westerman (1992) “Performance of a Low Temperature Lagoon Digester.” Biological Wastes . 9060-8524/92/S05.00.

Safley, L.M., Jr. and P.W. Westerma n (1990) “Psychrophilic Anaerobic Dige stion of Animal Manure: Proposed Design Methodology.” Biological Wastes . 34:133-148.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 324 Safley, L.M., Jr. and P.W. Westerman (1989) “Anaerobic Lagoon Biogas Recovery Systems.” Biological Wastes

. 27:43-62.

Safley, L.M., Jr. (2000) Telephone conversation between De b Bartram of ERG and L.M. Safley, President, AgriWaste Technology, June and October.

Stettler, D. (2000) Telephone convers ation between Lee-Ann Tracy of ER G and Don Stettler, Environmental Engineer, National Climate Center, Oregon Natu ral Resource Conservation Service, 27 June.

Summers, R. and S. Bousfield (1980) “A Detailed Study of Piggery-waste Anaerobic Digestion.” Agricultural Wastes . 2:61-78.

Sweeten, J. (2000) Telephone conversation between Indra Mitra of ERG and John Sweeten, Texas A&M University, June 2000.

UEP (1999) Voluntary Survey Results - Estimated Percentage Participation/Activity, Caged Layer Environmental Management Practices, Industry data submissions for EP A profile development, United Egg Producers and National Chicken Council. Received from J ohn Thorne, Capitolink. June 2000.

USDA (2004a) Cattle , U.S. Department of Agricultu re, National Agriculture Statistics Service, Washington, DC. January 31, 2004. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2004b) Cattle on Feed Cattle , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 23, 2004. Data also available from <h ttp://www.nass.usda.gov:81/ipedb/>.

USDA (2004c) Hogs and Pig , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. March 26, 2004. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2004d) Chicken and Eggs Annual Summary , U.S. Department of Agri culture, National Agriculture Statistics Service, Washington, DC. February 24, 2004. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2004e) Poultry Production and Value Annual Summary , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. April 29, 2004. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2004f) Sheep and Goats , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 31, 2004. Data also available from <http:// www.usda.gov/nass/pubs/reportname.htm>.

USDA (2003a) Cattle , U.S. Department of Agricultu re, National Agriculture Statistics Service, Washington, DC. January 31, 2003. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2003b) Cattle on Feed Cattle , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 17, 2003. Data also available from <h ttp://www.nass.usda.gov:81/ipedb/>.

USDA (2003c) Hogs and Pig , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. March 28, 2003. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2003d) Chicken and Eggs Annual Summary , U.S. Department of Agri culture, National Agriculture Statistics Service, Washington, DC. January 30, 2003. Data also available from <http://www.nass.usda.gov:81/ipedb/>.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 325 USDA (2003e) Poultry Production and Value Annual Summary , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. April 29, 2003, revised May 3, 2003. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2003f) Sheep and Goats , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 31, 2003. Data also available from <http:// www.usda.gov/nass/pubs/reportname.htm>.

USDA (2002a) Cattle , U.S. Department of Agricultu re, National Agriculture Statistics Service, Washington, DC. February 1, 2002. Data also availabl e from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2002b) Cattle on Feed Cattle , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 18, 2002. Data also available from <h ttp://www.nass.usda.gov:81/ipedb/>.

USDA (2002c) Hogs and Pig , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. March 28, 2002. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2002d) Chicken and Eggs Annual Summary , U.S. Department of Agri culture, National Agriculture Statistics Service, Washington, DC. January 29, 2002, revised March 22, 2002. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2002e) Poultry Production and Value Annual Summary , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. April 29, 2002, revised May 3, 2002. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2002f) Sheep and Goats , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. February 1, 2002. Data also available from <http:// www.usda.gov/nass/pubs/reportname.htm>.

USDA (2001a) Cattle , U.S. Department of Agricultu re, National Agriculture Statistics Service, Washington, DC. January 26, 2001. Data also availabl e from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2001b) Cattle on Feed Cattle , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 19, 2001. Data also available from <h ttp://www.nass.usda.gov:81/ipedb/>.

USDA (2001c) Hogs and Pig , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. March 30, 2001. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2001d) Chicken and Eggs - 1999 Summary Cattle , U.S. Department of Agri culture, National Agriculture Statistics Service, Washington, DC. January.

USDA (2001e) Poultry Production and Value - 1999 Summary , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. April.

USDA (2001f) Sheep and Goats , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January. Data also availabl e from <http://www.usda.gov/nass/pubs/reportname.htm>.

USDA (2001g) Published Estimates Database, U.S. Depart ment of Agriculture, National Agricultural Statistics Service, Washington, DC. Downloaded from <http ://www.nass.usda.gov:81/ipedb/>, September 26, 2001.

USDA (2000a) Cattle , U.S. Department of Agricultu re, National Agriculture Statistics Service, Washington, DC. January 28, 2000. Data also availabl e from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2000b) Cattle on Feed Cattle , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. April 14, 2000. Data also av ailable from <http://www.nass.usda.gov:81/ipedb/>.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 326 USDA (2000c) Hogs and Pig , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. March 24, 2000. Data also availabl e from <http://www.nass.usda.gov:81/ipedb/>.

USDA (2000d) Chicken and Eggs - 1999 Summary Cattle , U.S. Department of Agri culture, National Agriculture Statistics Service, Washington, DC. January.

USDA (2000e) Poultry Production and Value - 1999 Summary , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. April.

USDA (2000f) Sheep and Goats , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January. Data also available from <http://www.usda.gov/nass/pubs/reportname.htm>.

USDA (2000g) Chicken and Eggs - Final Estimates 1988-1993 , U.S. Department of Agriculture, NationalAgriculture Statistics Service, Washington, DC. Downloaded from <http://usda.mannlib.cornell.edu/datasets/livestock/95908/sb908.txt>, May 3, 2000.

USDA (2000h) Re-aggregated data from the National Animal Health Monitoring System’s (NAHMS) Dairy ’96 study provided by Stephen L. Ott of the U.S. Departme nt of Agriculture, Animal and Plant Health Inspection Service. June 19.

USDA (2000i) Layers ’99 – Part II: References of 1999 Table Egg Layer Management in the U.S. , U.S. Department of Agriculture, Animal and Plant Health Inspection Serv ice (APHIS), National Animal Health Monitoring System (NAHMS). January.

USDA (1999a) Cattle - Final Estimates 1994-98 , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (1999b) Poultry Production and Value - Final Estimates 1994-97 , U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. March.

USDA (1999c) Sheep and Goats - Final Estimates 1994-1998, U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January.

USDA (1999d). Miscellaneous Li vestock and Animal Specialties Invent ory and Sales: 1997 and 1992, Table 25, U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. Accessed May 2000 <http://www.nass.usda.gov/census/census97/volume1/us-51/us2_25.pdf>.

USDA (1999e) 1992 and 1997 Census of Agriculture (CD-RO M), U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC.

USDA (1998a) Hogs and Pigs - Final Estimates 1993-97, U.S. Department of Agri culture, National Agriculture Statistics Service, Washington, DC. December. Data also available from <http:// www.nass.usda.gov:81/ipedb/>.

USDA (1998b) Chicken and Eggs - Final Estimates 1994-97 , U.S. Department of Agri culture, National Agriculture Statistics Service, Washington, DC. December.

USDA (1998c) Nutrients Available from Livestock Manure Relative to Crop Growth Requirements , Resource Assessment and Strategic Planning Working Paper 98-1, U.S. Department of Agriculture, Natural Resources Conservation Service. February.

USDA (1998d) Re-aggregated data from the National Animal Health Monitoring System’s (NAHMS) Swine ’95 study aggregated by Eric Bush of the U.S. Department of Agriculture, Centers for Epidemiology and Animal Health.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 327 USDA (1996a) Agricultural Waste Management Field Handbook
, National Engineering Handbook (NEH) , Part 651, U.S. Department of Agriculture, Natu ral Resources Conservation Service. July.

USDA (1996b) Swine ’95: Grower/Finisher Part II: Refere nce of 1995 U.S. Grower/Finisher Health & Management Practices , U.S. Department of Agriculture, Animal Plant Health and Inspection Service, Washington, DC. June.

USDA (1995a) Cattle - Final Estimates 1989-93, U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January. Data also available from <http://www.nass.usda.gov:81/ipedb/>.

USDA (1995b) Poultry Production and Value - Final Estimates 1989-1993, U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January.

USDA (1994a) Hogs and Pigs - Final Estimates 1988-92, U.S. Department of Agricu lture, National Agriculture Statistics Service, Washington, DC. December. Data also available from <http:// www.nass.usda.gov:81/ipedb/>.

USDA (1994b) S heep and Goats - Final Estimates 1989-1993, U.S. Department of Agriculture, National Agriculture Statistics Service, Washington, DC. January 31, 1994.

Wright, P. (2000) Telephone conversation between Lee-Ann Tracy of ERG and Peter Wright, Cornell University, College of Agriculture and Life Sciences, June 23, 2000.

Rice Cultivation

Bollich, P. (2000) Telephone conversation between Payt on Deeks of ICF Consulting and Pat Bollich, Professor with Louisiana State University Agriculture Center. May 17, 2000.

Bossio, D.A., W. Horwath, R.G. Mutters, and C. van Kesse l (1999) “Methane pool and flux dynamics in a rice field following straw incorporation.” Soil Biology and Biochemistry 31:1313-1322.

Cantens, G. (2004) Telephone conversati on between Lauren Flinn of ICF Consu lting and Janet Lewis, Assistant to Gaston Cantens, Vice President of Corporate Relations, Florida Crystals Company. July 30, 2004.

Cicerone R.J., C.C. Delwiche, S.C. Tyler, and P.R. Zimmerman (1992) “Methane Emissions from California Rice Paddies with Varied Treatments

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Deren, C. (2002) Telephone conversati on between Caren Mintz and Dr. Chris Deren, Everglades Research and Education Centre at the University of Florida. August 15, 2002.

Guethle, D. (2004) Telephone conve rsation between Lauren Flinn of ICF Consulting and David Guethle, Agronomy Specialist, Missouri Cooperative Extension Service. June 23, 2004.

Guethle, D. (2003) Telephone c onversation between Caren Mintz of ICF Consulting and David Guethle, Agronomy Specialist, Missouri Cooperative Extension Service. June 19, 2003.

Guethle, D. (2002) Telephone c onversation between Caren Mintz of ICF Consulting and David Guethle, Agronomy Specialist, Missouri Cooperative Extension Service. August 19, 2002.

Guethle, D. (2001) Telephone conve rsation between Caren Mintz of IC F Consulting and David Guethle, Agronomy Specialist at Missouri Cooperative Extension Service. September 4, 2001.

Holzapfel-Pschorn, A., R. Conrad, and W. Seiler (1985) “P roduction, Oxidation, and Emissions of Methane in Rice Paddies.” FEMS Microbiology Ecology 31:343-351.Inventory of U.S. Greenhouse Gas Emissions and Si nks: 1990-2003 Page 328 IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories

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IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories. Paris: Intergovernmental Panel on Climate Change, United Nati ons Environment Programme, Organization for Economic Co-Operation and Development, International Energy Agency.

Kirstein, A. (2004) Telephone convers ation between Lauren Flinn of IC F Consulting and Arthur Kirstein, Coordinator, Agricultural Economic Development Program, Palm Beach C ounty Cooperative Extension Service, FL. June 30, 2004.

Kirstein, A. (2003) Telephone conve rsation between Caren Mintz of IC F Consulting and Arthur Kirstein, Coordinator, Agricultural Economic Development Program, Palm Beach C ounty Cooperative Extension Service, FL. August 13, 2003.

Klosterboer, A. (2003) Telephone c onversation between Caren Mintz of IC F Consulting and Arlen Klosterboer, retired Extension Agronomist, Texas A&M University. July 7, 2003.

Klosterboer, A. (2002) Telephone c onversation between Caren Mintz of IC F Consulting and Arlen Klosterboer, Extension Agronomist, Texas A&M University. August 19, 2002.

Klosterboer, A. (2001a) Tele phone conversation between Ca ren Mintz of ICF Consulti ng and Arlen Klosterboer, Extension Agronomist, Texas A & M University. August 6, 2001.

Klosterboer, A. (2001b) Telephone conve rsation between Caren Mintz of ICF Consulting and Arlen Klosterboer, Extension Agronomist, Texas A & M University. October 8, 2001.

Klosterboer, A. (2000) Telephone conve rsation between Payton Deeks of ICF Consulting and Arlen Klosterboer, Extension Agronomist, Texas A & M University. May 18, 2000.

Klosterboer, A. (1999) Telephone c onversation between Catherine Lein ing of ICF Consulting and Arlen Klosterboer, Extension Agronomist, Texas A & M University. June 10, 1999.

Klosterboer, A. (1997) Telephone c onversation between Holly Simpkins of ICF Incorporated and Arlen Klosterboer, Texas A & M University. December 1, 1997.

Lee, D. (2004) Telephone conversation between Lauren Flinn of ICF Consu lting and Danny Lee, OK Farm Service Agency, Stillwater, OK. July 23, 2004.

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