EPA430-R-11-005
DRAFT INVENTORY OF U.S. GREENHOUSE GAS EMISSIONS AND
SINKS:
1990-2009
FEBRUARY 15,2011
U.S. Environmental Protection Agency
1200 Pennsylvania Ave., N.W.
Washington, DC 20460
U.S.A.
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1
2
3 HOW TO OBTAIN COPIES
4 You can electronically download this document on the U. S. EPA's homepage at
5 . To request free copies of this report, call
6 the National Service Center for Environmental Publications (NSCEP) at (800) 490-9198, or visit the web site above
7 and click on "order online" after selecting an edition.
8 All data tables of this document are available for the full time series 1990 through 2008, inclusive, at the internet site
9 mentioned above.
10
11 FOR FURTHER INFORMATION
12 Contact Mr. Leif Hockstad, Environmental Protection Agency, (202) 343-9432, hockstad.leif@epa.gov.
13 Or Mr. Brian Cook, Environmental Protection Agency, (202) 343-9135, cook.brianb@epa.gov.
14 For more information regarding climate change and greenhouse gas emissions, see the EPA web site at
15 .
16
17 Released for printing: April 15, 2010
18
19
20
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i Acknowledgments
2 The Environmental Protection Agency would like to acknowledge the many individual and organizational
3 contributors to this document, without whose efforts this report would not be complete. Although the complete list
4 of researchers, government employees, and consultants who have provided technical and editorial support is too
5 long to list here, EPA's Office of Atmospheric Programs would like to thank some key contributors and reviewers
6 whose work has significantly improved this year's report.
7 Work on emissions from fuel combustion was led by Leif Hockstad and Brian Cook. Ed Coe directed the work on
8 mobile combustion and transportation. Work on industrial process emissions was led by Mausami Desai. Work on
9 methane emissions from the energy sector was directed by Lisa Hanle and Kitty Sibold. Calculations for the waste
10 sector were led by Rachel Schmeltz. Tom Wirth directed work on the Agriculture, and together with Jennifer
11 Jenkins, directed work on the Land Use, Land-Use Change, and Forestry chapters. Work on emissions of HFCs,
12 PFCs, and SF6 was directed by Deborah Ottinger and Dave Godwin.
13 Within the EPA, other Offices also contributed data, analysis, and technical review for this report. The Office of
14 Transportation and Air Quality and the Office of Air Quality Planning and Standards provided analysis and review
15 for several of the source categories addressed in this report. The Office of Solid Waste and the Office of Research
16 and Development also contributed analysis and research.
17 The Energy Information Administration and the Department of Energy contributed invaluable data and analysis on
18 numerous energy-related topics. The U.S. Forest Service prepared the forest carbon inventory, and the Department
19 of Agriculture's Agricultural Research Service and the Natural Resource Ecology Laboratory at Colorado State
20 University contributed leading research on nitrous oxide and carbon fluxes from soils.
21 Other government agencies have contributed data as well, including the U.S. Geological Survey, the Federal
22 Highway Administration, the Department of Transportation, the Bureau of Transportation Statistics, the Department
23 of Commerce, the National Agricultural Statistics Service, the Federal Aviation Administration, and the Department
24 of Defense.
25 We would also like to thank Marian Martin Van Pelt, Randy Freed, and their staff at ICF International's Energy,
26 Environment, and Transportation Practice, including Don Robinson, Diana Pape, Susan Asam, Michael Grant,
27 Robert Lanza, Chris Steuer, Toby Mandel, Lauren Pederson, Joseph Herr, Jeremy Scharfenberg, Mollie Averyt,
28 Ashley Labrie, Hemant Mallya, Sandy Seastream, Douglas Sechler, Ashaya Basnyat, Kristen Schell, Victoria
29 Thompson, Mark Flugge, Paul Stewart, Tristan Kessler, Katrin Moffroid, Veronica Kennedy, Kaye Schultz, Seth
30 Greenburg, Larry O'Rourke, Rubab Bhangu, Deborah Harris, Emily Rowan, Roshni Rathi, Lauren Smith, Nikhil
31 Nadkarni, Caroline Cochran, Joseph Indvik, Aaron Sobel, and Neha Mukhi for synthesizing this report and
32 preparing many of the individual analyses. Eastern Research Group, RTI International, Raven Ridge Resources, and
33 Ruby Canyon Engineering Inc. also provided significant analytical support.
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i Preface
2 The United States Environmental Protection Agency (EPA) prepares the official U.S. Inventory of Greenhouse Gas
3 Emissions and Sinks to comply with existing commitments under the United Nations Framework Convention on
4 Climate Change (UNFCCC). Under decision 3/CP.5 of the UNFCCC Conference of the Parties, national
5 inventories for UNFCCC Annex I parties should be provided to the UNFCCC Secretariat each year by April 15.
6 In an effort to engage the public and researchers across the country, the EPA has instituted an annual public review
7 and comment process for this document. The availability of the draft document is announced via Federal Register
8 Notice and is posted on the EPA web site. Copies are also mailed upon request. The public comment period is
9 generally limited to 30 days; however, comments received after the closure of the public comment period are
10 accepted and considered for the next edition of this annual report.
111
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i Table of Contents
2 ACKNOWLEDGMENTS I
3 PREFACE Ill
4 TABLE OF CONTENTS V
5 LIST OF TABLES, FIGURES, AND BOXES VII
6 EXECUTIVE SUMMARY ES-1
7 Background Information ES-2
8 Recent Trends in U.S. Greenhouse Gas Emissions and Sinks ES-3
9 Overview of Sector Emissions and Trends ES-11
10 Other Information ES-14
11 1. INTRODUCTION 1-1
12 1.1. Background Information 1-2
13 1.2. Institutional Arrangements 1-9
14 1.3. Inventory Process 1-10
15 1.4. Methodology andData Sources 1-11
16 1.5. Key Categories 1-12
17 1.6. Quality Assurance and Quality Control (QA/QC) 1-14
18 1.7. Uncertainty Analysis of Emission Estimates 1-16
19 1.8. Completeness 1-17
20 1.9. Organization of Report 1-17
21 2. TRENDS IN GREENHOUSE GAS EMISSIONS 2-1
22 2.1. Recent Trends in U.S. Greenhouse Gas Emissions and Sinks 2-1
23 2.2. Emissions by Economic Sector 2-16
24 2.3. Indirect Greenhouse Gas Emissions (CO, NOX, NMVOCs, and SO2) - TO BE UPDATED 2-26
25 3. ENERGY 3-1
26 3.1. Fossil Fuel Combustion (IPCC Source Category 1A) 3-3
27 3.2. Carbon Emitted from Non-Energy Uses of Fossil Fuels (IPCC Source Category 1A) 3-28
28 3.3. Incineration of Waste (IPCC Source Category lAla) 3-33
29 3.4. Coal Mining (IPCC Source Category IBla) 3-37
30 3.5. Abandoned Underground Coal Mines (IPCC Source Category IBla) 3-39
31 3.6. Natural Gas Systems (IPCC Source Category lB2b) 3-43
32 3.7. Petroleum Systems (IPCC Source Category lB2a) 3-48
33 3.8. Energy Sources of Indirect Greenhouse Gas Emissions - TO BE UPDATED 3-5
34 3.9. International Bunker Fuels (IPCC Source Category 1: Memo Items) 3-5
35 3.10. WoodBiomass andEthanol Consumption (IPCC Source Category 1A) 3-9
36 4. INDUSTRIAL PROCESSES 4-1
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1 4.1. Cement Production (IPCC Source Category 2A1) 4-5
2 4.2. Lime Production (IPCC Source Category 2A2) 4-7
3 4.3. Limestone and Dolomite Use (IPCC Source Category 2A3) 4-11
4 4.4. Soda Ash Production and Consumption (IPCC Source Category 2A4) 4-13
5 4.5. Ammonia Production (IPCC Source Category 2B1) and Urea Consumption 4-16
6 4.6. Nitric Acid Production (IPCC Source Category 2B2) 4-19
7 4.7. Adipic Acid Production (IPCC Source Category 2B3) 4-21
8 4.8. Silicon Carbide Production (IPCC Source Category 2B4) and Consumption 4-24
9 4.9. Petrochemical Production (IPCC Source Category 2B5) 4-26
10 4.10. Titanium Dioxide Production (IPCC Source Category 2B5) 4-29
11 4.11. Carbon Dioxide Consumption (IPCC Source Category 2B5) 4-31
12 4.12. Phosphoric Acid Production (IPCC Source Category 2B5) 4-33
13 4.13. Iron and Steel Production (IPCC Source Category 2C1) and Metallurgical Coke Production 4-36
14 4.14. Ferroalloy Production (IPCC Source Category 2C2) 4-45
15 4.15. Aluminum Production (IPCC Source Category 2C3) 4-47
16 4.16. Magnesium Production and Processing (IPCC Source Category 2C4) 4-51
17 4.17. Zinc Production (IPCC Source Category 2C5) 4-54
18 4.18. Lead Production (IPCC Source Category 2C5) 4-58
19 4.19. HCFC-22 Production (IPCC Source Category 2E1) 4-60
20 4.20. Substitution of Ozone Depleting Substances (IPCC Source Category 2F) 4-62
21 4.21. Semiconductor Manufacture (IPCC Source Category 2F6) 4-66
22 4.22. Electrical Transmission and Distribution (IPCC Source Category 2F7) 4-71
23 4.23. Industrial Sources of Indirect Greenhouse Gases - TO BE UPDATED 4-76
24 5. SOLVENT AND OTHER PRODUCT USE 5-1
25 5.1. Nitrous Oxide from Product Uses (IPCC Source Category 3D) 5-1
26 5.2. Indirect Greenhouse Gas Emissions from Solvent Use - TO BE UPDATED 5-3
27 6. AGRICULTURE 6-1
28 6.1. Enteric Fermentation (IPCC Source Category 4A) 6-2
29 6.2. Manure Management (IPCC Source Category 4B) 6-6
30 6.3. Rice Cultivation (IPCC Source Category 4C) 6-12
31 6.4. Agricultural Soil Management (IPCC Source Category 4D) 6-17
32 6.5. Field Burning of Agricultural Residues (IPCC Source Category 4F) 6-27
33 7. LAND USE, LAND-USE CHANGE, AND FORESTRY 7-1
34 7.1. Representation of the U.S. Land Base 7-4
35 7.2. Forest Land Remaining Forest Land 7-12
36 7.3. Land Converted to Forest Land (IPCC Source Category 5A2) 7-24
37 7.4. Cropland Remaining Cropland (IPCC Source Category 5B1) 7-24
vi DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 7.5. Land Converted to Cropland (IPCC Source Category 5B2) 7-35
2 7.6. Grassland Remaining Grassland (IPCC Source Category 5C1) 7-38
3 7.7. Land Converted to Grassland (IPCC Source Category 5C2) 7-42
4 7.8. Wetlands Remaining Wetlands 7-45
5 7.9. Settlements Remaining Settlements 7-49
6 7.10. Land Converted to Settlements (Source Category 5E2) 7-55
7 7.11. Other(IPCC Source Category 5G) 7-55
8 8. WASTE 8-1
9 8.1. Landfills (IPCC Source Category 6A1) 8-2
10 8.2. Wastewater Treatment (IPCC Source Category 6B) 8-7
11 8.3. Composting (IPCC Source Category 6D) 8-18
12 8.4. Waste Sources of Indirect Greenhouse Gases - TO BE UPDATED 8-19
13 9. OTHER 9-1
14 10. RECALCULATIONS AND IMPROVEMENTS 10-1
15 11. REFERENCES 11-1
16
17 List of Tables, Figures, and Boxes
18 Tables
19 Table ES-1: Global Warming Potentials (100-Year Time Horizon) Used in this Report ES-3
20 Table ES-2: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq. or million metric tons CO2
21 Eq.) ES-4
22 Table ES-3: CO2 Emissions fromFossil Fuel Combustion by Fuel Consuming End-Use Sector (Tg CO2 Eq.)....ES-7
23 Table ES-4: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg CO2 Eq.)
24 ES-11
25 Table ES- 5: Net CO2 Flux from Land Use, Land-Use Change, and Forestry (Tg CO2Eq.) ES-13
26 Table ES-6. Emissions from Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.) ES-13
27 Table ES-7: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (TgCO2Eq.) ES-14
28 Table ES-8: U.S Greenhouse Gas Emissions by Economic Sector with Electricity-Related Emissions Distributed
29 (TgCO2Eq.) ES-15
30 Table ES-9: Recent Trends in Various U.S. Data (Index 1990 = 100) ES-16
31 Table ES-10: Emissions of NOX, CO,NMVOCs, and SO2 (Gg) ES-16
32 Table 1-1: Global Atmospheric Concentration, Rate of Concentration Change, and Atmospheric Lifetime (years) of
33 Selected Greenhouse Gases 1-3
34 Table 1-2: Global Warming Potentials and Atmospheric Lifetimes (Years) Used in this Report 1-8
35 Table 1-3: Comparison of 100-Year GWPs 1-8
36 Table 1-4: Key Categories for the United States (1990-2009) 1-13
3 7 Table 1 -5. Estimated Overall Inventory Quantitative Uncertainty (Tg CO2 Eq. and Percent) 1-16
38 Table 1-6: IPCC Sector Descriptions 1-17
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1 Table 1-7: List of Annexes 1-18
2 Table 2-1: Recent Trends inU.S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq.) 2-3
3 Table 2-2: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg) 2-5
4 Table 2-3: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg CO2 Eq.)... 2-7
5 Table 2-4: Emissions from Energy (Tg CO2Eq.) 2-8
6 Table 2-5: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.) 2-9
7 Table 2-6: Emissions from Industrial Processes (TgCO2Eq.) 2-11
8 Table 2-7: N2O Emissions from Solvent and Other Product Use (Tg CO2 Eq.) 2-12
9 Table 2-8: Emissions from Agriculture (Tg CO2 Eq.) 2-13
10 Table 2-9: Net CO2 Flux from Land Use, Land-Use Change, and Forestry (TgCO2Eq.) 2-14
11 Table 2-10: Emissions from Land Use, Land-Use Change, and Forestry (TgCO2Eq.) 2-14
12 Table 2-11: Emissions from Waste (Tg CO2 Eq.) 2-15
13 Table 2-12: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO2 Eq. and Percent of Total in
14 2009) 2-16
15 Table 2-13: Electricity Generation-Related Greenhouse Gas Emissions (Tg CO2Eq.) 2-19
16 Table 2-14: U.S Greenhouse Gas Emissions by Economic Sector and Gas with Electricity-Related Emissions
17 Distributed (TgCO2Eq.) and Percent of Total in 2009 2-19
18 Table 2-15: Transportation-Related Greenhouse Gas Emissions (Tg CO2 Eq.) 2-22
19 Table 2-16: Recent Trends in Various U.S. Data (Index 1990 = 100) 2-25
20 Table 2-17: Emissions of NOX, CO, NMVOCs, and SO2 (Gg) 2-26
21 Table 3-1: CO2, CH4, andN2O Emissions fromEnergy (Tg CO2 Eq.) 3-1
22 Table 3-2: CO2, CH4, and N2O Emissions from Energy (Gg) 3-2
23 Table 3-3: CO2, CH4, and N2O Emissions from Fossil Fuel Combustion (Tg CO2 Eq.) 3-3
24 Table 3-4: CO2, CH4, and N2O Emissions from Fossil Fuel Combustion (Gg) 3-3
25 Table 3 -5: CO2 Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg CO2 Eq.) 3-3
26 Table 3-6: Annual Change in CO2 Emissions and Total 2009 Emissions from Fossil Fuel Combustion for Selected
27 Fuels and Sectors (Tg CO2 Eq. and Percent) 3-4
28 Table 3 -7: CO2, CH4, and N2O Emissions from Fossil Fuel Combustion by Sector (Tg CO2 Eq.) 3-6
29 Table 3-8: CO2, CH4, and N2O Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.) 3-7
30 Table 3-9: CO2 Emissions from Stationary Fossil Fuel Combustion (Tg CO2 Eq.) 3-8
31 Table 3-10: CH4 Emissions from Stationary Combustion (Tg CO2 Eq.) 3-9
32 Table 3-11: N2O Emissions from Stationary Combustion (Tg CO2 Eq.) 3-9
33 Table 3-12: CO2 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg CO2 Eq.)a 3-13
34 Table 3-13: CH4 Emissions from Mobile Combustion (Tg CO2 Eq.) 3-15
35 Table 3-14: N2O Emissions from Mobile Combustion (Tg CO2Eq.) 3-15
36 Table 3-15: Carbon Intensity from Direct Fossil Fuel Combustion by Sector (Tg CO2 Eq./QBtu) 3-19
37 Table 3-16: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Energy-related Fossil Fuel
38 Combustion by Fuel Type and Sector (Tg CO2 Eq. and Percent) 3-21
viii DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Table 3-17: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Energy-Related Stationary
2 Combustion, Including Biomass (Tg CO2Eq. and Percent) 3-24
3 Table 3-19: CO2 Emissions from Non-Energy Use Fossil Fuel Consumption (Tg CO2Eq.) 3-28
4 Table 3-20: Adjusted Consumption of Fossil Fuels for Non-Energy Uses (TBtu) 3-29
5 Table 3-21: 2009 Adjusted Non-Energy Use Fossil Fuel Consumption, Storage, and Emissions 3-30
6 Table 3-22: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Non-Energy Uses of Fossil Fuels
7 (Tg CO2 Eq. and Percent) 3-31
8 Table 3-23: Tier 2 Quantitative Uncertainty Estimates for Storage Factors of Non-Energy Uses of Fossil Fuels
9 (Percent) 3-32
10 Table 3-28: CH4 Emissions from Coal Mining (Tg CO2 Eq.) 3-37
11 Table 3-29: CH4 Emissions from Coal Mining (Gg) 3-37
12 Table 3-30: Coal Production (Thousand Metric Tons) 3-38
13 Table 3-31: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Coal Mining (Tg CO2 Eq. and
14 Percent) 3-39
15 Table 3-32: CH4 Emissions from Abandoned Coal Mines (Tg CO2 Eq.) 3-40
16 Table 3-33: CH4 Emissions from Abandoned Coal Mines (Gg) 3-40
17 Table 3-34: Number of gassy abandoned mines occurring in U.S. basins grouped by class according to post-
18 abandonment state 3-41
19 Table 3-35: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Abandoned Underground Coal
20 Mines (Tg CO2 Eq. and Percent) 3-43
21 Table 3-36: CH4 Emissions from Natural Gas Systems (Tg CO2 Eq.)* 3-44
22 Table 3-37: CH4Emissions from Natural Gas Systems (Gg)* 3-44
23 Table 3-38: Non-combustion CO2 Emissions from Natural Gas Systems (TgCO2Eq.) 3-44
24 Table 3-39: Non-combustion CO2 Emissions from Natural Gas Systems (Gg) 3-44
25 Table 3-40: Tier 2 Quantitative Uncertainty Estimates for CH4 and Non-energy CO2 Emissions from Natural Gas
26 Systems (Tg CO2 Eq. and Percent) 3-46
27 Table 3-41: CH4 Emissions from Petroleum Systems (Tg CO2 Eq.) 3-49
28 Table 3-42: CH4 Emissions from Petroleum Systems (Gg) 3-49
29 Table 3-43: CO2 Emissions from Petroleum Systems (Tg CO2 Eq.) 3-1
30 Table 3-44: CO2 Emissions from Petroleum Systems (Gg) 3-1
31 Table 3-45: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Petroleum Systems (Tg CO2 Eq. and
32 Percent) 3-2
33 Table 3-46: Potential Emissions from CO2 Capture and Transport (Tg CO2 Eq.) 3-4
34 Table 3-47: Potential Emissions from CO2 Capture and Transport (Gg) 3-4
35 Table 3-48: NOX, CO, and NMVOC Emissions from Energy-Related Activities (Gg) 3-5
36 Table 3-49: CO2, CH4, and N2O Emissions from International Bunker Fuels (Tg CO2Eq.) 3-6
37 Table 3-50: CO2, CH4 and N2O Emissions from International Bunker Fuels (Gg) 3-7
3 8 Table 3-51: Aviation Jet Fuel Consumption for International Transport (Million Gallons) 3-8
39 Table 3-52: Marine Fuel Consumption for International Transport (Million Gallons) 3-8
40 Table 3-53: CO2 Emissions from Wood Consumption by End-Use Sector (Tg CO2 Eq.) 3-10
ix
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1 Table 3-54: CO2 Emissions from Wood Consumption by End-Use Sector (Gg) 3-10
2 Table 3-55: CO2 Emissions fromEthanol Consumption (Tg CO2 Eq.) 3-10
3 Table 3-56: CO2 Emissions fromEthanol Consumption (Gg) 3-10
4 Table 3-57: Woody Biomass Consumption by Sector (Trillion Btu) 3-11
5 Table 3-58: Ethanol Consumption by Sector (Trillion Btu) 3-11
6 Table 4-1: Emissions from Industrial Processes (TgCO2Eq.) 4-1
7 Table 4-2: Emissions from Industrial Processes (Gg) 4-3
8 Table 4-3: CO2 Emissions from Cement Production (Tg CO2 Eq. and Gg) 4-5
9 Table 4-4: Clinker Production (Gg) 4-6
10 Table 4-5: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Cement Production (Tg CO2 Eq. and
11 Percent) 4-6
12 Table 4-6: CO2 Emissions from Lime Production (Tg CO2 Eq. and Gg) 4-7
13 Table 4-7: Potential, Recovered, and Net CO2 Emissions from Lime Production (Gg) 4-8
14 Table 4-8: High-Calcium- and Dolomitic-Quicklime, High-Calcium- and Dolomitic-Hydrated, and Dead-Burned-
15 Dolomite Lime Production (Gg) 4-9
16 Table 4-9: Adjusted Lime Production3 (Gg) 4-9
17 Table 4-10: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Lime Production (Tg CO2 Eq. and
18 Percent) 4-10
19 Table 4-11: CO2 Emissions from Limestone & Dolomite Use (TgCO2Eq.) 4-11
20 Table 4-12: CO2 Emissions from Limestone & Dolomite Use (Gg) 4-11
21 Table 4-13: Limestone and Dolomite Consumption (Thousand Metric Tons) 4-12
22 Table 4-14: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Limestone and Dolomite Use (Tg
23 CO2 Eq. and Percent) 4-13
24 Table 4-15: CO2 Emissions from Soda Ash Production and Consumption (Tg CO2 Eq.) 4-14
25 Table 4-16: CO2 Emissions from Soda Ash Production and Consumption (Gg) 4-14
26 Table 4-17: Soda Ash Production and Consumption (Gg) 4-15
27 Table 4-18: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Soda Ash Production and
28 Consumption (Tg CO2Eq. and Percent) 4-16
29 Table 4-19: CO2 Emissions from Ammonia Production and Urea Consumption (Tg CO2 Eq.) 4-17
30 Table 4-20: CO2 Emissions from Ammonia Production and Urea Consumption (Gg) 4-17
31 Table 4-21: Ammonia Production, Urea Production, Urea Net Imports, and Urea Exports (Gg) 4-18
32 Table 4-22: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Ammonia Production and Urea
33 Consumption (Tg CO2 Eq. and Percent) 4-19
34 Table 4-23: N2O Emissions from Nitric Acid Production (Tg CO2 Eq. and Gg) 4-20
35 Table 4-24: Nitric Acid Production (Gg) 4-20
36 Table 4-25: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from Nitric Acid Production (Tg CO2 Eq.
37 and Percent) 4-21
38 Table 4-26: N2O Emissions from Adipic Acid Production (Tg CO2 Eq. and Gg) 4-22
39 Table 4-27: Adipic Acid Production (Gg) 4-23
x DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Table 4-28: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from Adipic Acid Production (Tg CO2
2 Eq. and Percent) 4-23
3 Table 4-29: CO2 and CH4 Emissions from Silicon Carbide Production and Consumption (Tg CO2 Eq.) 4-24
4 Table 4-30: CO2 and CH4 Emissions from Silicon Carbide Production and Consumption (Gg) 4-24
5 Table 4-31: Production and Consumption of Silicon Carbide (Metric Tons) 4-25
6 Table 4-32: Tier 2 Quantitative Uncertainty Estimates for CH4 and CO2 Emissions from Silicon Carbide Production
7 and Consumption (Tg CO2Eq. and Percent) 4-25
8 Table 4-33: CO2 and CH4 Emissions from Petrochemical Production (Tg CO2 Eq.) 4-26
9 Table 4-34: CO2 and CH4 Emissions from Petrochemical Production (Gg) 4-26
10 Table 4-35: Production of Selected Petrochemicals (Thousand Metric Tons) 4-27
11 Table 4-36: Carbon Black Feedstock (Primary Feedstock) and Natural Gas Feedstock (Secondary Feedstock)
12 Consumption (Thousand Metric Tons) 4-28
13 Table 4-37: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Petrochemical Production and CO2
14 Emissions from Carbon Black Production (Tg CO2 Eq. and Percent) 4-28
15 Table 4-38: CO2 Emissions from Titanium Dioxide (Tg CO2 Eq. and Gg) 4-29
16 Table 4-39: Titanium Dioxide Production (Gg) 4-30
17 Table 4-40: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Titanium Dioxide Production (Tg
18 CO2 Eq. and Percent) 4-31
19 Table 4-41: CO2 Emissions from CO2 Consumption (Tg CO2 Eq. and Gg) 4-32
20 Table 4-42: CO2 Production (Gg CO2) and the Percent Used for Non-EOR Applications for Jackson Dome and
21 Bravo Dome 4-32
22 Table 4-43: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from CO2 Consumption (Tg CO2 Eq. and
23 Percent) 4-33
24 Table 4-44: CO2 Emissions from Phosphoric Acid Production (Tg CO2Eq. andGg) 4-34
25 Table 4-45: Phosphate Rock Domestic Production, Exports, and Imports (Gg) 4-35
26 Table 4-46: Chemical Composition of Phosphate Rock (percent by weight) 4-35
27 Table 4-47: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Phosphoric Acid Production (Tg
28 CO2 Eq. and Percent) 4-36
29 Table 4-48: CO2 and CH4 Emissions from Metallurgical Coke Production (Tg CO2 Eq.) 4-38
30 Table 4-49: CO2 and CH4 Emissions from Metallurgical Coke Production (Gg) 4-38
31 Table 4-50: CO2 Emissions from Iron and Steel Production (Tg CO2 Eq.) 4-39
32 Table 4-51: CO2 Emissions from Iron and Steel Production (Gg) 4-39
33 Table 4-52: CH4 Emissions from Iron and Steel Production (Tg CO2 Eq.) 4-39
34 Table 4-53: CH4 Emissions from Iron and Steel Production (Gg) 4-39
35 Table 4-54: Material Carbon Contents for Metallurgical Coke Production 4-40
36 Table 4-55: Production and Consumption Data for the Calculation of CO2 and CH4 Emissions from Metallurgical
37 Coke Production (Thousand Metric Tons) 4-40
38 Table 4-56: Production and Consumption Data for the Calculation of CO2 Emissions from Metallurgical Coke
39 Production (million ft3) 4-40
40 Table 4-57: CO2 Emission Factors for Sinter Production and Direct Reduced Iron Production 4-41
XI
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1 Table 4-58: Material Carbon Contents for Iron and Steel Production 4-41
2 Table 4-59: CH4 Emission Factors for Sinter and Pig Iron Production 4-42
3 Table 4-60: Production and Consumption Data for the Calculation of CO2 and CH4 Emissions from Iron and Steel
4 Production (Thousand Metric Tons) 4-43
5 Table 4-61: Production and Consumption Data for the Calculation of CO2 Emissions from Iron and Steel
6 Production (million ft3 unless otherwise specified) 4-43
7 Table 4-62: Tier 2 Quantitative Uncertainty Estimates for CO2 and CH4 Emissions from Iron and Steel Production
8 and Metallurgical Coke Production (Tg. CO2Eq. and Percent) 4-44
9 Table 4-63: CO2 and CH4 Emissions from Ferroalloy Production (Tg CO2 Eq.) 4-45
10 Table 4-64: CO2 and CH4 Emissions from Ferroalloy Production (Gg) 4-45
11 Table 4-65: Production of Ferroalloys (Metric Tons) 4-46
12 Table 4-66: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Ferroalloy Production (Tg CO2 Eq.
13 and Percent) 4-47
14 Table 4-67: CO2 Emissions from Aluminum Production (Tg CO2Eq. and Gg) 4-48
15 Table 4-68: PFC Emissions from Aluminum Production (Tg CO2 Eq.) 4-48
16 Table 4-69: PFC Emissions from Aluminum Production (Gg) 4-48
17 Table 4-70: Production of Primary Aluminum (Gg) 4-50
18 Table 4-71: Tier 2 Quantitative Uncertainty Estimates for CO2 and PFC Emissions from Aluminum Production (Tg
19 CO2 Eq. and Percent) 4-51
20 Table 4-72: SF6 Emissions from Magnesium Production and Processing (Tg CO2 Eq. and Gg) 4-52
21 Table 4-73: SF6 Emission Factors (kg SF6 per metric ton of magnesium) 4-53
22 Table 4-74: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Magnesium Production and
23 Processing (Tg CO2 Eq. and Percent) 4-54
24 Table 4-75: CO2 Emissions fromZinc Production (Tg CO2 Eq. and Gg) 4-55
25 Table 4-76: Zinc Production (Metric Tons) 4-56
26 Table 4-77: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Zinc Production (Tg CO2 Eq. and
27 Percent) 4-57
28 Table 4-78: CO2 Emissions fromLeadProduction (Tg CO2 Eq. and Gg) 4-58
29 Table 4-79: Lead Production (Metric Tons) 4-59
30 Table 4-80: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Lead Production (Tg CO2 Eq. and
31 Percent) 4-59
32 Table 4-81: HFC-23 Emissions from HCFC-22 Production (Tg CO2 Eq. and Gg) 4-60
33 Table 4-82: HCFC-22 Production (Gg) 4-61
34 Table 4-83: Quantitative Uncertainty Estimates for HFC-23 Emissions from HCFC-22 Production (Tg CO2 Eq. and
35 Percent) 4-62
36 Table 4-84: Emissions of HFCs and PFCs from ODS Substitutes (TgCO2Eq.) 4-62
37 Table 4-85: Emissions of HFCs and PFCs from ODS Substitution (Mg) 4-63
38 Table 4-86: Emissions of HFCs and PFCs from ODS Substitutes (Tg CO2 Eq.) by Sector 4-63
39 Table 4-87: Tier 2 Quantitative Uncertainty Estimates for HFC and PFC Emissions from ODS Substitutes (Tg CO2
40 Eq. and Percent) 4-66
xii DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Table 4-88: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Tg CO2 Eq.) 4-67
2 Table 4-89: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Mg) 4-67
3 Table 4-90: Tier 2 Quantitative Uncertainty Estimates for HFC, PFC, and SF6 Emissions from Semiconductor
4 Manufacture (TgCO2Eq. and Percent) 4-71
5 Table 4-91: SF6 Emissions from Electric Power Systems and Electrical Equipment Manufacturers (Tg CO2 Eq.)
6 4-72
7 Table 4-92: SF6 Emissions from Electric Power Systems and Electrical Equipment Manufacturers (Gg) 4-72
8 Table 4-93: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Electrical Transmission and
9 Distribution (Tg CO2Eq. and percent) 4-75
10 Table 4-94: NOX, CO, and NMVOC Emissions from Industrial Processes (Gg) 4-76
11 Table 5-1: N2O Emissions from Solvent and Other Product Use (TgCO2Eq. andGg) 5-1
12 Table 5-2: N2O Production (Gg) 5-1
13 Table 5-3: N2O Emissions fromN2O Product Usage (Tg CO2 Eq. and Gg) 5-1
14 Table 5-4: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from N2O Product Usage (Tg CO2 Eq. and
15 Percent) 5-3
16 Table 5-5: Emissions of NOX, CO, and NMVOC from Solvent Use (Gg) 5-4
17 Table 6-1: Emissions from Agriculture (Tg CO2 Eq.) 6-1
18 Table 6-2: Emissions from Agriculture (Gg) 6-1
19 Table 6-3: CH4 Emissions from Enteric Fermentation (Tg CO2 Eq.) 6-2
20 Table 6-4: CH4 Emissions from Enteric Fermentation (Gg) 6-2
21 Table 6-5: Quantitative Uncertainty Estimates for CH4 Emissions from Enteric Fermentation (Tg CO2 Eq. and
22 Percent) 6-5
23 Table 6-6: CH4 and N2O Emissions from Manure Management (Tg CO2Eq.) 6-7
24 Table 6-7: CH4 andN2O Emissions from Manure Management (Gg) 6-8
25 Table 6-8: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O (Direct and Indirect) Emissions from Manure
26 Management (Tg CO2Eq. and Percent) 6-11
27 Table 6-9: CH4 Emissions from Rice Cultivation (Tg CO2 Eq.) 6-13
28 Table 6-10: CH4 Emissions from Rice Cultivation (Gg) 6-13
29 Table 6-11: Rice Areas Harvested (Hectares) 6-14
30 Table 6-12: Ratooned Area as Percent of Primary Growth Area 6-15
31 Table 6-13: Non-USDA Data Sources for Rice Harvest Information 6-15
32 Table 6-14: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Rice Cultivation (Tg CO2 Eq. and
33 Percent) 6-16
34 Table 6-15: N2O Emissions from Agricultural Soils (Tg CO2 Eq.) 6-17
35 Table 6-16: N2O Emissions from Agricultural Soils (Gg) 6-18
36 Table 6-17: Direct N2O Emissions from Agricultural Soils by Land Use Type and N Input Type (Tg CO2 Eq.)... 6-18
37 Table 6-18: Indirect N2O Emissions from all Land-Use Types (Tg CO2Eq.) 6-18
38 Table 6-19: Quantitative Uncertainty Estimates of N2O Emissions from Agricultural Soil Management in 2009 (Tg
39 CO2 Eq. and Percent) 6-26
40 Table 6-20: CH4 and N2O Emissions from Field Burning of Agricultural Residues (Tg CO2 Eq.) 6-28
xiii
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1 Table 6-21: CH4, N2O, CO, and NOX Emissions from Field Burning of Agricultural Residues (Gg) 6-28
2 Table 6-22: Agricultural Crop Production (Gg of Product) 6-30
3 Table 6-23: U.S. Average Percent Crop Area Burned by Crop (Percent) 6-31
4 Table 6-24: Key Assumptions for Estimating Emissions from Field Burning of Agricultural Residues 6-31
5 Table 6-25: Greenhouse Gas Emission Ratios and Conversion Factors 6-31
6 Table 6-26: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Field Burning of
7 Agricultural Residues (Tg CO2Eq. and Percent) 6-31
8 Table 7-1: Net CO2 Flux from Carbon Stock Changes in Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.)
9 7-1
10 Table 7-2: Net CO2 Flux from Carbon Stock Changes in Land Use, Land-Use Change, and Forestry (Tg C) 7-2
11 Table 7-3: Emissions from Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.) 7-2
12 Table 7-4: Emissions from Land Use, Land-Use Change, and Forestry (Gg) 7-3
13 Table 7-5: Size of Land Use and Land-Use Change Categories on Managed Land Area by Land Use and Land Use
14 Change Categories (thousands of hectares) 7-4
15 Table 7-6: Net Annual Changes inC Stocks (TgCO2/yr) in Forest and Harvested Wood Pools 7-14
16 Table 7-7: Net Annual Changes in C Stocks (Tg C/yr) in Forest and Harvested Wood Pools 7-14
17 Table 7-8: Forest area (1000 ha) and C Stocks (Tg C) in Forest and Harvested Wood Pools 7-15
18 Table 7-9: Estimates of CO2 (Tg/yr) emissions for the lower 48 states and Alaska1 7-16
19 Table 7-10: Tier 2 Quantitative Uncertainty Estimates for Net CO2 Flux from Forest Land Remaining Forest Land:
20 Changes in Forest C Stocks (Tg CO2 Eq. and Percent) 7-19
21 Table 7-11: Estimated Non-CO2 Emissions from Forest Fires (Tg CO2Eq.) for U.S. Forests1 7-21
22 Table 7-12: Estimated Non-CO2 Emissions from Forest Fires (Gg Gas) for U.S. Forests1 7-21
23 Table 7-13: Estimated Carbon Released from Forest Fires for U.S. Forests 7-22
24 Table 7-14: Tier 2 Quantitative Uncertainty Estimates of Non-CO2 Emissions from Forest Fires in Forest Land
25 Remaining Forest Land (Tg CO2Eq. and Percent) 7-22
26 Table 7-15: Direct N2O Fluxes from Soils in Forest Land Remaining Forest Land (Tg CO2 Eq. and Gg N2O).... 7-23
27 Table 7-16: Quantitative Uncertainty Estimates of N2O Fluxes from Soils in Forest Land Remaining Forest Land
28 (Tg CO2 Eq. and Percent) 7-24
29 Table 7-17: Net CO2 Flux from Soil C Stock Changes in Cropland Remaining Cropland (Tg CO2 Eq.) 7-26
30 Table 7-18: Net CO2 Flux from Soil C Stock Changes in Cropland Remaining Cropland (Tg C) 7-26
31 Table 7-19: Tier 2 Quantitative Uncertainty Estimates for Soil C Stock Changes occurring within Cropland
32 Remaining Cropland (Tg CO2 Eq. and Percent) 7-30
33 Table 7-20: Emissions from Liming of Agricultural Soils (Tg CO2Eq.) 7-31
34 Table 7-21: Emissions from Liming of Agricultural Soils (TgC) 7-31
35 Table 7-22: Applied Minerals (Million Metric Tons) 7-32
36 Table 7-23: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Liming of Agricultural Soils (Tg
37 CO2 Eq. and Percent) 7-33
3 8 Table 7-24: CO2 Emissions from Urea Fertilization in Cropland Remaining Cropland (Tg CO2 Eq.) 7-33
3 9 Table 7-25: CO2 Emissions from Urea Fertilization in Cropland Remaining Cropland (Tg C) 7-33
40 Table 7-26: Applied Urea (Million Metric Tons) 7-34
xiv DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Table 7-27: Quantitative Uncertainty Estimates for CO2 Emissions from Urea Fertilization (Tg CO2 Eq. and Percent)
2 7-34
3 Table 7-28: Net CO2 Flux from Soil C Stock Changes in Land Converted to Cropland (Tg CO2 Eq.) 7-35
4 Table 7-29: Net CO2 Flux from Soil C Stock Changes in Land Converted to Cropland (Tg C) 7-35
5 Table 7-30: Tier 2 Quantitative Uncertainty Estimates for Soil C Stock Changes occurring within Land Converted to
6 Cropland (Tg CO2 Eq. and Percent) 7-37
7 Table 7-31: Net CO2 Flux from Soil C Stock Changes in Grassland Remaining Grassland (Tg CO2 Eq.) 7-38
8 Table 7-32: Net CO2 Flux from Soil C Stock Changes in Grassland Remaining Grassland (Tg C) 7-38
9 Table 7-33: Tier 2 Quantitative Uncertainty Estimates for C Stock Changes occurring within Grassland Remaining
10 Grassland (Tg CO2 Eq. and Percent) 7-40
11 Table 7-34: Net CO2 Flux from Soil C Stock Changes for Land Converted to Grassland (Tg CO2 Eq.) 7-42
12 Table 7-35: Net CO2 Flux from Soil C Stock Changes for Land Converted to Grassland (Tg C) 7-42
13 Table 7-36: Tier 2 Quantitative Uncertainty Estimates for Soil C Stock Changes occurring within Land Converted to
14 Grassland (Tg CO2 Eq. and Percent) 7-44
15 Table 7-37: Emissions fromPeatlandsRemaining Peatlands (Tg CO2Eq.) 7-46
16 Table 7-38: Emissions from. Peatlands Remaining Peatlands (Gg) 7-46
17 Table 7-39: Peat Production of Lower 48 States (in thousands of Metric Tons) 7-47
18 Table 7-40: Peat Production of Alaska (in thousands of Cubic Meters) 7-47
19 Table 7-41: Tier-2 Quantitative Uncertainty Estimates for CO2 Emissions from Peatlands Remaining Peatlands
20 7-48
21 Table 7-42: Net C Flux from Urban Trees (Tg CO2 Eq. and Tg C) 7-49
22 Table 7-43: C Stocks (Metric Tons C), Annual C Sequestration (Metric Tons C/yr), Tree Cover (Percent), and
23 Annual C Sequestration per Area of Tree Cover (kg C/m2-yr)for 14 U.S. Cities 7-51
24 Table 7-44: Tier 2 Quantitative Uncertainty Estimates for Net C Flux from Changes in C Stocks in Urban Trees
25 (Tg CO2 Eq. and Percent) 7-52
26 Table 7-45: Direct N2O Fluxes from Soils in Settlements Remaining Settlements (Tg CO2Eq. and GgN2O) 7-53
27 Table 7-46: Quantitative Uncertainty Estimates of N2O Emissions from Soils in Settlements Remaining Settlements
28 (Tg CO2 Eq. and Percent) 7-54
29 Table 7-47: Net Changes in Yard Trimming and Food Scrap Stocks in Landfills (Tg CO2 Eq.) 7-56
30 Table 7-48: Net Changes in Yard Trimming and Food Scrap Stocks in Landfills (Tg C) 7-56
31 Table 7-49: Moisture Content (%), C Storage Factor, Proportion of Initial C Sequestered (%), Initial C Content (%),
32 and Decay Rate (year"1) for Landfilled Yard Trimmings and Food Scraps in Landfills 7-58
33 Table 7-50: C Stocks in Yard Trimmings and Food Scraps in Landfills (Tg C) 7-58
34 Table 7-51: Tier 2 Quantitative Uncertainty Estimates for CO2 Flux from Yard Trimmings and Food Scraps in
35 Landfills (Tg CO2 Eq. and Percent) 7-59
36 Table 8-1. Emissions from Waste (Tg CO2 Eq.) 8-1
37 Table 8-2. Emissions from Waste (Gg) 8-2
38 Table 8-3. CH4 Emissions from Landfills (Tg CO2 Eq.) 8-3
39 Table 8-4. CH4 Emissions from Landfills (Gg) 8-3
40 Table 8-5. Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Landfills (Tg CO2 Eq. and Percent)8-5
xv
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1 Table 8-6. CH4 and N2O Emissions from Domestic and Industrial Wastewater Treatment (Tg CO2 Eq.) 8-7
2 Table 8-7. CH4 and N2O Emissions from Domestic and Industrial Wastewater Treatment (Gg) 8-8
3 Table 8-8. U.S. Population (Millions) and Domestic Wastewater BOD5 Produced (Gg) 8-10
4 Table 8-9. Domestic Wastewater CH4 Emissions from Septic and Centralized Systems (2009) 8-10
5 Table 8-10. Industrial Wastewater CH4 Emissions by Sector (2009) 8-10
6 Table 8-11. U.S. Pulp and Paper, Meat, Poultry, Vegetables, Fruits and Juices, Ethanol, and Petroleum Refining
7 Production (Tg) 8-10
8 Table 8-12. Variables Used to Calculate Percent Wastewater Treated Anaerobically by Industry (%) 8-11
9 Table 8-13. Wastewater Flow (m3/ton) and BOD Production (g/L) for U.S. Vegetables, Fruits, and Juices Production
10
11 Table 8-14. U.S. Population (Millions), Available Protein (kg/person-year), and Protein Consumed (kg/person-year)
12 8-15
13 Table 8-15. Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Wastewater Treatment (Tg CO2 Eq.
14 and Percent) 8-16
15 Table 8-16. CH4 and N2O Emissions from Composting (Tg CO2 Eq.) 8-18
16 Table 8-17. CH4 and N2O Emissions from Composting (Gg) 8-18
17 Table 8-18: U.S. Waste Composted (Gg) 8-19
18 Table 8-19 : Tier 1 Quantitative Uncertainty Estimates for Emissions from Composting (Tg CO2 Eq. and Percent)
19 8-19
20 Table 8-20: Emissions of NOX, CO, and NMVOC from Waste (Gg) 8-19
21 Table 10-1: Revisions to U.S. Greenhouse Gas Emissions (Tg CO2 Eq.) 10-2
22 Table 10-2: Revisions to Net Flux of CO2 to the Atmosphere from Land Use, Land-Use Change, and Forestry (Tg
23 CO2Eq.) 10-4
24
25 Figures
26 Figure ES-1: U.S. Greenhouse Gas Emissions by Gas ES-4
27 Figure ES-2: Annual Percent Change in U.S. Greenhouse Gas Emissions ES-4
28 Figure ES-3: Cumulative Change in Annual U.S. Greenhouse Gas Emissions Relative to 1990 ES-4
29 Figure ES-4: 2009 Greenhouse Gas Emissions by Gas (percents based on Tg CO2 Eq.) ES-6
30 Figure ES-5: 2009 Sources of CO2 Emissions ES-7
31 Figure ES-6: 2009 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type ES-7
32 Figure ES-7: 2009 End-Use Sector Emissions of CO2, CH4, andN2O from Fossil Fuel Combustion ES-7
33 Figure ES-8: 2009 Sources of CH4 Emissions ES-9
34 Figure ES-9: 2009 Sources of N2O Emissions ES-10
35 Figure ES-10: 2009 Sources of HFCs, PFCs, and SF6 Emissions ES-10
36 Figure ES-11: U.S. Greenhouse Gas Emissions and Sinks by Chapter/TPCC Sector ES-11
37 Figure ES-12: 2009 U.S. Energy Consumption by Energy Source ES-12
38 Figure ES-13: Emissions Allocated to Economic Sectors ES-14
39 Figure ES-14: Emissions with Electricity Distributed to Economic Sectors ES-15
xvi DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Figure ES-15: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product ES-16
2 Figure ES-16: 2009 Key Categories ES-18
3 Figure 1-1
4 Figure 2-1
5 Figure 2-2
6 Figure 2-3
7 Figure 2-4
8 Figure 2-5
9 Figure 2-6
10 Figure 2-7
11 Figure 2-8
12 Figure 2-9
U.S. QA/QC Plan Summary 1-15
U.S. Greenhouse Gas Emissions by Gas 2-1
Annual Percent Change in U.S. Greenhouse Gas Emissions 2-1
Cumulative Change in Annual U.S. Greenhouse Gas Emissions Relative to 1990 2-1
U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector 2-7
2009 Energy Chapter Greenhouse Gas Sources 2-8
2009 U.S. Fossil Carbon Flows (TgCO2Eq.) 2-8
2009 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type 2-9
2009 End-Use Sector Emissions from Fossil Fuel Combustion 2-10
2009 Industrial Processes Chapter Greenhouse Gas Sources 2-11
13 Figure 2-10: 2009 Agriculture Chapter Greenhouse Gas Sources 2-13
14 Figure 2-11: 2009 Waste Chapter Greenhouse Gas Sources 2-15
15 Figure 2-12: Emissions Allocated to Economic Sectors 2-16
16 Figure 2-13: Emissions with Electricity Distributed to Economic Sectors 2-19
17 Figure 2-14: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product 2-25
18 Figure 3-1: 2009 Energy Chapter Greenhouse Gas Sources 3-1
19 Figure 3-2: 2009 U.S. Fossil CarbonFlows (Tg CO2 Eq.) 3-1
20 Figure 3-3: 2009 U.S. Energy Consumption by Energy Source 3-5
21 Figure 3-4: U.S. Energy Consumption (QuadrillionBtu) 3-5
22 Figure 3-5: 2009 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type 3-5
23 Figure 3 -6: Annual Deviations from Normal Heating Degree Days for the United States (1950-2009) 3-5
24 Figure 3 -7: Annual Deviations from Normal Cooling Degree Days for the United States (1950-2009) 3-5
25 Figure 3 -8: Nuclear, Hydroelectric, and Wind Power Plant Capacity Factors in the United States (1990-2009).... 3 -6
26 Figure 3-9: Electricity Generation Retail Sales by End-Use Sector 3-10
27 Figure 3-10: Industrial Production Indices (Index 2002= 100) 3-11
28 Figure 3-11: Sales-Weighted Fuel Economy of New Passenger Cars and Light-Duty Trucks, 1990-2008 3-13
29 Figure 3-12: Sales of New Passenger Cars and Light-Duty Trucks, 1990-2008 3-13
30 Figure 3-13: Mobile Source CH4 and N2O Emissions 3-15
31 Figure 3-14: U.S. Energy Consumption and Energy-Related CO2 Emissions Per Capita and Per Dollar GDP 3-20
32 Figure 4-1: 2009 Industrial Processes Chapter Greenhouse Gas Sources 4-1
33 Figure 6-1: 2009 Agriculture Chapter Greenhouse Gas Emission Sources 6-1
34 Figure 6-2: Sources and Pathways of N that Result in N2O Emissions from Agricultural Soil Management 6-17
35 Figure 6-3: Major Crops, Average Annual Direct N2O Emissions Estimated Using the DAYCENT Model, 1990-
36 2009(TgCO2Eq./year) 6-19
37 Figure 6-4: Grasslands, Average Annual Direct N2O Emissions Estimated Using the DAYCENT Model, 1990-2009
38 (Tg CO2 Eq./year) 6-19
xvii
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1 Figure 6-5: Major Crops, Average Annual N Losses Leading to Indirect N2O Emissions Estimated Using the
2 DAYCENT Model, 1990-2009 (GgN/year) 6-19
3 Figure 6-6: Grasslands, Average Annual N Losses Leading to Indirect N2O Emissions Estimated Using the
4 DAYCENT Model, 1990-2009 (GgN/year) 6-19
5 Figure 6-7: Comparison of Measured Emissions at Field Sites and Modeled Emissions Using the DAYCENT
6 Simulation Model 6-26
7 Figure 7-1. Percent of Total Land Area in the General Land-Use Categories for 2009 7-5
8 Figure 7-2: Forest Sector Carbon Pools and Flows 7-13
9 Figure 7-3: Estimates of Net Annual Changes in C Stocks for Maj or C Pools 7-15
10 Figure 7-4: Average C Density in the Forest Tree Pool in the Conterminous United States, 2009 7-15
11 Figure 7-5: Total Net Annual CO2 Flux for Mineral Soils under Agricultural Management within States, 2009,
12 Cropland Remaining Cropland 7-26
13 Figure 7-6: Total Net Annual CO2 Flux for Organic Soils under Agricultural Management within States, 2009,
14 Cropland Remaining Cropland 7-26
15 Figure 7-7: Total Net Annual CO2 Flux for Mineral Soils under Agricultural Management within States, 2009, Land
16 Converted to Cropland 7-36
17 Figure 7-8: Total Net Annual CO2 Flux for Organic Soils under Agricultural Management within States, 2009, Land
18 Converted to Cropland 7-36
19 Figure 7-9: Total Net Annual CO2 Flux for Mineral Soils under Agricultural Management within States, 2009,
20 Grassland Remaining Grassland 7-39
21 Figure 7-10: Total Net Annual CO2 Flux for Organic Soils under Agricultural Management within States, 2009,
22 Grassland Remaining Grassland 7-39
23 Figure 7-11: Total Net Annual CO2 Flux for Mineral Soils under Agricultural Management within States, 2009,
24 Land Converted to Grassland 7-42
25 Figure 7-12: Total Net Annual CO2 Flux for Organic Soils under Agricultural Management within States, 2009,
26 Land Converted to Grassland 7-43
27 Figure 8-1: 2009 Waste Chapter Greenhouse Gas Sources 8-1
28
29 Boxes
30 BoxES-1: Methodological approach for estimating and reporting U.S. emissions and sinks ES-1
31 BoxES-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data ES-15
32 BoxES-3: Recalculations of Inventory Estimates ES-18
33 Box 1-1: Methodological approach for estimating and reporting U.S. emissions and sinks 1-2
34 Box 1-2: The IPCC Fourth Assessment Report and Global Warming Potentials 1-8
35 Box 1-3: IPCC Reference Approach 1-12
36 Box 2-1: Methodology for Aggregating Emissions by Economic Sector 2-24
37 Box 2-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data 2-25
38 Box 2-3: Sources and Effects of Sulfur Dioxide 2-27
39 Box 3 -1: Weather and Non-Fossil Energy Effects on CO2 from Fossil Fuel Combustion Trends 3-5
40 Box 3-2: Carbon Intensity of U.S. Energy Consumption 3-19
41 Box 3-3. Carbon Dioxide Transport, Injection, and Geological Storage 3-3
xviii DRAFT- Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Box 6-1. Tier 1 vs. Tier 3 Approach for Estimating N2O Emissions 6-20
2 Box 6-2: Comparison of Tier 2 U. S. Inventory Approach and IPCC (2006) Default Approach 6-29
3 Box 7-1: Methodological approach for estimating and reporting U.S. emissions and sinks 7-3
4 Box 7-2: CO2 Emissions from Forest Fires 7-15
5 Box 7-3: Tier 3 Approach for Soil C Stocks Compared to Tier 1 or 2 Approaches 7-27
6 Box8-1: BiogenicWastesinLandfills 8-6
7
xix
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i Executive Summary
2 An emissions inventory that identifies and quantifies a country's primary anthropogenic1 sources and sinks of
3 greenhouse gases is essential for addressing climate change. This inventory adheres to both 1) a comprehensive and
4 detailed set of methodologies for estimating sources and sinks of anthropogenic greenhouse gases, and 2) a common
5 and consistent mechanism that enables Parties to the United Nations Framework Convention on Climate Change
6 (UNFCCC) to compare the relative contribution of different emission sources and greenhouse gases to climate
7 change.
8 In 1992, the United States signed and ratified the UNFCCC. As stated in Article 2 of the UNFCCC, "The ultimate
9 objective of this Convention and any related legal instruments that the Conference of the Parties may adopt is to
10 achieve, in accordance with the relevant provisions of the Convention, stabilization of greenhouse gas
11 concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the
12 climate system. Such a level should be achieved within a time-frame sufficient to allow ecosystems to adapt
13 naturally to climate change, to ensure that food production is not threatened and to enable economic development to
14 proceed in a sustainable manner."2
15 Parties to the Convention, by ratifying, "shall develop, periodically update, publish and make available.. .national
16 inventories of anthropogenic emissions by sources and removals by sinks of all greenhouse gases not controlled by
17 the Montreal Protocol, using comparable methodologies.. ."3 The United States views this report as an opportunity
18 to fulfill these commitments.
19 This chapter summarizes the latest information on U.S. anthropogenic greenhouse gas emission trends from 1990
20 through 2009. To ensure that the U.S. emissions inventory is comparable to those of other UNFCCC Parties, the
21 estimates presented here were calculated using methodologies consistent with those recommended in the Revised
22 1996 Intergovernmental Panel on Climate Change (IPCC) Guidelines for National Greenhouse Gas Inventories
23 (IPCC/UNEP/OECD/IEA 1997), the IPCC Good Practice Guidance and Uncertainty Management in National
24 Greenhouse Gas Inventories (IPCC 2000), and the IPCC Good Practice Guidance for Land Use, Land-Use Change,
25 and Forestry (IPCC 2003). Additionally, the U.S. emission inventory has continued to incorporate new
26 methodologies and data from the 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006).
27 The structure of this report is consistent with the UNFCCC guidelines for inventory reporting.4 For most source
28 categories, the IPCC methodologies were expanded, resulting in a more comprehensive and detailed estimate of
29 emissions.
30
31 [BEGIN BOX]
32 Box ES-1: Methodological approach for estimating and reporting U.S. emissions and sinks
33 In following the UNFCCC requirement under Article 4.1 to develop and submit national greenhouse gas emissions
34 inventories, the emissions and sinks presented in this report are organized by source and sink categories and
35 calculated using internationally-accepted methods provided by the IPCC.5 Additionally, the calculated emissions
36 and sinks in a given year for the U. S. are presented in a common manner in line with the UNFCCC reporting
37 guidelines for the reporting of inventories under this international agreement.6 The use of consistent methods to
38 calculate emissions and sinks by all nations providing their inventories to the UNFCCC ensures that these reports
1 The term "anthropogenic", in this context, refers to greenhouse gas emissions and removals that are a direct result of human
activities or are the result of natural processes that have been affected by human activities (IPCC/UNEP/OECD/IEA 1997).
2 Article 2 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate
Change. See.
3 Article 4(l)(a) of the United Nations Framework Convention on Climate Change (also identified in Article 12). Subsequent
decisions by the Conference of the Parties elaborated the role of Annex I Parties in preparing national inventories. See
.
4 See .
5 See < http://www.ipcc-nggip.iges.or.jp/public/index.html>.
6 See.
Executive Summary ES-1
-------
1 are comparable. In this regard, U.S. emissions and sinks reported in this inventory report are comparable to
2 emissions and sinks reported by other countries. Emissions and sinks provided in this inventory do not preclude
3 alternative examinations, but rather this inventory report presents emissions and sinks in a common format
4 consistent with how countries are to report inventories under the UNFCCC. The report itself follows this
5 standardized format, and provides an explanation of the IPCC methods used to calculate emissions and sinks, and
6 the manner in which those calculations are conducted.
7
8 [END BOX]
9
10 Background Information
11 Naturally occurring greenhouse gases include water vapor, carbon dioxide (CO2), methane (CH4), nitrous oxide
12 (N2O), and ozone (O3). Several classes of halogenated substances that contain fluorine, chlorine, or bromine are
13 also greenhouse gases, but they are, for the most part, solely a product of industrial activities. Chlorofluorocarbons
14 (CFCs) and hydrochlorofluorocarbons (HCFCs) are halocarbons that contain chlorine, while halocarbons that
15 contain bromine are referred to as bromofluorocarbons (i.e., halons). As stratospheric ozone depleting substances,
16 CFCs, HCFCs, and halons are covered under the Montreal Protocol on Substances that Deplete the Ozone Layer.
17 The UNFCCC defers to this earlier international treaty. Consequently, Parties to the UNFCCC are not required to
18 include these gases in their national greenhouse gas emission inventories.7 Some other fluorine-containing
19 halogenated substances—hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6)—do
20 not deplete stratospheric ozone but are potent greenhouse gases. These latter substances are addressed by the
21 UNFCCC and accounted for in national greenhouse gas emission inventories.
22 There are also several gases that do not have a direct global warming effect but indirectly affect terrestrial and/or
23 solar radiation absorption by influencing the formation or destruction of greenhouse gases, including tropospheric
24 and stratospheric ozone. These gases include carbon monoxide (CO), oxides of nitrogen (NOX), and non-CH4
25 volatile organic compounds (NMVOCs). Aerosols, which are extremely small particles or liquid droplets, such as
26 those produced by sulfur dioxide (SO2) or elemental carbon emissions, can also affect the absorptive characteristics
27 of the atmosphere.
28 Although the direct greenhouse gases CO2, CH4, and N2O occur naturally in the atmosphere, human activities have
29 changed their atmospheric concentrations. From the pre-industrial era (i.e., ending about 1750) to 2005,
30 concentrations of these greenhouse gases have increased globally by 36, 148, and 18 percent, respectively (IPCC
31 2007).
32 Beginning in the 1950s, the use of CFCs and other stratospheric ozone depleting substances (ODS) increased by
33 nearly 10 percent per year until the mid-1980s, when international concern about ozone depletion led to the entry
34 into force of the Montreal Protocol. Since then, the production of ODS is being phased out. In recent years, use of
35 ODS substitutes such as HFCs and PFCs has grown as they begin to be phased in as replacements for CFCs and
36 HCFCs. Accordingly, atmospheric concentrations of these substitutes have been growing (IPCC 2007).
37 Global Warming Potentials
38 Gases in the atmosphere can contribute to the greenhouse effect both directly and indirectly. Direct effects occur
39 when the gas itself absorbs radiation. Indirect radiative forcing occurs when chemical transformations of the
40 substance produce other greenhouse gases, when a gas influences the atmospheric lifetimes of other gases, and/or
41 when a gas affects atmospheric processes that alter the radiative balance of the earth (e.g., affect cloud formation or
42 albedo).8 The IPCC developed the Global Warming Potential (GWP) concept to compare the ability of each
43 greenhouse gas to trap heat in the atmosphere relative to another gas.
7 Emissions estimates of CFCs, HCFCs, halons and other ozone-depleting substances are included in the annexes of the
Inventory report for informational purposes.
8 Albedo is a measure of the Earth's reflectivity, and is defined as the fraction of the total solar radiation incident on a body that
is reflected by it.
ES-2 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 The GWP of a greenhouse gas is defined as the ratio of the time-integrated radiative forcing from the instantaneous
2 release of 1 kilogram (kg) of a trace substance relative to that of 1 kg of a reference gas (IPCC 2001). Direct
3 radiative effects occur when the gas itself is a greenhouse gas. The reference gas used is CO2, and therefore GWP-
4 weighted emissions are measured in teragrams (or million metric tons) of CO2 equivalent (Tg CO2 Eq.).9'10 All
5 gases in this Executive Summary are presented in units of Tg CO2 Eq.
6 The UNFCCC reporting guidelines for national inventories were updated in 2006,n but continue to require the use
7 of GWPs from the IPCC Second Assessment Report (SAR) (IPCC 1996). This requirement ensures that current
8 estimates of aggregate greenhouse gas emissions for 1990 to 2009 are consistent with estimates developed prior to
9 the publication of the IPCC Third Assessment Report (TAR) (IPCC 2001) and the IPCC Fourth Assessment Report
10 (AR4) (IPCC 2007). Therefore, to comply with international reporting standards under the UNFCCC, official
11 emission estimates are reported by the United States using SAR GWP values. All estimates are provided throughout
12 the report in both CO2 equivalents and unweighted units. A comparison of emission values using the SAR GWPs
13 versus the TAR and AR4 GWPs can be found in Chapter 1 and, in more detail, in Annex 6.1 of this report. The
14 GWP values used in this report are listed below in Table ES-1.
15 Table ES-1: Global Warming Potentials (100-Year Time Horizon) Used in this Report
Gas
C02
CH4*
N20
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
CF4
C2F6
C4F10
C6F14
SF6
GWP
1
21
310
11,700
650
2,800
1,300
3,800
140
2,900
6,300
1,300
6,500
9,200
7,000
7,400
23,900
16 Source: IPCC (1996)
17 * The CH4 GWP includes the direct effects and those indirect effects due to the production of tropospheric ozone and
18 stratospheric water vapor. The indirect effect due to the production of CO2 is not included.
19
20 Global warming potentials are not provided for CO, NOX, NMVOCs, SO2, and aerosols because there is no agreed-
21 upon method to estimate the contribution of gases that are short-lived in the atmosphere, spatially variable, or have
22 only indirect effects on radiative forcing (IPCC 1996).
23 Recent Trends in U.S. Greenhouse Gas Emissions and Sinks
24 In 2009, total U.S. greenhouse gas emissions were 6,639.7 Tg CO2 Eq. While total U.S. emissions have increased
25 by 7.4 percent from 1990 to 2009, emissions decreased from 2008 to 2009 by 6.0 percent (422.2 Tg CO2 Eq.). This
26 decrease was primarily due to (1) a decrease in economic output resulting in a decrease in energy consumption
27 across all sectors; and (2) a decrease in the carbon intensity of fuels used to generate electricity due to fuel switching
28 as the price of coal increased, and the price of natural gas decreased significantly. Since 1990, U.S. emissions have
29 increased at an average annual rate of 0.4%.
9 Carbon comprises 12/44fts of carbon dioxide by weight.
10 One teragram is equal to 1012 grams or one million metric tons.
11 See .
Executive Summary ES-3
-------
1
2
o
6
4
5
6
7
Figure ES-1 through Figure ES-3 illustrate the overall trends in total U.S. emissions by gas, annual changes, and
absolute change since 1990. Table ES-2 provides a detailed summary of U.S. greenhouse gas emissions and sinks
for 1990 through 2009.
Figure ES-1: U.S. Greenhouse Gas Emissions by Gas
Figure ES-2: Annual Percent Change in U.S. Greenhouse Gas Emissions
9
10
11
12
Figure ES-3: Cumulative Change in Annual U.S. Greenhouse Gas Emissions Relative to 1990
Table ES-2: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq. or million metric tons CO2
Eq.)
Gas/Source
1990
2000
2005
2006
2007
2008
Iron and Steel Production &
Metallurgical Coke Production 99.5 85.9
Natural Gas Systems 37.6 29.9
Cement Production 33.3 41.2
Incineration of Waste g.ol 11.1
Ammonia Production and Urea
Consumption 16.8 16.4
Lime Production 11.5 14.1
Cropland Remaining Cropland 7.11 7.5
Limestone and Dolomite Use ^. 1B ^. 1
Soda Ash Production and
Consumption 4.11 4.2
Aluminum Production 6.81 6.1
Petrochemical Production 3.31 4.5
Carbon Dioxide Consumption 1.4l 1.4
Ferroalloy Production 2.2B 1.9
Titanium Dioxide Production l-^l !
Wetlands Remaining Wetlands l.ol 1.2
Phosphoric Acid Production 1-^B 1
Zinc Production 0.?B 1.0
Lead Production 0.5B 0.6
Petroleum Systems 0.6B 0.5
Silicon Carbide Production and
Consumption 0.4B 0.2
Land Use, Land-Use Change, and
Forestry (Sink)" (861.5m (576.6)1
Biomass - Woodb 215.2 218.1
International Bunker Fuels' 111.8 98.5
Biomass - Ethanof 4.1M 9.0
CH4 674.9 659.9
\.1
\.\
\.1
.3
.4
.8
.1
.4
.1
3.6
3.5
4.2
3.8
3.8
1.7
1.5
1.8
0.9
1.2
1.1
0.6
0.5
4.1
4.3
3.9
1.9
1.6
1.9
1.0
1.2
1.1
0.6
0.5
0.2
(1,056.5)
206.9
110.5
22.1
631.4
0.2
0.2
0.2
2009
C02
Fossil Fuel Combustion
Electricity Generation
Transportation
Industrial
Residential
Commercial
U.S. Territories
Non-Energy Use of Fuels
5
4
1
1
,100
,741
,820
,485
849
338
219
27
116
.2
.2
:»
.9
.3
.3
.0
.9
.2
5
5
2
1
,976.
,597.
,296.
,809.
853.
370.
230.
35.
142.
2
7
1
7 •
8
9
5
6,114.7
5,755.6
2,402.1
1,896.6
825.5
357.9
223.5
50.0
141.3
6,022.6
5,657.0
2,346.4
1,878.1
852.1
321.5
208.6
50.3
142.4
6,121.5
5,760.6
2,412.8
1,894.0
845.9
342.4
219.4
46.1
134.1
5,922.5
5,568.7
2,360.9
1,789.9
805.6
348.2
224.2
39.8
138.7
5,508.1
5,212.0
2,154.0
1,718.9
738.4
340.2
218.8
41.7
122.1
65.9
29.9
45.9
12.5
68.8
30.8
46.6
12.5
71.0
31.1
45.2
12.7
66.0
32.8
41.1
12.2
42.6
32.2
29.4
12.3
12.8
14.4
7.9
6.8
12.3
15.1
7.9
8.0
14.0
14.6
8.2
7.7
11.9
14.3
8.7
6.3
11.8
11.2
7.8
7.6
U
1.5
3.4
.8
.6
.8
.0
.2
.2
3.6
3.5
4.3
3.0
2.7
1.8
1.6
1.5
1.1
1.0
1.0
0.5
0.5
0.1
(1,064.3) (1,060.9) (1,040.5) (1,015.1)
203.8 203.3 198.4 183.8
129.1 127.1 135.2 131.3
29.9 37.5 52.8 59.0
672.1 664.6 676.7 686.5
ES-4 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Natural Gas Systems 189.8
Enteric Fermentation 132.1
Landfills 147.4
Coal Mining 84.1
Manure Management 31.7
Petroleum Systems 35.4
Wastewater Treatment 23.5
Forest Land Remaining Forest
Land 3.2
Rice Cultivation 7.1
Stationary Combustion 7.4
Abandoned Underground Coal
Mines 6.0
Mobile Combustion 4.7
Composting 0.3
Petrochemical Production 0.9
Iron and Steel Production &
Metallurgical Coke Production 1.0
Field Burning of Agricultural
Residues 0.3
Ferroalloy Production +1
Silicon Carbide Production and
Consumption +1
Incineration of Waste +1
International Bunker Fuels0 0.2
N2O 315.2
Agricultural Soil Management 197.8
Mobile Combustion 43.9
Manure Management 14.5
Nitric Acid Production 17.7
Stationary Combustion 12.8
Forest Land Remaining Forest
Land 2.7
Wastewater Treatment 3.7
N2O from Product Uses 4.4
Adipic Acid Production 15.8
Composting 0.4
Settlements Remaining Settlements 1.0
Incineration of Waste 0.5
Field Burning of Agricultural
Residues 0.1
Wetlands Remaining Wetlands +1
International Bunker Fuelsc 1.1
HFCs 36.9
Substitution of Ozone Depleting
Substances'1 0.3
HCFC-22 Production 36.4
Semiconductor Manufacture 0.2
PFCs 20.8
Semiconductor Manufacture 2.2
Aluminum Production 18.5
SF6 34.4
Electrical Transmission and
Distribution 28.4
Magnesium Production and
Processing 5.4
|209.3|
136.5B
111.7
209.3
136.5
111.7
60.4
42.4J
31.51
25.2
14.3
75I
6.6\
7.4
12
0.9J
0.1
341.0
206.8
53.2
17l[
19.4J
14.61
121
45l
4.9J
55[
1.4l
l.ll
0.4|
°
0.9\
103.2
74.31
28.6J
0.3
13.5
4.9J
8.6J
20.1
16.0J
3.0
190.4
136.5
112.5
56.9
46.6
29.4
24.3
217.7
138.8
111.7
58.2
46.7
29.4
24.5
205.2
141.0
111.3
57.9
50.7
30.0
24.4
211.8
140.6
115.9
67.1
49.4
30.2
24.5
221.2
139.8
117.5
71.0
49.5
30.9
24.5
9.8
6.8
6.6
0.7
0.2
0.1
1.0
120.2
15.1
2.9
21.6
5.9
6.2
20.0
6.2
6.5
0.7
0.2
0.7
0.2
0.1
1.2
123.4
0.1
1.2
129.5
14.1
2.9
13.2
2.6
11.9
7.2
6.5
0.6
0.1
1.2
129.1
13.3
1.9
7.8
7.3
6.2
5.5
2.5
1.6
1.1
5.5
2.3
1.6
1.0
5.6
2.2
1.7
1.0
5.9
2.0
1.7
0.9
5.5
2.2
1.7
0.8
0.4
0.2
0.1
322.9
211.3
36.9
17.3
16.5
14.7
0.2
326.4
208.9
33.6
18.0
16.2
14.4
0.2
325.1
209.4
30.3
18.1
19.2
14.6
0.2
310.8
210.7
26.1
17.9
16.4
14.2
0.2
299.5
204.6
27.8
17.9
14.6
12.8
8.4
4.8
4.4
5.0
1.7
1.5
0.4
18.0
4.8
4.4
4.3
1.8
1.5
0.4
16.7
4.9
4.4
3.7
1.8
1.6
0.4
10.1
5.0
4.4
2.0
1.9
1.5
0.4
6.7
5.0
4.4
1.9
1.8
1.5
0.4
0.1
1.2
125.0
104.2
15.8
0.2
6.2
3.2
3.0
19.0
109.3
13.8
0.3
6.0
3.5
2.5
17.9
112.2
17.0
0.3
7.5
3.7
3.8
16.7
115.2
13.6
0.3
6.6
4.0
2.7
16.1
119.3
5.4
0.3
5.6
4.0
1.6
14.8
12.8
1.1
Executive Summary ES-5
-------
Semiconductor Manufacture 0.5 1.1 1.0 1.0 0.8 0.9 1.0
Total
Net Emissions
(Sources
and
Sinks)
6,182.2
5,320.7
7,113.9
6,537.3
7,214.5
6,158.1
7,
6,
168.4
104.1
7,264.8
6,203.9
7,061.9
6,021.5
6,639.7
5,624.6
1 + Does not exceed 0.05 Tg CO2 Eq.
2 a Parentheses indicate negative values or sequestration. The net CO2 flux total includes both emissions and sequestration, and
3 constitutes a net sink in the United States. Sinks are only included in net emissions total.
4 b Emissions from Wood Biomass and Ethanol Consumption are not included specifically in summing energy sector totals. Net
5 carbon fluxes from changes in biogenic carbon reservoirs are accounted for in the estimates for Land Use, Land-Use Change, and
6 Forestry.
7 ° Emissions from International Bunker Fuels are not included in totals.
8 d Small amounts of PFC emissions also result from this source.
9 Note: Totals may not sum due to independent rounding.
10
11 Figure ES-4 illustrates the relative contribution of the direct greenhouse gases to total U.S. emissions in 2009. The
12 primary greenhouse gas emitted by human activities in the United States was CO2, representing approximately 83.0
13 percent of total greenhouse gas emissions. The largest source of CO2, and of overall greenhouse gas emissions, was
14 fossil fuel combustion. CH4 emissions, which have increased by 1.7 percent since 1990, resulted primarily from
15 natural gas systems, enteric fermentation associated with domestic livestock, and decomposition of wastes in
16 landfills. Agricultural soil management and mobile source fuel combustion were the major sources of N2O
17 emissions. Ozone depleting substance substitute emissions and emissions of HFC-23 during the production of
18 HCFC-22 were the primary contributors to aggregate HFC emissions. PFC emissions resulted as a by-product of
19 primary aluminum production and from semiconductor manufacturing, while electrical transmission and distribution
20 systems accounted for most SF6 emissions.
21
22 Figure ES-4: 2009 Greenhouse Gas Emissions by Gas (percents based on Tg CO2 Eq.)
23
24 Overall, from 1990 to 2009 total emissions of CO2 and CH4 increased by 408.0 Tg CO2 Eq. (8.0 percent) and 11.7
25 Tg CO2 Eq. (1.7 percent), respectively. Conversely, N2O emissions decreased by 15.7 Tg CO2 Eq. (5.0 percent).
26 During the same period, aggregate weighted emissions of HFCs, PFCs, and SF6 rose by 53.4 Tg CO2 Eq. (58.1
27 percent). From 1990 to 2009, HFCs increased by 88.1 Tg CO2 Eq. (238.6 percent), PFCs decreased by 15.1 Tg CO2
28 Eq. (73.0 percent), and SF6 decreased by 19.5 Tg CO2 Eq. (56.8 percent). Despite being emitted in smaller
29 quantities relative to the other principal greenhouse gases, emissions of HFCs, PFCs, and SF6 are significant because
30 many of these gases have extremely high global warming potentials and, in the cases of PFCs and SF6, long
31 atmospheric lifetimes. Conversely, U.S. greenhouse gas emissions were partly offset by carbon sequestration in
32 forests, trees in urban areas, agricultural soils, and landfilled yard trimmings and food scraps, which, in aggregate,
33 offset 15.3 percent of total emissions in 2009. The following sections describe each gas' contribution to total U.S.
34 greenhouse gas emissions in more detail.
35 Carbon Dioxide Emissions
36 The global carbon cycle is made up of large carbon flows and reservoirs. Billions of tons of carbon in the form of
37 CO2 are absorbed by oceans and living biomass (i.e., sinks) and are emitted to the atmosphere annually through
38 natural processes (i.e., sources). When in equilibrium, carbon fluxes among these various reservoirs are roughly
39 balanced. Since the Industrial Revolution (i.e., about 1750), global atmospheric concentrations of CO2 have risen
40 about 36 percent (IPCC 2007), principally due to the combustion of fossil fuels. Within the United States, fossil fuel
41 combustion accounted for 94.6 percent of CO2 emissions in 2009. Globally, approximately 30,398 Tg of CO2 were
42 added to the atmosphere through the combustion of fossil fuels in 2009, of which the United States accounted for
43 about 17 percent.12 Changes in land use and forestry practices can also emit CO2 (e.g., through conversion of forest
44 land to agricultural or urban use) or can act as a sink for CO2 (e.g., through net additions to forest biomass). In
45 addition to fossil-fuel combustion, several other sources emit significant quantities of CO2. These sources include,
12 Global CO2 emissions from fossil fuel combustion were taken from Energy Information Administration International Energy
Statistics 2010 < http://tonto.eia.doe.gov/cfapps/ipdbproject/IEDIndex3.cfm> EIA (2010a).
ES-6 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 but are not limited to non-energy use of fuels, iron and steel production and cement production (Figure ES-5).
2
3 Figure ES-5: 2009 Sources of CO2 Emissions
4
5 As the largest source of U.S. greenhouse gas emissions, CO2 from fossil fuel combustion has accounted for
6 approximately 78 percent of GWP-weighted emissions since 1990, growing slowly from 77 percent of total GWP-
7 weighted emissions in 1990 to 78 percent in 2009. Emissions of CO2 from fossil fuel combustion increased at an
8 average annual rate of 0.5 percent from 1990 to 2009. The fundamental factors influencing this trend include (1) a
9 generally growing domestic economy over the last 20 years, and (2) overall growth in emissions from electricity
10 generation and transportation activities. Between 1990 and 2009, CO2 emissions from fossil fuel combustion
11 increased from 4,741.2 Tg CO2 Eq. to 5,212.0 Tg CO2 Eq.—a 9.9 percent total increase over the twenty-year period.
12 From 2008 to 2009, these emissions decreased by 356.7 Tg CO2 Eq. (6.4 percent), the largest decrease in any year
13 over the twenty-year period.
14 Historically, changes in emissions from fossil fuel combustion have been the dominant factor affecting U.S.
15 emission trends. Changes in CO2 emissions from fossil fuel combustion are influenced by many long-term and
16 short-term factors, including population and economic growth, energy price fluctuations, technological changes, and
17 seasonal temperatures. In the short term, the overall consumption of fossil fuels in the United States fluctuates
18 primarily in response to changes in general economic conditions, energy prices, weather, and the availability of non-
19 fossil alternatives. For example, in a year with increased consumption of goods and services, low fuel prices, severe
20 summer and winter weather conditions, nuclear plant closures, and lower precipitation feeding hydroelectric dams,
21 there would likely be proportionally greater fossil fuel consumption than a year with poor economic performance,
22 high fuel prices, mild temperatures, and increased output from nuclear and hydroelectric plants. In the long term,
23 energy consumption patterns respond to changes that affect the scale of consumption (e.g., population, number of
24 cars, and size of houses), the efficiency with which energy is used in equipment (e.g., cars, power plants, steel mills,
25 and light bulbs) and consumer behavior (e.g., walking, bicycling, or telecommuting to work instead of driving).
26
27 Figure ES-6: 2009 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
28
29 Figure ES-7: 2009 End-Use Sector Emissions of CO2, CH4, and N2O from Fossil Fuel Combustion
30
31 The five major fuel consuming sectors contributing to CO2 emissions from fossil fuel combustion are electricity
32 generation, transportation, industrial, residential, and commercial. CO2 emissions are produced by the electricity
33 generation sector as they consume fossil fuel to provide electricity to one of the other four sectors, or "end-use"
34 sectors. For the discussion below, electricity generation emissions have been distributed to each end-use sector on
35 the basis of each sector's share of aggregate electricity consumption. This method of distributing emissions assumes
36 that each end-use sector consumes electricity that is generated from the national average mix of fuels according to
37 their carbon intensity. Emissions from electricity generation are also addressed separately after the end-use sectors
3 8 have been discussed.
39 Note that emissions from U.S. territories are calculated separately due to a lack of specific consumption data for the
40 individual end-use sectors.
41 Figure ES-6, Figure ES-7, and Table ES-3 summarize CO2 emissions from fossil fuel combustion by end-use sector.
42 Table ES-3: CO2 Emissions from Fossil Fuel Combustion by Fuel Consuming End-Use Sector (Tg CO2 Eq.)
End-Use Sector
Transportation
Combustion
Electricity
Industrial
Combustion
1990
1,489.0
1,485.9
3.0
1,536.0
849.3
2000
1,813.0
1,809.5
3.4
1,643.7
853.9
2005
1,901.3
1,896.6
4.7
1,562.4
825.5
2006
1,882.6
1,878.1
4.5
1,564.1
852.1
2007
1,899.0
1,894.0
5.0
1,575.9
845.9
2008
1,794.6
1,789.9
4.7
1,520.4
805.6
2009
1,723.3
1,718.9
4.4
1,341.7
738.4
Executive Summary ES-7
-------
Electricity
Residential
Combustion
Electricity
Commercial
Combustion
Electricity
U.S. Territories3
Total
Electricity Generation
686.7
931.4
338.3
593.0
757.0
219.0
538.0
27.9
4,741.2
1,820.8
789.8
1,133.1
370.7
762.4
972.1
230.8
741.3
35.9
5,597.7
2,296.9
737.0
1,214.7
357.9
856.7
1,027.2
223.5
803.7
50.0
5,755.6
2,402.1
712.0
1,152.4
321.5
830.8
1,007.6
208.6
799.0
50.3
5,657.0
2,346.4
730.0
1,198.5
342.4
856.1
1,041.1
219.4
821.7
46.1
5,760.6
2,412.8
714.8
1,182.2
348.2
834.0
1,031.6
224.2
807.4
39.8
5,568.7
2,360.9
603.3
1,124.8
340.2
784.6
980.5
218.8
761.7
41.7
5,212.0
2,154.0
1 Note: Totals may not sum due to independent rounding. Combustion-related emissions from electricity generation are allocated
2 based on aggregate national electricity consumption by each end-use sector.
3 a Fuel consumption by U.S. territories (i.e., American Samoa, Guam, Puerto Rico, U.S. Virgin Islands, Wake Island, and other
4 U.S. Pacific Islands) is included in this report.
5
6 Transportation End-Use Sector. Transportation activities (excluding international bunker fuels) accounted for 33
7 percent of CO2 emissions from fossil fuel combustion in 2009.13 Virtually all of the energy consumed in this end-
8 use sector came from petroleum products. Nearly 54 percent of the emissions resulted from gasoline consumption
9 for personal vehicle use. The remaining emissions came from other transportation activities, including the
10 combustion of diesel fuel in heavy-duty vehicles and jet fuel in aircraft. From 1990 to 2009, transportation
11 emissions rose by 16 percent due, in large part, to increased demand for travel and the stagnation of fuel efficiency
12 across the U.S. vehicle fleet. The number of vehicle miles traveled by light-duty motor vehicles (passenger cars and
13 light-duty trucks) increased 38 percent from 1990 to 2009, as a result of a confluence of factors including population
14 growth, economic growth, urban sprawl, and low fuel prices over much of this period.
15 Industrial End-Use Sector. Industrial CO2 emissions, resulting both directly from the combustion of fossil fuels and
16 indirectly from the generation of electricity that is consumed by industry, accounted for 26 percent of CO2 from
17 fossil fuel combustion in 2009. Approximately 55 percent of these emissions resulted from direct fossil fuel
18 combustion to produce steam and/or heat for industrial processes. The remaining emissions resulted from
19 consuming electricity for motors, electric furnaces, ovens, lighting, and other applications. In contrast to the other
20 end-use sectors, emissions from industry have steadily declined since 1990. This decline is due to structural changes
21 in the U.S. economy (i.e., shifts from a manufacturing-based to a service-based economy), fuel switching, and
22 efficiency improvements.
23 Residential and Commercial End-Use Sectors. The residential and commercial end-use sectors accounted for 22
24 and 19 percent, respectively, of CO2 emissions from fossil fuel combustion in 2009. Both sectors relied heavily on
25 electricity for meeting energy demands, with 70 and 78 percent, respectively, of their emissions attributable to
26 electricity consumption for lighting, heating, cooling, and operating appliances. The remaining emissions were due
27 to the consumption of natural gas and petroleum for heating and cooking. Emissions from these end-use sectors
28 have increased 25% since 1990, due to increasing electricity consumption for lighting, heating, air conditioning, and
29 operating appliances.
30 Electricity Generation. The United States relies on electricity to meet a significant portion of its energy demands.
31 Electricity generators consumed 36 percent of U. S. energy from fossil fuels and emitted 41 percent of the CO2 from
32 fossil fuel combustion in 2009. The type of fuel combusted by electricity generators has a significant effect on their
33 emissions. For example, some electricity is generated with low CO2 emitting energy technologies, particularly non-
34 fossil options such as nuclear, hydroelectric, or geothermal energy. However, electricity generators rely on coal for
35 over half of their total energy requirements and accounted for 95 percent of all coal consumed for energy in the
36 United States in 2009. Consequently, changes in electricity demand have a significant impact on coal consumption
37 and associated CO2 emissions.
38 Other significant CO2 trends included the following:
39 • CO2 emissions from non-energy use of fossil fuels have increased 5.8 Tg CO2 Eq. (5.0 percent) from 1990
13 If emissions from international bunker fuels are included, the transportation end-use sector accounted for 35 percent of U.S.
emissions from fossil fuel combustion in 2009.
ES-8 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 through 2009. Emissions from non-energy uses of fossil fuels were 122.1 Tg CO2 Eq. in 2009, which
2 constituted 2.2 percent of total national CO2 emissions, approximately the same proportion as in 1990.
3 • CO2 emissions from iron and steel production and metallurgical coke production decreased by 23.4 Tg CO2
4 Eq. (35.5 percent) from 2008 to 2009, continuing a trend of decreasing emissions from 1990 through 2009
5 of 57.2 percent (57.0 Tg CO2 Eq.). This decline is due to the restructuring of the industry, technological
6 improvements, and increased scrap utilization.
7 • In 2009, CO2 emissions from cement production decreased by 11.7 Tg CO2 Eq. (28.5 percent) from 2008.
8 After decreasing in 1991 by two percent from 1990 levels, cement production emissions grew every year
9 through 2006; emissions decreased in the last three years. Overall, from 1990 to 2009, emissions from
10 cement production decreased by 11.6 percent, a decrease of 3.9 Tg CO2 Eq.
11 • Net CO2 uptake from Land Use, Land-Use Change, and Forestry increased by 153.5 Tg CO2 Eq. (17.8
12 percent) from 1990 through 2009. This increase was primarily due to an increase in the rate of net carbon
13 accumulation in forest carbon stocks, particularly in aboveground and belowground tree biomass, and
14 harvested wood pools. Annual carbon accumulation in landfilled yard trimmings and food scraps slowed
15 over this period, while the rate of carbon accumulation in urban trees increased.
16 Methane Emissions
17 Methane (CH4) is more than 20 times as effective as CO2 at trapping heat in the atmosphere (IPCC 1996). Over the
18 last two hundred and fifty years, the concentration of CH4 in the atmosphere increased by 148 percent (IPCC 2007).
19 Anthropogenic sources of CH4 include natural gas and petroleum systems,,, agricultural activities, landfills, coal
20 mining, wastewater treatment, stationary and mobile combustion, and certain industrial processes (see Figure ES-8).
21
22 Figure ES-8: 2009 Sources of CH4 Emissions
23
24 Some significant trends in U.S. emissions of CH4 include the following:
25 • Natural gas systems were the largest anthropogenic source category of CH4 emissions in the United States
26 in 2009 with 221.2 Tg CO2 Eq. of CH4 emitted into the atmosphere. Those emissions have increased by
27 31.4 Tg CO2 Eq. (16.6 percent) since 1990. Methane emissions from this source increased 4 percent from
28 2008 to 2009 due to an increase in production and production wells.
29 • Enteric Fermentation is the second largest anthropogenic source of CH4 emissions in the United States. In
30 2009, enteric fermentation CH4 emissions were 139.8 Tg CO2 Eq. (20 percent of total CH4 emissions),
31 which represents an increase of 7.7 Tg CO2 Eq. (5.8 percent) since 1990.
32 • Landfills are the third largest anthropogenic source of CH4 emissions in the United States, accounting for
33 17 percent of total CH4 emissions (117.5 Tg CO2 Eq.) in 2009. From 1990 to 2009, CH4 emissions from
34 landfills decreased by 29.9 Tg CO2 Eq. (20 percent), with small increases occurring in some interim years.
35 This downward trend in overall emissions is the result of increases in the amount of landfill gas collected
36 and combusted,14 which has more than offset the additional CH4 emissions resulting from an increase in the
37 amount of municipal solid waste landfilled.
38 • In 2009, CH4 emissions from coal mining were 71.0 Tg CO2 Eq., a 3.9 Tg CO2 Eq. (5.8 percent) increase
39 over 2008 emission levels. The overall decline of 13.0 Tg CO2 Eq. (15.5 percent) from 1990 results from
40 the mining of less gassy coal from underground mines and the increased use of CH4 collected from
41 degasification systems.
42 • Methane emissions from manure management increased by 55.9 percent since 1990, from 31.7 Tg CO2 Eq.
43 in 1990 to 49.5 Tg CO2 Eq. in 2009. The majority of this increase was from swine and dairy cow manure,
14 The CO2 produced from combusted landfill CH4 at landfills is not counted in national inventories as it is considered part of the
natural C cycle of decomposition.
Executive Summary ES-9
-------
1 since the general trend in manure management is one of increasing use of liquid systems, which tends to
2 produce greater CH4 emissions. The increase in liquid systems is the combined result of a shift to larger
3 facilities, and to facilities in the West and Southwest, all of which tend to use liquid systems. Also, new
4 regulations limiting the application of manure nutrients have shifted manure management practices at
5 smaller dairies from daily spread to manure managed and stored on site.
6 Nitrous Oxide Emissions
7 N2O is produced by biological processes that occur in soil and water and by a variety of anthropogenic activities in
8 the agricultural, energy-related, industrial, and waste management fields. While total N2O emissions are much
9 lower than CO2 emissions, N2O is approximately 300 times more powerful than CO2 at trapping heat in the
10 atmosphere (IPCC 1996). Since 1750, the global atmospheric concentration of N2O has risen by approximately 18
11 percent (IPCC 2007). The main anthropogenic activities producing N2O in the United States are agricultural soil
12 management, fuel combustion in motor vehicles, manure management, nitric acid production and stationary fuel
13 combustion, (see Figure ES-9).
14
15 Figure ES-9: 2009 Sources of N2O Emissions
16
17 Some significant trends in U.S. emissions of N2O include the following:
18 • Agricultural soils accounted for approximately 68.3 percent of N2O emissions in the United States in 2009.
19 Estimated emissions from this source in 2009 were 204.6 Tg CO2 Eq. Annual N2O emissions from
20 agricultural soils fluctuated between 1990 and 2009, although overall emissions were 3.4 percent higher in
21 2009 than in 1990. N2O emissions from this source have not shown any significant long-term trend, as
22 they are highly sensitive to the amount of N applied to soils (which has not changed significantly over the
23 time-period), and to weather patterns and crop type.
24 • In 2009, N2O emissions from mobile combustion were 27.8 Tg CO2 Eq. (approximately 9.3 percent of U.S.
25 N2O emissions). From 1990 to 2009, N2O emissions from mobile combustion decreased by 36.8 percent.
26 However, from 1990 to 1998 emissions increased by 25.6 percent, due to control technologies that reduced
27 NOX emissions while increasing N2O emissions. Since 1998, newer control technologies have led to an
28 overall decline in N2O from this source.
29 • N2O emissions from adipic acid production were 1.9 Tg CO2 Eq. in 2009, and have decreased significantly
30 since 1996 from the widespread installation of pollution control measures. Emissions from adipic acid
31 production have decreased by 87.7 percent since 1990, and emissions from adipic acid production have
32 remained consistently lower than pre-1996 levels since 1998.
33 HFC, RFC, and SF6 Emissions
34 HFCs and PFCs are families of synthetic chemicals that are used as alternatives to ODS, which are being phased out
35 under the Montreal Protocol and Clean Air Act Amendments of 1990. HFCs and PFCs do not deplete the
36 stratospheric ozone layer, and are therefore acceptable alternatives under the Montreal Protocol.
37 These compounds, however, along with SF6, are potent greenhouse gases. In addition to having high global
38 warming potentials, SF6 and PFCs have extremely long atmospheric lifetimes, resulting in their essentially
39 irreversible accumulation in the atmosphere once emitted. Sulfur hexafluoride is the most potent greenhouse gas the
40 IPCC has evaluated (IPCC 1996).
41 Other emissive sources of these gases include electrical transmission and distribution systems, HCFC-22 production,
42 semiconductor manufacturing, aluminum production, and magnesium production and processing (see Figure ES-10).
43
44 Figure ES-10: 2009 Sources of HFCs, PFCs, and SF6 Emissions
45
ES-10 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Some significant trends in U.S. HFC, PFC, and SF6 emissions include the following:
2 • Emissions resulting from the substitution of ODS (e.g., CFCs) have been consistently increasing, from
3 small amounts in 1990 to 119.3 Tg CO2 Eq. in 2009. Emissions from ODS substitutes are both the largest
4 and the fastest growing source of HFC, PFC, and SF6 emissions. These emissions have been increasing as
5 phase-outs required under the Montreal Protocol come into effect, especially after 1994, when full market
6 penetration was made for the first generation of new technologies featuring ODS substitutes.
7 • HFC emissions from the production of HCFC-22 decreased by 85.2 percent (31.0 Tg CO2 Eq.) from 1990
8 through 2009, due to a steady decline in the emission rate of HFC-23 (i.e., the amount of HFC-23 emitted
9 per kilogram of HCFC-22 manufactured) and the use of thermal oxidation at some plants to reduce HFC-23
10 emissions.
11 • SF6 emissions from electric power transmission and distribution systems decreased by 54.8 percent (15.6
12 Tg CO2 Eq.) from 1990 to 2009, primarily because of higher purchase prices for SF6 and efforts by industry
13 to reduce emissions.
14 • PFC emissions from aluminum production decreased by 91.5 percent (17.0 Tg CO2 Eq.) from 1990 to
15 2009, due to both industry emission reduction efforts and lower domestic aluminum production.
16 Overview of Sector Emissions and Trends
17 In accordance with the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories
18 (IPCC/UNEP/OECD/IEA 1997), and the 2003 UNFCCC Guidelines on Reporting and Review (UNFCCC 2003),
19 Figure ES-11 and Table ES-4 aggregate emissions and sinks by these chapters. Emissions of all gases can be
20 summed from each source category from IPCC guidance. Over the twenty-year period of 1990 to 2009, total
21 emissions in the Energy and Agriculture sectors grew by 468.7 Tg CO2 Eq. (9 percent), and 35.7 Tg CO2 Eq. (9
22 percent), respectively. Emissions decreased in the Industrial Processes, Waste, and Solvent and Other Product Use
23 sectors by 32.3 Tg CO2 Eq. (10 percent), 24.7 Tg CO2 Eq. (14 percent) and less than 0.1 Tg CO2 Eq. (0.4 percent),
24 respectively. Over the same period, estimates of net C sequestration in the Land Use, Land-Use Change, and
25 Forestry sector (magnitude of emissions plus CO2 flux from all LULUCF source categories) increased by 143.5 Tg
26 CO2Eq. (17 percent).
27
28 Figure ES-11: U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector
29
30 Table ES-4: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg CO2 Eq.)
Chapter/IPCC Sector 1990 2000 2005 2006 2007 2008 2009
Energy
Industrial Processes
Solvent and Other Product Use
Agriculture
Land Use, Land-Use Change, and
Forestry (Emissions)
Waste
Total Emissions
5,288.2
315.8
4.4
383.6
15.0
175.2
6,182.2
6,168.4
349.6
4.9
410.6
36.3
143.9
7,113.9
6,283.1
334.8
4.4
418.8
28.6
144.9
7,214.5
6,210.9
340.2
4.4
418.8
49.8
144.4
7,168.4
6,291.5
351.6
4.4
425.8
47.5
144.1
7,264.8
6,117.1
332.0
4.4
426.3
33.2
149.0
7,061.9
5,757.0
283.5
4.4
419.3
25.0
150.5
6,639.7
Net CO2 Flux from Land Use, Land-
Use Change, and Forestry (Sinks)* (861.5) (576.6) (1,056.5) (1,064.3) (1,060.9) (1,040.5) (1,015.1)
Net Emissions (Sources and Sinks) 5,320.7 6,537.3 6,158.1 6,104.1 6,203.9 6,021.5 5,624.6
31 * The net CO2 flux total includes both emissions and sequestration, and constitutes a sink in the United States. Sinks are only
32 included in net emissions total.
33 Note: Totals may not sum due to independent rounding. Parentheses indicate negative values or sequestration.
34
35 Energy
36 The Energy chapter contains emissions of all greenhouse gases resulting from stationary and mobile energy
Executive Summary ES-11
-------
1 activities including fuel combustion and fugitive fuel emissions. Energy-related activities, primarily fossil fuel
2 combustion, accounted for the vast majority of U.S. CO2 emissions for the period of 1990 through 2009. In 2009,
3 approximately 83 percent of the energy consumed in the United States (on a Btu basis) was produced through the
4 combustion of fossil fuels. The remaining 17 percent came from other energy sources such as hydropower, biomass,
5 nuclear, wind, and solar energy (see Figure ES-12). Energy-related activities are also responsible for CH4 and N2O
6 emissions (49 percent and 14 percent of total U.S. emissions of each gas, respectively). Overall, emission sources in
7 the Energy chapter account for a combined 87 percent of total U.S. greenhouse gas emissions in 2009.
8 Figure ES-12: 2009 U.S. Energy Consumption by Energy Source
9 Industrial Processes
10 The Industrial Processes chapter contains by-product or fugitive emissions of greenhouse gases from industrial
11 processes not directly related to energy activities such as fossil fuel combustion. For example, industrial processes
12 can chemically transform raw materials, which often release waste gases such as CO2, CH4, and N2O. These
13 processes include iron and steel production and metallurgical coke production, cement production, ammonia
14 production and urea consumption, lime production, limestone and dolomite use (e.g., flux stone, flue gas
15 desulfurization, and glass manufacturing), soda ash production and consumption, titanium dioxide production,
16 phosphoric acid production, ferroalloy production, CO2 consumption, silicon carbide production and consumption,
17 aluminum production, petrochemical production, nitric acid production, adipic acid production, lead production, and
18 zinc production. Additionally, emissions from industrial processes release HFCs, PFCs, and SF6. Overall, emission
19 sources in the Industrial Process chapter account for 4 percent of U.S. greenhouse gas emissions in 2009.
20 Solvent and Other Product Use
21 The Solvent and Other Product Use chapter contains greenhouse gas emissions that are produced as a by-product of
22 various solvent and other product uses. In the United States, emissions from N2O from product uses, the only source
23 of greenhouse gas emissions from this sector, accounted for about 0.1 percent of total U.S. anthropogenic
24 greenhouse gas emissions on a carbon equivalent basis in 2009.
25 Agriculture
26 The Agricultural chapter contains anthropogenic emissions from agricultural activities (except fuel combustion,
27 which is addressed in the Energy chapter, and agricultural CO2 fluxes, which are addressed in the Land Use, Land-
28 Use Change, and Forestry Chapter). Agricultural activities contribute directly to emissions of greenhouse gases
29 through a variety of processes, including the following source categories: enteric fermentation in domestic livestock,
30 livestock manure management, rice cultivation, agricultural soil management, and field burning of agricultural
31 residues. CH4 and N2O were the primary greenhouse gases emitted by agricultural activities. CH4 emissions from
32 enteric fermentation and manure management represented 20 percent and 7 percent of total CH4 emissions from
33 anthropogenic activities, respectively, in 2009. Agricultural soil management activities such as fertilizer application
34 and other cropping practices were the largest source of U.S. N2O emissions in 2009, accounting for 68 percent. In
35 2009, emission sources accounted for in the Agricultural chapters were responsible for 6.3 percent of total U.S.
36 greenhouse gas emissions.
37 Land Use, Land-Use Change, and Forestry
38 The Land Use, Land-Use Change, and Forestry chapter contains emissions of CH4 and N2O, and emissions and
39 removals of CO2 from forest management, other land-use activities, and land-use change. Forest management
40 practices, tree planting in urban areas, the management of agricultural soils, and the landfilling of yard trimmings
41 and food scraps resulted in a net uptake (sequestration) of C in the United States. Forests (including vegetation,
42 soils, and harvested wood) accounted for 85 percent of total 2009 net CO2 flux, urban trees accounted for 9 percent,
43 mineral and organic soil carbon stock changes accounted for 4 percent, and landfilled yard trimmings and food
44 scraps accounted for 1 percent of the total net flux in 2009. The net forest sequestration is a result of net forest
45 growth and increasing forest area, as well as a net accumulation of carbon stocks in harvested wood pools. The net
46 sequestration in urban forests is a result of net tree growth in these areas. In agricultural soils, mineral and organic
47 soils sequester approximately 5.5 times as much C as is emitted from these soils through liming and urea
48 fertilization. The mineral soil C sequestration is largely due to the conversion of cropland to permanent pastures and
ES-12 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 hay production, a reduction in summer fallow areas in semi-arid areas, an increase in the adoption of conservation
2 tillage practices, and an increase in the amounts of organic fertilizers (i.e., manure and sewage sludge) applied to
3 agriculture lands. The landfilled yard trimmings and food scraps net sequestration is due to the long-term
4 accumulation of yard trimming carbon and food scraps in landfills.
5 Land use, land-use change, and forestry activities in 2009 resulted in a net C sequestration of 1,015.1 Tg CO2 Eq.
6 (Table ES- 5). This represents an offset of 18 percent of total U.S. CO2 emissions, or 15 percent of total greenhouse
7 gas emissions in 2009. Between 1990 and 2009, total land use, land-use change, and forestry net C flux resulted in a
8 17.8 percent increase in CO2 sequestration, primarily due to an increase in the rate of net C accumulation in forest C
9 stocks, particularly in aboveground and belowground tree biomass, and harvested wood pools. Annual C
10 accumulation in landfilled yard trimmings and food scraps slowed over this period, while the rate of annual C
11 accumulation increased in urban trees.
12 Table ES- 5: Net CO2 Flux from Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.)
Sink Category 1990 2000 2005 2006 2007 2008 2009
24
25
Forest Land Remaining Forest Land1
Cropland Remaining Cropland
Land Converted to Cropland
Grassland Remaining Grassland
Land Converted to Grassland
Settlements Remaining Settlements2
Other (Landfilled Yard Trimmings and
Food Scraps)
(681.1)
(29.4)
2.2
(52.2)
(19.8)
(57.1)
(24.2)
(378.3)
(30.2)
2.4
(52.6)
(27.2)
(77.5)
(13.2)
(911.5)
(18.3)
5.9
(8.9)
(24.4)
(87.8)
(11.5)
(917.5)
(19.1)
5.9
(8.8)
(24.2)
(89.8)
(11.0)
(911.9)
(19.7)
5.9
(8.6)
(24.0)
(91.9)
(10.9)
(891.0)
(18.1)
5.9
(8.5)
(23.8)
(93.9)
(11.2)
(863.1)
(17.4)
5.9
(8.3)
(23.6)
(95.9)
(12.6)
Total (861.5) (576.6) (1,056.5) (1,064.3) (1,060.9) (1,040.5) (1,015.1)
13 Note: Totals may not sum due to independent rounding. Parentheses indicate net sequestration.
14 Emissions from Land Use, Land-Use Change, and Forestry are shown in Table ES-6. The application of crushed
15 limestone and dolomite to managed land (i.e., liming of agricultural soils) and urea fertilization resulted in CO2
16 emissions of 7.8 Tg CO2 Eq. in 2009, an increase of 11 percent relative to 1990. The application of synthetic
17 fertilizers to forest and settlement soils in 2009 resulted in direct N2O emissions of 1.9 Tg CO2 Eq. Direct N2O
18 emissions from fertilizer application to forest soils have increased by 455 percent since 1990, but still account for a
19 relatively small portion of overall emissions. Additionally, direct N2O emissions from fertilizer application to
20 settlement soils increased by 55 percent since 1990. Forest fires resulted in CH4 emissions of 7.8 Tg CO2 Eq., and
21 in N2O emissions of 6.4 Tg CO2 Eq. in 2009. CO2 and N2O emissions from peatlands totaled 1.1 Tg CO2 Eq. and
22 less than 0.01 Tg CO2 Eq. in 2009, respectively.
23 Table ES-6: Emissions from Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.)
Source Category
C02
Cropland Remaining Cropland: Liming of
Agricultural Soils
Cropland Remaining Cropland: Urea
Fertilization
Wetlands Remaining Wetlands: Peatlands
Remaining Peatlands
CH4
Forest Land Remaining Forest Land: Forest Fires
N2O
Forest Land Remaining Forest Land: Forest Fires
Forest Land Remaining Forest Land: Forest Soils
Settlements Remaining Settlements: Settlement
Soils
Wetlands Remaining Wetlands: Peatlands
Remaining Peatlands
Total
+ Less than 0.05 Tg CO2 Eq.
Note: Totals may not sum due to independent rounding.
1990
8.1
4.7
2.4
1.0
3.2
3.2
3.7
2.6
0.1
1.0
+
15.0
2000
8.8
4.3
3.2
1.2
14.3
14.3
13.2
11.7
0.4
1.1
+
36.3
2005
8.9
4.3
3.5
1.1
9.8
9.8
9.8
8.0
0.4
1.5
+
28.6
2006
8.8
4.2
3.7
0.9
21.6
21.6
19.5
17.6
0.4
1.5
+
49.8
2007
9.2
4.5
3.7
1.0
20.0
20.0
18.3
16.3
0.4
1.6
+
47.5
2008
9.6
5.0
3.6
1.0
11.9
11.9
11.6
9.8
0.4
1.5
+
33.2
2009
8.9
4.2
3.6
1.1
7.8
7.8
8.3
6.4
0.4
1.5
+
25.0
Executive Summary ES-13
-------
i Waste
2 The Waste chapter contains emissions from waste management activities (except incineration of waste, which is
3 addressed in the Energy chapter). Landfills were the largest source of anthropogenic greenhouse gas emissions in
4 the Waste chapter, accounting for just over 78 percent of this chapter's emissions, and 17 percent of total U.S. CH4
5 emissions.15 Additionally, wastewater treatment accounts for 20 percent of Waste emissions, 4 percent of U. S. CH4
6 emissions, and 2 percent of U.S. N2O emissions. Emissions of CH4 and N2O from composting are also accounted
7 for in this chapter; generating emissions of 1.7 Tg CO2 Eq. and 1.8 Tg CO2 Eq., respectively. Overall, emission
8 sources accounted for in the Waste chapter generated 2.3 percent of total U.S. greenhouse gas emissions in 2009.
9 Other Information
10 Emissions by Economic Sector
11 Throughout the Inventory of U.S. Greenhouse Gas Emissions and Sinks report, emission estimates are grouped into
12 six sectors (i.e., chapters) defined by the IPCC: Energy; Industrial Processes; Solvent Use; Agriculture; Land Use,
13 Land-Use Change, and Forestry; and Waste. While it is important to use this characterization for consistency with
14 UNFCCC reporting guidelines, it is also useful to allocate emissions into more commonly used sectoral categories.
15 This section reports emissions by the following economic sectors: Residential, Commercial, Industry,
16 Transportation, Electricity Generation, Agriculture, and U.S. Territories.
17 Table ES-7 summarizes emissions from each of these sectors, and Figure ES-13 shows the trend in emissions by
18 sector from 1990 to 2009.
19
20 Figure ES-13: Emissions Allocated to Economic Sectors
21
22 Table ES-7: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO2 Eq.)
Implied Sectors
Electric Power Industry
Transportation
Industry
Agriculture
Commercial
Residential
U.S. Territories
Total Emissions
1
1
1
6
1990
,868.9
,545.2
,564.9
429.0
395.5
345.1
33.7
,182.2
2
1
1
7
2000
,337.6
,932.3
,545.2
485.1
381.4
386.2
46.0
,113.9
2
2
1
7
2005
,444.6
,017.4
,442.9
493.2
387.2
371.0
58.2
,214.5
2
1
1
7
2006
,388.2
,994.4
,498.8
516.7
375.2
335.8
59.3
,168.4
2007
2,454.0
2,003.7
1,484.5
520.7
389.6
358.8
53.5
7,264.8
2008
2,400.7
1,890.7
1,448.0
503.9
403.5
366.8
48.4
7,061.9
2009
2,193.0
1,815.8
1,330.6
490.0
404.3
360.5
45.5
6,639.7
Land Use, Land-Use Change, and
Forestry (Sinks) (861.5) (576.6) (1,056.5)(1,064.3)(1,060.9)(1,040.5)(1,015.1)
Net Emissions (Sources and Sinks) 5,320.7 6,537.3 6,158.1 6,104.1 6,203.9 6,021.5 5,624.6
23 Note: Totals may not sum due to independent rounding. Emissions include CO2, CH4, N2O, HFCs, PFCs, and SF6.
24 See Table 2-12 for more detailed data.
25
26 Using this categorization, emissions from electricity generation accounted for the largest portion (33 percent) of
27 U.S. greenhouse gas emissions in 2009. Transportation activities, in aggregate, accounted for the second largest
28 portion (27 percent), while emissions from industry accounted for the third largest portion (20 percent) of U.S.
29 greenhouse gas emissions in 2009. In contrast to electricity generation and transportation, emissions from industry
30 have in general declined over the past decade. The long-term decline in these emissions has been due to structural
31 changes in the U.S. economy (i.e., shifts from a manufacturing-based to a service-based economy), fuel switching,
32 and energy efficiency improvements. The remaining 20 percent of U.S. greenhouse gas emissions were contributed
33 by, in order of importance, the agriculture, commercial, and residential sectors, plus emissions from U.S. territories.
15 Landfills also store carbon, due to incomplete degradation of organic materials such as wood products and yard trimmings, as
described in the Land-Use, Land-Use Change, and Forestry chapter of the Inventory report.
ES-14 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Activities related to agriculture accounted for 7 percent of U.S. emissions; unlike other economic sectors,
2 agricultural sector emissions were dominated by N2O emissions from agricultural soil management and CH4
3 emissions from enteric fermentation. The commercial sector accounted for 6 percent of emissions while the
4 residential sector accounted for 5 percent of emissions and U.S. territories accounted for 1 percent of emissions;
5 emissions from these sectors primarily consisted of CO2 emissions from fossil fuel combustion.
6 CO2 was also emitted and sequestered by a variety of activities related to forest management practices, tree planting
7 in urban areas, the management of agricultural soils, and landfilling of yard trimmings.
8 Electricity is ultimately consumed in the economic sectors described above. Table ES-8 presents greenhouse gas
9 emissions from economic sectors with emissions related to electricity generation distributed into end-use categories
10 (i.e., emissions from electricity generation are allocated to the economic sectors in which the electricity is
11 consumed). To distribute electricity emissions among end-use sectors, emissions from the source categories
12 assigned to electricity generation were allocated to the residential, commercial, industry, transportation, and
13 agriculture economic sectors according to retail sales of electricity.16 These source categories include CO2 from
14 fossil fuel combustion and the use of limestone and dolomite for flue gas desulfurization, CO2 and N2O from
15 incineration of waste, CH4 and N2O from stationary sources, and SF6 from electrical transmission and distribution
16 systems.
17 When emissions from electricity are distributed among these sectors, Industrial activities account for the largest
18 share of U.S. greenhouse gas emissions (29 percent) in 2009. Transportation is the second largest contributor to
19 total U.S. emissions (27 percent). The commercial and residential sectors contributed the next largest shares of total
20 U.S. greenhouse gas emissions in 2009. Emissions from these sectors increase substantially when emissions from
21 electricity are included, due to their relatively large share of electricity consumption (e.g., lighting, appliances, etc.).
22 In all sectors except agriculture, CO2 accounts for more than 80 percent of greenhouse gas emissions, primarily from
23 the combustion of fossil fuels. Figure ES-14 shows the trend in these emissions by sector from 1990 to 2009.
24 Table ES-8: U.S Greenhouse Gas Emissions by Economic Sector with Electricity-Related Emissions Distributed
25 (TgC02Eq.)
Implied Sectors
Industry
Transportation
Commercial
Residential
Agriculture
U.S. Territories
Total Emissions
Land Use, Land-Use Change,
and Forestry (Sinks)
Net Emissions (Sources and
Sinks)
1990
2,238.7
1,548.3
947.7
953.8
460.0
33.7
6,182.2
(861.5)
5,320.7
2000
2,315.6
1,935.8
1,135.8
1,162.2
518.4
46.0
7,113.9
(576.6)
6,537.3
2005
2,163.5
2,022.2
1,205.1
1,242.8
522.7
58.2
7,214.5
(1,056.5)
6,158.1
2006
2,196.1
1,999.0
1,188.5
1,181.4
544.1
59.3
7,168.4
(1,064.3)
6,104.1
2007
2,194.4
2,008.9
1,225.3
1,229.5
553.2
53.5
7,264.8
(1,060.9)
6,203.9
2008
2,147.6
1,895.4
1,224.5
1,214.8
531.1
48.4
7,061.9
(1,040.5)
6,021.5
2009
1,918.9
1,820.3
1,179.7
1,159.3
516.0
45.5
6,639.7
(1,015.1)
5,624.6
See Table 2-14 for more detailed data.
26
27
28
29 Figure ES-14: Emissions with Electricity Distributed to Economic Sectors
30
31
32 [BEGIN BOX]
33
34 Box ES-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data
16 Emissions were not distributed to U.S. territories, since the electricity generation sector only includes emissions related to the
generation of electricity in the 50 states and the District of Columbia.
Executive Summary ES-15
-------
1 Total emissions can be compared to other economic and social indices to highlight changes over time. These
2 comparisons include: (1) emissions per unit of aggregate energy consumption, because energy-related activities are
3 the largest sources of emissions; (2) emissions per unit of fossil fuel consumption, because almost all energy-related
4 emissions involve the combustion of fossil fuels; (3) emissions per unit of electricity consumption, because the
5 electric power industry—utilities and nonutilities combined—was the largest source of U.S. greenhouse gas
6 emissions in 2009; (4) emissions per unit of total gross domestic product as a measure of national economic activity;
7 and (5) emissions per capita.
8 Table ES-9 provides data on various statistics related to U.S. greenhouse gas emissions normalized to 1990 as a
9 baseline year. Greenhouse gas emissions in the United States have grown at an average annual rate of 0.4 percent
10 since 1990. This rate is slightly slower than that for total energy and for fossil fuel consumption, and much slower
11 than that for electricity consumption, overall gross domestic product and national population (see Figure ES-15).
12 Table ES-9: Recent Trends in Various U.S. Data (Index 1990 = 100)
Variable
GDPb
Electricity Consumption0
Fossil Fuel Consumption0
Energy Consumption0
Population"1
Greenhouse Gas Emissions6
1990
100
100
100
100
100
100
2000
140
127
117
116
113
115
2005
157
134
119
118
118
117
2006
162
135
117
118
120
116
2007
165
138
119
120
121
118
2008
165
138
116
118
122
114
Growth
2009 Rate3
160
132
108
112
123
107
2.5%
1.5%
0.5%
0.6%
1.1%
0.4%
13 a Average annual growth rate
14 b Gross Domestic Product in chained 2005 dollars (BEA 2010)
15 ° Energy content-weighted values (EIA 201 Ob)
16 d U.S. Census Bureau (2010)
17 e GWP-weighted values
18
19 Figure ES-15: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product
20 Source: BEA (2010), U.S. Census Bureau (2010), and emission estimates in this report.
21
22 [END BOX]
23
24 Indirect Greenhouse Gases (CO, NOX, NMVOCs, and S02) - TO BE UPDATED
25 The reporting requirements of the UNFCCC request that information be provided on indirect greenhouse gases,
26 which include CO, NOX, NMVOCs, and SO2. These gases do not have a direct global warming effect, but indirectly
27 affect terrestrial radiation absorption by influencing the formation and destruction of tropospheric and stratospheric
28 ozone, or, in the case of SO2, by affecting the absorptive characteristics of the atmosphere. Additionally, some of
29 these gases may react with other chemical compounds in the atmosphere to form compounds that are greenhouse
30 gases.
31 Since 1970, the United States has published estimates of annual emissions of CO, NOX, NMVOCs, and SO2 (EPA
32 2008),18 which are regulated under the Clean Air Act. Table ES-10 shows that fuel combustion accounts for the
33 majority of emissions of these indirect greenhouse gases. Industrial processes—such as the manufacture of
34 chemical and allied products, metals processing, and industrial uses of solvents—are also significant sources of CO,
35 NOX, and NMVOCs.
36 Table ES-10: Emissions of NOX, CO, NMVOCs, and SO2 (Gg)
17 See .
18 NOX and CO emission estimates from field burning of agricultural residues were estimated separately, and therefore not taken
from EPA (2008).
ES-16 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1
2
o
3
4
6
7
8
9
10
11
12
13
Gas/Activity
NOX
Mobile Fossil Fuel Combustion
Stationary Fossil Fuel Combustion
Industrial Processes
Oil and Gas Activities
Incineration of Waste
Agricultural Burning
Solvent Use
Waste
CO
Mobile Fossil Fuel Combustion
Stationary Fossil Fuel Combustion
Industrial Processes
Incineration of Waste
Agricultural Burning
Oil and Gas Activities
Waste
Solvent Use
NMVOCs
Mobile Fossil Fuel Combustion
Solvent Use
Industrial Processes
Stationary Fossil Fuel Combustion
Oil and Gas Activities
Incineration of Waste
Waste
Agricultural Burning
SO2
Stationary Fossil Fuel Combustion
Industrial Processes
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Incineration of Waste
Waste
Solvent Use
Agricultural Burning
1990
21,728
10,862
10,023
591
139
82
30
1
0
130,536
119,360
5,000
4,125
978
766
302
1
5
20,930
10,932
5,216
2,422
912
554
222
673
NA
20,935
18,407
1,307
793
390
38
0
0
NA
2000
19,145
10,199
8,053
626
111
114
37
o
J
2
92,872
83,559
4,340
2,216
1,670
888
146
8
45
15,227
7,229
4,384
1,773
1,077
388
257
119
NA
14,830
12,849
1,031
632
287
29
1
1
NA
2005
15,933
9,012
5,858
569
321
129
40
o
J
2
71,555
62,692
4,649
1,555
1,403
930
318
7
2
13,761
6,330
3,851
1,997
716
510
241
114
NA
13,466
11,541
831
889
181
24
1
0
NA
2006
15,071
8,488
5,545
553
319
121
40
4
2
67,909
58,972
4,695
1,597
1,412
905
319
7
2
13,594
6,037
3,846
1,933
918
510
238
113
NA
12,388
10,612
818
750
182
24
1
0
NA
2007
14,410
7,965
5,432
537
318
114
38
4
2
64,348
55,253
4,744
1,640
1,421
960
320
7
2
13,423
5,742
3,839
1,869
1,120
509
234
111
NA
11,799
10,172
807
611
184
24
1
0
NA
2008 2009
13,578
7,441
5,148
520
318
106
40
4
2
60,739
51,533
4,792
1,682
1,430
970
322
7
2
13,254
5,447
3,834
1,804
1,321
509
230
109
NA
10,368
8,891
795
472
187
23
1
0
NA
Source: (EPA 2009, disaggregated based on EPA 2003) except for estimates from field burning of agricultural residues.
NA (Not Available)
Note: Totals may not sum due to independent rounding.
Key Categories
The 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006) defines a key category as a
"[source or sink category] that is prioritized within the national inventory system because its estimate has a
significant influence on a country's total inventory of direct greenhouse gases in terms of the absolute level of
emissions, the trend in emissions, or both."19 By definition, key categories are sources or sinks that have the
greatest contribution to the absolute overall level of national emissions in any of the years covered by the time
series. In addition, when an entire time series of emission estimates is prepared, a thorough investigation of key
categories must also account for the influence of trends of individual source and sink categories. Finally, a
qualitative evaluation of key categories should be performed, in order to capture any key categories that were not
19 See Chapter 7 "Methodological Choice and Recalculation" in IPCC (2000).
Executive Summary ES-17
-------
1 identified in either of the quantitative analyses.
2 Figure ES-16 presents 2009 emission estimates for the key categories as defined by a level analysis (i.e., the
3 contribution of each source or sink category to the total inventory level). The UNFCCC reporting guidelines request
4 that key category analyses be reported at an appropriate level of disaggregation, which may lead to source and sink
5 category names which differ from those used elsewhere in the inventory report. For more information regarding key
6 categories, see section 1.5 and Annex 1 of the inventory report.
7 Figure ES-16: 2009 Key Categories
8 Quality Assurance and Quality Control (QA/QC)
9 The United States seeks to continually improve the quality, transparency, and credibility of the Inventory of U.S.
10 Greenhouse Gas Emissions and Sinks. To assist in these efforts, the United States implemented a systematic
11 approach to QA/QC. While QA/QC has always been an integral part of the U.S. national system for inventory
12 development, the procedures followed for the current inventory have been formalized in accordance with the
13 QA/QC plan and the UNFCCC reporting guidelines.
14 Uncertainty Analysis of Emission Estimates
15 While the current U.S. emissions inventory provides a solid foundation for the development of a more detailed and
16 comprehensive national inventory, there are uncertainties associated with the emission estimates. Some of the
17 current estimates, such as those for CO2 emissions from energy-related activities and cement processing, are
18 considered to have low uncertainties. For some other categories of emissions, however, a lack of data or an
19 incomplete understanding of how emissions are generated increases the uncertainty associated with the estimates
20 presented. Acquiring a better understanding of the uncertainty associated with inventory estimates is an important
21 step in helping to prioritize future work and improve the overall quality of the Inventory. Recognizing the benefit of
22 conducting an uncertainty analysis, the UNFCCC reporting guidelines follow the recommendations of the IPCC
23 Good Practice Guidance (IPCC 2000) and require that countries provide single estimates of uncertainty for source
24 and sink categories.
25 Currently, a qualitative discussion of uncertainty is presented for all source and sink categories. Within the
26 discussion of each emission source, specific factors affecting the uncertainty surrounding the estimates are
27 discussed. Most sources also contain a quantitative uncertainty assessment, in accordance with UNFCCC reporting
28 guidelines.
29
30 [BEGIN BOX]
31 Box ES-3: Recalculations of Inventory Estimates
32 Each year, emission and sink estimates are recalculated and revised for all years in the Inventory of U.S. Greenhouse
33 Gas Emissions and Sinks, as attempts are made to improve both the analyses themselves, through the use of better
34 methods or data, and the overall usefulness of the report. In this effort, the United States follows the IPCC Good
35 Practice Guidance (IPCC 2000), which states, regarding recalculations of the time series, "It is good practice to
36 recalculate historic emissions when methods are changed or refined, when new source categories are included in the
37 national inventory, or when errors in the estimates are identified and corrected." In general, recalculations are made
38 to the U.S. greenhouse gas emission estimates either to incorporate new methodologies or, most commonly, to
39 update recent historical data.
40 In each Inventory report, the results of all methodology changes and historical data updates are presented in the
41 "Recalculations and Improvements" chapter; detailed descriptions of each recalculation are contained within each
42 source's description contained in the report, if applicable. In general, when methodological changes have been
43 implemented, the entire time series (in the case of the most recent inventory report, 1990 through 2009) has been
44 recalculated to reflect the change, per IPCC Good Practice Guidance (IPCC 2000). Changes in historical data are
45 generally the result of changes in statistical data supplied by other agencies. References for the data are provided for
46 additional information.
47 [END BOX]
ES-18 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
8,000 -|
7,000 -
6,000 -
m 5,000 -
O
CT 4,000 -
3,000 -
2,000 -
1,000 -
0 -
I MFCs, PFCs, &SF6
Nitrous Oxide
Methane
i Carbon Dioxide
6,768
6,852
6,918 ^ 7000 7039 22£ ^ — ^168^5
6,182 6,142 6,245
6,640
x
0*0*0*0000000000
0*0*0*0000000000
Figure ES-1: U.S. Greenhouse Gas Emissions by Gas
4% -i
2% -
3.3%
2.8%
1.6% 1.3%
0.6% 0.4% • 0.5%
-6.0%
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
Figure ES-2: Annual Percent Change in U.S. Greenhouse Gas Emissions
1,083
880
8888888888
Figure ES-3: Cumulative Change in Annual U.S. Greenhouse Gas Emissions Relative to 1990
-------
4.5%
MFCs, PFCs,
&SF6
2.2%
<0.5
<0.5
C02 as a Portion
of all Emissions
Figure ES-4: 2009 Greenhouse Gas Emissions by Gas (percents based on Tg CO2 Eq.)
Fossil Fuel Combustion H ^E ^H
Non-Energy Use of Fuels
Iron and Steel Prod. & Metallurgical Coke Prod.
Natural Gas Systems
Cement Production
Incineration of Waste
Ammonia Production and Urea Consumption
Lime Production
Cropland Remaining Cropland
Limestone and Dolomite Use
Soda Ash Production and Consumption
Aluminum Production
Petrochemical Production
Carbon Dioxide Consumption
Ferroalloy Production
Titanium Dioxide Production
Wetlands Remaining Wetlands
Phosphoric Acid Production
Zinc Production
Lead Production
Petroleum Systems
Silicon Carbide Production and Consumption
5,212
25
50 75
Tg CO2 Eq.
100
125
150
Figure ES-5: 2009 Sources of CO2 Emissions
-------
d1
(_)
2,500 -i
2,000
1,500 -
1,000 -
500 -
n
neiduv
by
42
Relative Contribution
by Fuel Type
2,154
219
Petroleum
• Coal
• Natural Gas
340
1,719
£-.2
Figure ES-6: 2009 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
Note: Electricity generation also includes emissions of less than 0.5 Tg CO 2 Eq. from geothermal-based electricity generation.
2,000 -,
1,500 -
cr
UJ
8 1,000
500 -
0
From Direct Fossil Fuel Combustion
• From Electricity Consumption
985
42
1,751
1,348
1,133
jjj
2
Figure ES-7: 2009 End-Use Sector Emissions of CO2, CH4, and N2O from Fossil Fuel Combustion
-------
Natural Gas Systems
Enteric Fermentation
Landfills
Coal Mining
Manure Management
Petroleum Systems
Wastewater Treatment
Forest Land Remaining Forest Land
Rice Cultivation
Stationary Combustion
Abandoned Underground Coal Mines |
Mobile Combustion |
Composting |
Petrochemical Production |
Iron and Steel Production & Metallurgical Coke Production
Field Burning of Agricultural Residues
Ferroalloy Production
Silicon Carbide Production and Consumption
Incineration of Waste
I
I
< 0.5
< 0.5
<0.5
<0.5
<0.5
CH4 as a Portion
of all Emissions
10.3%
o
25 50
Figure ES-8: 2009 Sources of CH4 Emissions
75 100 125
Tg C02 Eq.
150 175 200 225
Agricultural Soil Management
Mobile Combustion
Manure Management
Nitric Acid Production
Stationary Combustion
Forest Land Remaining Forest Land
Wastewater Treatment
N2O from Product Uses
Adipic Acid Production
Composting
Settlements Remaining Settlements
Incineration of Waste
Field Burning of Agricultural Residues
Wetlands Remaining Wetlands
205
N2O as a Portion
of all Emissions
4.5%
I <0.
< 0.
< 0.
10
20 30
Tg CO2 Eq.
40
50
Figure ES-9: 2009 Sources of N2O Emissions
-------
Substitution of Ozone
Depleting Substances
Electrical Transmission
and Distribution
HCFC-22 Production
Semiconductor
Manufacture
Aluminum Production
Magnesium Production
and Processing
MFCs, PFCs, and SF6 as a Portion
of all Emissions
2.2%
I
10
20 30
TgCO2Eq.
50
Figure ES-10: 2009 Sources of MFCs, PFCs, and SF6 Emissions
LULUCF (sources)
8
6,000 -
5,500
5,000
4,500 -
4,000 -
3,500 -
3,000 -
2,500 -
2,000 -
1,500 -
1,000 -
500 -
0 -
(500) -
(1,000) -
(1,500) -
Energy
Land Use, Land-Use Change and Forestry (sinks)
8888888888
Note: Relatively smaller amounts of GWP-weighted emissions are also emitted from the Solvent and Other Product Use
sectors
Figure ES-11: U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector
-------
Renewable
Energy
Nuclear Electric 8.2%
Power
Figure ES-12: 2009 U.S. Energy Consumption by Energy Source
8
2,500
2,000
i'500
1,000 -
500 -
Electric
Power Industry
Transportation
Industry
Agriculture
! Commercial
Residential
^j-L/i^D
o o o
_ o o o
-------
2,500 -,
Industry
Transportation
Commercial (gray)
Residential (black)
Agriculture
Figure ES-14: Emissions with Electricity Distributed to Economic Sectors
Note: Does not include U.S. Territories.
8
II
O
s
iH
~$
T3
s
170 -,
160 -
150 -
140 -
130 -
120 -
110 -
100 -
90 -
80 -
70 -
60 -
Real GDP
Population
Emissions
per capita
Emissions
per $GDP
s? s? s? s?
CTl CTl CTl CTl
0*0*0*0*0*
O1O1O1O1O1
0000000000
OOOOOOOOOO
Figure ES-15: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product
-------
C02 Emissions from Stationary Combustion - Coal
C02 Emissions from Mobile Combustion: Road
C02 Emissions from Stationary Combustion - Gas
C02 Emissions from Stationary Combustion - Oil
Fugitive Emissions from Natural Gas Systems
Direct N20 Emissions from Agricultural Soil Management
C02 Emissions from Mobile Combustion: Aviation
CH4 Emissions from Enteric Fermentation
C02 Emissions from Non-Energy Use of Fuels
Emissions from Substitutes for Ozone Depleting Substances
CH4 Emissions from Landfills
C02 Emissions from Mobile Combustion: Other
Fugitive Emissions from Coal Mining
CH4 Emissions from Manure Management
Indirect N20 Emissions from Applied Nitrogen
C02 Em. from Iron and Steel Prod. & Metallurgical Coke Prod.
C02 Emissions from Mobile Combustion: Marine
Fugitive Emissions from Petroleum Systems
CH4 Emissions from Wastewater Treatment
Non-C02 Emissions from Stationary Combustion
CH4 Emissions from Rice Cultivation
Key Categories as a Portion of All
Emissions
0 200 400 600
800 1,000 1,200 1,400 1,600 1,800 2,000
TgC02Eq.
Figure ES-16: 2009 Key Categories
Notes: For a complete discussion of the key category analysis, see Annex 1.
Black bars indicate a Tier 1 level assessment key category.
Gray bars indicate a Tier 2 level assessment key category.
-------
i 1. Introduction
2 This report presents estimates by the United States government of U.S. anthropogenic greenhouse gas emissions and
3 sinks for the years 1990 through 2009. A summary of these estimates is provided in Table 2.1 and Table 2.2 by gas
4 and source category in the Trends in Greenhouse Gas Emissions chapter. The emission estimates in these tables are
5 presented on both a full molecular mass basis and on a Global Warming Potential (GWP) weighted basis in order to
6 show the relative contribution of each gas to global average radiative forcing.20 This report also discusses the
7 methods and data used to calculate these emission estimates.
8 In 1992, the United States signed and ratified the United Nations Framework Convention on Climate Change
9 (UNFCCC). As stated in Article 2 of the UNFCCC, "The ultimate objective of this Convention and any related
10 legal instruments that the Conference of the Parties may adopt is to achieve, in accordance with the relevant
11 provisions of the Convention, stabilization of greenhouse gas concentrations in the atmosphere at a level that would
12 prevent dangerous anthropogenic interference with the climate system. Such a level should be achieved within a
13 time-frame sufficient to allow ecosystems to adapt naturally to climate change, to ensure that food production is not
14 threatened and to enable economic development to proceed in a sustainable manner."21'22
15 Parties to the Convention, by ratifying, "shall develop, periodically update, publish and make available.. .national
16 inventories of anthropogenic emissions by sources and removals by sinks of all greenhouse gases not controlled by
17 the Montreal Protocol, using comparable methodologies.. ,"23 The United States views this report as an opportunity
18 to fulfill these commitments under the UNFCCC.
19 In 1988, preceding the creation of the UNFCCC, the World Meteorological Organization (WMO) and the United
20 Nations Environment Programme (UNEP) jointly established the Intergovernmental Panel on Climate Change
21 (IPCC). The role of the IPCC is to assess on a comprehensive, objective, open and transparent basis the scientific,
22 technical and socio-economic information relevant to understanding the scientific basis of risk of human-induced
23 climate change, its potential impacts and options for adaptation and mitigation (IPCC 2003). Under Working Group
24 1 of the IPCC, nearly 140 scientists and national experts from more than thirty countries collaborated in the creation
25 of the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC/UNEP/OECD/IEA 1997) to
26 ensure that the emission inventories submitted to the UNFCCC are consistent and comparable between nations. The
27 IPCC accepted the Revised 1996 IPCC Guidelines at its Twelfth Session (Mexico City, September 11-13, 1996).
28 This report presents information in accordance with these guidelines. In addition, this Inventory is in accordance
29 with the IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories and
30 the Good Practice Guidance for Land Use, Land-Use Change, and Forestry, which further expanded upon the
31 methodologies in the Revised 1996 IPCC Guidelines. The IPCC has also accepted the 2006 Guidelines for National
32 Greenhouse Gas Inventories (IPCC 2006) at its Twenty-Fifth Session (Mauritius, April 2006). The 2006 IPCC
33 Guidelines build on the previous bodies of work and includes new sources and gases ".. .as well as updates to the
34 previously published methods whenever scientific and technical knowledge have improved since the previous
35 guidelines were issued." Many of the methodological improvements presented in the 2006 Guidelines have been
36 adopted in this Inventory.
37 Overall, this inventory of anthropogenic greenhouse gas emissions provides a common and consistent mechanism
38 through which Parties to the UNFCCC can estimate emissions and compare the relative contribution of individual
39 sources, gases, and nations to climate change. The inventory provides a national estimate of sources and sinks for
40 the United States, including all states and U.S. territories24 . The structure of this report is consistent with the current
20 See the section below entitled Global Warming Potentials for an explanation of GWP values.
21 The term "anthropogenic", in this context, refers to greenhouse gas emissions and removals that are a direct result of human
activities or are the result of natural processes that have been affected by human activities (IPCC/UNEP/OECD/IEA 1997).
22 Article 2 of the Framework Convention on Climate Change published by the UNEP/WMO Information Unit on Climate
Change. See . (UNEP/WMO 2000)
23 Article 4(l)(a) of the United Nations Framework Convention on Climate Change (also identified in Article 12). Subsequent
decisions by the Conference of the Parties elaborated the role of Annex I Parties in preparing national inventories. See
.
24 U.S. Territories include American Samoa, Guam, Puerto Rico, U.S. Virgin Islands, Wake Island, and other U.S. Pacific
Islands.
Introduction 1-1
-------
1 UNFCCC Guidelines on Annual Inventories (UNFCCC 2006).
2
3 [BEGIN BOX]
4
5 Box 1-1: Methodological approach for estimating and reporting U.S. emissions and sinks
6
7 In following the UNFCCC requirement under Article 4.1 to develop and submit national greenhouse gas emissions
8 inventories, the emissions and sinks presented in this report are organized by source and sink categories and
9 calculated using internationally-accepted methods provided by the Intergovernmental Panel on Climate Change
10 (IPCC).25 Additionally, the calculated emissions and sinks in a given year for the U.S. are presented in a common
11 manner in line with the UNFCCC reporting guidelines for the reporting of inventories under this international
12 agreement.26 The use of consistent methods to calculate emissions and sinks by all nations providing their
13 inventories to the UNFCCC ensures that these reports are comparable. In this regard, U.S. emissions and sinks
14 reported in this inventory report are comparable to emissions and sinks reported by other countries. Emissions and
15 sinks provided in this inventory do not preclude alternative examinations, but rather this inventory report presents
16 emissions and sinks in a common format consistent with how countries are to report inventories under the
17 UNFCCC. The report itself follows this standardized format, and provides an explanation of the IPCC methods
18 used to calculate emissions and sinks, and the manner in which those calculations are conducted.
19
20 [END BOX]
21 1.1. Background Information
22 Science
23 For over the past 200 years, the burning of fossil fuels such as coal and oil, deforestation, and other sources have
24 caused the concentrations of heat-trapping "greenhouse gases" to increase significantly in our atmosphere. These
25 gases absorb some of the energy being radiated from the surface of the earth and trap it in the atmosphere,
26 essentially acting like a blanket that makes the earth's surface warmer than it would be otherwise.
27 Greenhouse gases are necessary to life as we know it, because without them the planet's surface would be about 60
28 °F cooler than present. But, as the concentrations of these gases continue to increase in the atmosphere, the Earth's
29 temperature is climbing above past levels. According to NOAA and NASA data, the Earth's average surface
30 temperature has increased by about 1.2 to 1.4 °F since 1900. The ten warmest years on record (since 1850) have all
31 occurred in the past 13 years (EPA 2009). Most of the warming in recent decades is very likely the result of human
32 activities. Other aspects of the climate are also changing such as rainfall patterns, snow and ice cover, and sea level.
33 If greenhouse gases continue to increase, climate models predict that the average temperature at the Earth's surface
34 could increase from 2.0 to 11.5 °F above 1990 levels by the end of this century (IPCC 2007). Scientists are certain
35 that human activities are changing the composition of the atmosphere, and that increasing the concentration of
36 greenhouse gases will change the planet's climate. But they are not sure by how much it will change, at what rate it
37 will change, or what the exact effects will be.27
38 Greenhouse Gases
39 Although the Earth's atmosphere consists mainly of oxygen and nitrogen, neither plays a significant role in
40 enhancing the greenhouse effect because both are essentially transparent to terrestrial radiation. The greenhouse
41 effect is primarily a function of the concentration of water vapor, carbon dioxide (CO2), and other trace gases in the
25 See .
26 See
27 For more information see
1-2 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 atmosphere that absorb the terrestrial radiation leaving the surface of the Earth (IPCC 2001). Changes in the
2 atmospheric concentrations of these greenhouse gases can alter the balance of energy transfers between the
3 atmosphere, space, land, and the oceans.28 A gauge of these changes is called radiative forcing, which is a measure
4 of the influence a factor has in altering the balance of incoming and outgoing energy in the Earth-atmosphere system
5 (IPCC 2001). Holding everything else constant, increases in greenhouse gas concentrations in the atmosphere will
6 produce positive radiative forcing (i.e., a net increase in the absorption of energy by the Earth).
7 Climate change can be driven by changes in the atmospheric concentrations of a number ofradiatively
8 active gases and aerosols. We have clear evidence that human activities have affected concentrations,
9 distributions and life cycles of these gases (IPCC 1996).
10 Naturally occurring greenhouse gases include water vapor, CO2, methane (CH4), nitrous oxide (N2O), and ozone
11 (O3). Several classes of halogenated substances that contain fluorine, chlorine, or bromine are also greenhouse
12 gases, but they are, for the most part, solely a product of industrial activities. Chlorofluorocarbons (CFCs) and
13 hydrochlorofluorocarbons (HCFCs) are halocarbons that contain chlorine, while halocarbons that contain bromine
14 are referred to as bromofluorocarbons (i.e., halons). As stratospheric ozone depleting substances, CFCs, HCFCs,
15 and halons are covered under the Montreal Protocol on Substances that Deplete the Ozone Layer. The UNFCCC
16 defers to this earlier international treaty. Consequently, Parties to the UNFCCC are not required to include these
17 gases in national greenhouse gas inventories.29 Some other fluorine-containing halogenated substances—
18 hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6)—do not deplete stratospheric
19 ozone but are potent greenhouse gases. These latter substances are addressed by the UNFCCC and accounted for in
20 national greenhouse gas inventories.
21 There are also several gases that, although they do not have a commonly agreed upon direct radiative forcing effect,
22 do influence the global radiation budget. These tropospheric gases include carbon monoxide (CO), nitrogen dioxide
23 (NO2), sulfur dioxide (SO2), and tropospheric (ground level) ozone O3. Tropospheric ozone is formed by two
24 precursor pollutants, volatile organic compounds (VOCs) and nitrogen oxides (NOX) in the presence of ultraviolet
25 light (sunlight). Aerosols are extremely small particles or liquid droplets that are often composed of sulfur
26 compounds, carbonaceous combustion products, crustal materials and other human induced pollutants. They can
27 affect the absorptive characteristics of the atmosphere. Comparatively, however, the level of scientific
28 understanding of aerosols is still very low (IPCC 2001).
29 CO2, CH4, and N2O are continuously emitted to and removed from the atmosphere by natural processes on Earth.
30 Anthropogenic activities, however, can cause additional quantities of these and other greenhouse gases to be emitted
31 or sequestered, thereby changing their global average atmospheric concentrations. Natural activities such as
32 respiration by plants or animals and seasonal cycles of plant growth and decay are examples of processes that only
33 cycle carbon or nitrogen between the atmosphere and organic biomass. Such processes, except when directly or
34 indirectly perturbed out of equilibrium by anthropogenic activities, generally do not alter average atmospheric
35 greenhouse gas concentrations over decadal timeframes. Climatic changes resulting from anthropogenic activities,
36 however, could have positive or negative feedback effects on these natural systems. Atmospheric concentrations of
37 these gases, along with their rates of growth and atmospheric lifetimes, are presented in Table 1-1.
38 Table 1-1: Global Atmospheric Concentration, Rate of Concentration Change, and Atmospheric Lifetime (years) of
39 Selected Greenhouse Gases
Atmospheric Variable CO2 CH4 N2O SFg CF4
Pre-industrial atmospheric
concentration
Atmospheric concentration
Rate of concentration change
Atmospheric lifetime (years)
278 ppm
385 ppm
1.4ppm/yr
50-200d
0.715 ppm
1.741-1.865 ppnf
0.005 ppm/yrb
12e
0.270 ppm
0.321-0.322 ppma
0.26%/yr
114e
Oppt
5.6 ppt
Linear0
3,200
40 ppt
74 ppt
Linear0
>50,000
40 Source: Pre-industrial atmospheric concentrations and rate of concentration changes for all gases are from IPCC (2007). The
41 current atmospheric concentration for CO2 is from NOAA/ESRL (2009).
28 For more on the science of climate change, see NRC (2001).
29 Emissions estimates of CFCs, HCFCs, halons and other ozone-depleting substances are included in this document for
informational purposes.
Introduction 1-3
-------
1 a The range is the annual arithmetic averages from a mid-latitude Northern-Hemisphere site and a mid-latitude Southern-
2 Hemisphere site for October 2006 through September 2007 (CDIAC 2009).
3 b The growth rate for atmospheric CH4 has been decreasing from 1.4 ppb/yr in 1984 to less than 0 ppb/yr in 2001,2004, and
4 2005.
5 ° IPCC (2007) identifies the rate of concentration change for SF6 and CF4 as linear.
6 d No single lifetime can be defined for CO2 because of the different rates of uptake by different removal processes.
7 e This lifetime has been defined as an "adjustment time" that takes into account the indirect effect of the gas on its own residence
8 time.
9
10 A brief description of each greenhouse gas, its sources, and its role in the atmosphere is given below. The following
11 section then explains the concept of GWPs, which are assigned to individual gases as a measure of their relative
12 average global radiative forcing effect.
13 Water Vapor (H2O). Overall, the most abundant and dominant greenhouse gas in the atmosphere is water vapor.
14 Water vapor is neither long-lived nor well mixed in the atmosphere, varying spatially from 0 to 2 percent (IPCC
15 1996). In addition, atmospheric water can exist in several physical states including gaseous, liquid, and solid.
16 Human activities are not believed to affect directly the average global concentration of water vapor, but, the
17 radiative forcing produced by the increased concentrations of other greenhouse gases may indirectly affect the
18 hydrologic cycle. While a warmer atmosphere has an increased water holding capacity, increased concentrations of
19 water vapor affects the formation of clouds, which can both absorb and reflect solar and terrestrial radiation.
20 Aircraft contrails, which consist of water vapor and other aircraft emittants, are similar to clouds in their radiative
21 forcing effects (IPCC 1999).
22 Carbon Dioxide. In nature, carbon is cycled between various atmospheric, oceanic, land biotic, marine biotic, and
23 mineral reservoirs. The largest fluxes occur between the atmosphere and terrestrial biota, and between the
24 atmosphere and surface water of the oceans. In the atmosphere, carbon predominantly exists in its oxidized form as
25 CO2. Atmospheric CO2 is part of this global carbon cycle, and therefore its fate is a complex function of
26 geochemical and biological processes. CO2 concentrations in the atmosphere increased from approximately 280
27 parts per million by volume (ppmv) in pre-industrial times to 385 ppmv in 2008, a 37.5 percent increase (IPCC 2007
28 and NOAA/ESRL 2009) .3031 The IPCC definitively states that "the present atmospheric CO2 increase is caused by
29 anthropogenic emissions of CO2" (IPCC 2001). The predominant source of anthropogenic CO2 emissions is the
30 combustion of fossil fuels. Forest clearing, other biomass burning, and some non-energy production processes (e.g.,
31 cement production) also emit notable quantities of CO2. In it's fourth assessment, the IPCC stated "most of the
32 observed increase in global average temperatures since the mid-20th century is very likely due to the observed
33 increased in anthropogenic greenhouse gas concentrations," of which CO2is the most important (IPCC 2007)
34 Methane. CH4 is primarily produced through anaerobic decomposition of organic matter in biological systems.
35 Agricultural processes such as wetland rice cultivation, enteric fermentation in animals, and the decomposition of
36 animal wastes emit CH4, as does the decomposition of municipal solid wastes. CH4 is also emitted during the
37 production and distribution of natural gas and petroleum, and is released as a by-product of coal mining and
38 incomplete fossil fuel combustion. Atmospheric concentrations of CH4 have increased by about 143 percent since
39 1750, from a pre-industrial value of about 722 ppb to 1,741-1,865 ppb in 200732, although the rate of increase has
40 been declining. The IPCC has estimated that slightly more than half of the current CH4 flux to the atmosphere is
41 anthropogenic, from human activities such as agriculture, fossil fuel use, and waste disposal (IPCC 2007).
42 CH4 is removed from the atmosphere through a reaction with the hydroxyl radical (OH) and is ultimately converted
43 to CO2. Minor removal processes also include reaction with chlorine in the marine boundary layer, a soil sink, and
44 stratospheric reactions. Increasing emissions of CH4 reduce the concentration of OH, a feedback that may increase
45 the atmospheric lifetime of CH4 (IPCC 2001).
46 Nitrous Oxide. Anthropogenic sources of N2O emissions include agricultural soils, especially production of
30 The pre-industrial period is considered as the time preceding the year 1750 (IPCC 2001).
31 Carbon dioxide concentrations during the last 1,000 years of the pre-industrial period (i.e., 750-1750), a time of relative
climate stability, fluctuated by about +10 ppmv around 280 ppmv (IPCC 2001).
32 The range is the annual arithmetic averages from a mid-latitude Northern-Hemisphere site and a mid-latitude Southern-
Hemisphere site for October 2006 through September 2007 (CDIAC 2009)
1-4 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 nitrogen-fixing crops and forages, the use of synthetic and manure fertilizers, and manure deposition by livestock;
2 fossil fuel combustion, especially from mobile combustion; adipic (nylon) and nitric acid production; wastewater
3 treatment and waste incineration; and biomass burning. The atmospheric concentration of N2O has increased by 18
4 percent since 1750, from a pre-industrial value of about 270 ppb to 321-322 ppb in 200733, a concentration that has
5 not been exceeded during the last thousand years. N2O is primarily removed from the atmosphere by the photolytic
6 action of sunlight in the stratosphere (IPCC 2007).
7 Ozone. Ozone is present in both the upper stratosphere,34 where it shields the Earth from harmful levels of
8 ultraviolet radiation, and at lower concentrations in the troposphere,35 where it is the main component of
9 anthropogenic photochemical "smog." During the last two decades, emissions of anthropogenic chlorine and
10 bromine-containing halocarbons, such as CFCs, have depleted stratospheric ozone concentrations. This loss of
11 ozone in the stratosphere has resulted in negative radiative forcing, representing an indirect effect of anthropogenic
12 emissions of chlorine and bromine compounds (IPCC 1996). The depletion of stratospheric ozone and its radiative
13 forcing was expected to reach a maximum in about 2000 before starting to recover. As of IPCC's fourth
14 assessment,"whether or not recently observed changes in ozone trends are already indicative of recovery of the
15 global ozone layer is not yet clear." (IPCC 2007)
16 The past increase in tropospheric ozone, which is also a greenhouse gas, is estimated to provide the third largest
17 increase in direct radiative forcing since the pre-industrial era, behind CO2 and CH4. Tropospheric ozone is
18 produced from complex chemical reactions of volatile organic compounds mixing with NOX in the presence of
19 sunlight. The tropospheric concentrations of ozone and these other pollutants are short-lived and, therefore,
20 spatially variable. (IPCC 2001)
21 Halocarbons, Perfluorocarbons, and Sulfur Hexafluoride. Halocarbons are, for the most part, man-made chemicals
22 that have both direct and indirect radiative forcing effects. Halocarbons that contain chlorine (CFCs, HCFCs,
23 methyl chloroform, and carbon tetrachloride) and bromine (halons, methyl bromide, and hydrobromofluorocarbons
24 [HFCs]) result in stratospheric ozone depletion and are therefore controlled under the Montreal Protocol on
25 Substances that Deplete the Ozone Layer. Although CFCs and HCFCs include potent global warming gases, their
26 net radiative forcing effect on the atmosphere is reduced because they cause stratospheric ozone depletion, which
27 itself is an important greenhouse gas in addition to shielding the Earth from harmful levels of ultraviolet radiation.
28 Under the Montreal Protocol, the United States phased out the production and importation of halons by 1994 and of
29 CFCs by 1996. Under the Copenhagen Amendments to the Protocol, a cap was placed on the production and
30 importation of HCFCs by non-Article 536 countries beginning in 1996, and then followed by a complete phase-out
31 by the year 2030. While ozone depleting gases covered under the Montreal Protocol and its Amendments are not
32 covered by the UNFCCC; they are reported in this inventory under Annex 6.2 of this report for informational
33 purposes.
34 HFCs, PFCs, and SF6 are not ozone depleting substances, and therefore are not covered under the Montreal Protocol.
35 They are, however, powerful greenhouse gases. HFCs are primarily used as replacements for ozone depleting
36 substances but also emitted as a by-product of the HCFC-22 manufacturing process. Currently, they have a small
37 aggregate radiative forcing impact, but it is anticipated that their contribution to overall radiative forcing will
38 increase (IPCC 2001). PFCs and SF6 are predominantly emitted from various industrial processes including
39 aluminum smelting, semiconductor manufacturing, electric power transmission and distribution, and magnesium
33 The range is the annual arithmetic averages from a mid-latitude Northern-Hemisphere site and a mid-latitude Southern-
Hemisphere site for October 2006 through September 2007 (CDIAC 2009).
34 The stratosphere is the layer from the troposphere up to roughly 50 kilometers. In the lower regions the temperature is nearly
constant but in the upper layer the temperature increases rapidly because of sunlight absorption by the ozone layer. The ozone-
layer is the part of the stratosphere from 19 kilometers up to 48 kilometers where the concentration of ozone reaches up to 10
parts per million.
35 The troposphere is the layer from the ground up to 11 kilometers near the poles and up to 16 kilometers in equatorial regions
(i.e., the lowest layer of the atmosphere where people live). It contains roughly 80 percent of the mass of all gases in the
atmosphere and is the site for most weather processes, including most of the water vapor and clouds.
36 Article 5 of the Montreal Protocol covers several groups of countries, especially developing countries, with low consumption
rates of ozone depleting substances. Developing countries with per capita consumption of less than 0.3 kg of certain ozone
depleting substances (weighted by their ozone depleting potential) receive financial assistance and a grace period often
additional years in the phase-out of ozone depleting substances.
Introduction 1-5
-------
1 casting. Currently, the radiative forcing impact of PFCs and SF6 is also small, but they have a significant growth
2 rate, extremely long atmospheric lifetimes, and are strong absorbers of infrared radiation, and therefore have the
3 potential to influence climate far into the future (IPCC 2001).
4 Carbon Monoxide. Carbon monoxide has an indirect radiative forcing effect by elevating concentrations of CH4 and
5 tropospheric ozone through chemical reactions with other atmospheric constituents (e.g., the hydroxyl radical, OH)
6 that would otherwise assist in destroying CH4 and tropospheric ozone. Carbon monoxide is created when carbon-
7 containing fuels are burned incompletely. Through natural processes in the atmosphere, it is eventually oxidized to
8 CO2. Carbon monoxide concentrations are both short-lived in the atmosphere and spatially variable.
9 Nitrogen Oxides. The primary climate change effects of nitrogen oxides (i.e., NO and NO2) are indirect and result
10 from their role in promoting the formation of ozone in the troposphere and, to a lesser degree, lower stratosphere,
11 where it has positive radiative forcing effects.37 Additionally, NOX emissions from aircraft are also likely to
12 decrease CH4 concentrations, thus having a negative radiative forcing effect (IPCC 1999). Nitrogen oxides are
13 created from lightning, soil microbial activity, biomass burning (both natural and anthropogenic fires) fuel
14 combustion, and, in the stratosphere, from the photo-degradation of N2O. Concentrations of NOX are both relatively
15 short-lived in the atmosphere and spatially variable.
16 Nonmethane Volatile Organic Compounds (NMVOCs). Non-CH4 volatile organic compounds include substances
17 such as propane, butane, and ethane. These compounds participate, along with NOX, in the formation of
18 tropospheric ozone and other photochemical oxidants. NMVOCs are emitted primarily from transportation and
19 industrial processes, as well as biomass burning and non-industrial consumption of organic solvents. Concentrations
20 of NMVOCs tend to be both short-lived in the atmosphere and spatially variable.
21 Aerosols. Aerosols are extremely small particles or liquid droplets found in the atmosphere. They can be produced
22 by natural events such as dust storms and volcanic activity, or by anthropogenic processes such as fuel combustion
23 and biomass burning. Aerosols affect radiative forcing differently than greenhouse gases, and their radiative effects
24 occur through direct and indirect mechanisms: directly by scattering and absorbing solar radiation; and indirectly by
25 increasing droplet counts that modify the formation, precipitation efficiency, and radiative properties of clouds.
26 Aerosols are removed from the atmosphere relatively rapidly by precipitation. Because aerosols generally have
27 short atmospheric lifetimes, and have concentrations and compositions that vary regionally, spatially, and
28 temporally, their contributions to radiative forcing are difficult to quantify (IPCC 2001).
29 The indirect radiative forcing from aerosols is typically divided into two effects. The first effect involves decreased
30 droplet size and increased droplet concentration resulting from an increase in airborne aerosols. The second effect
31 involves an increase in the water content and lifetime of clouds due to the effect of reduced droplet size on
32 precipitation efficiency (IPCC 2001). Recent research has placed a greater focus on the second indirect radiative
3 3 forcing effect of aerosols.
34 Various categories of aerosols exist, including naturally produced aerosols such as soil dust, sea salt, biogenic
35 aerosols, sulfates, and volcanic aerosols, and anthropogenically manufactured aerosols such as industrial dust and
36 carbonaceous38 aerosols (e.g., black carbon, organic carbon) from transportation, coal combustion, cement
37 manufacturing, waste incineration, and biomass burning.
38 The net effect of aerosols on radiative forcing is believed to be negative (i.e., net cooling effect on the climate),
39 although because they remain in the atmosphere for only days to weeks, their concentrations respond rapidly to
40 changes in emissions.39 Locally, the negative radiative forcing effects of aerosols can offset the positive forcing of
41 greenhouse gases (IPCC 1996). "However, the aerosol effects do not cancel the global-scale effects of the much
42 longer-lived greenhouse gases, and significant climate changes can still result" (IPCC 1996).
43 The IPCC's Third Assessment Report notes that "the indirect radiative effect of aerosols is now understood to also
37 NOX emissions injected higher in the stratosphere, primarily from fuel combustion emissions from high altitude supersonic
aircraft, can lead to stratospheric ozone depletion.
38 Carbonaceous aerosols are aerosols that are comprised mainly of organic substances and forms of black carbon (or soot)
(IPCC 2001).
39 Volcanic activity can inject significant quantities of aerosol producing sulfur dioxide and other sulfur compounds into the
stratosphere, which can result in a longer negative forcing effect (i.e., a few years) (IPCC 1996).
1-6 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 encompass effects on ice and mixed-phase clouds, but the magnitude of any such indirect effect is not known,
2 although it is likely to be positive" (IPCC 2001). Additionally, current research suggests that another constituent of
3 aerosols, black carbon, has a positive radiative forcing, and that its presence "in the atmosphere above highly
4 reflective surfaces such as snow and ice, or clouds, may cause a significant positive radiative forcing (IPCC 2007).
5 The primary anthropogenic emission sources of black carbon include diesel exhaust and open biomass burning.
6 Global Warming Potentials
7 A global warming potential is a quantified measure of the globally averaged relative radiative forcing impacts of a
8 particular greenhouse gas (see Table 1-2). It is defined as the ratio of the time-integrated radiative forcing from the
9 instantaneous release of 1 kilogram (kg) of a trace substance relative to that of 1 kg of a reference gas (IPCC 2001).
10 Direct radiative effects occur when the gas itself absorbs radiation. Indirect radiative forcing occurs when chemical
11 transformations involving the original gas produce a gas or gases that are greenhouse gases, or when a gas
12 influences other radiatively important processes such as the atmospheric lifetimes of other gases. The reference gas
13 used is CO2, and therefore GWP weighted emissions are measured in teragrams of CO2 equivalent (Tg CO2 Eq.)40
14 The relationship between gigagrams (Gg) of a gas and Tg CO2 Eq. can be expressed as follows:
( T ^
15 TgCO2Eq = (Ggofgas)x(GWP)x i—
5 2 4 v 5 5 ; v ) ^OOOGgJ
16 where,
17 Tg CO2 Eq. = Teragrams of CO2 Equivalents
18 Gg = Gigagrams (equivalent to a thousand metric tons)
19 GWP = Global Warming Potential
20 Tg = Teragrams
21 GWP values allow for a comparison of the impacts of emissions and reductions of different gases. According to the
22 IPCC, GWPs typically have an uncertainty of ±35 percent. The parties to the UNFCCC have also agreed to use
23 GWPs based upon a 100-year time horizon although other time horizon values are available.
24 Greenhouse gas emissions and removals should be presented on a gas-by-gas basis in units of mass... In
25 addition, consistent with decision 2/CP.3, Parties should report aggregate emissions and removals of
26 greenhouse gases, expressed in CO2 equivalent terms at summary inventory level, using GWP values
27 provided by the IPCC in its Second Assessment Report... based on the effects of greenhouse gases over a
28 100-year time horizon.41
29 Greenhouse gases with relatively long atmospheric lifetimes (e.g., CO2, CH4, N2O, HFCs, PFCs, and SF6) tend to be
30 evenly distributed throughout the atmosphere, and consequently global average concentrations can be determined.
31 The short-lived gases such as water vapor, carbon monoxide, tropospheric ozone, ozone precursors (e.g., NOX, and
32 NMVOCs), and tropospheric aerosols (e.g., SO2 products and carbonaceous particles), however, vary regionally,
33 and consequently it is difficult to quantify their global radiative forcing impacts. No GWP values are attributed to
34 these gases that are short-lived and spatially inhomogeneous in the atmosphere.
35
36
40 Carbon comprises 12/44ths of carbon dioxide by weight.
41 Framework Convention on Climate Change; ; 1 November 2002; Report of the
Conference of the Parties at its eighth session; held at New Delhi from 23 October to 1 November 2002; Addendum; Part One:
Action taken by the Conference of the Parties at its eighth session; Decision -/CP.8; Communications from Parties included in
Annex I to the Convention: Guidelines for the Preparation of National Communications by Parties Included in Annex I to the
Convention, Part 1: UNFCCC reporting guidelines on annual inventories; p. 7. (UNFCCC 2003)
Introduction 1-7
-------
Table 1-2: Global Warming Potentials and Atmospheric Lifetimes (Years) Used in this Report
2
o
6
4
5
Gas
C02
CH4b
N2O
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-152a
HFC-227ea
HFC-236fa
HFC-4310mee
CF4
C2F6
C^io
C6Fi4
SF6
Source: (IPCC 1996)
a 100-year time horizon
bTheGWPofCH4incluc
stratospheric water vapor
Atmospheric Lifetime
50-200
12±3
120
264
5.6
32.6
14.6
48.3
1.5
36.5
209
17.1
50,000
10,000
2,600
3,200
3,200
ies the direct effects and those ini
. The indirect effect due to the pi
GWPa
1
21
310
11,700
650
2,800
1,300
3,800
140
2,900
6,300
1,300
6,500
9,200
7,000
7,400
23,900
direct effects due
reduction of CO2
[BEGIN BOX]
Box 1-2: The IPCC Fourth Assessment Report and Global Warming Potentials
10 In 2007, the IPCC published its Fourth Assessment Report (AR4), which provided an updated and more
1 1 comprehensive scientific assessment of climate change. Within this report, the GWPs of several gases were revised
12 relative to the SAR and the IPCC's Third Assessment Report (TAR) (IPCC 200 1). Thus the GWPs used in this
13 report have been updated twice by the IPCC; although the SAR GWPs are used throughout this report, it is
14 interesting to review the changes to the GWPs and the impact such improved understanding has on the total GWP-
15 weighted emissions of the United States. Since the SAR and TAR, the IPCC has applied an improved calculation of
16 CO2 radiative forcing and an improved CO2 response function. The GWPs are drawn from IPCC/TEAP (2005) and
17 the TAR, with updates for those cases where new laboratory or radiative transfer results have been published.
18 Additionally, the atmospheric lifetimes of some gases have been recalculated. In addition, the values for radiative
19 forcing and lifetimes have been recalculated for a variety of halocarbons, which were not presented in the SAR.
20 Table 1-3 presents the new GWPs, relative to those presented in the SAR.
21 Table 1-3: Comparison of 100-Year GWPs
Gas
C02
CH4*
N2O
HFC-23
HFC-32
HFC-125
HFC-134a
HFC-143a
HFC-152a
SAR
1
21
310
11,700
650
2,800
1,300
3,800
140
TAR
1
23
296
12,000
550
3,400
1,300
4,300
120
AR4
1
25
298
14,800
675
3,500
1,430
4,470
124
Change from
SAR
TAR
NC
2
(14)
300
(100)
600
NC
500
(20)
AR4
0
4
(12)
3,100
25
700
130
670
(16)
HFC-227ea 2,900 3,500 3,220 600 320
HFC-236fa 6,300 9,400 9,810 3,100 3,510
1-8 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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HFC-4310mee
CF4
C2F6
C4FJO
C6F14
SF6
1,300
6,500
9,200
7,000
7,400
23,900
1,500
5,700
11,900
8,600
9,000
22,200
1,640
7,390
12,200
8,860
9,300
22,800
200
(800)
2,700
1,600
1,600
(1,700)
340
890
3,000
1,860
1,900
(1,100)
1 Source: (IPCC 2007, IPCC 2001)
2 NC (No Change)
3 Note: Parentheses indicate negative values.
4 * The GWP of CH4 includes the direct effects and those indirect effects due to the production of tropospheric ozone and
5 stratospheric water vapor. The indirect effect due to the production of CO2 is not included.
6
7 To comply with international reporting standards under the UNFCCC, official emission estimates are reported by
8 the United States using SAR GWP values. The UNFCCC reporting guidelines for national inventories42 were
9 updated in 2002 but continue to require the use of GWPs from the SAR so that current estimates of aggregate
10 greenhouse gas emissions for 1990 through 2009 are consistent and comparable with estimates developed prior to
11 the publication of the TAR and AR4. For informational purposes, emission estimates that use the updated GWPs
12 are presented in detail in Annex 6.1 of this report. All estimates provided throughout this report are also presented
13 in unweighted units.
14
15 [END BOX]
16 1.2. Institutional Arrangements
17 The U.S. Environmental Protection Agency (EPA), in cooperation with other U.S. government agencies, prepares
18 the Inventory of U.S. Greenhouse Gas Emissions and Sinks. A wide range of agencies and individuals are involved
19 in supplying data to, reviewing, or preparing portions of the U.S. Inventory—including federal and state government
20 authorities, research and academic institutions, industry associations, and private consultants.
21 Within EPA, the Office of Atmospheric Programs (OAP) is the lead office responsible for the emission calculations
22 provided in the Inventory, as well as the completion of the National Inventory Report and the Common Reporting
23 Format tables. The Office of Transportation and Air Quality (OTAQ) is also involved in calculating emissions for
24 the Inventory. While the U.S. Department of State officially submits the annual Inventory to the UNFCCC, EPA's
25 OAP serves as the focal point for technical questions and comments on the U. S. Inventory. The staff of OAP and
26 OTAQ coordinates the annual methodological choice, activity data collection, and emission calculations at the
27 individual source category level. Within OAP, an inventory coordinator compiles the entire Inventory into the
28 proper reporting format for submission to the UNFCCC, and is responsible for the collection and consistency of
29 cross-cutting issues in the Inventory.
30 Several other government agencies contribute to the collection and analysis of the underlying activity data used in
31 the Inventory calculations. Formal relationships exist between EPA and other U.S. agencies that provide official
32 data for use in the Inventory. The U.S. Department of Energy's Energy Information Administration provides
33 national fuel consumption data and the U.S. Department of Defense provides military fuel consumption and bunker
34 fuels. Informal relationships also exist with other U.S. agencies to provide activity data for use in EPA's emission
35 calculations. These include: the U.S. Department of Agriculture, the U.S. Geological Survey, the Federal Highway
36 Administration, the Department of Transportation, the Bureau of Transportation Statistics, the Department of
37 Commerce, the National Agricultural Statistics Service, and the Federal Aviation Administration. Academic and
38 research centers also provide activity data and calculations to EPA, as well as individual companies participating in
39 voluntary outreach efforts with EPA. Finally, the U.S. Department of State officially submits the Inventory to the
40 UNFCCC each April.
42
See.
Introduction 1-9
-------
i 1.3. Inventory Process
2 EPA has a decentralized approach to preparing the annual U.S. Inventory, which consists of a National Inventory
3 Report (NIR) and Common Reporting Format (CRF) tables. The Inventory coordinator at EPA is responsible for
4 compiling all emission estimates, and ensuring consistency and quality throughout the NIR and CRF tables.
5 Emission calculations for individual sources are the responsibility of individual source leads, who are most familiar
6 with each source category and the unique characteristics of its emissions profile. The individual source leads
7 determine the most appropriate methodology and collect the best activity data to use in the emission calculations,
8 based upon their expertise in the source category, as well as coordinating with researchers and contractors familiar
9 with the sources. A multi-stage process for collecting information from the individual source leads and producing
10 the Inventory is undertaken annually to compile all information and data.
11 Methodology Development, Data Collection, and Emissions and Sink Estimation
12 Source leads at EPA collect input data and, as necessary, evaluate or develop the estimation methodology for the
13 individual source categories. For most source categories, the methodology for the previous year is applied to the
14 new "current" year of the Inventory, and inventory analysts collect any new data or update data that have changed
15 from the previous year. If estimates for a new source category are being developed for the first time, or if the
16 methodology is changing for an existing source category (e.g., the United States is implementing a higher Tiered
17 approach for that source category), then the source category lead will develop a new methodology, gather the most
18 appropriate activity data and emission factors (or in some cases direct emission measurements) for the entire time
19 series, and conduct a special source-specific peer review process involving relevant experts from industry,
20 government, and universities.
21 Once the methodology is in place and the data are collected, the individual source leads calculate emissions and sink
22 estimates. The source leads then update or create the relevant text and accompanying annexes for the Inventory.
23 Source leads are also responsible for completing the relevant sectoral background tables of the Common Reporting
24 Format, conducting quality assurance and quality control (QA/QC) checks, and uncertainty analyses.
25 Summary Spreadsheet Compilation and Data Storage
26 The inventory coordinator at EPA collects the source categories' descriptive text and Annexes, and also aggregates
27 the emission estimates into a summary spreadsheet that links the individual source category spreadsheets together.
28 This summary sheet contains all of the essential data in one central location, in formats commonly used in the
29 Inventory document. In addition to the data from each source category, national trend and related data are also
30 gathered in the summary sheet for use in the Executive Summary, Introduction, and Recent Trends sections of the
31 Inventory report. Electronic copies of each year's summary spreadsheet, which contains all the emission and sink
32 estimates for the United States, are kept on a central server at EPA under the jurisdiction of the Inventory
33 coordinator.
34 National Inventory Report Preparation
35 The NIR is compiled from the sections developed by each individual source lead. In addition, the inventory
36 coordinator prepares a brief overview of each chapter that summarizes the emissions from all sources discussed in
37 the chapters. The inventory coordinator then carries out a key category analysis for the Inventory, consistent with
38 the IPCC Good Practice Guidance, IPCC Good Practice Guidance for Land Use, Land Use Change and Forestry,
39 and in accordance with the reporting requirements of the UNFCCC. Also at this time, the Introduction, Executive
40 Summary, and Recent Trends sections are drafted, to reflect the trends for the most recent year of the current
41 Inventory. The analysis of trends necessitates gathering supplemental data, including weather and temperature
42 conditions, economic activity and gross domestic product, population, atmospheric conditions, and the annual
43 consumption of electricity, energy, and fossil fuels. Changes in these data are used to explain the trends observed in
44 greenhouse gas emissions in the United States. Furthermore, specific factors that affect individual sectors are
45 researched and discussed. Many of the factors that affect emissions are included in the Inventory document as
46 separate analyses or side discussions in boxes within the text. Text boxes are also created to examine the data
47 aggregated in different ways than in the remainder of the document, such as a focus on transportation activities or
48 emissions from electricity generation. The document is prepared to match the specification of the UNFCCC
49 reporting guidelines for National Inventory Reports.
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i Common Reporting Format Table Compilation
2 The CRF tables are compiled from individual tables completed by each individual source lead, which contain source
3 emissions and activity data. The inventory coordinator integrates the source data into the UNFCCC's "CRF
4 Reporter" for the United States, assuring consistency across all sectoral tables. The summary reports for emissions,
5 methods, and emission factors used, the overview tables for completeness and quality of estimates, the recalculation
6 tables, the notation key completion tables, and the emission trends tables are then completed by the inventory
7 coordinator. Internal automated quality checks on the CRF Reporter, as well as reviews by the source leads, are
8 completed for the entire time series of CRF tables before submission.
9 QA/QC and Uncertainty
10 QA/QC and uncertainty analyses are supervised by the QA/QC and Uncertainty coordinators, who have general
11 oversight over the implementation of the QA/QC plan and the overall uncertainty analysis for the Inventory (see
12 sections on QA/QC and Uncertainty, below). These coordinators work closely with the source leads to ensure that a
13 consistent QA/QC plan and uncertainty analysis is implemented across all inventory sources. The inventory QA/QC
14 plan, detailed in a following section, is consistent with the quality assurance procedures outlined by EPA and IPCC.
15 Expert and Public Review Periods
16 During the Expert Review period, a first draft of the document is sent to a select list of technical experts outside of
17 EPA. The purpose of the Expert Review is to encourage feedback on the methodological and data sources used in
18 the current Inventory, especially for sources which have experienced any changes since the previous Inventory.
19 Once comments are received and addressed, a second draft of the document is released for public review by
20 publishing a notice in the U.S. Federal Register and posting the document on the EPA Web site. The Public Review
21 period allows for a 30 day comment period and is open to the entire U.S. public.
22 Final Submittal to UNFCCC and Document Printing
23 After the final revisions to incorporate any comments from the Expert Review and Public Review periods, EPA
24 prepares the final National Inventory Report and the accompanying Common Reporting Format Reporter database.
25 The U.S. Department of State sends the official submission of the U.S. Inventory to the UNFCCC. The document is
26 then formatted for printing, posted online, printed by the U.S. Government Printing Office, and made available for
27 the public.
28 1.4. Methodology and Data Sources
29 Emissions of greenhouse gases from various source and sink categories have been estimated using methodologies
30 that are consistent with the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories
31 (IPCC/UNEP/OECD/IEA 1997). In addition, the United States references the additional guidance provided in the
32 IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (IPCC 2000),
33 the IPCC Good Practice Guidance for Land Use, Land-Use Change, and Forestry (IPCC 2003), and the 2006 IPCC
34 Guidelines for National Greenhouse Gas Inventories (IPCC 2006). To the extent possible, the present report relies
35 on published activity and emission factor data. Depending on the emission source category, activity data can
36 include fuel consumption or deliveries, vehicle-miles traveled, raw material processed, etc. Emission factors are
37 factors that relate quantities of emissions to an activity.
38 The IPCC methodologies provided in the Revised 1996 IPCC Guidelines represent baseline methodologies for a
39 variety of source categories, and many of these methodologies continue to be improved and refined as new research
40 and data become available. This report uses the IPCC methodologies when applicable, and supplements them with
41 other available methodologies and data where possible. Choices made regarding the methodologies and data
42 sources used are provided in conjunction with the discussion of each source category in the main body of the report.
43 Complete documentation is provided in the annexes on the detailed methodologies and data sources utilized in the
44 calculation of each source category.
45
46 [BEGIN BOX]
Introduction 1-11
-------
2 Box 1 -3: IPCC Reference Approach
3 The UNFCCC reporting guidelines require countries to complete a "top-down" reference approach for estimating
4 CO2 emissions from fossil fuel combustion in addition to their "bottom-up" sectoral methodology. This estimation
5 method uses alternative methodologies and different data sources than those contained in that section of the Energy
6 chapter. The reference approach estimates fossil fuel consumption by adjusting national aggregate fuel production
7 data for imports, exports, and stock changes rather than relying on end-user consumption surveys (see Annex 4 of
8 this report). The reference approach assumes that once carbon-based fuels are brought into a national economy, they
9 are either saved in some way (e.g., stored in products, kept in fuel stocks, or left unoxidized in ash) or combusted,
10 and therefore the carbon in them is oxidized and released into the atmosphere. Accounting for actual consumption
11 of fuels at the sectoral or sub-national level is not required.
12
13 [END BOX]
14 1.5. Key Categories
15
16 The IPCC's Good Practice Guidance (IPCC 2000) defines a key category as a "[source or sink category] that is
17 prioritized within the national inventory system because its estimate has a significant influence on a country's total
18 inventory of direct greenhouse gases in terms of the absolute level of emissions, the trend in emissions, or both."43
19 By definition, key categories include those sources that have the greatest contribution to the absolute level of
20 national emissions. In addition, when an entire time series of emission estimates is prepared, a thorough
21 investigation of key categories must also account for the influence of trends and uncertainties of individual source
22 and sink categories. This analysis culls out source and sink categories that diverge from the overall trend in national
23 emissions. Finally, a qualitative evaluation of key categories is performed to capture any categories that were not
24 identified in any of the quantitative analyses.
25 A Tier 1 approach, as defined in the IPCC's Good Practice Guidance (IPCC 2000), was implemented to identify the
26 key categories for the United States. This analysis was performed twice; one analysis included sources and sinks
27 from the Land Use, Land-Use Change, and Forestry (LULUCF) sector, the other analysis did not include the
28 LULUCF categories. Following the Tier 1 approach, a Tier 2 approach, as defined in the IPCC's Good Practice
29 Guidance (IPCC 2000), was then implemented to identify any additional key categories not already identified in the
30 Tier 1 assessment. This analysis, which includes each source categories' uncertainty assessments (or proxies) in its
31 calculations, was also performed twice to include or exclude LULUCF categories.
32 In addition to conducting Tier 1 and 2 level and trend assessments, a qualitative assessment of the source categories,
33 as described in the IPCC's Good Practice Guidance (IPCC 2000), was conducted to capture any key categories that
34 were not identified by either quantitative method. One additional key category, international bunker fuels, was
35 identified using this qualitative assessment. International bunker fuels are fuels consumed for aviation or marine
36 international transport activities, and emissions from these fuels are reported separately from totals in accordance
37 with IPCC guidelines. If these emissions were included in the totals, bunker fuels would qualify as a key category
38 according to the Tier 1 approach. The amount of uncertainty associated with estimation of emissions from
39 international bunker fuels also supports the qualification of this source category as key, because it would qualify
40 bunker fuels as a key category according to the Tier 2 approach. Table 1-4 presents the key categories for the United
41 States (including and excluding LULUCF categories) using emissions and uncertainty data in this report, and ranked
42 according to their sector and global warming potential-weighted emissions in 2009. The table also indicates the
43 criteria used in identifying these categories (i.e., level, trend, Tier 1, Tier 2, and/or qualitative assessments). Annex
44 1 of this report provides additional information regarding the key categories in the United States and the
45 methodologies used to identify them.
43 See Chapter 7 "Methodological Choice and Recalculation" in IPCC (2000).
1-12 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Table 1-4: Key Categories for the United States (1990-2009)
IPCC Source Categories
Gas
Tierl
Level Trend Level Trend
Without Without With With
LULUCF LULUCF LULUCF LULUCF
Level Trend Level Trend
Without Without With With
LULUCF LULUCF LULUCF LULUCF
Tier 2
Qual"
2009
Emissions
(Tg C02
Eg.)
Energy
CO2 Emissions from Stationary
Combustion - Coal
CO2 Emissions from Mobile
Combustion: Road
CO2 Emissions from Stationary
Combustion - Gas
CO2 Emissions from Stationary
Combustion - Oil
CO2 Emissions from Mobile
Combustion: Aviation
CO2 Emissions from Non-
Energy Use of Fuels
CO2 Emissions from Mobile
Combustion: Other
CO2 Emissions from Mobile
Combustion: Marine
CO2 Emissions from Natural
Gas Systems
Fugitive Emissions from
Natural Gas Systems
Fugitive Emissions from Coal
Mining
Fugitive Emissions from
Petroleum Systems
Non-CO2 Emissions from
Stationary Combustion
N2O Emissions from Mobile
Combustion: Road
Non-CO2 Emissions from
Stationary Combustion
International Bunker Fuelsb
C02
C02
CO2
CO2
CO2
CO2
C02
C02
C02
CH4
CH4
CH4
CH4
N20
N20
Several
1,841.0
l£552
1,164.6
487.1
149.7
122.1
77.2
36J
32.2
22L2
71.0
30.9
6.2
24.2
12.8
132.6
Industrial Processes
CO2 Emissions from Iron and
Steel Production &
Metallurgical Coke
Production
CO2 Emissions from Cement
Production
CO2 Emissions from Ammonia
Production and Urea
Consumption
CO2 Emissions from
Aluminum Production
N2O Emissions from Nitric
Acid Production
N2O Emissions from Adipic
Acid Production
Emissions from Substitutes for
Ozone Depleting Substances
SF6 Emissions from Electrical
Transmission and
Distribution
HFC-23 Emissions from
HCFC-22 Production
CO2
CO2
CO2
CO2
N2O
N2O
HiGWP
HiGWP
HiGWP
42.6
294
11.8
14.6
1.9
119.3
5.4
Introduction 1-13
-------
IPCC Source Categories
Gas
Tierl
Level Trend Level Trend
Without Without With With
LULUCF LULUCF LULUCF LULUCF
Level Trend
Without Without
LULUCF LULUCF
Tier 2
Level
With
LULUCF
Trend
With
LULUCF
Qual"
2009
Emissions
(Tg C02
Eg.)
PFC Emissions from
Aluminum Production
SF6 Emissions from
Magnesium Production and
Processing
HiGWP
HiGWP
1.6
1.1
Agriculture
CH4 Emissions from Enteric
Fermentation
CH4 Emissions from Manure
Management
CH4 Emissions from Rice
Cultivation
Direct N2O Emissions from
Agricultural Soil
Management
Indirect N2O Emissions from
Applied Nitrogen
CH4
CH4
CH4
N20
N2O
139.8
49.5
7.3
160.2
Waste
CH4 Emissions from Landfills
CH4 Emissions from
Wastewater Treatment
CH4
CH4
117.5
24.5
Land Use, Land Use Change,
and Forestry
CO2 Emissions from Changes
in Forest Carbon Stocks
CO2 Emissions from Urban
Trees
CO2 Emissions from Cropland
Remaining Cropland
CO2 Emissions from
Landfilled Yard Trimmings
and Food Scraps
CO2 Emissions from Grassland
Remaining Grassland
CH4 Emissions from Forest
Fires
N2O Emissions from Forest
Fires
CO2
CO2
CO2
CO2
CO2
CH4
N2O
(863.1)
(95.9)
(17.4)
(12.6)
(8.3)
7.8
6.4
Subtotal Without LULUCF
6,518.7
Total Emissions Without
LULUCF
6,614.7
Percent of Total Without
LULUCF
99%
Subtotal With LULUCF
5,535.5
Total Emissions With
LULUCF
5,624.6
Percent of Total With
LULUCF
98%
1
2
3
4
Qualitative criteria.
bEmissions from this source not included in totals.
Note: Parentheses indicate negative values (or sequestration).
5 1.6. Quality Assurance and Quality Control (QA/QC)
6 As part of efforts to achieve its stated goals for inventory quality, transparency, and credibility, the United States has
7 developed a quality assurance and quality control plan designed to check, document and improve the quality of its
1-14 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 inventory over time. QA/QC activities on the Inventory are undertaken within the framework of the U.S. QA/QC
2 plan, Quality Assurance/Quality Control and Uncertainty Management Plan for the U.S. Greenhouse Gas Inventory:
3 Procedures Manual for QA/QC and Uncertainty Analysis.
4 Key attributes of the QA/QC plan are summarized in Figure 1-1. These attributes include:
5 • specific detailed procedures and forms that serve to standardize the process of documenting and archiving
6 information, as well as to guide the implementation of QA/QC and the analysis of the uncertainty of the
7 inventory estimates;
8 • expert review as well as QC—for both the inventory estimates and the Inventory (which is the primary
9 vehicle for disseminating the results of the inventory development process). In addition, the plan provides
10 for public review of the Inventory;
11 • both Tier 1 (general) and Tier 2 (source-specific) quality controls and checks, as recommended by IPCC
12 Good Practice Guidance;
13 • consideration of secondary data quality and source-specific quality checks (Tier 2 QC) in parallel and
14 coordination with the uncertainty assessment; the development of protocols and templates provides for
15 more structured communication and integration with the suppliers of secondary information;
16 • record-keeping provisions to track which procedures have been followed, and the results of the QA/QC and
17 uncertainty analysis, and contains feedback mechanisms for corrective action based on the results of the
18 investigations, thereby providing for continual data quality improvement and guided research efforts;
19 • implementation of QA/QC procedures throughout the whole inventory development process—from initial
20 data collection, through preparation of the emission estimates, to publication of the Inventory;
21 • a schedule for multi-year implementation; and
22 • promotion of coordination and interaction within the EPA, across Federal agencies and departments, state
23 government programs, and research institutions and consulting firms involved in supplying data or
24 preparing estimates for the inventory. The QA/QC plan itself is intended to be revised and reflect new
25 information that becomes available as the program develops, methods are improved, or additional
26 supporting documents become necessary.
27 In addition, based on the national QA/QC plan for the Inventory, source-specific QA/QC plans have been developed
28 for a number of sources. These plans follow the procedures outlined in the national QA/QC plan, tailoring the
29 procedures to the specific text and spreadsheets of the individual sources. For each greenhouse gas emissions source
30 or sink included in this Inventory, a minimum of a Tier 1 QA/QC analysis has been undertaken. Where QA/QC
31 activities for a particular source go beyond the minimum Tier 1 level, further explanation is provided within the
32 respective source category text.
33 The quality control activities described in the U.S. QA/QC plan occur throughout the inventory process; QA/QC is
34 not separate from, but is an integral part of, preparing the inventory. Quality control—in the form of both good
35 practices (such as documentation procedures) and checks on whether good practices and procedures are being
36 followed—is applied at every stage of inventory development and document preparation. In addition, quality
37 assurance occurs at two stages—an expert review and a public review. While both phases can significantly
38 contribute to inventory quality, the public review phase is also essential for promoting the openness of the inventory
39 development process and the transparency of the inventory data and methods.
40 The QA/QC plan guides the process of ensuring inventory quality by describing data and methodology checks,
41 developing processes governing peer review and public comments, and developing guidance on conducting an
42 analysis of the uncertainty surrounding the emission estimates. The QA/QC procedures also include feedback loops
43 and provide for corrective actions that are designed to improve the inventory estimates over time.
44
45 Figure 1-1: U.S. QA/QC Plan Summary
46
Introduction 1-15
-------
i 1.7. Uncertainty Analysis of Emission Estimates
2 Uncertainty estimates are an essential element of a complete and transparent emissions inventory. Uncertainty
3 information is not intended to dispute the validity of the inventory estimates, but to help prioritize efforts to improve
4 the accuracy of future inventories and guide future decisions on methodological choice. While the U.S. Inventory
5 calculates its emission estimates with the highest possible accuracy, uncertainties are associated to a varying degree
6 with the development of emission estimates for any inventory. Some of the current estimates, such as those for CO2
7 emissions from energy-related activities, are considered to have minimal uncertainty associated with them. For
8 some other categories of emissions, however, a lack of data or an incomplete understanding of how emissions are
9 generated increases the uncertainty surrounding the estimates presented. Despite these uncertainties, the UNFCCC
10 reporting guidelines follow the recommendation in the 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997) and
11 require that countries provide single point estimates for each gas and emission or removal source category. Within
12 the discussion of each emission source, specific factors affecting the uncertainty associated with the estimates are
13 discussed.
14 Additional research in the following areas could help reduce uncertainty in the U.S. Inventory:
15 • Incorporating excluded emission sources. Quantitative estimates for some of the sources and sinks of
16 greenhouse gas emissions are not available at this time. In particular, emissions from some land-use
17 activities and industrial processes are not included in the inventory either because data are incomplete or
18 because methodologies do not exist for estimating emissions from these source categories. See Annex 5 of
19 this report for a discussion of the sources of greenhouse gas emissions and sinks excluded from this report.
20 • Improving the accuracy of emission factors. Further research is needed in some cases to improve the
21 accuracy of emission factors used to calculate emissions from a variety of sources. For example, the
22 accuracy of current emission factors applied to CH4 and N2O emissions from stationary and mobile
23 combustion is highly uncertain.
24 • Collecting detailed activity data. Although methodologies exist for estimating emissions for some sources,
25 problems arise in obtaining activity data at a level of detail in which aggregate emission factors can be
26 applied. For example, the ability to estimate emissions of SF6 from electrical transmission and distribution
27 is limited due to a lack of activity data regarding national SF6 consumption or average equipment leak
28 rates.
29 The overall uncertainty estimate for the U.S. greenhouse gas emissions inventory was developed using the IPCC
30 Tier 2 uncertainty estimation methodology. Estimates of quantitative uncertainty for the overall greenhouse gas
31 emissions inventory are shown below, in Table 1-5.
32 The IPCC provides good practice guidance on two approaches—Tier 1 and Tier 2—to estimating uncertainty for
33 individual source categories. Tier 2 uncertainty analysis, employing the Monte Carlo Stochastic Simulation
34 technique, was applied wherever data and resources permitted; further explanation is provided within the respective
35 source category text and in Annex 7. Consistent with the IPCC Good Practice Guidance (IPCC 2000), over a multi-
36 year timeframe, the United States expects to continue to improve the uncertainty estimates presented in this report.
37 Table 1-5. Estimated Overall Inventory Quantitative Uncertainty (Tg CO2 Eq. and Percent)
38
39
2009 Emission Uncertainty Range Relative to Emission Standard
Estimate" Estimate1" Mean0 Deviation0
Gas (TgCO2Eq.) (TgCO2Eq.) (%) (TgCO2Eq.)
Lower
Boundd
CO2
CH4e
N2Oe
PFC, HFC & SF6e
Total
Net Emissions (Sources
and Sinks)
5,507.7 5
686.5
299.5
142.8
6,636.6 6
5,621.5 5
,452.2
620.0
265.6
133.7
,598.3
,529.9
Notes:
a Emission estimates reported in this table correspond to emissions
Upper
Boundd
5,822.5
801.6
432.7
151.4
7,040.8
6,075.9
Lower
Bound
-1%
-10%
-11%
-6%
-1%
-2%
Upper
Bound
6%
17%
44%
6%
6%
8%
5,637.8
700.6
337.3
142.4
6,818.0
5,799.1
96.1
45.4
42.2
4.6
114.7
139.2
from only those source categories for which quantitative
1-16 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 uncertainty was performed this year. Thus the totals reported in this table exclude approximately 3.1 Tg CO2 Eq. of emissions for
2 which quantitative uncertainty was not assessed. Hence, these emission estimates do not match the final total U.S. greenhouse
3 gas emission estimates presented in this Inventory.
4 b The lower and upper bounds for emission estimates correspond to a 95 percent confidence interval, with the lower bound
5 corresponding to 2.5th percentile and the upper bound corresponding to 97.5th percentile.
6 ° Mean value indicates the arithmetic average of the simulated emission estimates; standard deviation indicates the extent of
7 deviation of the simulated values from the mean.
8 d The lower and upper bound emission estimates for the sub-source categories do not sum to total emissions because the low and
9 high estimates for total emissions were calculated separately through simulations.
10 e The overall uncertainty estimates did not take into account the uncertainty in the GWP values for CH4, N2O and high GWP
11 gases used in the inventory emission calculations for 2009.
12
13 Emissions calculated for the U.S. Inventory reflect current best estimates; in some cases, however, estimates are
14 based on approximate methodologies, assumptions, and incomplete data. As new information becomes available in
15 the future, the United States will continue to improve and revise its emission estimates. See Annex 7 of this report
16 for further details on the U. S. process for estimating uncertainty associated with the emission estimates and for a
17 more detailed discussion of the limitations of the current analysis and plans for improvement. Annex 7 also includes
18 details on the uncertainty analysis performed for selected source categories.
19 1.8. Completeness
20 This report, along with its accompanying CRF reporter, serves as a thorough assessment of the anthropogenic
21 sources and sinks of greenhouse gas emissions for the United States for the time series 1990 through 2009.
22 Although this report is intended to be comprehensive, certain sources have been identified yet excluded from the
23 estimates presented for various reasons. Generally speaking, sources not accounted for in this inventory are
24 excluded due to data limitations or a lack of thorough understanding of the emission process. The United States is
25 continually working to improve upon the understanding of such sources and seeking to find the data required to
26 estimate related emissions. As such improvements are implemented, new emission sources are quantified and
27 included in the Inventory. For a complete list of sources excluded, see Annex 5 of this report.
28 1.9. Organization of Report
29 In accordance with the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories
30 (IPCC/UNEP/OECD/IEA 1997), and the 2003 UNFCCC Guidelines on Reporting and Review (UNFCCC 2003),
31 this Inventory of U.S. Greenhouse Gas Emissions and Sinks is segregated into six sector-specific chapters, listed
32 below in Table 1-6. In addition, chapters on Trends in Greenhouse Gas Emissions and Other information to be
33 considered as part of the U.S. Inventory submission are included.
34 Table 1-6: IPCC Sector Descriptions
Chapter/IPCC Sector Activities Included
Energy Emissions of all greenhouse gases resulting from stationary and
mobile energy activities including fuel combustion and fugitive fuel
emissions.
Industrial Processes By-product or fugitive emissions of greenhouse gases from
industrial processes not directly related to energy activities such as
fossil fuel combustion.
Solvent and Other Product Use Emissions, of primarily NMVOCs, resulting from the use of
solvents and N2O from product uses.
Agriculture Anthropogenic emissions from agricultural activities except fuel
combustion, which is addressed under Energy.
Land Use, Land-Use Change, Emissions and removals of CO2, CH4, and N2O from forest
and Forestry management, other land-use activities, and land-use change.
Waste Emissions from waste management activities.
35 Source: (IPCC/UNEP/OECD/IEA 1997)
36 Within each chapter, emissions are identified by the anthropogenic activity that is the source or sink of the
37 greenhouse gas emissions being estimated (e.g., coal mining). Overall, the following organizational structure is
38 consistently applied throughout this report:
Introduction 1-17
-------
1 Chapter/IPCC Sector Overview of emission trends for each IPCC defined sector
2 SOUTCB CBtBQOry: Description of source pathway and emission trends.
3 Methodology: Description of analytical methods employed to produce emission estimates and identification of data
4 references, primarily for activity data and emission factors.
5 Uncertainty: A discussion and quantification of the uncertainty in emission estimates and a discussion of time-series
6 consistency.
7 QA/QC and Verification: A discussion on steps taken to QA/QC and verify the emission estimates, where beyond
8 the overall U.S. QA/QC plan, and any key findings.
9 Recalculations: A discussion of any data or methodological changes that necessitate a recalculation of previous
10 years' emission estimates, and the impact of the recalculation on the emission estimates, if applicable.
11 Planned Improvements: A discussion on any source-specific planned improvements, if applicable.
12 Special attention is given to CO2 from fossil fuel combustion relative to other sources because of its share of
13 emissions and its dominant influence on emission trends. For example, each energy consuming end-use sector (i.e.,
14 residential, commercial, industrial, and transportation), as well as the electricity generation sector, is described
15 individually. Additional information for certain source categories and other topics is also provided in several
16 Annexes listed in Table 1-7.
17 Table 1-7: List of Annexes
ANNEX 1 Key Category Analysis
ANNEX 2 Methodology and Data for Estimating CO2 Emissions from Fossil Fuel Combustion
2.1. Methodology for Estimating Emissions of CO2 from Fossil Fuel Combustion
2.2. Methodology for Estimating the Carbon Content of Fossil Fuels
2.3. Methodology for Estimating Carbon Emitted from Non-Energy Uses of Fossil Fuels
ANNEX 3 Methodological Descriptions for Additional Source or Sink Categories
3.1. Methodology for Estimating Emissions of CH4, N2O, and Indirect Greenhouse Gases from
Stationary Combustion
3.2. Methodology for Estimating Emissions of CH4, N2O, and Indirect Greenhouse Gases from Mobile
Combustion and Methodology for and Supplemental Information on Transportation-Related
Greenhouse Gas Emissions
3.3. Methodology for Estimating CH4 Emissions from Coal Mining
3.4. Methodology for Estimating CH4 Emissions from Natural Gas Systems
3.5. Methodology for Estimating CH4 and CO2 Emissions from Petroleum Systems
3.6. Methodology for Estimating CO2 and N2O Emissions from Incineration of Waste
3.7. Methodology for Estimating Emissions from International Bunker Fuels used by the U.S. Military
3.8. Methodology for Estimating HFC and PFC Emissions from Substitution of Ozone Depleting
Substances
3.9. Methodology for Estimating CH4 Emissions from Enteric Fermentation
3.10. Methodology for Estimating CH4 and N2O Emissions from Manure Management
3.11. Methodology for Estimating N2O Emissions from Agricultural Soil Management
3.12. Methodology for Estimating Net Carbon Stock Changes in Forest Lands Remaining Forest Lands
3.13. Methodology for Estimating Net Changes in Carbon Stocks in Mineral and Organic Soils on
Croplands and Grasslands
3.14. Methodology for Estimating CH4 Emissions from Landfills
ANNEX 4 IPCC Reference Approach for Estimating CO2 Emissions from Fossil Fuel Combustion
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
1-18 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
6.7. Chemical Formulas
ANNEX 7 Uncertainty
7.1. Overview
7.2. Methodology and Results
7.3. Planned Improvements
7.4. Additional Information on Uncertainty Analyses by Source
Introduction 1-19
-------
Figure 1: U.S. QA/QC Plan Summary
I-
rc
I
ns
c
<
•Obtain data in electronic
format (if possible)
•Review spreadsheet
construction
•Avoid hardwiring
*Use data validation
• Protect cells
•Develop automatic
checkers for:
• Outliers, negative values, or
missing data
•Variable types match values
•Time series consistency
•Maintain trackingtab for
status of gat he ring efforts
Check input data for
transcription errors
•Inspect automatic checkers
•Identifyspreadsheet
modifications that could
provide additional QA/QC
checks
Data Gathering
•Contact reports for non-
electronic comm uni cati ons
•Provide cell references for
primary data elements
•Obtain copies of all data
sources
•Li st and I ocati on of any
working/external
spreadsheets
•Document assumptions
•Clearly label parameters,
Sj and conversion factors
•Review spreadsheet
integrity
•Equations
•Units
•In put and output
•Develop automated
checkers for;
•Input ranges
•Calculations
•Emission aggregation
•Check citations in
spreadsheet and text for
accuracy and style
•Check reference dod
-------
i 2. Trends in Greenhouse Gas Emissions
2 2.1. Recent Trends in U.S. Greenhouse Gas Emissions and Sinks
3 In 2009, total U.S. greenhouse gas emissions were 6,639.7 teragrams of carbon dioxide equivalents (Tg CO2 Eq.);
4 net emissions were 5,624.6 Tg CO2 Eq. reflecting the influence of sinks (net CO2 flux from Land Use, Land Use
5 Change, and Forestry).44 While total U.S. emissions have increased by 7.4 percent from 1990 to 2009, emissions
6 decreased from 2008 to 2009 by 6.0 percent (422.2 Tg CO2 Eq.). The following factors were primary contributors
7 to this decrease: (1) a decrease in economic output resulting in a decrease in energy consumption across all sectors;
8 and (2) a decrease in the carbon intensity of fuels used to generate electricity due to fuel switching as the price of
9 coal increased, and the price of natural gas decreased significantly.
10
11 Figure 2-1: U.S. Greenhouse Gas Emissions by Gas
12
13 Figure 2-2: Annual Percent Change in U.S. Greenhouse Gas Emissions
14
15 Figure 2-3: Cumulative Change in Annual U.S. Greenhouse Gas Emissions Relative to 1990
16
17 As the largest contributor to U.S. greenhouse gas emissions, carbon dioxide (CO2) from fossil fuel combustion has
18 accounted for approximately 78 percent of global warming potential (GWP) weighted emissions since 1990, from
19 77 percent of total GWP-weighted emissions in 1990 to 78 percent in 2009. Emissions from this source category
20 grew by 9.9 percent (470.7 Tg CO2 Eq.) from 1990 to 2009 and were responsible for most of the increase in national
21 emissions during this period. From 2008 to 2009, these emissions decreased by 6.4 percent (356.7 Tg CO2 Eq.).
22 Historically, changes in emissions from fossil fuel combustion have been the dominant factor affecting U.S.
23 emission trends.
24 Changes in CO2 emissions from fossil fuel combustion are influenced by many long-term and short-term factors,
25 including population and economic growth, energy price fluctuations, technological changes, and seasonal
26 temperatures. On an annual basis, the overall consumption of fossil fuels in the United States fluctuates primarily in
27 response to changes in general economic conditions, energy prices, weather, and the availability of non-fossil
28 alternatives. For example, in a year with increased consumption of goods and services, low fuel prices, severe
29 summer and winter weather conditions, nuclear plant closures, and lower precipitation feeding hydroelectric dams,
30 there would likely be proportionally greater fossil fuel consumption than in a year with poor economic performance,
31 high fuel prices, mild temperatures, and increased output from nuclear and hydroelectric plants.
32 In the longer-term, energy consumption patterns respond to changes that affect the scale of consumption (e.g.,
33 population, number of cars, and size of houses), the efficiency with which energy is used in equipment (e.g., cars,
34 power plants, steel mills, and light bulbs) and consumer behavior (e.g., walking, bicycling, or telecommuting to
35 work instead of driving).
36 Energy-related CO2 emissions also depend on the type of fuel or energy consumed and its carbon (C) intensity.
37 Producing a unit of heat or electricity using natural gas instead of coal, for example, can reduce the CO2 emissions
3 8 because of the lower C content of natural gas.
39 A brief discussion of the year to year variability in fuel combustion emissions is provided below, beginning with
40 2005.
41 From 2005 to 2006, emissions from fuel combustion decreased for the first time since 2000 to 2001. This decrease
42 occurred across all sectors, with the exception of the industrial sector and the U.S. Territories sector, due to a
44 Estimates are presented in units of teragrams of carbon dioxide equivalent (Tg CO2 Eq.), which weight each gas by its global
warming potential, or GWP, value. See section on global warming potentials in the Executive Summary.
Trends in Greenhouse Gas Emissions 2-1
-------
1 number of factors. The decrease in emissions from electricity generation is a result of a smaller share of electricity
2 generated by coal and a greater share generated by natural gas. Coal and natural gas consumption for electricity
3 generation decreased by 1.5 percent and increased by 1.6 percent in 2006, respectively, and nuclear power
4 generation decreased by less than 1 percent. The decrease in consumption of transportation fuels is primarily a
5 result of the restraint on fuel consumption caused by rising fuel prices, which directly resulted in a decrease of
6 petroleum consumption within this sector of about 1.3 percent in 2006. The significant decrease in emissions from
7 the residential sector is primarily a result of decreased electricity consumption due to increases in the price of
8 electricity, and warmer winter weather conditions compared to 2005. A moderate increase in industrial sector
9 emissions is the result of growth in industrial output and growth in the U.S. economy. Renewable fuels used to
10 generate electricity increased in 2006, with the greatest growth occurring in generation from wind by 48 percent.
11 After experiencing a decrease from 2005 to 2006, emissions from fuel combustion grew from 2006 to 2007 at a rate
12 somewhat higher than the average growth rate since 1990. There were a number of factors contributing to this
13 increase. More energy-intensive weather conditions in both the winter and summer resulted in an increase in
14 consumption of heating fuels, as well as an increase in the demand for electricity. This demand for electricity was
15 met with an increase in coal consumption of 1.7 percent, and with an increase in natural gas consumption of 9.9
16 percent. This increase in fossil fuel consumption, combined with a 14.7 percent decrease in hydropower generation
17 from 2006 to 2007, resulted in an increase in emissions in 2007. The increase in emissions from the residential and
18 commercial sectors is a result of increased electricity consumption due to warmer summer conditions and cooler
19 winter conditions compared to 2006. In addition to these more energy-intensive weather conditions, electricity
20 prices remained relatively stable compared to 2006, and natural gas prices decreased slightly. Emissions from the
21 industrial sector decreased compared to 2006 as a result of a decrease in industrial production and fossil fuels used
22 for electricity generation. Despite an overall decrease in electricity generation from renewable energy in 2007
23 driven by decreases in hydropower generation, wind and solar generation increased significantly.
24 Emissions from fossil fuel combustion decreased from 2007 to 2008. Several factors contributed to this decrease in
25 emissions. An increase in energy prices coupled with the economic downturn led to a decrease in energy demand
26 and a resulting decrease in emissions from 2007 to 2008. In 2008, the price of coal, natural gas, and petroleum used
27 to generate electricity, as well as the price of fuels used for transportation, increased significantly. As a result of this
28 price increase, coal, natural gas, and petroleum consumption used for electricity generation decreased by 1.4
29 percent, 2.5 percent, and 28.8 percent, respectively. The increase in the cost of fuels to generate electricity translated
30 into an increase in the price of electricity, leading to a decrease in electricity consumption across all sectors except
31 the commercial sector. The increase in transportation fuel prices led to a decrease in vehicle miles traveled (VMT)
32 and a decrease of 5.5 percent in transportation fossil fuel combustion emissions from 2007 to 2008. Cooler weather
33 conditions in the summer led to a decrease in cooling degree days by 8.7 percent and a decrease in electricity
34 demand compared to 2007, whereas cooler winter conditions led to a 5.6 percent increase in heating degree days
35 compared to 2007 and a resulting increase in demand for heating fuels. The increased emissions from winter heating
36 energy demand was offset by a decrease in emissions from summer cooling related electricity demand. Lastly,
37 renewable energy45 consumption for electricity generation increased by 9.6 percent from 2007 to 2008, driven by a
38 significant increase in solar and wind energy consumption (of 19.4 percent and 60.2 percent, respectively). This
39 increase in renewable energy generation contributed to a decrease in the carbon intensity of electricity generation.
40 From 2008 to 2009, fossil fuel combustion emissions experienced a decrease of 6.4 percent, the greatest decrease of
41 any year over the course of the twenty-year period. Various factors contributed to this decrease in emissions. The
42 continued economic downturn resulted in a 2.6 percent decrease in GDP, and a decrease in energy consumption
43 across all sectors. The economic downturn also impacted total industrial production and manufacturing output,
44 which decreased by 9.3 and 10.9 percent, respectively. In 2009, the price of coal used to generate electricity
45 increased, while the price of natural gas used to generate electricity decreased significantly. As a result, natural gas
46 was used for a greater share of electricity generation in 2009 than 2008, and coal was used for a smaller share. The
47 fuel switching from coal to natural gas and additional electricity generation from other energy sources in 2009,
48 which included a 6.8 percent increase in hydropower generation from the previous year, resulted in a decrease in
49 carbon intensity, and in turn, a decrease in emissions from electricity generation. From 2008 to 2009, industrial
50 sector emissions decreased significantly as a result of a decrease in output from energy-intensive industries of 31.6
45 Renewable energy, as defined in EIA's energy statistics, includes the following energy sources: hydroelectric power,
geothermal energy, biofuels, solar energy, and wind energy.
2-2 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 percent in nonmetallic mineral and 16.6 percent in primary metal industries. The residential and commercial sectors
2 only experienced minor decreases in emissions as summer and winter weather conditions were less energy-intensive
3 from 2008 to 2009, and the price of electricity only increased slightly. Heating degree days decreased slightly and
4 cooling degree days decreased by 3.8 percent from 2008 to 2009.
5 Overall, from 1990 to 2009, total emissions of CO2 and CH4 increased by 408.0 Tg CO2 Eq. (8.0 percent) and 11.7
6 Tg CO2 Eq. (1.7 percent), respectively, while N2O emissions decreased by 15.7 Tg CO2 Eq. (about 5.0 percent).
7 During the same period, aggregate weighted emissions of HFCs, PFCs, and SF6 rose by 53.4 Tg CO2 Eq. (58.1
8 percent). Despite being emitted in smaller quantities relative to the other principal greenhouse gases, emissions of
9 HFCs, PFCs, and SF6 are significant because many of them have extremely high GWPs and, in the cases of PFCs
10 and SF6, long atmospheric lifetimes. Conversely, U.S. greenhouse gas emissions were partly offset by C
11 sequestration in managed forests, trees in urban areas, agricultural soils, and landfilled yard trimmings. These were
12 estimated to offset 15.3 percent of total emissions in 2009.
13 Table 2-1 summarizes emissions and sinks from all U.S. anthropogenic sources in weighted units of Tg CO2 Eq.,
14 while unweighted gas emissions and sinks in gigagrams (Gg) are provided in Table 2-2.
15 Table 2-1: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Tg CO2 Eq.)
Gas/Source
C02
Fossil Fuel Combustion
Electricity Generation
Transportation
Industrial
Residential
Commercial
U.S. Territories
Non-Energy Use of Fuels
Iron and Steel Production &
Metallurgical Coke
Production
Natural Gas Systems
Cement Production
Incineration of Waste
Ammonia Production and
Urea Consumption
Lime Production
Cropland Remaining Cropland
Limestone and Dolomite Use
Soda Ash Production and
Consumption
Aluminum Production
Petrochemical Production
Carbon Dioxide Consumption
Ferroalloy Production
Titanium Dioxide Production
Wetlands Remaining Wetlands
Phosphoric Acid Production
Zinc Production
Lead Production
Petroleum Systems
Silicon Carbide Production
and Consumption
Land Use, Land-Use Change,
and Forestry (Sink)"
Biomass — Wootf
International Bunker Fuels0
1990
5,100.2
4,741.2
1,820.8
1,485.9
849.3
338.3
219.0
27.9
116.2
99.5
37.6
33.3
8.0
16.8
11.5
7.1
5.1
4.1
6.8
3.3
1.4
2.2
1.2
1.0
1.5
0.7
0.5
0.6
0.4
(861.5)
215.2
111.8
2000
5,976.2
5,597.7
2,296.9
1,809.5
853.9
370.7
230.8
35.9
142.5
85.9
29.9
41.2
11.1
16.4
14.1
7.5
5.1
4.2
6.1
4.5
.4
.9
.8
.2
.4
.0
0.6
0.5
0.2
(576.6)
218.1
98.5
2005
6,114.7
5,755.6
2,402.1
1,896.6
825.5
357.9
223.5
50.0
141.3
65.9
29.9
45.9
12.5
12.8
14.4
7.9
6.8
4.2
4.1
4.2
.3
.4
.8
.1
.4
.1
0.6
0.5
0.2
(1,056.5)
206.9
110.5
2006
6,022.6
5,657.0
2,346.4
1,878.1
852.1
321.5
208.6
50.3
142.4
68.8
30.8
46.6
12.5
12.3
15.1
7.9
8.0
4.2
3.8
3.8
1.7
1.5
1.8
0.9
1.2
1.1
0.6
0.5
0.2
(1,064.3)
203.8
129.1
2007
6,121.5
5,760.6
2,412.8
1,894.0
845.9
342.4
219.4
46.1
134.1
71.0
31.1
45.2
12.7
14.0
14.6
8.2
7.7
4.1
4.3
3.9
.9
.6
.9
.0
.2
.1
0.6
0.5
0.2
(1,060.9)
203.3
127.1
2008
5,922.5
5,568.7
2,360.9
1,789.9
805.6
348.2
224.2
39.8
138.7
66.0
32.8
41.1
12.2
11.9
14.3
8.7
6.3
4.1
4.5
3.4
.8
.6
.8
.0
.2
.2
0.6
0.5
0.2
(1,040.5)
198.4
135.2
2009
5,508.1
5,212.0
2,154.0
1,718.9
738.4
340.2
218.8
41.7
122.1
42.6
32.2
29.4
12.3
11.8
11.2
7.8
7.6
4.3
3.0
2.7
1.8
1.6
1.5
1.1
1.0
1.0
0.5
0.5
0.1
(1,015.1)
183.8
131.3
Trends in Greenhouse Gas Emissions
2-3
-------
Biomass — Ethanol
CH4
Natural Gas Systems
Enteric Fermentation
Landfills
Coal Mining
Manure Management
Petroleum Systems
Wastewater Treatment
Forest Land Remaining Forest
Land
Rice Cultivation
Stationary Combustion
Abandoned Underground Coal
Mines
Mobile Combustion
Composting
Petrochemical Production
Iron and Steel Production &
Metallurgical Coke
Production
Field Burning of Agriculture
Residues
Ferroalloy Production
Silicon Carbide Production
and Consumption
Incineration of Waste
International Bunker Fuels0
N2O
Agricultural Soil Management
Mobile Combustion
Manure Management
Nitric Acid Production
Stationary Combustion
Forest Land Remaining Forest
Land
Wastewater Treatment
N2O from Product Uses
Adipic Acid Production
Composting
Settlements Remaining
Settlements
Incineration of Waste
Field Burning of Agricultural
Residues
Wetlands Remaining Wetlands
International Bunker Fuels0
HFCs
Substitution of Ozone
Depleting Substancesd
HCFC-22 Production
Semiconductor Manufacture
PFCs
Semiconductor Manufacture
Aluminum Production
SF6
4.1
674.9
189.8
132.1
147.4
84.1
31.7
35.4
23.5
3.2
7.1
7.4
6.0
4.7
0.3
0.9
1.0
0.3
+
+
+
0.2
315.2
197.8
43.9
14.5
17.7
12.8
2.7
3.7
4.4
15.8
0.4
1.0
0.5
0.1
+
1.1
36.9
0.3
36.4
0.2
20.8
2.2
18.5
34.4
9.0
659.9
209.3
136.5
111.7
60.4
42.4
31.5
25.2
14.3
7.5
6.6
7.4
3.4
1.3
1.2
0.9
0.3
+
+
+
0.1
341.0
206.8
53.2
17.1
19.4
14.6
12.1
4.5
4.9
5.5
1.4
1.1
0.4
0.1
+
0.9
103.2
74.3
28.6
0.3
13.5
4.9
8.6
20.1
22.1
631.4
190.4
136.5
112.5
56.9
46.6
29.4
24.3
9.8
6.8
6.6
5.5
2.5
1.6
1.1
0.7
0.2
+
+
+
0.1
322.9
211.3
36.9
17.3
16.5
14.7
8.4
4.8
4.4
5.0
1.7
1.5
0.4
0.1
+
1.0
120.2
104.2
15.8
0.2
6.2
3.2
3.0
19.0
29.9
672.1
217.7
138.8
111.7
58.2
46.7
29.4
24.5
21.6
5.9
6.2
5.5
2.3
1.6
1.0
0.7
0.2
+
+
+
0.2
326.4
208.9
33.6
18.0
16.2
14.4
18.0
4.8
4.4
4.3
1.8
1.5
0.4
0.1
+
1.2
123.4
109.3
13.8
0.3
6.0
3.5
2.5
17.9
37.5
664.6
205.2
141.0
111.3
57.9
50.7
30.0
24.4
20.0
6.2
6.5
5.6
2.2
1.7
1.0
0.7
0.2
+
+
+
0.2
325.1
209.4
30.3
18.1
19.2
14.6
16.7
4.9
4.4
3.7
1.8
1.6
0.4
0.1
+
1.2
129.5
112.2
17.0
0.3
7.5
3.7
3.8
16.7
52. 8
676.7
211.8
140.6
115.9
67.1
49.4
30.2
24.5
11.9
7.2
6.5
5.9
2.0
1.7
0.9
0.6
0.3
+
+
+
0.2
310.8
210.7
26.1
17.9
16.4
14.2
10.1
5.0
4.4
2.0
1.9
1.5
0.4
0.1
+
1.2
129.1
115.2
13.6
0.3
6.6
4.0
2.7
16.1
59.0
686.5
221.2
139.8
117.5
71.0
49.5
30.9
24.5
7.8
7.3
6.2
5.5
2.2
1.7
0.8
0.4
0.2
+
+
+
0.2
299.5
204.6
27.8
17.9
14.6
12.8
6.7
5.0
4.4
1.9
1.8
1.5
0.4
0.1
+
1.2
125.0
119.3
5.4
0.3
5.6
4.0
1.6
14.8
2-4 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Electrical Transmission and
Distribution
Magnesium Production and
Processing
Semiconductor Manufacture
Total
Net Emissions (Sources and
Sinks)
28.4
5.4
0.5
6,182.2
5,320.7
16.0
3.0
1.1
7,113.9
6,537.3
15.1
2.9
1.0
7,214.5
6,158.1
14.1
2.9
1.0
7,168.4
6,104.1
13.2
2.6
0.8
7,264.8
6,203.9
13.3
1.9
0.9
7,061.9
6,021.5
12.8
1.1
1.0
6,639.7
5,624.6
1 + Does not exceed 0.05 Tg CO2 Eq.
2 a The net CO2 flux total includes both emissions and sequestration, and constitutes a sink in the United States. Sinks are only
3 included in net emissions total. Parentheses indicate negative values or sequestration.
4 b Emissions from Wood Biomass and Ethanol Consumption are not included specifically in summing energy sector totals. Net
5 carbon fluxes from changes in biogenic carbon reservoirs are accounted for in the estimates for Land Use, Land-Use Change, and
6 Forestry.
7 ° Emissions from International Bunker Fuels are not included in totals.
8 dSmall amounts of PFC emissions also result from this source.
9 Note: Totals may not sum due to independent rounding.
10
11 Table 2-2: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks (Gg)
Gas/Source
C02
Fossil Fuel Combustion
Electricity Generation
Transportation
Industrial
Residential
Commercial
U.S. Territories
Non-Energy Use of Fuels
Iron and Steel Production
& Metallurgical Coke
Production
Natural Gas Systems
Cement Production
Incineration of Waste
Ammonia Production and
Urea Consumption
Lime Production
Cropland Remaining
Cropland
Limestone and Dolomite
Use
Soda Ash Production and
Consumption
Aluminum Production
Petrochemical Production
Carbon Dioxide
Consumption
Ferroalloy Production
Titanium Dioxide
Production
Wetlands Remaining
Wetlands
Phosphoric Acid
Production
Zinc Production
1990
5,100,159
4,741,246
1,820,818
1,485,937
849,299
338,347
218,964
27,882
116,245
99,528
37,574
33,278
7,989
16,831
11,533
7,084
5,127
4,141
6,831
3,311
1,416
2,152
1,195
1,033
1,529
667
2000
5,976,173
5,597,691
2,296,894
1,809,514
853,937
370,666
230,828
35,853
142,487
85,935
29,877
41,190
11,112
16,402
14,088
7,541
5,056
4,181
6,086
4,479
1,421
1,893
1,752
1,227
1,382
997
2005
6,114,730
5,755,608
2,402,142
1,896,606
825,477
357,903
223,512
49,968
141,250
65,925
29,902
45,910
12,450
12,849
14,379
7,854
6,768
4,228
4,142
4,181
1,321
1,392
1,755
1,079
1,386
1,088
2006
6,022,587
5,656,988
2,346,406
1,878,125
852,078
321,513
208,582
50,284
142,430
68,772
30,755
46,562
12,531
12,300
15,100
7,875
8,035
4,162
3,801
3,837
1,709
1,505
1,836
879
1,167
1,088
2007
6,121,452
5,760,628
2,412,827
1,893,994
845,931
342,397
219,356
46,123
134,102
71,045
31,050
45,229
12,700
14,038
14,595
8,202
7,702
4,140
4,251
3,931
1,867
1,552
1,930
1,012
1,166
1,081
2008
5,922,521
5,568,683
2,360,919
1,789,918
805,613
348,221
224,167
39,845
138,656
66,015
32,828
41,147
12,169
11,949
14,330
8,654
6,276
4,111
4,477
3,449
1,780
1,599
1,809
992
1,187
1,230
2009
5,508,132
5,211,969
2,154,025
1,718,878
738,374
340,225
218,816
41,652
122,062
42,576
32,171
29,417
12,300
11,797
11,223
7,832
7,649
4,265
3,009
2,735
1,763
1,599
1,541
1,090
1,035
966
Trends in Greenhouse Gas Emissions 2-5
-------
Lead Production
Petroleum Systems
Silicon Carbide
Production and
Consumption
Land Use, Land-Use
Change, and Forestry
(Sink)"
Biomass - Wootf
International Bunker
Fuels0
Biomass - Ethanof
CH4
Natural Gas Systems
Enteric Fermentation
Landfills
Coal Mining
Manure Management
Petroleum Systems
Wastewater Treatment
Forest Land Remaining
Forest Land
Rice Cultivation
Stationary Combustion
Abandoned Underground
Coal Mines
Mobile Combustion
Composting
Petrochemical Production
Iron and Steel Production
& Metallurgical Coke
Production
Field Burning of
Agricultural Residues
Ferroalloy Production
Silicon Carbide
Production and
Consumption
Incineration of Waste
International Bunker
Fuels0
N2O
Agricultural Soil
Management
Mobile Combustion
Manure Management
Nitric Acid Production
Stationary Combustion
Forest Land Remaining
Forest Land
Wastewater Treatment
N2O from Product Uses
Adipic Acid Production
Composting
Settlements Remaining
Settlements
516
555
375
(861,535)
215,186
111,828
4,074
32,136
9,038
6,290
7,018
4,003
1,511
1,685
1,118
152
339
354
288
223
15
41
46
13
1
1
+
8
1,017
638
142
47
57
41
9
12
14
51
1
3
594
534
248
(576,588)
218,088
98,482
9,009
31,423
9,968
6,502
5,317
2,877
2,019
1,501
1,199
682
357
316
350
160
60
59
44
12
1
1
+
6
1,100
667
172
55
63
47
39
14
16
18
4
4
553
490
219
(1,056,459)
206,865
110,505
22,115
30,069
9,069
6,500
5,358
2,710
2,217
1,398
1,159
467
326
313
264
119
75
51
34
9
+
+
+
7
1,042
682
119
56
53
47
27
15
14
16
6
5
560
488
207
(1,064,330)
203,846
129,104
29,867
32,004
10,364
6,611
5,321
2,774
2,226
1,398
1,167
1,027
282
293
261
112
75
48
35
11
+
+
+
8
1,053
674
108
58
52
47
58
16
14
14
6
5
562
474
196
(1,060,882)
203,316
127,054
37,520
31,647
9,771
6,715
5,299
2,756
2,416
1,427
1,163
953
295
308
267
105
79
48
33
11
+
+
+
7
1,049
675
98
58
62
47
54
16
14
12
6
5
551
453
175
(1,040,461)
198,361
135,226
52,765
32,225
10,087
6,696
5,520
3,196
2,353
1,439
1,168
569
343
310
279
97
80
43
31
13
+
+
+
8
1,002
680
84
58
53
46
33
16
14
7
6
5
525
463
145
(1,015,074)
183,777
131,294
58,989
32,692
10,535
6,655
5,593
3,382
2,356
1,473
1,167
372
349
293
262
106
79
40
17
12
+
+
+
7
966
660
90
58
47
41
22
16
14
6
6
5
2-6 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1
2
o
5
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Incineration of Waste
Field Burning of
Agricultural Residues
Wetlands Remaining
Wetlands
International Bunker
Fuels0
HFCs
Substitution of Ozone
Depleting Substancesd
HCFC-22 Production
Semiconductor
Manufacture
PFCs
Semiconductor
Manufacture
Aluminum Production
SF6
Electrical Transmission
and Distribution
Magnesium Production
and Processing
Semiconductor
Manufacture
3
M
M
3
M
M
M
1
3
M
M
2
M
M
M
1
3
M
M
1
M
M
M
1
4
M
M
1
M
M
M
1
4
M
M
1
M
M
M
1
4
M
M
1
M
M
M
1
4
M
M
M
M
M
1
+ Does not exceed 0.5 Gg.
M Mixture of multiple gases
a The net CO2 flux total includes both emissions and sequestration, and constitutes a sink in the United States. Sinks are only
included in net emissions total. Parentheses indicate negative values or sequestration.
b Emissions from Wood Biomass and Ethanol Consumption are not included specifically in summing energy sector totals. Net
carbon fluxes from changes in biogenic carbon reservoirs are accounted for in the estimates for Land Use, Land-Use Change, and
Forestry
0 Emissions from International Bunker Fuels are not included in totals.
d Small amounts of PFC emissions also result from this source.
Note: Totals may not sum due to independent rounding.
Emissions of all gases can be summed from each source category from Intergovernmental Panel on Climate Change
(IPCC) guidance. Over the twenty-year period of 1990 to 2009, total emissions in the Energy and Agriculture
sectors grew by 468.7 Tg CO2 Eq. (8.9 percent) and 35.7 Tg CO2 Eq. (9.3 percent), respectively. Emissions
decreased in the Industrial Processes, Waste, and Solvent and Other Product Use sectors by 32.3 Tg CO2 Eq. (10.2
percent), 24.7 Tg CO2 Eq. (14.1 percent) and less than 0.1 Tg CO2 Eq. (less than 0.4 percent), respectively. Over
the same period, estimates of net C sequestration in the Land Use, Land-Use Change, and Forestry sector increased
by 143.5 Tg CO2 Eq. (17.0 percent).
Figure 2-4: U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector
22 Table 2-3: Recent Trends in U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector (Tg CO2 Eq.)
Chapter/IPCC Sector
1990
2000
2005 2006
2007
2008
2009
Energy
Industrial Processes
Solvent and Other Product Use
Agriculture
Land Use, Land-Use Change,
and Forestry (Emissions)
Waste
5,288.2
315.8
4.4
383.6
15.0
175.2
6,168.4
349.6
4.9
410.6
36.3
143.9
6,283.1
334.8
4.4
418.8
28.6
144.9
6,210.9
340.2
4.4
418.8
49.8
144.4
6,291.5
351.6
4.4
425.8
47.5
144.1
6,117.1
332.0
4.4
426.3
33.2
149.0
5,757.0
283.5
4.4
419.3
25.0
150.5
Trends in Greenhouse Gas Emissions
2-7
-------
1
2
o
5
4
5
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Total Emissions
Net CO2 Flux from Land Use,
Land-Use Change, and
Forestry (Sinks)*
Net Emissions (Sources and
Sinks)
6,182.2
(861.5)
5,320.7
7,113.9
(576.6)
6,537.3
7,214.5 7,168.4 7,264.8 7,061.9 6,639.7
(1,056.5) (1,064.3) (1,060.9) (1,040.5) (1,015.1)
6,158.1 6,104.1 6,203.9 6,021.5 5,624.6
The net CO2 flux total includes both emissions and sequestration, and constitutes a sink in the United States. Sinks are only
included in net emissions total. Please refer to Table 2-9 for a breakout by source.
Note: Totals may not sum due to independent rounding.
Note: Parentheses indicate negative values or sequestration.
6 Energy
Energy-related activities, primarily fossil fuel combustion, accounted for the vast majority of U.S. CO2 emissions for
the period of 1990 through 2009. In 2009, approximately 83 percent of the energy consumed in the United States
(on a Btu basis) was produced through the combustion of fossil fuels. The remaining 17 percent came from other
energy sources such as hydropower, biomass, nuclear, wind, and solar energy (see Figure 2-5 and Figure 2-6). A
discussion of specific trends related to CO2 as well as other greenhouse gas emissions from energy consumption is
presented in the Energy chapter. Energy-related activities are also responsible for CH4 and N2O emissions (49
percent and 14 percent of total U.S. emissions of each gas, respectively). Table 2-4 presents greenhouse gas
emissions from the Energy chapter, by source and gas.
Figure 2-5: 2009 Energy Chapter Greenhouse Gas Sources
Figure 2-6: 2009 U.S. Fossil Carbon Flows (Tg CO2 Eq.)
Table 2-4: Emissions from Energy (Tg CO2 Eq.)
Gas/Source
C02
Fossil Fuel Combustion
Electricity Generation
Transportation
Industrial
Residential
Commercial
U.S. Territories
Non-Energy Use of Fuels
Natural Gas Systems
Incineration of Waste
Petroleum Systems
Biomass - Wood"
International Bunker Fuelsb
Biomass - Ethanol"
CH4
Natural Gas Systems
Coal Mining
Petroleum Systems
Stationary Combustion
Abandoned Underground
Coal Mines
Mobile Combustion
Incineration of Waste
1990
4,903.6
4,741.2
1,820.8
1,485.9
849.3
338.3
219.0
27.9
116.2
37.6
8.0
0.6
215.2
111.8
4.1
327.4
189.8
84.1
35.4
7.4
6.0
4.7
+
2000
5,781.7
5,597.7
2,296.9
1,809.5
853.9
370.7
230.8
35.9
142.5
29.9
11.1
0.5
218.1
98.5
9.0
318.6
209.3
60.4
31.5
6.6
7.4
3.4
+
2005
5,939.7
5,755.6
2,402.1
1,896.6
825.5
357.9
223.5
50.0
141.3
29.9
12.5
0.5
206. 9
110.5
22.1
291.3
190.4
56.9
29.4
6.6
5.5
2.5
+
2006
5,843.2
5,657.0
2,346.4
1,878.1
852.1
321.5
208.6
50.3
142.4
30.8
12.5
0.5
203.8
129.1
29.9
319.2
217.7
58.2
29.4
6.2
5.5
2.3
+
2007
5,939.0
5,760.6
2,412.8
1,894.0
845.9
342.4
219.4
46.1
134.1
31.1
12.7
0.5
203.3
127.1
37.5
307.3
205.2
57.9
30.0
6.5
5.6
2.2
+
2008
5,752.8
5,568.7
2,360.9
1,789.9
805.6
348.2
224.2
39.8
138.7
32.8
12.2
0.5
198.4
135.2
52.8
323.6
211.8
67.1
30.2
6.5
5.9
2.0
+
2009
5,379.0
5,212.0
2,154.0
1,718.9
738.4
340.2
218.8
41.7
122.1
32.2
12.3
0.5
183.8
131.3
59.0
337.0
221.2
71.0
30.9
6.2
5.5
2.2
+
2-8 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
International Bunker Fuels
N2O
Mobile Combustion
Stationary Combustion
Incineration of Waste
International Bunker Fuelsb
Total
0.2
57.2
43.9
12.8
0.5
1.1
5,288.2
0.1
68.1
53.2
14.6
0.4
0.9
6,168.4
0.1
52.1
36.9
14.7
0.4
1.0
6,283.1
0.2
48.5
33.6
14.4
0.4
1.2
6,210.9
0.2
45.2
30.3
14.6
0.4
1.2
6,291.5
0.2
40.7
26.1
14.2
0.4
1.2
6,117.1
0.2
41.0
27.8
12.8
0.4
1.2
5,757.0
1 + Does not exceed 0.05 Tg CO2 Eq.
2 "Emissions from Wood Biomass and Ethanol Consumption are not included specifically in summing energy sector totals. Net
3 carbon fluxes from changes in biogenic carbon reservoirs are accounted for in the estimates for Land Use, Land-Use Change, and
4 Forestry
5 bEmissions from International Bunker Fuels are not included in totals.
6 Note: Totals may not sum due to independent rounding.
7
8 Carbon dioxide emissions from fossil fuel combustion are presented in Table 2-5 based on the underlying U.S.
9 energy consumer data collected by EIA. Estimates of CO2 emissions from fossil fuel combustion are calculated from
10 these EIA "end-use sectors" based on total consumption and appropriate fuel properties (any additional analysis and
11 refinement of the EIA data is further explained in the Energy chapter of this report). EIA's fuel consumption data
12 for the electric power sector comprises electricity-only and combined-heat-and-power (CHP) plants within the
13 NAICS 22 category whose primary business is to sell electricity, or electricity and heat, to the public (nonutility
14 power producers can be included in this sector as long as they meet they electric power sector definition). EIA
15 statistics for the industrial sector include fossil fuel consumption that occurs in the fields of manufacturing,
16 agriculture, mining, and construction. EIA's fuel consumption data for the transportation sector consists of all
17 vehicles whose primary purpose is transporting people and/or goods from one physical location to another. EIA's
18 fuel consumption data for the industrial sector consists of all facilities and equipment used for producing,
19 processing, or assembling goods (EIA includes generators that produce electricity and/or useful thermal output
20 primarily to support on-site industrial activities in this sector). EIA's fuel consumption data for the residential sector
21 consists of living quarters for private households. EIA's fuel consumption data for the commercial sector consists of
22 service-providing facilities and equipment from private and public organizations and businesses (EIA includes
23 generators that produce electricity and/or useful thermal output primarily to support the activities at commercial
24 establishments in this sector). Table 2-5, Figure 2-7, and Figure 2-8 summarize CO2 emissions from fossil fuel
25 combustion by end-use sector.
26 Table 2-5: CO2 Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.)
End-Use Sector 1990 2000 2005 2006 2007 2008 2009
Transportation
Combustion
Electricity
Industrial
Combustion
Electricity
Residential
Combustion
Electricity
Commercial
Combustion
Electricity
U.S. Territories
Total
Electricity Generation
1,489.0
1,485.9
3.0
1,536.0
849.3
686.7
931.4
338.3
593.0
757.0
219.0
538.0
27.9
4,741.2
1,820.8
1,813.0
1,809.5
3.4
1,643.7
853.9
789.8
1,133.1
370.7
762.4
972.1
230.8
741.3
35.9
5,597.7
2,296.9
1,901.3
1,896.6
4.7
1,562.4
825.5
737.0
1,214.7
357.9
856.7
1,027.2
223.5
803.7
50.0
5,755.6
2,402.1
1,882.6
1,878.1
4.5
1,564.1
852.1
712.0
1,152.4
321.5
830.8
1,007.6
208.6
799.0
50.3
5,657.0
2,346.4
1,899.0
1,894.0
5.0
1,575.9
845.9
730.0
1,198.5
342.4
856.1
1,041.1
219.4
821.7
46.1
5,760.6
2,412.8
1,794.6
1,789.9
4.7
1,520.4
805.6
714.8
1,182.2
348.2
834.0
1,031.6
224.2
807.4
39.8
5,568.7
2,360.9
1,723.3
1,718.9
4.4
1,341.7
738.4
603.3
1,124.8
340.2
784.6
980.5
218.8
761.7
41.7
5,212.0
2,154.0
27 Note: Totals may not sum due to independent rounding. Combustion-related emissions from electricity generation are allocated
28 based on aggregate national electricity consumption by each end-use sector.
29
30 Figure 2-7: 2009 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
31
Trends in Greenhouse Gas Emissions 2-9
-------
1 Figure 2-8: 2009 End-Use Sector Emissions from Fossil Fuel Combustion
2
3 The main driver of emissions in the energy sector is CO2 from fossil fuel combustion. The transportation end-use
4 sector accounted for 1,723.3 Tg CO2 Eq. in 2009 or approximately 3 3 percent of total CO2 emissions from fossil
5 fuel combustion, the largest share of any end-use sector.46 The industrial end-use sector accounted for 26 percent of
6 CO2 emissions from fossil fuel combustion. The residential and commercial end-use sectors accounted for an
7 average 22 and 19 percent, respectively, of CO2 emissions from fossil fuel combustion. Both end-use sectors were
8 heavily reliant on electricity for meeting energy needs, with electricity consumption for lighting, heating, air
9 conditioning, and operating appliances contributing 70 and 78 percent of emissions from the residential and
10 commercial end-use sectors, respectively. Significant trends in emissions from energy source categories over the
11 twenty-year period from 1990 through 2009 included the following:
12 • Total CO2 emissions from fossil fuel combustion increased from 4,741.2 Tg CO2 Eq. to 5,212.0 Tg CO2
13 Eq.—a 9.9 percent total increase over the twenty-year period. From 2008 to 2009, these emissions
14 decreased by 356.7 Tg CO2 Eq. (6.4 percent), the largest decrease of any year over the twenty-year period.
15 • CO2 emissions from non-energy use of fossil fuels increased 5.8 Tg CO2 Eq. (5.0 percent) from 1990
16 through 2009. Emissions from non-energy uses of fossil fuels were 122.1 Tg CO2 Eq. in 2009, which
17 constituted 2.2 percent of total national CO2 emissions.
18 • CH4 emissions from natural gas systems were 221.2 Tg CO2 Eq. in 2009; emissions have increased by 31.4
19 Tg CO2 Eq. (16.6 percent) since 1990.
20 • CH4 emissions from coal mining were 71.0 Tg CO2 Eq. in 2009, a decline in emissions of 13.0 Tg CO2 Eq.
21 (15.5 percent) from 1990.This occurred as a result of the mining of less gassy coal from underground mines
22 and the increased use of CH4 collected from degasification systems.
23 • In 2009, N2O emissions from mobile combustion were 27.8 Tg CO2 Eq. (approximately 9.3 percent of U.S.
24 N2O emissions). From 1990 to 2009, N2O emissions from mobile combustion decreased by 36.7 percent.
25 However, from 1990 to 1998 emissions increased by 26 percent, due to control technologies that reduced
26 NOX emissions while increasing N2O emissions. Since 1998, newer control technologies have led to a
27 steady decline in N2O from this source.
28 • CO2 emissions from incineration of waste (12.3 Tg CO2 Eq. in 2009) increased by 4.3 Tg CO2 Eq. (54
29 percent) from 1990 through 2009, as the volume of plastics and other fossil carbon-containing materials in
30 municipal solid waste grew.
31 Industrial Processes
32 Greenhouse gas emissions are produced as the by-products of many non-energy-related industrial activities. For
33 example, industrial processes can chemically transform raw materials, which often release waste gases such as CO2,
34 CH4, and N2O. These processes include iron and steel production and metallurgical coke production, cement
35 production, ammonia production and urea consumption, lime production, limestone and dolomite use (e.g., flux
36 stone, flue gas desulfurization, and glass manufacturing), soda ash production and consumption, titanium dioxide
37 production, phosphoric acid production, ferroalloy production, CO2 consumption, silicon carbide production and
38 consumption, aluminum production, petrochemical production, nitric acid production, adipic acid production, lead
39 production, and zinc production (see Figure 2-9). Industrial processes also release HFCs, PFCs and SF6. In addition
40 to their use as ODS substitutes, HFCs, PFCs, SF6, and other fluorinated compounds are employed and emitted by a
41 number of other industrial sources in the United States. These industries include aluminum production, HCFC-22
42 production, semiconductor manufacture, electric power transmission and distribution, and magnesium metal
43 production and processing. Table 2-6 presents greenhouse gas emissions from industrial processes by source
44 category.
45
46 Note that electricity generation is the largest emitter of CO2 when electricity is not distributed among end-use sectors.
2-10 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
4
5
6
Figure 2-9: 2009 Industrial Processes Chapter Greenhouse Gas Sources
Table 2-6: Emissions from Industrial Processes (Tg CO2 Eq.)
Gas/Source
C02
Iron and Steel Production &
Metallurgical Coke Production
Iron and Steel Production
Metallurgical Coke Production
Cement Production
Ammonia Production & Urea
Consumption
Lime Production
Limestone and Dolomite Use
Soda Ash Production and
Consumption
Aluminum Production
Petrochemical Production
Carbon Dioxide Consumption
Ferroalloy Production
Titanium Dioxide Production
Phosphoric Acid Production
Zinc Production
Lead Production
Silicon Carbide Production and
Consumption
CH4
Petrochemical Production
Iron and Steel Production &
Metallurgical Coke Production
Iron and Steel Production
Metallurgical Coke Production
Ferroalloy Production
Silicon Carbide Production and
Consumption
N2O
Nitric Acid Production
Adipic Acid Production
HFCs
Substitution of Ozone Depleting
Substances3
HCFC-22 Production
Semiconductor Manufacture
PFCs
Semiconductor Manufacture
Aluminum Production
SF6
Electrical Transmission and
Distribution
Magnesium Production and Processing
Semiconductor Manufacture
Total
+ Does not exceed 0.05 Tg CO2 Eq.
a Small amounts of PFC emissions also result
1990
188.4
99.5
97.1
2.5
33.3
16.8
11.5
5.1
4.1
6.8
3.3
1.4
2.2
1.2
1.5
0.7
0.5
0.4
1.9
0.9
1.0
1.0
+
+
+
33.5
17.7
15.8
36.9
0.3
36.4
0.2
20.8
2.2
18.5
34.4
28.4
5.4
0.5
315.8
2000
185.7
85.9
83.7
2.2
41.2
16.4
14.1
5.1
4.2
6.1
4.5
1.4
1.9
1.8
1.4
1.0
0.6
0.2
2.2
1.2
0.9
0.9
+
+
+
24.9
19.4
5.5
103.2
74.3
28.6
0.3
13.5
4.9
8.6
20.1
16.0
3.0
1.1
349.6
2005
166.1
65.9
63. 9
2.0
45.9
12.8
14.4
6.8
4.2
4.1
4.2
1.3
1.4
1.8
1.4
1.1
0.6
0.2
1.8
1.1
0.7
0.7
+
+
+
21.5
16.5
5.0
120.2
104.2
15.8
0.2
6.2
3.2
3.0
19.0
15.1
2.9
1.0
334.8
2006
170.6
68.8
66.9
1.9
46.6
12.3
15.1
8.0
4.2
3.8
3.8
.7
.5
.8
.2
.1
0.6
0.2
1.7
1.0
0.7
0.7
+
+
+
20.5
16.2
4.3
123.4
109.3
13.8
0.3
6.0
3.5
2.5
17.9
14.1
2.9
1.0
340.2
2007
173.3
71.0
69.0
2.1
45.2
14.0
14.6
7.7
4.1
4.3
3.9
1.9
1.6
1.9
1.2
1.1
0.6
0.2
1.7
1.0
0.7
0.7
+
+
+
22.9
19.2
3.7
129.5
112.2
17.0
0.3
7.5
3.7
3.8
16.7
13.2
2.6
0.8
351.6
2008
160.1
66.0
63.7
2.3
41.1
11.9
14.3
6.3
4.1
4.5
3.4
.8
.6
.8
.2
.2
0.6
0.2
1.6
0.9
0.6
0.6
+
+
+
18.5
16.4
2.0
129.1
115.2
13.6
0.3
6.7
4.0
2.7
16.1
13.3
1.9
0.9
332.0
2009
120.2
42.6
41.6
1.0
29.4
11.8
11.2
7.6
4.3
3.0
2.7
.8
.6
.5
.0
.0
0.5
0.1
1.2
0.8
0.4
0.4
+
+
+
16.5
14.6
1.9
125.0
119.3
5.4
0.3
5.6
4.0
1.6
14.8
12.8
1.1
1.0
283.5
from this source.
Note: Totals may not sum due to independent rounding.
Trends in Greenhouse Gas Emissions
2-11
-------
2 Overall, emissions from industrial processes decreased by 10.2 percent from 1990 to 2009 due to decreases in
3 emissions from several industrial processes, such as iron and steel production and metallurgical coke production,
4 HCFC-22 production, aluminum production, adipic acid production, and electrical transmission and distribution.
5 Significant trends in emissions from industrial processes source categories over the twenty-year period from 1990
6 through 2009 included the following:
7 • HFC emissions from ODS substitutes have been increasing from small amounts in 1990 to 119.3 Tg CO2
8 Eq. in 2009. This increase results from efforts to phase out CFCs and other ODSs in the United States. In
9 the short term, this trend is expected to continue, and will likely accelerate over the next decade as
10 HCFCs—which are interim substitutes in many applications—are phased out under the provisions of the
11 Copenhagen Amendments to the Montreal Protocol.
12 • Combined CO2 and CH4 emissions from iron and steel production and metallurgical coke production
13 decreased by 35.6 percent to 42.9 Tg CO2 Eq. from 2008 to 2009, and have declined overall by 57.5 Tg
14 CO2 Eq. (57.3 percent) from 1990 through 2009, due to restructuring of the industry, technological
15 improvements, and increased scrap utilization.
16 • PFC emissions from aluminum production decreased by about 91.5 percent (17.0 Tg CO2 Eq.) from 1990
17 to 2009, due to both industry emission reduction efforts and lower domestic aluminum production.
18 • N2O emissions from adipic acid production were 1.9 Tg CO2 Eq. in 2009, and have decreased significantly
19 in recent years from the widespread installation of pollution control measures. Emissions from adipic acid
20 production have decreased by 87.7 percent since 1990 and by 89.0 percent since a peak in 1995.
21 • CO2 emissions from ammonia production and urea consumption (11.8 Tg CO2 Eq. in 2009) have decreased
22 by 5.0 Tg CO2 Eq. (29.9 percent) since 1990, due to a decrease in domestic ammonia production. This
23 decrease in ammonia production is primarily attributed to market fluctuations.
24 Solvent and Other Product Use
25 Greenhouse gas emissions are produced as a by-product of various solvent and other product uses. In the United
26 States, N2O Emissions from Product Uses, the only source of greenhouse gas emissions from this sector, accounted
27 for 4.4 Tg CO2 Eq., or less than 0.1 percent of total U.S. emissions in 2009 (see Table 2-7).
28 Table 2-7: N2O Emissions from Solvent and Other Product Use (Tg CO2 Eq.)
Gas/Source 1990 2000 2005 2006 2007 2008 2009
N2O
N2O from Product Uses
Total
4.4
4.4
4.4
4.9
4.9
4.9
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
29
30 In 2009, N2O emissions from product uses constituted 1.5 percent of U.S. N2O emissions. From 1990 to 2009,
31 emissions from this source category decreased by just under 0.4 percent, though slight increases occurred in
32 intermediate years.
33 Agriculture
34 Agricultural activities contribute directly to emissions of greenhouse gases through a variety of processes, including
35 the following source categories: enteric fermentation in domestic livestock, livestock manure management, rice
36 cultivation, agricultural soil management, and field burning of agricultural residues.
37 In 2009, agricultural activities were responsible for emissions of 419.3 Tg CO2 Eq., or 6.3 percent of total U.S.
38 greenhouse gas emissions. CH4 and N2O were the primary greenhouse gases emitted by agricultural activities. CH4
39 emissions from enteric fermentation and manure management represented about 20.4 percent and 7.2 percent of total
40 CH4 emissions from anthropogenic activities, respectively, in 2009. Agricultural soil management activities, such as
41 fertilizer application and other cropping practices, were the largest source of U.S. N2O emissions in 2009,
42 accounting for almost 68.3 percent.
43
2-12 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Figure 2-10: 2009 Agriculture Chapter Greenhouse Gas Sources
2
3 Table 2-8: Emissions from Agriculture (Tg CO2 Eq.)
Gas/Source
CH4
Enteric Fermentation
Manure Management
Rice Cultivation
Field Burning of Agricultural
Residues
N2O
Agricultural Soil
Management
Manure Management
Field Burning of Agricultural
Residues
Total
1990
171.2
132.1
31.7
7.1
0.3
212.4
197.8
14.5
0.1
383.6
2000
186.7
136.5
42.4
7.5
0.3
224.0
206.8
17.1
0.1
410.6
2005
190.1
136.5
46.6
6.8
0.2
228.7
211.3
17.3
0.1
418.8
2006
191.7
138.8
46.7
5.9
0.2
227.1
208.9
18.0
0.1
418.8
2007
198.2
141.0
50.7
6.2
0.2
227.6
209.4
18.1
0.1
425.8
2008
197.5
140.6
49.4
7.2
0.3
228.8
210.7
17.9
0.1
426.3
2009
196.8
139.8
49.5
7.3
0.2
222.5
204.6
17.9
0.1
419.3
4 Note: Totals may not sum due to independent rounding.
5
6 Some significant trends in U.S. emissions from Agriculture include the following:
7 • Agricultural soils produced approximately 68 percent of N2O emissions in the United States in 2009.
8 Estimated emissions from this source in 2009 were 204.6 Tg CO2 Eq. Annual N2O emissions from
9 agricultural soils fluctuated between 1990 and 2009, although overall emissions were 3.4 percent higher in
10 2009 than in 1990. Nitrous oxide emissions from this source have not shown any significant long-term
11 trend, as their estimation is highly sensitive to the amount of N applied to soils, which has not changed
12 significantly over the time-period, and to weather patterns and crop type.
13 • Enteric fermentation was the largest source of CH4 emissions in 2009, at 139.8 Tg CO2Eq. Generally,
14 emissions decreased from 1996 to 2003, though with a slight increase in 2002. This trend was mainly due
15 to decreasing populations of both beef and dairy cattle and increased digestibility of feed for feedlot cattle.
16 Emissions increased from 2004 through 2007, as both dairy and beef populations increased and the
17 literature for dairy cow diets indicated a trend toward a decrease in feed digestibility for those years.
18 Emissions decreased again in 2008 and 2009 as beef cattle populations decreased again. During the
19 timeframe of this analysis, populations of sheep have decreased 49 percent since 1990 while horse
20 populations have increased over 87 percent, mostly since 1999. Goat and swine populations have increased
21 25 percent and 23 percent, respectively, during this timeframe.
22 • Overall, emissions from manure management increased 46 percent between 1990 and 2009. This
23 encompassed an increase of 56 percent for CH4, from 31.7 Tg CO2 Eq. in 1990 to 49.5 Tg CO2 Eq. in 2009;
24 and an increase of 23 percent for N2O, from 14.5 Tg CO2 Eq. in 1990 to 17.9 Tg CO2 Eq. in 2009. The
25 majority of this increase was from swine and dairy cow manure, since the general trend in manure
26 management is one of increasing use of liquid systems, which tends to produce greater CH4 emissions.
27 Land Use, Land-Use Change, and Forestry
28 When humans alter the terrestrial biosphere through land use, changes in land use, and land management practices,
29 they also alter the background carbon fluxes between biomass, soils, and the atmosphere. Forest management
30 practices, tree planting in urban areas, the management of agricultural soils, and the landfilling of yard trimmings
31 and food scraps have resulted in an uptake (sequestration) of carbon in the United States, which offset about 15
32 percent of total U.S. greenhouse gas emissions in 2009. Forests (including vegetation, soils, and harvested wood)
33 accounted for approximately 85 percent of total 2009 net CO2 flux, urban trees accounted for 9 percent, mineral and
34 organic soil carbon stock changes accounted for 4 percent, and landfilled yard trimmings and food scraps accounted
35 for 1 percent of the total net flux in 2009. The net forest sequestration is a result of net forest growth, increasing
36 forest area, and a net accumulation of carbon stocks in harvested wood pools. The net sequestration in urban forests
37 is a result of net tree growth and increased urban forest size. In agricultural soils, mineral and organic soils
Trends in Greenhouse Gas Emissions 2-13
-------
1 sequester approximately 5.5 times as much C as is emitted from these soils through liming and urea fertilization.
2 The mineral soil C sequestration is largely due to the conversion of cropland to hay production fields, the limited use
3 of bare-summer fallow areas in semi-arid areas, and an increase in the adoption of conservation tillage practices.
4 The landfilled yard trimmings and food scraps net sequestration is due to the long-term accumulation of yard
5 trimming carbon and food scraps in landfills.
6 Land use, land-use change, and forestry activities in 2009 resulted in a net C sequestration of 1,015.1 Tg CO2 Eq.
7 (276.8 Tg C) (Table 2-9). This represents an offset of approximately 18 percent of total U.S. CO2 emissions, or 15
8 percent of total greenhouse gas emissions in 2009. Between 1990 and 2009, total land use, land-use change, and
9 forestry net C flux resulted in a 17.8 percent increase in CO2 sequestration.
10 Table 2-9: Net CO2 Flux from Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.)
23
24
25
Sink Category
Forest Land Remaining Forest
Land
Cropland Remaining Cropland
Land Converted to Cropland
Grassland Remaining Grassland
Land Converted to Grassland
Settlements Remaining
Settlements
Other (Landfilled Yard
Trimmings and Food Scraps)
Total
1990
(681.1)
(29.4)
2.2
(52.2)
(19.8)
(57.1)
(24.2)
(861.5)
2000
(378.3)
(30.2)
2.4
(52.6)
(27.2)
(77.5)
(13.2)
(576.6)
2005
(911.5)
(18.3)
5.9
(8.9)
(24.4)
(87.8)
(11.5)
(1,056.5)
2006
(917.5)
(19.1)
5.9
(8.8)
(24.2)
(89.8)
(11.0)
(1,064.3)
2007
(911.9)
(19.7)
5.9
(8.6)
(24.0)
(91.9)
(10.9)
(1,060.9)
2008
(891.0)
(18.1)
5.9
(8.5)
(23.8)
(93.9)
(11.2)
(1,040.5)
2009
(863.1)
(17.4)
5.9
(8.3)
(23.6)
(95.9)
(12.6)
(1,015.1)
11 Note: Totals may not sum due to independent rounding. Parentheses indicate net sequestration.
12
13 Land use, land-use change, and forestry source categories also resulted in emissions of CO2, CH4, and N2O that are
14 not included in the net CO2 flux estimates presented in Table 2-9. The application of crushed limestone and
15 dolomite to managed land (i.e., soil liming) and urea fertilization resulted in CO2 emissions of 7.8 Tg CO2 Eq. in
16 2009, an increase of about 10.6 percent relative to 1990. Lands undergoing peat extraction resulted in CO2
17 emissions of 1.1 Tg CO2 Eq. (1,090 Gg), and N2O emissions of less than 0.01 Tg CO2 Eq. N2O emissions from the
18 application of synthetic fertilizers to forest soils have increased from 0.1 Tg CO2 Eq. in 1990 to 0.4 Tg CO2 Eq. in
19 2009. Settlement soils in 2009 resulted in direct N2O emissions of 1.5 Tg CO2 Eq., a 55 percent increase relative to
20 1990.Emissions from forest fires in 2009 resulted in CH4 emissions of 7.8 Tg CO2 Eq., and in N2O emissions of 6.4
21 TgCO2Eq. (Table 2-10).
22 Table 2-10: Emissions from Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.)
Source Category
C02
Cropland Remaining Cropland: Liming of
Agricultural Soils
Cropland Remaining Cropland: Urea Fertilization
Wetlands Remaining Wetlands: Peatlands
Remaining Peatlands
CH4
Forest Land Remaining Forest Land: Forest Fires
N2O
Forest Land Remaining Forest Land: Forest Fires
Forest Land Remaining Forest Land: Forest Soils
Settlements Remaining Settlements: Settlement
Soils
Wetlands Remaining Wetlands: Peatlands
Remaining Peatlands
Total
+ Less than 0.05 Tg CO2 Eq.
Note: Totals may not sum due to independent rounding.
1990
8.1
4.7
2.4
1.0
3.2
3.2
3.7
2.6
0.1
1.0
+
15.0
2000
8.8
4.3
3.2
1.2
14.3
14.3
13.2
11.7
0.4
1.1
+
36.3
2005
8.9
4.3
3.5
1.1
9.8
9.8
9.8
8.0
0.4
1.5
+
28.6
2006
8.8
4.2
3.7
0.9
21.6
21.6
19.5
17.6
0.4
1.5
+
49.8
2007
9.2
4.5
3.7
1.0
20.0
20.0
18.3
16.3
0.4
1.6
+
47.5
2008
9.6
5.0
3.6
1.0
11.9
11.9
11.6
9.8
0.4
1.5
+
33.2
2009
8.9
4.2
3.6
1.1
7.8
7.8
8.3
6.4
0.4
1.5
+
25.0
2-14 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Other significant trends from 1990 to 2009 in land use, land-use change, and forestry emissions include:
2 • Net C sequestration by forest land has increased by almost 27 percent. This is primarily due to increased
3 forest management and the effects of previous reforestation. The increase in intensive forest management
4 resulted in higher growth rates and higher biomass density. The tree planting and conservation efforts of
5 the 1970s and 1980s continue to have a significant impact on sequestration rates. Finally, the forested area
6 in the United States increased over the past 20 years, although only at an average rate of 0.20 percent per
7 year.
8 • Net sequestration of C by urban trees has increased by 68 percent over the period from 1990 to 2009. This
9 is primarily due to an increase in urbanized land area in the United States.
10 • Annual C sequestration in landfilled yard trimmings and food scraps has decreased by 48 percent since
11 1990. This is due in part to a decrease in the amount of yard trimmings and food scraps generated. In
12 addition, the proportion of yard trimmings and food scraps landfilled has decreased, as there has been a
13 significant rise in the number of municipal composting facilities in the United States.
14 Waste
15 Waste management and treatment activities are sources of greenhouse gas emissions (see Figure 2-11). In 2009,
16 landfills were the third largest source of anthropogenic CH4 emissions, accounting for 17 percent of total U.S. CH4
17 emissions.47 Additionally, wastewater treatment accounts for 4 percent of U.S. CH4 emissions, and 2 percent of N2O
18 emissions. Emissions of CH4 and N2O from composting grew from 1990 to 2009, and resulted in emissions of 3.5
19 Tg CO2 Eq. in 2009. A summary of greenhouse gas emissions from the Waste chapter is presented in Table 2-11.
20
21 Figure 2-11: 2009 Waste Chapter Greenhouse Gas Sources
22
23 Overall, in 2009, waste activities generated emissions of 150.5 Tg CO2 Eq., or 2.3 percent of total U.S. greenhouse
24 gas emissions.
25 Table 2-11: Emissions from Waste (Tg CO2 Eq.)
Gas/Source
CH4
Landfills
Wastewater Treatment
Composting
N2O
Wastewater Treatment
Composting
Total
1990
171.2
147.4
23.5
0.3
4.0
3.7
0.4
175.2
2000
138.1
111.7
25.2
1.3
5.9
4.5
1.4
143.9
2005
138.4
112.5
24.3
1.6
6.5
4.8
1.7
144.9
2006
137.8
111.7
24.5
1.6
6.6
4.8
1.8
144.4
2007
137.4
111.3
24.4
1.7
6.7
4.9
1.8
144.1
2008
142.1
115.9
24.5
1.7
6.8
5.0
1.9
149.0
2009
143.6
117.5
24.5
1.7
6.9
5.0
1.8
150.5
26 Note: Totals may not sum due to independent rounding.
27
28 Some significant trends in U.S. emissions from Waste include the following:
29 • From 1990 to 2009, net CH4 emissions from landfills decreased by 29.9 Tg CO2 Eq. (20 percent), with
30 small increases occurring in interim years. This downward trend in overall emissions is the result of
31 increases in the amount of landfill gas collected and combusted,48 which has more than offset the
32 additional CH4 emissions resulting from an increase in the amount of municipal solid waste landfilled.
33 • From 1990 to 2009, CH4 and N2O emissions from wastewater treatment increased by 1.0 Tg CO2 Eq. (4.4
47 Landfills also store carbon, due to incomplete degradation of organic materials such as wood products and yard trimmings, as
described in the Land Use, Land-Use Change, and Forestry chapter.
48 Lhe CO2 produced from combusted landfill CH4 at landfills is not counted in national inventories as it is considered part of the
natural C cycle of decomposition.
Trends in Greenhouse Gas Emissions 2-15
-------
percent) and 1.3 Tg CO2 Eq. (36 percent), respectively.
• Emissions from composting have generally increased since 1990, from 0.7 Tg CO2 Eq. to 3.5 Tg CO2 Eq.
in 2009, an over four-fold increase over the time series.
4 2.2. Emissions by Economic Sector
5 Throughout this report, emission estimates are grouped into six sectors (i.e., chapters) defined by the IPCC and
6 detailed above: Energy; Industrial Processes; Solvent and Other Product Use; Agriculture; Land Use, Land-Use
7 Change, and Forestry; and Waste. While it is important to use this characterization for consistency with UNFCCC
8 reporting guidelines, it is also useful to allocate emissions into more commonly used sectoral categories. This
9 section reports emissions by the following U.S. economic sectors: residential, commercial, industry, transportation,
10 electricity generation, and agriculture, as well as U.S. territories.
11 Using this categorization, emissions from electricity generation accounted for the largest portion (33 percent) of
12 U.S. greenhouse gas emissions in 2009. Transportation activities, in aggregate, accounted for the second largest
13 portion (27 percent). Emissions from industry accounted for about 20 percent of U.S. greenhouse gas emissions in
14 2009. In contrast to electricity generation and transportation, emissions from industry have in general declined over
15 the past decade. The long-term decline in these emissions has been due to structural changes in the U.S. economy
16 (i.e., shifts from a manufacturing-based to a service-based economy), fuel switching, and efficiency improvements.
17 The remaining 20 percent of U.S. greenhouse gas emissions were contributed by the residential, agriculture, and
18 commercial sectors, plus emissions from U.S. territories. The residential sector accounted for 5 percent, and
19 primarily consisted of CO2 emissions from fossil fuel combustion. Activities related to agriculture accounted for
20 roughly 7 percent of U.S. emissions; unlike other economic sectors, agricultural sector emissions were dominated by
21 N2O emissions from agricultural soil management and CH4 emissions from enteric fermentation, rather than CO2
22 from fossil fuel combustion. The commercial sector accounted for roughly 6 percent of emissions, while U.S.
23 territories accounted for less than 1 percent.
24 CO2 was also emitted and sequestered (in the form of C) by a variety of activities related to forest management
25 practices, tree planting in urban areas, the management of agricultural soils, and landfilling of yard trimmings.
26 Table 2-12 presents a detailed breakdown of emissions from each of these economic sectors by source category, as
27 they are defined in this report. Figure 2-12 shows the trend in emissions by sector from 1990 to 2009.
28
29 Figure 2-12: Emissions Allocated to Economic Sectors
30
3 1 Table 2-12: U.S. Greenhouse Gas Emissions Allocated to Economic Sectors (Tg CO2
32 2009)
Sector/Source
Electric Power Industry
CO2 from Fossil Fuel Combustion
Electrical Transmission and
Distribution
Incineration of Waste
Stationary Combustion
Limestone and Dolomite Use
Transportation
CO2 from Fossil Fuel Combustion
Substitution of Ozone Depleting
Substances
Mobile Combustion
Non-Energy Use of Fuels
Industry
CO2 from Fossil Fuel Combustion
1990
1,868.9
1,820.8
28.4
8.5
8.6
2.6
1,545.2
1,485.9
+
47.4
11.8
1,564.9
818.3
2000
2,337.6
2,296.9
16.0
11.5
10.6
2.5
1,932.3
1,809.5
55.7
55.1
12.1
1,545.2
815.2
2005
2,444.6
2,402.1
15.1
12.9
11.0
3.4
2,017.4
1,896.6
72.9
37.7
10.2
1,442.9
778.7
2006
2,388.2
2,346.4
14.1
12.9
10.8
4.0
1,994.4
1,878.1
72.2
34.2
9.9
1,498.8
803.0
2007
2,454.0
2,412.8
13.2
13.1
11.0
3.9
2,003.7
1,894.0
68.8
30.7
10.2
1,484.5
797.5
Eq. and Percent of Total in
2008
2,400.7
2,360.9
13.3
12.5
10.8
3.1
1,890.7
1,789.9
64.9
26.4
9.5
1,448.0
760.2
2009
2,193.0
2,154.0
12.8
12.7
9.7
3.8
1,815.8
1,718.9
60.2
28.2
8.5
1,330.6
691.7
Percent"
33.0%
32.4%
0.2%
0.2%
0.1%
0.1%
27.3%
25.9%
0.9%
0.4%
0.1%
20.0%
10.4%
2-16 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Natural Gas Systems
Non-Energy Use of Fuels
Coal Mining
Iron and Steel Production &
Metallurgical Coke Production
Petroleum Systems
Cement Production
Nitric Acid Production
Ammonia Production and Urea
Consumption
Lime Production
Substitution of Ozone Depleting
Substances
Abandoned Underground Coal Mines
HCFC-22 Production
Semiconductor Manufacture
Aluminum Production
N2O from Product Uses
Soda Ash Production and
Consumption
Limestone and Dolomite Use
Stationary Combustion
Petrochemical Production
Adipic Acid Production
Carbon Dioxide Consumption
Ferroalloy Production
Titanium Dioxide Production
Mobile Combustion
Magnesium Production and
Processing
Phosphoric Acid Production
Zinc Production
Lead Production
Silicon Carbide Production and
Consumption
Agriculture
N2O from Agricultural Soil
Management
Enteric Fermentation
Manure Management
CO2 from Fossil Fuel Combustion
CH4 and N2O from Forest Fires
Rice Cultivation
Liming of Agricultural Soils
Urea Fertilization
CO2 and N2O from Managed
Peatlands
Mobile Combustion
N2O from Forest Soils
Field Burning of Agricultural
Residues
227.4
98.7
84.1
100.5
35.9
33.3
17.7
16.8
11.5
+
6.0
36.4
2.9
25.4
4.4
4.1
2.6
4.7
4.2
15.8
1.4
2.2
1.2
0.9
5.4
1.5
0.7
0.5
0.4
429.0
197.8
132.1
46.2
31.0
5.8
7.1
4.7
2.4
1.0
0.3
0.1
0.4
239.2
120.4
60.4
86.9
32.0
41.2
19.4
16.4
14.1
3.2
7.4
28.6
6.2
14.7
4.9
4.2
2.5
4.8
5.7
5.5
1.4
1.9
1.8
1.1
3.0
1.4
1.0
0.6
0.3
485.1
206.8
136.5
59.5
38.8
26.0
7.5
4.3
3.2
1.2
0.4
0.4
0.4
220.4
123.0
56.9
66.6
29.9
45.9
16.5
12.8
14.4
6.4
5.5
15.8
4.4
7.1
4.4
4.2
3.4
4.4
5.3
5.0
1.3
1.4
1.8
1.3
2.9
1.4
1.1
0.6
0.2
493.2
211.3
136.5
63.8
46.8
17.8
6.8
4.3
3.5
1.1
0.5
0.4
0.3
248.4
123.7
58.2
69.5
29.8
46.6
16.2
12.3
15.1
7.1
5.5
13.8
4.7
6.3
4.4
4.2
4.0
4.6
4.8
4.3
1.7
1.5
1.8
1.3
2.9
1.2
1.1
0.6
0.2
516.7
208.9
138.8
64.8
49.0
39.2
5.9
4.2
3.7
0.9
0.5
0.4
0.3
236.2
116.7
57.9
71.7
30.4
45.2
19.2
14.0
14.6
7.8
5.6
17.0
4.8
8.1
4.4
4.1
3.9
4.4
4.9
3.7
1.9
1.6
1.9
1.3
2.6
1.2
1.1
0.6
0.2
520.7
209.4
141.0
68.9
48.4
36.4
6.2
4.5
3.7
1.0
0.5
0.4
0.3
244.6
120.8
67.1
66.7
30.7
41.1
16.4
11.9
14.3
8.5
5.9
13.6
5.1
7.2
4.4
4.1
3.1
4.1
4.4
2.0
.8
.6
.8
.3
.9
.2
.2
0.6
0.2
503.9
210.7
140.6
67.3
45.4
21.7
7.2
5.0
3.6
1.0
0.5
0.4
0.4
253.4
109.8
71.0
42.9
31.4
29.4
14.6
11.8
11.2
10.9
5.5
5.4
5.3
4.6
4.4
4.3
3.8
3.6
3.6
1.9
1.8
1.6
1.5
1.3
1.1
1.0
1.0
0.5
0.2
490.0
204.6
139.8
67.3
46.7
14.2
7.3
4.2
3.6
1.1
0.5
0.4
0.4
3.8%
1.7%
1.1%
0.6%
0.5%
0.4%
0.2%
0.2%
0.2%
0.2%
0.1%
0.1%
0.1%
0.1%
0.1%
0.1%
0.1%
0.1%
0.1%
+
+
+
+
+
+
+
+
+
+
7.4%
3.1%
2.1%
1.0%
0.7%
0.2%
0.1%
0.1%
0.1%
+
+
+
+
Trends in Greenhouse Gas Emissions
2-17
-------
Stationary Combustion
Commercial
CO2 from Fossil Fuel Combustion
Landfills
Substitution of Ozone Depleting
Substances
Wastewater Treatment
Human Sewage
Composting
Stationary Combustion
Residential
CO2 from Fossil Fuel Combustion
Substitution of Ozone Depleting
Substances
Stationary Combustion
Settlement Soil Fertilization
U.S. Territories
CO2 from Fossil Fuel Combustion
Non-Energy Use of Fuels
Stationary Combustion
Total Emissions
+
395.5
219.0
147.4
+
23.5
3.7
0.7
1.3
345.1
338.3
0.3
5.5
1.0
33.7
27.9
5.7
0.1
6,182.2
+
381.4
230.8
111.7
5.4
25.2
4.5
2.6
1.3
386.2
370.7
10.1
4.3
1.1
46.0
35.9
10.0
0.1
7,113.9
+
387.2
223.5
112.5
17.6
24.3
4.8
3.3
1.2
371.0
357.9
7.3
4.3
1.5
58.2
50.0
8.1
0.2
7,214.5
+
375.2
208.6
111.7
21.1
24.5
4.8
3.3
1.2
335.8
321.5
8.9
3.9
1.5
59.3
50.3
8.8
0.2
7,168.4
+
389.6
219.4
111.3
25.0
24.4
4.9
3.5
1.2
358.8
342.4
10.6
4.2
1.6
53.5
46.1
7.2
0.2
7,264.8
+
403.5
224.2
115.9
29.1
24.5
5.0
3.5
1.2
366.8
348.2
12.6
4.4
1.5
48.4
39.8
8.4
0.2
7,061.9
+
404.3
218.8
117.5
33.7
24.5
5.0
3.5
1.2
360.5
340.2
14.5
4.2
1.5
45.5
41.7
3.7
0.2
6,639.7
+
6.1%
3.3%
1.8%
0.5%
0.4%
0.1%
0.1%
+
5.4%
5.1%
0.2%
0.1%
+
0.7%
0.6%
0.1%
0.0%
100.0%
Sinks
(861.5) (576.6) (1,056.5) (1,064.3) (1,060.9) (1,040.5) (1,015.1) -15.3%
CO2 Flux from Forestsb
Urban Trees
CO2 Flux from Agricultural Soil
Carbon Stocks (99.2) (107.6)
Landfilled Yard Trimmings and Food
Scraps (24.2) (13.2)
(681.1) (378.3) (911.5) (917.5) (911.9) (891.0) (863.1) -13.0%
(57.1) (77.5) (87.8) (89.8) (91.9) (93.9) (95.9) -1.4%
(45.6) (46.1) (46.3) (44.4) (43.4) -0.7%
(11.5) (11.0) (10.9) (11.2) (12.6) -0.2%
Net Emissions
5,320.7 6,537.3 6,158.1 6,104.1 6,203.9 6,021.5 5,624.6 84.7%
1
2
o
5
4
5
6
7
Note: Includes all emissions of CO2, CH4, N2O, HFCs, PFCs, and SF6. Parentheses indicate negative values or sequestration.
Totals may not sum due to independent rounding.
ODS (Ozone Depleting Substances)
+ Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.
a Percent of total emissions for year 2009.
b Includes the effects of net additions to stocks of carbon stored in harvested wood products.
8 Emissions with Electricity Distributed to Economic Sectors
9 It can also be useful to view greenhouse gas emissions from economic sectors with emissions related to electricity
10 generation distributed into end-use categories (i.e., emissions from electricity generation are allocated to the
11 economic sectors in which the electricity is consumed). The generation, transmission, and distribution of electricity,
12 which is the largest economic sector in the United States, accounted for 33 percent of total U.S. greenhouse gas
13 emissions in 2009. Emissions increased by 17 percent since 1990, as electricity demand grew and fossil fuels
14 remained the dominant energy source for generation. Electricity generation-related emissions decreased from 2008
15 to 2009 by 9 percent, primarily due to decreased CO2 emissions from fossil fuel combustion. The decrease in
16 electricity-related emissions was due to decreased economic output and the resulting decrease in electricity demand.
17 Electricity-related emissions also declined due to a decrease in the carbon intensity of fuels used to generate
18 electricity. This was caused by fuel switching as the price of coal increased and the price natural gas decreased
19 significantly. The fuel switching from coal to natural gas and additional electricity generation from other energy
20 sources in 2009, which included a 7 percent increase in hydropower generation from the previous year, resulted in a
21 decrease in carbon intensity, and in turn, a decrease in emissions from electricity generation. The electricity
22 generation sector in the United States is composed of traditional electric utilities as well as other entities, such as
23 power marketers and non-utility power producers. The majority of electricity generated by these entities was
2-18 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 through the combustion of coal in boilers to produce high-pressure steam that is passed through a turbine. Table
2 2-13 provides a detailed summary of emissions from electricity generation-related activities.
3 Table 2-13: Electricity Generation-Related Greenhouse Gas Emissions (Tg CO2 Eq.)
4
5
6
7
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Gas/Fuel Type or Source
C02
CO2 from Fossil Fuel
Combustion
Coal
Natural Gas
Petroleum
Geothermal
Incineration of Waste
Limestone and Dolomite Use
CH4
Stationary Combustion*
Incineration of Waste
N2O
Stationary Combustion*
Incineration of Waste
SF6
Electrical Transmission and
Distribution
Total
1990
1,831.4
1,820.8
1,547.6
175.3
97.5
0.4
8.0
2.6
0.6
0.6
8.5
8.1
0.5
28.4
28.4
1,868.9
2000
2,310.5
2,296.9
1,927.4
280.8
88.4
0.4
11.1
2.5
0.7
0.7
10.4
10.0
0.4
16.0
16.0
2,337.6
2005
2,418.0
2,402.1
1,983.8
318.8
99.2
0.4
12.5
3.4
0.7
0.7
10.7
10.3
0.4
15.1
15.1
2,444.6
2006
2,363.0
2,346.4
1,953.7
338.0
54.4
0.4
12.5
4.0
0.7
0.7
10.5
10.1
0.4
14.1
14.1
2,388.2
2007
2,429.4
2,412.8
1,987.3
371.3
53.9
0.4
12.7
3.9
0.7
0.7
10.6
10.2
0.4
13.2
13.2
2,454.0
2008
2,376.2
2,360.9
1,959.4
361.9
39.2
0.4
12.2
3.1
0.7
0.7
10.4
10.1
0.4
13.3
13.3
2,400.7
2009
2,170.1
2,154.0
1,747.6
373.1
32.9
0.4
12.3
3.8
0.7
0.7
9.4
9.0
0.4
12.8
12.8
2,193.0
Note: Totals may not sum due to independent rounding.
* Includes only stationary combustion emissions related to the generation of electricity.
+ Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.
To distribute electricity emissions among economic end-use sectors, emissions from the source categories assigned
to the electricity generation sector were allocated to the residential, commercial, industry, transportation, and
agriculture economic sectors according to retail sales of electricity (EIA 2010 and Duffield 2006). These three
source categories include CO2 from Fossil Fuel Combustion, CH4 and N2O from Stationary Combustion, and SF6
from Electrical Transmission and Distribution Systems.49
When emissions from electricity are distributed among these sectors, industry activities account for the largest share
of U.S. greenhouse gas emissions (28.9 percent), followed closely by emissions from transportation, which account
for 27.4 percent of total emissions. Emissions from the residential and commercial sectors also increase
substantially when emissions from electricity are included. In all sectors except agriculture, CO2 accounts for more
than 80 percent of greenhouse gas emissions, primarily from the combustion of fossil fuels.
Table 2-14 presents a detailed breakdown of emissions from each of these economic sectors, with emissions from
electricity generation distributed to them. Figure 2-13 shows the trend in these emissions by sector from 1990 to
2009.
Figure 2-13: Emissions with Electricity Distributed to Economic Sectors
Table 2-14: U.S Greenhouse Gas Emissions by Economic Sector and Gas with Electricity-Related Emissions
Distributed (Tg CO2 Eq.) and Percent of Total in 2009
Sector/Gas
Industry
Direct Emissions
1990
2,238.7
1,564.9
2000
2,315.6
1,545.2
2005 2006 2007 2008 2009 Percent3
2,163.5 2,196.1 2,194.4 2,147.6 1,918.9 28.9%
1,442.9 1,498.8 1,484.5 1,448.0 1,330.6 20.0%
49 Emissions were not distributed to U.S. territories, since the electricity generation sector only includes emissions related to the
generation of electricity in the 50 states and the District of Columbia.
Trends in Greenhouse Gas Emissions
2-19
-------
C02
CH4
N2O
MFCs, PFCs, and SF6
Electricity-Related
C02
CH4
N2O
SF6
Transportation
Direct Emissions
C02
CH4
N2O
HFCsb
Electricity -Related
C02
CH4
N2O
SF6
Commercial
Direct Emissions
C02
CH4
N2O
MFCs
Electricity-Related
C02
CH4
N2O
SF6
Residential
Direct Emissions
CO2
CH4
N2O
MFCs
Electricity-Related
C02
CH4
N2O
SF6
Agriculture
Direct Emissions
C02
CH4
N2O
Electricity -Related
C02
CH4
N2O
SF6
U.S. Territories
Total
1,140.9
318.8
41.8
63.3
673.9
660.3
0.2
3.1
10.2
1,548.3
1,545.2
1,497.8
4.5
42.95
+
3.1
3.1
+
+
+
947.7
395.5
219.0
172.1
4.4
+
552.2
541.1
0.2
2.5
8.4
953.8
345.1
338.3
4.4
2.1
0.3
608.7
596.5
0.2
2.8
9.2
460.01
429.0
39.2
174.5
215.3
31.0
30.4
+
0.1
0.5
33.7
6,182.2
1,149.1
312.5
34.0
49.6
770.4
761.5
0.2
3.4
5.3
1,935.8
1,932.3
1,821.6
3.1
51.95
55.7
3.5
3.5
+
+
+
1,135.8
381.4
230.8
139.0
6.2
5.4
754.4
745.7
0.2
3.3
5.2
1,162.2
386.2
370.7
3.4
2.1
10.1
775.9
767.0
0.2
3.4
5.3
518.41
485.1
47.6
201.1
236.4
33.3
32.9
+
0.1
0.2
46.0
7,113.9
1,094.8
285.7
30.0
32.5
720.5
712.7
0.2
3.2
4.5
2,022.2
2,017.4
1,906.8
2.2
35.47
72.9
4.8
4.8
+
+
+
1,205.1
387.2
223.5
139.3
6.8
17.6
817.9
809.0
0.2
3.6
5.1
1,242.8
371.0
357.9
3.4
2.4
7.3
871.9
862.4
0.3
3.8
5.4
522.66
493.2
55.7
200.1
237.4
29.4
29.1
+
0.1
0.2
58.2
7,214.5
1,124.6
314.1
29.1
31.0
697.3
689.9
0.2
3.1
4.1
1,999.0
1,994.4
1,888.0
2.0
32.12
72.2
4.6
4.6
+
+
+
1,188.5
375.2
208.6
138.7
6.9
21.1
813.2
804.7
0.2
3.6
4.8
1,181.4
335.8
321.5
3.1
2.3
8.9
845.6
836.7
0.3
3.7
5.0
544.07
516.7
57.8
213.4
245.4
27.4
27.1
+
0.1
0.2
59.3
7,168.4
1,115.2
301.9
31.4
36.0
709.9
702.8
0.2
3.1
3.8
2,008.9
2,003.7
1,904.2
1.9
28.77
68.8
5.1
5.1
+
+
+
1,225.3
389.6
219.4
138.2
7.1
25.0
835.7
827.4
0.2
3.6
4.5
1,229.5
358.8
342.4
3.4
2.4
10.6
870.7
862.0
0.3
3.8
4.7
553.20
520.7
57.7
218.4
244.7
32.5
32.2
+
0.1
0.2
53.5
7,264.8
Note: Emissions from electricity generation are allocated based on aggregate electricity
1,071.2
318.1
26.8
31.9
699.7
692.5
0.2
3.0
3.9
1,895.4
1,890.7
1,799.4
1.7
24.64
64.9
4.7
4.7
+
+
+
1,224.5
403.5
224.2
143.1
7.2
29.1
821.0
812.7
0.2
3.6
4.6
1,214.8
366.8
348.2
3.5
2.4
12.6
848.1
839.4
0.2
3.7
4.7
531.12
503.9
55.1
209.6
239.2
27.2
26.9
+
0.1
0.2
48.4
7,061.9
950.6
331.2
24.5
24.2
588.3
582.2
0.2
2.5
3.4
1,820.3
1,815.8
1,727.4
1.9
26.27
60.2
4.5
4.5
+
+
+
1,179.7
404.3
218.8
144.5
7.2
33.7
775.4
767.4
0.2
3.3
4.5
1,159.3
360.5
340.2
3.4
2.4
14.5
798.8
790.5
0.2
3.4
4.7
515.98
490.0
55.6
204.8
229.7
25.9
25.7
+
0.1
0.2
45.5
6,639.7
14.3%
5.0%
0.4%
0.4%
8.9%
8.8%
+
+
0.1%
27.4%
27.3%
26.0%
+
0.4%
0.9%
0.1%
0.1%
+
+
+
17.8%
6.1%
3.3%
2.2%
0.1%
0.5%
11.7%
11.6%
+
+
0.1%
17.5%
5.4%
5.1%
0.1%
+
0.2%
12.0%
11.9%
+
0.1%
0.1%
7.8%
7.4%
0.8%
3.1%
3.5%
0.4%
0.4%
+
+
+
0.7%
100.0%
r consumption in each end-use sector.
2-20 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Totals may not sum due to independent rounding.
2 + Does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.
3 a Percent of total emissions for year 2009.
4 b Includes primarily HFC-134a.
5
6 Industry
7 The industrial end-use sector includes CO2 emissions from fossil fuel combustion from all manufacturing facilities,
8 in aggregate. This sector also includes emissions that are produced as a by-product of the non-energy-related
9 industrial process activities. The variety of activities producing these non-energy-related emissions includes
10 methane emissions from petroleum and natural gas systems, fugitive CH4 emissions from coal mining, by-product
11 CO2 emissions from cement manufacture, and HFC, PFC, and SF6 by-product emissions from semiconductor
12 manufacture, to name a few. Since 1990, industrial sector emissions have declined. The decline has occurred both
13 in direct emissions and indirect emissions associated with electricity use, however, the decline in direct emissions
14 has been sharper. In theory, emissions from the industrial end-use sector should be highly correlated with economic
15 growth and industrial output, but heating of industrial buildings and agricultural energy consumption are also
16 affected by weather conditions. In addition, structural changes within the U.S. economy that lead to shifts in
17 industrial output away from energy-intensive manufacturing products to less energy-intensive products (e.g., from
18 steel to computer equipment) also have a significant effect on industrial emissions.
19 Transportation
20 When electricity-related emissions are distributed to economic end-use sectors, transportation activities accounted
21 for 27 percent of U.S. greenhouse gas emissions in 2009. The largest sources of transportation GHGs in 2009 were
22 passenger cars (34 percent), light duty trucks, which include sport utility vehicles, pickup trucks, and minivans (30
23 percent), freight trucks (21 percent) and commercial aircraft (6 percent). These figures include direct emissions
24 from fossil fuel combustion, as well as HFC emissions from mobile air conditioners and refrigerated transport
25 allocated to these vehicle types. From 2008 to 2009, CO2 emissions from the transportation end-use sector declined
26 4 percent. The decrease in emissions can largely be attributed to decreased economic activity in 2009 and an
27 associated decline in the demand for transportation. Modes such as medium- and heavy-duty trucks were
28 significantly impacted by the decline in freight transport. Similarly, increased jet fuel prices were a factor in the 19
29 percent decrease in commercial aircraft emissions since 2007.
30 Almost all of the energy consumed for transportation was supplied by petroleum-based products, with more than
31 half being related to gasoline consumption in automobiles and other highway vehicles. Other fuel uses, especially
32 diesel fuel for freight trucks and jet fuel for aircraft, accounted for the remainder. The primary driver of
33 transportation-related emissions was CO2 from fossil fuel combustion, which increased by 18 percent from 1990 to
34 2009. This rise in CO2 emissions, combined with an increase in HFCs from close to zero emissions in 1990 to 60.2
35 Tg CO2 Eq. in 2009, led to an increase in overall emissions from transportation activities of 18 percent. From 2008
36 to 2009, CO2 emissions from the transportation end-use sector declined 4 percent. The decrease in emissions can
37 largely be attributed to decreased economic activity in 2009 and an associated decline in the demand for
38 transportation. Modes such as medium- and heavy-duty trucks were significantly impacted by the decline in freight
39 transport. Similarly, increased jet fuel prices were a factor in the 19 percent decrease in commercial aircraft
40 emissions since 2007.
41 Almost all of the energy consumed for transportation was supplied by petroleum-based products, with more than
42 half being related to gasoline consumption in automobiles and other highway vehicles. Other fuel uses, especially
43 diesel fuel for freight trucks and jet fuel for aircraft, accounted for the remainder. The primary driver of
44 transportation-related emissions was CO2 from fossil fuel combustion, which increased by 18 percent from 1990 to
45 2009. This rise in CO2 emissions, combined with an increase in HFCs from close to zero emissions in 1990 to 60.2
46 Tg CO2 Eq. in 2009, led to an increase in overall emissions from transportation activities of 18 percent.
47 Table 2-15 provides a detailed summary of greenhouse gas emissions from transportation-related activities with
48 electricity-related emissions included in the totals.
49 From 1990 to 2009, transportation emissions rose by 18 percent due, in large part, to increased demand for travel
50 and the stagnation of fuel efficiency across the U.S. vehicle fleet. The number of vehicle miles traveled by light-
51 duty motor vehicles (passenger cars and light-duty trucks) increased 38 percent from 1990 to 2009, as a result of a
Trends in Greenhouse Gas Emissions 2-21
-------
1 confluence of factors including population growth, economic growth, urban sprawl, and low fuel prices over much
2 of this period.
3 From 2008 to 2009, CO2 emissions from the transportation end-use sector declined 4 percent. The decrease in
4 emissions can largely be attributed to decreased economic activity in 2009 and an associated decline in the demand
5 for transportation. Modes such as medium- and heavy-duty trucks were significantly impacted by the decline in
6 freight transport. Similarly, increased jet fuel prices were a factor in the 19 percent decrease in commercial aircraft
7 emissions since 2007.
8 Almost all of the energy consumed for transportation was supplied by petroleum-based products, with more than
9 hah0being related to gasoline consumption in automobiles and other highway vehicles. Other fuel uses, especially
10 diesel fuel for freight trucks and jet fuel for aircraft, accounted for the remainder. The primary driver of
11 transportation-related emissions was CO2 from fossil fuel combustion, which increased by 18 percent from 1990 to
12 2009. This rise in CO2 emissions, combined with an increase in HFCs from close to zero emissions in 1990 to 60.2
13 Tg CO2 Eq. in 2009, led to an increase in overall emissions from transportation activities of 18 percent.
14 Table 2-15: Transportation-Related Greenhouse Gas Emissions (Tg CO2 Eq.)
Gas/Vehicle Type
Passenger Cars
C02
CH4
N2O
HFCs
Light-Duty Trucks
CO2
CH4
N2O
HFCs
Medium- and Heavy-
Duty Trucks
C02
CH4
N2O
HFCs
Buses
C02
CH4
N2O
HFCs
Motorcycles
C02
CH4
N2O
Commercial Aircraft"
C02
CH4
N2O
Other Aircraft11
CO2
CH4
N2O
Ships and Boats0
C02
CH4
N2O
HFCs
Rail
1990
657.4
629.3
2.6
25.4
+
336.6
321.1
1.4
14.1
+
231.1
230.1
0.2
0.8
+
8.4
8.4
+
+
+
1.8
1.7
+
+
136.8
135.4
0.1
1.3
44.4
43.9
0.1
0.4
45.1
44.5
+
0.6
+
39.0
2000
695.3
644.2
1.6
25.2
24.3
512.1
467.0
1.1
22.4
21.7
354.6
345.8
0.1
1.2
7.4
11.2
11.1
+
+
0.1
1.9
1.8
+
+
170.9
169.2
0.1
1.6
33.5
33.1
0.1
0.3
61.0
60.0
+
0.9
0.1
48.1
2005
709.5
662.3
1.1
17.8
28.4
551.3
505.9
0.7
13.7
31.0
408.4
396.0
0.1
1.1
11.1
12.0
11.8
+
+
0.2
1.7
1.6
+
+
162.8
161.2
0.1
1.5
35.9
35.5
0.1
0.3
45.2
44.5
+
0.6
+
53.0
2006
682.9
639.1
1.0
15.7
27.1
564.0
519.5
0.7
12.6
31.2
418.6
406.1
0.1
1.1
11.4
12.3
12.0
+
+
0.3
1.9
1.9
+
+
138.5
137.1
0.1
1.3
35.1
34.7
0.1
0.3
48.4
47.7
+
0.7
+
55.1
2007
672.0
632.8
0.9
13.8
24.6
570.3
528.4
0.6
11.2
30.1
425.2
412.5
0.1
1.1
11.5
12.5
12.1
+
+
0.3
2.1
2.1
+
+
139.5
138.1
0.1
1.3
33.2
32.8
0.1
0.3
55.2
54.4
+
0.8
+
54.3
2008
632.5
597.9
0.8
11.7
22.1
553.8
515.1
0.6
9.5
28.6
403.1
390.4
0.1
1.0
11.6
12.2
11.8
+
+
0.4
2.2
2.1
+
+
123.4
122.2
0.1
1.2
35.2
34.8
0.1
0.3
37.1
36.6
+
0.5
+
50.6
2009
627.5
595.3
0.9
12.0
19.3
549.3
510.9
0.7
11.1
26.6
371.9
359.1
0.1
1.1
11.6
11.3
10.9
+
+
0.4
2.2
2.1
+
+
112.5
111.4
0.1
1.1
29.6
29.3
+
0.3
28.9
28.5
+
0.4
+
43.3
2-22 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
C02
CH4
N2O
MFCs
Other Emissions from
Electricity
Generation"1
Pipelines6
C02
Lubricants
CO2
Total Transportation
International Bunker
Fuel/
38.5
0.1
0.3
+
0.1
36.0
36.0
11.8
11.8
1,548.3
113.0
45.6
0.1
0.3
2.0
+
35.2
35.2
12.1
12.1
1,935.8
99.5
50.3
0.1
0.4
2.2
0.1
32.2
32.2
10.2
10.2
2,022.2
110.9
52.4
0.1
0.4
2.2
0.1
32.3
32.3
9.9
9.9
1,999.0
129.7
51.6
0.1
0.4
2.2
0.1
34.3
34.3
10.2
10.2
2,008.9
129.0
47.9
0.1
0.4
2.3
0.1
35.7
35.7
9.5
9.5
1,895.4
135.1
40.6
0.1
0.3
2.3
0.1
35.2
35.2
8.5
8.5
1,820.3
124.5
1 Note: Totals may not sum due to independent rounding. Passenger cars and light-duty trucks include vehicles typically used for
2 personal travel and less than 8500 Ibs; medium- and heavy-duty trucks include vehicles larger than 8500 Ibs. HFC emissions
3 primarily reflect HFC-134a.
4 + Does not exceed 0.05 Tg CO2 Eq.
5 a Consists of emissions from jet fuel consumed by domestic operations of commercial aircraft (no bunkers).
6 b Consists of emissions from jet fuel and aviation gasoline consumption by general aviation and military aircraft.
7 ° Fluctuations in emission estimates are associated with fluctuations in reported fuel consumption, and may reflect data collection
8 problems.
9 Other emissions from electricity generation are a result of waste incineration (as the majority of municipal solid waste is
10 combusted in "trash-to-steam" electricity generation plants), electrical transmission and distribution, and a portion of limestone
11 and dolomite use (from pollution control equipment installed in electricity generation plants).
12 e CO2 estimates reflect natural gas used to power pipelines, but not electricity. While the operation of pipelines produces CH4 and
13 N2O, these emissions are not directly attributed to pipelines in the US Inventory.
14 f Emissions from International Bunker Fuels include emissions from both civilian and military activities; these emissions are not
15 included in the transportation totals.
16
17 Commercial
18 The commercial sector is heavily reliant on electricity for meeting energy needs, with electricity consumption for
19 lighting, heating, air conditioning, and operating appliances. The remaining emissions were largely due to the direct
20 consumption of natural gas and petroleum products, primarily for heating and cooking needs. Energy-related
21 emissions from the residential and commercial sectors have generally been increasing since 1990, and are often
22 correlated with short-term fluctuations in energy consumption caused by weather conditions, rather than prevailing
23 economic conditions. Landfills and wastewater treatment are included in this sector, with landfill emissions
24 decreasing since 1990 and wastewater treatment emissions increasing slightly.
25 Residential
26 The residential sector is heavily reliant on electricity for meeting energy needs, with electricity consumption for
27 lighting, heating, air conditioning, and operating appliances. The remaining emissions were largely due to the direct
28 consumption of natural gas and petroleum products, primarily for heating and cooking needs. Emissions from the
29 residential sectors have generally been increasing since 1990, and are often correlated with short-term fluctuations in
30 energy consumption caused by weather conditions, rather than prevailing economic conditions. In the long-term,
31 this sector is also affected by population growth, regional migration trends, and changes in housing and building
32 attributes (e.g., size and insulation).
33 Agriculture
34 The agriculture sector includes a variety of processes, including enteric fermentation in domestic livestock, livestock
35 manure management, and agricultural soil management. In 2009, agricultural soil management was the largest
36 source of N2O emissions, and enteric fermentation was the second largest source of CH4 emissions in the United
37 States. This sector also includes small amounts of CO2 emissions from fossil fuel combustion by motorized farm
38 equipment like tractors. The agriculture sector relies less heavily on electricity than the other sectors.
Trends in Greenhouse Gas Emissions 2-23
-------
1
2 [BEGIN BOX]
o
J
4 Box 2-1: Methodology for Aggregating Emissions by Economic Sector
5
6 In presenting the Economic Sectors in the annual Inventory of U.S. Greenhouse Gas Emissions and Sinks, the
7 Inventory expands upon the standard IPCC sectors common for UNFCCC reporting. Discussing greenhouse gas
8 emissions relevant to U.S.-specific sectors improves communication of the report's findings.
9 In the Electricity Generation economic sector, CO2 emissions from the combustion of fossil fuels included in the
10 El A electric utility fuel consuming sector are apportioned to this economic sector. Stationary combustion emissions
11 of CH4 and N2O are also based on the EIA electric utility sector. Additional sources include CO2, CH4 and N2O
12 from waste incineration, as the majority of municipal solid waste is combusted in "trash-to-steam" electricity
13 generation plants. The Electricity Generation economic sector also includes SF6 from Electrical Transmission and
14 Distribution, and a portion of CO2 from Limestone and Dolomite Use (from pollution control equipment installed in
15 electricity generation plants).
16 In the Transportation economic sector, the CO2 emissions from the combustion of fossil fuels included in the EIA
17 transportation fuel consuming sector are apportioned to this economic sector (additional analyses and refinement of
18 the EIA data is further explained in the Energy chapter of this report). Additional emissions are apportioned from
19 the CH4 and N2O from Mobile Combustion, based on the EIA transportation sector. Substitutes of Ozone Depleting
20 Substitutes are apportioned based on their specific end-uses within the source category, with emissions from
21 transportation refrigeration/air-conditioning systems to this economic sector. Finally, CO2 emissions from Non-
22 Energy Uses of Fossil Fuels identified as lubricants for transportation vehicles are included in the Transportation
23 economic sector.
24 For the Industry economic sector, the CO2 emissions from the combustion of fossil fuels included in the EIA
25 industrial fuel consuming sector, minus the agricultural use of fuel explained below, are apportioned to this
26 economic sector. Stationary and mobile combustion emissions of CH4 and N2O are also based on the EIA industrial
27 sector, minus emissions apportioned to the Agriculture economic sector described below. Substitutes of Ozone
28 Depleting Substitutes are apportioned based on their specific end-uses within the source category, with most
29 emissions falling within the Industry economic sector (minus emissions from the other economic sectors).
30 Additionally, all process-related emissions from sources with methods considered within the IPCC Industrial
31 Process guidance have been apportioned to this economic sector. This includes the process-related emissions (i.e.,
32 emissions from the actual process to make the material, not from fuels to power the plant) from such activities as
33 Cement Production, Iron and Steel Production and Metallurgical Coke Production, and Ammonia Production.
34 Additionally, fugitive emissions from energy production sources, such as Natural Gas Systems, Coal Mining, and
35 Petroleum Systems are included in the Industry economic sector. A portion of CO2 from Limestone and Dolomite
36 Use (from pollution control equipment installed in large industrial facilities) are also included in the Industry
37 economic sector. Finally, all remaining CO2 emissions from Non-Energy Uses of Fossil Fuels are assumed to be
38 industrial in nature (besides the lubricants for transportation vehicles specified above), and are attributed to the
39 Industry economic sector.
40 As agriculture equipment is included in EIA's industrial fuel consuming sector surveys, additional data is used to
41 extract the fuel used by agricultural equipment, to allow for accurate reporting in the Agriculture economic sector
42 from all sources of emissions, such as motorized farming equipment. Energy consumption estimates are obtained
43 from Department of Agriculture survey data, in combination with separate EIA fuel sales reports. This
44 supplementary data is used to apportion CO2 emissions from fossil fuel combustion, and CH4 and N2O emissions
45 from stationary and mobile combustion (all data is removed from the Industrial economic sector, to avoid double-
46 counting). The other emission sources included in this economic sector are intuitive for the agriculture sectors, such
47 as N2O emissions from Agricultural Soils, CH4 from Enteric Fermentation (i.e., exhalation from the digestive tracts
48 of domesticated animals), CH4 and N2O from Manure Management, CH4 from Rice Cultivation, CO2 emissions
49 from Liming of Agricultural Soils and Urea Application, and CH4 and N2O from Forest Fires. N2O emissions from
50 the Application of Fertilizers to tree plantations (termed "forest land" by the IPCC) are also included in the
51 Agriculture economic sector.
2-24 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 The Residential economic sector includes the CO2 emissions from the combustion of fossil fuels reported for the
2 EIA residential sector. Stationary combustion emissions of CH4 and N2O are also based on the EIA residential fuel
3 consuming sector. Substitutes of Ozone Depleting Substitutes are apportioned based on their specific end-uses
4 within the source category, with emissions from residential air-conditioning systems to this economic sector. N2O
5 emissions from the Application of Fertilizers to developed land (termed "settlements" by the IPCC) are also
6 included in the Residential economic sector.
7 The Commercial economic sector includes the CO2 emissions from the combustion of fossil fuels reported in the
8 EIA commercial fuel consuming sector data. Stationary combustion emissions of CH4 and N2O are also based on the
9 EIA commercial sector. Substitutes of Ozone Depleting Substitutes are apportioned based on their specific end-uses
10 within the source category, with emissions from commercial refrigeration/air-conditioning systems to this economic
11 sector. Public works sources including direct CH4 from Landfills and CH4 and N2O from Wastewater Treatment and
12 Composting are included in this economic sector.
13
14 [END BOX]
15
16 [BEGIN BOX]
17
18 Box 2-2: Recent Trends in Various U.S. Greenhouse Gas Emissions-Related Data
19
20 Total emissions can be compared to other economic and social indices to highlight changes over time. These
21 comparisons include: (1) emissions per unit of aggregate energy consumption, because energy-related activities are
22 the largest sources of emissions; (2) emissions per unit of fossil fuel consumption, because almost all energy-related
23 emissions involve the combustion of fossil fuels; (3) emissions per unit of electricity consumption, because the
24 electric power industry—utilities and non-utilities combined—was the largest source of U.S. greenhouse gas
25 emissions in 2009; (4) emissions per unit of total gross domestic product as a measure of national economic activity;
26 or (5) emissions per capita.
27 Table 2-16 provides data on various statistics related to U.S. greenhouse gas emissions normalized to 1990 as a
28 baseline year. Greenhouse gas emissions in the United States have grown at an average annual rate of 0.4 percent
29 since 1990. This rate is slightly slower than that for total energy consumption and growth in national population
30 since 1990 and much slower than that for electricity consumption and overall gross domestic product, respectively.
31 Total U.S. greenhouse gas emissions are growing at a rate similar to that of fossil fuel consumption since 1990 (see
32 Table 2-16).
33 Table 2-16: Recent Trends in Various U.S. Data (Index 1990 = 100)
Variable
GDPb
Electricity Consumption0
Fossil Fuel Consumption0
Energy Consumption0
Population"1
Greenhouse Gas Emissions6
1990
100
100
100
100
100
100
2000
140
127
117
116
113
115
2005
157
134
119
118
118
117
2006
162
135
117
118
120
116
2007
165
138
119
120
121
118
2008
165
138
116
118
122
114
2009
160
132
108
112
123
107
Growth
Rate"
2.5%
1.5%
0.5%
0.6%
1.1%
0.4%
34 a Average annual growth rate
3 5 b Gross Domestic Product in chained 2005 dollars (BEA 2010)
36 ° Energy-content-weighted values (EIA 2010)
37 d U.S. Census Bureau (2010)
3 8 e GWP-weighted values
39
40
41 Figure 2-14: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product
42 Source: BEA (2010), U.S. Census Bureau (2010), and emission estimates in this report.
Trends in Greenhouse Gas Emissions 2-25
-------
[END BOX]
4 2.3. Indirect Greenhouse Gas Emissions (CO, NOX, NMVOCs, and SO^ - TO BE
5 UPDATED
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
The reporting requirements of the UNFCCC50 request that information be provided on indirect greenhouse gases,
which include CO, NOX, NMVOCs, and SO2. These gases do not have a direct global warming effect, but indirectly
affect terrestrial radiation absorption by influencing the formation and destruction of tropospheric and stratospheric
ozone, or, in the case of SO2, by affecting the absorptive characteristics of the atmosphere. Additionally, some of
these gases may react with other chemical compounds in the atmosphere to form compounds that are greenhouse
gases. Carbon monoxide is produced when carbon-containing fuels are combusted incompletely. Nitrogen oxides
(i.e., NO and NO2) are created by lightning, fires, fossil fuel combustion, and in the stratosphere from N2O. Non-
CH4 volatile organic compounds—which include hundreds of organic compounds that participate in atmospheric
chemical reactions (i.e., propane, butane, xylene, toluene, ethane, and many others)—are emitted primarily from
transportation, industrial processes, and non-industrial consumption of organic solvents. In the United States, SO2 is
primarily emitted from coal combustion for electric power generation and the metals industry. Sulfur-containing
compounds emitted into the atmosphere tend to exert a negative radiative forcing (i.e., cooling) and therefore are
discussed separately.
One important indirect climate change effect of NMVOCs and NOX is their role as precursors for tropospheric ozone
formation. They can also alter the atmospheric lifetimes of other greenhouse gases. Another example of indirect
greenhouse gas formation into greenhouse gases is CO's interaction with the hydroxyl radical—the major
atmospheric sink for CH4 emissions—to form CO2. Therefore, increased atmospheric concentrations of CO limit
the number of hydroxyl molecules (OH) available to destroy CH4.
Since 1970, the United States has published estimates of annual emissions of CO, NOX, NMVOCs, and SO2 (EPA
2009),51 which are regulated under the Clean Air Act. Table 2-17 shows that fuel combustion accounts for the
majority of emissions of these indirect greenhouse gases. Industrial processes—such as the manufacture of
chemical and allied products, metals processing, and industrial uses of solvents—are also significant sources of CO,
NOX, and NMVOCs.
Table 2-17: Emissions of NOX, CO,
Gas/Activity
NOX
Mobile Fossil Fuel Combustion
Stationary Fossil Fuel Combustion
Industrial Processes
Oil and Gas Activities
Incineration of Waste
Agricultural Burning
Solvent Use
Waste
CO
Mobile Fossil Fuel Combustion
Stationary Fossil Fuel Combustion
Industrial Processes
Incineration of Waste
NMVOCs, and SO2 (Gg)
1990
21,728
10,862
10,023
591
139
82
;
130,536
119,360
5,000
4,125
978
2000
19
10
,145
,199
8,053
626
111
114
1
92,872
83
4
2
1
,559
,340
,216
,670
2005
15,933
9
5
71
,012
,858
569
321
129
1
,555
62,692
4
1
1
,649
,555
,403
2006
15,071
8
5
,488
,545
553
319
121
1
67,909
58
4
1
1
,972
,695
,597
,412
2007
14,410
7
5
,965
,432
537
318
114
1
64,348
55
4
1
1
,253
,744
,640
,421
2008 2009
13,578
7
5
60
51
4
1
1
,441
,148
520
318
106
1
,739
,533
,792
,682
,430
50 See .
from EPA (2009).
2-26 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1
2
o
6
4
5
6
7
Agricultural Burning
Oil and Gas Activities
Waste
Solvent Use
NMVOCs
Mobile Fossil Fuel Combustion
Solvent Use
Industrial Processes
Stationary Fossil Fuel Combustion
Oil and Gas Activities
Incineration of Waste
Waste
Agricultural Burning
S02
Stationary Fossil Fuel Combustion
Industrial Processes
Mobile Fossil Fuel Combustion
Oil and Gas Activities
Incineration of Waste
Waste
Solvent Use
Agricultural Burning
Source: (EPA 2009) except for estimates
NA (Not Available)
766
302
1
5
20,930
10,932
5,216
2,422
912
554
222
673
NA
20,935
18,407
1,307
793
390
38
o
0
NA
888
146
8
45
15,227
7,229
4,384
1,773
1,077
388
257
119
NA
14,830
12,849
1,031
632
287
29
1
1
NA
930
318
7
|
13,761
6,330
3,851
1,997
716
510
241
114
NA
13,466
11,541
831
889
181
24
1
0
905
319
7
|
13,594
6,037
3,846
1,933
918
510
238
113
NA
12,388
10,612
818
750
182
24
1
0
960
320
7
|
13,423
5,742
3,839
1,869
1,120
509
234
111
NA
11,799
10,172
807
611
184
24
1
0
970
322
7
|
13,254
5,447
3,834
1,804
1,321
509
230
109
NA
10,368
8,891
795
472
187
23
1
0
NA NA NA NA
from field burning of agricultural residues.
Note: Totals may not sum due to independent rounding.
[BEGIN BOX]
Box 2-3 : Sources and Effects of Sulfur Dioxide
9 Sulfur dioxide (SO2) emitted into the atmosphere through natural and anthropogenic processes affects the earth's
10 radiative budget through its photochemical transformation into sulfate aerosols that can (1) scatter radiation from the
11 sun back to space, thereby reducing the radiation reaching the earth's surface; (2) affect cloud formation; and (3)
12 affect atmospheric chemical composition (e.g., by providing surfaces for heterogeneous chemical reactions). The
13 indirect effect of sulfur-derived aerosols on radiative forcing can be considered in two parts. The first indirect effect
14 is the aerosols' tendency to decrease water droplet size and increase water droplet concentration in the atmosphere.
15 The second indirect effect is the tendency of the reduction in cloud droplet size to affect precipitation by increasing
16 cloud lifetime and thickness. Although still highly uncertain, the radiative forcing estimates from both the first and
17 the second indirect effect are believed to be negative, as is the combined radiative forcing of the two (IPCC 2001).
18 However, because SO2 is short-lived and unevenly distributed in the atmosphere, its radiative forcing impacts are
19 highly uncertain.
20 Sulfur dioxide is also a major contributor to the formation of regional haze, which can cause significant increases in
21 acute and chronic respiratory diseases. Once SO2 is emitted, it is chemically transformed in the atmosphere and
22 returns to the earth as the primary source of acid rain. Because of these harmful effects, the United States has
23 regulated SO2 emissions in the Clean Air Act.
24 Electricity generation is the largest anthropogenic source of SO2 emissions in the United States, accounting for 86
25 percent in 2008. Coal combustion contributes nearly all of those emissions (approximately 92 percent). Sulfur
26 dioxide emissions have decreased in recent years, primarily as a result of electric power generators switching from
27 high-sulfur to low-sulfur coal and installing flue gas desulfurization equipment.
28
29 [END BOX]
Trends in Greenhouse Gas Emissions
2-27
-------
O
8,000
7,000
6,000 -
5,000
4,000
3,000
2,000
1,000
0
• MFCs, PFCs, &SF6
Nitrous Oxide
Methane
• Carbon Dioxide
6,182 6,142 6,245
6,640
oooooooooo
(N(N(N(N(N(N(N(N(N(N
Figure 2-1: U.S. Greenhouse Gas Emissions by Gas
4% -,
3.3%
2.8%
2% -
1.6% 1.3%
0.6% 0.4% II 0.5%
-6.0%
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
Figure 2-2: Annual Percent Change in U.S. Greenhouse Gas Emissions
932
Figure 2-3: Cumulative Change in Annual U.S. Greenhouse Gas Emissions Relative to 1990
1,100 -,
1,000 -
900 -
800 -
d- 700 -
"i 600 -
0 500 -
™ 400 -
H 300 -
200 -
100 -
0 -
-100 J
~^H
-40
-------
7,500
7,000
6,500
6,000
5,500
5,000
4,500
ci- 4,000
"i 3,500
<-> 3,000
F 2,500
2,000
1,500
1,000
500
(500) -
(1,000) -1
Industrial Processes
Waste
LULUCF (sources)
Agriculture
Energy
Land Use, Land-Use Change and Forestry (sinks)
s
a
§ §
Note: Relatively smaller amounts of GWP-weighted emissions are also emitted from the Solvent and Other Product
Use sector
Figure 2-4: U.S. Greenhouse Gas Emissions and Sinks by Chapter/IPCC Sector
Fossil Fuel Combustion
Natural Gas Systems
Non-Energy Use of Fuels
Coal Mining
Petroleum Systems |
Mobile Combustion |
Stationary Combustion |
Incineration of Waste |
Abandoned Underground Coal Mines |
5,212
Energy as a Portion
of all Emissions
50
100 150 200
Tg CO2 Eq.
250 300
Figure 2-5: 2009 Energy Sector Greenhouse Gas Sources
-------
Natural Gas Emissions
1,209
NEU Emissions 51
Non-Energy Use
Carbon Sequestered
184
Fossil Fue
Non-Energy Consumption
Use imports U.S.
47 Territories
40
Non-Energy
Use U.S.
Territories
9
Balancing item
160
Note: Totals may not sum due to independent rounding.
The "Balancing Item" above accounts for the statistical imbalances
and unknowns in the reported data sets combined here.
2-6 2009 U.S. (Tg C02 Eq.)
-------
2,500 -|
2,000 -
fi" 1,500 -
O
CT 1,000 -
h-
500 -
0 -
Relative Contribution
by Fuel Type
42
219
O
U
Petroleum
• Coal
• Natural Gas
340
738
2,154
1,719
£-0
Figure 2-7: 2009 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
Note: Electricity generation also includes emissions of less than 0.5 Tg CO 2 Eq. from geothermal-based electricity
generation.
2,000 -|
1,500 -
8 1,000 -
500 -
0 J
From Direct Fossil Fuel Combustion
• From Electricity Consumption
985
42
1,348
1,133
1,751
Figure 2-8: 2009 End-Use Sector Emissions from Fossil Fuel Combustion
-------
Substitution of Ozone Depleting Substances
Iron and Steel Production & Metallurgical Coke Production
Cement Production
Nitric Acid Production
Electrical Transmission and Distribution
Ammonia Production and Urea Application
Lime Production
Limestone and Dolomite Use
HCFC-22 Production
Semiconductor Manufacture
Aluminum Production
Soda Ash Production and Consumption
Petrochemical Production
Adipic Acid Production
Carbon Dioxide Consumption
Ferroalloy Production
Titanium Dioxide Production
Magnesium Production and Processing
Phosphoric Acid Production
Zinc Production
119
Lead Production |
Silicon Carbide Production and Consumption < °-5
Industrial Processes
as a Portion of all Emissions
4.3%
10 20 30 40
TgCO2Eq.
50
Figure 2-9: 2009 Industrial Processes Chapter Greenhouse Gas Sources
Agricultural Soil Management
Enteric Fermentation
Manure Management
Rice Cultivation I
Field Burning of Agricultural Residues < 0.5
205
Agriculture as a Portion of all
Emissions
6.3%
©
0 50 100
TgCO2Eq.
Figure 2-10: 2009 Agriculture Chapter Greenhouse Gas Sources
150
-------
Landfills
Wastewater Treatment
Composting
Waste as a Portion of all Emissions
2.3%
I
0 25 50 75
TgCO2Eq.
Figure 2-11: 2009 Waste Chapter Greenhouse Gas Sources
100 125
2,500 -|
2,000 -
ff 1-500 -
8
P 1,000 -
500 -
Electric
Power Industry
Transportation
Industry
Agriculture
! Commercial
Residential
Figure 2-12: Emissions Allocated to Economic Sectors
Note: Does not include U.S. Territories.
-------
2,500 -
2,000 -
1,500 -
O
<-> 1,000 -
500 -
Industry
Transportation
Commercial (gray)
Residential (black)
Agriculture
Figure 2-13: Emissions with Electricity Distributed to Economic Sectors
Real GDP
Population
Emissions
per capita
Emissions
per $GDP
iHrsim^-m^Dixcooi
ooooooooo
rsirsirsirsirsirsirsirsirsi
Figure 2-14: U.S. Greenhouse Gas Emissions Per Capita and Per Dollar of Gross Domestic Product
-------
i 6. bnergy
2
3 Energy-related activities were the primary sources of U.S. anthropogenic greenhouse gas emissions, accounting for
4 86.7 percent of total emissions on a carbon dioxide (CO2) equivalent basis in 2009. This included 98, 49, and 14
5 percent of the nation's CO2, methane (CH4), and nitrous oxide (N2O) emissions, respectively. Energy -related CO2
6 emissions alone constituted 8 1 percent of national emissions from all sources on a CO2 equivalent basis, while the
7 non-CO2 emissions from energy -related activities represented a much smaller portion of total national emissions (5.7
8 percent collectively).
9 Emissions from fossil fuel combustion comprise the vast majority of energy -related emissions, with CO2 being the
10 primary gas emitted (see Figure 3-1). Globally, approximately 30,398 Tg of CO2 were added to the atmosphere
1 1 through the combustion of fossil fuels in 2009, of which the United States accounted for about 17 percent.52 Due to
12 their relative importance, fossil fuel combustion-related CO2 emissions are considered separately, and in more detail
13 than other energy-related emissions (see Figure 3-2). Fossil fuel combustion also emits CH4 and N2O and mobile
14 fossil fuel combustion was the second largest source of N2O emissions in the United States.
15
16 Figure 3-1: 2009 Energy Chapter Greenhouse Gas Sources
17
18 Figure 3-2: 2009 U.S. Fossil Carbon Flows (Tg CO2 Eq.)
19
20 Energy-related activities other than fuel combustion, such as the production, transmission, storage, and distribution
21 of fossil fuels, also emit greenhouse gases. These emissions consist primarily of fugitive CH4 from natural gas
22 systems, petroleum systems, and coal mining.
23 Table 3-1 summarizes emissions from the Energy sector in units of teragrams of CO2 equivalents (Tg CO2 Eq.),
24 while unweighted gas emissions in gigagrams (Gg) are provided in Table 3-2. Overall, emissions due to energy-
25 related activities were 5,757.0 Tg CO2 Eq. in 2009, an increase of 9 percent since 1990.
26 Table 3-1: CO2, CH4, and N2O Emissions from Energy (TgCO2Eq.)
Gas/Source
C02
Fossil Fuel Combustion
Electricity Generation
Transportation
Industrial
Residential
Commercial
U.S. Territories
Non-Energy Use of Fuels
Natural Gas Systems
Incineration of Waste
Petroleum Systems
Biomass - Wood
International Bunker Fuels
Biomass - Ethanol
CH4
Natural Gas Systems
Coal Mining
1990
4,903.6
4,741.2
1,820.8
1,485.9
849.3
338.3
219.0
27.9
116.2
37.6
8.0
0.6
215.2
111.8
4.1
327.4
189.8
84.1
2000
5,781.7
5,597.7
2,296.9
1,809.5
853.9
370.7
230.8
35.9
142.5
29.9
11.1
0.5
218.1
98.5
9.0
318.6
209.3
60.4
2005
5,939.7
5,755.6
2,402.1
1,896.6
825.5
357.9
223.5
50.0
141.3
29.9
12.5
0.5
206. 9
110.5
22.1
291.3
190.4
56.9
2006
5,843.2
5,657.0
2,346.4
1,878.1
852.1
321.5
208.6
50.3
142.4
30.8
12.5
0.5
203.8
129.1
29.9
319.2
217.7
58.2
2007
5,939.0
5,760.6
2,412.8
1,894.0
845.9
342.4
219.4
46.1
134.1
31.1
12.7
0.5
203.3
127.1
37.5
307.3
205.2
57.9
2008
5,752.8
5,568.7
2,360.9
1,789.9
805.6
348.2
224.2
39.8
138.7
32.8
12.2
0.5
198.4
135.2
52.8
323.6
211.8
67.1
2009
5,379.0
5,212.0
2,154.0
1,718.9
738.4
340.2
218.8
41.7
122.1
32.2
12.3
0.5
183.8
131.3
59.0
337.0
221.2
71.0
52 Global CO2 emissions from fossil fuel combustion were taken from Energy Information Administration International Energy
Statistics 2010 < http://tonto.eia.doe.gov/cfapps/ipdbproject/IEDIndex3.cfm> EIA (2010).
Energy 3-1
-------
1
2
3
4
5
6
7
Petroleum Systems
Stationary Combustion
Abandoned Underground
Coal Mines
Mobile Combustion
Incineration of Waste
International Bunker Fuels
N2O
Mobile Combustion
Stationary Combustion
Incineration of Waste
International Bunker Fuels
Total
35.4
7.4
6.0
4.7
+
0.2
57.2
43.9
12.8
0.5
1.1
5,288.2
31.5
6.6
7.4
3.4
+
0.1
68.1
53.2
14.6
0.4
0.9
6,168.4
29.4
6.6
5.5
2.5
+
0.1
52.1
36.9
14.7
0.4
1.0
6,283.1
29.4
6.2
5.5
2.3
+
0.2
48.5
33.6
14.4
0.4
1.2
30.0
6.5
5.6
2.2
+
0.2
45.2
30.3
14.6
0.4
1.2
6,210.9 6,291.5 6,
30.2 30.9
6.5 6.2
5.9 5.5
2.0 2.2
+ +
0.2 0.2
40.7 41.0
26.1 27.8
14.2 12.8
0.4 0.4
1.2 1.2
117.1 5,757.0
+ Does not exceed 0.05 Tg CO2 Eq.
* These values are presented for informational purposes only, in line with IPCC methodological guidance and UNFCCC
reporting obligations, and are not included in the specific energy sector contribution to the totals, and are already accounted for
elsewhere.
Note: Totals may not sum due to independent rounding.
Table 3-2: CO2, CH4, and N2O Emissions from Energy (Gg)
Gas/Source
1990
CO2 4,903,611
8
9
10
11
12
13
Fossil Fuel Combustion 4
Non-Energy Use of
Fuels
Natural Gas Systems
Incineration of Waste
Petroleum Systems
Biomass -Wood*
International Bunker
Fuels
Biomass - Ethanol
CH4
Natural Gas Systems
Coal Mining
Petroleum Systems
Stationary Combustion
Abandoned
Underground Coal
Mines
Mobile Combustion
Incineration of Waste
International Bunker
Fuels
N2O
Mobile Combustion
Stationary Combustion
Incineration of Waste
International Bunker
Fuels
+ Does not exceed 0.05 Tg CO2
,741,246
116,245
37,574
7,989
555
215,186
111,828
4,074
15,590
9,038
4,003
1,685
354
288
223
+
8
185
142
41
2
3
Eq.
* These values are presented for informational
2000
5,781,700
5,597,691
142,487
29,877
11,112
534
218,088
98,482
9,009
15,171
9,968
2,877
1,501
316
350
160
+
6
220
172
47
1
3
purposes only, in
reporting obligations, and are not included in the specific energy
elsewhere.
2005
5,939,700
5,755,608
141,250
29,902
12,450
490
206, 865
110,505
22,115
13,872
9,069
2,710
1,398
313
264
119
+
7
168
119
47
1
3
line with IPCC
2006
2007
5,843,192 5,938,955
5,656,988 5,
142,430
30,755
12,531
488
203,846
129,104
29,867
15,202
10,364
2,774
1,398
293
261
112
+
8
156
108
47
1
4
methodological
760,628
134,102
31,050
12,700
474
203,316
127,054
37,520
14,634
9,771
2,756
1,427
308
267
105
+
7
146
98
47
1
4
2008
5,752,789
5,568,683
138,656
32,828
12,169
453
198,361
135,226
52, 765
15,408
10,087
3,196
1,439
310
279
97
+
8
131
84
46
1
4
2009
5,378,965
5,211,969
122,062
32,171
12,300
463
183,777
131,294
58,989
16,050
10,535
3,382
1,473
293
262
106
+
7
132
90
41
1
4
guidance and UNFCCC
sector contribution to the totals, and are already accounted for
Note: Totals may not sum due to independent rounding.
3-2 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
i 3.1. Fossil Fuel Combustion (IPCC Source Category 1A)
2 Emissions from the combustion of fossil fuels for energy include the gases CO2, CH4, and N2O. Given that CO2 is
3 the primary gas emitted from fossil fuel combustion and represents the largest share of U.S. total emissions, CO2
4 emissions from fossil fuel combustion are discussed at the beginning of this section. Following that is a discussion
5 of emissions of all three gases from fossil fuel combustion presented by sectoral breakdowns. Methodologies for
6 estimating CO2 from fossil fuel combustion also differ from the estimation of CH4 and N2O emissions from
7 stationary combustion and mobile combustion. Thus, three separate descriptions of methodologies, uncertainties,
8 recalculations, and planned improvements are provided at the end of this section. Total CO2, CH4, and N2O
9 emissions from fossil fuel combustion are presented in Table 3-3 and Table 3-4.
10 Table 3-3: CO2, CH4, and N2O Emissions from Fossil Fuel Combustion (Tg CO2 Eq.)
11
12
13
Gas 1990
CO2 4,741.2
CH4 12.7
N2O 65.3
Total 4,819.2
2000
5,597.7
10.7
78.1
5,686.4
2005
5,755.6
9.8
62.3
5,827.8
Note: Totals may not sum due to independent rounding.
Table 3-4: CO2, CH4, and N2O Emissions from Fossil Fuel
Gas 1990
CO2 4,741,246
CH4 604
N2O 211
2000
5,597,691
508
252
2005
5,755,608 5
467
201
2006
5,657.0
9.2
58.5
5,724.7
Combustion
2006
2007
5,760.6
9.4
55.5
5,825.5
(Gg)
2007
,656,988 5,760,628
439 448
189 179
2008
5,568.7
9.3
50.8
5,628.7
2008
5,568,683
441
164
2009
5,212.0
9.0
50.0
5,271.0
2009
5,211,969
430
161
14 Note: Totals may not sum due to independent rounding.
15
16 C02 from Fossil Fuel Combustion
17 CO2 is the primary gas emitted from fossil fuel combustion and represents the largest share of U.S. total greenhouse
18 gas emissions. CO2 emissions from fossil fuel combustion are presented in Table 3-5. In 2009, CO2 emissions from
19 fossil fuel combustion decreased by 6.4 percent relative to the previous year. This decrease represents the largest
20 annual decrease in CO2 emissions from fossil fuel combustion for the twenty-year period.53 The decrease in CO2
21 emissions from fossil fuel combustion was a result of multiple factors including: (1) a decrease in economic output
22 resulting in a decrease in energy consumption across all sectors; (2) a decrease in the carbon intensity of fuels used
23 to generate electricity due to fuel switching as the price of coal increased, and the price natural gas decreased
24 significantly; and (3) an increase in non-fossil fuel consumption by approximately 2 percent. In 2009, CO2
25 emissions from fossil fuel combustion were 5,212.0 Tg CO2 Eq., or almost 10 percent above emissions in 1990 (see
26 Table 3-5).54
27 Table 3-5: CO2 Emissions from Fossil Fuel Combustion by Fuel Type and Sector (Tg CO2 Eq.)
Fuel/Sector
Coal
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Natural Gas
Residential
1990
1,718.4
3.0
12.0
155.3
NE
1,547.6
0.6
1,000.6
238.0
2000
2,065.5
1.1
8.8
127.3
NE
1,927.4
0.9
1,217.4
270.7
2005
2,112.3
0.8
9.3
115.3
NE
1,983.8
3.0
1,159.0
262.2
2006
2,076.5
0.6
6.2
112.6
NE
1,953.7
3.4
1,141.3
237.3
2007
2,106.0
0.7
6.7
107.0
NE
1,987.3
4.3
1,218.0
257.0
2008
2,072.5
0.7
6.5
102.6
NE
1,959.4
o o
J.J
1,226.0
264.4
2009
1,841.0
0.6
5.8
83.4
NE
1,747.6
3.5
1,200.9
257.2
53 This decrease also represents the largest absolute and percentage decrease since the beginning of EIA's record of annual
energy consumption data, beginning in 1949 (EIA 2010a).
54 An additional discussion of fossil fuel emission trends is presented in the Trends in U.S. Greenhouse Gas Emissions Chapter.
Energy 3-3
-------
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Petroleum
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Geothermal*
Total
142.1
409.1
36.0
175.3
NO
2,021.9
97.4
64.9
284.9
1,449.9
97.5
27.2
0.4
4,741.2
172.5
457.2
35.6
280.8
0.7
2,314.4
98.8
49.6
269.5
1,773.9
88.4
34.2
0.4
5,597.7
162.9
380.8
33.1
318.8
1.3
2,484.0
94.9
51.3
329.3
1,863.5
99.2
45.7
0.4
5,755.6
153.8
377.7
33.1
338.0
1.4
2,438.7
83.6
48.5
361.8
1,845.0
54.4
45.5
0.4
5,657.0
164.0
389.0
35.3
371.3
1.4
2,436.3
84.6
48.7
349.9
1,858.7
53.9
40.4
0.4
5,760.6
170.2
391.0
36.8
361.9
1.6
2,269.8
83.1
47.4
312.0
1,753.1
39.2
35.0
0.4
5,568.7
167.9
365.0
36.3
373.1
1.5
2,169.7
82.4
45.1
290.0
1,682.6
32.9
36.7
0.4
5,212.0
NE (Not estimated)
NO (Not occurring)
* Although not technically a fossil fuel, geothermal energy-related CO2 emissions are included for reporting purposes.
Note: Totals may not sum due to independent rounding.
Trends in CO2 emissions from fossil fuel combustion are influenced by many long-term and short-term factors. On
a year-to-year basis, the overall demand for fossil fuels in the United States and other countries generally fluctuates
in response to changes in general economic conditions, energy prices, weather, and the availability of non-fossil
alternatives. For example, in a year with increased consumption of goods and services, low fuel prices, severe
summer and winter weather conditions, nuclear plant closures, and lower precipitation feeding hydroelectric dams,
there would likely be proportionally greater fossil fuel consumption than a year with poor economic performance,
high fuel prices, mild temperatures, and increased output from nuclear and hydroelectric plants.
Longer-term changes in energy consumption patterns, however, tend to be more a function of aggregate societal
trends that affect the scale of consumption (e.g., population, number of cars, size of houses, and number 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).
CO2 emissions also depend on the source of energy and its carbon (C) intensity. The amount of C in fuels varies
significantly by fuel type. For example, coal contains the highest amount of C per unit of useful energy. Petroleum
has roughly 75 percent of the C per unit of energy as coal, and natural gas has only about 55 percent.55 Table 3-6
shows annual changes in emissions during the last five years for coal, petroleum, and natural gas in selected sectors.
Table 3-6: Annual Change in CO2 Emissions and Total 2009 Emissions from Fossil Fuel Combustion for Selected
Fuels and Sectors (Tg CO2 Eq. and Percent)
Sector Fuel Type
Electricity Generation Coal
Electricity Generation Natural Gas
Electricity Generation Petroleum
Transportation a Petroleum
Residential Natural Gas
Commercial Natural Gas
Industrial Coal
Industrial Natural Gas
All Sectors b All Fuels b
2005 to 2006
-30.1 -1.5%
19.2 6.0%
.44.8 -45.2%
-18.5 -1.0%
-24.9 -9.5%
-9.1 -5.6%
-2.8 -2.4%
-3.1 -0.8%
-98.6 -1.7%
2006 to 2007
33.6 1.7%
33.3 9.9%
-0.5 -0.9%
13.7 0.7%
19.7 8.3%
10.2 6.6%
-5.6 -5.0%
11.3 3.0%
103.6 1.8%
2007 to 2008
-27.9 -1.4%
-9.3 -2.5%
-14.7 -27.2%
-105.6 -5.7%
7.4 2.9%
6.2 3.8%
.4.4 -4.io/o
2.0 0.5%
-191.9 -3.3%
2008 to 2009
-211.7 -10.8%
11.1 3.1%
-6.3 -16.0%
-70.5 -4.0%
-7.3 -2.8%
-2.3 -1.3%
-19.2 -18.7%
-26.0 -6.6%
-356.7 -6.4%
Total 2009
1,747.6
373.1
32.9
1,682.6
257.2
167.9
83.4
365.0
5,212.0
23
24
25
a Excludes emissions from International Bunker Fuels.
b Includes fuels and sectors not shown in table.
26 In the United States, 83 percent of the energy consumed in 2009 was produced through the combustion of fossil
55 Based on national aggregate carbon content of all coal, natural gas, and petroleum fuels combusted in the United States.
3-4 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 fuels such as coal, natural gas, and petroleum (see Figure 3-3 and Figure 3-4). The remaining portion was supplied
2 by nuclear electric power (9 percent) and by a variety of renewable energy sources (8 percent), primarily
3 hydroelectric power and biofuels (EIA 20 lOb). Specifically, petroleum supplied the largest share of domestic
4 energy demands, accounting for an average of 42 percent of total fossil fuel based energy consumption in 2009.
5 Natural gas and coal followed in order of importance, accounting for approximately 32 and 27 percent of total
6 consumption, respectively. Petroleum was consumed primarily in the transportation end-use sector and the vast
7 majority of coal was used in electricity generation. Natural gas was broadly consumed in all end-use sectors except
8 transportation (see Figure 3-5) (EIA 20lOb).
9
10 Figure 3-3: 2009 U.S. Energy Consumption by Energy Source
11
12 Figure 3-4: U.S. Energy Consumption (Quadrillion Btu)
13
14 Figure 3-5: 2009 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
15
16 Fossil fuels are generally combusted for the purpose of producing energy for useful heat and work. During the
17 combustion process, the C stored in the fuels is oxidized and emitted as CO2 and smaller amounts of other gases,
18 including CH4, CO, and NMVOCs.56 These other C containing non-CO2 gases are emitted as a by-product of
19 incomplete fuel combustion, but are, for the most part, eventually oxidized to CO2 in the atmosphere. Therefore, it
20 is assumed that all of the C in fossil fuels used to produce energy is eventually converted to atmospheric CO2.
21
22 [BEGIN BOX]
23
24 Box 3-1: Weather and Non-Fossil Energy Effects on CO2 from Fossil Fuel Combustion Trends
25
26 In 2009, weather conditions remained constant in the winter and slightly cooler in the summer compared to 2008, as
27 heating degree days decreased slightly and cooling degree days decreased by 3.8 percent. Winter conditions were
28 relatively constant in 2009 compared to 2008, and the winter was slightly warmer than normal, with heating degree
29 days in the United States 0.7 percent below normal (see Figure 3-6). Summer conditions were slightly cooler in
30 2009 compared to 2008, and summer temperatures were slightly cooler than normal, with cooling degree days 1
31 percent below normal (see Figure 3-7) (EIA 2010b).57
32
33 Figure 3-6: Annual Deviations from Normal Heating Degree Days for the United States (1950-2009)
34
35 Figure 3-7: Annual Deviations from Normal Cooling Degree Days for the United States (1950-2009)
36
56 See the sections entitled Stationary Combustion and Mobile Combustion in this chapter for information on non-CO2 gas
emissions from fossil fuel combustion.
57 Degree days are relative measurements of outdoor air temperature. Heating degree days are deviations of the mean daily
temperature below 65° F, while cooling degree days are deviations of the mean daily temperature above 65° F. Heating degree
days have a considerably greater affect on energy demand and related emissions than do cooling degree days. Excludes Alaska
and Hawaii. Normals are based on data from 1971 through 2000. The variation in these normals during this time period was +10
percent and +14 percent for heating and cooling degree days, respectively (99 percent confidence interval).
Energy 3-5
-------
1 Although no new U.S. nuclear power plants have been constructed in recent years, the utilization (i.e., capacity
2 factors58) of existing plants in 2009 remained high at just over 90 percent. Electricity output by hydroelectric power
3 plants increased in 2009 by approximately 6.8 percent. Electricity generated by nuclear plants in 2009 provided
4 nearly 3 times as much of the energy consumed in the United States as hydroelectric plants (EIA 2010b). Nuclear,
5 hydroelectric, and wind power capacity factors since 1990 are shown in Figure 3-8.
6
7 Figure 3-8: Nuclear, Hydroelectric, and Wind Power Plant Capacity Factors in the United States (1990-2009)
9
10
[END BOX]
11 Fossil Fuel Combustion Emissions by Sector
12 In addition to the CO2 emitted from fossil fuel combustion, CH4 and N2O are emitted from stationary and mobile
13 combustion as well. Table 3-7 provides an overview of the CO2, CH4, and N2O emissions from fossil fuel
14 combustion by sector.
15 Table 3-7: CO2, CH4, and N2O Emissions from Fossil Fuel Combustion by Sector (Tg CO2 Eq.)
End-Use Sector
1990
Electricity Generation 1,838.6
C02
CH4
N2O
Transportation
C02
CH4
N2O
Industrial
CO2
CH4
N2O
Residential
C02
CH4
N2O
Commercial
C02
CH4
N2O
U.S. Territories*
16
17
18
19
20
21
22
Total
1,820.
1.
16.
8
1
6
1,534.6
1,485.
4.
43.
854.
849.
1.
3.
343.
338.
4.
1.
220.
219.
0.
0.
28.
9
7
9
1
3
5
2
8
3
4
1
2
0
9
4
0
4,819.2
2000
2,318.6
2,296.9
1.4
20.3
1,866.0
1,809.5
3.4
53.2
858.8
853.9
1.6
3.2
375.0
370.7
3.4
0.9
232.1
230.8
0.9
0.4
36.0
5,686.4
2005
2,424.
2,402.
1.
21.
1,936.
6
1
5
0
0
1,896.6
2.
5
36.9
830.
825.
1.
3.
362.
357.
3.
0.
224.
223.
0.
0.
50.
5,827.
Note: Totals may not sum due to independent rounding. Emissions from
allocated based on aggregate national electricity
* U.S. Territories are not
sources.
Other than CO2, gases
indirect j
apportioned by
sector,
consumption by
0
5
5
0
2
9
4
9
8
5
9
4
2
7
2006
2,368.3
2,346.4
1.4
20.5
1,914.1
1,878.1
2.3
33.6
856.7
852.1
1.5
3.1
325.4
321.5
3.1
0.8
209.7
208.6
0.8
0.3
50.5
5,724.7
2007
2,435.2
2,412.8
1.5
20.9
1,926.5
1,894.0
2.2
30.3
850.4
845.9
1.4
3.0
346.6
342.4
3.4
0.9
220.6
219.4
0.9
0.3
46.3
5,825.5
fossil fuel combustion by
each end-use
sector.
2008
2,382.8
2,360.9
1.4
20.5
1,818.1
1,789.9
2.0
26.1
809.8
805.6
1.3
2.8
352.6
348.2
3.5
0.9
225.4
224.2
0.9
0.3
40.0
5,628.7
2009
2,173.7
2,154.0
1.3
18.4
1,748.9
1,718.9
2.2
27.8
742.0
738.4
1.2
2.5
344.5
340.2
3.4
0.9
220.0
218.8
0.9
0.3
41.8
5,270.9
electricity generation are
and emissions are total greenhouse gas emissions from all fuel combustion
emitted from stationary combustion include the
greenhouse gases NOX, CO,
and NMVOCs.59 CH
greenhouse gases CH4 and N2O
4 and N2O emissions
and the
from stationary combustion sources
58The capacity factor equals generation divided by net summer capacity. Summer capacity is defined as "The maximum output
that generating equipment can supply to system load, as demonstrated by a multi-hour test, at the time of summer peak demand
(period of June 1 through September 30)." Data for both the generation and net summer capacity are from EIA (201 Ob).
59 Sulfur dioxide (SO2) emissions from stationary combustion are addressed in Annex 6.3.
3-6 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 depend upon fuel characteristics, size and vintage, along with combustion technology, pollution control equipment,
2 ambient environmental conditions, and operation and maintenance practices. N2O emissions from stationary
3 combustion are closely related to air-fuel mixes and combustion temperatures, as well as the characteristics of any
4 pollution control equipment that is employed. CH4 emissions from stationary combustion are primarily a function of
5 the CH4 content of the fuel and combustion efficiency.
6 Mobile combustion produces greenhouse gases other than CO2, including CH4, N2O, and indirect greenhouse gases
7 including NOX, CO, and NMVOCs. As with stationary combustion, N2O and NOX emissions from mobile
8 combustion are closely related to fuel characteristics, air-fuel mixes, combustion temperatures, and the use of
9 pollution control equipment. N2O from mobile sources, in particular, can be formed by the catalytic processes used
10 to control NOX, CO, and hydrocarbon emissions. Carbon monoxide emissions from mobile combustion are
11 significantly affected by combustion efficiency and the presence of post-combustion emission controls. CO
12 emissions are highest when air-fuel mixtures have less oxygen than required for complete combustion. These
13 emissions occur especially in idle, low speed, and cold start conditions. CH4 and NMVOC emissions from motor
14 vehicles are a function of the CH4 content of the motor fuel, the amount of hydrocarbons passing uncombusted
15 through the engine, and any post-combustion control of hydrocarbon emissions (such as catalytic converters).
16 An alternative method of presenting combustion emissions is to allocate emissions associated with electricity
17 generation to the sectors in which it is used. Four end-use sectors were defined: industrial, transportation,
18 residential, and commercial. In the table below, electricity generation emissions have been distributed to each end-
19 use sector based upon the sector's share of national electricity consumption, with the exception of CH4 and N2O
20 from transportation.60 Emissions from U.S. territories are also calculated separately due to a lack of end-use-specific
21 consumption data. This method of distributing emissions assumes that 564 combustion sources focus on the
22 alternative method as presented in Table 3-8.
23 Table 3-8: CO2, CH4, and N2O Emissions from Fossil Fuel Combustion by End-Use Sector (Tg CO2 Eq.)
End-Use Sector
1990
2000
2005
2006
2007
2008
2009
24
25
26
27
28
Transportation 1,546.7 1,880.5
CO2 1,489.0 1,813.0
CH4 5.3 4.0
N2O 52.5 63.5
Industrial 1,544.1 1,652.2
CO2 1,536.0 1,643.7
CH4 1.8 1.8
N2O 6.3 6.7
Residential 939.7 1,140.9
CO2 931.4 1,133.1
CH4 4.6 3.6
N2O 3.7 4.2
Commercial 760.8 976.8
CO2 757.0 972.1
CH4 1.0 1.1
N2O 2.8 3.6
U.S. Territories* 28.0 36.0
Total 4,819.2 5,686.4
1,952.2 1,929.8
1,901.3 1,882.6
3.2 3.1
47.6 44.1
1,570.3 1,572.0
1,562.4 1,564.1
1.7 1.7
6.2 6.2
1,222.9 1,160.1
1,214.7 1,152.4
3.7 3.3
4.6 4.4
1,032.2 1,012.4
1,027.2 1,007.6
1.1 1.1
3.8 3.8
50.2 50.5
5,827.7 5,724.7
Note: Totals may not sum due to independent rounding. Emissions from fossil fuel
allocated based on aggregate national electricity consumption
1,942.9
1,899.0
2.9
40.9
1,583.6
1,575.9
1.6
6.1
1,206.7
1,198.5
3.6
4.5
1,046.0
1,041.1
1.1
3.8
46.3
5,825.5
combustion by
1,833.9
1,794.6
2.7
36.5
1,527.9
1,520.4
1.6
5.8
1,190.4
1,182.2
3.7
4.5
1,036.5
1,031.6
1.2
3.8
40.0
5,628.7
electricity
1,763.3
1,723.3
2.9
37.1
1,348.1
1,341.7
1.4
5.0
1,132.6
1,124.8
3.6
4.2
985.1
980.5
1.1
3.5
41.8
5,270.9
generation are
by each end-use sector.
* U.S. Territories are not apportioned by sector, and emissions are total greenhouse gas emissions from all fuel combustion
sources.
29 Stationary Combustion
30 The direct combustion of fuels by stationary sources in the electricity generation, industrial, commercial, and
60 Separate calculations were performed for transportation-related CH4 and N2O. The methodology used to calculate these
emissions are discussed in the mobile combustion section.
Energy 3-7
-------
1
2
o
J
4
5
6
7
8
9
10
11
12
residential sectors represent the greatest share of U.S. greenhouse gas emissions. Table 3-9 presents CO2 emissions
from fossil fuel combustion by stationary sources. The CO2 emitted is closely linked to the type of fuel being
combusted in each sector (see Methodology section for CO2 from fossil fuel combustion). Other than CO2, gases
emitted from stationary combustion include the greenhouse gases CH4 and N2O. Table 3-10 and Table 3-11 present
CH4 and N2O emissions from the combustion of fuels in stationary sources. CH4 and N2O emissions from stationary
combustion sources depend upon fuel characteristics, size and vintage, along with combustion technology, pollution
control equipment, ambient environmental conditions, and operation and maintenance practices. N2O emissions
from stationary combustion are closely related to air-fuel mixes and combustion temperatures, as well as the
characteristics of any pollution control equipment that is employed. CH4 emissions from stationary combustion are
primarily a function of the CH4 content of the fuel and combustion efficiency. Please refer to Table 3-7 for the
corresponding presentation of all direct emission sources of fuel combustion.
Table 3-9: CO2 Emissions from Stationary Fossil Fuel Combustion (Tg CO2 Eq.)
Sector/Fuel Type
1990
Electricity Generation 1,820.8
13
14
15
Coal
Natural Gas
Fuel Oil
Geothermal
Industrial
Coal
Natural Gas
Fuel Oil
Commercial
Coal
Natural Gas
Fuel Oil
Residential
Coal
Natural Gas
Fuel Oil
U.S. Territories
Coal
Natural Gas
Fuel Oil
Total
* U.S. Territories are not
presented in this table.
1,547.6
175.3
97.5
0.4
849.3
155.3
409.1
284.9
219.0
12.0
142.1
64.9
338.3
3.0
238.0
97.4
27.9
0.6
NO
27.2
3,255.3
apportioned by
2000
2,296.9
1,927.4
280.8
88.4
0.4
853.9
127.3
457.2
269.5
230.8
8.8
172.5
49.6
370.7
1.1
270.7
98.8
35.9
0.9
0.7
34.2
3,788.2
2005
2,402.1
1,983.8
318.8
99.2
0.4
825.5
115.3
380.8
329.3
223.5
9.3
162.9
51.3
357.9
0.8
262.2
94.9
50.0
3.0
1.3
45.7
3,859.0
sector, and emissions are from all
2006
2,346.4 2,
1,953.7 1,
338.0
54.4
0.4
852.1
112.6
377.7
361.8
208.6
6.2
153.8
48.5
321.5
0.6
237.3
83.6
50.3
3.4
1.4
45.5
3,778.9 3,
fuel combustion
2007
412.8
987.3
371.3
53.9
0.4
845.9
107.0
389.0
349.9
219.4
6.7
164.0
48.7
342.4
0.7
257.0
84.6
46.1
4.3
1.4
40.4
866.6
2008
2,360.9
1,959.4
361.9
39.2
0.4
805.6
102.6
391.0
312.0
224.2
6.5
170.2
47.4
348.2
0.7
264.4
83.1
39.8
3.3
1.6
35.0
3,778.8
sources (stationary
2009
2,154.0
1,747.6
373.1
32.9
0.4
738.4
83.4
365.0
290.0
218.8
5.8
167.9
45.1
340.2
0.6
257.2
82.4
41.7
3.5
1.5
36.7
3,493.1
and mobile) are
3-8 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Table 3-10: CH4 Emissions from Stationary Combustion (Tg CO2 Eq.)
2
3
4
5
Sector/Fuel Type
Electricity Generation
Coal
Fuel Oil
Natural Gas
Wood
Industrial
Coal
Fuel Oil
Natural Gas
Wood
Commercial
Coal
Fuel Oil
Natural Gas
Wood
Residential
Coal
Fuel Oil
Natural Gas
Wood
U.S. Territories
Coal
Fuel Oil
Natural Gas
Wood
Total
+ Does not exceed 0.05 Tg
Note: Totals may not sum
1990
0.6
0.3
0.1
0.1
0.1
1.5
0.3
0.2
0.2
0.9
0.9
+
0.2
0.3
0.4
4.4
0.2
0.3
0.4
3.5
+
+
+
+
+
7.4
CO2 Eq.
2000
0.7
0.4
0.1
0.1
0.1
1.6
0.3
0.1
0.2
1.0
0.9
+
0.1
0.3
0.4
3.4
0.1
0.3
0.5
2.5
0.1
+
+
+
+
6.6
2005
0.7
0.4
0.1
0.1
0.1
1.5
0.3
0.2
0.1
0.9
0.9
+
0.2
0.3
0.4
3.4
0.1
0.3
0.5
2.6
0.1
+
0.1
+
+
6.6
2006
0.7
0.4
+
0.1
0.1
1.5
0.3
0.2
0.1
0.9
0.8
+
0.1
0.3
0.4
3.1
+
0.3
0.4
2.3
0.1
+
0.1
+
+
6.2
2007
0.7
0.4
+
0.1
0.1
1.4
0.2
0.2
0.1
0.8
0.9
+
0.1
0.3
0.4
3.4
+
0.3
0.5
2.6
0.1
+
0.1
+
+
6.5
2008
0.7
0.4
+
0.1
0.1
1.3
0.2
0.2
0.1
0.8
0.9
+
0.1
0.3
0.4
3.5
+
0.3
0.5
2.7
0.1
+
0.1
+
+
6.5
2009
0.7
0.4
+
0.1
0.1
1.2
0.2
0.1
0.1
0.7
0.9
+
0.1
0.3
0.4
3.4
+
0.3
0.5
2.6
0.1
+
0.1
+
+
6.2
due to independent rounding.
Table 3-11: N2O Emissions from Stationary
Sector/Fuel Type
Electricity Generation
Coal
Fuel Oil
Natural Gas
Wood
Industrial
Coal
Fuel Oil
Natural Gas
Wood
Commercial
Coal
Fuel Oil
Natural Gas
Wood
Residential
Coal
Fuel Oil
Natural Gas
Wood
U.S. Territories
Coal
1990
8.1
7.6
0.2
0.1
0.2
3.2
0.8
0.5
0.2
1.7
0.4
0.1
0.2
0.1
0.1
1.1
+
0.3
0.1
0.7
0.1
+
Combustion
2000
10.0
9.4
0.2
0.2
0.2
3.2
0.6
0.4
0.3
1.9
0.4
+
0.1
0.1
0.1
0.9
+
0.3
0.2
0.5
0.1
+
(TgC02Eq.)
2005
10.3
9.7
0.2
0.2
0.2
3.0
0.6
0.5
0.2
1.7
0.4
+
0.1
0.1
0.1
0.9
+
0.3
0.1
0.5
0.1
+
2006
10.1
9.5
0.1
0.2
0.2
3.1
0.6
0.6
0.2
1.7
0.3
+
0.1
0.1
0.1
0.8
+
0.2
0.1
0.5
0.1
+
2007
10.2
9.7
0.1
0.2
0.2
3.0
0.5
0.6
0.2
1.7
0.3
+
0.1
0.1
0.1
0.9
+
0.2
0.1
0.5
0.1
+
2008
10.1
9.6
0.1
0.2
0.2
2.8
0.5
0.5
0.2
1.6
0.3
+
0.1
0.1
0.1
0.9
+
0.2
0.1
0.5
0.1
+
2009
9.0
8.5
0.1
0.2
0.2
2.5
0.4
0.4
0.2
1.4
0.3
+
0.1
0.1
0.1
0.9
+
0.2
0.1
0.5
0.1
+
Energy 3-9
-------
Fuel Oil 0.1 0.1 0.1 0.1 0.1 0.1 0.1
Natural Gas + + + + + + +
Wood + + + + + + +_
Total 12.8 14.6 14.7 14.4 14.6 14.2 12.8
1 + Does not exceed 0.05 Tg CO2 Eq.
2 Note: Totals may not sum due to independent rounding.
o
J
4 Electricity Generation
5 The process of generating electricity is the single largest source of CO2 emissions in the United States, representing
6 39 percent of total CO2 emissions from all CO2 emissions sources across the United States. CH4 and N2O accounted
7 for a small portion of emissions from electricity generation, representing less than 0.1 percent and 0.8 percent,
8 respectively.61 Electricity generation also accounted for the largest share of CO2 emissions from fossil fuel
9 combustion, approximately 41 percent in 2009. CH4 and N2O from electricity generation represented 15 and 37
10 percent of emissions from CH4 and N2O emissions from fossil fuel combustion in 2009, respectively. Electricity was
11 consumed primarily in the residential, commercial, and industrial end-use sectors for lighting, heating, electric
12 motors, appliances, electronics, and air conditioning (see Figure 3-9).
13
14 Figure 3-9: Electricity Generation Retail Sales by End-Use Sector
15
16 The electric power industry includes all power producers, consisting of both regulated utilities and nonutilities (e.g.
17 independent power producers, qualifying cogenerators, and other small power producers). For the underlying
18 energy data used in this chapter, the Energy Information Administration (ElA) places electric power generation into
19 three functional categories: the electric power sector, the commercial sector, and the industrial sector. The electric
20 power sector consists of electric utilities and independent power producers whose primary business is the production
21 of electricity,62 while the other sectors consist of those producers that indicate their primary business is something
22 other than the production of electricity.
23 The industrial, residential, and commercial end-use sectors, as presented in Table 3-8, were reliant on electricity for
24 meeting energy needs. The residential and commercial end-use sectors were especially reliant on electricity
25 consumption for lighting, heating, air conditioning, and operating appliances. Electricity sales to the residential and
26 commercial end-use sectors in 2009 decreased approximately 1.2 percent and 1.0 percent, respectively. The trend in
27 the commercial and residential sectors can largely be attributed to the decreased carbon intensity in the fuels used to
28 generate electricity for these sectors. In addition, electricity consumption in both sectors decreased as a result of the
29 less energy-intensive weather conditions compared to 2008. In 2009, the amount of electricity generated (in kWh)
30 decreased by 4 percent from the previous year. This decline was due to the economic downturn, a decrease in the
31 carbon intensity of fuels used to generate electricity due to fuel switching as the price of coal increased, and the
32 price of natural gas decreased significantly, and an increase in non-fossil fuel sources used to generate electricity. As
33 a result, CO2 emissions from the electric power sector decreased by 8.8 percent as the consumption of coal and
34 petroleum for electricity generation decreased by 10.8 percent and 16.6 percent, respectively, in 2009 and the
3 5 consumption of natural gas for electricity generation, increased by 3.1 percent. The decrease in C intensity of the
36 electricity supply (see Table 3-15) was the result of a decrease in the carbon intensity of fossil fuels consumed to
37 generate electricity and an increase in renewable generation of 5 percent spurred by a 28 percent increase in wind-
38 generated electricity.
61 Since emissions estimates for U.S. territories cannot be disaggregated by gas in Table 3-7and Table 3-8, the percentages for
CH4 and N2O exclude U.S. territory estimates.
62 Utilities primarily generate power for the U.S. electric grid for sale to retail customers. Nonutilities produce electricity for
their own use, to sell to large consumers, or to sell on the wholesale electricity market (e.g., to utilities for distribution and resale
to customers).
3-10 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Industrial Sector
2 The industrial sector accounted for 14 percent of CO2 emissions from fossil fuel combustion, 13 percent of CH4
3 emissions from fossil fuel combustion, and 5 percent of N2O emissions from fossil fuel combustion. CO2, CH4, and
4 N2O emissions resulted from the direct consumption of fossil fuels for steam and process heat production.
5 The industrial sector, per the underlying energy consumption data from EIA, includes activities such as
6 manufacturing, construction, mining, and agriculture. The largest of these activities in terms of energy consumption
7 is manufacturing, of which six industries—Petroleum Refineries, Chemicals, Paper, Primary Metals, Food, and
8 Nonmetallic Mineral Products—represent the vast majority of the energy use (EIA 2010b and EIA 2009c).
9 In theory, emissions from the industrial sector should be highly correlated with economic growth and industrial
10 output, but heating of industrial buildings and agricultural energy consumption are also affected by weather
11 conditions.63 In addition, structural changes within the U.S. economy that lead to shifts in industrial output away
12 from energy-intensive manufacturing products to less energy-intensive products (e.g., from steel to computer
13 equipment) also have a significant effect on industrial emissions.
14 From 2008 to 2009, total industrial production and manufacturing output decreased by 9.3 and 10.9 percent,
15 respectively (FRB 2010). Over this period, output decreased across all production indices for Food, Petroleum
16 Refineries, Chemicals, Paper, Primary Metals, and Nonmetallic Mineral Products (see Figure 3-10).
17
18 Figure 3-10: Industrial Production Indices (Index 2002=100)
19
20 Despite the growth in industrial output (41 percent) and the overall U.S. economy (60 percent) from 1990 to 2009,
21 CO2 emissions from fossil fuel combustion in the industrial sector decreased by 13.1 percent over that time. A
22 number of factors are believed to have caused this disparity between growth in industrial output and decrease in
23 industrial emissions, including: (1) more rapid growth in output from less energy-intensive industries relative to
24 traditional manufacturing industries, and (2) energy-intensive industries such as steel are employing new methods,
25 such as electric arc furnaces, that are less carbon intensive than the older methods. In 2009, CO2, CH4, and N2O
26 emissions from fossil fuel combustion and electricity use within the industrial end-use sector totaled 1,348.1 Tg CO2
27 Eq., or approximately 11.8 percent below 2008 emissions.
28 Residential and Commercial Sectors
29 The residential and commercial sectors accounted for 7 and 4 percent of CO2 emissions from fossil fuel combustion,
30 37 and 10 percent of CH4 emissions from fossil fuel combustion, and 2 and 1 percent of N2O emissions from fossil
31 fuel combustion, respectively. Emissions from these sectors were largely due to the direct consumption of natural
32 gas and petroleum products, primarily for heating and cooking needs. Coal consumption was a minor component of
33 energy use in both of these end-use sectors. In 2009, CO2, CH4, and N2O emissions from fossil fuel combustion and
34 electricity use within the residential and commercial end-use sectors were 1,132.6 Tg CO2 Eq. and 985.1 Tg CO2
35 Eq., respectively. Total CO2, CH4, and N2O emissions from the residential and commercial sectors decreased by 4.9
36 and 5.0 percent from 2008 to 2009, respectively.
37 Emissions from the residential and commercial sectors have generally been increasing since 1990, and are often
38 correlated with short-term fluctuations in energy consumption caused by weather conditions, rather than prevailing
39 economic conditions. In the long-term, both sectors are also affected by population growth, regional migration
40 trends, and changes in housing and building attributes (e.g., size and insulation).
41 Emissions from natural gas consumption represent about 76 percent of the direct fossil fuel CO2 emissions from
42 each of these sectors. In 2009, natural gas CO2 emissions from the residential and commercial sectors decreased by
43 2.8 percent and 1.3 percent, respectively. The decrease in natural gas emissions in both sectors is a result of less
44 energy-intensive weather conditions in the United States compared to 2008.
63 Some commercial customers are large enough to obtain an industrial price for natural gas and/or electricity and are
consequently grouped with the industrial end-use sector in U.S. energy statistics. These misclassiiications of large commercial
customers likely cause the industrial end-use sector to appear to be more sensitive to weather conditions.
Energy 3-11
-------
1 U.S. Territories
2 Emissions from U.S. territories are based on the fuel consumption in American Samoa, Guam, Puerto Rico, U.S.
3 Virgin Islands, Wake Island, and other U.S. Pacific Islands. As described the Methodology section for CO2 from
4 fossil fuel combustion, this data is collected separately from the sectoral-level data available for the general
5 calculations. As sectoral information is not available for U.S. Territories, CO2, CH4, and N2O emissions are not
6 presented for U.S. Territories in the tables above, though the emissions will include some transportation and mobile
7 combustion sources.
8 Transportation and Mobile Combustion
9 This discussion of transportation emissions follows the alternative method of presenting combustion emissions by
10 allocating emissions associated with electricity generation to the transportation end-use sector, as presented in Table
11 3-8. For direct emissions from transportation (i.e., not including emissions associated with the sector's electricity
12 consumption), please see Table 3-7.
13 Transportation End-Use Sector
14 The transportation end-use sector accounted for 1,748.9 Tg CO2 Eq. in 2009, which represented 33 percent of CO2
15 emissions, 25 percent of CH4 emissions, and 56 percent of N2O emissions from fossil fuel combustion, respectively.
16 Fuel purchased in the U.S. for international aircraft and marine travel accounted for an additional 123.1 Tg CO2 in
17 2009; these emissions are recorded as international bunkers and are not included in U.S. totals according to
18 UNFCCC reporting protocols. Among domestic transportation sources, light duty vehicles (including passenger
19 cars and light-duty trucks) represented 64 percent of CO2 emissions, medium- and heavy-duty trucks 21 percent,
20 commercial aircraft 6 percent, and other sources 9 percent. See General aviation aircraft CO2 emissions increased
21 by 60 percent (5.7 Tg) from 1990 to 2009, representing the largest percentage increase of any transportation mode.
22 Among on-road vehicles, CO2 emissions from light-duty trucks increased by the largest percentage, 59 percent
23 (189.8 Tg) from 1990 to 2009. CO2 from the domestic operation of commercial aircraft decreased by 18 percent
24 (24.0 Tg) from 1990 to 2009. Across all categories of aviation, CO2 emissions decreased by 21.6 percent (38.7 Tg)
25 between 1990 and 2009. This includes a 59 percent (20.3 Tg) decrease in emissions from domestic military
26 operations. For further information on all greenhouse gas emissions from transportation sources, please refer to
27 Annex 3.2.
28 Table 3-12 for a detailed breakdown of CO2 emissions by mode and fuel type.
29 From 1990 to 2009, transportation emissions rose by 18 percent due, in large part, to increased demand for travel
30 and the stagnation of fuel efficiency across the U.S. vehicle fleet. The number of vehicle miles traveled by light-
31 duty motor vehicles (passenger cars and light-duty trucks) increased 38 percent from 1990 to 2009, as a result of a
32 confluence of factors including population growth, economic growth, urban sprawl, and low fuel prices over much
33 of this period.
34 From 2008 to 2009, CO2 emissions from the transportation end-use sector declined 4 percent. The decrease in
35 emissions can largely be attributed to decreased economic activity in 2009 and an associated decline in the demand
36 for transportation. Modes such as medium- and heavy-duty trucks were significantly impacted by the decline in
37 freight transport. Similarly, increased jet fuel prices were a factor in the 19 percent decrease in commercial aircraft
38 emissions since 2007.
39 Almost all of the energy consumed for transportation was supplied by petroleum-based products, with more than
40 half being related to gasoline consumption in automobiles and other highway vehicles. Other fuel uses, especially
41 diesel fuel for freight trucks and jet fuel for aircraft, accounted for the remainder. The primary driver of
42 transportation-related emissions was CO2 from fossil fuel combustion, which increased by 18 percent from 1990 to
43 2009. This rise in CO2 emissions, combined with an increase in HFCs from close to zero emissions in 1990 to 60.2
44 Tg CO2 Eq. in 2009, led to an increase in overall emissions from transportation activities of 18 percent.
45 Fossil Fuel Combustion CO2 Emissions from Transportation
46 Domestic transportation CO2 emissions increased by 16 percent (234.3 Tg) between 1990 and 2009, an annualized
47 increase of 0.8 percent. The 4 percent decline in emissions between 2008 and 2009 followed the previous year's
48 trend of decreasing emissions. Almost all of the energy consumed by the transportation sector is petroleum-based,
3-12 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 including motor gasoline, diesel fuel, jet fuel, and residual oil.64 Transportation sources also produce CH4 and N2O;
2 these emissions are included in Table 3-13 and Table 3-14 in the "Mobile Combustion" Section. Annex 3.2 presents
3 total emissions from all transportation and mobile sources, including CO2, N2O, CH4, and HFCs.
4 Carbon dioxide emissions from passenger cars and light-duty trucks totaled 1,106.2 Tg in 2009, an increase of 16
5 percent (155.8 Tg) from 1990. CO2 emissions from passenger cars and light-duty trucks peaked at 1,184.3 Tg in
6 2004, and since then have declined about 7 percent. Over the 1990s through early this decade, growth in vehicle
7 travel substantially outweighed improvements in vehicle fuel economy; however, the rate of Vehicle Miles Traveled
8 (VMT) growth slowed considerably starting in 2005 (and declined rapidly in 2008) while average vehicle fuel
9 economy increased. Among new vehicles sold annually, average fuel economy gradually declined from 1990 to
10 2004 (Figure 3-11), reflecting substantial growth in sales of light-duty trucks—in particular, growth in the market
11 share of sport utility vehicles—relative to passenger cars (Figure 3-12). New vehicle fuel economy improved
12 beginning in 2005, largely due to higher light-duty truck fuel economy standards, which have risen each year since
13 2005. The overall increase in fuel economy is also due to a slightly lower light-duty truck market share, which
14 peaked in 2004 at 51 percent and declined to 39 percent in 2009.
15
16 Figure 3-11: Sales-Weighted Fuel Economy of New Passenger Cars and Light-Duty Trucks, 1990-2008
17
18 Figure 3-12: Sales of New Passenger Cars and Light-Duty Trucks, 1990-2008
19
20 General aviation aircraft CO2 emissions increased by 60 percent (5.7 Tg) from 1990 to 2009, representing the largest
21 percentage increase of any transportation mode. Among on-road vehicles, CO2 emissions from light-duty trucks65
22 increased by the largest percentage, 59 percent (189.8 Tg) from 1990 to 2009. CO2 from the domestic operation of
23 commercial aircraft decreased by 18 percent (24.0 Tg) from 1990 to 2009. Across all categories of aviation66, CO2
24 emissions decreased by 21.6 percent (38.7 Tg) between 1990 and 2009. This includes a 59 percent (20.3 Tg)
25 decrease in emissions from domestic military operations. For further information on all greenhouse gas emissions
26 from transportation sources, please refer to Annex 3.2.
27 Table 3-12: CO2 Emissions from Fossil Fuel Combustion in Transportation End-Use Sector (Tg CO2 Eq.)a
Fuel/Vehicle Type 1990 2000 2005 2006 2007 2008 2009
Gasoline
Passenger Cars
Light-Duty Trucks
Medium- and Heavy -Duty
Trucks'3
Buses
Motorcycles
Recreational Boats
Distillate Fuel Oil
(Diesel)
Passenger Cars
Light-Duty Trucks
Medium- and Heavy-Duty
983.7
621.4
309.1
38.7
0.3
1.7
12.4
262.9
7.9
11.5
190.5
1,135.0
640.6
446.4
36.0
0.4
1.8
9.8
402.5
3.7
20.1
309.6
1,187.8
658.0
478.7
34.9
0.4
1.6
14.1
458.1
4.2
25.8
360.6
1,178.2
635.0
491.5
35.5
0.4
1.9
14.0
470.3
4.1
26.8
370.1
1,181.2
628.7
500.1
36.1
0.4
2.1
13.9
476.3
4.1
27.3
376.1
1,130.3
594.0
486.5
33.7
0.4
2.1
13.5
443.5
3.9
26.9
356.0
1,125.7
591.7
484.6
33.6
0.4
2.1
13.4
401.7
3.6
24.5
324.8
64 Biofuel estimates are presented for informational purposes only in the Energy chapter, in line with IPCC
methodological guidance and UNFCCC reporting obligations. Net carbon fluxes from changes in biogenic carbon
reservoirs in croplands are accounted for in the estimates for Land Use, Land-Use Change, and Forestry (see
Chapter 7). More information and additional analyses onbiofuels are available at EPA's "Renewable Fuels:
Regulations & Standards" web page: http://www.epa.gov/otaq/fuels/renewablefuels/regulations.htm
65Includes "light-duty trucks" fueled by gasoline, diesel and LPG.
66 Includes consumption of jet fuel and aviation gasoline. Does not include aircraft bunkers, which are not included in national
emission totals, in line with IPCC methodological guidance and UNFCCC reporting obligations.
Energy 3-13
-------
Trucks"
Buses
Rail
Recreational Boats
Ships and Other Boats
International Bunker
Fuels c
Jet Fuel
Commercial Aircraft
Military Aircraft
General Aviation Aircraft
International Bunker
Fuels c
Aviation Gasoline
General Aviation Aircraft
Residual Fuel Oil
Ships and Other Boats'1
International Bunker
Fuels c
Natural Gas
Passenger Cars
Light-Duty Trucks
Buses
Pipeline
LPG
Light-Duty Trucks
Medium- and Heavy -Duty
Trucks'3
Buses
Electricity
Rail
Total
Total (Including
Bunkers) c
8.0
35.5
2.0
7.5
11.7
176.2
135.4
34.4
6.4
46.4
3.1
3.1
22.6
22.6
53.7
36.0
-
36.0
1.4
0.6
0.8
-
3.0
3.0
1,489.0
1,600.8
10.2
42.1
2.7
14.1
6.3
199.8
169.2
21.1
9.5
58.8
2.5
2.5
33.3
33.3
33.3
35.6
0.4
35.2
0.7
0.5
0.3
+
3.4
3.4
1,813.0
1,911.4
10.6
45.6
3.1
8.1
9.4
194.2
161.2
18.1
14.9
56.7
2.4
2.4
19.3
19.3
43.6
33.1
0.8
32.2
1.7
1.3
0.4
-
4.7
4.7
1,901.3
2,011.1
10.8
47.8
3.2
7.5
8.8
169.5
137.1
16.4
16.0
74.6
2.3
2.3
23.0
23.0
45.0
33.1
0.8
32.3
1.7
1.2
0.5
-
4.5
4.5
1,882.6
2,011.0
10.8
46.6
3.3
8.2
8.2
168.7
138.1
16.1
14.5
73. 8
2.2
2.2
29.0
29.0
45.6
35.3
1.0
34.3
1.4
1.0
0.4
-
5.0
5.0
1,899.0
2,026.6
10.3
43.2
0.9
2.2
9.0
155.1
122.2
16.3
16.6
75.5
2.0
2.0
19.9
19.9
49.2
36.8
1.1
35.7
2.4
1.8
0.7
-
4.7
4.7
1,794.6
1,928.3
9.4
36.2
0.9
2.2
8.3
138.8
111.4
14.1
13.3
69.4
1.8
1.8
12.0
12.0
45.4
36.3
1.1
35.2
2.5
1.8
0.7
-
4.4
4.4
1,723.3
1,846.4
1 a This table does not include emissions from non-transportation mobile sources, such as agricultural equipment and
2 construction/mining equipment; it also does not include emissions associated with electricity consumption by pipelines or
3 lubricants used in transportation.
4 b Includes medium- and heavy-duty trucks over 8,500 Ibs.
5 ° Official estimates exclude emissions from the combustion of both aviation and marine international bunker fuels; however,
6 estimates including international bunker fuel-related emissions are presented for informational purposes.
7 Note: Totals may not sum due to independent rounding.
8 Note: See section 3.10 of this chapter, in line with IPCC methodological guidance and UNFCCC reporting obligations, for more
9 information on ethanol.
10 + Less than 0.05 Tg CO2 Eq.
11 - Unreported or zero
12 Fossil Fuel Combustion CFi4 and N2O Emissions from Mobile Sources
13 Mobile combustion includes emissions of CH4 and N2O from all transportation sources identified in the U.S.
14 inventory with the exception of pipelines, which are stationary; mobile sources also include non-transportation
15 sources such as construction/mining equipment, agricultural equipment, vehicles used off-road, and other sources
16 (e.g., snowmobiles, lawnmowers, etc.). Annex 3.2 includes a summary of all emissions from both transportation
17 and mobile sources. Table 3-13 and Table 3-14 provide CH4 and N2O emission estimates in Tg CO2 Eq.67
67 See Annex 3.2 for a complete time series of emission estimates for 1990 through 2009.
3-14 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1
2
o
J
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Mobile combustion was responsible for a small portion of national CH4 emissions (0.3 percent) but was the second
largest source of U.S. N2O emissions (9 percent). From 1990 to 2009, mobile source CH4 emissions declined by 53
percent, to 2.2 Tg CO2 Eq. (106 Gg), due largely to control technologies employed in on-road vehicles since the
mid-1990s to reduce CO, NOX, NMVOC, and CH4 emissions. Mobile source emissions of N2O decreased by 37
percent, to 27.8 Tg CO2 Eq. (90 Gg). Earlier generation control technologies initially resulted in higher N2O
emissions, causing a 26 percent increase in N2O emissions from mobile sources between 1990 and 1998.
Improvements in later-generation emission control technologies have reduced N2O output, resulting in a 50 percent
decrease in mobile source N2O emissions from 1998 to 2009 (Figure 3-13). Overall, CH4 and N2O emissions were
predominantly from gasoline-fueled passenger cars and light-duty trucks.
Figure 3-13: Mobile Source CH4 and N2O Emissions
Table 3-13: CH4 Emissions from Mobile Combustion (Tg CO2 Eq.)
Fuel Type/Vehicle Type3
Gasoline On-Road
Passenger Cars
Light-Duty Trucks
Medium- and Heavy -Duty
Trucks and Buses
Motorcycles
Diesel On-Road
Passenger Cars
Light-Duty Trucks
Medium- and Heavy -Duty
Trucks and Buses
Alternative Fuel On-Road
Non-Road
Ships and Boats
Rail
Aircraft
Agricultural Equipment13
Construction/Mining
Equipment0
Otherd
Total
1990
4.2
2.6
1.4
0.2
+
+
+
+
+
+
0.4
+
0.1
0.2
0.1
+
0.1
4.7
2000
2.8
1.6
1.1
0.1
+
+
+
+
+
+
0.5
+
0.1
0.2
0.1
0.1
0.1
3.4
2005
1.9
1.1
0.7
0.1
+
+
+
+
+
+
0.6
+
0.1
0.2
0.1
0.1
0.1
2.5
2006
1.7
1.0
0.6
0.1
+
+
+
+
+
0.1
0.6
+
0.1
0.1
0.1
0.1
0.1
2.3
2007
1.6
0.9
0.6
0.1
+
+
+
+
+
0.1
0.5
+
0.
0.
0.
0.
0.
2.2
2008
1.4
0.8
0.6
0.1
+
+
+
+
+
0.1
0.5
+
0.
0.
0.
0.
0.
2.0
2009
1.6
0.9
0.7
0.1
+
+
+
+
+
0.1
0.5
+
0.1
0.1
0.1
0.1
0.1
2.2
a See Annex 3.2 for definitions of on-road vehicle types.
b Includes equipment, such as tractors and combines, as well as fuel consumption from trucks that are used off-road in
agriculture.
0 Includes equipment, such as cranes, dumpers, and excavators, as well as fuel consumption from trucks that are used off-road in
construction.
d "Other" includes snowmobiles and other recreational equipment, logging equipment, lawn and garden equipment, railroad
equipment, airport equipment, commercial equipment, and industrial equipment, as well as fuel consumption from trucks that are
used off-road for commercial/industrial purposes.
Note: Totals may not sum due to independent rounding.
+ Less than 0.05 Tg CO2 Eq.
25 Table 3-14: N2O Emissions from Mobile Combustion (Tg CO2 Eq.)
Fuel Type/Vehicle Type"
Gasoline On-Road
Passenger Cars
Light-Duty Trucks
Medium- and Heavy -Duty
Trucks and Buses
Motorcycles
1990
40.1
25.4
14.1
0.6
+
2000
48.4
25.2
22.4
0.9
+
2005
32.1
17.7
13.6
0.8
+
2006
29.0
15.7
12.5
0.7
+
2007
25.5
13.7
11.1
0.7
+
2008
21.8
11.7
9.5
0.6
+
2009
23.7
11.9
11.1
0.6
+
Energy 3-15
-------
Diesel On-Road
Passenger Cars
Light-Duty Trucks
Medium- and Heavy -Duty
Trucks and Buses
Alternative Fuel On-Road
Non-Road
Ships and Boats
Rail
Aircraft
Agricultural Equipment13
Construction/Mining
Equipment0
Otherd
Total
0.2
+
+
0.2
0.1
3.6
0.6
0.3
1.7
0.2
0.3
0.4
43.9
0.3
+
+
0.3
0.1
4.3
0.9
0.3
1.9
0.3
0.4
0.5
53.2
0.3
+
+
0.3
0.2
4.3
0.6
0.4
1.9
0.4
0.5
0.6
36.9
0.3
+
+
0.3
0.2
4.2
0.7
0.4
1.6
0.4
0.5
0.6
33.6
0.3
+
+
0.3
0.2
4.3
0.8
0.4
1.6
0.4
0.5
0.6
30.3
0.3
+
+
0.3
0.2
3.8
0.5
0.3
1.5
0.4
0.5
0.6
26.1
0.4
+
+
0.4
0.2
3.5
0.4
0.3
1.3
0.4
0.5
0.6
27.8
1 a See Annex 3.2 for definitions of on-road vehicle types.
2 b Includes equipment, such as tractors and combines, as well as fuel consumption from trucks that are used off-road in
3 agriculture.
4 ° Includes equipment, such as cranes, dumpers, and excavators, as well as fuel consumption from trucks that are used off-road in
5 construction.
6 d "Other" includes snowmobiles and other recreational equipment, logging equipment, lawn and garden equipment, railroad
7 equipment, airport equipment, commercial equipment, and industrial equipment, as well as fuel consumption from trucks that are
8 used off-road for commercial/industrial purposes.
9 Note: Totals may not sum due to independent rounding.
10 + Less than 0.05 Tg CO2 Eq.
11 C02 from Fossil Fuel Combustion
12 Methodology
13 The methodology used by the United States for estimating CO2 emissions from fossil fuel combustion is
14 conceptually similar to the approach recommended by the IPCC for countries that intend to develop detailed,
15 sectoral-based emission estimates in line with a tier 2 method in the 2006 IPCC Guidelines for National Greenhouse
16 Gas Inventories (IPCC 2006). A detailed description of the U.S. methodology is presented in Annex 2.1, and is
17 characterized by the following steps:
18 1. Determine total fuel consumption by fuel type and sector. Total fossil fuel consumption for each year is
19 estimated by aggregating consumption data by end-use sector (e.g., commercial, industrial, etc.), primary
20 fuel type (e.g., coal, petroleum, gas), and secondary fuel category (e.g., motor gasoline, distillate fuel oil,
21 etc.). Fuel consumption data for the United States were obtained directly from the Energy Information
22 Administration (EIA) of the U. S. Department of Energy (DOE), primarily from the Monthly Energy
23 Review and published supplemental tables on petroleum product detail (EIA 2010c). The EIA does not
24 include territories in its national energy statistics, so fuel consumption data for territories were collected
25 separately from Jacobs (2010).68
26 For consistency of reporting, the IPCC has recommended that countries report energy data using the
27 International Energy Agency (IEA) reporting convention and/or IEA data. Data in the IEA format are
28 presented "top down"—that is, energy consumption for fuel types and categories are estimated from energy
29 production data (accounting for imports, exports, stock changes, and losses). The resulting quantities are
30 referred to as "apparent consumption." The data collected in the United States by EIA on an annual basis
31 and used in this inventory are predominantly from mid-stream or conversion energy consumers such as
32 refiners and electric power generators. These annual surveys are supplemented with end-use energy
33 consumption surveys, such as the Manufacturing Energy Consumption Survey, that are conducted on a
34 periodic basis (every 4 years). These consumption data sets help inform the annual surveys to arrive at the
68 Fuel consumption by U.S. territories (i.e., American Samoa, Guam, Puerto Rico, U.S. Virgin Islands, Wake Island, and other
U.S. Pacific Islands) is included in this report and contributed emissions of 42 Lg CO2 Eq. in 2009.
3-16 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 national total and sectoral breakdowns for that total. 69
2 It is also important to note that U.S. fossil fuel energy statistics are generally presented using gross calorific
3 values (GCV) (i.e., higher heating values). Fuel consumption activity data presented here have not been
4 adjusted to correspond to international standards, which are to report energy statistics in terms of net
5 calorific values (NCV) (i.e., lower heating values).70
6 2. Subtract uses accounted for in the Industrial Processes chapter. Portions of the fuel consumption data for
7 seven fuel categories—coking coal, distillate fuel, industrial other coal, petroleum coke, natural gas,
8 residual fuel oil, and other oil—were reallocated to the industrial processes chapter, as they were consumed
9 during non-energy related industrial activity. To make these adjustments, additional data were collected
10 from AISI (2004 through 2010), Coffeyville (2010), U.S. Census Bureau (2010), EIA (2010c), USGS
11 (1991 through 2010), USGS (1994 through 2010), USGS (1995, 1998, 2000 through 2002, 2007, and
12 2009), USGS (1991 through 2009a), and USGS (1991 through 2009b).71
13 3. Adjust for conversion of fuels and exports ofCO2. Fossil fuel consumption estimates are adjusted
14 downward to exclude fuels created from other fossil fuels and exports of CO2.72 Synthetic natural gas is
15 created from industrial coal, and is currently included in EIA statistics for both coal and natural gas.
16 Therefore, synthetic natural gas is subtracted from energy consumption statistics.73 Since October 2000,
17 the Dakota Gasification Plant has been exporting CO2 to Canada by pipeline. Since this CO2 is not emitted
18 to the atmosphere in the United States, energy used to produce this CO2 is subtracted from energy
19 consumption statistics. To make these adjustments, additional data for ethanol were collected from EIA
20 (2010c) and data for synthetic natural gas were collected from EIA (2009b), and data for CO2 exports were
21 collected from the Dakota Gasification Company (2006), Fitzpatrick (2002), Erickson (2003), and EIA
22 (2007b).
23 4. Adjust Sectoral Allocation of Distillate Fuel Oil and Motor Gasoline. EPA had conducted a separate
24 bottom-up analysis of transportation fuel consumption based on the Federal Highway Administration's
25 (FHWA) VMT that indicated that the amount of distillate and motor gasoline consumption allocated to the
26 transportation sector in the EIA statistics should be adjusted. Therefore, for these estimates, the
27 transportation sector's distillate fuel and motor gasoline consumption was adjusted upward to match the
28 value obtained from the bottom-up analysis based on VMT. As the total distillate and motor gasoline
29 consumption estimate from EIA are considered to be accurate at the national level, the distillate
30 consumption totals for the residential, commercial, and industrial sectors were adjusted downward
31 proportionately. The data sources used in the bottom-up analysis of transportation fuel consumption include
32 AAR (2009 through 2010), Benson (2002 through 2004), DOE (1993 through 2010), EIA (2009a), EIA
33 (1991 through 2010), EPA (2009), and FHWA (1996 through 2010).74
34 5. Adjust for fuels consumed for non-energy uses. U.S. aggregate energy statistics include consumption of
35 fossil fuels for non-energy purposes. These are fossil fuels that are manufactured into plastics, asphalt,
36 lubricants, or other products. Depending on the end-use, this can result in storage of some or all of the C
37 contained in the fuel for a period of time. As the emission pathways of C used for non-energy purposes are
38 vastly different than fuel combustion (since the C in these fuels ends up in products instead of being
69 See IPCC Reference Approach for estimating CO2 emissions from fossil fuel combustion in Annex 4 for a comparison of U.S.
estimates using top-down and bottom-up approaches.
70 A crude convention to convert between gross and net calorific values is to multiply the heat content of solid and liquid fossil
fuels by 0.95 and gaseous fuels by 0.9 to account for the water content of the fuels. Biomass-based fuels in U.S. energy statistics,
however, are generally presented using net calorific values.
71 See sections on Iron and Steel Production and Metallurgical Coke Production, Ammonia Production and Urea Consumption,
Petrochemical Production, Titanium Dioxide Production, Ferroalloy Production, Aluminum Production, and Silicon Carbide
Production and Consumption in the Industrial Processes chapter.
72 Energy statistics from EIA(2010c) are already adjusted downward to account for ethanol added to motor gasoline, and biogas
in natural gas.
73 These adjustments are explained in greater detail in Annex 2.1.
74 The source of VMT data is FHWA VM-1 table, which has not yet been published for 1990-2009. A proxy has been used for
initial inventory estimate and data will be updated for final publication.
Energy 3-17
-------
1 combusted), these emissions are estimated separately in the Carbon Emitted and Stored in Products from
2 Non-Energy Uses of Fossil Fuels section in this chapter. Therefore, the amount of fuels used for non-
3 energy purposes was subtracted from total fuel consumption. Data on non-fuel consumption was provided
4 by EIA (2010c).
5 6. Subtract consumption of international bunker fuels. According to the UNFCCC reporting guidelines
6 emissions from international transport activities, or bunker fuels, should not be included in national totals.
7 U.S. energy consumption statistics include these bunker fuels (e.g., distillate fuel oil, residual fuel oil, and
8 jet fuel) as part of consumption by the transportation end-use sector, however, so emissions from
9 international transport activities were calculated separately following the same procedures used for
10 emissions from consumption of all fossil fuels (i.e., estimation of consumption, and determination of C
11 content).75 The Office of the Under Secretary of Defense (Installations and Environment) and the Defense
12 Energy Support Center (Defense Logistics Agency) of the U.S. Department of Defense (DoD) (DESC
13 2011) supplied data on military jet fuel and marine fuel use. Commercial jet fuel use was obtained from
14 FAA (2006 and 2008); residual and distillate fuel use for civilian marine bunkers was obtained from DOC
15 (1991 through 2010) for 1990 through 2001, 2007 and 2008, and DHS (2008) for 2003 through 2006.
16 Consumption of these fuels was subtracted from the corresponding fuels in the transportation end-use
17 sector. Estimates of international bunker fuel emissions for the United States are discussed in detail later in
18 the International Bunker Fuels section of this chapter.
19 7. Determine the total C content of fuels consumed. Total C was estimated by multiplying the amount of fuel
20 consumed by the amount of C in each fuel. This total C estimate defines the maximum amount of C that
21 could potentially be released to the atmosphere if all of the C in each fuel was converted to CO2. The C
22 content coefficients used by the United States were obtained from EIA's Emissions of Greenhouse Gases in
23 the United States 2008 (EIA 2009a), and an EPA analysis of C content coefficients used in the mandatory
24 reporting rule (EPA 2010a). A discussion of the methodology used to develop the C content coefficients
25 are presented in Annexes 2.1 and 2.2.
26 8. Estimate CO2 Emissions. Total CO2 emissions are the product of the adjusted energy consumption (from
27 the previous methodology steps 1 through 6), the C content of the fuels consumed, and the fraction of C
28 that is oxidized. The fraction oxidized was assumed to be 100 percent for petroleum, coal, and natural gas
29 based on guidance in IPCC (2006) (see Annex 2.1).
30 9. Allocate transportation emissions by vehicle type. This report provides a more detailed accounting of
31 emissions from transportation because it is such a large consumer of fossil fuels in the United States. For
32 fuel types other than jet fuel, fuel consumption data by vehicle type and transportation mode were used to
33 allocate emissions by fuel type calculated for the transportation end-use sector.
34 • For on-road vehicles, annual estimates of combined motor gasoline and diesel fuel consumption by
35 vehicle category were obtained from FHWA (1996 through 2010); for each vehicle category, the
36 percent gasoline, diesel, and other (e.g., CNG, LPG) fuel consumption are estimated using data from
37 DOE (1993 through 2010). FHWA data for 2009 fuel consumption was not available for the
38 Inventory public review file, and so proxy data was used. The final version of the inventory will
39 include data from the most recent VM-1 file, which is expected to be released soon. As such, fuel
40 consumption and emissions estimates are expected to change when these data become available.
41 • For non-road vehicles, activity data were obtained from AAR (2009 through 2010), APTA (2007
42 through 2010), BEA (1991 through 2009), Benson (2002 through 2004), DOE (1993 through 2010),
43 DESC (2011), DOC (1991 through 2010), DOT (1991 through 2010), EIA (2009a), EIA (2009d), EIA
44 (2007a), EIA (2002), EIA (1991 through 2009), EPA (2010b), FAA (2008), and Gaffney (2007).
45 • For jet fuel used by aircraft, CO2 emissions were calculated directly based on reported consumption of
46 fuel as reported by EIA, and allocated to commercial aircraft using flight-specific fuel consumption
47 data from the Federal Aviation Administration's (FAA) Aviation Environmental Design Tool (AEDT)
48 (FAA 2011). 76 Allocation to domestic general aviation was made using FAA Aerospace Forecast
75 See International Bunker Fuels section in this chapter for a more detailed discussion.
76 Data for inventory years 2000 through 2005 were developed using the FAA's System for assessing Aviation's Global
3-18 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 data, and allocation to domestic military uses was made using DoD data (see Annex 3.7).
2 Heat contents and densities were obtained from EIA (2010b) and USAF (1998).77
o
5
4 [BEGIN BOX]
5
6 Box 3-2: Carbon Intensity of U.S. Energy Consumption
7
8 Fossil fuels are the dominant source of energy in the United States, and CO2 is the dominant greenhouse gas emitted
9 as a product from their combustion. Energy-related CO2 emissions are impacted by not only lower levels of energy
10 consumption but also by lowering the C intensity of the energy sources employed (e.g., fuel switching from coal to
11 natural gas). The amount of C emitted from the combustion of fossil fuels is dependent upon the C content of the
12 fuel and the fraction of that C that is oxidized. Fossil fuels vary in their average C content, ranging from about 53
13 Tg CO2 Eq./QBtu for natural gas to upwards of 95 Tg CO2 Eq./QBtu for coal and petroleum coke.78 In general, the
14 C content per unit of energy of fossil fuels is the highest for coal products, followed by petroleum, and then natural
15 gas. The overall C intensity of the U.S. economy is thus dependent upon the quantity and combination of fuels and
16 other energy sources employed to meet demand.
17 Table 3-15 provides a time series of the C intensity for each sector of the U.S. economy. The time series
18 incorporates only the energy consumed from the direct combustion of fossil fuels in each sector. For example, the C
19 intensity for the residential sector does not include the energy from or emissions related to the consumption of
20 electricity for lighting. Looking only at this direct consumption of fossil fuels, the residential sector exhibited the
21 lowest C intensity, which is related to the large percentage of its energy derived from natural gas for heating. The C
22 intensity of the commercial sector has predominantly declined since 1990 as commercial businesses shift away from
23 petroleum to natural gas. The industrial sector was more dependent on petroleum and coal than either the residential
24 or commercial sectors, and thus had higher C intensities over this period. The C intensity of the transportation
25 sector was closely related to the C content of petroleum products (e.g., motor gasoline and jet fuel, both around 70
26 Tg CO2 Eq./EJ), which were the primary sources of energy. Lastly, the electricity generation sector had the highest
27 C intensity due to its heavy reliance on coal for generating electricity.
28 Table 3-15: Carbon Intensity from Direct Fossil Fuel Combustion by Sector (Tg CO2 Eq./QBtu)
Sector 1990 2000 2005 2006 2007 2008 2009
29
30
31
32
33
Residential a 57.4 56.6
Commercial a 59.2 57.2
Industrial a 64.3 62.9
Transportation3 71.1 71.3
Electricity Generation b 87.3 86.2
U.S. Territories' 73.0 72.5
All Sectors c 73.0 73.0
a Does not include electricity or renewable energy consumption.
56.6
57.5
64.3
71.4
85.8
73.4
73.5
56.5
57.2
64.6
71.6
85.4
73.5
73.6
56.3
57.1
64.1
71.9
84.7
73.8
73.3
56.1
56.8
63.7
71.6
84.9
73.3
73.1
56.1
56.6
63.4
71.5
83.7
73.1
72.5
b Does not include electricity produced using nuclear or renewable energy.
0 Does not include nuclear or renewable energy consumption.
Note: Excludes non-energy fuel use emissions and consumption.
Emissions (SAGE) model. That tool has been incorporated into the Aviation Environmental Design Tool (AEDT), which
calculates noise in addition to aircraft fuel burn and emissions for all commercial flights globally in a given year. Data for
inventory years 2006-2008 were developed using AEDT. The AEDT model dynamically models aircraft performance in space
and time to produce fuel bum, emissions and noise. Full flight gate-to-gate analyses are possible for study sizes ranging from a
single flight at an airport to scenarios at the regional, national, and global levels. AEDT is currently used by the U.S. government
to consider the interdependencies between aircraft-related fuel bum, noise and emissions.
77 For a more detailed description of the data sources used for the analysis of the transportation end use sector see the Mobile
Combustion (excluding CO2) and International Bunker Fuels sections of the Energy chapter, Annex 3.2, and Annex 3.7.
78 One exajoule (EJ) is equal to 1018 joules or 0.9478 QBtu.
Energy 3-19
-------
1 Over the twenty-year period of 1990 through 2009, however, the C intensity of U.S. energy consumption has been
2 fairly constant, as the proportion of fossil fuels used by the individual sectors has not changed significantly. Per
3 capita energy consumption fluctuated little from 1990 to 2007, but in 2009 is approximately 9 percent below levels
4 in 1990 (see Figure 3-14). Due to a general shift from a manufacturing-based economy to a service-based economy,
5 as well as overall increases in efficiency, energy consumption and energy-related CO2 emissions per dollar of gross
6 domestic product (GDP) have both declined since 1990 (BEA 2010).
7
8 Figure 3-14: U.S. Energy Consumption and Energy-Related CO2 Emissions Per Capita and Per Dollar GDP
9
10 C intensity estimates were developed using nuclear and renewable energy data from EIA (2010b), EPA (2010a), and
11 fossil fuel consumption data as discussed above and presented in Annex 2.1.
12
13 [END BOX]
14
15 Uncertainty and Time Series Consistency
16 For estimates of CO2 from fossil fuel combustion, the amount of CO2 emitted is directly related to the amount of
17 fuel consumed, the fraction of the fuel that is oxidized, and the carbon content of the fuel. Therefore, a careful
18 accounting of fossil fuel consumption by fuel type, average carbon contents of fossil fuels consumed, and
19 production of fossil fuel-based products with long-term carbon storage should yield an accurate estimate of CO2
20 emissions.
21 Nevertheless, there are uncertainties in the consumption data, carbon content of fuels and products, and carbon
22 oxidation efficiencies. For example, given the same primary fuel type (e.g., coal, petroleum, or natural gas), the
23 amount of carbon contained in the fuel per unit of useful energy can vary. For the United States, however, the
24 impact of these uncertainties on overall CO2 emission estimates is believed to be relatively small. See, for example,
25 Marland and Pippin (1990).
26 Although statistics of total fossil fuel and other energy consumption are relatively accurate, the allocation of this
27 consumption to individual end-use sectors (i.e., residential, commercial, industrial, and transportation) is less
28 certain. For example, for some fuels the sectoral allocations are based on price rates (i.e., tariffs), but a commercial
29 establishment may be able to negotiate an industrial rate or a small industrial establishment may end up paying an
30 industrial rate, leading to a misallocation of emissions. Also, the deregulation of the natural gas industry and the
31 more recent deregulation of the electric power industry have likely led to some minor problems in collecting
32 accurate energy statistics as firms in these industries have undergone significant restructuring.
33 To calculate the total CO2 emission estimate from energy-related fossil fuel combustion, the amount of fuel used in
34 these non-energy production processes were subtracted from the total fossil fuel consumption for 2009. The amount
35 of CO2 emissions resulting from non-energy related fossil fuel use has been calculated separately and reported in the
36 Carbon Emitted from Non-Energy Uses of Fossil Fuels section of this report. These factors all contribute to the
37 uncertainty in the CO2 estimates. Detailed discussions on the uncertainties associated with C emitted from Non-
3 8 Energy Uses of Fossil Fuels can be found within that section of this chapter.
39 Various sources of uncertainty surround the estimation of emissions from international bunker fuels, which are
40 subtracted from the U.S. totals (see the detailed discussions on these uncertainties provided in the International
41 Bunker Fuels section of this chapter). Another source of uncertainty is fuel consumption by U.S. territories. The
42 United States does not collect energy statistics for its territories at the same level of detail as for the fifty states and
43 the District of Columbia. Therefore, estimating both emissions and bunker fuel consumption by these territories is
44 difficult.
45 Uncertainties in the emission estimates presented above also result from the data used to allocate CO2 emissions
46 from the transportation end-use sector to individual vehicle types and transport modes. In many cases, bottom-up
47 estimates of fuel consumption by vehicle type do not match aggregate fuel-type estimates from EIA. Further
48 research is planned to improve the allocation into detailed transportation end-use sector emissions.
49 The uncertainty analysis was performed by primary fuel type for each end-use sector, using the IPCC-recommended
3-20 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1
2
3
4
5
6
7
8
9
10
1 1
12
1 3
14
15
16
17
18
19
20
21
Tier 2 uncertainty estimation methodology, Monte Carlo Simulation technique, with @RISK software. For this
uncertainty estimation, the inventory estimation model for CO2 from fossil fuel combustion was integrated with the
relevant 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 120 input variables
were modeled for CO2 from energy -related Fossil Fuel Combustion (including about 10 for non-energy fuel
consumption and about 20 for International Bunker Fuels).
In developing the uncertainty estimation model, uniform distributions were assumed for all activity -related input
variables and emission factors, based on the SAIC/EIA (2001) report.79 Triangular distributions were assigned for
the oxidization factors (or combustion efficiencies). The uncertainty ranges were assigned to the input variables
based on the data reported in SAIC/EIA (200 1) and on conversations with various agency personnel.80
The uncertainty ranges for the activity -related input variables were typically asymmetric around their inventory
estimates; the uncertainty ranges for the emissions factors were symmetric. Bias (or systematic uncertainties)
associated with these variables accounted for much of the uncertainties associated with these variables (SAIC/EIA
2001). 81 For purposes of this uncertainty analysis, each input variable was simulated 10,000 times through Monte
Carlo Sampling.
The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-16. Fossil fuel combustion
CO2 emissions in 2009 were estimated to be between 5,153.1 and 5,527.5 Tg CO2 Eq. at a 95 percent confidence
level. This indicates a range of 1 percent below to 6 percent above the 2009 emission estimate of 5,212.0 Tg CO2
Eq.
Table 3-16: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Energy-related Fossil
Combustion by Fuel Type and Sector (Tg CO2 Eq. and Percent)
Fuel
Fuel/Sector
Coalb
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Natural Gas b
Residential
Commercial
Industrial
Transportation
Electricity Generation
U.S. Territories
Petroleum b
Residential
2009 Emission Estimate
(Tg C02 Eq.)
1,841.0
0.6
5.8
83.4
NE
1,747.6
3.5
1,200.9
257.2
167.9
365.0
36.3
373.1
1.5
2,169.7
82.4
Uncertainty Range Relative to Emission Estimate"
(TgC02
Lower
Bound
1,779.4
0.6
5.5
80.5
NE
1,679.6
3.1
1,209.1
249.9
163.3
374.7
35.2
362.3
1.3
2,074.2
77.9
Eq.)
Upper
Bound
2,014.3
0.7
6.7
97.7
NE
1,913.9
4.2
1,276.4
275.2
179.7
412.7
38.8
392.1
1.7
2,331.2
86.7
(°/
Lower
Bound
-3%
-5%
-5%
-3%
NA
-4%
-12%
+1%
-3%
-3%
+3%
-3%
-3%
-12%
-4%
-6%
Upper
Bound
+9%
+15%
+15%
+17%
NA
+10%
+19%
+6%
+7%
+7%
+13%
+7%
+5%
+17%
+7%
+5%
79 SAIC/EIA (2001) characterizes the underlying probability density function for the input variables as a combination of uniform
and normal distributions (the former to represent the bias component and the latter to represent the random component).
However, for purposes of the current uncertainty analysis, it was determined that uniform distribution was more appropriate to
characterize the probability density function underlying each of these variables.
80 In the SAIC/EIA (2001) report, the quantitative uncertainty estimates were developed for each of the three major fossil fuels
used within each end-use sector; the variations within the sub-fuel types within each end-use sector were not modeled. However,
for purposes of assigning uncertainty estimates to the sub-fuel type categories within each end-use sector in the current
uncertainty analysis, SAIC/EIA (2001)-reported uncertainty estimates were extrapolated.
81 Although, in general, random uncertainties are the main focus of statistical uncertainty analysis, when the uncertainty
estimates are elicited from experts, their estimates include both random and systematic uncertainties. Hence, both these types of
uncertainties are represented in this uncertainty analysis.
Energy 3-21
-------
Commercial
Industrial
Transportation
Electric Utilities
U.S. Territories
Total (excluding
Geothermal) b
Geothermal
Total (including
Geothermal) b'c
45.1
290.0
1,682.6
32.9
36.7
5,211.6
0.4
5,212.0
43.0
244.2
1,600.0
31.5
33.8
5,152.7
NE
5,153.1
47.0
342.7
1,827.2
35.3
40.8
5,527.1
NE
5,527.5
-5%
-16%
-5%
-4%
-8%
-1%
NE
-1%
+4%
+18%
+9%
+7%
+11%
+6%
NE
+6%
1 NA (Not Applicable)
2 NE (Not Estimated)
3 a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
4 b The low and high estimates for total emissions were calculated separately through simulations and, hence, the low and high
5 emission estimates for the sub-source categories do not sum to total emissions.
6 ° Geothermal emissions added for reporting purposes, but an uncertainty analysis was not performed for CO2 emissions from
7 geothermal production.
8
9 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
10 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
11 above.
12 QA/QC and Verification
13 A source-specific QA/QC plan for CO2 from fossil fuel combustion was developed and implemented. This effort
14 included a Tier 1 analysis, as well as portions of a Tier 2 analysis. The Tier 2 procedures that were implemented
15 involved checks specifically focusing on the activity data and methodology used for estimating CO2 emissions from
16 fossil fuel combustion in the United States. Emission totals for the different sectors and fuels were compared and
17 trends were investigated to determine whether any corrective actions were needed. Minor corrective actions were
18 taken.
19 Recalculations Discussion
20 The Energy Information Administration (EIA 2010c) updated energy consumption statistics across the time series.
21 These revisions primarily impacted the emission estimates for 2007 and 2008. In addition, the coal emissions for
22 U.S. Territories decreased from 2001 to 2008 due to the closure of a coal power plan in the U.S. Virgin Islands.
23 Overall, these changes resulted in an average annual increase of 3.8 Tg CO2 Eq. (less than 0.1 percent) in CO2
24 emissions from fossil fuel combustion for the period 1990 through 2008.
25 Planned Improvements
26 To reduce uncertainty of CO2 from fossil fuel combustion estimates, efforts will be taken to work with EIA and
27 other agencies to improve the quality of the U.S. territories data. This improvement is not all-inclusive, and is part
28 of an ongoing analysis and efforts to continually improve the CO2 from fossil fuel combustion estimates. In
29 addition, further expert elicitation may be conducted to better quantify the total uncertainty associated with
30 emissions from this source.
31 Beginning in 2010, those facilities that emit over 25,000 tons of greenhouse gases (CO2e) from stationary
32 combustion across all sectors of the economy will be required to calculate and report their greenhouse gas emissions
33 to EPA through its Greenhouse Gas Reporting Program. These data will be used in future inventories to improve the
34 emission calculations through the use of these collected higher tier methodological data.
35 CH4 and N20 from Stationary Combustion
36 Methodology
37 CH4 and N2O emissions from stationary combustion were estimated by multiplying fossil fuel and wood
38 consumption data by emission factors (by sector and fuel type). National coal, natural gas, fuel oil, and wood
3-22 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 consumption data were grouped by sector: industrial, commercial, residential, electricity generation, and U.S.
2 territories. For the CH4 and N2O estimates, wood consumption data for the United States was obtained from EIA's
3 Annual Energy Review (ElA 201 Ob). Fuel consumption data for coal, natural gas, and fuel oil for the United States
4 were obtained from EIA's Monthly Energy Review and unpublished supplemental tables on petroleum product
5 detail (EIA 2010c). Because the United States does not include territories in its national energy statistics, fuel
6 consumption data for territories were provided separately by Jacobs (2010).82 Fuel consumption for the industrial
7 sector was adjusted to subtract out construction and agricultural use, which is reported under mobile sources.83
8 Construction and agricultural fuel use was obtained from EPA (2010). Estimates for wood biomass consumption for
9 fuel combustion do not include wood wastes, liquors, municipal solid waste, tires, etc., that are reported as biomass
10 by EIA.
11 Emission factors for the four end-use sectors were provided by the 2006 IPCC Guidelines for National Greenhouse
12 Gas Inventories (IPCC 2006). U.S. territories' emission factors were estimated using the U.S. emission factors for
13 the primary sector in which each fuel was combusted.
14 More detailed information on the methodology for calculating emissions from stationary combustion, including
15 emission factors and activity data, is provided in Annex 3.1.
16 Uncertainty and Time-Series Consistency
17 CH4 emission estimates from stationary sources exhibit high uncertainty, primarily due to difficulties in calculating
18 emissions from wood combustion (i.e., fireplaces and wood stoves). The estimates of CH4 and N2O emissions
19 presented are based on broad indicators of emissions (i.e., fuel use multiplied by an aggregate emission factor for
20 different sectors), rather than specific emission processes (i.e., by combustion technology and type of emission
21 control).
22 An uncertainty analysis was performed by primary fuel type for each end-use sector, using the IPCC-recommended
23 Tier 2 uncertainty estimation methodology, Monte Carlo Simulation technique, with @RISK software.
24 The uncertainty estimation model for this source category was developed by integrating the CH4 and N2O stationary
25 source inventory estimation models with the model for CO2 from fossil fuel combustion to realistically characterize
26 the interaction (or endogenous correlation) between the variables of these three models. About 55 input variables
27 were simulated for the uncertainty analysis of this source category (about 20 from the CO2 emissions from fossil
28 fuel combustion inventory estimation model and about 35 from the stationary source inventory models).
29 In developing the uncertainty estimation model, uniform distribution was assumed for all activity-related input
30 variables and N2O emission factors, based on the SAIC/EIA (2001) report.84 For these variables, the uncertainty
31 ranges were assigned to the input variables based on the data reported in SAIC/EIA (2001).85 However, the CH4
32 emission factors differ from those used by EIA. Since these factors were obtained from IPCC/UNEP/OECD/IEA
33 (1997), uncertainty ranges were assigned based on IPCC default uncertainty estimates (IPCC 2000).
34 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-17. Stationary combustion
35 CH4 emissions in 2009 (including biomass) were estimated to be between 4.0 and 14.0 Tg CO2 Eq. at a 95 percent
82 U.S. territories data also include combustion from mobile activities because data to allocate territories' energy use were
unavailable. For this reason, CH4 and N2O emissions from combustion by U.S. territories are only included in the stationary
combustion totals.
83 Though emissions from construction and farm use occur due to both stationary and mobile sources, detailed data was not
available to determine the magnitude from each. Currently, these emissions are assumed to be predominantly from mobile
sources.
84 SAIC/EIA (2001) characterizes the underlying probability density function for the input variables as a combination of uniform
and normal distributions (the former distribution to represent the bias component and the latter to represent the random
component). However, for purposes of the current uncertainty analysis, it was determined that uniform distribution was more
appropriate to characterize the probability density function underlying each of these variables.
85 In the SAIC/EIA (2001) report, the quantitative uncertainty estimates were developed for each of the three major fossil fuels
used within each end-use sector; the variations within the sub-fuel types within each end-use sector were not modeled. However,
for purposes of assigning uncertainty estimates to the sub-fuel type categories within each end-use sector in the current
uncertainty analysis, SAIC/EIA (2001)-reported uncertainty estimates were extrapolated.
Energy 3-23
-------
1 confidence level. This indicates a range of 34 percent below to 127 percent above the 2009 emission estimate of 6.2
2 Tg CO2 Eq.86 Stationary combustion N2O emissions in 2009 (including biomass) were estimated to be between 9.7
3 and 36.8 Tg CO2 Eq. at a 95 percent confidence level. This indicates a range of 24 percent below to 187 percent
4 above the 2009 emissions estimate of 12.8 Tg CO2 Eq.
5 Table 3-17: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Energy-Related Stationary
6 Combustion, Including Biomass (Tg CO2 Eq. and Percent)
Source Gas 2009 Emission
Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Stationary Combustion CH4 6.2
Stationary Combustion N2O 12.8
4.0 14.0 -34% +127%
9.7 36.8 -24% +187%
7 a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
8
9 The uncertainties associated with the emission estimates of CH4 and N2O are greater than those associated with
10 estimates of CO2 from fossil fuel combustion, which mainly rely on the carbon content of the fuel combusted.
11 Uncertainties in both CH4 and N2O estimates are due to the fact that emissions are estimated based on emission
12 factors representing only a limited subset of combustion conditions. For the indirect greenhouse gases, uncertainties
13 are partly due to assumptions concerning combustion technology types, age of equipment, emission factors used,
14 and activity data projections.
15 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
16 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
17 above.
18 QA/QC and Verification
19 A source-specific QA/QC plan for stationary combustion was developed and implemented. This effort included a
20 Tier 1 analysis, as well as portions of a Tier 2 analysis. The Tier 2 procedures that were implemented involved
21 checks specifically focusing on the activity data and emission factor sources and methodology used for estimating
22 CH4, N2O, and the indirect greenhouse gases from stationary combustion in the United States. Emission totals for
23 the different sectors and fuels were compared and trends were investigated.
24 Recalculations Discussion
25 Historical CH4 and N2O emissions from stationary sources (excluding CO2) were revised due to a couple of changes,
26 mainly impacting 2007 and 2008 estimates. Slight changes to emission estimates for sectors are due to revised data
27 from EIA (2010b). Wood consumption data in EIA (2010c) were revised for the residential, commercial, and
28 industrial sectors for 2007 and 2008 as well as for the electric power sector for 2006 through 2008. The
29 combination of the methodological and historical data changes resulted in an average annual increase of 0.01 Tg
30 CO2 Eq. (0.2 percent) in CH4 emissions from stationary combustion and an average annual decrease of 0.07 Tg CO2
31 Eq. (0.5 percent) in N2O emissions from stationary combustion for the period 1990 through 2008.
32 Planned Improvements
33 Several items are being evaluated to improve the CH4 and N2O emission estimates from stationary combustion and
34 to reduce uncertainty. Efforts will be taken to work with EIA and other agencies to improve the quality of the U.S.
35 territories data. Because these data are not broken out by stationary and mobile uses, further research will be aimed
36 at trying to allocate consumption appropriately. In addition, the uncertainty of biomass emissions will be further
37 investigated since it was expected that the exclusion of biomass from the uncertainty estimates would reduce the
38 uncertainty; and in actuality the exclusion of biomass increases the uncertainty. These improvements are not all-
86 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.
3-24 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 inclusive, but are part of an ongoing analysis and efforts to continually improve these stationary estimates.
2 Beginning in 2010, those facilities that emit over 25,000 tons of greenhouse gases (CO2e) from stationary
3 combustion across all sectors of the economy will be required to calculate and report their greenhouse gas emissions
4 to EPA through its Greenhouse Gas Reporting Program. These data will be used in future inventories to improve the
5 emission calculations through the use of these collected higher tier methodological data.
6 CH4 and N20 from Mobile Combustion
7 Methodology
8 Estimates of CH4 and N2O emissions from mobile combustion were calculated by multiplying emission factors by
9 measures of activity for each fuel and vehicle type (e.g., light-duty gasoline trucks). Activity data included vehicle
10 miles traveled (VMT) for on-road vehicles and fuel consumption for non-road mobile sources. The activity data and
11 emission factors used are described in the subsections that follow. A complete discussion of the methodology used
12 to estimate CH4 and N2O emissions from mobile combustion and the emission factors used in the calculations is
13 provided in Annex 3.2.
14 On-Road Vehicles
15 Estimates of CH4 and N2O emissions from gasoline and diesel on-road vehicles are based on VMT and emission
16 factors by vehicle type, fuel type, model year, and emission control technology. Emission estimates for alternative
17 fuel vehicles (AFVs)87 are based on VMT and emission factors by vehicle and fuel type.
18 Emission factors for gasoline and diesel on-road vehicles utilizing Tier 2 and Low Emission Vehicle (LEV)
19 technologies were developed by ICF (2006b); all other gasoline and diesel on-road vehicle emissions factors were
20 developed by ICF (2004). These factors were derived from EPA, California Air Resources Board (CARD) and
21 Environment Canada laboratory test results of different vehicle and control technology types. The EPA, CARD and
22 Environment Canada tests were designed following the Federal Test Procedure (FTP), which covers three separate
23 driving segments, since vehicles emit varying amounts of GHGs depending on the driving segment. These driving
24 segments are: (1) a transient driving cycle that includes cold start and running emissions, (2) a cycle that represents
25 running emissions only, and (3) a transient driving cycle that includes hot start and running emissions. For each test
26 run, a bag was affixed to the tailpipe of the vehicle and the exhaust was collected; the content of this bag was then
27 analyzed to determine quantities of gases present. The emissions characteristics of segment 2 were used to define
28 running emissions, and subtracted from the total FTP emissions to determine start emissions. These were then
29 recombined based upon the ratio of start to running emissions for each vehicle class from MOBILE6.2, an EPA
30 emission factor model that predicts gram per mile emissions of CO2, CO, HC, NOX, and PM from vehicles under
31 various conditions, to approximate average driving characteristics.88
32 Emission factors for AFVs were developed by ICF (2006a) after examining Argonne National Laboratory's GREET
33 1.7-Transportation Fuel Cycle Model (ANL 2006) and Lipman and Delucchi (2002). These sources describe AFV
34 emission factors in terms of ratios to conventional vehicle emission factors. Ratios of AFV to conventional vehicle
35 emissions factors were then applied to estimated Tier 1 emissions factors from light-duty gasoline vehicles to
36 estimate light-duty AFVs. Emissions factors for heavy-duty AFVs were developed in relation to gasoline heavy-
37 duty vehicles. A complete discussion of the data source and methodology used to determine emission factors from
38 AFVs is provided in Annex 3.2.
39 Annual VMT data for 1990 through 2010 were obtained from the Federal Highway Administration's (FHWA)
40 Highway Performance Monitoring System database as reported in Highway Statistics (FHWA 1996 through
41 2010).89 VMT estimates were then allocated from FHWA's vehicle categories to fuel-specific vehicle categories
87 Alternative fuel and advanced technology vehicles are those that can operate using a motor fuel other than gasoline or diesel.
This includes electric or other bi-fuel or dual-fuel vehicles that may be partially powered by gasoline or diesel.
88 Additional information regarding the model can be found online at http://www.epa.gov/OMS/m6.htm.
89 FHWA VMT data for 2009 fuel consumption was not available for the Inventory public review file, and so proxy data was
used. The final version of the inventory will include data from the most recent VM-1 file, which is expected to be released soon.
As such, VMT and emissions estimates are expected to change when these data become available.
Energy 3-25
-------
1 using the calculated shares of vehicle fuel use for each vehicle category by fuel type reported in DOE (1993 through
2 2010) and information on total motor vehicle fuel consumption by fuel type from FHWA (1996 through 2010).
3 VMT for AFVs were taken from Browning (2003). The age distributions of the U.S. vehicle fleet were obtained
4 from EPA (2010a, 2000), and the average annual age-specific vehicle mileage accumulation of U.S. vehicles were
5 obtained from EPA (2000).
6 Control technology and standards data for on-road vehicles were obtained from EPA's Office of Transportation and
7 Air Quality (EPA 2007a, 2007b, 2000, 1998, and 1997) and Browning (2005). These technologies and standards are
8 defined in Annex 3.2, and were compiled from EPA (1993, 1994a, 1994b, 1998, 1999a) and
9 IPCC/UNEP/OECD/IEA (1997).
10 Non-Road Vehicles
11 To estimate emissions from non-road vehicles, fuel consumption data were employed as a measure of activity, and
12 multiplied by fuel-specific emission factors (in grams of N2O and CH4 per kilogram of fuel consumed).90 Activity
13 data were obtained from AAR (2009 through 2010), APTA (2007 through 2010), APTA (2006), BEA (1991 through
14 2005), Benson (2002 through 2004), DHS (2008), DOC (1991 through 2008), DOE (1993 through 2010), DESC
15 (2011), DOT (1991 through 2010), EIA (2008a, 2007a, 2007b, 2002), EIA (2007 through 2010), EIA (1991 through
16 20010), EPA (2009), Esser (2003 through 2004), FAA (2011, 2010, and 2006), Gaffney (2007), and (2006 through
17 2010). Emission factors for non-road modes were taken from IPCC/UNEP/OECD/IEA (1997) and Browning
18 (2009).
19 Uncertainty and Time-Series Consistency
20 A quantitative uncertainty analysis was conducted for the mobile source sector using the IPCC-recommended Tier 2
21 uncertainty estimation methodology, Monte Carlo simulation technique, using @RISK software. The uncertainty
22 analysis was performed on 2009 estimates of CH4 and N2O emissions, incorporating probability distribution
23 functions associated with the major input variables. For the purposes of this analysis, the uncertainty was modeled
24 for the following four major sets of input variables: (1) vehicle miles traveled (VMT) data, by on-road vehicle and
25 fuel type and (2) emission factor data, by on-road vehicle, fuel, and control technology type, (3) fuel consumption,
26 data, by non-road vehicle and equipment type, and (4) emission factor data, by non-road vehicle and equipment
27 type.
28 Uncertainty analyses were not conducted for NOX, CO, or NMVOC emissions. Emission factors for these gases
29 have been extensively researched since emissions of these gases from motor vehicles are regulated in the United
30 States, and the uncertainty in these emission estimates is believed to be relatively low. However, a much higher
31 level of uncertainty is associated with CH4 and N2O emission factors, because emissions of these gases are not
32 regulated in the United States (and, therefore, there are not adequate emission test data), and because, unlike CO2
33 emissions, the emission pathways of CH4 and N2O are highly complex.
34 The results of the Tier 2 quantitative uncertainty analysis for the mobile source CH4 and N2O emissions from on-
35 road vehicles are summarized in Mobile combustion CH4 emissions from on-road vehicles in 2009 were estimated
36 to be between 2.0 and 2.5 Tg CO2 Eq. at a 95 percent confidence level. This indicates a range of 9 percent below to
37 15 percent above the corresponding 2009 emission estimate of 2.2 Tg CO2 Eq. Also at a 95 percent confidence
38 level, mobile combustion N2O emissions from on-road vehicles in 2009 were estimated to be between 23.8 and 32.4
39 Tg CO2 Eq., indicating a range of 14 percent below to 16 percent above the corresponding 2009 emission estimate
40 of27.8TgCO2Eq.
41 Table 3-18. As noted above, an uncertainty analysis was not performed for CH4 and N2O emissions from non-road
42 vehicles. Mobile combustion CH4 emissions from on-road vehicles in 2009 were estimated to be between 2.0 and
43 2.5 Tg CO2 Eq. at a 95 percent confidence level. This indicates a range of 9 percent below to 15 percent above the
44 corresponding 2009 emission estimate of 2.2 Tg CO2 Eq. Also at a 95 percent confidence level, mobile combustion
45 N2O emissions from on-road vehicles in 2009 were estimated to be between 23.8 and 32.4 Tg CO2 Eq., indicating a
46 range of 14 percent below to 16 percent above the corresponding 2009 emission estimate of 27.8 Tg CO2 Eq.
90 The consumption of international bunker fuels is not included in these activity data, but is estimated separately under the
International Bunker Fuels source category.
3-26 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Table 3-18. Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Mobile Sources (Tg CO2
2 Eq. and Percent)
Source
Gas
2009 Emission
Estimate"
(TgC02Eq.)
Uncertainty Range Relative to Emission Estimate3'1"
(Tg C02 Eq.) (%)
Lower Bound Upper Bound Lower Bound Upper Bound
On-Road Sources
On-Road Sources
CH4
N2O
2.2
27.8
2.0 2.5 -9% +15%
23.8 32.4 -14% +16%
3 a 2009 emission estimates and the uncertainty ranges presented in this table correspond to on-road vehicles, comprising
4 conventional and alternative fuel vehicles. Because the uncertainty associated with the emissions from non-road vehicles were
5 not estimated, they were excluded in the estimates reported in this table.
6 b Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
7
8 This uncertainty analysis is a continuation of a multi-year process for developing quantitative uncertainty estimates
9 for this source category using the IPCC Tier 2 approach to uncertainty analysis. As a result, as new information
10 becomes available, uncertainty characterization of input variables may be improved and revised. For additional
11 information regarding uncertainty in emission estimates for CH4 and N2O please refer to the Uncertainty Annex.
12 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
13 through 2008. Details on the emission trends through time are described in more detail in the Methodology section,
14 above.
15 QA/QC and Verification
16 A source-specific QA/QC plan for mobile combustion was developed and implemented. This plan is based on the
17 IPCC-recommended QA/QC Plan. The specific plan used for mobile combustion was updated prior to collection and
18 analysis of this current year of data. This effort included a Tier 1 analysis, as well as portions of a Tier 2 analysis.
19 The Tier 2 procedures focused on the emission factor and activity data sources, as well as the methodology used for
20 estimating emissions. These procedures included a qualitative assessment of the emissions estimates to determine
21 whether they appear consistent with the most recent activity data and emission factors available. A comparison of
22 historical emissions between the current Inventory and the previous Inventory was also conducted to ensure that the
23 changes in estimates were consistent with the changes in activity data and emission factors.
24 Recalculations Discussion
25 In order to ensure that these estimates are continuously improved, the calculation methodology is revised annually
26 based on comments from internal and external reviewers. Each year, a number of adjustments are made to the
27 methodologies used in calculating emissions in the current Inventory relative to previous Inventory reports. One of
28 the revisions that were made this year was incorporating motor vehicle age distribution from EPA's MOtor Vehicle
29 Emission Simulator (MOVES) model. MOVES is EPA's tool for estimating emissions from highway vehicles,
30 based on analysis of millions of emission test results and considerable advances in US EPA's understanding of
31 vehicle emissions. Population data from the MOVES model was used to estimate the age distribution of motor
32 vehicles in the United States.
33 Planned Improvements
34 While the data used for this report represent the most accurate information available, four areas have been identified
35 that could potentially be improved in the short-term given available resources.
36 1. Develop updated emissions factors for diesel vehicles, motorcycle, and biodiesel vehicles. Previous
37 emission factors were based upon extrapolations from other vehicle classes and new test data from
38 Environment Canada and other sources may allow for better estimation of emission factors for these
39 vehicles.
40 2. Develop new emission factors for non-road equipment. The current inventory estimates for non-CO2
41 emissions from non-road sources are based on emission factors from IPCC guidelines published in 1996.
42 Recent data on non-road sources from Environment Canada and the California Air Resources Board will be
43 investigated in order to assess the feasibility of developing new N2O and CH4 emissions factors for non-
Energy 3-27
-------
1 road equipment.
2 3. Examine the feasibility of estimating aircraft N2O and CH4 emissions by the number of takeoffs and
3 landings, instead of total fuel consumption. Various studies have indicated that aircraft N2O and CH4
4 emissions are more dependent on aircraft takeoffs and landings than on total aircraft fuel consumption;
5 however, aircraft emissions are currently estimated from fuel consumption data. FAA's SAGE and AEDT
6 databases contain detailed data on takeoffs and landings for each calendar year starting in 2000, and could
7 potentially be used to conduct a Tier II analysis of aircraft emissions. This methodology will require a
8 detailed analysis of the number of takeoffs and landings by aircraft type on domestic trips, the development
9 of procedures to develop comparable estimates for years prior to 2000, and the dynamic interaction of
10 ambient air with aircraft exhausts is developed. The feasibility of this approach will be explored.
11 4. Develop improved estimates of domestic waterborne fuel consumption. The inventory estimates for
12 residual and distillate fuel used by ships and boats is based in part on data on bunker fuel use from the U. S.
13 Department of Commerce. Domestic fuel consumption is estimated by subtracting fuel sold for
14 international use from the total sold in the United States. It may be possible to more accurately estimate
15 domestic fuel use and emissions by using detailed data on marine ship activity. The feasibility of using
16 domestic marine activity data to improve the estimates will be investigated. Continue to examine the use
17 of EPA's MOVES model in the development of the inventory estimates, including use for uncertainty
18 analysis. Although the inventory uses some of the underlying data from MOVES, such as vehicle age
19 distributions by model year, MOVES is not used directly in calculating mobile source emissions. As
20 MOVES goes through additional testing and refinement, the use of MOVES will be further explored.
21
22 3.2. Carbon Emitted from Non-Energy Uses of Fossil Fuels (IPCC Source
23 Category 1A)
24 In addition to being combusted for energy, fossil fuels are also consumed for non-energy uses (NEU) in the United
25 States. The fuels used for these purposes are diverse, including natural gas, liquefied petroleum gases (LPG),
26 asphalt (a viscous liquid mixture of heavy crude oil distillates), petroleum coke (manufactured from heavy oil), and
27 coal (metallurgical) coke (manufactured from coking coal). The non-energy applications of these fuels are equally
28 diverse, including feedstocks for the manufacture of plastics, rubber, synthetic fibers and other materials; reducing
29 agents for the production of various metals and inorganic products; and non-energy products such as lubricants,
30 waxes, and asphalt (IPCC 2006).
31 CO2 emissions arise from non-energy uses via several pathways. Emissions may occur during the manufacture of a
32 product, as is the case in producing plastics or rubber from fuel-derived feedstocks. Additionally, emissions may
33 occur during the product's lifetime, such as during solvent use. Overall, throughout the time series and across all
34 uses, about 62 percent of the total C consumed for non-energy purposes was stored in products, and not released to
35 the atmosphere; the remaining 38 percent was emitted.
36 There are several areas in which non-energy uses of fossil fuels are closely related to other parts of the inventory.
37 For example, some of the NEU products release CO2 at the end of their commercial life when they are combusted
38 after disposal; these emissions are reported separately within the Energy chapter in the Incineration of Waste source
39 category. In addition, there is some overlap between fossil fuels consumed for non-energy uses and the fossil-
40 derived CO2 emissions accounted for in the Industrial Processes chapter, especially for fuels used as reducing
41 agents. To avoid double-counting, the "raw" non-energy fuel consumption data reported by EIA are modified to
42 account for these overlaps. There are also net exports of petrochemicals that are not completely accounted for in the
43 EIA data, and the inventory calculations make adjustments to address the effect of net exports on the mass of C in
44 non-energy applications.
45 As shown in Table 3-19, fossil fuel emissions in 2009 from the non-energy uses of fossil fuels were 122.1 Tg CO2
46 Eq., which constituted approximately 2 percent of overall fossil fuel emissions. In 2009, the consumption of fuels
47 for non-energy uses (after the adjustments described above) was 4,420.5 TBtu, an increase of 0.1 percent since 1990
48 (see Table 3-20). About 49.4 Tg of the C (181.0 Tg CO2 Eq.) in these fuels was stored, while the remaining 33.3 Tg
49 C (122.1 Tg CO2 Eq.) was emitted.
50 Table 3-19: CO2 Emissions from Non-Energy Use Fossil Fuel Consumption (Tg CO2 Eq.)
3-28 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Year
Potential Emissions
C Stored
Emissions as a % of Potential
Emissions
1990
308.0
191.7
38%
116.2
2000
380.7
238.2
37%
142.5
2005
379.2
238.0
37%
141.3
2006
377.8
235.4
38%
142.4
2007
366.2
232.1
37%
134.1
2008
342.1
203.5
41%
138.7
2009
303.0
181.0
40%
122.1
2 Methodology
3 The first step in estimating C stored in products was to determine the aggregate quantity of fossil fuels consumed for
4 non-energy uses. The C content of these feedstock fuels is equivalent to potential emissions, or the product of
5 consumption and the fuel-specific C content values. Both the non-energy fuel consumption and C content data were
6 supplied by the EIA (2010c) (see Annex 2.1). Consumption of natural gas, LPG, pentanes plus, naphthas, other oils,
7 and special naphtha were adjusted to account for net exports of these products that are not reflected in the raw data
8 from EIA. Consumption values for industrial coking coal, petroleum coke, other oils, and natural gas in Table 3-20
9 and Table 3-21 have been adjusted to subtract non-energy uses that are included in the source categories of the
10 Industrial Processes chapter.91 Consumption values were also adjusted to subtract net exports of intermediary
11 chemicals.
12 For the remaining non-energy uses, the quantity of C stored was estimated by multiplying the potential emissions by
13 a storage factor.
14 • For several fuel types—petrochemical feedstocks (including natural gas for non-fertilizer uses, LPG,
15 pentanes plus, naphthas, other oils, still gas, special naphtha, and industrial other coal), asphalt and road oil,
16 lubricants, and waxes—U.S. data on C stocks and flows were used to develop C storage factors, calculated
17 as the ratio of (a) the C stored by the fuel's non-energy products to (b) the total C content of the fuel
18 consumed. A lifecycle approach was used in the development of these factors in order to account for losses
19 in the production process and during use. Because losses associated with municipal solid waste
20 management are handled separately in this sector under the Incineration of Waste source category, the
21 storage factors do not account for losses at the disposal end of the life cycle.
22 • For industrial coking coal and distillate fuel oil, storage factors were taken from IPCC/UNEP/OECD/IEA
23 (1997), which in turn draws from Marland and Rotty (1984).
24 • For the remaining fuel types (petroleum coke, miscellaneous products, and other petroleum), IPCC does not
25 provide guidance on storage factors, and assumptions were made based on the potential fate of C in the
26 respective NEU products.
27 Table 3-20: Adjusted Consumption of Fossil Fuels for Non-Energy Uses (TBtu)
Year
Industry
Industrial Coking Coal
Industrial Other Coal
Natural Gas to Chemical Plants
Asphalt & Road Oil
LPG
Lubricants
Pentanes Plus
Naphtha (<401°F)
Other Oil (>401°F)
Still Gas
Petroleum Coke
Special Naphtha
1990
4,153.4
+
8.2
277.3
1,170.2
1,119.2
186.3
77.5
325.9
661.4
21.3
27.2
100.8
2000
5,186.6
53.0
12.4
420.3
1,275.7
1,607.0
189.9
229.3
593.7
527.0
12.6
7.5
94.4
2005
5,150.8
79.8
11.9
397.0
1,323.2
1,444.0
160.2
146.3
679.6
514.8
67.7
105.2
60.9
2006
5,125.3
62.3
12.4
407.7
1,261.2
1,488.6
156.1
105.5
618.1
573.4
57.2
134.2
68.9
2007
5,022.6
1.7
12.4
412.5
1,197.0
1,483.0
161.2
132.7
542.6
669.2
44.2
117.8
75.5
2008
4,644.9
28.4
12.4
395.2
1,012.0
1,409.6
149.6
114.9
467.3
599.2
47.3
147.4
83.2
2009
4,237.1
6.1
12.4
366.0
873.1
1,446.2
134.5
93.4
450.7
392.5
133.9
102.5
44.2
91 These source categories include Iron and Steel Production, Lead Production, Zinc Production, Ammonia Manufacture, Carbon
Black Manufacture (included in Petrochemical Production), Titanium Dioxide Production, Ferroalloy Production, Silicon
Carbide Production, and Aluminum Production.
Energy 3-29
-------
Distillate Fuel Oil
Waxes
Miscellaneous Products
Transportation
Lubricants
U.S. Territories
Lubricants
Other Petroleum (Misc. Prod.)
Total
7.0
33.3
137.8
176.0
176.0
86.7
0.7
86.0
4,416.1
11.7
33.1
119.2
179.4
179.4
152.2
3.1
149.1
5,518.1
16.0
31.4
112.8
151.3
151.3
121.9
4.6
117.3
5,424.0
17.5
26.1
136.0
147.4
147.4
133.4
6.2
127.2
5,406.0
17.5
21.9
133.5
152.2
152.2
108.4
5.9
102.5
5,283.3
17.5
19.1
142.0
141.3
141.3
126.7
2.7
124.1
4,913.0
17.5
12.2
151.8
127.1
127.1
56.3
1.0
55.2
4,420.5
1 + Does not exceed 0.05 TBtu
2 Note: To avoid double-counting, coal coke, petroleum coke, natural gas consumption, and other oils are adjusted for industrial
3 process consumption reported in the Industrial Processes sector. Natural gas, LPG, Pentanes Plus, Naphthas, Special Naphtha,
4 and Other Oils are adjusted to account for exports of chemical intermediates derived from these fuels. For residual oil (not
5 shown in the table), all non-energy use is assumed to be consumed in C black production, which is also reported in the Industrial
6 Processes chapter.
7 Note: Totals may not sum due to independent rounding.
Table 3-21: 2009 Adjusted Non-Energy Use Fossil Fuel Consumption, Storage, and Emissions
Adjusted Carbon
Non-Energy Content Potential Carbon Carbon Carbon
Use" Coefficient Carbon Storage Stored Emissions Emissions
Sector/Fuel Type (TBtu) (TgC/QBtu) (TgC) Factor (TgC) (TgC) (TgCO2Eq.)
Industry
Industrial Coking Coal
Industrial Other Coal
Natural Gas to Chemical
Plants
Asphalt & Road Oil
LPG
Lubricants
Pentanes Plus
Naphtha (<401°F)
Other Oil (>401°F)
Still Gas
Petroleum Coke
Special Naphtha
Distillate Fuel Oil
Waxes
Miscellaneous Products
Transportation
Lubricants
U.S. Territories
Lubricants
Other Petroleum (Misc.
Prod.)
Total
4,237.1
6.1
12.4
366.0
873.1
1,446.2
134.5
93.4
450.7
392.5
133.9
102.5
44.2
17.5
12.2
151.8
127.1
127.1
56.3
1.0
55.2
4,420.5
-
31.00
25.82
14.47
20.55
17.06
20.20
19.10
18.55
20.17
17.51
27.85
19.74
20.17
19.80
20.31
-
20.20
-
20.20
20.00
-
79.0
0.2
0.3
5.3
17.9
24.7
2.7
1.8
8.4
7.9
2.3
2.9
0.9
0.4
0.2
3.1
2.6
2.6
1.1
+
1.1
82.6
-
0.10
0.57
0.57
1.00
0.57
0.09
0.57
0.57
0.57
0.57
0.30
0.57
0.50
0.58
0.00
-
0.09
-
0.09
0.10
-
49.0
0.0
0.2
3.0
17.9
14.2
0.3
1.0
4.8
4.5
1.3
0.9
0.5
0.2
0.1
0.0
0.2
0.2
0.1
+
0.1
49.4
29.9
0.2
0.1
2.3
0.0
10.5
2.5
0.8
3.6
3.4
1.0
2.0
0.4
0.2
0.1
3.1
2.3
2.3
1.0
+
1.0
33.3
109.8
0.6
0.5
8.3
0.0
38.5
9.0
2.8
13.0
12.4
3.7
7.3
1.4
0.6
0.4
11.3
8.5
8.5
3.7
0.1
3.6
122.1
10 + Does not exceed 0.05 Tg
11 - Not applicable.
12 a To avoid double counting, net exports have been deducted.
13 Note: Totals may not sum due to independent rounding.
14
15 Lastly, emissions were estimated by subtracting the C stored from the potential emissions (see Table 3-19). More
16 detail on the methodology for calculating storage and emissions from each of these sources is provided in Annex
17 2.3.
18 Where storage factors were calculated specifically for the United States, data were obtained on (1) products such as
3-30 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 asphalt, plastics, synthetic rubber, synthetic fibers, cleansers (soaps and detergents), pesticides, food additives,
2 antifreeze and deicers (glycols), and silicones; and (2) industrial releases including energy recovery, Toxics Release
3 Inventory (TRI) releases, hazardous waste incineration, and volatile organic compound, solvent, and non-
4 combustion CO emissions. Data were taken from a variety of industry sources, government reports, and expert
5 communications. Sources include EPA reports and databases such as compilations of air emission factors (EPA
6 2001), National Emissions Inventory (NEI) Air Pollutant Emissions Trends Data (EPA 2008), Toxics Release
7 Inventory, 1998 (2000b), Biennial Reporting System (EPA 2004, 2007a), and pesticide sales and use estimates
8 (EPA 1998, 1999, 2002, 2004); the EIA Manufacturer's Energy Consumption Survey (MECS) (EIA 1994, 1997,
9 2001, 2005, 2010b); the National Petrochemical & Refiners Association (NPRA 2002); the U.S. Bureau of the
10 Census (1999, 2004, 2009); Bank of Canada (2009); Financial Planning Association (2006); INEGI (2006); the
11 United States International Trade Commission (2011); Gosselin, Smith, and Hodge (1984); the Rubber
12 Manufacturers' Association (RMA 2009a,b); the International Institute of Synthetic Rubber Products (IISRP 2000,
13 2003); the Fiber Economics Bureau (FEE 2010); and the American Chemistry Council (ACC 2003-2010). Specific
14 data sources are listed in full detail in Annex 2.3.
15 Uncertainty and Time-Series Consistency
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
An uncertainty analysis was conducted to quantify the uncertainty surrounding the estimates of emissions and
storage factors from non-energy uses. This analysis, performed using @RISK software and the IPCC-recommended
Tier 2 methodology (Monte Carlo Simulation technique), provides for the specification of probability density
functions for key variables within a computational structure that mirrors the calculation of the inventory estimate.
The results presented below provide the 95 percent confidence interval, the range of values within which emissions
are likely to fall, for this source category.
As noted above, the non-energy use analysis is based on U.S.-specific storage factors for (1) feedstock materials
(natural gas, LPG, pentanes plus, naphthas, other oils, still gas, special naphthas, and other industrial coal), (2)
asphalt, (3) lubricants, and (4) waxes. For the remaining fuel types (the "other" category in Table 3-22 and Table
3-23), the storage factors were taken directly from the IPCC Guidelines for National Greenhouse Gas Inventories,
where available, and otherwise assumptions were made based on the potential fate of carbon in the respective NEU
products. To characterize uncertainty, five separate analyses were conducted, corresponding to each of the five
categories. In all cases, statistical analyses or expert judgments of uncertainty were not available directly from the
information sources for all the activity 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 3-22 (emissions) and Table 3-23
(storage factors). Carbon emitted from non-energy uses of fossil fuels in 2009 was estimated to be between 100.8
and 145.4 Tg CO2 Eq. at a 95 percent confidence level. This indicates a range of 17 percent below to 19 percent
above the 2009 emission estimate of 122.1 Tg CO2 Eq. The uncertainty in the emission estimates is a function of
uncertainty in both the quantity of fuel used for non-energy purposes and the storage factor.
Table 3-22: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Non-Energy Uses of Fossil Fuels
(Tg CO2 Eq. and Percent)
Source
2009
Emission
Estimate
Gas (Tg CO2 Eq.)
Uncertainty Range Relative to Emission Estimate"
(Tg CO2 Eq.) (%)
Lower Bound Upper Bound Lower Bound Upper Bound
Feedstocks
Asphalt
Lubricants
Waxes
Other
Total
CO2
CO2
C02
C02
C02
C02
80.5
0.0
17.6
0.4
23.5
122.1
67.6
0.0
14.6
0.3
9.4
100.8
108.6
0.6
20.4
0.7
24.3
145.4
-16%
NA
-17%
-29%
-60%
-17%
35%
NA
16%
75%
3%
19%
38
39
40
a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
NA (Not Applicable)
Energy 3-31
-------
1 Table 3-23: Tier 2 Quantitative Uncertainty Estimates for Storage Factors of Non-Energy Uses of Fossil Fuels
2 (Percent)
Source
Feedstocks
Asphalt
Lubricants
Waxes
Other
2009 Storage
Gas Factor Uncertainty Range Relative to Emission Estimate"
(%) (%) (%, Relative)
CO2
CO2
CO2
CO2
CO2
57%
100%
9%
58%
15%
Lower
Bound
51%
99%
4%
49%
16%
Upper
Bound
57%
100%
18%
71%
65%
Lower
Bound
-11%
-1%
-57%
-15%
5%
Upper
Bound
0%
0%
92%
22%
326%
3 a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval, as a
4 percentage of the inventory value (also expressed in percent terms).
5
6 In Table 3-23, feedstocks and asphalt contribute least to overall storage factor uncertainty on a percentage basis.
7 Although the feedstocks category—the largest use category in terms of total carbon flows—appears to have tight
8 confidence limits, this is to some extent an artifact of the way the uncertainty analysis was structured. As discussed
9 in Annex 2.3, the storage factor for feedstocks is based on an analysis of six fates that result in long-term storage
10 (e.g., plastics production), and eleven that result in emissions (e.g., volatile organic compound emissions). Rather
11 than modeling the total uncertainty around all of these fate processes, the current analysis addresses only the storage
12 fates, and assumes that all C that is not stored is emitted. As the production statistics that drive the storage values
13 are relatively well-characterized, this approach yields a result that is probably biased toward understating
14 uncertainty.
15 As is the case with the other uncertainty analyses discussed throughout this document, the uncertainty results above
16 address only those factors that can be readily quantified. More details on the uncertainty analysis are provided in
17 Annex 2.3.
18 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
19 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
20 above.
21 QA/QC and Verification
22 A source-specific QA/QC plan for non-energy uses of fossil fuels was developed and implemented. This effort
23 included a Tier 1 analysis, as well as portions of a Tier 2 analysis for non-energy uses involving petrochemical
24 feedstocks and for imports and exports. The Tier 2 procedures that were implemented involved checks specifically
25 focusing on the activity data and methodology for estimating the fate of C (in terms of storage and emissions) across
26 the various end-uses of fossil C. Emission and storage totals for the different subcategories were compared, and
27 trends across the time series were analyzed to determine whether any corrective actions were needed. Corrective
28 actions were taken to rectify minor errors and to improve the transparency of the calculations, facilitating future
29 QA/QC.
30 For petrochemical import and export data, special attention was paid to NAICS numbers and titles to verify that
31 none had changed or been removed. Import and export totals were compared for 2009 as well as their trends across
32 the time series.
33 Recalculations Discussion
34 Updates to the EIA Manufacturer's Energy Consumption Survey (MECS) for 2006 were released in the past year.
35 MECS data are only released once every four years and contribute to approximately 28 percent (as a time-weighted
36 average) of the C accounted for in feedstocks. MECS data are used to estimate the amount of C emitted from
37 energy recovery. Updating the energy recovery emission estimates with this new data affected emissions from 2003
38 through 2009, resulting in annual average increases of 7 percent from 2003 through 2009. In addition, EPA
39 recalculated the entire energy recovery time series to adjust for energy recovered from combustion of scrap tires.
40 Carbon emissions from scrap tires were inadvertently included in the energy recovery estimates; however, they are
3-32 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 already accounted for in the Incineration of Waste category.92 MECS data were adjusted to remove carbon from
2 scrap tires used as fuel in cement kilns, lime kilns, and electric arc furnaces. This adjustment resulted in decreases in
3 emissions across the entire time series. Emissions decreased by 0.3, 2.1, 1.3, and 1.5 percent for MECS-reporting
4 years 1991, 1994, 1998, and 2002, respectively. Updating the energy recovery emissions estimates with the 2006
5 MECS data combined with adjusting for combustion of scrap tires increased the 2006 emission estimate by 9.5
6 percent. Overall, emissions from energy recovery averaged over the entire time series increased by 1.2 percent when
7 compared to last year's inventory estimate because the increase resulting from updating the MECS data more than
8 offsets the decrease from adjusting for scrap tire combustion across the time series.
9 Planned Improvements
10 There are several improvements planned for the future:
11 • Improving the uncertainty analysis. Most of the input parameter distributions are based on professional
12 judgment rather than rigorous statistical characterizations of uncertainty.
13 • Better characterizing flows of fossil C. Additional fates may be researched, including the fossil C load in
14 organic chemical wastewaters, plasticizers, adhesives, films, paints, and coatings. There is also a need to
15 further clarify the treatment of fuel additives and backflows (especially methyl tert-butyl ether, MTBE).
16 • Reviewing the trends in fossil fuel consumption for non-energy uses. Annual consumption for several fuel types
17 is highly variable across the time series, including industrial coking coal and other petroleum (miscellaneous
18 products). EPA plans to better understand these trends to identify any mischaracterized or misreported fuel
19 consumption for non-energy uses.
20 • More accurate accounting of carbon in petrochemical feedstocks. Since 2001, the C accounted for in the
21 feedstocks carbon balance outputs (i.e., storage plus emissions) exceeds carbon inputs. Priorto 2001, the
22 carbon balance inputs exceed outputs. EPA plans to research this discrepancy by assessing the trends on both
23 sides of the carbon balance. An initial review of EIA (20 lOb) data indicates that trends in LPG consumption for
24 non-energy uses may largely contribute to this discrepancy.
25 • EPA recently researched updating the average carbon content of solvents, since the entire time series depends
26 on one year's worth of solvent composition data. Unfortunately, the data on carbon emissions from solvents that
27 were readily available do not provide composition data for all categories of solvent emissions and also have
28 conflicting definitions for volatile organic compounds, the source of emissive carbon in solvents. EPA plans to
29 identify additional sources of solvents data in order to update the carbon content assumptions.
30 Finally, although U.S.-specific storage factors have been developed for feedstocks, asphalt, lubricants, and waxes,
31 default values from IPCC are still used for two of the non-energy fuel types (industrial coking coal and distillate oil),
32 and broad assumptions are being used for miscellaneous products and other petroleum. Over the long term, there
33 are plans to improve these storage factors by conducting analyses of C fate similar to those described in Annex 2.3
34 or deferring to more updated default storage factors from IPCC where available.
35 3.3. Incineration of Waste (IPCC Source Category 1A1a)
36 Incineration is used to manage about 7 to 19 percent of the solid wastes generated in the United States, depending on
37 the source of the estimate and the scope of materials included in the definition of solid waste (EPA 2000, Goldstein
38 andMatdes 2001, Kaufman etal. 2004, Simmons etal. 2006, van Haaren et al. 2010). In the context of this section,
39 waste includes all municipal solid waste (MSW) as well as tires. In the United States, almost all incineration of
40 MSW occurs at waste-to-energy facilities or industrial facilities where useful energy is recovered, and thus
41 emissions from waste incineration are accounted for in the Energy chapter. Similarly, tires are combusted for energy
42 recovery in industrial and utility boilers. Incineration of waste results in conversion of the organic inputs to CO2.
43 According to IPCC guidelines, when the CO2 emitted is of fossil origin, it is counted as a net anthropogenic
44 emission of CO2 to the atmosphere. Thus, the emissions from waste incineration are calculated by estimating the
92 From a regulatory-definition perspective combustion of scrap tires in cement kilns, lime kilns, and electric arc furnaces is not considered
"incineration;" however the use of the term "incineration" in this document also applies to the combustion of scrap tires and other materials for
energy recovery.
Energy 3-33
-------
1 quantity of waste combusted and the fraction of the waste that is C derived from fossil sources.
2 Most of the organic materials in municipal solid wastes are of biogenic origin (e.g., paper, yard trimmings), and
3 have their net C flows accounted for under the Land Use, Land-Use Change, and Forestry chapter. However, some
4 components—plastics, synthetic rubber, synthetic fibers, and carbon black—are of fossil origin. Plastics in the U.S.
5 waste stream are primarily in the form of containers, packaging, and durable goods. Rubber is found in durable
6 goods, such as carpets, and in non-durable goods, such as clothing and footwear. Fibers in municipal solid wastes
7 are predominantly from clothing and home furnishings. As noted above, tires (which contain rubber and carbon
8 black) are also considered a "non-hazardous" waste and are included in the waste incineration estimate, though
9 waste disposal practices for tires differ from municipal solid waste. Estimates on emissions from hazardous waste
10 incineration can be found in Annex 2.3 and are accounted for as part of the carbon mass balance for non-energy uses
11 of fossil fuels.
12 Approximately 26 million metric tons of MSW was incinerated in the United States in 2009 (EPA 2011). CO2
13 emissions from incineration of waste rose 54 percent since 1990, to an estimated 12.3 Tg CO2 Eq. (12,300 Gg) in
14 2009, as the volume of tires and other fossil C-containing materials in waste increased (see Table 3-24 and Table
15 3-25). Waste incineration is also a source of N2O and CH4 emissions (De Soete 1993; IPCC 2006). N2O emissions
16 from the incineration of waste were estimated to be 0.4 Tg CO2 Eq. (1 Gg N2O) in 2009, and have not changed
17 significantly since 1990. CH4 emissions from the incineration of waste were estimated to be less than 0.05 Tg CO2
18 Eq. (less than 0.5 Gg CH4) in 2009, and have not changed significantly since 1990.
19 Table 3-24: CO2 and N2O Emissions from the Incineration of Waste (Tg CO2 Eq.)
20
21
Gas/Waste Product
C02
Plastics
Synthetic Rubber in Tires
Carbon Black in Tires
Synthetic Rubber in MSW
Synthetic Fibers
N2O
CH4
Total
+ Does not exceed 0.05 Tg CO2
1990
8.0
5.6
0.3
0.4
0.9
0.8
0.5
+
8.5
Eq.
Table 3-25: CO2 and N2O Emissions
Gas/Waste Product
C02
Plastics
Synthetic Rubber in Tires
Carbon Black in Tires
Synthetic Rubber in MSW
Synthetic Fibers
N2O
CH4
1990
7,989
5,588
308
385
872
838
2
+
2000
11.1
6.1
1.5
1.8
0.7
1.0
0.4
+
11.5
2005
12.5
6.9
1.6
2.0
0.8
1.2
0.4
+
12.9
from the Incineration of Waste
2000
11,112
6,104
1,454
1,818
689
1,046
1
+
2005
12,450
6,919
1,599
1,958
781
1,194
1
+
2006
12.5
6.7
1.7
2.1
0.8
1.2
0.4
+
12.9
(Gg)
2006
12,531
6,722
1,712
2,113
775
1,208
1
+
2007
12.7
6.7
1.8
2.3
0.8
1.2
0.4
+
13.1
2007
12,700
6,660
1,823
2,268
791
1,159
1
+
2008
12.2
6.1
1.8
2.3
0.8
1.2
0.4
+
12.5
2008
12,169
6,148
1,823
2,268
770
1,161
1
+
2009
12.3
6.2
1.8
2.3
0.8
1.2
0.4
+
12.7
2009
12,300
6,233
1,823
2,268
782
1,195
1
+
+ Does not exceed 0.5 Gg.
22
23 Methodology
24 Emissions of CO2 from the incineration of waste include CO2 generated by the incineration of plastics, synthetic
25 fibers, and synthetic rubber, as well as the incineration of synthetic rubber and carbon black in tires. These emissions
26 were estimated by multiplying the amount of each material incinerated by the C content of the material and the
27 fraction oxidized (98 percent). Plastics incinerated in municipal solid wastes were categorized into seven plastic
28 resin types, each material having a discrete C content. Similarly, synthetic rubber is categorized into three product
29 types, and synthetic fibers were categorized into four product types, each having a discrete C content. Scrap tires
30 contain several types of synthetic rubber, as well as carbon black. Each type of synthetic rubber has a discrete C
31 content, and carbon black is 100 percent C. Emissions of CO2 were calculated based on the amount of scrap tires
32 used for fuel and the synthetic rubber and carbon black content of tires.
3-34 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 More detail on the methodology for calculating emissions from each of these waste incineration sources is provided
2 in Annex 3.6.
3 For each of the methods used to calculate CO2 emissions from the incineration of waste, data on the quantity of
4 product combusted and the C content of the product are needed. For plastics, synthetic rubber, and synthetic fibers,
5 the amount of specific materials discarded as municipal solid waste (i.e., the quantity generated minus the quantity
6 recycled) was taken from Municipal Solid Waste Generation, Recycling, and Disposal in the United States: Facts and
1 Figures (EPA 1999 through 2003, 2005 through 2011) and detailed unpublished backup data for some years not shown
8 in the reports (Schneider 2007). The proportion of total waste discarded that is incinerated was derived from data in
9 BioCycle's "State of Garbage in America" (van Haaren et al. 2010). The most recent data provides the proportion of
10 waste incinerated for 2008, so the corresponding proportion in 2009 is assumed to be equal to the proportion in
11 2008. For synthetic rubber and carbon black in scrap tires, information was obtained from U.S. Scrap Tire Markets
12 in the United States, 2007 Edition (RMA 2009a). For 2008 and 2009, synthetic rubber mass in tires is assumed to be
13 equal to that in 2007 due to a lack of more recently available data.
14 Average C contents for the "Other" plastics category and synthetic rubber in municipal solid wastes were calculated
15 from 1998 and 2002 production statistics: carbon content for 1990 through 1998 is based on the 1998 value; content
16 for 1999 through 2001 is the average of 1998 and 2002 values; and content for 2002 to date is based on the 2002
17 value. Carbon content for synthetic fibers was calculated from 1999 production statistics. Information about scrap
18 tire composition was taken from the Rubber Manufacturers' Association internet site (RMA 2009b).
19 The assumption that 98 percent of organic C is oxidized (which applies to all waste incineration categories for CO2
20 emissions) was reported in EPA's life cycle analysis of greenhouse gas emissions and sinks from management of
21 solid waste (EPA 2006).
22 Incineration of waste, including MSW, also results in emissions of N2O and CH4. These emissions were calculated
23 as a function of the total estimated mass of waste incinerated and an emission factor. As noted above, N2O and CH4
24 emissions are a function of total waste incinerated in each year; for 1990 through 2008, these data were derived from
25 the information published in BioCycle (van Haaren et al. 2010). Data on total waste incinerated was not available
26 for 2009, so this value was assumed to equal the most recent value available (2008). Table 3-26 provides data on
27 municipal solid waste discarded and percentage combusted for the total waste stream. According to Covanta Energy
28 (Bahor 2009) and confirmed by additional research based on ISWA (ERC 2009), all municipal solid waste
29 combustors in the United States are continuously fed stoker units. The emission factors of N2O and CH4 emissions
30 per quantity of municipal solid waste combusted are default emission factors for this technology type and were taken
31 from the 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006).
32 Table 3-26: Municipal Solid Waste Generation (Metric Tons) and Percent Combusted.
Year
1990
2000
2005
2006
2007
2008
2009
Waste Discarded
235,733,657
252,328,354
259,559,787
267,526,493
268,279,240
268,541,088
268,541,088"
Waste Incinerated
30,632,057
25,974,978
25,973,520
25,853,401
24,788,539
23,674,017
23,674,017 a
Incinerated (%
of Discards)
13.0
10.3
10.0
9.7
9.2
8.8
8.8a
3 3 a Assumed equal to 2008 value.
34 Source: van Haaren et al. (2010).
35 Uncertainty and Time-Series Consistency
36 A Tier 2 Monte Carlo analysis was performed to determine the level of uncertainty surrounding the estimates of CO2
37 emissions and N2O emissions from the incineration of waste (given the very low emissions for CH4, no uncertainty
38 estimate was derived). IPCC Tier 2 analysis allows the specification of probability density functions for key
39 variables within a computational structure that mirrors the calculation of the inventory estimate. Uncertainty
40 estimates and distributions for waste generation variables (i.e., plastics, synthetic rubber, and textiles generation)
41 were obtained through a conversation with one of the authors of the Municipal Solid Waste in the United States
Energy 3-35
-------
1 reports. Statistical analyses or expert judgments of uncertainty were not available directly from the information
2 sources for the other variables; thus, uncertainty estimates for these variables were determined using assumptions
3 based on source category knowledge and the known uncertainty estimates for the waste generation variables.
4 The uncertainties in the waste incineration emission estimates arise from both the assumptions applied to the data
5 and from the quality of the data. Key factors include MSW incineration rate; fraction oxidized; missing data on
6 waste composition; average C content of waste components; assumptions on the synthetic/biogenic C ratio; and
7 combustion conditions affecting N2O emissions. The highest levels of uncertainty surround the variables that are
8 based on assumptions (e.g., percent of clothing and footwear composed of synthetic rubber); the lowest levels of
9 uncertainty surround variables that were determined by quantitative measurements (e.g., combustion efficiency, C
10 content of C black).
11 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-27. Waste incineration CO2
12 emissions in 2009 were estimated to be between 9.8 and 15.2 Tg CO2 Eq. at a 95 percent confidence level. This
13 indicates a range of 21 percent below to 24 percent above the 2009 emission estimate of 12.3 Tg CO2 Eq. Also at a
14 95 percent confidence level, waste incineration N2O emissions in 2009 were estimated to be between 0.2 and 1.5 Tg
15 CO2 Eq. This indicates a range of 51 percent below to 320 percent above the 2009 emission estimate of 0.4 Tg CO2
16 Eq.
17 Table 3-27: Tier 2 Quantitative Uncertainty Estimates for CO2 and N2O from the Incineration of Waste (Tg CO2 Eq.
18 and Percent)
Source
Incineration of Waste
Incineration of Waste
2009 Emission
Estimate
Gas (TgC02Eq.)
CO2 12.3
N2O 0.4
Uncertainty Range Relative to Emission
(TgC02Eq.) (»/
Lower
Bound
9.8
0.2
Upper
Bound
15.2
1.5
Lower
Bound
-21%
-51%
Estimate"
Upper
Bound
+24%
+320%
19 a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
20 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
21 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
22 above.
23 QA/QC and Verification
24 A source-specific QA/QC plan was implemented for incineration of waste. This effort included a Tier 1 analysis, as
25 well as portions of a Tier 2 analysis. The Tier 2 procedures that were implemented involved checks specifically
26 focusing on the activity data and specifically focused on the emission factor and activity data sources and
27 methodology used for estimating emissions from incineration of waste. Trends across the time series were analyzed
28 to determine whether any corrective actions were needed. Actions were taken to streamline the activity data
29 throughout the calculations on incineration of waste.
30 Recalculations Discussion
31 Several changes were made to input variables compared to the previous Inventory, resulting in an overall decrease in
32 the total emissions from the incineration of waste. Formerly, the percentage of overall rubber waste that is synthetic
33 (i.e., fossil-derived rather than biogenic) varied across the product categories, ranging from 25 percent for clothing
34 and footwear to 100 percent synthetic rubber for durable goods and containers and packaging. For the current
35 Inventory, this variable was updated to be 70 percent synthetic rubber for all four waste categories based on an
36 industry average (RMA, 2011). This change resulted in an average 1 percent decrease in CO2 emissions throughout
37 the time series. In addition, the percentage of waste incinerated was updated for 2008 based on data obtained from
38 The State of Garbage in America report (vanHaaren et al., 2010). Because the report is released every otheryear,
39 the percentage incinerated in 2007 was also updated using linear interpolation from the 2006 and 2008 values. The
40 change in the percentage incinerated, along with the change in the percentage synthetic rubber noted above,
41 decreased the 2007 and 2008 estimates by 4 percent and 7 percent, respectively, relative to the previous report.
3-36 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
i Planned Improvements
2 Beginning in 2010, those facilities that emit over 25,000 tons of greenhouse gases (CO2e) from stationary
3 combustion across all sectors of the economy will be required to calculate and report their greenhouse gas emissions
4 to EPA through its Greenhouse Gas Reporting Program. These data will be used in future inventories to improve the
5 emission calculations through the use of these collected higher tier methodological data.
6 Additional data sources for calculating the N2O and CH4 emission factors for U.S. incineration of waste may be
7 investigated.
8 3.4. Coal Mining (IPCC Source Category 1B1a)
9 Three types of coal mining related activities release CH4 to the atmosphere: underground mining, surface mining,
10 and post-mining (i.e., coal-handling) activities. Underground coal mines contribute the largest share of CH4
11 emissions. In 2009, 135 gassy underground coal mines in the United States employ ventilation systems to ensure
12 that CH4 levels remain within safe concentrations. These systems can exhaust significant amounts of CH4 to the
13 atmosphere in low concentrations. Additionally, 23 U.S. coal mines supplement ventilation systems with
14 degasification systems. Degasification systems are wells drilled from the surface or boreholes drilled inside the
15 mine that remove large volumes of CH4 before, during, or after mining. In 2009, 14 coal mines collected CH4 from
16 degasification systems and utilized this gas, thus reducing emissions to the atmosphere. Of these mines, 13 coal
17 mines sold CH4 to the natural gas pipeline and one coal mine used CH4 from its degasification system to heat mine
18 ventilation air on site. In addition, one of the coal mines that sold gas to pipelines also used CH4 to fuel a thermal
19 coal dryer. Surface coal mines also release CH4 as the overburden is removed and the coal is exposed, but the level
20 of emissions is much lower than from underground mines. Finally, some of the CH4 retained in the coal after
21 mining is released during processing, storage, and transport of the coal.
22 Total CH4 emissions in 2009 were estimated to be 71.0 Tg CO2 Eq. (3,382 Gg), a decline of 16 percent since 1990
23 (see Table 3-28 and Table 3-29). Of this amount, underground mines accounted for 71 percent, surface mines
24 accounted for 18 percent, and post-mining emissions accounted for 11 percent. The decline in CH4 emissions from
25 underground mines from 1996 to 2002 was the result of the reduction of overall coal production, the mining of less
26 gassy coal, and an increase in CH4 recovered and used. Since that time, underground coal production and the
27 associated methane emissions have remained fairly level, while surface coal production and its associated emissions
28 have generally increased.
29 Table 3-28: CH4 Emissions from Coal Mining (Tg CO2 Eq.)
30
31
32
33
Activity
UG Mining
Liberated
Recovered & Used
Surface Mining
Post-Mining (UG)
Post-Mining (Surface)
Total
Note: Totals may not sum
1990
62.3
67.9
(5.6)
12.0
7.7
2.0
84.1
2000
39.4
54.4
(14.9)
12.3
6.7
2.0
60.4
due to independent rounding.
Table 3-29: CH4 Emissions from Coal
Activity
UG Mining
Liberated
Recovered & Used
Surface Mining
Post-Mining (UG)
Post-Mining (Surface)
Total
Note: Totals may not sum
1990
2,968
3,234
(265.9)
573.6
368.3
93.2
4,003
2005
35.0
50.2
(15.1)
13.3
6.4
2.2
56.9
2006
35.7
54.3
(18.7)
14.0
6.3
2.3
58.2
2007
35.7
51.0
(15.3)
13.8
6.1
2.2
57.9
2008
44.4
60.5
(16.1)
14.3
6.1
2.3
67.1
2009
50.4
67.0
(16.5)
12.9
5.6
2.1
71.0
Parentheses indicate negative values.
Mining (Gg)
2000
1,878
2,588
(710.4)
585.7
318.1
95.2
2,877
due to independent rounding.
2005
1,668
2,389
(720.8)
633.1
305.9
102.9
2,710
2006
1,699
2,588
(889.4)
668.0
298.5
108.5
2,774
2007
1,700
2,427
(727.2)
658.9
289.6
107.1
2,756
2008
2,113
2,881
(768.0)
680.5
292.0
110.6
3,196
2009
2,401
3,189
(787.1)
614.2
266.7
99.8
3,382
Parentheses indicate negative values.
Energy 3-37
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i Methodology
2 The methodology for estimating CH4 emissions from coal mining consists of two parts. The first part involves
3 estimating CH4 emissions from underground mines. Because of the availability of ventilation system measurements,
4 underground mine emissions can be estimated on a mine-by-mine basis and then summed to determine total
5 emissions. The second step involves estimating emissions from surface mines and post-mining activities by
6 multiplying basin-specific coal production by basin-specific emission factors.
7 Underground mines. Total CH4 emitted from underground mines was estimated as the sum of CH4 liberated from
8 ventilation systems and CH4 liberated by means of degasification systems, minus CH4 recovered and used. The
9 Mine Safety and Heath Administration (MSHA) samples CH4 emissions from ventilation systems for all mines with
10 detectable93 CH4 concentrations. These mine-by-mine measurements are used to estimate CH4 emissions from
11 ventilation systems.
12 Some of the higher-emitting underground mines also use degasification systems (e.g., wells or boreholes) that
13 remove CH4 before, during, or after mining. This CH4 can then be collected for use or vented to the atmosphere.
14 Various approaches were employed to estimate the quantity of CH4 collected by each of the twenty mines using
15 these systems, depending on available data. For example, some mines report to EPA the amount of CH4 liberated
16 from their degasification systems. For mines that sell recovered CH4 to a pipeline, pipeline sales data published by
17 state petroleum and natural gas agencies were used to estimate degasification emissions. For those mines for which
18 no other data are available, default recovery efficiency values were developed, depending on the type of
19 degasification system employed.
20 Finally, the amount of CH4 recovered by degasification systems and then used (i.e., not vented) was estimated. In
21 2009, 13 active coal mines sold recovered CH4 into the local gas pipeline networks and one coal mine used
22 recovered CH4 on site for heating. Emissions avoided for these projects were estimated using gas sales data reported
23 by various state agencies. For most mines with recovery systems, companies and state agencies provided individual
24 well production information, which was used to assign gas sales to a particular year. For the few remaining mines,
25 coal mine operators supplied information regarding the number of years in advance of mining that gas recovery
26 occurs.
27 Surface Mines and Post-Mining Emissions. Surface mining and post-mining CH4 emissions were estimated by
28 multiplying basin-specific coal production, obtained from the Energy Information Administration's Annual Coal
29 Report (see Table 3-30) (EIA 2010), by basin-specific emission factors. Surface mining emission factors were
30 developed by assuming that surface mines emit two times as much CH4 as the average in situ CH4 content of the
31 coal. Revised data on in situ CH4 content and emissions factors are taken from EPA (2005), EPA (1996), and
32 AAPG(1984). This calculation accounts for CH4 released from the strata surrounding the coal seam. For post-
33 mining emissions, the emission factor was assumed to be 32.5 percent of the average in situ CH4 content of coals
34 mined in the basin.
35 Table 3-30: Coal Production (Thousand Metric Tons)
Year
1990
2000
2005
2006
2007
2008
2009
Underground
384,244
338,168
334,398
325,697
319,139
323,932
301,241
Surface
546,808
635,581
691,448
728,447
720,023
737,832
671,475
Total
931,052
973,749
1,025,846
1,054,144
1,039,162
1,061,764
972,716
36
93 MSHA records coal mine CH4 readings with concentrations of greater than 50 ppm (parts per million) CELt. Readings below
this threshold are considered non-detectable.
3-38 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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i Uncertainty and Time-Series Consistency
2 A quantitative uncertainty analysis was conducted for the coal mining source category using the IPCC-
3 recommended Tier 2 uncertainty estimation methodology. Because emission estimates from underground
4 ventilation systems were based on actual measurement data, uncertainty is relatively low. A degree of imprecision
5 was introduced because the measurements used were not continuous but rather an average of quarterly instantaneous
6 readings. Additionally, the measurement equipment used can be expected to have resulted in an average of 10
7 percent overestimation of annual CH4 emissions (Mutmansky and Wang 2000). Estimates of CH4 recovered by
8 degasification systems are relatively certain because many coal mine operators provided information on individual
9 well gas sales and mined through dates. Many of the recovery estimates use data on wells within 100 feet of a
10 mined area. Uncertainty also exists concerning the radius of influence of each well. The number of wells counted,
11 and thus the avoided emissions, may vary if the drainage area is found to be larger or smaller than currently
12 estimated.
13 Compared to underground mines, there is considerably more uncertainty associated with surface mining and post-
14 mining emissions because of the difficulty in developing accurate emission factors from field measurements.
15 However, since underground emissions comprise the majority of total coal mining emissions, the uncertainty
16 associated with underground emissions is the primary factor that determines overall uncertainty. The results of the
17 Tier 2 quantitative uncertainty analysis are summarized in Table 3-31. Coal mining CH4 emissions in 2009 were
18 estimated to be between 62.0 and 82.4 Tg CO2 Eq. at a 95 percent confidence level. This indicates a range of 12.7
19 percent below to 16.1 percent above the 2009 emission estimate of 71.0 Tg CO2Eq.
20 Table 3-31: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Coal Mining (Tg CO2 Eq. and
21 Percent)
2009 Emission
Estimate
Source Gas (Tg CO2 Eq.)
Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (%)
Lower Bound Upper Bound Lower Bound Upper Bound
Coal Mining CH4 71.0
62.0 82.4 -12.7% +16.1%
22 a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
23 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
24 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
25 above.
26 Recalculations Discussion
27 For the current Inventory, there were some changes to pre-2009 emission estimates relative to the previous
28 Inventory. For the current Inventory, the conversion factor for converting short tons to metric tons was updated to
29 0.90718474 to be consistent with the number of significant digits used in other source categories. In the past, 0.9072
30 had been used. The factor was updated for all years, thus coal production estimates in Table 3-31 have changed
31 slightly.
32 Other changes include the recalculation of emissions avoided for two Jim Walter Resources (JWR) mines: Blue
33 Creek #4 Mine and Blue Creek #7 Mine. This resulted in changes to emissions avoided numbers for 2007 and 2008.
34 In 1998, 2000, 2001, 2002, 2003, and 2004, the emissions avoided for the Blacksville No. 2 mine in West Virginia
35 were assigned to Pennsylvania rather than West Virginia. These emissions avoided were correctly assigned to West
36 Virginia in the current Inventory; however, total emissions were not affected.
37 The emissions avoided for the Emerald and Cumberland mines were adjusted going back to 2006 based on
3 8 information provided by the proj ect developer.
39 3.5. Abandoned Underground Coal Mines (IPCC Source Category 1B1a)
40 Underground coal mines contribute the largest share of CH4 emissions, with active underground mines the leading
41 source of underground emissions. However, mines also continue to release CH4 after closure. As mines mature and
42 coal seams are mined through, mines are closed and abandoned. Many are sealed and some flood through intrusion
43 of groundwater or surface water into the void. Shafts or portals are generally filled with gravel and capped with a
Energy 3-39
-------
1 concrete seal, while vent pipes and boreholes are plugged in a manner similar to oil and gas wells. Some abandoned
2 mines are vented to the atmosphere to prevent the buildup of CH4 that may find its way to surface structures through
3 overburden fractures. As work stops within the mines, the CH4 liberation decreases but it does not stop completely.
4 Following an initial decline, abandoned mines can liberate CH4 at a near-steady rate over an extended period of
5 time, or, if flooded, produce gas for only a few years. The gas can migrate to the surface through the conduits
6 described above, particularly if they have not been sealed adequately. In addition, diffuse emissions can occur when
7 CH4 migrates to the surface through cracks and fissures in the strata overlying the coal mine. The following factors
8 influence abandoned mine emissions:
9 • Time since abandonment;
10 • Gas content and adsorption characteristics of coal;
11 • CH4 flow capacity of the mine;
12 • Mine flooding;
13 • Presence of vent holes; and
14 • Mine seals.
15
16
17
18
19
20
21
22
23
24
25
26
27
Gross abandoned mine CH4 emissions ranged from 6.0 to 9.1 Tg CO2 Eq. from 1990 through 2009, varying, in
general, by less than 1 to approximately 19 percent 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. Gross
abandoned mine emissions peaked in 1996 (9. 1 Tg CO2 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 emissions
have been generally on the decline since 1996. There were fewer than fifteen gassy mine closures during each of the
years from 1998 through 2009, with only ten closures in 2009. By 2009, gross abandoned mine emissions decreased
slightly to 8.5 Tg CO2 Eq. (see Table 3-32 and Table 3-33). Gross emissions are reduced by CH4 recovered and
used at 38 mines, resulting in net emissions in 2009 of 5.5 Tg CO2 Eq.
Table 3-32: CH4 Emissions from Abandoned Coal Mines (Tg CO2 Eq.)
Activity
Abandoned Underground
Recovered & Used
Total
1990
Mines 6.0
0.0
6.0
2000
8.9
1.5
7.4
2005
7.0
1.5
5.5
i
2006
7.6
2.2
5.5
2007
8.9
3.3
5.6
2008
9.0
3.2
5.9
2009
8.5
3.0
5.5
Note: Totals may not sum due to independent rounding.
Table 3-33 : CH4 Emissions from Abandoned Coal Mines (Gg)
Activity
Abandoned Underground
Recovered & Used
Total
1990
Mines 288
0
288
2000
422
72
350
2005
334
70
264
2006
364
103
261
2007
425
158
267
2008
430
150
279
2009
406
144
262
_
28 Note: Totals may not sum due to independent rounding.
29 Methodology
30 Estimating CH4 emissions from an abandoned coal mine requires predicting the emissions of a mine from the time
31 of abandonment through the inventory year of interest. The flow of CH4 from the coal to the mine void is primarily
32 dependent on the mine's emissions when active and the extent to which the mine is flooded or sealed. The CH4
33 emission rate before abandonment reflects the gas content of the coal, rate of coal mining, and the flow capacity of
34 the mine in much the same way as the initial rate of a water-free conventional gas well reflects the gas content of the
35 producing formation and the flow capacity of the well. A well or a mine which produces gas from a coal seam and
36 the surrounding strata will produce less gas through time as the reservoir of gas is depleted. Depletion of a reservoir
37 will follow a predictable pattern depending on the interplay of a variety of natural physical conditions imposed on
38 the reservoir. The depletion of a reservoir is commonly modeled by mathematical equations and mapped as a type
39 curve. Type curves which are referred to as decline curves have been developed for abandoned coal mines. Existing
40 data on abandoned mine emissions through time, although sparse, appear to fit the hyperbolic type of decline curve
3-40 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 used in forecasting production from natural gas wells.
2 In order to estimate CH4 emissions over time for a given mine, it is necessary to apply a decline function, initiated
3 upon abandonment, to that mine. In the analysis, mines were grouped by coal basin with the assumption that they
4 will generally have the same initial pressures, permeability and isotherm. As CH4 leaves the system, the reservoir
5 pressure, Pr, declines as described by the isotherm. The emission rate declines because the mine pressure (Pw) is
6 essentially constant at atmospheric pressure, for a vented mine, and the PI term is essentially constant at the
7 pressures of interest (atmospheric to 30 psia). A rate-time equation can be generated that can be used to predict
8 future emissions. This decline through time is hyperbolic in nature and can be empirically expressed as:
9 q =
10 where,
11 q Gas rate at time t in mmcf/d
12 Qi = Initial gas rate at time zero (to) in million cubic feet per day mmcfd)
13 b = The hyperbolic exponent, dimensionless
14 D! = Initial decline rate, 1/yr
15 t = Elapsed time from t0 (years)
16 This equation is applied to mines of various initial emission rates that have similar initial pressures, permeability and
17 adsorption isotherms (EPA 2003).
18 The decline curves created to model the gas emission rate of coal mines must account for factors that decrease the
19 rate of emission after mining activities cease, such as sealing and flooding. Based on field measurement data, it was
20 assumed that most U.S. mines prone to flooding will become completely flooded within eight years and therefore no
21 longer have any measurable CH4 emissions. Based on this assumption, an average decline rate for flooding mines
22 was established by fitting a decline curve to emissions from field measurements. An exponential equation was
23 developed from emissions data measured at eight abandoned mines known to be filling with water located in two of
24 the five basins. Using a least squares, curve-fitting algorithm, emissions data were matched to the exponential
25 equation shown below. There was not enough data to establish basin-specific equations as was done with the
26 vented, non-flooding mines (EPA 2003).
27 q = qle™
28 where,
29 q Gas flow rate at time t in mcf/d
30 Qi = Initial gas flow rate at time zero (to) in mcfd
31 D = Decline rate, 1/yr
32 t = Elapsed time from t0 (years)
33
34 Seals have an inhibiting effect on the rate of flow of CH4 into the atmosphere compared to the rate that would be
3 5 emitted if the mine had an open vent. The total volume emitted will be the same, but will occur over a longer
36 period. The methodology, therefore, treats the emissions prediction from a sealed mine similar to emissions from a
37 vented mine, but uses a lower initial rate depending on the degree of sealing. The computational fluid dynamics
38 simulator was again used with the conceptual abandoned mine model to predict the decline curve for inhibited flow.
39 The percent sealed is defined as 100 * (1 - (initial emissions from sealed mine / emission rate at abandonment prior
40 to sealing)). Significant differences are seen between 50 percent, 80 percent and 95 percent closure. These decline
41 curves were therefore used as the high, middle, and low values for emissions from sealed mines (EPA 2003).
42 For active coal mines, those mines producing over 100 mcfd account for 98 percent of all CH4 emissions. This same
43 relationship is assumed for abandoned mines. It was determined that 469 abandoned mines closing after 1972
44 produced emissions greater than 100 mcfd when active. Further, the status of 273 of the 469 mines (or 58 percent)
45 is known to be either: 1) vented to the atmosphere; 2) sealed to some degree (either earthen or concrete seals); or, 3)
46 flooded (enough to inhibit CH4 flow to the atmosphere). The remaining 42 percent of the mines were placed in one
47 of the three categories by applying a probability distribution analysis based on the known status of other mines
48 located in the same coal basin (EPA 2003).
49 Table 3-34: Number of gassy abandoned mines occurring in U.S. basins grouped by class according to post-
50 abandonment state
Energy 3-41
-------
Basin Sealed Vented Flooded Total Known Unknown Total Mines
Central Appl.
Illinois
Northern Appl.
Warrior Basin
Western Basins
Total
25
30
42
0
27
124
25
3
22
0
3
53
48
14
16
16
2
96
98
47
80
16
32
273
127
25
35
0
9
196
224
72
115
16
41
469
1
2 Inputs to the decline equation require the average emission rate and the date of abandonment. Generally this data is
3 available for mines abandoned after 1972; however, such data are largely unknown for mines closed before 1972.
4 Information that is readily available such as coal production by state and county are helpful, but do not provide
5 enough data to directly employ the methodology used to calculate emissions from mines abandoned after 1971. It is
6 assumed that pre-1972 mines are governed by the same physical, geologic, and hydrologic constraints that apply to
7 post-1972 mines; thus, their emissions may be characterized by the same decline curves.
8 During the 1970s, 78 percent of CH4 emissions from coal mining came from seventeen counties in seven states. In
9 addition, mine closure dates were obtained for two states, Colorado and Illinois, for the hundred year period
10 extending from 1900 through 1999. The data were used to establish a frequency of mine closure histogram (by
11 decade) and applied to the other five states with gassy mine closures. As a result, basin-specific decline curve
12 equations were applied to 145 gassy coal mines estimated to have closed between 1920 and 1971 in the United
13 States, representing 78 percent of the emissions. State-specific, initial emission rates were used based on average
14 coal mine CH4 emission rates during the 1970s (EPA 2003).
15 Abandoned mines emission estimates are based on all closed mines known to have active mine CH4 ventilation
16 emission rates greater than 100 mcfd at the time of abandonment. For example, for 1990 the analysis included 145
17 mines closed before 1972 and 258 mines closed between 1972 and 1990. Initial emission rates based on MSHA
18 reports, time of abandonment, and basin-specific decline curves influenced by a number of factors were used to
19 calculate annual emissions for each mine in the database. Coal mine degasification data are not available for years
20 prior to 1990, thus the initial emission rates used reflect ventilation emissions only for pre-1990 closures. CH4
21 degasification amounts were added to the quantity of CH4 ventilated for the total CH4 liberation rate for 21 mines
22 that closed between 1992 and 2009. Since the sample of gassy mines (with active mine emissions greater than 100
23 mcfd) is assumed to account for 78 percent of the pre-1971 and 98 percent of the post-1971 abandoned mine
24 emissions, the modeled results were multiplied by 1.22 and 1.02 to account for all U.S. abandoned mine emissions.
25 From 1993 through 2009, emission totals were downwardly adjusted to reflect abandoned mine CH4 emissions
26 avoided from those mines. The inventory totals were not adjusted for abandoned mine reductions in 1990 through
27 1992, because no data was reported for abandoned coal mining CH4 recovery projects during that time.
28 Uncertainty and Time-Series Consistency
29 A quantitative uncertainty analysis was conducted to estimate the uncertainty surrounding the estimates of emissions
30 from abandoned underground coal mines. The uncertainty analysis described below provides for the specification of
31 probability density functions for key variables within a computational structure that mirrors the calculation of the
32 inventory estimate. The results provide the range within which, with 95 percent certainty, emissions from this
33 source category are likely to fall.
34 As discussed above, the parameters for which values must be estimated for each mine in order to predict its decline
35 curve are: 1) the coal's adsorption isotherm; 2) CH4 flow capacity as expressed by permeability; and 3) pressure at
36 abandonment. Because these parameters are not available for each mine, a methodological approach to estimating
37 emissions was used that generates a probability distribution of potential outcomes based on the most likely value and
38 the probable range of values for each parameter. The range of values is not meant to capture the extreme values, but
3 9 values that represent the highest and lowest quartile of the cumulative probability density function of each
40 parameter. Once the low, mid, and high values are selected, they are applied to a probability density function.
41 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-35. Abandoned coal mines
42 CH4 emissions in 2009 were estimated to be between 4.0 and 7.3 Tg CO2 Eq. at a 95 percent confidence level. This
43 indicates a range of 27 percent below to 32 percent above the 2009 emission estimate of 5.5 Tg CO2 Eq. One of the
44 reasons for the relatively narrow range is that mine-specific data is used in the methodology. The largest degree of
3-42 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 uncertainty is associated with the unknown status mines (which account for 42 percent of the mines), with a ±57
2 percent uncertainty.
3 Table 3-35: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Abandoned Underground Coal
4 Mines (Tg CO2 Eq. and Percent)
2009 Emission Uncertainty Range Relative to Emission
Estimate Estimate"
Source Gas (TgCO2Eq.) (TgCO2Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper
Bound
Abandoned Underground p^r
Coal Mines 4 5.5 4.0 7.3 -27% +32%
5 a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
6
7 Recalculations Discussion
8 Changes in pre-2009 emissions avoided relative to the previous Inventory are due to the additions of pre-1972
9 Grayson Hills Energy and DTE Corinth projects, which were added to the current inventory. There were also two
10 abandoned mines added to the current Inventory, one abandoned in 2007 and one in 2008, which resulted in changes
11 in the liberated emissions relative to the previous report.
12 3.6. Natural Gas Systems (IPCC Source Category 1B2b)
13 The U.S. natural gas system encompasses hundreds of thousands of wells, hundreds of processing facilities, and
14 over a million miles of transmission and distribution pipelines. Overall, natural gas systems emitted 221.2 Tg CO2
15 Eq. (10,535 Gg) of CH4 in 2009, a 17 percent increase over 1990 emissions (see Table 3-36 and Table 3-37), and
16 32.2 Tg CO2 Eq. (32,171 Gg) of non-combustion CO2 in 2009, a 14 percent decrease over 1990 emissions (see
17 Table 3-38 and Table 3-39). Improvements in management practices and technology, along with the replacement of
18 older equipment, have helped to stabilize emissions. Methane emissions increased since 2008 due to an increase in
19 production and production wells.
20 CH4 and non-combustion CO2 emissions from natural gas systems are generally process related, with normal
21 operations, routine maintenance, and system upsets being the primary contributors. Emissions from normal
22 operations include: natural gas engines and turbine uncombusted exhaust, bleed and discharge emissions from
23 pneumatic devices, and fugitive emissions from system components. Routine maintenance emissions originate from
24 pipelines, equipment, and wells during repair and maintenance activities. Pressure surge relief systems and
25 accidents can lead to system upset emissions. Below is a characterization of the four major stages of the natural gas
26 system. Each of the stages is described and the different factors affecting CH4 and non-combustion CO2 emissions
27 are discussed.
28 Field Production. In this initial stage, wells are used to withdraw raw gas from underground formations. Emissions
29 arise from the wells themselves, gathering pipelines, and well-site gas treatment facilities such as dehydrators and
30 separators. Emissions from pneumatic devices, well clean-ups, and unconventional gas well completions and re-
31 completions account for the majority of CH4 emissions. Flaring emissions account for the majority of the non-
32 combustion CO2 emissions. Emissions from field production accounted for approximately 59 percent of CH4
33 emissions and about 34 percent of non-combustion CO2 emissions from natural gas systems in 2009.
34 Processing. In this stage, natural gas liquids and various other constituents from the raw gas are removed, resulting
35 in "pipeline quality" gas, which is injected into the transmission system. Fugitive CH4 emissions from compressors,
36 including compressor seals, are the primary emission source from this stage. The majority of non-combustion CO2
37 emissions come from acid gas removal units, which are designed to remove CO2 from natural gas. Processing plants
38 account for about 8 percent of CH4 emissions and approximately 66 percent of non-combustion CO2 emissions from
39 natural gas systems.
40 Transmission and Storage. Natural gas transmission involves high pressure, large diameter pipelines that transport
41 gas long distances from field production and processing areas to distribution systems or large volume customers
42 such as power plants or chemical plants. Compressor station facilities, which contain large reciprocating and turbine
43 compressors, are used to move the gas throughout the United States transmission system. Fugitive CH4 emissions
Energy 3-43
-------
1 from these compressor stations and from metering and regulating stations account for the majority of the emissions
2 from this stage. Pneumatic devices and engine uncombusted exhaust are also sources of CH4 emissions from
3 transmission facilities.
4 Natural gas is also injected and stored in underground formations, or liquefied and stored in above ground tanks,
5 during periods of low demand (e.g., summer), and withdrawn, processed, and distributed during periods of high
6 demand (e.g., winter). Compressors and dehydrators are the primary contributors to emissions from these storage
7 facilities. CH4 emissions from the transmission and storage sector account for approximately 20 percent of
8 emissions from natural gas systems, while CO2 emissions from transmission and storage account for less than 1
9 percent of the non-combustion CO2 emissions from natural gas systems.
10 Distribution. Distribution pipelines take the high-pressure gas from the transmission system at "city gate" stations,
11 reduce the pressure and distribute the gas through primarily underground mains and service lines to individual end
12 users. There were over 1,208,000 miles of distribution mains in 2009, an increase from just over 944,000 miles in
13 1990 (OPS 2010b). Distribution system emissions, which account for approximately 13 percent of CH4 emissions
14 from natural gas systems and less than 1 percent of non-combustion CO2 emissions, result mainly from fugitive
15 emissions from gate stations and pipelines. An increased use of plastic piping, which has lower emissions than other
16 pipe materials, has reduced emissions from this stage. Distribution system CH4 emissions in 2009 were 13 percent
17 lower than 1990 levels.
18 Table 3-36: CH4 Emissions from Natural Gas Systems (Tg CO2 Eq.)*
19
20
21
22
23
24
25
26
27
28
29
30
Stage 1990 2000 2005 2006 2007 2008
Field Production 89.2 113.5 105.4 134.0 118.2 122.9
Processing 18.0 17.7 14.3 14.5 15.1 15.7
Transmission and Storage 49.2 46.7 41.4 41.0 42.5 43.3
Distribution 33.4 31.4 29.3 28.3 29.4 29.9
Total 189.8 209.3 190.4 217.7 205.2 211.8
2009
130.3
17.5
44.4
29.0
221.2
*Including CH4 emission reductions achieved by the Natural Gas STAR program and NESHAP regulations.
Note: Totals may not sum due to independent rounding.
Table 3-37: CH4Emissions from Natural Gas Systems (Gg)*
Stage 1990 2000 2005 2006 2007 2008
Field Production 4,248 5,406 5,021 6,380 5,628 5,854
Processing 855 841 681 689 717 748
Transmission and Storage 2,344 2,224 1,973 1,950 2,025 2,062
Distribution 1,591 1,497 1,395 1,346 1,402 1,423
Total 9,038 9,968 9,069 10,364 9,771 10,087
2009
6,205
834
2,115
1,381
10,535
*Including CH4 emission reductions achieved by the Natural Gas STAR program and NESHAP regulations.
Note: Totals may not sum due to independent rounding.
Table 3-38: Non-combustion CO2 Emissions from Natural Gas Systems (Tg CO2 Eq.)
Stage 1990 2000 2005 2006 2007 2008
Field Production 9.7 6.4 8.0 9.4 9.7 11.3
Processing 27.8 23.3 21.7 21.2 21.2 21.4
Transmission and Storage 0.1 0.1 0.1 0.1 0.1 0.1
Distribution + + + + + +
Total 37.6 29.9 29.9 30.8 31.1 32.8
2009
10.9
21.2
0.1
32.2
Note: Totals may not sum due to independent rounding.
+ Emissions are less than 0. 1 Tg CO2 Eq.
Table 3-39: Non-combustion CO2 Emissions from Natural Gas Systems (Gg)
Stage 1990 2000 2005 2006 2007 2008
Field Production 9,704 6,425 8,050 9,438 9,746 11,336
Processing 27,763 23,343 21,746 21,214 21,199 21,385
Transmission and Storage 62 64 64 63 64 65
Distribution 46 44 41 40 41 42
2009
10,877
21,189
65
41
3-44 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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Total 37,574 29,877 29,902 30,755 31,050 32,828 32,1^1
7~
3 Note: Totals may not sum due to independent rounding.
4 Methodology
5 The primary basis for estimates of CH4 and non-combustion-related CO2 emissions from the U.S. natural gas
6 industry is a detailed study by the Gas Research Institute and EPA (EPA/GRI1996). The EPA/GRI study developed
7 over 80 CH4 emission and activity factors to characterize emissions from the various components within the
8 operating stages of the U.S. natural gas system. The same activity factors were used to estimate both CH4 and non-
9 combustion CO2 emissions. However, the CH4 emission factors were adjusted for CO2 content when estimating
10 fugitive and vented non-combustion CO2 emissions. The EPA/GRI study was based on a combination of process
11 engineering studies and measurements at representative gas facilities. From this analysis, a 1992 emission estimate
12 was developed using the emission and activity factors, except where direct activity data was available (e.g., offshore
13 platform counts, processing plant counts, transmission pipeline miles, and distribution pipelines). For other years, a
14 set of industry activity factor drivers was developed that can be used to update activity factors. These drivers
15 include statistics on gas production, number of wells, system throughput, miles of various kinds of pipe, and other
16 statistics that characterize the changes in the U.S. natural gas system infrastructure and operations.
17 Although the inventory primarily uses EPA/GRI emission factors, significant improvements were made to the
18 emissions estimates for three sources this year: gas well cleanups, condensate storage tanks and centrifugal
19 compressors. In addition, EPA has added data for two sources not included in the EPA/GRI study - unconventional
20 gas well completions and unconventional gas well workovers (re-completions). In the case of gas well cleanups, the
21 methodology was revised to use a large sample of well and reservoir characteristics from the HPDI database (HPDI
22 2009) along with an engineering statics equation (EPA 2006a) to estimate the volume of natural gas necessary to
23 expel a liquid column choking the well production. EPA used the same sample E&P Tank sample runs for
24 condensate tank flashing emissions; however, improved the factor by using a large sample distribution of condensate
25 production by gravity from the HPDI database (HPDI 2009) to weigh the sample simulation flashing emissions
26 rather than assuming a uniform distribution of condensate gravities. Additionally, TERC (TERC 2009) data
27 representing two regions was used in the emission factors for those two regions to estimate the effects of separator
28 dump valves malfunctioning and allowing natural gas to vent through the downstream storage tanks. The EPA/GRI
29 emission factor for centrifugal compressors sampled emissions at the seal face of wet seal compressors, EPA used a
30 World Gas Conference publication (WGC 2009) on the seal oil degassing vents to update this factor and also
31 accounted for the emergence of dry seal centrifugal compressors (EPA 2006b), which eliminates seal oil degassing
32 vents and reduces overall emissions. Unconventional gas well completions and workvovers were not common at the
33 time the EPA/GRI survey was conducted, since then emissions data has become available through Natural Gas
34 STAR experiences and presentations (EPA 2004, 2007) as these activities became more prevalent. These changes
35 are described below in the Recalculations section. See Annex 3.4 for more detailed information on the methodology
36 and data used to calculate CH4 and non-combustion CO2 emissions from natural gas systems.
37 Activity factor data were taken from the following sources: American Gas Association (AGA 1991-1998); Bureau
38 of Ocean Energy Management, Regulation and Enforcement (previous Minerals and Management Service)
39 (BOEMRE 2010a-d); Monthly Energy Review (EIA 2010f); Natural Gas Liquids Reserves Report (EIA 2005);
40 Natural Gas Monthly (EIA 2010b,c,e); the Natural Gas STAR Program annual emissions savings (EPA 2010); Oil
41 and Gas Journal (OGJ 1997-2010); Office of Pipeline Safety (OPS 2010a-b); Federal Energy Regulatory
42 Commission (FERC 2010) and other Energy Information Administration publications (EIA 2001, 2004, 2010a,d);
43 World Oil Magazine (20 lOa-b). Data for estimating emissions from hydrocarbon production tanks were
44 incorporated (EPA 1999). Coalbed CH4 well activity factors were taken from the Wyoming Oil and Gas
45 Conservation Commission (Wyoming 2009) and the Alabama State Oil and Gas Board (Alabama 2010). Other state
46 well data was taken from: American Association of Petroleum Geologists (AAPG 2004); Brookhaven College
47 (Brookhaven 2004); Kansas Geological Survey (Kansas 2010); Montana Board of Oil and Gas Conservation
48 (Montana 2010); Oklahoma Geological Survey (Oklahoma 2010); Morgan Stanley (Morgan Stanley 2005); Rocky
49 Mountain Production Report (Lippman 2003); New Mexico Oil Conservation Division (New Mexico 2010, 2005);
50 Texas Railroad Commission (Texas 20 lOa-d); Utah Division of Oil, Gas and Mining (Utah 2010). Emission factors
51 were taken from EPA/GRI (1996). GTFs Unconventional Natural Gas and Gas Composition Databases (GTI2001)
52 were used to adapt the CH4 emission factors into non-combustion related CO2 emission factors. Additional
53 information about CO2 content in transmission quality natural gas was obtained via the internet from numerous U.S.
Energy 3-45
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1 transmission companies to help further develop the non-combustion CO2 emission factors.
2 Uncertainty and Time-Series Consistency
3 A quantitative uncertainty analysis was conducted to determine the level of uncertainty surrounding estimates of
4 emissions from natural gas systems. Performed using @RISK software and the IPCC-recommended Tier 2
5 methodology (Monte Carlo Simulation technique), this analysis provides for the specification of probability density
6 functions for key variables within a computational structure that mirrors the calculation of the inventory estimate.
7 The @PJSK model utilizes 1992 (base year) emissions to quantify the uncertainty associated with the emissions
8 estimates using the top twelve emission sources for the year 2009.
9 The results presented below provide with 95 percent certainty the range within which emissions from this source
10 category are likely to fall for the year 2009. The heterogeneous nature of the natural gas industry makes it difficult
11 to sample facilities that are completely representative of the entire industry. Because of this, scaling up from model
12 facilities introduces a degree of uncertainty. Additionally, highly variable emission rates were measured among
13 many system components, making the calculated average emission rates uncertain. The results of the Tier 2
14 quantitative uncertainty analysis are summarized in Table 3-40. Natural gas systems CH4 emissions in 2009 were
15 estimated to be between 179.1 and 287.6 Tg CO2 Eq. at a 95 percent confidence level. Natural gas systems non-
16 energy CO2 emissions in 2009 were estimated to be between 26.1 and 41.9 Tg CO2 Eq. at 95 percent confidence
17 level.
18 Table 3-40: Tier 2 Quantitative Uncertainty Estimates for CH4 and Non-energy CO2 Emissions from Natural Gas
19 Systems (Tg CO2 Eq. and Percent)
2009 Emission
Estimate
Source Gas (Tg CO2 Eq.)c
Natural Gas Systems CH4 221.2
Natural Gas Systems'3 CO2 32.2
Uncertainty Range Relative to Emission Estimate"
(TgC02Eq.) (%)
Lower
Bound0
179.1
26.1
Upper
Bound0
287.6
41.9
Lower
Bound0
-19%
-19%
Upper
Bound0
+30%
+30%
20 a Range of emission estimates predicted by Monte Carlo Simulation for a 95 percent confidence interval.
21 b An uncertainty analysis for the non-energy CO2 emissions was not performed. The relative uncertainty estimated (expressed as
22 a percent) from the CH4 uncertainty analysis was applied to the point estimate of non-energy CO2 emissions.
23 ° All reported values are rounded after calculation. As a result, lower and upper bounds may not be duplicable from other
24 rounded values as shown in table.
25 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
26 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
27 above.
28 QA/QC and Verification Discussion
29 A number of potential data sources were investigated to improve selected emission factors in the natural gas
30 industry. First, the HPDI database for well production and well properties was investigated for potential engineering
31 parameters to be used in engineering equations to develop a new emission factor for well cleanups (HPDI 2009).
32 The database was queried to obtain average well depth, shut-in pressure, well counts, and well production from each
33 basin. These parameters were used along with industry experiences to develop an engineering estimate of emissions
34 from each well in each basin of the sample data. The analysis led to a new emission factor for the gas well cleanup
35 source.
36 Additionally, industry experiences with hydraulic fracturing of tight formations for the completion or workover of
37 natural gas wells were reviewed to account for this source of emissions. Several Partners of the Natural Gas STAR
38 Program have reported recovering substantial volumes of natural gas that would have otherwise been vented
39 following completions or re-completions (workovers) involving hydraulic fracturing. This completion method,
40 which is a large emission source, was not characterized by the base EPA/GRI1996 study and has not been
41 accounted for in the EPA Inventory until this year.
42 A World Gas Conference paper (WGC 2009) gathered 48 sample measurements of centrifugal compressor wet seal
43 oil degassing emissions and published the results. The base year EPA/GRI 1996 study did not measure emissions
3-46 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 from the seal oil degassing vent. Instead seal face emissions were quantified and as such this emission source has
2 gone uncharacterized in the EPA Inventory until this year.
3 EPA has learned that in some production areas the separator liquid level may drop too low such that the produced
4 associated gas blows through the dump valve and vents through the storage tank. These data were included where
5 available for the Inventory. More data will be necessary to potentially separate this source from storage tank
6 flashing emissions and also to represent the true scope of activity across the United States.
7 A number of other data sources for fugitive emission factors from the processing and transmission and storage
8 segments were reviewed. Several studies have been published since the EPA/GRI1996 base year study that sample
9 emissions from the same common equipment components. The raw emissions data from these surveys can
10 potentially be combined with the raw data from the base year study to develop stronger emission factors. In addition
11 to common component leaks, several of these studies propose emission factors for pneumatic devices or other
12 sources. These studies require further review and thus the data are not included in the Inventory at this time.
13 Recalculations Discussion
14 Methodologies for gas well cleanups and condensate storage tanks were revised for the current Inventory, and new
15 sources of data for centrifugal compressors with wet seals, unconventional gas well completions, and
16 unconventional gas well workovers were used.
17 The largest increase in emissions relative to the previous Inventory was due to the revised emission factor for gas
18 well cleanups (also referred to in industry as gas well liquids unloading). HPDI well production and well property
19 sample data on well depth, shut-in pressure, and production rates were used in an engineering equation to re-
20 estimate the average unloading emissions by NEMS region for this source (HPDI 2009). This methodological
21 change increased emissions by more than 22 times while decreasing the substantial uncertainty that was associated
22 with the previous emission factor from the EPA/GRI 1996 study. The activity data remained the same as the
23 previous methodology.
24 The next largest increase in emissions was due to the inclusion of gas well completions and workovers involving
25 hydraulic fracture. The EPA/GRI 1996 study did not account for this emerging technology and the source was
26 previously unaccounted for in the Inventory. Unlike conventional completions and workovers, the high pressure
27 venting of gas in order to expel the large volumes of liquid used to fracture the well formation, results in a large
28 emission of natural gas. The Inventory tracks activity data for unconventional well counts (which were assumed to
29 be completed by hydraulic fracture for the purposes of this analysis) in each region. This activity data was used
30 along with a newly developed emission factor to estimate emissions from these sources.
31 The same E&P Tank simulation data for hydrocarbon liquids above 45 "API flashing emission in tanks was used as
32 in previous Inventories to estimate emissions from condensate tanks; however, these flashing emissions simulations
33 were coupled with a large sample of condensate production gravities from the HPDI database to improve the factor
34 to account for the average national distribution of condensate gravities. Previously, a simple average of simulation
35 results for each liquid gravity was used. Additionally, the TERC (2009) study provided a small sample of data
36 representing two regions in Texas where separator dump valve malfunctions were detected and measured. This data
37 was applied only to the regions represented by the study to account for this emission source.
38 Finally, WGC (2009) sample data on centrifugal compressor seal oil degassing vent rates was used to divide the
39 centrifugal compressors source in the processing and transmission and storage segments into two sources—
40 centrifugal compressors equipped with wet seals and centrifugal compressors equipped with dry seals. The seal oil
41 degassing vent (found with compressors using wet seals) was previously unaccounted for in the Inventory. This
42 improved methodology accounted for an increase in emissions from these sources between 50 and 100 percent.
43 Finally, the previous Inventory activity data is updated with revised values each year. However, the impact of these
44 changes was small compared to the changes described above.
45 The net effect of these changes was to increase total CH4 emissions from natural gas systems between 47 and 120
46 percent each year between 1990 and 2008 relative to the previous report. The natural gas production segment
47 accounted for the largest increases, largely due to the methodological changes to gas well cleanups and the addition
48 of unconventional gas well completions and workovers.
Energy 3-47
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i Planned Improvements
2 Emission reductions reported to Natural Gas STAR are deducted from the total sector emissions each year in the
3 natural gas systems inventory model to estimate emissions. These reported reductions often rely on Inventory
4 emission factors to quantify the extent of reductions. Since these emission factors have been revised throughout the
5 time series, many of these reductions may be under reported. These reductions are also a source of uncertainty that
6 is not currently analyzed in the Inventory. In the next Inventory cycle, the potential for emissions reductions—in
7 particular from gas well cleanups—to be underestimated and make appropriate revisions to more accurately account
8 for emissions from natural gas systems will be investigated. Additionally, accounting for the uncertainty of these
9 reductions to more accurately provide upper and lower bounds within the 95 percent confidence interval will be
10 investigated.
11 Separately, a larger study is currently underway to update selected emission factors used in the national inventory.
12 Most of the activity factors and emission factors in the natural gas model are from the EPA/GRI (1996) study. The
13 current study seeks to review selected emission factors in the natural gas industry, and as appropriate, conduct
14 measurement-based studies to develop updated emission factors to better reflect current national circumstances.
15 Results from these studies are expected in the next few years, and will be incorporated into the Inventory, pending a
16 peer review.
17 Malfunctioning separator dump valves is not an occurrence isolated to the Texas counties in which the sample data
18 was obtained. New data will be reviewed as it becomes available on this emissions source and emissions will be
19 updated appropriately as this data becomes available.
20 Data collected through 40 CFR Part 98 (Mandatory Reporting of Greenhouse Gases; Final Rule) for potential
21 improvements to natural gas systems emissions sources will be reviewed. The rule will collect actual activity data
22 and improved quantification methods from those used in several of the studies which form the basis of this
23 Inventory. This data will be infused as appropriate with the current Inventory to improve the accuracy and
24 uncertainty of the emissions estimates.
25 Beginning in 2010, all U.S. natural gas suppliers will be required to calculate and report their greenhouse gas
26 emissions to EPA through its Greenhouse Gas Reporting Program. Data collected under this program will be used in
27 future inventories to improve the calculation of national emissions from natural gas systems.
28
29
30 3.7. Petroleum Systems (IPCC Source Category 1B2a)
31 CH4 emissions from petroleum systems are primarily associated with crude oil production, transportation, and
32 refining operations. During each of these activities, CH4 emissions are released to the atmosphere as fugitive
33 emissions, vented emissions, emissions from operational upsets, and emissions from fuel combustion. Fugitive and
34 vented CO2 emissions from petroleum systems are primarily associated with crude oil production and refining
35 operations but are negligible in transportation operations. Combusted CO2 emissions from fuels are already
36 accounted for in the Fossil Fuels Combustion source category, and hence have not been taken into account in the
37 Petroleum Systems source category. Total CH4 and CO2 emissions from petroleum systems in 2009 were 30.9 Tg
38 CO2 Eq. (1,473 Gg CH4) and 0.5 Tg CO2 (463 Gg), respectively. Since 1990, CH4 emissions have declined by 13
39 percent, due to industry efforts to reduce emissions and a decline in domestic oil production (see Table 3-4land
40 Table 3-42). CO2 emissions have also declined by 17 percent since 1990 due to similar reasons (see Table 3-43 and
41 Table 3-44).
42 Production Field Operations. Production field operations account for about 98 percent of total CH4 emissions from
43 petroleum systems. Vented CH4 from field operations account for over 90 percent of the emissions from the
44 production sector, unburned CH4 combustion emissions account for 6.4 percent, fugitive emissions are 3.4 percent,
45 and process upset emissions are slightly under two-tenths of a percent. The most dominant sources of emissions, in
46 order of magnitude, are shallow water offshore oil platforms, natural-gas-powered high bleed pneumatic devices, oil
47 tanks, natural-gas powered low bleed pneumatic devices, gas engines, deep water offshore platforms, and chemical
48 injection pumps. These seven sources alone emit about 94 percent of the production field operations emissions.
49 Offshore platform emissions are a combination of fugitive, vented, and unburned fuel combustion emissions from all
50 equipment housed on oil platforms producing oil and associated gas. Emissions from high and low-bleed pneumatics
3-48 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 occur when pressurized gas that is used for control devices is bled to the atmosphere as they cycle open and closed
2 to modulate the system. Emissions from oil tanks occur when the CH4 entrained in crude oil under pressure
3 volatilizes once the crude oil is put into storage tanks at atmospheric pressure. Emissions from gas engines are due
4 to unburned CH4 that vents with the exhaust. Emissions from chemical injection pumps are due to the 25 percent
5 that use associated gas to drive pneumatic pumps. The remaining six percent of the emissions are distributed among
6 26 additional activities within the four categories: vented, fugitive, combustion and process upset emissions. For
7 more detailed, source-level data on CH4 emissions in production field operations, refer to Annex 3.5.
8 Vented CO2 associated with natural gas emissions from field operations account for 99 percent of the total CO2
9 emissions from this source category, while fugitive and process upsets together account for less than 1 percent of the
10 emissions. The most dominant sources of vented emissions are oil tanks, high bleed pneumatic devices, shallow
11 water offshore oil platforms, low bleed pneumatic devices, and chemical injection pumps. These five sources
12 together account for 98.5 percent of the non-combustion CO2 emissions from this source category, while the
13 remaining 1.5 percent of the emissions is distributed among 24 additional activities within the three categories:
14 vented, fugitive and process upsets.
15 Crude Oil Transportation. Crude oil transportation activities account for less than one half of one percent of total
16 CH4 emissions from the oil industry. Venting from tanks and marine vessel loading operations accounts for 61
17 percent of CH4 emissions from crude oil transportation. Fugitive emissions, almost entirely from floating roof tanks,
18 account for 19 percent. The remaining 20 percent is distributed among six additional sources within these two
19 categories. Emissions from pump engine drivers and heaters were not estimated due to lack of data.
20 Crude Oil Refining. Crude oil refining processes and systems account for slightly less than two percent of total CH4
21 emissions from the oil industry because most of the CH4 in crude oil is removed or escapes before the crude oil is
22 delivered to the refineries. There is an insignificant amount of CH4 in all refined products. Within refineries, vented
23 emissions account for about 86 percent of the emissions, while both fugitive and combustion emissions account for
24 approximately seven percent each. Refinery system blowdowns for maintenance and the process of asphalt
25 blowing—with air, to harden the asphalt—are the primary venting contributors. Most of the fugitive CH4 emissions
26 from refineries are from leaks in the fuel gas system. Refinery combustion emissions include small amounts of
27 unburned CH4 in process heater stack emissions and unburned CH4 in engine exhausts and flares.
28 Asphalt blowing from crude oil refining accounts for 36 percent of the total non-combustion CO2 emissions in
29 petroleum systems.
30 Table 3-41: CH4 Emissions from Petroleum Systems (Tg CO2 Eq.)
Activity 1990
Production Field Operations 34.7
Pneumatic device venting 10.3
Tank venting 5.3
Combustion & process upsets 1.9
Misc. venting & fugitives 16.8
Wellhead fugitives 0.6
Crude Oil Transportation 0.1
Refining 0.5
Total 35.4
31 Note: Totals may not sum due to independent rounding.
2000
30.8
9.0
4.5
1.6
15.3
0.5
0.1
0.6
31.5
2005
28.7
8.4
3.9
1.5
14.5
0.4
0.1
0.6
29.4
2006
28.7
8.3
3.9
1.5
14.6
0.4
0.1
0.6
29.4
2007
29.3
8.4
4.0
1.5
15.0
0.4
0.1
0.6
30.0
2008
29.6
8.7
4.0
1.6
14.8
0.5
0.1
0.5
30.2
2009
30.3
8.8
4.5
2.0
14.6
0.5
0.1
0.5
30.9
33 Table 3 -42: CH4 Emissions from Petroleum Systems (Gg)
Activity 1990
Production Field Operations 1,653
Pneumatic device venting 489
Tank venting 250
Combustion & process upsets 88
Misc. venting & fugitives 799
Wellhead fugitives 26
Crude Oil Transportation 7
Refining 25
Total 1,685
2000
1,468
428
214
76
727
22
5
28
1,501
2005
1,366
397
187
71
691
19
5
28
1,398
2006
1,365
396
188
71
693
17
5
28
1,398
2007
1,396
398
192
72
714
20
5
27
1,427
2008
1,409
416
189
75
707
23
5
25
1,439
2009
1,444
419
212
94
696
23
5
24
1,473
34 Note: Totals may not sum due to independent rounding.
Energy 3-49
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Table 3-43: CO2 Emissions from Petroleum Systems (Tg CO2 Eq.)
Activity
Production Field Operations
Pneumatic device venting
Tank venting
Misc. venting & fugitives
Wellhead fugitives
Crude Refining
Total
+ Does not exceed 0.05 Tg CO2 Eq.
Table 3 -44: CO2 Emissions from
Activity
Production Field Operations
Pneumatic device venting
Tank venting
Misc. venting & fugitives
Wellhead fugitives
Crude Refining
Total
1990
0.4
+
0.3
+
+
0.2
0.6
Petroleum
1990
376
27
328
18
1
180
555
2000
0.3
+
0.3
+
+
0.2
0.5
Systems (Gg)
2000
323
24
281
17
1
211
534
2005
0.3
+
0.3
+
+
0.2
0.5
2005
285
22
246
16
1
205
490
2006
0.3
+
0.3
+
+
0.2
0.5
2006
285
22
246
16
1
203
488
2007
0.3
+
0.3
+
+
0.2
0.5
2007
292
22
252
16
1
182
474
2008
0.3
+
0.3
+
+
0.2
0.5
2008
288
23
247
16
1
165
453
2009
0.3
+
0.3
+
+
0.1
0.5
2009
319
23
278
16
1
144
463
Note: Totals may not sum due to independent rounding.
7 Methodology
8 The methodology for estimating CH4 emissions from petroleum systems is a bottom-up approach, based on
9 comprehensive studies of CH4 emissions from U.S. petroleum systems (EPA 1996, EPA 1999). These studies
10 combined emission estimates from 64 activities occurring in petroleum systems from the oil wellhead through crude
11 oil refining, including 33 activities for crude oil production field operations, 11 for crude oil transportation activities,
12 and 20 for refining operations. Annex 3.5 provides greater detail on the emission estimates for these 64 activities.
13 The estimates of CH4 emissions from petroleum systems do not include emissions downstream of oil refineries
14 because these emissions are negligible.
15 The methodology for estimating CH4 emissions from the 64 oil industry activities employs emission factors initially
16 developed by EPA (1999). Activity factors for the years 1990 through 2009 were collected from a wide variety of
17 statistical resources. Emissions are estimated for each activity by multiplying emission factors (e.g., emission rate
18 per equipment item or per activity) by their corresponding activity factor (e.g., equipment count or frequency of
19 activity). EPA (1999) provides emission factors for all activities except those related to offshore oil production and
20 field storage tanks. For offshore oil production, two emission factors were calculated using data collected over a
21 one-year period for all federal offshore platforms (EPA 2005, BOEMRE 2004). One emission factor is for oil
22 platforms in shallow water, and one emission factor is for oil platforms in deep water. Emission factors are held
23 constant for the period 1990 through 2009. The number of platforms in shallow water and the number of platforms
24 in deep water are used as activity factors and are taken from Bureau of Ocen Energy Management, Regulation, and
25 Enforcement (BOEMRE) (formerly Minerals Management Service) statistics (BOEMRE 2010a-c). For oil storage
26 tanks, the emissions factor was calculated as the total emissions per barrel of crude charge from E&P Tank data
27 weighted by the distribution of produced crude oil gravities from the HPDI production database (EPA 1999, HPDI
28 2009).
29 For some years, complete activity factor data were not available. In such cases, one of three approaches was
30 employed. Where appropriate, the activity factor was calculated from related statistics using ratios developed for
31 EPA (1996). For example, EPA (1996) found that the number of heater treaters (a source of CH4 emissions) is
32 related to both number of producing wells and annual production. To estimate the activity factor for heater treaters,
33 reported statistics for wells and production were used, along with the ratios developed for EPA (1996). In other
34 cases, the activity factor was held constant from 1990 through 2009 based on EPA (1999). Lastly, the previous
35 year's data were used when data for the current year were unavailable. The CH4 and CO2 sources in the production
36 sector share common activity factors. See Annex 3.5 for additional detail.
3-50 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Among the more important references used to obtain activity factors are the Energy Information Administration
2 annual and monthly reports (EIA 1990 through 2010, 1995 through 2010, 1995 through 2010a-b), Methane
3 Emissions from the Natural Gas Industry by the Gas Research Institute and EPA (EPA/GRI 1996a-d), Estimates of
4 Methane Emissions from the U.S. Oil Industry (EPA 1999), consensus of industry peer review panels, BOEMRE
5 reports (BOEMRE 2005, 2010a-c), analysis of BOEMRE data (EPA 2005, BOEMRE 2004), the Oil & Gas Journal
6 (OGJ 2010a,b), the Interstate Oil and Gas Compact Commission (IOGCC 2008), and the United States Army Corps
7 of Engineers (1995-2008).
8 The methodology for estimating CO2 emissions from petroleum systems combines vented, fugitive, and process
9 upset emissions sources from 29 activities for crude oil production field operations and one activity from petroleum
10 refining. Emissions are estimated for each activity by multiplying emission factors by their corresponding activity
11 factors. The emission factors for CO2 are estimated by multiplying the CH4 emission factors by a conversion factor,
12 which is the ratio of CO2 content and methane content in produced associated gas. The only exceptions to this
13 methodology are the emission factors for crude oil storage tanks, which are obtained from E&P Tank simulation
14 runs, and the emission factor for asphalt blowing, which was derived using the methodology and sample data from
15 API (2004).
16 Uncertainty and Time-Series Consistency
17 This section describes the analysis conducted to quantify uncertainty associated with the estimates of emissions from
18 petroleum systems. Performed using @RISK software and the IPCC-recommended Tier 2 methodology (Monte
19 Carlo Simulation technique), the method employed provides for the specification of probability density functions for
20 key variables within a computational structure that mirrors the calculation of the Inventory estimate. The results
21 provide the range within which, with 95 percent certainty, emissions from this source category are likely to fall.
22 The detailed, bottom-up Inventory analysis used to evaluate U.S. petroleum systems reduces the uncertainty related
23 to the CH4 emission estimates in comparison to a top-down approach. However, some uncertainty still remains.
24 Emission factors and activity factors are based on a combination of measurements, equipment design data,
25 engineering calculations and studies, surveys of selected facilities and statistical reporting. Statistical uncertainties
26 arise from natural variation in measurements, equipment types, operational variability and survey and statistical
27 methodologies. Published activity factors are not available every year for all 64 activities analyzed for petroleum
28 systems; therefore, some are estimated. Because of the dominance of the seven major sources, which account for 92
29 percent of the total methane emissions, the uncertainty surrounding these seven sources has been estimated most
30 rigorously, and serves as the basis for determining the overall uncertainty of petroleum systems emission estimates.
31 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 3-45. Petroleum systems CH4
32 emissions in 2009 were estimated to be between 23.5 and 76.9 Tg CO2 Eq., while CO2 emissions were estimated to
33 be between 0.4 and 1.2 Tg CO2Eq. at a 95 percent confidence level. This indicates a range of 24 percent below to
34 149 percent above the 2009 emission estimates of 30.9 and 0.5 Tg CO2 Eq. for CH4 and CO2, respectively.
35 Table 3-45: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Petroleum Systems (Tg CO2 Eq. and
36 Percent)
2009 Emission Uncertainty Range Relative to Emission Estimate"
Estimate
Source Gas (Tg CO2 Eq.)b (Tg CO2 Eq.) (%)
Lower Upper Lower Upper
Boundb Boundb Boundb Boundb
Petroleum Systems CH4 30.9 23.5 76.9 -24% 149%
Petroleum Systems CO2 0.5 0.4 L2 -24% 149%
37 a Range of 2009 relative uncertainty predicted by Monte Carlo Simulation, based on 1995 base year activity factors, for a 95
38 percent confidence interval.
39 b All reported values are rounded after calculation. As a result, lower and upper bounds may not be duplicable from other
40 rounded values as shown in table.
41 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
42 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
43 above.
Energy 3-51
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i QA/QC and Verification Discussion
2 Potential Inventory improvements include a new emissions source associated with fixed roof storage tank emissions
3 in the production segment. EPA has learned that in some production areas the separator liquid level may drop too
4 low such that the produced associated gas blows through the dump valve and vents through the storage tank. This
5 data was included where available for the Inventory (see Recalculation discussion below). More data will be
6 necessary to potentially add this as a separator source from storage tank flashing emissions and also to represent the
7 true scope of activity across the United States.
8 Recalculations Discussion
9 Most revisions for the current Inventory relative to the previous report were due to updating previous years' data
10 with revised data from existing data sources. Well completion venting, well drilling, and offshore platform activity
11 factors were updated from existing data sources from 1990 onward.
12 Additionally, the emission factor for venting from fixed roof storage tanks in the crude oil production segment was
13 revised. Using the same E&P Tank sample data runs on crude oil gravities ranging up to 45°API, a new national
14 level flashing emissions factor was developed by using a large sample of production data, sorted by gravity,
15 available from the HPDI database.
16 A study prepared for the Texas Environmental Research Consortium measured emissions rates from several oil and
17 condensate tanks in Texas (TERC 2009). This data was plotted and compared to the flashing emissions simulated
18 via E&P Tank simulation. EPA observed that additional emissions beyond the flashing were present in
19 approximately SOpercent of the tanks. These emissions may be attributed to separator dump valves malfunctioning
20 or other methods of associated gas entering the tank and venting from the roof. Because the dataset was limited to
21 represent production from only 14 counties that represent 0.5 percent of U.S. production, the national emission
22 factor was scaled up such that only production from these counties is affected by the occurrence of associated gas
23 venting through the storage tank.
24 Planned Improvements
25 As noted above, nearly all emission factors used in the development of the petroleum systems estimates were taken
26 from EPA (1995, 1996, 1999), with the remaining emission factors taken from EPA default values (EPA 2005) and
27 a consensus of industry peer review panels. These emission factors will be reviewed as part of future Inventory
28 work. Results of this review and analysis will be incorporated into future inventories, as appropriate.
29 EPA is aware that malfunctioning separator dump valves is not an occurrence isolated to the Texas counties in
30 which the sample data was obtained. It will continue to review new data as they become available on this emissions
31 source and update emissions appropriately.
32 Data collected through 40 CFR Part 98 (Mandatory Reporting of Greenhouse Gases; Final Rule) will be reviewed
33 for potential improvements to petroleum systems emissions sources. The rule will collect actual activity data and
34 improved quantification methods from those used in several of the studies which form the basis of this Inventory.
35 This data will be infused as appropriate with the current Inventory to improve the accuracy and uncertainty of the
36 emissions estimates.
37 Beginning in 2010, all U.S. petroleum refineries will be required to calculate and report their greenhouse gas
38 emissions to EPA through its Greenhouse Gas Reporting Program. Data collected under this program will be used in
39 future inventories to improve the calculation of national emissions from petroleum systems.
40
41 [BEGIN BOX]
42
43 Box 3-3. Carbon Dioxide Transport, Injection, and Geological Storage
44
45 Carbon dioxide is produced, captured, transported, and used for Enhanced Oil Recovery (EOR) as well as
46 commercial and non-EOR industrial applications. This CO2 is produced from both naturally-occurring CO2
3-52 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 reservoirs and from industrial sources such as natural gas processing plants and ammonia plants. In the current
2 Inventory, emissions from naturally-produced CO2 are estimated based on the application.
3 In the current Inventory report, the CO2 that is used in non-EOR industrial and commercial applications (e.g., food
4 processing, chemical production) is assumed to be emitted to the atmosphere during its industrial use. These
5 emissions are discussed in the Carbon Dioxide Consumption section. The naturally-occurring CO2 used in EOR
6 operations is assumed to be fully sequestered. Additionally, all anthropogenic CO2 emitted from natural gas
7 processing and ammonia plants is assumed to be emitted to the atmosphere, regardless of whether the CO2 is
8 captured or not. These emissions are currently included in the Natural Gas Systems and the Ammonia Production
9 sections of the Inventory report, respectively.
10 IPCC (IPCC, 2006) included, for the first time, methodological guidance to estimate emissions from the capture,
11 transport, injection, and geological storage of CO2. The methodology is based on the principle that the carbon
12 capture and storage system should be handled in a complete and consistent manner across the entire Energy sector.
13 The approach accounts for CO2 captured at natural and industrial sites as well as emissions from capture, transport,
14 and use. For storage specifically, a Tier 3 methodology is outlined for estimating and reporting emissions based on
15 site-specific evaluations. However, IPCC (IPCC, 2006) notes that if a national regulatory process exists, emissions
16 information available through that process may support development of CO2 emissions estimates for geologic
17 storage.
18 EPA recently established such a regulatory process as part of the GHG Reporting Program. On November 22, 2010,
19 EPA issued a final rule that requires facilities that conduct geologic sequestration of CO2 and all other facilities that
20 inject CO2 underground to report GHG data to EPA annually. Subpart RR of the Greenhouse Gas Reporting Rule
21 requires GHG reporting from facilities that inject CO2underground for geologic sequestration, and subpart UU
22 requires GHG reporting from all other facilities that inject CO2 underground for any reason, including enhanced oil
23 and gas recovery. Beginning in 2011, facilities conducting geologic sequestration of CO2 are required to develop
24 and implement an EPA-approved site-specific monitoring, reporting and verification (MRV) plan, and to report the
25 amount of CO2 sequestered using a mass balance approach. Data from this program, which will be reported to EPA
26 in early 2012, for the 2011 calendar year, will provide additional facility-specific information about the carbon
27 capture, transport and storage chain, EPA intends to evaluate that information closely and consider opportunities for
28 improving our current inventory estimates.
29
30 Preliminary estimates indicate that the amount of CO2 captured from industrial and natural sites is 47.3 Tg CO2
31 (47,340 Gg CO2) (see Table 3-46 and Table 3-47). Site-specific monitoring and reporting data for CO2 injection
32 sites (i.e., EOR operations) were not readily available, therefore, these estimates assume all CO2 is emitted.
33 Table 3-46: Potential Emissions from CO2 Capture and Transport (Tg CO2 Eq.)
34
35
36
37
38
39
40
Year
Acid Gas Removal Plants
Naturally Occurring CO2
Ammonia Production Plants
Pipelines Transporting CO2
Total
+ Does not exceed 0.05 Tg CO2
1990
4.8
20.8
+
25.6
Eq.
Table 3-47: Potential Emissions from CO2
Year
Acid Gas Removal Plants
Naturally Occurring CO2
Ammonia Production Plants
Pipelines Transporting CO2
Total
1990
4,832
20,811
8
25,643
2000
2.3
23.2
0.7
+
26.1
2005
5.8
28.3
0.7
+
34.7
2006
6.2
30.2
0.7
+
37.1
2007
6.4
33.1
0.7
+
40.1
2008 2009
6.6 7.0
36.1 39.7
0.6 0.6
+ +
43.3 47.3
Capture and Transport (Gg)
2000
2,264
23,208
676
8
26,149
2005
5,798
28,267
676
7
34,742
2006
6,224
30,224
676
7
37,124
2007
6,088
33,086
676
7
40,141
2008
6,726
36,096
580
8
43,311
2009
7,035
39,725
580
8
47,340
+ Does not exceed 0.5 Ge.
[END BOX]
Energy 3-53
-------
3.8. Energy Sources of Indirect Greenhouse Gas Emissions - TO BE UPDATED
2
3
4
5
6
7
In addition to the main greenhouse gases addressed above, many energy-related activities generate emissions of
indirect greenhouse gases. Total
organic compounds (NMVOCs)
emissions of nitroj
;en oxides
from energy -related activities
(NOX),
carbon monoxide (CO),
from 1990 to 2008 are
Table 3-48: NOX, CO, and NMVOC Emissions from Energy-Related
Gas/Source
NOX
Mobile Combustion
Stationary Combustion
Oil and Gas Activities
Incineration of Waste
International Bunker Fuels*
CO
Mobile Combustion
Stationary Combustion
Incineration of Waste
Oil and Gas Activities
International Bunker Fuels*
NMVOCs
Mobile Combustion
Stationary Combustion
Oil and Gas Activities
Incineration of Waste
International Bunker Fuels*
1990
21,106
10,862
10,023
139
82
2,020
125,640
119,360
5,000
978
302
130
12,620
10,932
912
554
222
61
* These values are presented for informational
1995
20
10
9
,586
,536
,862
100
88
1,566
104
97
5
1
10
8
,402
,630
,383
,073
316
124
,538
,745
973
582
237
50 •
2000
18,477
10,199
8,053
111
114
1,344
89,714
83,559
4,340
1,670
146
128
8,952
7,229
1,077
388
257
45
Activities
(Gg)
2005
15,319
9,
5,
;,
012
858
321
129
705
69,062
62,
4,
1,
692
649
403
318
133
7,798
6,
330
716
510
241
54
reported
2006
14,473
8,488
5,545
319
121
1,796
65,399
58,972
4,695
1,412
319
162
7,702
6,037
918
510
238
59
and non-CH4
volatile
in Table 3-48.
2007
13,829
7
5
;
61
55
4
1
,965
,432
318
114
,789
,739
,253
,744
,421
320
159
7,604
5
1
,742
,120
509
234
58
2008
13,012
7,441
5,148
318
106
1,923
58,078
51,533
4,792
1,430
322
167
7,507
5,447
1,321
509
230
62
purposes only and are not included in totals.
Note: Totals may not sum due to independent rounding.
9 Methodology
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
These emission estimates were obtained from preliminary data (EPA 2009), and disaggregated based on EPA
(2003), which, in its final iteration, will be published on the National Emission Inventory (NEI) Air Pollutant
Emission Trends web site. Emissions were calculated either for individual categories or for many categories
combined, using basic activity data (e.g., the amount of raw material processed) as an indicator of emissions.
National activity data were collected for individual categories from various agencies. Depending on the category,
these basic activity data may include data on production, fuel deliveries, raw material processed, etc.
Activity data were used in conjunction with emission factors, which together relate the quantity of emissions to the
activity. Emission factors are generally available from the EPA's Compilation of Air Pollutant Emission Factors,
AP-42 (EPA 1997). The EPA currently derives the overall emission control efficiency of a source category from a
variety of information sources, including published reports, the 1985 National Acid Precipitation and Assessment
Program emissions inventory, and other EPA databases.
Uncertainty and Time-Series Consistency
Uncertainties in these estimates are partly due to the accuracy of the emission factors used and accurate estimates of
activity data. A quantitative uncertainty analysis was not performed.
Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2008. Details on the emission trends through time are described in more detail in the Methodology section,
above.
3.9. International Bunker Fuels (IPCC Source Category 1: Memo Items)
Emissions resulting from the combustion of fuels used for international transport activities, termed international
3-54 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 bunker fuels under the UNFCCC, are not included in national emission totals, but are reported separately based upon
2 location of fuel sales. The decision to report emissions from international bunker fuels separately, instead of
3 allocating them to a particular country, was made by the Intergovernmental Negotiating Committee in establishing
4 the Framework Convention on Climate Change.94 These decisions are reflected in the IPCC methodological
5 guidance, including the 2006 IPCC Guidelines, in which countries are requested to report emissions from ships or
6 aircraft that depart from their ports with fuel purchased within national boundaries and are engaged in international
7 transport separately from national totals (IPCC 2006).95
8 Greenhouse gases emitted from the combustion of international bunker fuels, like other fossil fuels, include CO2,
9 CH4 and N2O. Two transport modes are addressed under the IPCC definition of international bunker fuels: aviation
10 and marine.96 Emissions from ground transport activities—by road vehicles and trains—even when crossing
11 international borders are allocated to the country where the fuel was loaded into the vehicle and, therefore, are not
12 counted as bunker fuel emissions.
13 The IPCC Guidelines distinguish between different modes of air traffic. Civil aviation comprises aircraft used for
14 the commercial transport of passengers and freight, military aviation comprises aircraft under the control of national
15 armed forces, and general aviation applies to recreational and small corporate aircraft. The IPCC Guidelines further
16 define international bunker fuel use from civil aviation as the fuel combusted for civil (e.g., commercial) aviation
17 purposes by aircraft arriving or departing on international flight segments. However, as mentioned above, and in
18 keeping with the IPCC Guidelines, only the fuel purchased in the United States and used by aircraft taking-off (i.e.,
19 departing) from the United States are reported here. The standard fuel used for civil aviation is kerosene-type jet
20 fuel, while the typical fuel used for general aviation is aviation gasoline.97
21 Emissions of CO2 from aircraft are essentially a function of fuel use. CH4 and N2O emissions also depend upon
22 engine characteristics, flight conditions, and flight phase (i.e., take-off, climb, cruise, decent, and landing). CH4 is
23 the product of incomplete combustion and occur mainly during the landing and take-off phases. In jet engines, N2O
24 is primarily produced by the oxidation of atmospheric nitrogen, and the majority of emissions occur during the
25 cruise phase. International marine bunkers comprise emissions from fuels burned by ocean-going ships of all flags
26 that are engaged in international transport. Ocean-going ships are generally classified as cargo and passenger
27 carrying, military (i.e., U.S. Navy), fishing, and miscellaneous support ships (e.g., tugboats). For the purpose of
28 estimating greenhouse gas emissions, international bunker fuels are solely related to cargo and passenger carrying
29 vessels, which is the largest of the four categories, and military vessels. Two main types of fuels are used on sea-
30 going vessels: distillate diesel fuel and residual fuel oil. CO2 is the primary greenhouse gas emitted from marine
31 shipping.
32 Overall, aggregate greenhouse gas emissions in 2009 from the combustion of international bunker fuels from both
33 aviation and marine activities were 124.4 Tg CO2 Eq., or ten percent above emissions in 1990 (see Table 3-49 and
34 Table 3-50). Emissions from international flights and international shipping voyages departing from the United
35 States have increased by 49 percent and decreased by 18 percent, respectively, since 1990. The majority of these
36 emissions were in the form of CO2; however, small amounts of CH4 and N2O were also emitted.
37 Table 3-49: CO2, CH4, and N2O Emissions from International Bunker Fuels (Tg CO2 Eq.)
Gas/Mode 1990 2000 2005 2006 2007 2008 2009
C02
Aviation
Marine
CH4
Aviation
111.8
46.4
65.4
0.2
+
98.5
58.8
39.7
0.1
+
109.7
56.7
53.0
0.1
+
128.4
74.6
53.8
0.2
+
127.6
73.8
53.9
0.2
+
133.7
75.5
58.2
0.2
+
123.1
69.4
53.7
0.1
+
94 See report of the Intergovernmental Negotiating Committee for a Framework Convention on Climate Change on the work of
its ninth session, held at Geneva from 7 to 18 February 1994 (A/AC.237/55, annex I, para. Ic).
95 Note that the definition of international bunker fuels used by the UNFCCC differs from that used by the International Civil
Aviation Organization.
96 Most emission related international aviation and marine regulations are under the rubric of the International Civil Aviation
Organization (ICAO) or the International Maritime Organization (IMO), which develop international codes, recommendations,
and conventions, such as the International Convention of the Prevention of Pollution from Ships (MARPOL).
97 Naphtha-type jet fuel was used in the past by the military in turbojet and turboprop aircraft engines.
Energy 3-55
-------
Marine 0.1 0.1
N2O 1.1 0.9
Aviation 0.5 0.6
Marine 0.5 0.3
0.1
1.0
0.6
0.4
Total 113.0 99.5 110.9
1
2
+ Does not exceed 0.05 Tg CO2 Eq.
Note: Totals may not sum due to independent rounding.
0.1
1.2
0.8
0.4
129.7
0.1
1.2
0.8
0.4
129.0
0.1
1.2
0.8
0.5
135.1
0.1
1.1
0.7
0.4
124.4
Includes aircraft cruise altitude emissions.
Table 3-50: CO2, CH4 and N2O Emissions from International Bunker Fuels (Gg)
5
6
Gas/Mode
CO2
Aviation
Marine
CH4
Aviation
Marine
N2O
Aviation
Marine
1990
111,828
46,399
65,429
8
2
7
3
2
2
2000
98,482
58,785
39,697
6
2
4
3
2
1
2005
109,750
56,736
53,014
7
2
5
3
2
1
2006
128,384
74,552
53,832
8
2
5
4
2
1
2007
127,618
73,762
53,856
8
2
5
4
2
1
2008
133,704
75,508
58,196
8
2
6
4
2
1
2009
123,127
69,404
53,723
7
2
5
4
2
1
Note: Totals may not sum due to independent rounding. Includes aircraft cruise altitude emissions.
7 Methodology
8 Emissions of CO2 were estimated by applying C content and fraction oxidized factors to fuel consumption activity
9 data. This approach is analogous to that described under CO2 from Fossil Fuel Combustion. C content and fraction
10 oxidized factors for jet fuel, distillate fuel oil, and residual fuel oil were taken directly from EIA and are presented in
11 Annex 2.1, Annex 2.2, and Annex 3.7 of this Inventory. Density conversions were taken from Chevron (2000),
12 ASTM (1989), and USAF (1998). Heat content for distillate fuel oil and residual fuel oil were taken from EIA
13 (2010) and USAF (1998), and heat content for jet fuel was taken from EIA (2010). A complete description of the
14 methodology and a listing of the various factors employed can be found in Annex 2.1. See Annex 3.7 for a specific
15 discussion on the methodology used for estimating emissions from international bunker fuel use by the U.S.
16 military.
17 Emission estimates for CH4 and N2O were calculated by multiplying emission factors by measures of fuel
18 consumption by fuel type and mode. Emission factors used in the calculations of CH4 and N2O emissions were
19 obtained from the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). For aircraft emissions, the
20 following values, in units of grams of pollutant per kilogram of fuel consumed (g/kg), were employed: 0.09 for CH4
21 and 0.1 for N2O For marine vessels consuming either distillate diesel or residual fuel oil the following values
22 (g/MJ), were employed: 0.32 for CH4 and 0.08 for N2O. Activity data for aviation included solely jet fuel
23 consumption statistics, while the marine mode included both distillate diesel and residual fuel oil.
24 Activity data on aircraft fuel consumption for inventory years 2000 through 2005 were developed using the FAA's
25 System for assessing Aviation's Global Emissions (SAGE) model (FAA 2006). That tool has been subsequently
26 replaced by the Aviation Environmental Design Tool (AEDT), which calculates noise in addition to aircraft fuel
27 burn and emissions for flights globally in a given year (FAA 2010). Data for inventory years 2006 through 2009
28 were developed using AEDT.
29 International aviation bunker fuel consumption from 1990 to 2009 was calculated by assigning the difference
30 between the sum of domestic activity data (in Tbtu) from SAGE and the AEDT, and the reported EIA transportation
31 jet fuel consumption to the international bunker fuel category for jet fuel from EIA (2010). Data on U.S. Department
32 of Defense (DoD) aviation bunker fuels and total jet fuel consumed by the U.S. military was supplied by the Office
33 of the Under Secretary of Defense (Installations and Environment), DoD. Estimates of the percentage of each
34 Service's total operations that were international operations were developed by DoD. Military aviation bunkers
35 included international operations, operations conducted from naval vessels at sea, and operations conducted from
36 U.S. installations principally over international water in direct support of military operations at sea. Military
37 aviation bunker fuel emissions were estimated using military fuel and operations data synthesized from unpublished
3-56 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 data by the Defense Energy Support Center, under DoD's Defense Logistics Agency (DESC 2011). Together, the
2 data allow the quantity of fuel used in military international operations to be estimated. Densities for each jet fuel
3 type were obtained from a report from the U.S. Air Force (USAF 1998). Final jet fuel consumption estimates are
4 presented in Table 3-51. See Annex 3.7 for additional discussion of military data.
5 Activity data on distillate diesel and residual fuel oil consumption by cargo or passenger carrying marine vessels
6 departing from U.S. ports were taken from unpublished data collected by the Foreign Trade Division of the U. S.
7 Department of Commerce's Bureau of the Census (DOC 1991 through 2010) for 1990 through 2001, 2007, through
8 2009, and the Department of Homeland Security's Bunker Report for 2003 through 2006 (DHS 2008). Fuel
9 consumption data for 2002 was interpolated due to inconsistencies in reported fuel consumption data. Activity data
10 on distillate diesel consumption by military vessels departing from U.S. ports were provided by DESC (2011). The
11 total amount of fuel provided to naval vessels was reduced by 13 percent to account for fuel used while the vessels
12 were not-underway (i.e., in port). Data on the percentage of steaming hours underway versus not-underway were
13 provided by the U.S. Navy. These fuel consumption estimates are presented in. Table 3-52.
14 Table 3-51: Aviation Jet Fuel Consumption for International Transport (Million Gallons)
15
16
17
Nationality 1990
U.S. and Foreign Carriers 4,934
U.S. Military 862
Total 5,796
2000
6,157
480
6,638
2005
5,943
462
6,405
2006
7,809
400
8,209
2007
7,726
410
8,137
2008
7,909
386
8,295
2009
7,270
368
7,638
Note: Totals may not sum due to independent rounding.
Table 3-52: Marine Fuel Consumption for International
Fuel Type 1990
Residual Fuel Oil 4,781
Distillate Diesel Fuel & Other 617
U.S. Military Naval Fuels 522
Total 5,920
2000
2,967
290
329
3,586
Transport
2005
3,881
444
471
4,796
(Million
2006
4,004
446
414
4,864
Gallons)
2007
4,059
358
444
4,861
2008
4,373
445
437
5,254
2009
4,040
426
384
4,850
18 Note: Totals may not sum due to independent rounding.
19
20 Uncertainty and Time-Series Consistency
21 Emission estimates related to the consumption of international bunker fuels are subject to the same uncertainties as
22 those from domestic aviation and marine mobile combustion emissions; however, additional uncertainties result
23 from the difficulty in collecting accurate fuel consumption activity data for international transport activities separate
24 from domestic transport activities.98 For example, smaller aircraft on shorter routes often carry sufficient fuel to
25 complete several flight segments without refueling in order to minimize time spent at the airport gate or take
26 advantage of lower fuel prices at particular airports. This practice, called tankering, when done on international
27 flights, complicates the use of fuel sales data for estimating bunker fuel emissions. Tankering is less common with
28 the type of large, long-range aircraft that make many international flights from the United States, however. Similar
29 practices occur in the marine shipping industry where fuel costs represent a significant portion of overall operating
30 costs and fuel prices vary from port to port, leading to some tankering from ports with low fuel costs.
31 Uncertainties exist with regard to the total fuel used by military aircraft and ships, and in the activity data on military
32 operations and training that were used to estimate percentages of total fuel use reported as bunker fuel emissions.
33 Total aircraft and ship fuel use estimates were developed from DoD records, which document fuel sold to the Navy
34 and Air Force from the Defense Logistics Agency. These data may slightly over or under estimate actual total fuel
35 use in aircraft and ships because each Service may have procured fuel from, and/or may have sold to, traded with,
36 and/or given fuel to other ships, aircraft, governments, or other entities. There are uncertainties in aircraft operations
37 and training activity data. Estimates for the quantity of fuel actually used in Navy and Air Force flying activities
38 reported as bunker fuel emissions had to be estimated based on a combination of available data and expert judgment.
39 Estimates of marine bunker fuel emissions were based on Navy vessel steaming hour data, which reports fuel used
40 while underway and fuel used while not underway. This approach does not capture some voyages that would be
98
See uncertainty discussions under Carbon Dioxide Emissions from Fossil Fuel Combustion.
Energy 3-57
-------
1 classified as domestic for a commercial vessel. Conversely, emissions from fuel used while not underway preceding
2 an international voyage are reported as domestic rather than international as would be done for a commercial vessel.
3 There is uncertainty associated with ground fuel estimates for 1997 through 2001. Small fuel quantities may have
4 been used in vehicles or equipment other than that which was assumed for each fuel type.
5 There are also uncertainties in fuel end-uses by fuel-type, emissions factors, fuel densities, diesel fuel sulfur content,
6 aircraft and vessel engine characteristics and fuel efficiencies, and the methodology used to back-calculate the data
7 set to 1990 using the original set from 1995. The data were adjusted for trends in fuel use based on a closely
8 correlating, but not matching, data set. All assumptions used to develop the estimate were based on process
9 knowledge, Department and military Service data, and expert judgments. The magnitude of the potential errors
10 related to the various uncertainties has not been calculated, but is believed to be small. The uncertainties associated
11 with future military bunker fuel emission estimates could be reduced through additional data collection.
12 Although aggregate fuel consumption data have been used to estimate emissions from aviation, the recommended
13 method for estimating emissions of gases other than CO2 in the Revised 1996 IPCC Guidelines is to use data by
14 specific aircraft type (IPCC/UNEP/OECD/IEA 1997). The IPCC also recommends that cruise altitude emissions be
15 estimated separately using fuel consumption data, while landing and take-off (LTO) cycle data be used to estimate
16 near-ground level emissions of gases other than CO2."
17 There is also concern as to the reliability of the existing DOC (1991 through 2010) data on marine vessel fuel
18 consumption reported at U.S. customs stations due to the significant degree of inter-annual variation.
19 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
20 through 2008. Details on the emission trends through time are described in more detail in the Methodology section,
21 above.
22 QA/QC and Verification
23 A source-specific QA/QC plan for international bunker fuels was developed and implemented. This effort included
24 a Tier 1 analysis, as well as portions of a Tier 2 analysis. The Tier 2 procedures that were implemented involved
25 checks specifically focusing on the activity data and emission factor sources and methodology used for estimating
26 CO2, CH4, and N2O from international bunker fuels in the United States. Emission totals for the different sectors
27 and fuels were compared and trends were investigated. No corrective actions were necessary.
28 Recalculations Discussion
29 Slight changes to emission estimates are due to revisions made to historical activity data for aviation jet fuel
30 consumption using the FAA's AEDT. These historical data changes resulted in changes to the emission estimates for
31 1990 through 2008 relative to the previous Inventory, which averaged to an annual decrease in emissions from
32 international bunker fuels of 0.13 Tg CO2Eq. (0.1 percent) in CO2 emissions, an annual decrease of less than 0.01
33 Tg CO2 Eq. (0.05 percent) in CH4 emissions, and an annual decrease of less than 0.01 Tg CO2 Eq. (0.1 percent) in
34 N2O emissions.
35 3.10. Wood Biomass and Ethanol Consumption (IPCC Source Category 1A)
36 The combustion of biomass fuels such as wood, charcoal, and wood waste and biomass-based fuels such as ethanol
37 from corn and woody crops generates CO2 in addition to CH4 and N2O already covered in this chapter. In line with
38 the reporting requirements for inventories submitted under the UNFCCC, CO2 emissions from biomass combustion
39 have been estimated separately from fossil fuel CO2 emissions and are not directly included in the energy sector
99 U.S. aviation emission estimates for CO, NOX, and NMVOCs are reported by EPA's National Emission Inventory (NET) Air
Pollutant Emission Trends web site, and reported under the Mobile Combustion section. It should be noted that these estimates
are based solely upon LTO cycles and consequently only capture near ground-level emissions, which are more relevant for air
quality evaluations. These estimates also include both domestic and international flights. Therefore, estimates reported under the
Mobile Combustion section overestimate IPCC-defined domestic CO, NOX, and NMVOC emissions by including landing and
take-off (LTO) cycles by aircraft on international flights, but underestimate because they do not include emissions from aircraft
on domestic flight segments at cruising altitudes. The estimates in Mobile Combustion are also likely to include emissions from
ocean-going vessels departing from U.S. ports on international voyages.
3-58 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 contributions to U.S. totals. In accordance with IPCC methodological guidelines, any such emissions are calculated
2 by accounting for net carbon (C) fluxes from changes in biogenic C reservoirs in wooded or crop lands. For a more
3 complete description of this methodological approach, see the Land Use, Land-Use Change, and Forestry chapter
4 (Chapter 7), which accounts for the contribution of any resulting CO2 emissions to U. S. totals within the Land Use,
5 Land-Use Change and Forestry sector's approach.
6 In 2009, total CO2 emissions from the burning of woody biomass in the industrial, residential, commercial, and
7 electricity generation sectors were approximately 183.8 Tg CO2 Eq. (183,777 Gg) (see Table 3-53 and Table 3-54).
8 As the largest consumer of woody biomass, the industrial sector was responsible for 62 percent of the CO2 emissions
9 from this source. Emissions from this sector decreased from 2008 to 2009 due to a corresponding decrease in wood
10 consumption. The residential sector was the second largest emitter, constituting 24 percent of the total, while the
11 commercial and electricity generation sectors accounted for the remainder.
12 Table 3-53: CO2 Emissions from Wood Consumption by End-Use Sector (Tg CO2 Eq.)
End-Use Sector 1990 2000 2005 2006 2007 2008 2009
13
14
15
Industrial
Residential
Commercial
Electricity Generation
Total
Note: Totals may not sum
135.
59.
6.
13.
215.
3
8
8
3
2
153.
43.
7.
13.
218.
6
3
4
9
1
136.3
44.3
7.2
19.1
206.9
138.2
40.2
6.7
18.7
203.8
132.6
44.3
7.2
19.2
203.3
126.
46.
7.
18.
198.
1
4
5
3
4
114.2
44.3
7.4
17.8
183.8
due to independent rounding.
Table 3-54: CO2 Emissions from Wood
End-Use Sector
Industrial
Residential
Commercial
Electricity Generation
Total
1990
135,348
59,808
6,779
13,252
215,186
Consumption by End-Use
2000
153,559
43,309
7,370
13,851
218,088
2005
136,269
44,340
7,182
19,074
206,865
Sector (Gg)
2006
138,207
40,215
6,675
18,748
203,846
2007
132,642
44,340
7,159
19,175
203,316
2008
126
46
7
18
198
,145
,402
,526
,288
,361
2009
114
44
7
17
,222
,340
,406
,809
183,777
16 Note: Totals may not sum due to independent rounding.
17 Biomass-derived fuel consumption in the United States transportation sector consisted primarily of ethanol use.
18 Ethanol is primarily produced from corn grown in the Midwest, and was used mostly in the Midwest and South.
19 Pure ethanol can be combusted, or it can be mixed with gasoline as a supplement or octane-enhancing agent. The
20 most common mixture is a 90 percent gasoline, 10 percent ethanol blend known as gasohol. Ethanol and ethanol
21 blends are often used to fuel public transport vehicles such as buses, or centrally fueled fleet vehicles.
22 In 2009, the United States consumed an estimated 894 trillion Btu of ethanol, and as a result, produced
23 approximately 59.0 Tg CO2 Eq. (58,989 Gg) (see Table 3-55 and Table 3-56 ) of CO2 emissions. Ethanol
24 production and consumption has grown steadily every year since 1990, with the exception of 1996 due to short corn
25 supplies and high prices in that year.
26 Table 3-55: CO2 Emissions from Ethanol Consumption (Tg CO2 Eq.)
27
28
29
30
End-Use Sector
Transportation
Industrial
Commercial
Total
1990
4.0
0.1
+
4.1
+ Does not exceed 0.05 Tg CO
Table 3-56: CO2 Emissions
End-Use Sector
Transportation3
Industrial
Commercial
Total
1990
3,987
54
33
4,074
2000
8.9
0.1
+
9.0
2Eq.
from Ethanol
2000
8,901
84
25
9,009
2005
21.6
0.5
0.1
22.1
Consumption
2005
21,606
451
58
22,115
2006
29.1
0.6
0.1
29.9
(Gg)
2006
29,147
638
83
29,867
2007
36.7
0.6
0.1
37.5
2007
36,741
649
130
37,520
2008
51
0
0
52
.9
.8
.1
.8
2008
51,
52,
856
768
141
765
a See Annex 3.2, Table A-88 for additional information on transportation consumption of these
2009
58
0
0
59
.0
.9
.2
.0
2009
57,973
859
157
58,989
fuels.
Energy 3-59
-------
i Methodology
2 Woody biomass emissions were estimated by applying two EIA gross heat contents (Lindstrom 2006) to U.S.
3 consumption data (EIA 2010) (see Table 3-57), provided in energy units for the industrial, residential, commercial,
4 and electric generation sectors. One heat content (16.95 MMBtu/MT wood and wood waste) was applied to the
5 industrial sector's consumption, while the other heat content (15.43 MMBtu/MT wood and wood waste) was applied
6 to the consumption data for the other sectors. An EIA emission factor of 0.434 MT C/MT wood (Lindstrom 2006)
7 was then applied to the resulting quantities of woody biomass to obtain CO2 emission estimates. It was assumed
8 that the woody biomass contains black liquor and other wood wastes, has a moisture content of 12 percent, and is
9 converted into CC>2 with 100 percent efficiency. The emissions from ethanol consumption were calculated by
10 applying an EIA emission factor of 17.99 Tg C/QBtu (Lindstrom 2006) to U.S. ethanol consumption estimates that
11 were provided in energy units (EIA 2010) (see Table 3-58).
12 Table 3-57: Woody Biomass Consumption by Sector (Trillion Btu)
End-Use Sector
Industrial
Residential
Commercial
Electricity Generation
13
14
Total
Table 3-58: Ethanol
End-Use Sector
Transportation
Industrial
Commercial
Total
1990
1,442
580
66
129
2,216
Consumption by
1990
60
0
0
61
.5
.8
.5
.8
2000
1,636
420
71
134
2,262
2005
1,
452
430
70
185
2,136
2006
1,472
390
65
182
2,109
2007
1,413
430
69
186
2,098
2008
1,344
450
73
177
2,044
2009
1,217
430
72
173
1,891
Sector (Trillion Btu)
2000
135.0
1.3
0.4
136.6
2005
327
6
0
335
.6
.8
.9
.3
2006
442.0
9.7
1.3
452.9
2007
557.1
9.8
2.0
568.9
2008
786.3
11.7
2.1
800.1
2009
879.0
13.0
2.4
894.5
15
16 Uncertainty and Time-Series Consistency
17 It is assumed that the combustion efficiency for woody biomass is 100 percent, which is believed to be an
18 overestimate of the efficiency of wood combustion processes in the United States. Decreasing the combustion
19 efficiency would decrease emission estimates. Additionally, the heat content applied to the consumption of woody
20 biomass in the residential, commercial, and electric power sectors is unlikely to be a completely accurate
21 representation of the heat content for all the different types of woody biomass consumed within these sectors.
22 Emission estimates from ethanol production are more certain than estimates from woody biomass consumption due
23 to better activity data collection methods and uniform combustion techniques.
24 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
25 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
26 above.
27 Recalculations Discussion
28 Wood consumption values were revised for 2006 through 2008 based on updated information from EIA's Annual
29 Energy Review (EIA 2010). This adjustment of historical data for wood biomass consumption resulted in an average
30 annual decrease in emissions from wood biomass consumption of 0.8 Tg CO2 Eq. (0.4 percent) from 1990 through
31 2008. Slight adjustments were made to ethanol consumption based on updated information from EIA (2010), which
32 slightly decreased estimates for ethanol consumed. As a result of these adjustments, average annual emissions from
33 ethanol consumption decreased by about 0.2 Tg CO2 Eq. (1.9 percent) relative to the previous Inventory.
3-60 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Fossil Fuel Combustion
Natural Gas Systems
Non-Energy Use of Fuels
Coal Mining
Petroleum Systems •
Mobile Combustion I
Stationary Combustion I
Incineration of Waste I
Abandoned Underground Coal Mines |
5,212
Energy as a Portion
of all Emissions
50
100
150 200
Tg C02 Eq.
Figure 3-1: 2009 Energy Chapter Greenhouse Gas Sources
250
300
-------
Natural Gas Emissions
1,209
NEU Emissions 51
Non-Energy Use
Carbon Sequestered
184
Fossil Fue
Non-Energy Consumption
Use imports U.S.
47 Territories
40
Non-Energy
Use U.S.
Territories
9
Balancing item
160
Note: Totals may not sum due to independent rounding.
The "Balancing Item" above accounts for the statistical imbalances
and unknowns in the reported data sets combined here.
3-2 2009 U.S. (Tg C02 Eq.)
-------
Renewable
Nuclear EnergV
Electric
Power
8.8%
Figure 3-3: 2009 U.S. Energy Consumption by Energy Source
-------
120 -i
100 -
80 -
60 -
40 -
20 -
Total Energy
Fossil Fuels
Renewable & Nuclear
O^O^O^O^O^O^O^O^CTiCT'
i-Hi-li-li-li-li-li-li-li-li-
Figure 3-4: U.S. Energy Consumption (Quadrillion Btu)
Note: Expressed as gross calorific values.
2,500 -i
2,000 -
1'500
1,000
500 -
0 -
Relative Contribution
by Fuel Type
2,154
42
219
Petroleum
• Coal
• Natural Gas
340
1,719
Figure 3-5: 2009 CO2 Emissions from Fossil Fuel Combustion by Sector and Fuel Type
Note: The electricity generation sector also includes emissions of less than 0.5 Tg CO 2 Eq. from geothermal-based electricity
-------
20 -i
-20 J
Normal
(4,524 Heating Degree Days)
Bffifeffi33S[38£f2!C
m in ix
Figure 3-6: Annual Deviations from Normal Heating Degree Days for the United States (1950-2009)
Note: Climatological normal data are highlighted.
Statistical confidence interval for "normal" climatology period of 1971 through 2000.
20 -i 99% Confidence
*£ -10
-------
_
I
u
100
90
80
70
60
50
40
30
20
10
0
Nuclear
Hydroelectric
Wind
Figure 3-8: Nuclear, Hydroelectric, and Wind Power Plant Capacity Factors in the United States (1990-2009)
-------
Total excluding Computers,
Communications Equipment, and
Semiconductors
S
Sin & r*^ co &>
ooooo
i-< CM ro , -. _ .
ooooooo _ _
ooooooooo
rMfMfMrMrMrMrMrMrM
Figure 3-10: Industrial Production Indexes (Index 2007=100)
22.5 -,
22.0 -
21.5 -
21.0 -
20.5 -
20.0 -
19.5 -
19.0 -
18.5 -
18.0 -
Model Year
Figure 3-11: Sales-Weighted Fuel Economy of New Passenger Cars and Light-Duty Trucks, 1990-2009
-------
10,000 -,
g. 8,000 -
8
I 6,000 -
l/l
"oi
"8
s 4,000 -
2,000 -
Passenger Cars
8 8 8
8888888888
Figure 3-12: Sales of New Passenger Cars and Light-Duty Trucks, 1990-2009
60 -,
50 -
. 40 -
8 30 H
20 -
10 -
N,O
CH4
§888888888
Figure 3-13: Mobile Source CH4 and N2O Emissions
co2/capita
COz/Energy Energy
Consumption Consumption/
capita
-------
i 4. Industrial Processes
2 Greenhouse gas emissions are produced as the by-products of various non-energy-related industrial activities. That
3 is, these emissions are produced from an industrial process itself and are not directly a result of energy consumed
4 during the process. For example, raw materials can be chemically transformed from one state to another. This
5 transformation can result in the release of greenhouse gases such as carbon dioxide (CO2), methane (CH4), and
6 nitrous oxide (N2O). The processes addressed in this chapter include iron and steel production and metallurgical
7 coke production, cement production, lime production, ammonia production and urea consumption, limestone and
8 dolomite consumption (e.g., flux stone, flue gas desulfurization, and glass manufacturing), soda ash production and
9 use, aluminum production, titanium dioxide production, CO2 consumption, ferroalloy production, phosphoric acid
10 production, zinc production, lead production, petrochemical production, silicon carbide production and
11 consumption, nitric acid production, and adipic acid production (see Figure 4-1).
12
13 Figure 4-1: 2009 Industrial Processes Chapter Greenhouse Gas Sources
14
15 In addition to the three greenhouse gases listed above, there are also industrial sources of man-made fluorinated
16 compounds called hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). The present
17 contribution of these gases to the radiative forcing effect of all anthropogenic greenhouse gases is small; however,
18 because of their extremely long lifetimes, many of them will continue to accumulate in the atmosphere as long as
19 emissions continue. In addition, many of these gases have high global warming potentials; SF6 is the most potent
20 greenhouse gas the Intergovernmental Panel on Climate Change (IPCC) has evaluated. Usage of HFCs is growing
21 rapidly since they are the primary substitutes for ozone depleting substances (ODSs), which are being phased-out
22 under the Montreal Protocol on Substances that Deplete the Ozone Layer. In addition to their use as ODS
23 substitutes, HFCs, PFCs, and SF6 are employed and emitted by a number of other industrial sources in the United
24 States. These industries include aluminum production, HCFC-22 production, semiconductor manufacture, electric
25 power transmission and distribution, and magnesium metal production and processing.
26 In 2009, industrial processes generated emissions of 283.5 teragrams of CO2 equivalent (Tg CO2 Eq.), or 4 percent
27 of total U.S. greenhouse gas emissions. CO2 emissions from all industrial processes were 120.2 Tg CO2 Eq.
28 (120,244 Gg) in 2009, or 2 percent of total U.S. CO2 emissions. CH4 emissions from industrial processes resulted in
29 emissions of approximately 1.2 Tg CO2 Eq. (58 Gg) in 2009, which was less than 1 percent of U.S. CH4 emissions.
30 N2O emissions from adipic acid and nitric acid production were 16.5 Tg CO2 Eq. (53 Gg) in 2009, or 6 percent of
31 total U.S. N2O emissions. In 2009 combined emissions of HFCs, PFCs and SF6 totaled 145.5 Tg CO2 Eq. Despite
32 the significant increase in HFC emissions associated with increased usage of ODSs, total emissions from industrial
33 processes in 2009 were less than 1990 for the first time since 1994. This decrease is primarily due to significant
34 reductions in emissions from iron and steel production, metallurgical coke production, ammonia production and urea
35 consumption, adipic acid production, HCFC-22 production, aluminum production and cement production.
36 Table 4-1 summarizes emissions for the Industrial Processes chapter in Tg CO2 Eq., while unweighted native gas
37 emissions in Gg are provided in Table 4-2. The source descriptions that follow in the chapter are presented in the
38 order as reported to the UNFCCC in the common reporting format tables, corresponding generally to: mineral
39 products, chemical production, metal production, and emissions from the uses of HFCs, PFCs, and SF6.
40 Table 4-1: Emissions from Industrial Processes (Tg CO2 Eq.)
Gas/Source
C02
Iron and Steel Production
and Metallurgical Coke
Production
Iron and Steel
Production
Metallurgical Coke
Production
Cement Production
Ammonia Production &
1990
188.4
99.5
97.1
2.5
33.3
16.8
2000
185.7
85.9
83.7
2.2
41.2
16.4
2005
166.1
65.9
63. 9
2.0
45.9
12.8
2006
170.6
68.8
66. 9
1.9
46.6
12.3
2007
173.3
71.1
69.0
2.1
45.2
14.0
2008
160.1
66.0
63.7
2.3
41.1
11.9
2009
120.2
42.6
41.6
1.0
29.4
11.8
Industrial Processes 4-1
-------
1
2
o
3
4
Urea Consumption
Lime Production
Limestone and Dolomite
Use
Soda Ash Production and
Consumption
Aluminum Production
Petrochemical Production
Carbon Dioxide
Consumption
Ferroalloy Production
Titanium Dioxide
Production
Phosphoric Acid Productio
Zinc Production
Lead Production
Silicon Carbide Production
and Consumption
CH4
Petrochemical Production
Iron and Steel Production
and Metallurgical Coke
Production
Iron and Steel
Production
Metallurgical Coke
Production
Ferroalloy Production
Silicon Carbide Production
and Consumption
N2O
Nitric Acid Production
Adipic Acid Production
HFCs
Substitution of Ozone
Depleting Substances3
HCFC-22 Production
Semiconductor
Manufacturing HFCs
PFCs
Aluminum Production
Semiconductor
Manufacturing PFCs
SF6
Electrical Transmission an
Distribution
Semiconductor
Manufacturing SF6
Magnesium Production anc
Processing
Total
+ Does not exceed 0.05 Tg CO2
11.5
5.1
4.1
6.8
3.3
1.4
2.2
1.2
1.5
0.7
0.5
0.4
1.9
0.9
1.0
1.0
+
+
+
33.5
17.7
15.8
36.9
0.3
36.4
0.2
20.8
18.5
2.2
34.4
28.4
0.5
5.4
315.8
Eq.
14.1
5.1
4.2
6.1
4.5
.4
.9
.8
.4
.0
0.6
0.2
2.2
1.2
0.9
0.9
+
+
+
24.9
19.4
5.5
103.2
74.3
28.6
0.3
13.5
8.6
4.9
20.1
16.0
1.1
3.0
349.6
14.4
6.8
4.2
4.1
4.2
.3
.4
.8
.4
.1
0.6
0.2
1.8
1.1
0.7
0.7
+
+
+
21.5
16.5
5.0
120.2
104.2
15.8
0.2
6.2
3.0
3.2
19
15.1
1.0
2.9
334.8
15.1
8.0
4.2
3.8
3.8
1.7
1.5
1.8
1.2
1.1
0.6
0.2
1.7
1.0
0.7
0.7
+
+
+
20.5
16.2
4.3
123.4
109.3
13.8
0.3
6.0
2.5
3.5
17.9
14.1
1.0
2.9
340.2
14.6
7.7
4.1
4.3
3.9
1.9
1.6
1.9
1.2
1.1
0.6
0.2
1.7
1.0
0.7
0.7
+
+
+
22.9
19.2
3.7
129.5
112.2
17.0
0.3
7.5
3.8
3.7
16.7
13.2
0.8
2.6
351.6
14.3
6.3
4.1
4.5
3.4
.8
.6
.8
.2
.2
0.6
0.2
1.6
0.9
0.6
0.6
+
+
+
18.5
16.4
2.0
129.1
115.2
13.6
0.3
6.7
2.7
4.0
16.1
13.3
0.9
1.9
332.0
11.2
7.6
4.3
3.0
2.7
.8
.6
.5
.0
.0
0.5
0.1
1.2
0.8
0.4
0.4
+
+
+
16.5
14.6
1.9
125.0
119.3
5.4
0.3
5.6
1.6
4.0
14.8
12.8
1.0
1.1
283.5
Note: Totals may not sum due to independent rounding.
a Small amounts of PFC emissions also result
from this source.
4-2 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Table 4-2: Emissions from Industrial Processes (Gg)
Gas/Source
CO2
Iron and Steel Production
and Metallurgical Coke
Production
Iron and Steel
Production
Metallurgical Coke
Production
Cement Production
Ammonia Production &
Urea Consumption
Lime Production
Limestone and Dolomite
Use
Soda Ash Production and
Consumption
Aluminum Production
Petrochemical Production
Carbon Dioxide
Consumption
Ferroalloy Production
Titanium Dioxide
Production
Phosphoric Acid
Production
Zinc Production
Lead Production
Silicon Carbide
Production and
Consumption
CH4
Petrochemical Production
Iron and Steel Production
and Metallurgical Coke
Production
Iron and Steel
Production
Metallurgical Coke
Production
Ferroalloy Production
Silicon Carbide
Production and
Consumption
N2O
Nitric Acid Production
Adipic Acid Production
HFCs
Substitution of Ozone
Depleting Substances3
HCFC-22 Production
Semiconductor
Manufacturing HFCs
PFCs
Aluminum Production
1990
188,431
99,528
97,058
2,470
33,278
16,831
11,533
5,127
4,141
6,831
3,311
1,416
2,152
1,195
1,529
667
516
375
88
41
46
46
+
1
1
108
57
51
M
M
o
J
+
M
M
2000
185,704
85,935
83, 740
2,195
41,190
16,402
14,088
5,056
4,181
6,086
4,479
1,421
1,893
1,752
1,382
997
594
248
104
59
44
44
+
1
1
80
63
18
M
M
2
+
M
M
2005
166,097
65,925
63,882
2,043
45,910
12,849
14,379
6,768
4,228
4,142
4,181
1,321
1,392
1,755
1,386
1,088
553
219
86
51
34
34
+
+
+
69
53
16
M
M
1
+
M
M
2006
170,641
68,772
66, 852
1,919
46,562
12,300
15,100
8,035
4,162
3,801
3,837
1,709
1,505
1,836
1,167
1,088
560
207
83
48
35
35
+
+
+
66
52
14
M
M
1
+
M
M
2007
173,283
71,045
68,991
2,054
45,229
14,038
14,595
7,702
4,140
4,251
3,931
1,867
1,552
1,930
1,166
1,081
562
196
82
48
33
33
+
+
+
74
62
12
M
M
1
+
M
M
2008
160,086
66,015
63, 682
2,334
41,147
11,949
14,330
6,276
4,111
4,477
3,449
1,780
1,599
1,809
1,187
1,230
551
175
75
43
31
31
+
+
+
60
53
7
M
M
1
+
M
M
2009
120,244
42,576
41,619
956
29,417
11,797
11,223
7,649
4,265
3,009
2,735
1,763
1,599
1,541
1,035
966
525
145
58
40
17
17
+
+
+
53
47
6
M
M
+
+
M
M
Industrial Processes 4-3
-------
Semiconductor
Manufacturing PFCs M M M M M M M
SF6 1111111
Electrical Transmission
and Distribution 1 1 11111
Semiconductor
Manufacturing SF6 + + + + + + +
Magnesium Production
and Processing + + + + + + +_
1 + Does not exceed 0.5 Gg
2 M (Mixture of gases)
3 Note: Totals may not sum due to independent rounding.
4 a Small amounts of PFC emissions also result from this source.
5
6 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
7 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
8 above.
9 QA/QC and Verification Procedures
10 Tier 1 quality assurance and quality control procedures have been performed for all industrial process sources. For
11 industrial process sources of CO2 and CH4 emissions, a detailed plan was developed and implemented. This plan
12 was based on the overall U.S. strategy, but was tailored to include specific procedures recommended for these
13 sources. Two types of checks were performed using this plan: 1) general, or Tier 1, procedures that focus on annual
14 procedures and checks to be used when gathering, maintaining, handling, documenting, checking, and archiving the
15 data, supporting documents, and files, and 2) source-category specific, or Tier 2, procedures that focus on
16 procedures and checks of the emission factors, activity data, and methodologies used for estimating emissions from
17 the relevant industrial process sources. Examples of these procedures include checks to ensure that activity data and
18 emission estimates are consistent with historical trends; that, where possible, consistent and reputable data sources
19 are used across sources; that interpolation or extrapolation techniques are consistent across sources; and that
20 common datasets and factors are used where applicable.
21 The general method employed to estimate emissions for industrial processes, as recommended by the IPCC,
22 involves multiplying production data (or activity data) for each process by an emission factor per unit of production.
23 The uncertainty in the emission estimates is therefore generally a function of a combination of the uncertainties
24 surrounding the production and emission factor variables. Uncertainty of activity data and the associated probability
25 density functions for industrial processes CO2 sources were estimated based on expert assessment of available
26 qualitative and quantitative information. Uncertainty estimates and probability density functions for the emission
27 factors used to calculate emissions from this source were devised based on IPCC recommendations.
28 Activity data is obtained through a survey of manufacturers conducted by various organizations (specified within
29 each source); the uncertainty of the activity data is a function of the reliability of plant-level production data and is
30 influenced by the completeness of the survey response. The emission factors used were either derived using
31 calculations that assume precise and efficient chemical reactions, or were based upon empirical data in published
32 references. As a result, uncertainties in the emission coefficients can be attributed to, among other things,
33 inefficiencies in the chemical reactions associated with each production process or to the use of empirically-derived
34 emission factors that are biased; therefore, they may not represent U.S. national averages. Additional assumptions
35 are described within each source.
36 The uncertainty analysis performed to quantify uncertainties associated with the 2009 inventory estimates from
37 industrial processes continues a multi-year process for developing credible quantitative uncertainty estimates for
38 these source categories using the IPCC Tier 2 approach. As the process continues, the type and the characteristics of
39 the actual probability density functions underlying the input variables are identified and better characterized
40 (resulting in development of more reliable inputs for the model, including accurate characterization of correlation
41 between variables), based primarily on expert judgment. Accordingly, the quantitative uncertainty estimates
42 reported in this section should be considered illustrative and as iterations of ongoing efforts to produce accurate
43 uncertainty estimates. The correlation among data used for estimating emissions for different sources can influence
4-4 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 the uncertainty analysis of each individual source. While the uncertainty analysis recognizes very significant
2 connections among sources, a more comprehensive approach that accounts for all linkages will be identified as the
3 uncertainty analysis moves forward.
4 4.1. Cement Production (IPCC Source Category 2A1)
5 Cement production is an energy- and raw-material-intensive process that results in the generation of CO2 from both
6 the energy consumed in making the cement and the chemical process itself.100 Cement is produced in 37 states and
7 Puerto Rico. CO2 emitted from the chemical process of cement production is the second largest source of industrial
8 CO2 emissions in the United States.
9 During the cement production process, calcium carbonate (CaCO3) is heated in a cement kiln at a temperature of
10 about 1,450°C (2,400°F) to form lime (i.e., calcium oxide or CaO) and CO2 in a process known as calcination or
11 calcining. A very small amount of carbonates other than CaCO3 and non-carbonates are also present in the raw
12 material; however, for calculation purposes all of the raw material is assumed to be CaCO3. Next, the lime is
13 combined with silica-containing materials to produce clinker (an intermediate product), with the earlier by-product
14 CO2 being released to the atmosphere. The clinker is then allowed to cool, mixed with a small amount of gypsum
15 and potentially other materials (e.g., slag), and used to make portland cement.101
16 In 2009, U.S. clinker production—including Puerto Rico—totaled 56,889 thousand metric tons (USGS 2010b). The
17 resulting CO2 emissions were estimated to be 29.4 Tg CO2 Eq. (29,417 Gg) (see Table 4-3).
18 Table 4-3: CO2 Emissions from Cement Production (Tg CO2 Eq. and Gg)
19
20
21
22
23
24
Year Tg CO2 Eq. Gg
1990 33.3 33,278
2000 41.2 41,190
2005 45.9 45,910
2006 46.6 46,562
2007 45.2 45,229
2008 41.1 41,147
2009 29.4 29,417
Cement production emissions grew every year from 1991 through 2006, but have decreased since.
1990 have decreased by 12 percent. A significant decrease in emissions is seen between 2008 and
Emissions since
2009, due to the
economic recession and associated decrease in demand for construction materials. Cement continues to be a critical
component of the construction industry; therefore, the availability of public construction funding, as well as overall
economic conditions, have considerable influence on cement production.
25 Methodology
26 CO2 emissions from cement production are created by the chemical reaction of carbon-containing minerals (i.e.,
27 calcining limestone) in the cement kiln. While in the kiln, limestone is broken down into CO2 and lime with the
28 CO2 released to the atmosphere. The quantity of CO2 emitted during cement production is directly proportional to
29 the lime content of the clinker. During calcination, each mole of CaCO3 (i.e., limestone) heated in the clinker kiln
30 forms one mole of lime (CaO) and one mole of CO2:
31 CaCO3 + heat -» CaO + CO2
32 CO2 emissions were estimated by applying an emission factor, in tons of CO2 released per ton of clinker produced,
100 The CO2 emissions related to the consumption of energy for cement manufacture are accounted for under CO2 from Fossil
Fuel Combustion in the Energy chapter.
101 Approximately six percent of total clinker production is used to produce masonry cement, which is produced using
plasticizers (e.g., ground limestone, lime) and portland cement. CO2 emissions that result from the production of lime used to
create masonry cement are included in the Lime Manufacture source category (van Oss 2008c).
Industrial Processes 4-5
-------
1 to the total amount of clinker produced. The emission factor used in this analysis is the product of the average lime
2 fraction for clinker of 65 percent (van Oss 2008c) and a constant reflecting the mass of CO2 released per unit of
3 lime. This calculation yields an emission factor of 0.51 tons of CO2 per ton of clinker produced, which was
4 determined as follows:
6
7
8
9
10
11
,
Clinker
= 0.6460 CaOx
44.01 g/moleCO
56.08 g/moleCaO
= 0.5070 tons CO /tonclinker
During clinker production, some of the clinker precursor materials remain in the kiln as non-calcinated, partially
calcinated, or fully calcinated cement kiln dust (CKD). The emissions attributable to the calcinated portion of the
CKD are not accounted for by the clinker emission factor. The IPCC recommends that these additional CKD CO2
emissions should be estimated as two percent of the CO2 emissions calculated from clinker production.102 Total
cement production emissions were calculated by adding the emissions from clinker production to the emissions
assigned to CKD (IPCC 2006).103
12 The 1990 through 2008 activity data for clinker production (see Table 4-4) were obtained through the USGS
13 Minerals Yearbook: Cement (US Bureau of Mines 1990 through 1993, USGS 1995 through 2010a). The 2009
14 activity data were obtained through the USGS Mineral Commodity Summary: Cement (2010b). The data were
15 compiled by USGS through questionnaires sent to domestic clinker and cement manufacturing plants.
16 Table 4-4: Clinker Production (Gg)
17
Year
1990
2000
2005
2006
2007
2008
2009
Clinker
64,355
79,656
88,783
90,045
87,466
79,599
56,889
is Uncertainty and Time-Series Consistency
19 The uncertainties contained in these estimates are primarily due to uncertainties in the lime content of clinker and in
20 the percentage of CKD recycled inside the cement kiln. Uncertainty is also associated with the assumption that all
21 calcium-containing raw materials are CaCO3 when a small percentage likely consists of other carbonate and non-
22 carbonate raw materials. The lime content of clinker varies from 60 to 67 percent (van Oss 2008b). CKD loss can
23 range from 1.5 to 8 percent depending upon plant specifications. Additionally, some amount of CO2 is reabsorbed
24 when the cement is used for construction. As cement reacts with water, alkaline substances such as calcium
25 hydroxide are formed. During this curing process, these compounds may react with CO2 in the atmosphere to create
26 calcium carbonate. This reaction only occurs in roughly the outer 0.2 inches of surface area. Because the amount of
27 CO2 reabsorbed is thought to be minimal, it was not estimated.
28 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-5. Cement Production CO2
29 emissions were estimated to be between 25.7 and 33.5 Tg CO2 Eq. at the 95 percent confidence level. This indicates
30 a range of approximately 13 percent below and 14 percent above the emission estimate of 29.4 Tg CO2 Eq.
31 Table 4-5: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Cement Production (Tg CO2 Eq. and
102 Default IPCC clinker and CKD emission factors were verified through expert consultation with the Portland Cement
Association (PCA 2008) and van Oss (2008a).
103 The 2 percent CO2 addition associated with CKD is included in the emission estimate for completeness. The cement emission
estimate also includes an assumption that all raw material is limestone (CaCO3) when in fact a small percentage is likely
composed of non-carbonate materials. Together these assumptions may result in a small emission overestimate (van Oss 2008c).
4-6 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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Percent)
2009 Emission
Source Gas Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Cement Production CO2 29.4
25.7 33.5 -13% +14%
2 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
3 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
4 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
5 above.
6 Planned Improvements
7 Future improvements to the cement source category involve evaluating facility level greenhouse gas emissions data
8 as a basis for improving emissions calculations from cement production. Beginning in 2010, all U.S. cement
9 production facilities will be required to monitor, calculate and report their greenhouse gas emissions to EPA through
10 its Greenhouse Gas Reporting Program. Under the program, EPA will obtain data for 2010 emissions from facilities
11 based on use of higher tier methods and in particular assess how this data could be used to improve the overall
12 method for calculating emissions from the U.S. cement industry, including also improving emission factors for
13 clinker production and CKD.
14 4.2. Lime Production (IPCC Source Category 2A2)
15 Lime is an important manufactured product with many industrial, chemical, and environmental applications. Its
16 major uses are in steel making, flue gas desulfurization (FGD) systems at coal-fired electric power plants,
17 construction, and water purification. For U.S. operations, the term "lime" actually refers to a variety of chemical
18 compounds. These include calcium oxide (CaO), or high-calcium quicklime; calcium hydroxide (Ca(OH)2), or
19 hydrated lime; dolomitic quicklime ([CaOMgO]); and dolomitic hydrate ([Ca(OH)2«MgO] or
20 [Ca(OH)2«Mg(OH)2]).
21 Lime production involves three main processes: stone preparation, calcination, and hydration. CO2 is generated
22 during the calcination stage, when limestone—mostly calcium carbonate (CaCO3)—is roasted at high temperatures
23 in a kiln to produce CaO and CO2. The CO2 is given off as a gas and is normally emitted to the atmosphere. Some
24 of the CO2 generated during the production process, however, is recovered at some facilities for use in sugar refining
25 and precipitated calcium carbonate (PCC) production.104 In certain additional applications, lime reabsorbs CO2
26 during use.
27 Lime production in the United States—including Puerto Rico—was reported to be 15,781 thousand metric tons in
28 2009 (USGS 2010). This production resulted in estimated CO2 emissions of 11.2 Tg CO2 Eq. (11,223 Gg) (see
29 Table 4-6 and Table 4-7).
30 Table 4-6: CO2 Emissions from Lime Production (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq.
1990
2000
2005
2006
2007
2008
2009
11.5
14.1
14.4
15.1
14.6
14.3
11.2
Gg
11,533
14,088
14,379
15,100
14,595
14,330
11,223
104 PQQ js obtained from the reaction of CO2 with calcium hydroxide. It is used as a filler and/or coating in the paper, food, and
plastic industries.
Industrial Processes 4-7
-------
2 Table 4-7: Potential, Recovered, and Net CO2 Emissions from Lime Production (Gg)
Year
1990
2000
2005
2006
2007
2008
2009
Potential
12,004
14,872
15,131
15,825
15,264
14,977
11,913
Recovered*
471
784
752
725
669
647
690
Net Emissions
11,533
14,088
14,379
15,100
14,595
14,330
11,223
3 For sugar refining and PCC production.
4 Note: Totals may not sum due to rounding
5
6 Lime production in 2009 decreased by 21 percent compared to 2008, owing mostly to a significant downturn in
7 major markets such as construction and steel. Because of this significant downturn, overall lime production in 2009
8 was approximately equal to production in 1990. The contemporary lime market is approximately distributed across
9 five end-use categories as follows: environmental uses, 34 percent; metallurgical uses, 31 percent; chemical and
10 industrial uses, 25 percent; construction uses, 9 percent; and refractory dolomite, 1 percent. In the construction
11 sector, lime is used to improve durability in plaster, stucco, and mortars, as well as to stabilize soils. Consumption
12 for metallurgical uses accounted for 57% of the overall decrease in lime consumption (USGS 2010).
13 Methodology
14 During the calcination stage of lime production, CO2 is given off as a gas and normally exits the system with the
15 stack gas. To calculate emissions, the amounts of high-calcium and dolomitic lime produced were multiplied by
16 their respective emission factors. The emission factor is the product of a constant reflecting the mass of CO2
17 released per unit of lime and the average calcium plus magnesium oxide (CaO + MgO) content for lime (95 percent
18 for both types of lime) (IPCC 2006). The emission factors were calculated as follows:
19 For high-calcium lime:
20 [(44.01 g/mole CO2) - (56.08 g/mole CaO)] x (0.9500 CaO/lime) = 0.7455 g CO2/g lime
21 For dolomitic lime:
22 [(88.02 g/mole CO2) - (96.39 g/mole CaO)] x (0.9500 CaO/lime) = 0.8675 g CO2/g lime
23 Production was adjusted to remove the mass of chemically combined water found in hydrated lime, determined
24 according to the molecular weight ratios of H2O to (Ca(OH)2 and [Ca(OH)2«Mg(OH)2]) (IPCC 2000). These factors
25 set the chemically combined water content to 24.30 percent for high-calcium hydrated lime, and 27.20 percent for
26 dolomitic hydrated lime.
27 Lime emission estimates were multiplied by a factor of 1.02 to account for lime kiln dust (LKD), which is produced
28 as a by-product during the production of lime (IPCC 2006).
29 Lime emission estimates were further adjusted to account for PCC producers and sugar refineries that recover CO2
30 emitted by lime production facilities for use as an input into production or refining processes. For CO2 recovery by
31 sugar refineries, lime consumption estimates from USGS were multiplied by a CO2 recovery factor to determine the
32 total amount of CO2 recovered from lime production facilities. According to industry surveys, sugar refineries use
33 captured CO2 for 100 percent of their CO2 input (Lutter 2009). CO2 recovery by PCC producers was determined by
34 multiplying estimates for the percentage CO2 of production weight for PCC production at lime plants by a CO2
35 recovery factor based on the amount of purchased CO2 by PCC manufacturers (Prillaman 2008 and 2009). As data
36 were only available starting in 2007, CO2 recovery for the period 1990 through 2006 was extrapolated by
37 determining a ratio of PCC production at lime facilities to lime consumption for PCC (USGS 2002 through 2007 &
38 2009a, USGS 2009b).
39 Lime production data (high-calcium- and dolomitic-quicklime, high-calcium- and dolomitic-hydrated, and dead-
4-8 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 burned dolomite) for 1990 through 2008 (see Table 4-8) were obtained from USGS (1992 through 2010). Lime
2 production data for 2009 were obtained from personal communication with the USGS lime commodity specialist
3 (Miller 2010). Natural hydraulic lime, which is produced from CaO and hydraulic calcium silicates, is not
4 produced in the United States (USGS 2009). Total lime production was adjusted to account for the water content of
5 hydrated lime by converting hydrate to oxide equivalent based on recommendations from the IPCC, and is presented
6 in Table 4-9 (IPCC 2000). The CaO and CaO'MgO contents of lime were obtained from the IPCC (IPCC 2006).
7 Since data for the individual lime types (high calcium and dolomitic) was not provided prior to 1997, total lime
8 production for 1990 through 1996 was calculated according to the three year distribution from 1997 to 1999.
9 Table 4-8: High-Calcium- and Dolomitic-Quicklime, High-Calcium- and Dolomitic-Hydrated, and Dead-Burned-
10 Dolomite Lime Production (Gg)
11
12
13
14
Year
1990
2000
2005
2006
2007
2008
2009
Table
Year
1990
2000
2005
2006
2007
2008
2009
High-Calcium
Quicklime
11,166
14,300
14,100
15,000
14,700
14,900
11,800
4-9: Adjusted Lime
High-Calcium
12,514
15,473
15,781
16,794
16,396
16,467
13,079
Dolomitic
Quicklime
2,234
3,000
2,990
2,950
2,700
2,310
1,650
Production3 (Gg)
Dolomitic
2,809
3,506
3,535
3,448
3,156
2,771
2,220
High-Calcium
Hydrated
1,781
1,550
2,220
2,370
2,240
2,070
1,690
Dolomitic
Hydrated
319
421
474
409
352
358
261
Dead-Burned
Dolomite
342
200
200
200
200
200
200
a Minus water content of hydrated lime
15 Uncertainty and Time-Series Consistency
16 The uncertainties contained in these estimates can be attributed to slight differences in the chemical composition of
17 these products and recovery rates for sugar refineries and PCC manufacturers located at lime plants. Although the
18 methodology accounts for various formulations of lime, it does not account for the trace impurities found in lime,
19 such as iron oxide, alumina, and silica. Due to differences in the limestone used as a raw material, a rigid
20 specification of lime material is impossible. As a result, few plants produce lime with exactly the same properties.
21 In addition, a portion of the CO2 emitted during lime production will actually be reabsorbed when the lime is
22 consumed. As noted above, lime has many different chemical, industrial, environmental, and construction
23 applications. In many processes, CO2 reacts with the lime to create calcium carbonate (e.g., water softening). CO2
24 reabsorption rates vary, however, depending on the application. For example, 100 percent of the lime used to
25 produce precipitated calcium carbonate reacts with CO2; whereas most of the lime used in steel making reacts with
26 impurities such as silica, sulfur, and aluminum compounds. A detailed accounting of lime use in the United States
27 and further research into the associated processes are required to quantify the amount of CO2 that is reabsorbed. 105
105 Representatives of the National Lime Association estimate that CO2 reabsorption that occurs from the use of lime may offset
as much as a quarter of the CO2 emissions from calcination (Males 2003).
Industrial Processes 4-9
-------
1 In some cases, lime is generated from calcium carbonate by-products at pulp mills and water treatment plants. 106
2 The lime generated by these processes is not included in the USGS data for commercial lime consumption. In the
3 pulping industry, mostly using the Kraft (sulfate) pulping process, lime is consumed in order to causticize a process
4 liquor (green liquor) composed of sodium carbonate and sodium sulfide. The green liquor results from the dilution
5 of the smelt created by combustion of the black liquor where biogenic C is present from the wood. Kraft mills
6 recover the calcium carbonate "mud" after the causticizing operation and calcine it back into lime—thereby
7 generating CO2—for reuse in the pulping process. Although this re-generation of lime could be considered a lime
8 manufacturing process, the CO2 emitted during this process is mostly biogenic in origin, and therefore is not
9 included in the industrial processes totals (Miner and Upton 2002), In accordance with IPCC methodological
10 guidelines, any such emissions are calculated by accounting for net carbon (C) fluxes from changes in biogenic C
11 reservoirs in wooded or crop lands (see Chapter 7).
12 In the case of water treatment plants, lime is used in the softening process. Some large water treatment plants may
13 recover their waste calcium carbonate and calcine it into quicklime for reuse in the softening process. Further
14 research is necessary to determine the degree to which lime recycling is practiced by water treatment plants in the
15 United States.
16 Uncertainties also remain surrounding recovery rates used for sugar refining and PCC production. The recovery rate
17 for sugar refineries is based on two sugar beet processing and refining facilities located in California that use 100
18 percent recovered CO2 from lime plants (Lutter 2009). This analysis assumes that all sugar refineries located on-site
19 at lime plants also use 100 percent recovered CO2. The recovery rate for PCC producers located on-site at lime
20 plants is based on the 2008 value for PCC manufactured at commercial lime plants, given by the National Lime
21 Association (Prillaman 2009).
22 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-10. Lime CO2 emissions were
23 estimated to be between 10.3 and 12.2 Tg CO2 Eq. at the 95 percent confidence level. This indicates a range of
24 approximately 8 percent below and 9 percent above the emission estimate of 11.2 Tg CO2 Eq.
25 Table 4-10: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Lime Production (Tg CO2 Eq. and
26 Percent)
Source
2009 Emission
Gas Estimate
(TgC02Eq.)
Uncertainty Range Relative to Emission Estimate"
(TgC02Eq.) (%)
Lower Bound Upper Bound Lower Bound Upper Bound
Lime Production CO2 11.2 10.3 12.2 -8% +9%
27 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
28 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
29 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
30 above.
31 Planned Improvements
32 Future improvements to the lime source category involve evaluating facility level greenhouse gas emissions data as
33 a basis for improving emissions calculations from lime production. Beginning in 2010, all U.S. lime production
34 facilities will be required to monitor, calculate and report their greenhouse gas emissions to EPA through its
35 Greenhouse Gas Reporting Program. Under the program, EPA will obtain data for 2010 emissions from facilities
36 based on use of higher tier methods and in particular assess how this data could be used to improve the overall
37 method for calculating emissions from the U.S. lime industry, including also improving emission factors for various
38 lime types and LKD.
39 Future improvements to the lime source category will also involve continued research into CO2 recovery associated
106 Some carbide producers may also regenerate lime from their calcium hydroxide by-products, which does not result in
emissions of CO2. In making calcium carbide, quicklime is mixed with coke and heated in electric furnaces. The regeneration of
lime in this process is done using a waste calcium hydroxide (hydrated lime) [CaC2 + 2H2O —> C2H2 + Ca(OH) 2], not calcium
carbonate [CaCO3]. Thus, the calcium hydroxide is heated in the kiln to simply expel the water [Ca(OH)2 + heat —> CaO + H2O]
and no CO2 is released.
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-------
1 with lime use during sugar refining and precipitate calcium carbonate (PCC) production. Currently, two sugar
2 refining facilities in California have been identified to capture CO2 produced in lime kilns located on the same site
3 as the sugar refinery (Lutter, 2009). Currently, data on CO2 production by these lime facilities is unavailable. Future
4 work will include research to determine the number of sugar refineries that employ the carbonation technique, the
5 percentage of these that use captured CO2 from lime production facilities, and the amount of CO2 recovered per unit
6 of lime production. Future research will also aim to improve estimates of CO2 recovered as part of the PCC
7 production process using estimates of PCC production and CO2 inputs rather than lime consumption by PCC
8 facilities.
9 4.3. Limestone and Dolomite Use (IPCC Source Category 2A3)
10 Limestone (CaCO3) and dolomite (CaCO3MgCO3)107 are basic raw materials used by a wide variety of industries,
11 including construction, agriculture, chemical, metallurgy, glass production, and environmental pollution control.
12 Limestone is widely distributed throughout the world in deposits of varying sizes and degrees of purity. Large
13 deposits of limestone occur in nearly every state in the United States, and significant quantities are extracted for
14 industrial applications. For some of these applications, limestone is heated sufficiently enough to calcine the
15 material and generate CO2 as a by-product. Examples of such applications include limestone used as a flux or
16 purifier in metallurgical furnaces, as a sorbent in flue gas desulfurization (FGD) systems for utility and industrial
17 plants, or as a raw material in glass manufacturing and magnesium production.
18 In 2009, approximately 14,928 thousand metric tons of limestone and 3,020 thousand metric tons of dolomite were
19 consumed for these emissive applications. Overall, usage of limestone and dolomite resulted in aggregate CO2
20 emissions of 7.6 Tg CO2 Eq. (7,649 Gg) (see Table 4-1 land Table 4-12). Overall, emissions have increased 49
21 percent from 1990 through 2009.
22 Table 4-11: CO2 Emissions from Limestone & Dolomite Use (Tg CO2 Eq.)
23
24
25
26
27
Year
1990
2000
2005
2006
2007
2008
2009
Flux Stone
2.6
2.1
2.7
4.5
2.0
1.0
1.8
Glass Making
0.2
0.4
0.4
0.7
0.3
0.4
0.1
FGD
1.4
1.8
3.0
2.1
3.2
3.8
5.4
Magnesium
Production
0.1
0.1
0.0
0.0
0.0
0.0
0.0
Other
Miscellaneous Uses
0.8
0.7
0.7
0.7
2.2
1.1
0.4
Total
5.1
5.1
6.8
8.0
7.7
6.3
7.6
Notes: Totals may not sum due to independent rounding. "Other miscellaneous uses" include chemical stone, mine dusting or
acid water treatment, acid neutralization, and sugar refining.
Table 4-12: CO2 Emissions from Limestone & Dolomite Use (Gg)
Year
1990
2000
2005
2006
2007
2008
2009
Flux Stone
2,593
2,104
2,650
4,492
1,959
974
1,785
Glass Making
217
371
425
747
333
387
61
FGD
1,433
1,787
2,975
2,061
3,179
3,801
5,406
Magnesium
Production
64
73
0
0
0
0
0
Other Miscellaneous
Uses
819
722
718
735
2,231
1,114
396
Total
5,127
5,056
6,768
8,035
7,702
6,276
7,649
107 Limestone and dolomite are collectively referred to as limestone by the industry, and intermediate varieties are seldom
distinguished.
Industrial Processes 4-11
-------
i Methodology
2 CO2 emissions were calculated by multiplying the quantity of limestone or dolomite consumed by the average C
3 content, 12.0 percent for limestone and 13.0 percent for dolomite (based on stoichiometry), and converting this
4 value to CO2. This methodology was used for flux stone, glass manufacturing, flue gas desulfurization systems,
5 chemical stone, mine dusting or acid water treatment, acid neutralization, and sugar refining and then converting to
6 CO2 using a molecular weight ratio. Flux stone used during the production of iron and steel was deducted from the
7 Limestone and Dolomite Use estimate and attributed to the Iron and Steel Production estimate.
8 Traditionally, the production of magnesium metal was the only other significant use of limestone and dolomite that
9 produced CO2 emissions. At the start of 2001, there were two magnesium production plants operating in the United
10 States and they used different production methods. One plant produced magnesium metal using a dolomitic process
11 that resulted in the release of CO2 emissions, while the other plant produced magnesium from magnesium chloride
12 using a CO2-emissions-free process called electrolytic reduction. However, the plant utilizing the dolomitic process
13 ceased its operations prior to the end of 2001, so beginning in 2002 there were no emissions from this particular sub-
14 use.
15 Consumption data for 1990 through 2008 of limestone and dolomite used for flux stone, glass manufacturing, flue
16 gas desulfurization systems, chemical stone, mine dusting or acid water treatment, acid neutralization, and sugar
17 refining (see Table 4-13) were obtained from the USGS Minerals Yearbook: Crushed Stone Annual Report (1995
18 through 2010a) and the U.S. Bureau of Mines (1991 & 1993a). Consumption data for 2009 were obtained from
19 personal communication with the USGS crushed stone commodity specialist (Willett 2010). The production
20 capacity data for 1990 through 2009of dolomitic magnesium metal also came from the USGS (1995 through 2010b)
21 and the U.S. Bureau of Mines (1990 through 1993b). The last plant in the United States that used the dolomitic
22 production process for magnesium metal closed in 2001. The USGS does not mention this process in the Minerals
23 Yearbook: Magnesium; therefore, it is assumed that this process continues to be non-existent in the United States
24 (USGS 2010b). During 1990 and 1992, the USGS did not conduct a detailed survey of limestone and dolomite
25 consumption by end-use. Consumption for 1990 was estimated by applying the 1991 percentages of total limestone
26 and dolomite use constituted by the individual limestone and dolomite uses to 1990 total use. Similarly, the 1992
27 consumption figures were approximated by applying an average of the 1991 and 1993 percentages of total limestone
28 and dolomite use constituted by the individual limestone and dolomite uses to the 1992 total.
29 Additionally, each year the USGS withholds data on certain limestone and dolomite end-uses due to confidentiality
30 agreements regarding company proprietary data. For the purposes of this analysis, emissive end-uses that contained
31 withheld data were estimated using one of the following techniques: (1) the value for all the withheld data points for
32 limestone or dolomite use was distributed evenly to all withheld end-uses; (2) the average percent of total limestone
33 or dolomite for the withheld end-use in the preceding and succeeding years; or (3) the average fraction of total
34 limestone or dolomite for the end-use over the entire time period.
35 There is a large quantity of crushed stone reported to the USGS under the category "unspecified uses." A portion of
36 this consumption is believed to be limestone or dolomite used for emissive end uses. The quantity listed for
37 "unspecified uses" was, therefore, allocated to each reported end use according to each end uses fraction of total
3 8 consumption in that year.108
39 Table 4-13: Limestone and Dolomite Consumption (Thousand Metric Tons)
Activity 1990 2000 2005 2006 2007 2008 2009
Flux Stone
Limestone
Dolomite
Glass Making
Limestone
Dolomite
FGD
Other Miscellaneous Uses
Total
6,737
5,804
933
489
430
59
3,258
1,835
12,319
6,283
4,151
2,132
843
843
0
4,061
1,640
12,826
7,022
3,165
3,857
962
920
43
6,761
1,632
16,377
11,030
5,208
5,822
1,693
1,629
64
4,683
1,671
19,078
5,305
3,477
1,827
757
757
0
7,225
5,057
18,344
3,253
1,970
1,283
879
879
0
8,639
2,531
15,302
4,623
1,631
2,992
139
139
0
12,288
898
17,948
108This approach was recommended by USGS.
4-12 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Notes: "Other miscellaneous uses" includes chemical stone, mine dusting or acid water treatment, acid neutralization, and sugar
2 refining. Zero values for limestone and dolomite consumption for glass making result during years when the USGS reports that
3 no limestone or dolomite are consumed for this use.
4 Uncertainty and Time Series Consistency
5 The uncertainty levels presented in this section arise in part due to variations in the chemical composition of
6 limestone. In addition to calcium carbonate, limestone may contain smaller amounts of magnesia, silica, and sulfur,
7 among other minerals. The exact specifications for limestone or dolomite used as flux stone vary with the
8 pyrometallurgical process and the kind of ore processed. Similarly, the quality of the limestone used for glass
9 manufacturing will depend on the type of glass being manufactured.
10 The estimates below also account for uncertainty associated with activity data. Large fluctuations in reported
11 consumption exist, reflecting year-to-year changes in the number of survey responders. The uncertainty resulting
12 from a shifting survey population is exacerbated by the gaps in the time series of reports. The accuracy of
13 distribution by end use is also uncertain because this value is reported by the manufacturer and not the end user.
14 Additionally, there is significant inherent uncertainty associated with estimating withheld data points for specific
15 end uses of limestone and dolomite. The uncertainty of the estimates for limestone used in glass making is
16 especially high; however, since glass making accounts for a small percent of consumption, its contribution to the
17 overall emissions estimate is low. Lastly, much of the limestone consumed in the United States is reported as "other
18 unspecified uses;" therefore, it is difficult to accurately allocate this unspecified quantity to the correct end-uses.
19 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-14. Limestone and Dolomite
20 Use CO2 emissions were estimated to be between 6.6 and 9.1 Tg CO2 Eq. at the 95 percent confidence level. This
21 indicates a range of approximately 13 percent below and 19 percent above the emission estimate of 7.6 Tg CO2 Eq.
22 Table 4-14: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Limestone and Dolomite Use (Tg
23 CO2 Eq. and Percent)
2009 Emission
Source Gas Estimate Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper
Bound
Limestone and Dolomite Use CO2 7.6 6.6 9.1 -13% +19%
24 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
25 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
26 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
27 above.
28 Planned Improvements
29 Future improvements to the limestone and dolomite source category involve research into the availability of
30 limestone and dolomite end-use data, including from EPA's new Greenhouse Gas Reporting Program. If sufficient
31 data are available, limestone and dolomite used as process materials in source categories included in future
32 inventories (e.g., glass production, other process use of carbonates) may be removed from this section and will be
33 reported under the appropriate source categories. Additionally, future improvements include revisiting the
34 methodology to distribute withheld data across emissive end-uses for all years to improve consistency of
35 calculations.
36 4.4. Soda Ash Production and Consumption (IPCC Source Category 2A4)
37 Soda ash (sodium carbonate, Na2CO3) is a white crystalline solid that is readily soluble in water and strongly
38 alkaline. Commercial soda ash is used as a raw material in a variety of industrial processes and in many familiar
39 consumer products such as glass, soap and detergents, paper, textiles, and food. It is used primarily as an alkali,
40 either in glass manufacturing or simply as a material that reacts with and neutralizes acids or acidic substances.
41 Internationally, two types of soda ash are produced, natural and synthetic. The United States produces only natural
42 soda ash and is second only to China in total soda ash production. Trona is the principal ore from which natural
43 soda ash is made.
Industrial Processes 4-13
-------
1 Only two states produce natural soda ash: Wyoming and California. Of these two states, only net emissions of CO2
2 from Wyoming were calculated due to specifics regarding the production processes employed in the state.109
3 During the production process used in Wyoming, trona ore is calcined to produce crude soda ash. CO2 is generated
4 as a by-product of this reaction, and is eventually emitted into the atmosphere. In addition, CO2 may also be
5 released when soda ash is consumed.
6 In 2009, CO2 emissions from the production of soda ash from trona were approximately 1.7 Tg CO2 Eq. (1,733 Gg).
7 Soda ash consumption in the United States generated 2.5 Tg CO2 Eq. (2,532 Gg) in 2009. Total emissions from
8 soda ash production and consumption in 2009 were 4.3 Tg CO2 Eq. (4,265 Gg) (see Table 4-15 and Table 4-16).
9 Emissions have remained relatively constant with some fluctuations since 1990. These fluctuations were strongly
10 related to the behavior of the export market and the U.S. economy. Emissions from the production of soda ash from
11 trona in 2009 are currently proxied to emissions in 2008, due to lack of available data at time of publication.
12 Emissions in 2009 increased by approximately 4 percent from emissions in 2008, and have also increased overall by
13 3 percent since 1990.
14 Table 4-15: CO2 Emissions from Soda Ash Production and Consumption (Tg CO2 Eq.)
Year Production Consumption Total
1990 1.4 2.7 4.1
2000 1.5 2.7 4.2
2005
2006
2007
2008
2009
1.7
1.6
1.7
1.7
1.7
2.6
2.5
2.5
2.4
2.5
4.2
4.2
4.1
4.1
4.3
15 Note: Totals may not sum due to independent rounding.
16
17 Table 4-16: CO2 Emissions from Soda Ash Production and Consumption (Gg)
Year Production Consumption Total
1990 1,431 2,710 4,141
2000 1,529 2,652 4,181
2005
2006
2007
2008
2009
,655
,626
,675
,733
,733
2,573
2,536
2,465
2,378
2,532
4,228
4,162
4,140
4,111
4,265
18 Note: Totals may not sum due to independent rounding.
19
20 The United States represents about one-fourth of total world soda ash output. Based on final 2007 reported data, the
21 estimated distribution of soda ash by end-use in 2008 was glass making, 49 percent; chemical production, 30
22 percent; soap and detergent manufacturing, 8 percent; distributors, 5 percent; flue gas desulfurization, 2 percent;
23 water treatment, 2 percent; pulp and paper production, 2 percent; and miscellaneous, 3 percent (USGS 2009). The
109 In California, soda ash is manufactured using sodium carbonate-bearing brines instead of trona ore. To extract the sodium
carbonate, the complex brines are first treated with CO2 in carbonation towers to convert the sodium carbonate into sodium
bicarbonate, which then precipitates from the brine solution. The precipitated sodium bicarbonate is then calcined back into
sodium carbonate. Although CO2 is generated as a by-product, the CO2 is recovered and recycled for use in the carbonation stage
and is not emitted. A third state, Colorado, produced soda ash until the plant was idled in 2004. The lone producer of sodium
bicarbonate no longer mines trona in the state. For a brief time, NaHCO3 was produced using soda ash feedstocks mined in
Wyoming and shipped to Colorado. Because the trona is mined in Wyoming, the production numbers given by the USGS
included the feedstocks mined in Wyoming and shipped to Colorado. In this way, the sodium bicarbonate production that took
place in Colorado was accounted for in the Wyoming numbers.
4-14 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 same distribution by end-use is currently assumed for 2009, due to lack of available data at time of publication.
2 Although the United States continues to be a major supplier of world soda ash, China, which surpassed the United
3 States in soda ash production in 2003, is the world's leading producer. While Chinese soda ash production appears
4 to be stabilizing, U.S. competition in Asian markets is expected to continue. Despite this competition, U.S. soda ash
5 production is expected to increase by about 0.5 percent annually (USGS 2008).
6 Methodology
7 During the production process, trona ore is calcined in a rotary kiln and chemically transformed into a crude soda
8 ash that requires further processing. CO2 and water are generated as by-products of the calcination process. CO2
9 emissions from the calcination of trona can be estimated based on the following chemical reaction:
10 2(Na3(CO3)(HCO3)'2H2O) -> 3Na2CO3 + 5H2O + CO2
11 [trona] [soda ash]
12 Based on this formula, approximately 10.27 metric tons of trona are required to generate one metric ton of CO2, or
13 an emission factor of 0.097 metric tons CO2 per metric ton trona (IPCC 2006). Thus, the 17.8 million metric tons of
14 trona mined in 2008 for soda ash production (USGS 2008) resulted in CO2 emissions of approximately 1.7 Tg CO2
15 Eq. (1,733 Gg). The same production and associated emissions estimates are assumed for 2009 due to lack of
16 available data at time of publication.
17 Once produced, most soda ash is consumed in glass and chemical production, with minor amounts in soap and
18 detergents, pulp and paper, flue gas desulfurization and water treatment. As soda ash is consumed for these
19 purposes, additional CO2 is usually emitted. In these applications, it is assumed that one mole of C is released for
20 every mole of soda ash used. Thus, approximately 0.113 metric tons of C (or 0.415 metric tons of CO2) are released
21 for every metric ton of soda ash consumed.
22 The activity data for trona production and soda ash consumption (see Table 4-17) were taken from USGS (1994
23 through 2008). Data for soda ash consumption in 2009 was taken from USGS (2010) Mineral Commodity Summary:
24 Soda Ash. Due to lack of 2009 trona production data at time of publication, the 2008 estimates is used as a proxy for
25 2009. Soda ash production and consumption data were collected by the USGS from voluntary surveys of the U.S.
26 soda ash industry.
27 Table 4-17: Soda Ash Production and Consumption (Gg)
Year
1990
2000
2005
2006
2007
2008
2009
Production*
14,700
15,700
17,000
16,700
17,200
17,800
17,800
Consumption
6,530
6,390
6,200
6,110
5,940
5,730
6,100
28 Soda ash produced from trona ore only.
29 Uncertainty and Time-Series Consistency
30 Emission estimates from soda ash production have relatively low associated uncertainty levels in that reliable and
31 accurate data sources are available for the emission factor and activity data. The primary source of uncertainty,
32 however, results from the fact that emissions from soda ash consumption are dependent upon the type of processing
33 employed by each end-use. Specific information characterizing the emissions from each end-use is limited.
34 Therefore, there is uncertainty surrounding the emission factors from the consumption of soda ash.
35 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-18. Soda Ash Production and
36 Consumption CO2 emissions were estimated to be between 4.0 and 4.6 Tg CO2 Eq. at the 95 percent confidence
37 level. This indicates a range of approximately 7 percent below and 7 percent above the emission estimate of 4.3 Tg
38 CO2Eq.
Industrial Processes 4-15
-------
1 Table 4-18: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Soda Ash Production and
2 Consumption (Tg CO2 Eq. and Percent)
2009 Emission
Source Gas Estimate Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper
Bound
Soda Ash Production
and Consumption CO2 4.3 4.0 4.6 -7% +7%
3 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
4 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
5 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
6 above.
7 Planned Improvements
8 Future inventories are anticipated to estimate emissions from glass production and other use of carbonates. These
9 inventories will extract soda ash consumed for glass production and other use of carbonates from the current soda
10 ash consumption emission estimates and include them under those sources.
11 In addition, future improvements to the soda ash production category involve evaluating facility level greenhouse
12 gas emissions data as a basis for improving emissions calculations from soda ash production. Beginning in 2010, all
13 U.S. soda ash production facilities will be required to monitor, calculate and report their greenhouse gas emissions
14 to EPA through its Greenhouse Gas Reporting Program. Under the program, EPA will obtain data for 2010
15 emissions from facilities based on use of higher tier methods and in particular assess how this data could be used to
16 improve the overall method for calculating emissions from the U. S. soda ash production industry, including also
17 improving emission factors associated with trona consumption.
is 4.5. Ammonia Production (IPCC Source Category 2B1) and Urea Consumption
19 Emissions of CO2 occur during the production of synthetic ammonia, primarily through the use of natural gas as a
20 feedstock. The natural gas-based, naphtha-based, and petroleum coke-based processes produce CO2 and hydrogen
21 (H2), the latter of which is used in the production of ammonia. One N production plant located in Kansas is
22 producing ammonia from petroleum coke feedstock. In some plants the CO2 produced is captured and used to
23 produce urea. The brine electrolysis process for production of ammonia does not lead to process-based CO2
24 emissions.
25 There are five principal process steps in synthetic ammonia production from natural gas feedstock. The primary
26 reforming step converts CH4 to CO2, carbon monoxide (CO), and H2 in the presence of a catalyst. Only 30 to 40
27 percent of the CH4 feedstock to the primary reformer is converted to CO and CO2. The secondary reforming step
28 converts the remaining CH4 feedstock to CO and CO2. The CO in the process gas from the secondary reforming
29 step (representing approximately 15 percent of the process gas) is converted to CO2 in the presence of a catalyst,
30 water, and air in the shift conversion step. CO2 is removed from the process gas by the shift conversion process, and
31 the hydrogen gas is combined with the nitrogen (N2) gas in the process gas during the ammonia synthesis step to
32 produce ammonia. The CO2 is included in a waste gas stream with other process impurities and is absorbed by a
33 scrubber solution. In regenerating the scrubber solution, CO2 is released.
34 The conversion process for conventional steam reforming of CH4, including primary and secondary reforming and
35 the shift conversion processes, is approximately as follows:
36 (catalyst)
37 0.88 CH4 + 1.26 Air + 1.24 H2O > 0.88 CO2 + N2 + 3 H2
38 N2 + 3 H2 HX 2 NH3
39 To produce synthetic ammonia from petroleum coke, the petroleum coke is gasified and converted to CO2 and H2.
40 These gases are separated, and the H2 is used as a feedstock to the ammonia production process, where it is reacted
41 with N2 to form ammonia.
4-16 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Not all of the CO2 produced in the production of ammonia is emitted directly to the atmosphere. Both ammonia and
2 CO2 are used as raw materials in the production of urea [CO(NH2)2], which is another type of nitrogenous fertilizer
3 that contains C as well as N. The chemical reaction that produces urea is:
4 2NH3 + CO2-» NH2COONH4 -» CO(NH2)2 + H2O
5 Urea is consumed for a variety of uses, including as a nitrogenous fertilizer, in urea-formaldehyde resins, and as a
6 deicing agent (TIG 2002). The C in the consumed urea is assumed to be released into the environment as CO2
7 during use. Therefore, the CO2 produced by ammonia production that is subsequently used in the production of urea
8 is still emitted during urea consumption. The majority of CO2 emissions associated with urea consumption are those
9 that result from its use as a fertilizer. These emissions are accounted for in the Cropland Remaining Cropland
10 section of the Land Use, Land-Use Change, and Forestry chapter. CO2 emissions associated with other uses of urea
11 are accounted for in this chapter. Net emissions of CO2 from ammonia production in 2009 were 11.8 Tg CO2 Eq.
12 (11,797 Gg), and are summarized in Table 4-19 and Table 4-20. Emissions of CO2 from urea consumed for non-
13 fertilizer purposes in 2009 totaled 3.9 Tg CO2 Eq. (3,942 Gg), and are summarized in Table 4-19 and Table 4-20.
14 The decrease in ammonia production in recent years is due to several factors, including market fluctuations and high
15 natural gas prices. Ammonia production relies on natural gas as both a feedstock and a fuel, and as such, domestic
16 producers are competing with imports from countries with lower gas prices. If natural gas prices remain high, it is
17 likely that domestically produced ammonia will continue to decrease with increasing ammonia imports (EEA 2004).
18 Table 4-19: CO2 Emissions from Ammonia Production and Urea Consumption (Tg CO2 Eq.)
Source
Ammonia Production
Urea Consumption3
Total
1990
13.0
3.8
16.8
2000
12.2
4.2
16.4
2005
9.2
3.7
12.8
2006
8.8
3.5
12.3
2007
9.1
5.0
14.0
2008
7.9
4.1
11.9
2009
7.9
3.9
11.8
19 Note: Totals may not sum due to independent rounding.
20 a Urea Consumption is for non-fertilizer purposes only. Urea consumed as a fertilizer is accounted for in the Land Use, Land-Use
21 Change, and Forestry chapter.
22
23 Table 4-20: CO2 Emissions from Ammonia Production and Urea Consumption (Gg)
Source 1990 2000 2005 2006 2007 2008 2009
24
25
Ammonia
Production 13,047
Urea Consumption3 3,784
Total 16,831
12,172
4,231
16,402
a Urea Consumption is for non- fertilizer purposes only.
Change, and Forestry chapter.
9,196
3,653
12,849
8,781
3,519
12,300
Urea consumed as a
9,074
4,963
14,038
7,883
4,066
11,949
fertilizer is accounted
7,855
3,942
11,797
for in the Land Use,
Land-Use
26 Methodology
27 The calculation methodology for non-combustion CO2 emissions from production of nitrogenous fertilizers from
28 natural gas feedstock is based on a CO2 emission factor published by the European Fertilizer Manufacturers
29 Association (EFMA). The selected EFMA factor is based on ammonia production technologies that are similar to
30 those employed in the United States. The CO2 emission factor (1.2 metric tons CO2/metric ton NH3) is applied to
31 the percent of total annual domestic ammonia production from natural gas feedstock. Emissions from fuels
32 consumed for energy purposes during the production of ammonia are accounted for in the Energy chapter.
33 Emissions of CO2 from ammonia production are then adjusted to account for the use of some of the CO2 produced
34 from ammonia production as a raw material in the production of urea. For each ton of urea produced, 8.8 of every
35 12 tons of CO2 are consumed and 6.8 of every 12 tons of ammonia are consumed (IPCC 2006, EFMA 2000). The
36 CO2 emissions reported for ammonia production are therefore reduced by a factor of 0.73 multiplied by total annual
37 domestic urea production. Total CO2 emissions resulting from nitrogenous fertilizer production do not change as a
38 result of this calculation, but some of the CO2 emissions are attributed to ammonia production and some of the CO2
39 emissions are attributed to urea consumption. Those CO2 emissions that result from the use of urea as a fertilizer are
40 accounted for in the Land Use, Land-Use Change, and Forestry chapter.
41 The total amount of urea consumed for non-agricultural purposes is estimated by deducting the quantity of urea
42 fertilizer applied to agricultural lands, which is obtained directly from the Land Use, Land-Use Change, and Forestry
43 Chapter and is reported in Table 4-21, from total U.S. production. Total urea production is estimated based on the
Industrial Processes 4-17
-------
1 amount of urea produced plus the sum of net urea imports and exports. CO2 emissions associated with urea that is
2 used for non-fertilizer purposes are estimated using a factor of 0.73 tons of CO2 per ton of urea consumed.
3 All ammonia production and subsequent urea production are assumed to be from the same process—conventional
4 catalytic reforming of natural gas feedstock, with the exception of ammonia production from petroleum coke
5 feedstock at one plant located in Kansas. The CO2 emission factor for production of ammonia from petroleum coke
6 is based on plant specific data, wherein all C contained in the petroleum coke feedstock that is not used for urea
7 production is assumed to be emitted to the atmosphere as CO2 (Bark 2004). Ammonia and urea are assumed to be
8 manufactured in the same manufacturing complex, as both the raw materials needed for urea production are
9 produced by the ammonia production process. The CO2 emission factor (3.57 metric tons CO2/metric ton NH3) is
10 applied to the percent of total annual domestic ammonia production from petroleum coke feedstock.
11 The emission factor of 1.2 metric ton CO2/metric ton NH3 for production of ammonia from natural gas feedstock
12 was taken from the EFMA Best Available Techniques publication, Production of Ammonia (EFMA 1995). The
13 EFMA reported an emission factor range of 1.15 to 1.30 metric ton CO2/metric tonNH3, with 1.2 metric ton
14 CO2/metric ton NH3 as a typical value. Technologies (e.g., catalytic reforming process) associated with this factor
15 are found to closely resemble those employed in the U.S. for use of natural gas as a feedstock. The EFMA reference
16 also indicates that more than 99 percent of the CH4 feedstock to the catalytic reforming process is ultimately
17 converted to CO2. The emission factor of 3.57 metric ton CO2/metric ton NH3 for production of ammonia from
18 petroleum coke feedstock was developed from plant-specific ammonia production data and petroleum coke
19 feedstock utilization data for the ammonia plant located in Kansas (Bark 2004). As noted earlier, emissions from
20 fuels consumed for energy purposes during the production of ammonia are accounted for in the Energy chapter.
21 Ammonia production data (see Table 4-21) was obtained from Coffeyville Resources (Coffeyville 2005, 2006,
22 2007a, 2007b, 2009, 2010) and the Census Bureau of the U.S. Department of Commerce (U.S. Census Bureau 1991
23 through 1994, 1998 through 2010) as reported in Current Industrial Reports Fertilizer Materials and Related
24 Products annual and quarterly reports. Urea-ammonia nitrate production was obtained from Coffeyville Resources
25 (Coffeyville 2005, 2006, 2007a, 2007b, 2009, 2010). Urea production data for 1990 through 2008 were obtained
26 from the Minerals Yearbook: Nitrogen (USGS 1994 through 2009). Urea production data for 2009 was obtained
27 from the U.S. Bureau of the Census (2010). Import data for urea were obtained from the U.S. Census Bureau
28 Current Industrial Reports Fertilizer Materials and Related Products annual and quarterly reports for 1997 through
29 2009 (U.S. Census Bureau 1998 through 2010), The Fertilizer Institute (TFI2002) for 1993 through 1996, and the
30 United States International Trade Commission Interactive Tariff and Trade DataWeb (U.S. ITC 2002) for 1990
31 through 1992 (see Table 4-21). Urea export data for 1990 through 2009 were taken from U.S. Fertilizer
32 Import/Exports from USDA Economic Research Service Data Sets (U.S. Department of Agriculture 2010).
33 Table 4-21: Ammonia Production, Urea Production, Urea Net Imports, and Urea Exports (Gg)
34
Year
1990
2000
2005
2006
2007
2008
2009
Ammonia Production
15,425
14,342
10,143
9,962
10,393
9,570
9,372
Urea Production
7,450
6,910
5,270
5,410
5,590
5,240
5,084
Urea Applied
as Fertilizer
3,296
4,382
4,779
4,985
5,097
4,925
4,295
Urea Imports
1,860
3,904
5,026
5,029
6,546
5,459
5,505
Urea Exports
854
663
536
656
271
230
289
35 Uncertainty and Time-Series Consistency
36 The uncertainties presented in this section are primarily due to how accurately the emission factor used represents an
37 average across all ammonia plants using natural gas feedstock. Uncertainties are also associated with natural gas
38 feedstock consumption data for the U.S. ammonia industry as a whole, the assumption that all ammonia production
39 and subsequent urea production was from the same process—conventional catalytic reforming of natural gas
40 feedstock, with the exception of one ammonia production plant located in Kansas that is manufacturing ammonia
41 from petroleum coke feedstock. It is also assumed that ammonia and urea are produced at collocated plants from the
4-18 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 same natural gas raw material.
2 Such recovery may or may not affect the overall estimate of CO2 emissions depending upon the end use to which the
3 recovered CO2 is applied. Further research is required to determine whether byproduct CO2 is being recovered from
4 other ammonia production plants for application to end uses that are not accounted for elsewhere.
5 Additional uncertainty is associated with the estimate of urea consumed for non-fertilizer purposes. Emissions
6 associated with this consumption are reported in this source category, while those associated with consumption as
7 fertilizer are reported in Cropland Remaining Cropland section of the Land Use, Land-Use Change, and Forestry
8 chapter. The amount of urea used for non-fertilizer purposes is estimated based on estimates of urea production, net
9 urea imports, and the amount of urea used as fertilizer. There is uncertainty associated with the accuracy of these
10 estimates as well as the fact that each estimate is obtained from a different data source.
11 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-22. Ammonia Production and
12 Urea Consumption CO2 emissions were estimated to be between 10.9 and 12.7 Tg CO2 Eq. at the 95 percent
13 confidence level. This indicates a range of approximately 7 percent below and 8 percent above the emission
14 estimate of 11.8 Tg CO2 Eq.
15 Table 4-22: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Ammonia Production and Urea
16 Consumption (Tg CO2 Eq. and Percent)
Source
2009 Emission
Gas Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate"
(TgC02Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Ammonia Production
and Urea Consumption CO2 11.8 10.9 12.7 -7% +8%
17 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
18 Note that this uncertainty range (-7 percent/+8 percent) has decreased by 7 percent compared to the uncertainty
19 range in the previous Inventory (+/-11 percent), due to two stoichiometric variables being removed from the
20 uncertainty analysis. Furthermore, methodological recalculations were applied to the entire time-series to ensure
21 time-series consistency from 1990 through 2009. Details on the emission trends through time are described in more
22 detail in the Methodology section, above.
23 Planned Improvements
24 Future improvements to the ammonia production and urea consumption category involve evaluating facility level
25 greenhouse gas emissions data as a basis for improving emissions calculations from ammonia production.
26 Beginning in 2010, all U.S. ammonia production facilities will be required to monitor, calculate and report their
27 greenhouse gas emissions to EPA through its Greenhouse Gas Reporting Program. Under the program, EPA will
28 obtain data for 2010 emissions from facilities based on use of higher tier methods and in particular assess how this
29 data could be used to improve the overall method for calculating emissions from U.S. ammonia production.
30 Specifically, the planned improvements include assessing data to update the emission factors to include both fuel
31 and feedstock CO2 emissions and incorporate CO2 capture and storage. Methodologies will also be updated if
32 additional ammonia-production plants are found to use hydrocarbons other than natural gas for ammonia production.
33 Additional efforts will be made to find consistent data sources for urea consumption and to report emissions from
34 this consumption appropriately as defined.
35 4.6. Nitric Acid Production (IPCC Source Category 2B2)
36 Nitric acid (HNO3) is an inorganic compound used primarily to make synthetic commercial fertilizers. It is also a
37 major component in the production of adipic acid—a feedstock for nylon—and explosives. Virtually all of the nitric
38 acid produced in the United States is manufactured by the catalytic oxidation of ammonia (EPA 1997). During this
39 reaction, N2O is formed as a by-product and is released from reactor vents into the atmosphere.
40 Currently, the nitric acid industry controls for emissions of NO and NO2 (i.e., NOX). As such, the industry in the US
41 uses a combination of non-selective catalytic reduction (NSCR) and selective catalytic reduction (SCR)
42 technologies. In the process of destroying NOX, NSCR systems are also very effective at destroying N2O. However,
Industrial Processes 4-19
-------
1 NSCR units are generally not preferred in modern plants because of high energy costs and associated high gas
2 temperatures. NSCRs were widely installed in nitric plants built between 1971 and 1977. Approximately 25
3 percent of nitric acid plants use NSCR and they represent 15.3 percent of estimated national production (EPA
4 20 lOa). The remaining 84.7 percent of production occurs using SCR or extended absorption, neither of which is
5 known to reduce N2O emissions.
6 N2O emissions from this source were estimated to be 14.6 Tg CO2 Eq. (47 Gg) in 2009 (see Table 4-23). Emissions
7 from nitric acid production have decreased by 18 percent since 1990, with the trend in the time series closely
8 tracking the changes in production. Emissions decreased 11.4 percent between 2008 and 2009. Emissions have
9 decreased by 30.8 percent since 1997, the highest year of production in the time series.
10 Table 4-23: N2O Emissions from Nitric Acid Production (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq.
1990
2000
2005
2006
2007
2008
2009
17.7
19.4
16.5
16.2
19.2
16.4
14.6
Gg
57
63
53
52
62
53
47
11 Methodology
12 N2O emissions were calculated by multiplying nitric acid production by the amount of N2O emitted per unit of nitric
13 acid produced. The emission factor was determined as a weighted average of two known emission factors: 2 kg
14 N2O/metric ton HNO3 produced at plants using non-selective catalytic reduction (NSCR) systems and 9 kg
15 N2O/metric ton HNO3 produced at plants not equipped with NSCR (IPCC 2006). In the process of destroying NOX,
16 NSCR systems destroy 80 to 90 percent of the N2O, which is accounted for in the emission factor of 2 kg
17 N2O/metric ton HNO3. Approximately 25 percent of HNO3 plants in the United States are equipped with NSCR
18 representing 15.3 percent of estimated national production (EPA 2010a). Hence, the emission factor is equal to (9 x
19 0.847)+ (2 x 0.153) = 7.9 kg N2O per metric ton HNO3.
20 Nitric acid production data for 1990 through 2002 were obtained from the U.S. Census Bureau, Current Industrial
21 Reports (2006). Production data for 2003 were obtained from the U.S. Census Bureau, Current Industrial Reports
22 (2008). Production data for 2004 through 2009 were obtained from the U.S. Census Bureau, Current Industrial
23 Reports (2010) (see Table 4-24).
24 Table 4-24: Nitric Acid Production (Gg)
Year
1990
2000
2005
2006
2007
2008
2009
Gg
7,195
7,900
6,711
6,572
7,827
6,686
5,924
25 Uncertainty and Time-Series Consistency
26 The overall uncertainty associated with the 2009 N2O emissions estimate from nitric acid production was calculated
27 using the IPCC Guidelines for National Greenhouse Gas Inventories (2006) Tier 2 methodology. Uncertainty
28 associated with the parameters used to estimate N2O emissions included that of production data, the share of U.S.
29 nitric acid production attributable to each emission abatement technology over the time series, and the emission
30 factors applied to each abatement technology type.
4-20 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 The results of this Tier 2 quantitative uncertainty analysis are summarized in Table 4-25. N2O emissions from nitric
2 acid production were estimated to be between 8.8 and 20.7 Tg CO2 Eq. at the 95 percent confidence level. This
3 indicates a range of approximately 40 percent below to 42 percent above the 2009 emissions estimate of 14.6 Tg
4 CO2 Eq.
5 Table 4-25: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from Nitric Acid Production (Tg CO2 Eq.
6 and Percent)
Source
Gas
2009 Emission
Estimate
(TgC02Eq.)
Uncertainty Range Relative to Emission Estimate"
(TgC02Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Nitric Acid Production
N2O
14.6
8.8 20.7 -40% +42%
7 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
8 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
9 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
10 above.
11 Planned Improvements
12 Future improvements to the nitric acid production category involve evaluating facility level greenhouse gas
13 emissions data as a basis for improving emissions calculations from nitric acid production. Beginning in 2010, all
14 U.S. nitric acid production facilities will be required to monitor, calculate and report their greenhouse gas emissions
15 to EPA through its Greenhouse Gas Reporting Program. Under the program, EPA will obtain data for 2010
16 emissions from facilities based on use of higher tier methods and in particular assess how this data could be used to
17 improve the overall method for calculating emissions from U.S. nitric acid production. Specifically, the planned
18 improvements include assessing data to update the N2O emission factors, abatement utilization and destruction
19 factors, and the current share of nitric acid production attributable to various abatement technologies.
20 Recalculations Discussion
21 Historical estimates for N2O emissions from nitric acid production have been revised relative to the previous
22 inventory based on updated information from US EPA (2010) on abatement technologies in use and based on
23 revised production data published by the U.S. Census Bureau (2010). The previous Inventory assumed that
24 approximately 17 percent of facilities accounting for less than 8 percent of national production were equipped with
25 NSCR systems (EPA 2010b). The current Inventory assumes that approximately 25 percent of facilities accounting
26 forroughly 15 percent of national production were equipped with NSCR systems (EPA2010a). This change
27 resulted in a decrease in the weighted average emission factor of 0.6 kg N2O/metric ton HNO3 (6.3 percent).
28 Additionally, national nitric acid production values for 1991, 1993-1995, 1997-1999, 2002, and 2008 have been
29 updated relative to the previous Inventory (US Census Bureau 2009, 2010). Revised production in 2008 contributed
30 to an overall decrease in emissions of 2.6 TgCO2Eq. (13.6 percent) in that year; revised production in the other
31 historical years had a negligible impact on emissions. Overall, changes relative to the previous Inventory resulted in
32 an average annual decrease in emissions of 1.3 Tg CO2Eq. (6.7 percent) for the period 1990 through 2008.
33 4.7. Adipic Acid Production (IPCC Source Category 2B3)
34 Adipic acid production is an anthropogenic source of N2O emissions. Worldwide, few adipic acid plants exist. The
35 United States and Europe are the major producers. In 2009, the United States had two companies with a total of
36 three adipic acid processes, two of which were operational (CW 2007; Desai 2010; VA DEQ 2009). The United
37 States accounts for the largest share of global adipic acid production capacity (30 percent), followed by the
38 European Union (29 percent) and China (22 percent) (SEI2010). Adipic acid is a white crystalline solid used in the
39 manufacture of synthetic fibers, plastics, coatings, urethane foams, elastomers, and synthetic lubricants.
40 Commercially, it is the most important of the aliphatic dicarboxylic acids, which are used to manufacture polyesters.
41 84 percent of all adipic acid produced in the United States is used in the production of nylon 6,6; nine percent is
42 used in the production of polyester polyols; four percent is used in the production of plasticizers; and the remaining
43 four percent is accounted for by other uses, including unsaturated polyester resins and food applications (ICIS
Industrial Processes 4-21
-------
1 2007). Food grade adipic acid is used to provide some foods with a "tangy" flavor (Thiemens and Trogler 1991).
2 Adipic acid is produced through a two-stage process during which N2O is generated in the second stage. The first
3 stage of manufacturing usually involves the oxidation of cyclohexane to form a cyclohexanone/cyclohexanol
4 mixture. The second stage involves oxidizing this mixture with nitric acid to produce adipic acid. N2O is generated
5 as a by-product of the nitric acid oxidation stage and is emitted in the waste gas stream (Thiemens and Trogler
6 1991). Process emissions from the production of adipic acid vary with the types of technologies and level of
7 emission controls employed by a facility. In 1990, two of the three major adipic acid-producing plants had N2O
8 abatement technologies in place and, as of 1998, the three major adipic acid production facilities had control systems
9 in place (Reimer et al. 1999). One small plant, which last operated in April 2006 and represented approximately two
10 percent of production, did not control for N2O (VA DEQ 2009; ICIS 2007; VA DEQ 2006).
11 N2O emissions from adipic acid production were estimated to be 1.9 Tg CO2 Eq. (6 Gg) in 2009 (see Table 4-26).
12 National adipic acid production has increased by approximately 11 percent over the period of 1990 through 2009, to
13 roughly 820,000 metric tons. Over the same period, emissions have been reduced by 88 percent due to both the
14 widespread installation of pollution control measures in the late 1990s and plant idling in the late 2000s. In April
15 2006, the smallest of the four facilities ceased production of adipic acid (VA DEQ 2009); furthermore, one of the
16 major adipic acid production facilities was not operational in 2009 (Desai 2010).
17 Table 4-26: N2O Emissions from Adipic Acid Production (Tg CO2 Eq. and Gg)
Year
1990
2000
2005
2006
2007
2008
2009
Tg CO2 Eq.
15.8
5.5
5.0
4.3
3.7
2.0
1.9
Gg
51
18
16
14
12
7
6
is Methodology
19 Due to confidential business information, plant names are not provided in this section. The four adipic acid-
20 producing plants will henceforth be referred to as Plants 1 through 4.
21 For Plants 1 and 2, 1990 to 2009 emission estimates were obtained directly from the plant engineer and account for
22 reductions due to control systems in place at these plants during the time series (Desai 2010). These estimates were
23 based on continuous emissions monitoring equipment installed at the two facilities. In 2009, no Adipic acid
24 production occurred at Plant 1. For Plants 3 and 4, N2O emissions were calculated by multiplying adipic acid
25 production by an emission factor (i.e., N2O emitted per unit of adipic acid produced) and adjusting for the
26 percentage of N2O released as a result of plant-specific emission controls. On the basis of experiments, the overall
27 reaction stoichiometry for N2O production in the preparation of adipic acid was estimated at approximately 0.3
28 metric tons of N2O per metric ton of product (IPCC 2006). Emissions are estimated using the following equation:
29 N2O emissions = (production of adipic acid [metric tons {MT} of adipic acid]) x (0.3 MT N2O / MT adipic acid) x
30 (1 - [N2O destruction factor x abatement system utility factor])
31 The "N2O destruction factor" represents the percentage of N2O emissions that are destroyed by the installed
32 abatement technology. The "abatement system utility factor" represents the percentage of time that the abatement
33 equipment operates during the annual production period. Overall, in the United States, two of the plants employ
34 catalytic destruction (Plants 1 and 2), one plant employs thermal destruction (Plant 3), and the smallest plant used no
35 N2O abatement equipment (Plant 4). For Plant 3, which uses thermal destruction and for which no reported plant-
36 specific emissions are available, the N2O abatement system destruction factor is assumed to be 98.5 percent, and the
37 abatement system utility factor is assumed to be 97 percent (IPCC 2006).
38 From 1990 to 2003, plant-specific production data were estimated for Plant 3 where direct emission measurements
39 were not available. In order to calculate plant-specific production for this plant, national adipic acid production was
40 allocated to the plant level using the ratio of known plant capacity to total national capacity for all U.S. plants. The
4-22 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 estimated plant production for this plant was then used for calculating emissions as described above. For 2004 and
2 2006, actual plant production data were obtained and used for emission calculations (CW 2007; CW 2005). For
3 2005, interpolated national production was used for calculating emissions. Updated production data were not
4 available for Plant 3 for 2007 through 2009; therefore, production values for 2007 through 2009 were proxied using
5 2006 data.
6 For Plant 4, which last operated in April 2006 (VA DEQ 2009), plant-specific production data were obtained across
7 the time series from 1990 through 2008 (VA DEQ 2010). Since the plant has not operated since 2006, production in
8 2009 is assumed to be equal to the 2008 estimate, which was zero. The plant-specific production data were then used
9 for calculating emissions as described above.
10 National adipic acid production data (see Table 4-27) from 1990 through 2009 were obtained from the American
11 Chemistry Council (ACC 2010).
12 Plant capacities for 1990 through 1994 were obtained from Chemical and Engineering News, "Facts and Figures"
13 and "Production of Top 50 Chemicals" (C&EN 1992 through 1995). Plant capacities for 1995 and 1996 were kept
14 the same as 1994 data. The 1997 plant capacities were taken from Chemical Market Reporter "Chemical Profile:
15 Adipic Acid" (CMR 1998). The 1998 plant capacities for all four plants and 1999 plant capacities for three of the
16 plants were obtained from Chemical Week, Product Focus: Adipic Acid/Adiponitrile (CW 1999). Plant capacities
17 for 2000 for three of the plants were updated using Chemical Market Reporter, "Chemical Profile: Adipic Acid"
18 (CMR 2001). For 2001 through 2005, the plant capacities for three plants were kept the same as the year 2000
19 capacities. Plant capacity for 1999 to 2005 for the one remaining plant was kept the same as 1998. For 2004 to
20 2009, although some plant capacity data are available (CW 1999, CMR 2001, ICIS 2007), they are not used to
21 calculate plant-specific production for these years because plant-specific production data for 2004 and 2006 are also
22 available and are used in our calculations instead (CW 2005, CW 2007).
23 Table 4-27: Adipic Acid Production (Gg)
Year Gg
1990 735
2000 925
2005 903
2006 964
2007 930
2008 869
2009 819
24 Uncertainty and Time-Series Consistency
25 The overall uncertainty associated with the 2009 N2O emission estimate from adipic acid production was calculated
26 using the IPCC Guidelines for National Greenhouse Gas Inventories (2006) Tier 2 methodology. Uncertainty
27 associated with the parameters used to estimate N2O emissions included that of company specific production data,
28 emission factors for abated and unabated emissions, and company-specific historical emissions estimates.
29 The results of this Tier 2 quantitative uncertainty analysis are summarized in Table 4-28. N2O emissions from
30 adipic acid production were estimated to be between 1.2 and 2.8 Tg CO2 Eq. at the 95 percent confidence level.
31 This indicates a range of approximately 40 percent below to 42 percent above the 2009 emission estimate of 1.9 Tg
32 CO2 Eq.
33 Table 4-28: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from Adipic Acid Production (Tg CO2
34 Eq. and Percent)
Source
Gas
2009 Emission
Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Adipic Acid Production
N2O
1.9
1.2 2.8 -40% +42%
35 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Industrial Processes 4-23
-------
1 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
2 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
3 above.
4 Recalculations
5 The current Inventory uses national production data from the ACC (2010) across the full time series. Previous
6 Inventories relied upon a variety of sources and linear interpolation for missing intervening years in the national
7 production time series. This change resulted in an average annual decrease in the national production estimate of
8 approximately 2 percent for the period 1990 through 2008 relative to the previous Inventory. Emissions decreased
9 by less than 0.1 percent over the same time period relative to the previous Inventory.
10 Planned Improvements
11 Future improvements to the adipic acid production category involve evaluating facility level greenhouse gas
12 emissions data as a basis for improving emissions calculations from adipic acid production. Beginning in 2010, all
13 U.S. adipic acid production facilities will be required to monitor, calculate and report their greenhouse gas emissions
14 to EPA through its Greenhouse Gas Reporting Program. Under the program, EPA will obtain data for 2010
15 emissions from facilities based on use of higher tier methods and in particular assess how this data could be used to
16 improve the overall method for calculating emissions from U.S. adipic acid production. Specifically, the planned
17 improvements include assessing data to update the N2O emission factors and update abatement utility and
18 destruction factors based on actual performance of the latest catalytic and thermal abatement equipment at plants
19 with continuous process and emission monitoring equipment.
20 4.8. Silicon Carbide Production (IPCC Source Category 2B4) and Consumption
21 CO2 and CH4 are emitted from the production110 of silicon carbide (SiC), a material used as an industrial abrasive.
22 To make SiC, quartz (SiO2) is reacted with C in the form of petroleum coke. A portion (about 35 percent) of the C
23 contained in the petroleum coke is retained in the SiC. The remaining C is emitted as CO2, CH4, or CO.
24 CO2 is also emitted from the consumption of SiC for metallurgical and other non-abrasive applications. The USGS
25 reports that a portion (approximately 50 percent) of SiC is used in metallurgical and other non-abrasive applications,
26 primarily in iron and steel production (USGS 2006).
27 CO2 from SiC production and consumption in 2009 were 0.1 Tg CO2 Eq. (145 Gg) (USGS 2009). Approximately
28 63 percent of these emissions resulted from SiC production while the remainder results from SiC consumption. CH4
29 emissions from SiC production in 2009 were 0.01 Tg CO2 Eq. CH4 (0.4 Gg) (see Table 4-29 and Table 4-30).
30 Table 4-29: CO2 and CH4 Emissions from Silicon Carbide Production and Consumption (Tg CO2 Eq.)
Year
C02
CH4
Total
1990
0.4
+
0.4
2000
0.2
+
0.3
2005
0.2
+
0.2
2006
0.2
+
0.2
2007
0.2
+
0.2
2008
0.2
+
0.2
2009
0.1
+
0.2
31 + Does not exceed 0.05 Tg CO2 Eq.
32 Note: Totals may not sum due to independent rounding.
33
34 Table 4-30: CO2 and CH4 Emissions from Silicon Carbide Production and Consumption (Gg)
Year 1990 2000 2005 2006 2007 2008 2009
CO2 375 248 219 207 196 175 145
CH4 1 1 + + + + +_
35 + Does not exceed 0.5 Gg.
110 Silicon carbide is produced for both abrasive and metallurgical applications in the United States. Production for metallurgical
applications is not available and therefore both CELt and CO2 estimates are based solely upon production estimates of silicon
carbide for abrasive applications.
4-24 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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i Methodology
2 Emissions of CO2 and CH4 from the production of SiC were calculated by multiplying annual SiC production by the
3 emission factors (2.62 metric tons CO2/metric ton SiC for CO2 and 11.6 kg CH^metric ton SiC for CH4) provided
4 by the 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006).
5 Emissions of CO2 from silicon carbide consumption were calculated by multiplying the annual SiC consumption
6 (production plus net imports) by the percent used in metallurgical and other non-abrasive uses (50 percent) (USGS
7 2009). The total SiC consumed in metallurgical and other non-abrasive uses was multiplied by the C content of SiC
8 (31.5 percent), which was determined according to the molecular weight ratio of SiC.
9 Production data for 1990 through 2008 were obtained from the Minerals Yearbook: Manufactured Abrasives (USGS
10 1991a through 2005a, 2007, and 2009). Production data for 2009 was taken from the Minerals Commodity
11 Summary: Abrasives (Manufactured) (USGS 2010). Silicon carbide consumption by major end use was obtained
12 from the Minerals Yearbook: Silicon (USGS 1991b through 2005b) (see Table 4-31) for years 1990 through 2004
13 and from the USGS Minerals Commodity Specialist for 2005 and 2006 (Corathers 2006, 2007). Silicon carbide
14 consumption by major end use data for 2009 is proxied using 2008 data due to unavailability of data at time of
15 publication. Net imports for the entire time series were obtained from the U.S. Census Bureau (2005 through 2010).
16 Table 4-31: Production and Consumption of Silicon Carbide (Metric Tons)
Year Production Consumption
1990 105,000 172,465
2000 45,000 225,070
17
2005
2006
2007
2008
2009
35,000
35,000
35,000
35,000
35,000
220,149
199,937
179,741
144,928
92,280
is Uncertainty and Time-Series Consistency
19 There is uncertainty associated with the emission factors used because they are based on stoichiometry as opposed to
20 monitoring of actual SiC production plants. An alternative would be to calculate emissions based on the quantity of
21 petroleum coke used during the production process rather than on the amount of silicon carbide produced. However,
22 these data were not available. For CH4, there is also uncertainty associated with the hydrogen-containing volatile
23 compounds in the petroleum coke (IPCC 2006). There is also some uncertainty associated with production, net
24 imports, and consumption data as well as the percent of total consumption that is attributed to metallurgical and
25 other non-abrasive uses.
26 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-32. Silicon carbide production
27 and consumption CO2 emissions were estimated to be between 9 percent below and 9 percent above the emission
28 estimate of 0.2 Tg CO2 Eq. at the 95 percent confidence level. Silicon carbide production CH4 emissions were
29 estimated to be between 9 percent below and 9 percent above the emission estimate of 0.01 Tg CO2 Eq. at the 95
30 percent confidence level.
31 Table 4-32: Tier 2 Quantitative Uncertainty Estimates for CH4 and CO2 Emissions from Silicon Carbide Production
32 and Consumption (Tg CO2 Eq. and Percent)
2009 Emission
Source Gas Estimate Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Silicon Carbide Production
and Consumption
Silicon Carbide Production
CO2 0.2
CH4 +
Lower Upper Lower
Bound Bound Bound
0.13 0.16 -9%
+ + -9%
Upper
Bound
+9%
+9%
33 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
34 + Does not exceed 0.05 Tg CO2 Eq. or 0.5 Gg.
Industrial Processes 4-25
-------
1 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
2 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
3 above.
4 Planned Improvements
5 Future improvements to the silicon carbide production source category include evaluating facility level greenhouse
6 gas emissions data as a basis for improving emissions calculations from silicon carbide production. Beginning in
7 2010, all U. S. silicon carbide production facilities will be required to monitor, calculate and report their greenhouse
8 gas emissions to EPA through its Greenhouse Gas Reporting Program. Under the program, EPA will obtain data for
9 2010 emissions from facilities based on use of higher tier methods and in particular assess how this data could be
10 used to improve the overall method for calculating emissions from the U.S. silicon carbide production industry. In
11 addition, improvements will involve continued research to determine if calcium carbide production and consumption
12 data are available for the United States. If these data are available, calcium carbide emission estimates will be
13 included in this source category. Additionally, as future improvement to the silicon carbide uncertainty analysis,
14 USGS Mineral Commodity Specialists will be contacted to verify the uncertainty range associated with silicon
15 carbide emissive utilization.
16 4.9. Petrochemical Production (IPCC Source Category 2B5)
17 The production of some petrochemicals results in the release of small amounts of CH4 and CO2 emissions.
18 Petrochemicals are chemicals isolated or derived from petroleum or natural gas. CH4 emissions are presented here
19 from the production of carbon black, ethylene, ethylene dichloride, and methanol, while CO2 emissions are
20 presented here for only carbon black production. The CO2 emissions from petrochemical processes other than
21 carbon black are currently included in the Carbon Stored in Products from Non-Energy Uses of Fossil Fuels Section
22 of the Energy chapter. The CO2 from carbon black production is included here to allow for the direct reporting of
23 CO2 emissions from the process and direct accounting of the feedstocks used in the process.
24 Carbon black is an intense black powder generated by the incomplete combustion of an aromatic petroleum or coal-
25 based feedstock. Most carbon black produced in the United States is added to rubber to impart strength and abrasion
26 resistance, and the tire industry is by far the largest consumer. Ethylene is consumed in the production processes of
27 the plastics industry including polymers such as high, low, and linear low density polyethylene (HDPE, LDPE,
28 LLDPE), polyvinyl chloride (PVC), ethylene dichloride, ethylene oxide, and ethylbenzene. Ethylene dichloride is
29 one of the first manufactured chlorinated hydrocarbons with reported production as early as 1795. In addition to
30 being an important intermediate in the synthesis of chlorinated hydrocarbons, ethylene dichloride is used as an
31 industrial solvent and as a fuel additive. Methanol is an alternative transportation fuel as well as a principle
32 ingredient in windshield wiper fluid, paints, solvents, refrigerants, and disinfectants. In addition, methanol-based
33 acetic acid is used in making PET plastics and polyester fibers.
34 Emissions of CO2 and CH4 from petrochemical production in 2009 were 2.7 Tg CO2 Eq. (2,735 Gg) and 0.8 Tg CO2
35 Eq. (40 Gg), respectively (see Table 4-33 and Table 4-34), totaling 3.6 Tg CO2 Eq. There has been an overall
36 decrease in CO2 emissions from carbon black production of 17 percent since 1990. CH4 emissions from
37 petrochemical production decreased by approximately two percent since 1990.
38 Table 4-33: CO2 and CH4 Emissions from Petrochemical Production (Tg CO2 Eq.)
39
40
41
Year
C02
CH4
Total
1990
3.3
0.9
4.2
2000
4.5
1.2
5.7
2005
4.2
1.1
5.3
2006
3.8
1.0
4.8
2007
3.9
1.0
4.9
2008
3.4
0.9
4.4
2009
2.7
0.8
3.6
Note: Totals may not sum due to independent rounding.
Table 4-34:
Year
C02
CH4
CO2and
1990
3,311
41
CH4 Emissions from Petrochemical Production (Gg)
2000
4,479
59
2005
4,181
51
2006
3,837
48
2007
3,931
48
2008
3,449
43
2009
2,735
40
42
4-26 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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i Methodology
2 Emissions of CH4 were calculated by multiplying annual estimates of chemical production by the appropriate
3 emission factor, as follows: 11 kg CH4/metric ton carbon black, 1 kg CH^metric ton ethylene, 0.4 kg CH^metric ton
4 ethylene dichloride,111 and 2 kg CH^metric ton methanol. Although the production of other chemicals may also
5 result in CH4 emissions, insufficient data were available to estimate their emissions.
6 Emission factors were taken from the Revised 1996 IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997). Annual
7 production data (see Table 4-35) were obtained from the American Chemistry Council's Guide to the Business of
8 Chemistry (ACC 2002, 2003, 2005 through 2010) and the International Carbon Black Association (Johnson 2003,
9 2005 through 2010). Note that 2009 production data for Methanol was not available at time of publication, as such,
10 2008 methanol production is used as a proxy for 2009.
11 Table 4-35: Production of Selected Petrochemicals (Thousand Metric Tons)
Chemical
Carbon Black
Ethylene
Ethylene Dichloride
Methanol
1990
1,307
16,541
6,282
3,785
2000
1,769
24,970
9,866
5,221
2005
1,651
23,954
11,260
2,336
2006
1,515
25,000
9,736
1,123
2007
1,552
25,392
9,566
1,068
2008
1,362
22,539
8,981
1,136
2009
1,080
22,596
8,131
1,136
12
13 Almost all carbon black in the United States is produced from petroleum-based or coal-based feedstocks using the
14 "furnace black" process (European IPPC Bureau 2004). The furnace black process is a partial combustion process
15 in which a portion of the carbon black feedstock is combusted to provide energy to the process. Carbon black is also
16 produced in the United States by the thermal cracking of acetylene-containing feedstocks ("acetylene black
17 process") and by the thermal cracking of other hydrocarbons ("thermal black process"). One U.S carbon black plant
18 produces carbon black using the thermal black process, and one U.S. carbon black plant produces carbon black
19 using the acetylene black process (The Innovation Group 2004).
20 The furnace black process produces carbon black from "carbon black feedstock" (also referred to as "carbon black
21 oil"), which is a heavy aromatic oil that may be derived as a byproduct of either the petroleum refining process or
22 the metallurgical (coal) coke production process. For the production of both petroleum-derived and coal-derived
23 carbon black, the "primary feedstock" (i.e., carbon black feedstock) is injected into a furnace that is heated by a
24 "secondary feedstock" (generally natural gas). Both the natural gas secondary feedstock and a portion of the carbon
25 black feedstock are oxidized to provide heat to the production process and pyrolyze the remaining Carbon black
26 feedstock to carbon black. The "tail gas" from the furnace black process contains CO2, carbon monoxide, sulfur
27 compounds, CH4, and non-CH4 volatile organic compounds. A portion of the tail gas is generally burned for energy
28 recovery to heat the downstream carbon black product dryers. The remaining tail gas may also be burned for energy
29 recovery, flared, or vented uncontrolled to the atmosphere.
30 The calculation of the C lost during the production process is the basis for determining the amount of CO2 released
31 during the process. The C content of national carbon black production is subtracted from the total amount of C
32 contained in primary and secondary carbon black feedstock to find the amount of C lost during the production
33 process. It is assumed that the C lost in this process is emitted to the atmosphere as either CH4 or CO2. The C
34 content of the CH4 emissions, estimated as described above, is subtracted from the total C lost in the process to
3 5 calculate the amount of C emitted as CO2. The total amount of primary and secondary carbon black feedstock
36 consumed in the process (see
37 Table 4-36) is estimated using a primary feedstock consumption factor and a secondary feedstock consumption
38 factor estimated from U.S. Census Bureau (1999, 2004, and 2007) data. The average carbon black feedstock
39 consumption factor for U.S. carbon black production is 1.69 metric tons of carbon black feedstock consumed per
40 metric ton of carbon black produced. The average natural gas consumption factor for U.S. carbon black production
41 is 321 normal cubic meters of natural gas consumed per metric ton of carbon black produced. The amount of C
42 contained in the primary and secondary feedstocks is calculated by applying the respective C contents of the
43 feedstocks to the respective levels of feedstock consumption (EIA 2003, 2004).
111 The emission factor obtained from IPCC/UNEP/OECD/IEA (1997), page 2.23 is assumed to have a misprint; the chemical
identified should be ethylene dichloride (C2H4C12) rather than dichloroethylene (C2H2C12).
Industrial Processes 4-27
-------
2 Table 4-36: Carbon Black Feedstock (Primary Feedstock) and Natural Gas Feedstock (Secondary Feedstock)
3 Consumption (Thousand Metric Tons)
Activity
Primary Feedstock
Secondary Feedstock
1990
2,213
284
2000
2,993
384
2005
2,794
359
2006
2,564
329
2007
2,627
337
2008
2,305
296
2009
1,828
235
5 For the purposes of emissions estimation, 100 percent of the primary carbon black feedstock is assumed to be
6 derived from petroleum refining byproducts. Carbon black feedstock derived from metallurgical (coal) coke
7 production (e.g., creosote oil) is also used for carbon black production; however, no data are available concerning
8 the annual consumption of coal-derived carbon black feedstock. Carbon black feedstock derived from petroleum
9 refining byproducts is assumed to be 89 percent elemental C (Srivastava et al. 1999). It is assumed that 100 percent
10 of the tail gas produced from the carbon black production process is combusted and that none of the tail gas is
11 vented to the atmosphere uncontrolled. The furnace black process is assumed to be the only process used for the
12 production of carbon black because of the lack of data concerning the relatively small amount of carbon black
13 produced using the acetylene black and thermal black processes. The carbon black produced from the furnace black
14 process is assumed to be 97 percent elemental C (Othmer et al. 1992).
15 Uncertainty and Time-Series Consistency
16 The CH4 emission factors used for petrochemical production are based on a limited number of studies. Using plant-
17 specific factors instead of average factors could increase the accuracy of the emission estimates; however, such data
18 were not available. There may also be other significant sources of CH4 arising from petrochemical production
19 activities that have not been included in these estimates.
20 The results of the quantitative uncertainty analysis for the CO2 emissions from carbon black production calculation
21 are based on feedstock consumption, import and export data, and carbon black production data. The composition of
22 carbon black feedstock varies depending upon the specific refinery production process, and therefore the assumption
23 that carbon black feedstock is 89 percent C gives rise to uncertainty. Also, no data are available concerning the
24 consumption of coal-derived carbon black feedstock, so CO2 emissions from the utilization of coal-based feedstock
25 are not included in the emission estimate. In addition, other data sources indicate that the amount of petroleum-
26 based feedstock used in carbon black production may be underreported by the U.S. Census Bureau. Finally, the
27 amount of carbon black produced from the thermal black process and acetylene black process, although estimated to
28 be a small percentage of the total production, is not known. Therefore, there is some uncertainty associated with the
29 assumption that all of the carbon black is produced using the furnace black process.
30 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-37. Petrochemical production
31 CO2 emissions were estimated to be between 2.0 and 3.6 Tg CO2 Eq. at the 95 percent confidence level. This
32 indicates a range of approximately 27 percent below to 31 percent above the emission estimate of 2.7 Tg CO2 Eq.
33 Petrochemical production CH4 emissions were estimated to be between 0.6 and 1.1 Tg CO2 Eq. at the 95 percent
34 confidence level. This indicates a range of approximately 26 percent below to 27 percent above the emission
3 5 estimate of 0.8 Tg CO2 Eq.
36 Table 4-37: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Petrochemical Production and CO2
37 Emissions from Carbon Black Production (Tg CO2 Eq. and Percent)
2009 Emission
Source Gas Estimate
(Tg C02 Eq.)
Petrochemical Production CO2
Petrochemical Production CH4
2.7
0.8
Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (%)
Lower
Bound
2.0
0.6
Upper
Bound
3.6
1.1
Lower
Bound
-27%
-26%
Upper
Bound
+31%
+27%
38 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
39 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
40 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
41 above.
4-28 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
i Planned Improvements
2 Future improvements to the petrochemicals source category involve evaluating facility level greenhouse gas
3 emissions data as a basis for improving emissions calculations from petrochemical production. Beginning in 2010,
4 all U.S. petrochemical production facilities will be required to monitor, calculate and report their greenhouse gas
5 emissions to EPA through its Greenhouse Gas Reporting Program. Under the program, EPA will obtain data for
6 2010 emissions from facilities based on use of higher tier methods and in particular assess how this data could be
7 used to improve the overall method for calculating emissions from the U.S. petrochemical production industry, for
8 example using a Tier 2 methodology to calculate emissions from the production of methanol, ethylene, propylene,
9 ethylene dichloride, and ethylene oxide. In addition, the planned improvements include assessing the data EPA
10 obtains to update data sources for acrylonitrile production in the United States.
11 4.10. Titanium Dioxide Production (IPCC Source Category 2B5)
12 Titanium dioxide (TiO2) is a metal oxide manufactured from titanium ore, and is principally used as a pigment.
13 Titanium dioxide is a principal ingredient in white paint, and is also used as a pigment in the manufacture of white
14 paper, foods, and other products. There are two processes for making TiO2: the chloride process and the sulfate
15 process. The chloride process uses petroleum coke and chlorine as raw materials and emits process-related CO2.
16 The sulfate process does not use petroleum coke or other forms of C as a raw material and does not emit CO2.
17 The chloride process is based on the following chemical reactions:
18 2 FeTiO3 + 7 C12 + 3 C -» 2 TiCL, + 2 FeCl3 + 3 CO2
19 2 TiCL, + 2 O2 -» 2 TiO2 + 4 C12
20 The C in the first chemical reaction is provided by petroleum coke, which is oxidized in the presence of the chlorine
21 and FeTiO3 (the Ti-containing ore) to form CO2. The majority of U.S. TiO2 was produced in the United States
22 through the chloride process, and a special grade of "calcined" petroleum coke is manufactured specifically for this
23 purpose.
24 Emissions of CO2 in 2009 were 1.5 TgCO2Eq. (1,541 Gg), which represents an increase of 29 percent since 1990
25 (see Table 4-38).
26 Table 4-3 8: CO2 Emissions from Titanium Dioxide (Tg CO2 Eq. and Gg)
Year 1
1990
2000
2005
2006
2007
2008
2009
27
fg CO2 Eq.
1.2
1.8
1.8
1.8
1.9
1.8
1.5
Gg
1,195
1,752
,755
,836
,930
,809
,541
28 Methodology
29 Emissions of CO2 from TiO2 production were calculated by multiplying annual TiO2 production by chloride-
30 process-specific emission factors.
31 Data were obtained for the total amount of TiO2 produced each year. For years previous to 2004, it was assumed
32 that TiO2 was produced using the chloride process and the sulfate process in the same ratio as the ratio of the total
33 U.S. production capacity for each process. As of 2004, the last remaining sulfate-process plant in the United States
34 had closed; therefore, 100 percent of post-2004 production uses the chloride process (USGS 2005). An emission
35 factor of 0.4 metric tons C/metric ton TiO2 was applied to the estimated chloride-process production. It was
36 assumed that all TiO2 produced using the chloride process was produced using petroleum coke, although some TiO2
37 may have been produced with graphite or other C inputs. The amount of petroleum coke consumed annually in
38 TiO2 production was calculated based on the assumption that the calcined petroleum coke used in the process is 98.4
Industrial Processes 4-29
-------
1 percent C and 1.6 percent inert materials (Nelson 1969).
2 The emission factor for the TiO2 chloride process was taken from the 2006 IPCC Guidelines for National
3 Greenhouse Gas Inventories (IPCC 2006). Titanium dioxide production data and the percentage of total TiO2
4 production capacity that is chloride process for 1990 through 2008 (see Table 4-39) were obtained through the
5 Minerals Yearbook: Titanium Annual Report (USGS 1991 through 2008). Production data in 2009 was obtained
6 from the Minerals Commodity Summary: Titanium and Titanium Dioxide (USGS 2010). Due to lack of available
7 2009 capacity data at the time of publication, the 2008 capacity estimate is used as a proxy for 2009. Percentage
8 chloride-process data were not available for 1990 through 1993, and data from the 1994 USGS Minerals Yearbook
9 were used for these years. Because a sulfate-process plant closed in September 2001, the chloride-process
10 percentage for 2001 was estimated based on a discussion with Joseph Gambogi (2002). By 2002, only one sulfate
11 plant remained online in the United States and this plant closed in 2004 (USGS 2005).
12 Table 4-39: Titanium Dioxide Production (Gg)
Year
1990
2000
2005
2006
2007
2008
2009
G£
979
1,400
,310
,370
,440
,350
,150
13
14 Uncertainty and Time-Series Consistency
15 Although some TiO2 may be produced using graphite or other C inputs, information and data regarding these
16 practices were not available. Titanium dioxide produced using graphite inputs, for example, may generate differing
17 amounts of CO2 per unit of TiO2 produced as compared to that generated through the use of petroleum coke in
18 production. While the most accurate method to estimate emissions would be to base calculations on the amount of
19 reducing agent used in each process rather than on the amount of TiO2 produced, sufficient data were not available
20 to do so.
21 Also, annual TiO2 is not reported by USGS by the type of production process used (chloride or sulfate). Only the
22 percentage of total production capacity by process is reported. The percent of total TiO2 production capacity that
23 was attributed to the chloride process was multiplied by total TiO2 production to estimate the amount of TiO2
24 produced using the chloride process (since, as of 2004, the last remaining sulfate-process plant in the United States
25 closed). This assumes that the chloride-process plants and sulfate-process plants operate at the same level of
26 utilization. Finally, the emission factor was applied uniformly to all chloride-process production, and no data were
27 available to account for differences in production efficiency among chloride-process plants. In calculating the
28 amount of petroleum coke consumed in chloride-process TiO2 production, literature data were used for petroleum
29 coke composition. Certain grades of petroleum coke are manufactured specifically for use in the TiO2 chloride
30 process; however, this composition information was not available.
31 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-40. Titanium dioxide
32 consumption CO2 emissions were estimated to be between 1.4 and 1.7 Tg CO2 Eq. at the 95 percent confidence
33 level. This indicates a range of approximately 13 percent below and 13 percent above the emission estimate of 1.5
34 Tg CO2 Eq.
35
36
37
38
39
4-30 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Table 4-40: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Titanium Dioxide Production (Tg
2 CO2 Eq. and Percent)
2009 Emission
Source Gas Estimate Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper
Bound
Titanium Dioxide Production CO2 L5 L3 1/7 -13% +13%
3 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
4 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
5 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
6 above.
7 Planned Improvements
8 Future improvements to the titanium dioxide production category involve evaluating facility level greenhouse gas
9 emissions data as a basis for improving emissions calculations from titanium dioxide production. Beginning in
10 2010, all U. S. titanium dioxide production facilities using the chloride production process will be required to
11 monitor, calculate and report their greenhouse gas emissions to EPA through its Greenhouse Gas Reporting
12 Program. Under the program, EPA will obtain data for 2010 emissions from facilities based on use of higher tier
13 methods and in particular assess how this data could be used to improve the overall method for calculating
14 emissions from the U.S. titanium dioxide production industry, including improving the emission factors. In
15 addition, the planned improvements include researching the significance of titanium-slag production in electric
16 furnaces and synthetic-rutile production using the Becher process in the United States. Significant use of these
17 production processes will be included in future estimates.
is 4.11. Carbon Dioxide Consumption (IPCC Source Category 2B5)
19 CO2 is used for a variety of commercial applications, including food processing, chemical production, carbonated
20 beverage production, and refrigeration, and is also used in petroleum production for enhanced oil recovery (EOR).
21 CO2 used for EOR is injected into the underground reservoirs to increase the reservoir pressure to enable additional
22 petroleum to be produced.
23 For the most part, CO2 used in non-EOR applications will eventually be released to the atmosphere, and for the
24 purposes of this analysis CO2 used in commercial applications other than EOR is assumed to be emitted to the
25 atmosphere. CO2 used in EOR applications is discussed in the Energy Chapter under "Carbon Capture and Storage,
26 including Enhanced Oil Recovery" and is not discussed in this section.
27 CO2 is produced from naturally occurring CO2 reservoirs, as a by-product from the energy and industrial production
28 processes (e.g., ammonia production, fossil fuel combustion, ethanol production), and as a by-product from the
29 production of crude oil and natural gas, which contain naturally occurring CO2 as a component. Only CO2 produced
30 from naturally occurring CO2 reservoirs and used in industrial applications other than EOR is included in this
31 analysis. Neither by-product CO2 generated from energy nor industrial production processes nor CO2 separated
32 from crude oil and natural gas are included in this analysis for a number of reasons. CO2 captured from biogenic
33 sources (e.g., ethanol production plants) is not included in the inventory. CO2 captured from crude oil and gas
34 production is used in EOR applications and is therefore reported in the Energy Chapter. Any CO2 captured from
35 industrial or energy production processes (e.g., ammonia plants, fossil fuel combustion) and used in non-EOR
36 applications is assumed to be emitted to the atmosphere. The CO2 emissions from such capture and use are
37 therefore accounted for under Ammonia Production, Fossil Fuel Combustion, or other appropriate source category.
38 "2
39 CO2 is produced as a by-product of crude oil and natural gas production. This CO2 is separated from the crude oil
112 There are currently four known electric power plants operating in the U.S. that capture CO2 for use as food-grade CO2 or
other industrial processes; however, insufficient data prevents estimating emissions from these activities as part of Carbon
Dioxide Consumption.
Industrial Processes 4-31
-------
1 and natural gas using gas processing equipment, and may be emitted directly to the atmosphere, or captured and
2 reinjected into underground formations, used for EOR, or sold for other commercial uses. A further discussion of
3 CO2 used in EOR is described in the Energy Chapter under the text box titled "Carbon Dioxide Transport, Injection,
4 and Geological Storage." The only CO2 consumption that is accounted for in this analysis is CO2 produced from
5 naturally-occurring CO2 reservoirs that is used in commercial applications other than EOR.
6 There are currently two facilities, one in Mississippi and one in New Mexico, producing CO2 from naturally
7 occurring CO2 reservoirs for use in both EOR and in other commercial applications (e.g., chemical manufacturing,
8 food production). There are other naturally occurring CO2 reservoirs, mostly located in the western U.S. Facilities
9 are producing CO2 from these natural reservoirs, but they are only producing CO2 for EOR applications, not for
10 other commercial applications (Allis et al. 2000). CO2 production from these facilities is discussed in the Energy
11 Chapter.
12 In 2009, the amount of CO2 produced by the Mississippi and New Mexico facilities for commercial applications and
13 subsequently emitted to the atmosphere was 1.8 Tg CO2Eq. (1,763 Gg) (see Table 4-41). This amount represents a
14 decrease of one percent from the previous year and an increase of 24 percent since 1990. This increase was due to
15 an in increase in production at the Mississippi facility, despite the decrease in the percent of the facility's total
16 reported production that was used for commercial applications.
17 Table 4-41: CO2 Emissions from CO2 Consumption (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq.
1990
2000
2005
2006
2007
2008
2009
1.4
1.4
1.3
1.7
1.9
1.8
1.8
Gg
1,416
1,421
1,321
1,709
1,867
1,780
1,763
18
19 Methodology
20 CO2 emission estimates for 1990 through 2009 were based on production data for the two facilities currently
21 producing CO2 from naturally-occurring CO2 reservoirs for use in non-EOR applications. Some of the CO2
22 produced by these facilities is used for EOR and some is used in other commercial applications (e.g., chemical
23 manufacturing, food production). It is assumed that 100 percent of the CO2 production used in commercial
24 applications other than EOR is eventually released into the atmosphere.
25 CO2 production data for the Jackson Dome, Mississippi facility and the percentage of total production that was used
26 for EOR and in non-EOR applications were obtained from the Advanced Resources Institute (ARI2006, 2007) for
27 1990 to 2000 and from the Annual Reports for Denbury Resources (Denbury Resources 2002 through 2010) for
28 2001 to 2009 (see Table 4-42). Denbury Resources reported the average CO2 production in units of MMCF CO2 per
29 day for 2001 through 2009 and reported the percentage of the total average annual production that was used for
30 EOR. CO2 production data for the Bravo Dome, New Mexico facility were obtained from the Advanced Resources
31 International, Inc. (ARI 1990 through 2010). The percentage of total production that was used for EOR and in non-
32 EOR applications were obtained from the New Mexico Bureau of Geology and Mineral Resources (Broadhead 2003
33 and New Mexico Bureau of Geology and Mineral Resources 2006).
34 Table 4-42: CO2 Production (Gg CO2) and the Percent Used for Non-EOR Applications for Jackson Dome and
35 Bravo Dome
Year
1990
2000
Jackson Dome CO2
Production (Gg)
1,353
1,353
Jackson Dome %
Used for Non-EOR
100%
100%
Bravo Dome CO2
Production (Gg)
6,301
6,834
Bravo Dome % Used
for Non-EOR
1%
1%
4-32 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
2005
2006
2007
2008
2009
4,678
6,610
9,529
12,312
13,201
27%
25%
19%
14%
13%
5,799
5,613
5,605
5,605
4,639
1%
1%
1%
1%
1%
i Uncertainty and Time-Series Consistency
2 Uncertainty is associated with the number of facilities that are currently producing CO2 from naturally occurring
3 CO2 reservoirs for commercial uses other than EOR, and for which the CO2 emissions are not accounted for
4 elsewhere. Research indicates that there are only two such facilities, which are in New Mexico and Mississippi;
5 however, additional facilities may exist that have not been identified. In addition, it is possible that CO2 recovery
6 exists in particular production and end-use sectors that are not accounted for elsewhere. Such recovery may or may
7 not affect the overall estimate of CO2 emissions from that sector depending upon the end use to which the recovered
8 CO2 is applied. Further research is required to determine whether CO2 is being recovered from other facilities for
9 application to end uses that are not accounted for elsewhere.
10 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-43. CO2 consumption CO2
11 emissions were estimated to be between 1.3 and 2.2 Tg CO2 Eq. at the 95 percent confidence level. This indicates a
12 range of approximately 25 percent below to 27 percent above the emission estimate of 1.8 Tg CO2 Eq.
13 Table 4-43: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from CO2 Consumption (Tg CO2 Eq. and
14 Percent)
Source
Gas
2009 Emission
Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (%)
Lower Bound Upper Bound Lower Bound Upper Bound
CO2 Consumption CO2 L8 1.3 22 -25% +27%
15 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
16 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
17 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
18 above.
19 Planned Improvements
20 Future improvements to the Carbon Dioxide Consumption source category involve evaluating facility level
21 greenhouse gas emissions data as a basis for improving emissions calculations from carbon dioxide consumption.
22 Beginning in 2010, all U.S. CO2 producers will be required to monitor, calculate and report the quantity of CO2
23 supplied to EPA through its Greenhouse Gas Reporting Program. Under the program, EPA will obtain data for 2010
24 on CO2 supplied from facilities based on use of higher tier methods and in particular assess how this data could be
25 used to improve the overall method for calculating emissions from consumption of CO2
26 4.12. Phosphoric Acid Production (IPCC Source Category 2B5)
21 Phosphoric acid (H3PO4) is a basic raw material in the production of phosphate-based fertilizers. Phosphate rock is
28 mined in Florida, North Carolina, Idaho, Utah, and other areas of the United States and is used primarily as a raw
29 material for phosphoric acid production. The production of phosphoric acid from phosphate rock produces
30 byproduct gypsum (CaSO4-2H2O), referred to as phosphogypsum.
31 The composition of natural phosphate rock varies depending upon the location where it is mined. Natural phosphate
32 rock mined in the United States generally contains inorganic C in the form of calcium carbonate (limestone) and
33 also may contain organic C. The chemical composition of phosphate rock (francolite) mined in Florida is:
34 Ca10-x-y Nax Mgy (PO4)6-x(CO3)xF2+o.4x
35 The calcium carbonate component of the phosphate rock is integral to the phosphate rock chemistry. Phosphate
36 rock can also contain organic C that is physically incorporated into the mined rock but is not an integral component
37 of the phosphate rock chemistry. Phosphoric acid production from natural phosphate rock is a source of CO2
Industrial Processes 4-33
-------
1 emissions, due to the chemical reaction of the inorganic C (calcium carbonate) component of the phosphate rock.
2 The phosphoric acid production process involves chemical reaction of the calcium phosphate (Ca3(PO4)2)
3 component of the phosphate rock with sulfuric acid (H2SO4) and recirculated phosphoric acid (H3PO4) (EFMA
4 2000). The primary chemical reactions for the production of phosphoric acid from phosphate rock are:
5 Ca3(PO4)2 + 4H3PO4 -> 3Ca(H2PO4)2
6 3 Ca(H2PO4)2 + 3H2SO4 + 6H2O -> 3 CaSO4 • 6H2O + 6H3PO4
7 The limestone (CaCO3) component of the phosphate rock reacts with the sulfuric acid in the phosphoric acid
8 production process to produce calcium sulfate (phosphogypsum) and CO2. The chemical reaction for the limestone-
9 sulfuric acid reaction is:
10 CaCO3+H2SO4 +H2O -> CaSO4 • 2H2O + CO2
11 Total marketable phosphate rock production in 2009 was 27.2 million metric tons (USGS 2010). Approximately
12 87 percent of domestic phosphate rock production was mined in Florida and North Carolina, while approximately 13
13 percent of production was mined in Idaho and Utah. Total imports of phosphate rock in 2009 was 1.8 million metric
14 tons (USGS 2010). The vast majority, 99 percent, of imported phosphate rock is sourced from Morocco (USGS
15 2005). Marketable phosphate rock production, including domestic production and imports for consumption,
16 decreased by 13.6 percent between 2008 and 2009. Over the 1990 to 2009 period, production has decreased by 34
17 percent. Total CO2 emissions from phosphoric acid production were 1.0 Tg CO2 Eq. (1,035 Gg) in 2009 (see Table
18 4-44). According to USGS 2010, the weak market conditions of phosphate rock in the U.S. in 2009 were a result of
19 the global economic crisis that started in late 2008 and carried into 2009.
20 Table 4-44: CO2 Emissions from Phosphoric Acid Production (Tg CO2 Eq. and Gg)
Year
1990
2000
2005
2006
2007
2008
2009
Tg CO2 Eq.
1.5
1.4
1.4
1.2
1.2
1.2
1.0
Gg
1,529
1,382
1,386
1,167
1,166
1,187
1,035
21
22 Methodology
23 CO2 emissions from production of phosphoric acid from phosphate rock are calculated by multiplying the average
24 amount of calcium carbonate contained in the natural phosphate rock by the amount of phosphate rock that is used
25 annually to produce phosphoric acid, accounting for domestic production and net imports for consumption.
26 The CO2 emissions calculation methodology is based on the assumption that all of the inorganic C (calcium
27 carbonate) content of the phosphate rock reacts to CO2 in the phosphoric acid production process and is emitted with
28 the stack gas. The methodology also assumes that none of the organic C content of the phosphate rock is converted
29 to CO2 and that all of the organic C content remains in the phosphoric acid product.
30 From 1993 to 2004, the USGS Mineral Yearbook: Phosphate Rock disaggregated phosphate rock mined annually in
31 Florida and North Carolina from phosphate rock mined annually in Idaho and Utah, and reported the annual
32 amounts of phosphate rock exported and imported for consumption (see Table 4-45). For the years 1990, 1991,
33 1992, 2005, 2006, and 2007 only nationally aggregated mining data was reported by USGS. For these years, the
34 breakdown of phosphate rock mined in Florida and North Carolina, and the amount mined in Idaho and Utah, are
35 approximated using 1993 to 2004 data. Data for domestic production of phosphate rock, exports of phosphate rock
36 (primarily from Florida and North Carolina), and imports of phosphate rock for consumption for 1990 through 2008
37 were obtained from USGS Minerals Yearbook: Phosphate Rock (USGS 1994 through 2010). 2009 data were
38 obtained from USGS Minerals Commodity Summary: Phosphate Rock (USGS 2010). From 2004 through 2009, the
39 USGS reported no exports of phosphate rock from U.S. producers (USGS 2005 through 2010).
4-34 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 The carbonate content of phosphate rock varies depending upon where the material is mined. Composition data for
2 domestically mined and imported phosphate rock were provided by the Florida Institute of Phosphate Research
3 (FIPR 2003). Phosphate rock mined in Florida contains approximately 1 percent inorganic C, and phosphate rock
4 imported from Morocco contains approximately 1.46 percent inorganic C. Calcined phosphate rock mined in North
5 Carolina and Idaho contains approximately 0.41 percent and 0.27 percent inorganic C, respectively (see Table 4-46).
6 Carbonate content data for phosphate rock mined in Florida are used to calculate the CO2 emissions from
7 consumption of phosphate rock mined in Florida and North Carolina (87 percent of domestic production) and
8 carbonate content data for phosphate rock mined in Morocco are used to calculate CO2 emissions from consumption
9 of imported phosphate rock. The CO2 emissions calculation is based on the assumption that all of the domestic
10 production of phosphate rock is used in uncalcined form. As of 2006, the USGS noted that one phosphate rock
11 producer in Idaho produces calcined phosphate rock; however, no production data were available for this single
12 producer (USGS 2006). Carbonate content data for uncalcined phosphate rock mined in Idaho and Utah (13 percent
13 of domestic production) were not available, and carbonate content was therefore estimated from the carbonate
14 content data for calcined phosphate rock mined in Idaho.
15 Table 4-45: Phosphate Rock Domestic Production, Exports, and Imports (Gg)
Location/Year 1990 2000 2005 2006 2007 2008 2009
16
17
18
19
20
21
22
U.S. Production3
FL&NC
ID&UT
Exports— FL & NC
Imports — Morocco
Total U.S.
Consumption
49,800
42,494
7,306
6,240
451
44,011
37,370
31,900
5,470
299
1,930
39,001
36,100
31,227
4,874
2,630
38,730
30,100
26,037
4,064
2,420
32,520
29,700
25,691
4,010
2,670
32,370
a USGS does not disaggregate production data regionally (FL & NC and ID & UT) for 1990,
those years are estimated based on the remaining time series distribution.
- Assumed equal to zero.
Table 4-46: Chemical Composition of Phosphate Rock (percent by weight)
Composition
Total Carbon (as C)
Inorganic Carbon (as C)
Organic Carbon (as C)
Inorganic Carbon (as CO2)
Source: FIPR 2003
- Assumed equal to zero.
Central
Florida
1.60
1.00
0.60
3.67
North Carolina
North Florida (calcined)
1.76
0.93
0.83
3.43
0.76
0.41
0.35
1.50
30,
26,
4,
2,
200
123
077
754
32,954
2005,
27,200
23,528
3,672
1,800
29,000
2006, and 2007.
Idaho (calcined)
0.60
0.27
1.00
Data for
Morocco
1.56
1.46
0.10
5.00
23 Uncertainty and Time-Series Consistency
24 Phosphate rock production data used in the emission calculations were developed by the USGS through monthly and
25 semiannual voluntary surveys of the active phosphate rock mines during 2009. For previous years in the time series,
26 USGS provided the data disaggregated regionally; however, beginning in 2006 only total U.S. phosphate rock
27 production were reported. Regional production for 2008 was estimated based on regional production data from
28 previous years and multiplied by regionally-specific emission factors. There is uncertainty associated with the
29 degree to which the estimated 2008 regional production data represents actual production in those regions. Total
30 U.S. phosphate rock production data are not considered to be a significant source of uncertainty because all the
31 domestic phosphate rock producers report their annual production to the USGS. Data for exports of phosphate rock
32 used in the emission calculation are reported by phosphate rock producers and are not considered to be a significant
33 source of uncertainty. Data for imports for consumption are based on international trade data collected by the U.S.
34 Census Bureau. These U.S. government economic data are not considered to be a significant source of uncertainty.
35 An additional source of uncertainty in the calculation of CO2 emissions from phosphoric acid production is the
36 carbonate composition of phosphate rock; the composition of phosphate rock varies depending upon where the
37 material is mined, and may also vary over time. Another source of uncertainty is the disposition of the organic C
3 8 content of the phosphate rock. A representative of the FIPR indicated that in the phosphoric acid production
Industrial Processes 4-35
-------
1 process, the organic C content of the mined phosphate rock generally remains in the phosphoric acid product, which
2 is what produces the color of the phosphoric acid product (FIPR 2003a). Organic C is therefore not included in the
3 calculation of CO2 emissions from phosphoric acid production.
4 A third source of uncertainty is the assumption that all domestically-produced phosphate rock is used in phosphoric
5 acid production and used without first being calcined. Calcination of the phosphate rock would result in conversion
6 of some of the organic C in the phosphate rock into CO2. However, according to the USGS, only one producer in
7 Idaho is currently calcining phosphate rock, and no data were available concerning the annual production of this
8 single producer (USGS 2005). For available years, total production of phosphate rock in Utah and Idaho combined
9 amounts to approximately 13 percent of total domestic production on average (USGS 1994 through 2005).
10 Finally, USGS indicated that approximately 7 percent of domestically-produced phosphate rock is used to
11 manufacture elemental phosphorus and other phosphorus-based chemicals, rather than phosphoric acid (USGS
12 2006). According to USGS, there is only one domestic producer of elemental phosphorus, in Idaho, and no data
13 were available concerning the annual production of this single producer. Elemental phosphorus is produced by
14 reducing phosphate rock with coal coke, and it is therefore assumed that 100 percent of the carbonate content of the
15 phosphate rock will be converted to CO2 in the elemental phosphorus production process. The calculation for CO2
16 emissions is based on the assumption that phosphate rock consumption, for purposes other than phosphoric acid
17 production, results in CO2 emissions from 100 percent of the inorganic C content in phosphate rock, but none from
18 the organic C content.
19 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-47. Phosphoric acid
20 production CO2 emissions were estimated to be between 0.9 and 1.2 Tg CO2 Eq. at the 95 percent confidence level.
21 This indicates a range of approximately 18 percent below and 19 percent above the emission estimate of 1.0 Tg CO2
22 Eq.
23 Table 4-47: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Phosphoric Acid Production (Tg
24 CO2 Eq. and Percent)
2009 Emission
Source Gas Estimate Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper Bound
Phosphoric Acid Production CO2 LO 0.9 L2 -18% +19%
25 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
26 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
27 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
28 above.
29 Planned Improvements
30 Future improvements to the phosphoric acid production source category involve evaluating facility level greenhouse
31 gas emissions data as a basis for improving emissions calculations from phosphoric acid production. Beginning in
32 2010, all U.S. phosphoric acid producers will be required to monitor, calculate and report their greenhouse gas
33 emissions to EPA through its Greenhouse Gas Reporting Program. Under the program, EPA will obtain data for
34 2010 from facilities based on use of higher tier methods and assess how this data could be used to improve the
35 method for calculating emissions from the U.S. phosphoric acid production industry. Currently, data sources for the
36 carbonate content of the phosphate rock are limited. If additional data sources are found, this information will be
37 incorporated into future estimates. Additionally, as future improvement to the phosphoric acid uncertainty analysis,
38 USGS Mineral Commodity Specialists will be contacted to verify uncertainty ranges associated with phosphate rock
39 imports and exports.
40 4.13. Iron and Steel Production (IPCC Source Category 2C1) and Metallurgical
41 Coke Production
42 The production of iron and steel is an energy-intensive activity that also generates process-related emissions of CO2
43 and CH4. Process emissions occur at each step of steel production from the production of raw materials to the
4-36 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 refinement of iron to the making of crude steel. In the United States, steel is produced through both primary and
2 secondary processes. Historically, primary production—using a basic oxygen furnace (EOF) with pig iron as the
3 primary feedstock—has been the dominant method. But secondary production through the use scrap steel and
4 electric arc furnaces (EAFs) has increased significantly in recent years due to the economic advantages of steel
5 recycling, which has been driven by the increased availability of scrap steel. Total production of crude steel in the
6 United States in the time period between 2001 and 2008 ranged from a low of 99,321,000 tons to a high of
7 109,879,000 tons (2001 and 2004, respectively). But due to the decrease in demand caused by the global economic
8 downturn, crude steel production in the United States decreased to 65,460,000 tons in 2009 (AISI2010).
9 Metallurgical coke is an important input in the production of iron and steel. Coke is used to produce iron or pig iron
10 feedstock from raw iron ore. The production of metallurgical coke from coking coal occurs both on-site at
11 "integrated" iron and steel plants and off-site at "merchant" coke plants. Metallurgical coke is produced by heating
12 coking coal in a coke oven in a low-oxygen environment. The process drives off the volatile components of the
13 coking coal and produces coal (metallurgical) coke. Carbon containing byproducts of the metallurgical coke
14 manufacturing process include coke oven gas, coal tar, coke breeze (small-grade coke oven coke with particle size
15 <5mm) and light oil. Coke oven gas is recovered and used for underfiring the coke ovens and within the iron and
16 steel mill. Small amounts of coke oven gas are also sold as synthetic natural gas outside of iron and steel mills (and
17 are accounted for in the Energy chapter). Coal tar is used as a raw material to produce anodes used for primary
18 aluminum production, electric arc furnace (EAF) steel production, and other electrolytic processes, and also is used
19 in the production of other coal tar products. Light oil is sold to petroleum refiners who use the material as an
20 additive for gasoline. The metallurgical coke production process produces CO2 emissions and fugitive CH4
21 emissions.
22 Iron is produced by first reducing iron oxide (iron ore) with metallurgical coke in a blast furnace. Iron can be
23 introduced into the blast furnace in the form of raw iron ore, taconite pellets (9-16mm iron-containing spheres),
24 briquettes, or sinter. In addition to metallurgical coke and iron, other inputs to the blast furnace include natural gas,
25 fuel oil, and coke oven gas. The carbon in the metallurgical coke used in the blast furnace combines with oxides in
26 the iron ore in a reducing atmosphere to produce blast furnace gas containing carbon monoxide (CO) and CO2. The
27 CO is then converted and emitted as CO2 when combusted to either pre-heat the blast air used in the blast furnace or
28 for other purposes at the steel mill. This pig iron or crude iron that is produced from this process contains about 3 to
29 5 percent carbon by weight. The pig iron production process in a blast furnace produces CO2 emissions and fugitive
30 CH4 emissions.
31 Iron can also be produced through the direct reduction process; wherein, iron ore is reduced to metallic iron in the
32 solid state at process temperatures less than 1000°C. Direct reduced iron production results in process emissions of
33 CO2 and emissions of CH4 through the consumption of natural gas used during the reduction process.
34 Sintering is a thermal process by which fine iron-bearing particles, such as air emission control system dust, are
35 baked, which causes the material to agglomerate into roughly one-inch pellets that are then recharged into the blast
36 furnace for pig iron production. Iron ore particles may also be formed into larger pellets or briquettes by mechanical
37 means, and then agglomerated by heating. The agglomerate is then crushed and screened to produce an iron-bearing
38 feed that is charged into the blast furnace. The sintering process produces CO2 and fugitive CH4 emissions through
39 the consumption of carbonaceous inputs (e.g., coke breeze) during the sintering process.
40 Steel is produced from varying levels of pig iron and scrap steel in specialized EOF and EAF steel-making furnaces.
41 Carbon inputs to EOF steel-making furnaces include pig iron and scrap steel as well as natural gas, fuel oil, and
42 fluxes (e.g., limestone, dolomite). In a EOF, the carbon in iron and scrap steel combines with high-purity oxygen to
43 reduce the carbon content of the metal to the amount desired for the specified grade of steel. EAFs use carbon
44 electrodes, charge carbon and other materials (e.g., natural gas) to aid in melting metal inputs (primarily recycled
45 scrap steel), which are refined and alloyed to produce the desired grade of steel. CO2 emissions occur in BOFs
46 through the reduction process. In EAFs, CO2 emissions result primarily from the consumption of carbon electrodes
47 and also from the consumption of supplemental materials used to augment the melting process.
48 In addition to the production processes mentioned above, CO2 is also generated at iron and steel mills through the
49 consumption of process by-products (e.g., blast furnace gas, coke oven gas) used for various purposes including
50 heating, annealing, and electricity generation. Process by-products sold for use as synthetic natural gas are deducted
51 and reported in the Energy chapter (emissions associated with natural gas and fuel oil consumption for these
52 purposes are reported in the Energy chapter).
Industrial Processes 4-37
-------
1 The majority of CO2 emissions from the iron and steel production process come from the use of metallurgical coke
2 in the production of pig iron and from the consumption of other process by-products at the iron and steel mill, with
3 lesser amounts emitted from the use of flux and from the removal of carbon from pig iron used to produce steel.
4 Some carbon is also stored in the finished iron and steel products.
5 According to the 2006IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006), the production of
6 metallurgical coke from coking coal is considered to be an energy use of fossil fuel and the use of coke in iron and
7 steel production is considered to be an industrial process source. Therefore, the Guidelines suggest that emissions
8 from the production of metallurgical coke should be reported separately in the Energy source, while emissions from
9 coke consumption in iron and steel production should be reported in the industrial process source. However, the
10 approaches and emission estimates for both metallurgical coke production and iron and steel production are both
11 presented here because the activity data used to estimate emissions from metallurgical coke production have
12 significant overlap with activity data used to estimate iron and steel production emissions. Further, some by-
13 products (e.g., coke oven gas) of the metallurgical coke production process are consumed during iron and steel
14 production, and some by-products of the iron and steel production process (e.g., blast furnace gas) are consumed
15 during metallurgical coke production. Emissions associated with the consumption of these by-products are
16 attributed to point of consumption. As an example, CO2 emissions associated with the combustion of coke oven gas
17 in the blast furnace during pig iron production are attributed to pig iron production. Emissions associated with the
18 use of conventional fuels (e.g., natural gas and fuel oil) for electricity generation, heating and annealing, or other
19 miscellaneous purposes downstream of the iron and steelmaking furnaces are reported in the Energy chapter.
20 Metallurgical Coke Production
21 Emissions of CO2 and CH4 from metallurgical coke production in 2009 were 1.0 Tg CO2 Eq. (956 Gg) and less than
22 0.002 Tg CO2 Eq. (less than 0.00003 Gg), respectively (see Table 4-48 and Table 4-49), totaling 1.0 Tg CO2 Eq.
23 Emissions decreased in 2009, and have decreased overall since 1990. In 2009, domestic coke production decreased
24 by 29 percent and has decreased overall since 1990. Coke production in 2009 was 46 percent lower than in 2000
25 and 60 percent below 1990. Overall, emissions from metallurgical coke production have declined by 61 percent (1.5
26 Tg CO2 Eq.) from 1990 to 2009.
27 Table 4-48: CO2 and CH4 Emissions from Metallurgical Coke Production (Tg CO2 Eq.)
Year
C02
CH4
Total
1990
2.5
+
2.5
2000
2.2
+
2.2
2005
2.0
+
2.0
2006
1.9
+
1.9
2007
2.1
+
2.1
2008
2.3
+
2.3
2009
1.0
+
1.0
28 + Does not exceed 0.05 Tg CO2 Eq.
29
30 Table 4-49: CO2 and CH4 Emissions from Metallurgical Coke Production (Gg)
31
Year 1990
CO2 2,470
CH4 +
+ Does not exceed 0.5 Gg
2000
2,195
2005
2,043
2006
1,919
2007
2,054
2008
2,334
2009
956
32 Iron and Steel Production
33 Emissions of CO2 and CH4 from iron and steel production in 2009 were 41.6 Tg CO2 Eq. (41,619 Gg) and 0.4 Tg
34 CO2 Eq. (17.4 Gg), respectively (see Table 4-50 through Table 4-53), totaling approximately 42 Tg CO2 Eq.
35 Emissions decreased in 2009—largely due to decreased steel production associated with the global economic
36 downturn—and have decreased overall since 1990 due to restructuring of the industry, technological improvements,
37 and increased scrap steel utilization. CO2 emission estimates include emissions from the consumption of
38 carbonaceous materials in the blast furnace, EAF, and EOF as well as blast furnace gas and coke oven gas
39 consumption for other activities at the steel mill.
40 In 2009, domestic production of pig iron decreased by 44 percent. Overall, domestic pig iron production has
41 declined since the 1990s. Pig iron production in 2009 was 60 percent lower than in 2000 and 62 percent below
42 1990. CO2 emissions from steel production have declined by 5 percent (0.4 Tg CO2 Eq.) since 1990, while overall
43 CO2 emissions from iron and steel production have declined by 57 percent (55.4 Tg CO2 Eq.) from 1990 to 2009.
4-38 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Table 4-50: CO2 Emissions from Iron and Steel Production (Tg CO2 Eq.)
Year
Sinter Production
Iron Production
Steel Production
Other Activities3
Total
1990
2.4
47.9
7.5
39.3
97.1
2000
2.2
33.8
7.9
39.9
83.7
2005
1.7
19.6
8.5
34.2
63.9
2006
1.4
23.9
8.9
32.6
66.9
2007
1.4
27.3
9.4
31.0
69.0
2008
1.3
25.7
7.5
29.1
63.7
2009
0.8
15.9
7.1
17.8
41.6
2 Note: Totals may not sum due to independent rounding.
3 a Includes emissions from blast furnace gas and coke oven gas combustion for activities at the steel mill other than consumption
4 in blast furnace, EAFs, or BOFs.
5
6 Table 4-51: CO2 Emissions from Iron and Steel Production (Gg)
Year
Sinter Production
Iron Production
Steel Production
Other Activities a
Total
1990
2,448
47,880
7,475
39,256
97,058
2000
2,158
33,818
7,887
39,877
83,728
2005
1,663
19,570
8,489
34,160
63,882
2006
1,418
23,928
8,924
32,583
66,852
2007
1,383
27,262
9,382
30,964
68,991
2008
1,299
25,696
7,541
29,146
63,682
2009
763
15,948
7,094
17,815
41,619
7 Note: Totals may not sum due to independent rounding.
8 a Includes emissions from blast furnace gas and coke oven gas combustion for activities at the steel mill other than consumption
9 in blast furnace, EAFs, or BOFs.
10
11 Table 4-52: CH4 Emissions from Iron and Steel Production (Tg CO2 Eq.)
12
13
14
15
Year
Sinter Production
Iron Production
Total
+ Does not exceed 0.05 Tg CO
1990 2000 2005 2006 2007 2008 2009
+
0.9
1.0
2Eq.
+
0.9
0.9
+
0.7
0.7
+ + + +
0.7 0.7 0.6 0.4
0.7 0.7 0.6 0.4
Note: Totals may not sum due to independent rounding.
Table 4-53 : CH4 Emissions
Year
Sinter Production
Iron Production
Total
from Iron and Steel Production (Gg)
1990
0.9
44.7
45.6
2000
0.7
43.1
43.8
2005
0.6
33.5
34.1
2006 2007 2008 2009
0.5 0.5 0.4 0.3
34.1 32.7 30.4 17.1
34.6 33.2 30.8 17.4
16 Note: Totals may not sum due to independent rounding.
17 Methodology
18 Emission estimates presented in this chapter are based on the methodologies provided by the 2006IPCC Guidelines
19 for National Greenhouse Gas Inventories (IPCC 2006), which call for a mass balance accounting of the
20 carbonaceous inputs and outputs during the iron and steel production process and the metallurgical coke production
21 process.
22 Metallurgical Coke Production
23 Coking coal is used to manufacture metallurgical (coal) coke that is used primarily as a reducing agent in the
24 production of iron and steel, but is also used in the production of other metals including lead and zinc (see Lead
25 Production and Zinc Production in this chapter). Emissions associated with producing metallurgical coke from
26 coking coal are estimated and reported separately from emissions that result from the iron and steel production
27 process. To estimate emission from metallurgical coke production, a Tier 2 method provided by the 2006 IPCC
28 Guidelines for National Greenhouse Gas Inventories (IPCC 2006) was utilized. The amount of carbon contained in
29 materials produced during the metallurgical coke production process (i.e., coke, coke breeze, coke oven gas, and
30 coal tar) is deducted from the amount of carbon contained in materials consumed during the metallurgical coke
31 production process (i.e., natural gas, blast furnace gas, coking coal). Light oil, which is produced during the
Industrial Processes 4-39
-------
1 metallurgical coke production process, is excluded from the deductions due to data limitations. The amount of
2 carbon contained in these materials is calculated by multiplying the material-specific carbon content by the amount
3 of material consumed or produced (see Table 4-54). The amount of coal tar produced was approximated using a
4 production factor of 0.03 tons of coal tar per ton of coking coal consumed. The amount of coke breeze produced
5 was approximated using a production factor of 0.075 tons of coke breeze per ton of coking coal consumed. Data on
6 the consumption of carbonaceous materials (other than coking coal) as well as coke oven gas production were
7 available for integrated steel mills only (i.e., steel mills with co-located coke plants). Therefore, carbonaceous
8 material (other than coking coal) consumption and coke oven gas production were excluded from emission estimates
9 for merchant coke plants. Carbon contained in coke oven gas used for coke-oven underfiring was not included in
10 the deductions to avoid double-counting.
11 Table 4-54: Material Carbon Contents for Metallurgical Coke Production
Material kgC/kg
Coal Tar 0.62
Coke 0.83
Coke Breeze 0.83
Coking Coal 0.73
Material kg C/GJ
Coke Oven Gas 12.1
Blast Furnace Gas 70.8
12 Source: IPCC 2006, Table 4.3. Coke Oven Gas and Blast Furnace Gas, Table 1.3.
13 The production processes for metallurgical coke production results in fugitive emissions of CH4, which are emitted
14 via leaks in the production equipment rather than through the emission stacks or vents of the production plants. The
15 fugitive emissions were calculated by applying Tier 1 emission factors (0.1 g CH4 per metric ton) taken from the
16 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006) for metallurgical coke production.
17 Data relating to the mass of coking coal consumed at metallurgical coke plants and the mass of metallurgical coke
18 produced at coke plants were taken from the Energy Information Administration (EIA), Quarterly Coal Report
19 October through December (EIA 1998 through 2004) and January through March (EIA 2010a) (see Table 4-55).
20 Data on the volume of natural gas consumption, blast furnace gas consumption, and coke oven gas production for
21 metallurgical coke production at integrated steel mills were obtained from the American Iron and Steel Institute
22 (AISI), Annual Statistical Report (AISI 2004 through 20010) and through personal communications with AISI
23 (2008b) (see Table 4-56). The factor for the quantity of coal tar produced per ton of coking coal consumed was
24 provided by AISI (2008b). The factor for the quantity of coke breeze produced per ton of coking coal consumed
25 was obtained through Table 2-1 of the report Energy and Environmental Profile of the U.S. Iron and Steel Industry
26 (DOE 2000). Data on natural gas consumption and coke oven gas production at merchant coke plants were not
27 available and were excluded from the emission estimate. Carbon contents for coking coal, metallurgical coke, coal
28 tar, coke oven gas, and blast furnace gas were provided by the 2006 IPCC Guidelines for National Greenhouse Gas
29 Inventories (IPCC 2006). The C content for coke breeze was assumed to equal the C content of coke.
30 Table 4-55: Production and Consumption Data for the Calculation of CO2 and CH4 Emissions from Metallurgical
31 Coke Production (Thousand Metric Tons)
Source/Activity Data 1990 2000 2005 2006 2007 2008 2009
32
33
34
Metallurgical Coke Production
Coking Coal Consumption at Coke
Plants
Coke Production at Coke Plants
Coal Breeze Production
Coal Tar Production
35,269
25,054
2,645
1,058
Table 4-56: Production and Consumption Data
Production (million ft3)
26
18
1
,254
,877
,969
788
21
15
1
,259
,167
,594
638
20,827
14,882
1,562
625
for the Calculation of CO2 Emissions
20,607
14,698
1,546
618
20
14
1
from Metallurj
,022
,194
,502
601
;ical
13,904
10,109
1,043
417
Coke
Source/Activity Data 1990 2000 2005 2006 2007 2008 2009
Metallurgical Coke Production
Coke Oven Gas Production3 250,767 149,477 114,213 114,386 109,912 103,191 66,155
Natural Gas Consumption 599 180 2,996 3,277 3,309 3,134 2,121
4-40 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Blast Furnace Gas Consumption 24,602 26,075 4,460 5,505 5,144 4,829 2,435
1 a Includes coke oven gas used for purposes other than coke oven underfiring only.
2 Iron and Steel Production
3 Emissions of CO2 from sinter production and direct reduced iron production were estimated by multiplying total
4 national sinter production and the total national direct reduced iron production by Tier 1 CO2 emission factors (see
5 Table 4-57). Because estimates of sinter production and direct reduced iron production were not available,
6 production was assumed to equal consumption.
7 Table 4-57: CO2 Emission Factors for Sinter Production and Direct Reduced Iron Production
Material Produced Metric Ton
CO2/Metric Ton
Sinter 0.2
Direct Reduced Iron 0/7
8 Source: IPCC 2006, Table 4.1.
9
10 To estimate emissions from pig iron production in the blast furnace, the amount of C contained in the produced pig
11 iron and blast furnace gas were deducted from the amount of C contained in inputs (i.e., metallurgical coke, sinter,
12 natural ore, pellets, natural gas, fuel oil, coke oven gas, direct coal injection). The C contained in the pig iron, blast
13 furnace gas, and blast furnace inputs was estimated by multiplying the material-specific carbon content by each
14 material type (see Table 4-58). Carbon in blast furnace gas used to pre-heat the blast furnace air is combusted to
15 form CO2 during this process.
16 Emissions from steel production in EAFs were estimated by deducting the C contained in the steel produced from
17 the carbon contained in the EAF anode, charge carbon, and scrap steel added to the EAF. Small amounts of C from
18 direct reduced iron, pig iron, and flux additions to the EAFs were also included in the EAF calculation. For BOFs,
19 estimates of C contained in EOF steel were deducted from carbon contained in inputs such as natural gas, coke oven
20 gas, fluxes, and pig iron. In each case, the C was calculated by multiplying material-specific carbon contents by
21 each material type (see Table 4-58). For EAFs, the amount of EAF anode consumed was approximated by
22 multiplying total EAF steel production by the amount of EAF anode consumed per metric ton of steel produced
23 (0.002 metric tons EAF anode per metric ton steel produced (AISI 2008b)). The amount of flux (e.g., limestone and
24 dolomite) used during steel manufacture was deducted from the Limestone and Dolomite Use source category to
25 avoid double-counting.
26 CO2 emissions from the consumption of blast furnace gas and coke oven gas for other activities occurring at the
27 steel mill were estimated by multiplying the amount of these materials consumed for these purposes by the material-
28 specific C content (see Table 4-58).
29 CO2 emissions associated with the sinter production, direct reduced iron production, pig iron production, steel
30 production, and other steel mill activities were summed to calculate the total CO2 emissions from iron and steel
31 production (see Table 4-50and Table 4-51).
32 Table 4-58: Material Carbon Contents for Iron and Steel Production
Material
Coke
Direct Reduced Iron
Dolomite
EAF Carbon Electrodes
EAF Charge Carbon
Limestone
Pig Iron
Steel
Material
Coke Oven Gas
Blast Furnace Gas
kgC/kg
0.83
0.02
0.13
0.82
0.83
0.12
0.04
0.01
kg C/GJ
12.1
70.8
33 Source: IPCC 2006, Table 4.3. Coke Oven Gas and Blast Furnace Gas, Table 1.3.
34
Industrial Processes 4-41
-------
1 The production processes for sinter and pig iron result in fugitive emissions of CH4, which are emitted via leaks in
2 the production equipment rather than through the emission stacks or vents of the production plants. The fugitive
3 emissions were calculated by applying Tier 1 emission factors taken from the 2006IPCC Guidelines for National
4 Greenhouse Gas Inventories (IPCC 2006) for sinter production and the 1995 IPCC Guidelines
5 (IPCC/UNEP/OECD/IEA 1995) (see Table 4-59) for pig iron production. The production of direct reduced iron also
6 results in emissions of CH4 through the consumption of fossil fuels (e.g., natural gas); however, these emissions
7 estimates are excluded due to data limitations.
8 Table 4-59: CH4 Emission Factors for Sinter and Pig Iron Production
Material Produced Factor Unit
Pig Iron 0.9 g CH4/kg
Sinter 0.07 kg CH4/metric ton
9 Source: Sinter (IPCC 2006, Table 4.2), Pig Iron (IPCC/UNEP/OECD/IEA 1995, Table 2.2)
10
11 Sinter consumption and direct reduced iron consumption data were obtained from AISI's Annual Statistical Report
12 (AISI 2004 through 2010) and through personal communications with AISI (2008b) (see Table 4-60). Data on
13 direct reduced iron consumed in EAFs were not available for the years 1990, 1991, 1999, 2006, 2007, 2008, and
14 2009. EAF direct reduced iron consumption in 1990 and 1991 were assumed to equal consumption in 1992, and
15 consumption in 1999 was assumed to equal the average of 1998 and 2000. EAF consumption in 2006, 2007, 2008,
16 and 2009 were calculated by multiplying the total DRI consumption for all furnaces as provided in the 2009 AISI
17 Annual Statistical Report by the EAF share of total DRI consumption in 2005 (the most recent year that data was
18 available for EAF vs. EOF consumption of DRI). Data on direct reduced iron consumed in BOFs were not available
19 for the years 1990 through 1994, 1999, 2006, 2007, 2008, and 2009. EOF direct reduced iron consumption in 1990
20 through 1994 was assumed to equal consumption in 1995, and consumption in 1999 was assumed to equal the
21 average of 1998 and 2000. EOF consumption in 2006, 2007, and 2008 were calculated by multiplying the total DRI
22 consumption for all furnaces as provided in the 2009 AISI Annual Statistical Report by the EOF share of total DRI
23 consumption in 2005 (the most recent year that data was available for EAF vs. EOF consumption of DRI). The Tier
24 1 CO2 emission factors for sinter production and direct reduced iron production were obtained through the 2006
25 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006). Data for pig iron production, coke, natural
26 gas, fuel oil, sinter, and pellets consumed in the blast furnace; pig iron production; and blast furnace gas produced at
27 the iron and steel mill and used in the metallurgical coke ovens and other steel mill activities were obtained from
28 AISI's Annual Statistical Report (AISI 2004 through 2010) and through personal communications with AISI
29 (2008b) (see Table 4-61). Data for EAF steel production, flux, EAF charge carbon, direct reduced iron, pig iron,
30 scrap steel, and natural gas consumption as well as EAF steel production were obtained from AISI's Annual
31 Statistical Report (AISI 2004 through 2010) and through personal communications with AISI (2008b). The factor
32 for the quantity of EAF anode consumed per ton of EAF steel produced was provided by AISI (AISI 2008b). Data
33 for EOF steel production, flux, direct reduced iron, pig iron, scrap steel, natural gas, natural ore, pellet sinter
34 consumption as well as EOF steel production were obtained from AISI's Annual Statistical Report (AISI 2004
35 through 2010) and through personal communications with AISI (2008b). Because data on pig iron consumption and
36 scrap steel consumption in BOFs and EAFs were not available for 2006, 2007, and 2009, values for these years were
37 calculated by multiplying the total pig iron and scrap steel consumption for all furnaces as provided in the 2009 AISI
38 Annual Statistical Report by the EOF and EAF shares of total pig iron and scrap consumption in 2005 (the most
39 recent year that data was available for EAF vs. EOF consumption of pig iron and scrap steel). Because pig iron
40 consumption in EAFs was also not available in 2003 and 2004, the average of 2002 and 2005 pig iron consumption
41 data were used. Data on coke oven gas and blast furnace gas consumed at the iron and steel mill other than in the
42 EAF, EOF, or blast furnace were obtained from AISI's Annual Statistical Report (AISI 2004 through 2010) and
43 through personal communications with AISI (2008b). Data on blast furnace gas and coke oven gas sold for use as
44 synthetic natural gas were obtained through EIA's Natural Gas Annual 2008 (EIA 2010b). As 2009 data were not
45 available, 2008 data were used. C contents for direct reduced iron, EAF carbon electrodes, EAF charge carbon,
46 limestone, dolomite, pig iron, and steel were provided by the 2006 IPCC Guide lines for National Greenhouse Gas
47 Inventories (IPCC 2006). The C contents for natural gas, fuel oil, and direct injection coal as well as the heat
48 contents for the same fuels were provided by EIA (1992, 2010c). Heat contents for coke oven gas and blast furnace
49 gas were provided in Table 2-2 of the report Energy and Environmental Profile of the U.S. Iron and Steel Industry
50 (DOE 2000).
51
4-42 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Table 4-60: Production and Consumption Data for the Calculation of CO2 and CH4 Emissions from Iron and Steel
2 Production (Thousand Metric Tons)
Source/Activity Data
Sinter Production
Sinter Production
Direct Reduced Iron
Production
Direct Reduced Iron
Production
Pig Iron Production
Coke Consumption
Pig Iron Production
Direct Injection Coal
Consumption
EAF Steel Production
EAF Anode and Charge
Carbon Consumption
Scrap Steel Consumption
Flux Consumption
EAF Steel Production
EOF Steel Production
Pig Iron Consumption
Scrap Steel Consumption
Flux Consumption
EOF Steel Production
1990
12,239
936
24,946
49,669
1,485
67
35,743
319
33,511
46,564
14,548
576
43,973
2000
10,788
1,914
19,215
47,888
3,012
96
43,001
654
47,860
46,993
14,969
978
53,965
2005
8,315
1,633
13,832
37,222
2,573
1,127
37,558
695
52,194
32,115
11,612
582
42,705
2006
7,088
1,497
14,684
37,904
2,526
1,245
38,033
671
56,071
32,638
11,759
610
42,119
2007
6,914
2,087
15,039
36,337
2,734
1,214
40,845
567
57,004
33,773
12,628
408
41,099
2008
6,497
1,769
14,251
33,730
2,578
1,109
40,824
680
52,791
29,322
8,029
431
39,105
2009
3,814
1,243
8,572
19,019
1,674
1,077
35,472
476
36,700
23,134
6,641
318
22,659
4 Table 4-61: Production and Consumption Data for the Calculation of CO2 Emissions from Iron and Steel
5 Production (million ft3 unless otherwise specified)
Source/Activity Data
Pig Iron Production
Natural Gas Consumption
Fuel Oil Consumption
(thousand gallons)
Coke Oven Gas
Consumption
Blast Furnace Gas
Production
EAF Steel Production
Natural Gas Consumption
EOF Steel Production
Natural Gas Consumption
Coke Oven Gas
Consumption
Other Activities
Coke Oven Gas
Consumption
Blast Furnace Gas
Consumption
1990
56,273
163,397
22,033
1,439,380
9,604
6,301
3,851
224,883
1,414,778
2000
91,798
120,921
13,702
1,524,891
13,717
6,143
640
135,135
1,498,816
2005
59,844
16,170
16,557
1,299,980
14,959
5,026
524
97,132
1,295,520
2006
58,344
87,702
16,649
1,236,526
16,070
5,827
559
97,178
1,231,021
2007
56,112
84,498
16,239
1,173,588
16,337
11,740
525
93,148
1,168,444
2008
53,349
55,552
15,336
1,104,674
15,130
-4,304a
528
87,327
1,099,845
2009
35,933
23,179
9,951
672,486
10,518
-2,670a
373
55,831
670,051
6 a EPA is continuing to work with AISI to investigate why this value is negative.
7 Uncertainty and Time-Series Consistency
8 The estimates of CO2 and CH4 emissions from metallurgical coke production are based on material production and
9 consumption data and average carbon contents. Uncertainty is associated with the total U.S. coking coal
10 consumption, total U.S. coke production and materials consumed during this process. Data for coking coal
Industrial Processes 4-43
-------
1 consumption and metallurgical coke production are from different data sources (EIA) than data for other
2 carbonaceous materials consumed at coke plants (AISI), which does not include data for merchant coke plants.
3 There is uncertainty associated with the fact that coal tar and coke breeze production were estimated based on coke
4 production because coal tar and coke breeze production data were not available. Since merchant coke plant data is
5 not included in the estimate of other carbonaceous materials consumed at coke plants, the mass balance equation for
6 CO2 from metallurgical coke production cannot be reasonably completed. Therefore, for the purpose of this
7 analysis, uncertainty parameters are applied to primary data inputs to the calculation (i.e, coking coal consumption
8 and metallurgical coke production) only.
9 The estimates of CO2 emissions from iron and steel production are based on material production and consumption
10 data and average carbon contents. There is uncertainty associated with the assumption that direct reduced iron and
11 sinter consumption are equal to production. There is uncertainty associated with the assumption that all coal used
12 for purposes other than coking coal is for direct injection coal. Some of this coal may be used for electricity
13 generation. There is also uncertainty associated with the carbon contents for pellets, sinter, and natural ore, which
14 are assumed to equal the carbon contents of direct reduced iron. For EAF steel production there is uncertainty
15 associated with the amount of EAF anode and charge carbon consumed due to inconsistent data throughout the time
16 series. Uncertainty is also associated with the use of process gases such as blast furnace gas and coke oven gas.
17 Data are not available to differentiate between the use of these gases for processes at the steel mill versus for energy
18 generation (e.g., electricity and steam generation); therefore, all consumption is attributed to iron and steel
19 production. These data and carbon contents produce a relatively accurate estimate of CO2 emissions. However,
20 there are uncertainties associated with each.
21 For the purposes of the CH4 calculation from iron and steel production it is assumed that all of the CH4 escapes as
22 fugitive emissions and that none of the CH4 is captured in stacks or vents. Additionally, the CO2 emissions
23 calculation is not corrected by subtracting the C content of the CH4, which means there may be a slight double
24 counting of C as both CO2 and CH4.
25 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-62 for metallurgical coke
26 production and iron and steel production. Total CO2 emissions from metallurgical coke production and iron and
27 steel production were estimated to be between 35.5 and 48.3 Tg CO2 Eq. at the 95 percent confidence level. This
28 indicates a range of approximately 17 percent below and 13 percent above the emission estimate of 42.6 Tg CO2 Eq.
29 Total CH4 emissions from metallurgical coke production and iron and steel production were estimated to be less
30 than 0.4 Tg CO2 Eq. at the 95 percent confidence level. This indicates a range of approximately 21 percent below
31 and 22 percent above the emission estimate of less than 0.4 Tg CO2 Eq.
32 Table 4-62: Tier 2 Quantitative Uncertainty Estimates for CO2 and CH4 Emissions from Iron and Steel Production
33 and Metallurgical Coke Production (Tg. CO2 Eq. and Percent)
2009 Emission Uncertainty Range Relative to Emission
Source Gas Estimate Estimate"
(Tg C02 Eq.) (Tg C02 Eq.) (%}
Lower Upper Lower Upper
Bound Bound Bound Bound
Metallurgical Coke & Iron and
Steel Production
Metallurgical Coke & Iron and
Steel Production
C02
CH4
42.6
0.4
35.5
0.3
48.3
0.5
-17%
-21%
+13%
+22%
34 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
35 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
36 through 2008. Details on the emission trends through time are described in more detail in the Methodology section,
37 above.
38 Planned Improvements
39 Future improvements to the Iron and Steel production source category involve evaluating facility level greenhouse
40 gas emissions data as a basis for improving emissions calculations from iron and steel production. Beginning in
41 2010, all U. S. iron and steel producing facilities that emit over 25,000 tons of greenhouse gases (CO2e) will be
42 required to monitor, calculate and report their greenhouse gas emissions to EPA through its Greenhouse Gas
4-44 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Reporting Program. Under the program, EPA will obtain data for 2010 from these facilities based on use of higher
2 tier methods and assess how this data could be used to improve the method for calculating emissions from the U.S.
3 iron and steel industry. Specifically, plans include attributing emissions estimates for the production of
4 metallurgical coke to the Energy chapter as well as identifying the amount of carbonaceous materials, other than
5 coking coal, consumed at merchant coke plants. Additional improvements include identifying the amount of coal
6 used for direct injection and the amount of coke breeze, coal tar, and light oil produced during coke production.
7 Efforts will also be made to identify inputs for preparing Tier 2 estimates for sinter and direct reduced iron
8 production, as well as identifying information to better characterize emissions from the use of process gases and
9 fuels within the Energy and Industrial Processes chapters.
10 Recalculations Discussion
11 In last year's Inventory, coal tar production and coke breeze production were incorrectly estimated by multiplying
12 the respective production factors by U.S. coke production at coke plants rather than U.S. coking coal consumption at
13 coke plants (to which the coal tar and coke breeze production factors should be applied). This issue has been
14 corrected and decreased the 1990 through 2008 emissions from metallurgical coke production by an average of 53
15 percent per year relative to the previous Inventory. The total 1990 through 2008 emissions for metallurgical coke
16 and iron and steel production decreased by an average of 3 percent per year relative to the previous Inventory.
17 4.14. Ferroalloy Production (IPCC Source Category 2C2)
18 CO2 and CH4 are emitted from the production of several ferroalloys. Ferroalloys are composites of iron and other
19 elements such as silicon, manganese, and chromium. When incorporated in alloy steels, ferroalloys are used to alter
20 the material properties of the steel. Estimates from two types of ferrosilicon (25 to 55 percent and 56 to 95 percent
21 silicon), silicon metal (about 98 percent silicon), and miscellaneous alloys (36 to 65 percent silicon) have been
22 calculated. Emissions from the production of ferrochromium and ferromanganese are not included here because of
23 the small number of manufacturers of these materials in the United States. Subsequently, government information
24 disclosure rules prevent the publication of production data for these production facilities.
25 Similar to emissions from the production of iron and steel, CO2 is emitted when metallurgical coke is oxidized
26 during a high-temperature reaction with iron and the selected alloying element. Due to the strong reducing
27 environment, CO is initially produced, and eventually oxidized to CO2. A representative reaction equation for the
28 production of 50 percent ferrosilicon is given below:
29 Fe2O3+2SiO2+7C-»2FeSi+7CO
30 While most of the C contained in the process materials is released to the atmosphere as CO2, a percentage is also
31 released as CH4 and other volatiles. The amount of CH4 that is released is dependent on furnace efficiency,
32 operation technique, and control technology.
33 Emissions of CO2 from ferroalloy production in 2009 were 1.6 Tg CO2 Eq. (1,599 Gg) (see Table 4-63 and Table
34 4-64), which is a 26 percent reduction since 1990. Emissions of CH4 from ferroalloy production in 2009 were 0.01
35 Tg CO2 Eq. (0.465 Gg), which is a 32 percent decrease since 1990.
36 Table 4-63: CO2 and CH4 Emissions from Ferroalloy Production (Tg CO2 Eq.)
37
38
39
40
Year
C02
CH4
Total
1990
2.2
+
2.2
2000
1.9
+
1.9
2005
1.4
+
1.4
2006
1.5
+
1.5
2007
1.6
+
1.6
2008
1.6
+
1.6
2009
1.6
+
1.6
+ Does not exceed 0.05 Tg CO2 Eq.
Note: Totals may not sum due to independent rounding.
Table
Year
C02
CH4
4-64: CO2and
1990
2,152
1
CH4 Emissions from Ferroalloy
2000
1,893
1
2005
1,392
+
Production (Gg)
2006
1,505
+
2007
1,552
+
2008
1,599
+
2009
1,599
+
41
Industrial Processes 4-45
-------
i Methodology
2 Emissions of CO2 and CH4 from ferroalloy production were calculated by multiplying annual ferroalloy production
3 by material-specific emission factors. Emission factors taken from the 2006IPCC Guidelines for National
4 Greenhouse Gas Inventories (IPCC 2006) were applied to ferroalloy production. For ferrosilicon alloys containing
5 25 to 55 percent silicon and miscellaneous alloys (including primarily magnesium-ferrosilicon, but also including
6 other silicon alloys) containing 32 to 65 percent silicon, an emission factor for 45 percent silicon was applied for
7 CO2 (2.5 metric tons CO2/metric ton of alloy produced) and an emission factor for 65 percent silicon was applied for
8 CH4 (1 kg CHVmetric ton of alloy produced). Additionally, for ferrosilicon alloys containing 56 to 95 percent
9 silicon, an emission factor for 75 percent silicon ferrosilicon was applied for both CO2 and CH4 (4 metric tons
10 CO2/metric ton alloy produced and 1 kg CH4/metric ton of alloy produced, respectively). The emission factors for
11 silicon metal equaled 5 metric tons CO2/metric ton metal produced and 1.2 kg CH4/metric ton metal produced. It
12 was assumed that 100 percent of the ferroalloy production was produced using petroleum coke using an electric arc
13 furnace process (IPCC 2006), although some ferroalloys may have been produced with coking coal, wood, other
14 biomass, or graphite C inputs. The amount of petroleum coke consumed in ferroalloy production was calculated
15 assuming that the petroleum coke used is 90 percent C and 10 percent inert material.
16 Ferroalloy production data for 1990 through 2008 (see Table 4-65) were obtained from the USGS through personal
17 communications with the USGS Silicon Commodity Specialist (Corathers 2009) and through the Minerals
18 Yearbook: Silicon Annual Report (USGS 1991 through 2010). Data for 2009 were not available in time for this
19 publication. Therefore, production values in 2009 were assumed to equal 2008 values. Because USGS does not
20 provide estimates of silicon metal production for 2006-2009, 2005 production data are used. Until 1999, the USGS
21 reported production of ferrosilicon containing 25 to 55 percent silicon separately from production of miscellaneous
22 alloys containing 32 to 65 percent silicon; beginning in 1999, the USGS reported these as a single category (see
23 Table 4-65). The composition data for petroleum coke was obtained from Onder and Bagdoyan (1993).
24 Table 4-65: Production of Ferroalloys (Metric Tons)
Year
1990
2000
2005
2006
2007
2008
2009
Ferrosilicon
25%-55%
321,385
229,000
123,000
164,000
180,000
193,000
193,000
Ferrosilicon
56%-95%
109,566
100,000
86,100
88,700
90,600
94,000
94,000
Silicon Metal
145,744
184,000
148,000
148,000
148,000
148,000
148,000
Misc. Alloys
32-65%
72,442
NA
NA
NA
NA
NA
NA
25 NA (Not Available)
26 Uncertainty and Time-Series Consistency
27 Although some ferroalloys may be produced using wood or other biomass as a C source, information and data
28 regarding these practices were not available. Emissions from ferroalloys produced with wood or other biomass
29 would not be counted under this source because wood-based C is of biogenic origin.113 Even though emissions from
30 ferroalloys produced with coking coal or graphite inputs would be counted in national trends, they may be generated
31 with varying amounts of CO2 per unit of ferroalloy produced. The most accurate method for these estimates would
32 be to base calculations on the amount of reducing agent used in the process, rather than the amount of ferroalloys
33 produced. These data, however, were not available.
34 Emissions of CH4 from ferroalloy production will vary depending on furnace specifics, such as type, operation
35 technique, and control technology. Higher heating temperatures and techniques such as sprinkle charging will
36 reduce CH4 emissions; however, specific furnace information was not available or included in the CH4 emission
37 estimates.
113
Emissions and sinks of biogenic carbon are accounted for in the Land Use, Land-Use Change, and Forestry chapter.
4-46 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Also, annual ferroalloy production is now reported by the USGS in three broad categories: ferroalloys containing 25
2 to 55 percent silicon (including miscellaneous alloys), ferroalloys containing 56 to 95 percent silicon, and silicon
3 metal. It was assumed that the IPCC emission factors apply to all of the ferroalloy production processes, including
4 miscellaneous alloys. Finally, production data for silvery pig iron (alloys containing less than 25 percent silicon) are
5 not reported by the USGS to avoid disclosing company proprietary data. Emissions from this production category,
6 therefore, were not estimated.
7 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-66. Ferroalloy production CO2
8 emissions were estimated to be between 1.4 and 1.8 Tg CO2 Eq. at the 95 percent confidence level. This indicates a
9 range of approximately 12 percent below and 12 percent above the emission estimate of 1.6 Tg CO2 Eq. Ferroalloy
10 production CH4 emissions were estimated to be between a range of approximately 12 percent below and 12 percent
11 above the emission estimate of 0.01 Tg CO2 Eq.
12 Table 4-66: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Ferroalloy Production (Tg CO2 Eq.
13 and Percent)
2009 Emission
Source Gas Estimate
(Tg C02 Eq.)
Ferroalloy Production CO2 1.6
Ferroalloy Production CH4 +
Uncertainty Range Relative to Emission Estimate"
(TgC02Eq.) (%)
Lower
Bound
1.4
+
Upper
Bound
1.8
+
Lower
Bound
-12%
-12%
Upper
Bound
+12%
+12%
14 aRange of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
15 + Does not exceed 0.05 Tg CO2 Eq.
16 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
17 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
18 above.
19 Planned Improvements
20 Future improvements to the ferroalloy production source category involve evaluating facility level greenhouse gas
21 emissions data as a basis for improving emissions calculations from ferroalloy production. Beginning in 2010, all
22 U.S. ferroalloy producing facilities that emit over 25,000 tons of greenhouse gases (CO2e) will be required to
23 monitor, calculate and report their greenhouse gas emissions to EPA through its Greenhouse Gas Reporting
24 Program. Under the program, EPA will obtain data for 2010 from these facilities based on use of higher tier
25 methods and assess how this data could be used to improve the methodology and emissions factors for calculating
26 emissions from the U.S. ferroalloy industry, in particular, including emission esimates from production of
27 ferroalloys other than ferrosilicon and silicon metal. If data are available, emissions will be estimated for those
28 ferroalloys. Additionally, research will be conducted to determine whether data are available concerning raw
29 material consumption (e.g., coal coke, limestone and dolomite flux, etc.) for inclusion in ferroalloy production
30 emission estimates.
31 4.15. Aluminum Production (IPCC Source Category 2C3)
32 Aluminum is a light-weight, malleable, and corrosion-resistant metal that is used in many manufactured products,
33 including aircraft, automobiles, bicycles, and kitchen utensils. As of last reporting, the United States was the fourth
34 largest producer of primary aluminum, with approximately seven percent of the world total (USGS 2009a). The
35 United States was also a major importer of primary aluminum. The production of primary aluminum—in addition
36 to consuming large quantities of electricity—results in process-related emissions of CO2 and two perfluorocarbons
37 (PFCs): perfluoromethane (CF4) and perfluoroethane (C2F6).
38 CO2 is emitted during the aluminum smelting process when alumina (aluminum oxide, A12O3) is reduced to
39 aluminum using the Hall-Heroult reduction process. The reduction of the alumina occurs through electrolysis in a
40 molten bath of natural or synthetic cryolite (Na3AlF6). The reduction cells contain a C lining that serves as the
41 cathode. C is also contained in the anode, which can be a C mass of paste, coke briquettes, or prebaked C blocks
42 from petroleum coke. During reduction, most of this C is oxidized and released to the atmosphere as CO2.
43 Process emissions of CO2 from aluminum production were estimated to be 3.0 Tg CO2 Eq. (3,009 Gg) in 2009 (see
Industrial Processes 4-47
-------
1 Table 4-67). The C anodes consumed during aluminum production consist of petroleum coke and, to a minor extent,
2 coal tar pitch. The petroleum coke portion of the total CO2 process emissions from aluminum production is
3 considered to be a non-energy use of petroleum coke, and is accounted for here and not under the CO2 from Fossil
4 Fuel Combustion source category of the Energy sector. Similarly, the coal tar pitch portion of these CO2 process
5 emissions is accounted for here rather than in the Iron and Steel source category of the Industrial Processes sector.
Table 4-67: CO2 Emissions from Aluminum Production (Tg CO2 Eq. and Gg)
Year
1990
2000
2005
2006
2007
2008
2009
Tg C02 Eq.
6.8
6.1
4.1
3.8
4.3
4.5
3.0
Gg
6,831
6,086
4,142
3,801
4,251
4,477
3,009
8 In addition to CO2 emissions, the aluminum production industry is also a source of PFC emissions. During the
9 smelting process, when the alumina ore content of the electrolytic bath falls below critical levels required for
10 electrolysis, rapid voltage increases occur, which are termed "anode effects." These anode effects cause carbon
11 from the anode and fluorine from the dissociated molten cryolite bath to combine, thereby producing fugitive
12 emissions of CF4 and C2F6. In general, the magnitude of emissions for a given smelter and level of production
13 depends on the frequency and duration of these anode effects. As the frequency and duration of the anode effects
14 increase, emissions increase.
15 Since 1990, emissions of CF4 and C2F6 have declined by 92 percent and 89 percent, respectively, to 1.3 Tg CO2 Eq.
16 of CF4 (0.20 Gg) and 0.30 Tg CO2 Eq. of C2F6 (0.032 Gg) in 2009, as shown in Table 4-68 and Table 4-69. This
17 decline is due both to reductions in domestic aluminum production and to actions taken by aluminum smelting
18 companies to reduce the frequency and duration of anode effects. Since 1990, aluminum production has declined by
19 57 percent, while the combined CF4 and C2F6 emission rate (per metric ton of aluminum produced) has been reduced
20 by 80 percent.
21 Table 4-68: PFC Emissions from Aluminum Production (Tg CO2 Eq.)
Year CF4 C2F6 Total
1990 15.9 2.7 18.5
2000 7.8 0.8 8.6
2005 2.5 0.4 3.0
2006 2.1 0.4 2.5
2007 3.2 0.6 3.8
2008 2.2 0.5 2.7
2009 y 03 1.6
22 Note: Totals may not sum due to independent rounding.
23
24 Table 4-69: PFC Emissions from Aluminum Production (Gg)
Year CF4 C2F6
1990 2.4 0.3
2000 1.2 0.1
25
26
2005
2006
2007
2008
2009
+ Does not exceed 0.05 Gg.
0.4
0.3
0.5
0.3
0.2
+
+
0.1
0.1
+
4-48 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 In 2009, U.S. primary aluminum production totaled approximately 1.7 million metric tons, a 35 percent decrease
2 from 2008 production levels (USAA 2010). In 2009, six companies managed production at 13 operational primary
3 aluminum smelters. Four smelters were closed the entire year, and demolition of one smelter that had been idle
4 since 2000 was completed in 2009. Of the operating smelters, three were temporarily idled, and parts of four others
5 were temporarily closed in 2009 (USGS 2010a). During 2009, U.S. primary aluminum production was less for
6 every month when compared to the corresponding month in 2008 (USGS 2009b, USGS 20 lOb).
7 For 2010, total production during January-September was approximately 1.28 million metric tons compared to 1.32
8 million metric tons for the same period in 2009, only a 3 percent decrease (USGS 2010c). Based on the similarity in
9 production, process CO2 and PFC emissions are likely to be similar over this period in 2009 given no significant
10 changes in process controls at operational facilities.
11 Methodology
12 CO2 emissions released during aluminum production were estimated using the combined application of process-
13 specific emissions estimates modeling with individual partner reported data. These estimates are based on
14 information gathered by EPA's Voluntary Aluminum Industrial Partnership (VAIP) program.
15 Most of the CO2 emissions released during aluminum production occur during the electrolysis reaction of the C
16 anode, as described by the following reaction:
17 2A12O3 + 3C -> 4A1 + 3CO2
18 For prebake smelter technologies, CO2 is also emitted during the anode baking process. These emissions can
19 account for approximately 10 percent of total process CO2 emissions from prebake smelters.
20 Depending on the availability of smelter-specific data, the CO2 emitted from electrolysis at each smelter was
21 estimated from: (1) the smelter's annual anode consumption, (2) the smelter's annual aluminum production and rate
22 of anode consumption (per ton of aluminum produced) for previous and /or following years, or, (3) the smelter's
23 annual aluminum production and IPCC default CO2 emission factors. The first approach tracks the consumption and
24 carbon content of the anode, assuming that all carbon in the anode is converted to CO2. Sulfur, ash, and other
25 impurities in the anode are subtracted from the anode consumption to arrive at a carbon consumption figure. This
26 approach corresponds to either the IPCC Tier 2 or Tier 3 method, depending on whether smelter-specific data on
27 anode impurities are used. The second approach interpolates smelter-specific anode consumption rates to estimate
28 emissions during years for which anode consumption data are not available. This avoids substantial errors and
29 discontinuities that could be introduced by reverting to Tier 1 methods for those years. The last approach
30 corresponds to the IPCC Tier 1 method (2006) and is used in the absence of present or historic anode consumption
31 data.
32 The equations used to estimate CO2 emissions in the Tier 2 and 3 methods vary depending on smelter type (IPCC
33 2006) For Prebake cells, the process formula accounts for various parameters, including net anode consumption,
34 and the sulfur, ash, and impurity content of the baked anode. For anode baking emissions, the formula accounts for
35 packing coke consumption, the sulfur and ash content of the packing coke, as well as the pitch content and weight of
36 baked anodes produced. For Sederberg cells, the process formula accounts for the weight of paste consumed per
37 metric ton of aluminum produced, and pitch properties, including sulfur, hydrogen, and ash content.
38 Through the VAIP, anode consumption (and some anode impurity) data have been reported for 1990, 2000, 2003,
39 2004, 2005, 2006, 2007, 2008, and 2009. Where available, smelter-specific process data reported under the VAIP
40 were used; however, if the data were incomplete or unavailable, information was supplemented using industry
41 average values recommended by IPCC (2006). Smelter-specific CO2 process data were provided by 18 of the 23
42 operating smelters in 1990 and 2000, by 14 out of 16 operating smelters in 2003 and 2004, 14 out of 15 operating
43 smelters in 2005, 13 out of 14 operating smelters in 2006, 5 out of 14 operating smelters in, 2007 and 2008, and 3
44 out of 13 operating smelters in 2009. For years where CO2 process data were not reported by these companies,
45 estimates were developed through linear interpolation, and/or assuming industry default values.
46 In the absence of any previous smelter specific process data (i.e., 1 out of 13 smelters in 2009, 1 out of 14 smelters
47 in 2006, 2007, and 2008, 1 out of 15 smelters in 2005, and 5 out of 23 smelters between 1990 and 2003), CO2
48 emission estimates were estimated using Tier 1 Sederberg and/or Prebake emission factors (metric ton of CO2 per
49 metric ton of aluminum produced) from IPCC (2006).
Industrial Processes 4-49
-------
1 Aluminum production data for 10 out of 13 operating smelters were reported under the VAIP in 2009. Between
2 1990 and 2008, production data were provided by 21 of the 23 U.S. smelters that operated during at least part of that
3 period. For the non-reporting smelters, production was estimated based on the difference between reporting
4 smelters and national aluminum production levels (USAA 2010), with allocation to specific smelters based on
5 reported production capacities (USGS 2009a).
6 PFC emissions from aluminum production were estimated using a per-unit production emission factor that is
7 expressed as a function of operating parameters (anode effect frequency and duration), as follows:
8 PFC (CF4 or C2F6) kg/metric ton Al = S x (Anode Effect Minutes/Cell-Day)
9 where,
10 S = Slope coefficient ((kg PFC/metric ton Al)/(Anode Effect Minutes/Cell-Day))
11 (Anode Effect Minutes/Cell-Day) = (Anode Effect Frequency/Cell-Day) x Anode Effect Duration (minutes)
12 This approach corresponds to either the Tier 3 or the Tier 2 approach in the 2006 IPCC Guidelines, depending upon
13 whether the slope-coefficient is smelter-specific (Tier 3) or technology-specific (Tier 2). For 1990 through 2009,
14 smelter-specific slope coefficients were available and were used for smelters representing between 30 and 94
15 percent of U.S. primary aluminum production. The percentage changed from year to year as some smelters closed
16 or changed hands and as the production at remaining smelters fluctuated. For smelters that did not report smelter-
17 specific slope coefficients, IPCC technology-specific slope coefficients were applied (IPCC 2000, 2006). The slope
18 coefficients were combined with smelter-specific anode effect data collected by aluminum companies and reported
19 under the VAIP, to estimate emission factors over time. For 1990 through 2009, smelter-specific anode effect data
20 were available for smelters representing between 80 and 100 percent of U.S. primary aluminum production. Where
21 smelter-specific anode effect data were not available, industry averages were used.
22 For all smelters, emission factors were multiplied by annual production to estimate annual emissions at the smelter
23 level. For 1990 through 2009, smelter-specific production data were available for smelters representing between 30
24 and 100 percent of U.S. primary aluminum production. (For the years after 2000, this percentage was near the high
25 end of the range.) Production at non-reporting smelters was estimated by calculating the difference between the
26 production reported under VAIP and the total U.S. production supplied by USGS or USAA and then allocating this
27 difference to non-reporting smelters in proportion to their production capacity. Emissions were then aggregated
28 across smelters to estimate national emissions.
29 National primary aluminum production data for 2009 were obtained via USAA (USAA 2010). For 1990 through
30 2001, and 2006 (see Table 4-70) data were obtained from USGS, Mineral Industry Surveys: Aluminum Annual
31 Report (USGS 1995, 1998, 2000, 2001, 2002, 2007). For 2002 through 2005, and 2007 through 2008 national
32 aluminum production data were obtained from the United States Aluminum Association's Primary Aluminum
33 Statistics (USAA 2004, 2005, 2006, 2008, 2009).
34 Table 4-70: Production of Primary Aluminum (Gg)
Year Gg
1990 4,048
2000 3,668
2005 2,478
2006 2,284
2007 2,560
2008 2,659
2009 1,727
35
36 Uncertainty and Time Series Consistency
37 The overall uncertainties associated with the 2009 CO2, CF4, and C2F6 emission estimates were calculated using
38 Approach 2, as defined by IPCC (2006). For CO2, uncertainty was assigned to each of the parameters used to
39 estimate CO2 emissions. Uncertainty surrounding reported production data was assumed to be 1 percent (IPCC
40 2006). For additional variables, such as net C consumption, and sulfur and ash content in baked anodes, estimates
41 for uncertainties associated with reported and default data were obtained from IPCC (2006). A Monte Carlo
4-50 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 analysis was applied to estimate the overall uncertainty of the CO2 emission estimate for the U.S. aluminum industry
2 as a whole, and the results are provided below.
3 To estimate the uncertainty associated with emissions of CF4 and C2F6, the uncertainties associated with three
4 variables were estimated for each smelter: (1) the quantity of aluminum produced, (2) the anode effect minutes per
5 cell day (which may be reported directly or calculated as the product of anode effect frequency and anode effect
6 duration), and, (3) the smelter- or technology-specific slope coefficient. A Monte Carlo analysis was then applied to
7 estimate the overall uncertainty of the emission estimate for each smelter and for the U.S. aluminum industry as a
8 whole.
9 The results of this quantitative uncertainty analysis are summarized in Table 4-71. Aluminum production-related
10 CO2 emissions were estimated to be between 2.90 and 3.12 Tg CO2 Eq. at the 95 percent confidence level. This
11 indicates a range of approximately 4 percent below to 4 percent above the emission estimate of 3.01 Tg CO2 Eq.
12 Also, production-related CF4 emissions were estimated to be between 1.14 and 1.44 Tg CO2 Eq. at the 95 percent
13 confidence level. This indicates a range of approximately 12 percent below to 12 percent above the emission
14 estimate of 1.29 Tg CO2 Eq. Finally, aluminum production-related C2F6 emissions were estimated to be between
15 0.25 and 0.35 Tg CO2 Eq. at the 95 percent confidence level. This indicates a range of approximately 17 percent
16 below to 19 percent above the emission estimate of 0.30 Tg CO2 Eq.
17 Table 4-71: Tier 2 Quantitative Uncertainty Estimates for CO2 and PFC Emissions from Aluminum Production (Tg
18 CO2 Eq. and Percent)
_ , . , Uncertainty Range Relative to 2009 Emission Estimate3
Source Gas (Tg CO2 Eq.) (Tg CO2 Eq.) (%)
Aluminum Production CO2
Aluminum Production CF4
Aluminum Production C2F6
3.0
1.3
0.3
Lower Bound
2.9
1.1
0.2
Upper Bound
3.1
1.4
0.4
Lower Bound
-4%
-12%
-17%
Upper Bound
+4%
+12%
+19%
19 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
20
21 The 2009 emission estimate was developed using either company-wide or site-specific PFC slope coefficients for all
22 but 1 of the 14 operating smelters where default IPCC (2006) slope data was used. In some cases, where smelters
23 are owned by one company, data have been reported on a company-wide basis as totals or weighted averages.
24 Consequently, in the Monte Carlo analysis, uncertainties in anode effect minutes per cell day, slope coefficients, and
25 aluminum production have been applied to the company as a whole and not to each smelter. This probably
26 overestimates the uncertainty associated with the cumulative emissions from these smelters, because errors that were
27 in fact independent were treated as if they were correlated. It is therefore likely that uncertainties calculated above
28 for the total U.S. 2009 emission estimates for CF4 and C2F6 are also overestimated.
29 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
30 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
31 above.
32 Planned Improvements
33 Beginning in 2010, all U.S. aluminum production facilities will be required to calculate and report their greenhouse
34 gas emissions to EPA through its Greenhouse Gas Reporting Program. Data collected under this program will be
35 used in future inventories to improve the calculation of national emissions from aluminium production.
36
37 4.16. Magnesium Production and Processing (IPCC Source Category 2C4)
38 The magnesium metal production and casting industry uses sulfur hexafluoride (SF6) as a cover gas to prevent the
39 rapid oxidation of molten magnesium in the presence of air. Sulfur hexafluoride has been used in this application
40 around the world for more than twenty-five years. A dilute gaseous mixture of SF6 with dry air and/or CO2 is blown
41 over molten magnesium metal to induce and stabilize the formation of a protective crust. A small portion of the SF6
42 reacts with the magnesium to form a thin molecular film of mostly magnesium oxide and magnesium fluoride. The
43 amount of SF6 reacting in magnesium production and processing is considered to be negligible and thus all SF6 used
Industrial Processes 4-51
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1 is assumed to be emitted into the atmosphere. Although alternative cover gases, such as AM-cover™ (containing
2 HFC-134a), Novec™ 612 and dilute SO2 systems can be used, many facilities in the United States are still using
3 traditional SF6 cover gas systems.
4 The magnesium industry emitted 1.1 Tg CO2 Eq. (0.04 Gg) of SF6 in 2009, representing a decrease of approximately
5 45 percent from 2008 emissions (See Table X-l). The decrease can be attributed to die casting facilities in the
6 United States closing or halting production due to reduced demand from the American auto industry and other
7 industrial sectors (USGS 2010a). Production associated with primary and secondary facilities also dropped in 2009.
8 The significant reduction in emissions can also be attributed to industry efforts to switch to cover gas alternatives,
9 such as sulfur dioxide, as part of the EPA's SF6 Emission Reduction Partnership for the Magnesium Industry.
10 Table 4-72: SF6 Emissions from Magnesium Production and Processing (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq.
1990
2000
2005
2006
2007
2008
2009
5.4
3.0
2.9
2.9
2.6
1.9
1.1
Gg
0.2
0.1
0.1
0.1
0.1
0.1
0.04
11
12 Methodology
13 Emission estimates for the magnesium industry incorporate information provided by industry participants in EPA's
14 SF6 Emission Reduction Partnership for the Magnesium Industry. The Partnership started in 1999 and, currently,
15 participating companies represent 100 percent of U.S. primary and secondary production and 90 percent of the
16 casting sector production (i.e., die, sand, permanent mold, wrought, and anode casting). Absolute emissions for
17 1999 through 2009 from primary production, secondary production (i.e., recycling), and die casting were generally
18 reported by Partnership participants. Partners reported their SF6 consumption, which was assumed to be equivalent
19 to emissions. When a partner did not report emissions, they were estimated based on the metal processed and
20 emission rate reported by that partner in previous and (if available) subsequent years. Where data for subsequent
21 years was not available, metal production and emissions rates were extrapolated based on the trend shown by
22 partners reporting in the current and previous years. When it was determined a Partner is no longer in production,
23 their metal production and emissions rates were set to zero if no activity information was available; in one case a
24 partner that closed mid-year was estimated to have produced 50 percent of the metal from the prior year.
25 Emission factors for 2002 to 2006 for sand casting activities were also acquired through the Partnership. For 2007,
26 2008 and 2009, the sand casting partner did not report and the reported emission factor from 2005 was utilized as
27 being representative of the industry. The 1999 through 2009 emissions from casting operations (other than die)
28 were estimated by multiplying emission factors (kg SF6 per metric ton of metal produced or processed) by the
29 amount of metal produced or consumed. The emission factors for casting activities are provided below in Table
30 4-73. The emission factors for primary production, secondary production and sand casting are withheld to protect
31 company-specific production information. However, the emission factor for primary production has not risen above
32 the average 1995 partner value of 1.1 kg SF6 per metric ton.
33 Die casting emissions for 1999 through 2009, which accounted for 18 to 52 percent of all SF6 emissions from the
34 U.S. magnesium industry during this period, were estimated based on information supplied by industry partners.
35 From 2000 to 2009, partners accounted for all U.S. die casting that was tracked by USGS. In 1999, partners did not
36 account for all die casting tracked by USGS, and, therefore, it was necessary to estimate the emissions of die casters
37 who were not partners. Die casters who were not partners were assumed to be similar to partners who cast small
38 parts. Due to process requirements, these casters consume larger quantities of SF6 per metric ton of processed
39 magnesium than casters that process large parts. Consequently, emission estimates from this group of die casters
40 were developed using an average emission factor of 5.2 kg SF6 per metric ton of magnesium. The emission factors
41 for the other industry sectors (i.e., permanent mold, wrought, and anode casting) were based on discussions with
42 industry representatives.
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Table 4-73: SF6 Emission Factors (kg SF6 per metric ton of magnesium)
Year Die Casting Permanent Mold Wrought Anodes
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2.14a
0.72
0.72
0.71
0.81
0.81
0.79
0.86
0.67
1.15
1.77
2
2
2
2
2
2
2
2
2
2
2
2 a Weighted average that includes an estimated emission factor of 5.2 kg SF6 per metric ton of magnesium for die casters that do
3 not participate in the Partnership.
4
5 Data used to develop SF6 emission estimates were provided by the Magnesium Partnership participants and the
6 USGS. U.S. magnesium consumption (casting) data from 1990 through 2009 were available from the USGS (USGS
7 2002, 2003, 2005, 2006, 2007, 2008, 2010). Emission factors from 1990 through 1998 were based on a number of
8 sources. Emission factors for primary production were available from U.S. primary producers for 1994 and 1995,
9 and an emission factor for die casting of 4.1 kg per metric ton was available for the mid-1990s from an international
10 survey (Gjestland & Magers 1996).
11 To estimate emissions for 1990 through 1998, industry emission factors were multiplied by the corresponding metal
12 production and consumption (casting) statistics from USGS. The primary production emission factors were 1.2 kg
13 per metric ton for 1990 through 1993, and 1.1 kg per metric ton for 1994 through 1997. For die casting, an emission
14 factor of 4.1 kg per metric ton was used for the period 1990 through 1996. For 1996 through 1998, the emission
15 factors for primary production and die casting were assumed to decline linearly to the level estimated based on
16 partner reports in 1999. This assumption is consistent with the trend in SF6 sales to the magnesium sector that is
17 reported in the RAND survey of major SF6 manufacturers, which shows a decline of 70 percent from 1996 to 1999
18 (RAND 2002). Sand casting emission factors for 2002 through 2009 were provided by the Magnesium Partnership
19 participants, and 1990 through 2001 emission factors for this process were assumed to have been the same as the
20 2002 emission factor. The emission factor for secondary production from 1990 through 1998 was assumed to be
21 constant at the 1999 average partner value. The emission factors for the other processes (i.e., permanent mold,
22 wrought, and anode casting), about which less is known, were assumed to remain constant at levels defined in Table
23 4-73.
24 Uncertainty
25 To estimate the uncertainty surrounding the estimated 2009 SF6 emissions from magnesium production and
26 processing, the uncertainties associated with three variables were estimated (1) emissions reported by magnesium
27 producers and processors that participate in the Magnesium Partnership, (2) emissions estimated for magnesium
28 producers and processors that participate in the Partnership but did not report this year, and (3) emissions estimated
29 for magnesium producers and processors that do not participate in the Partnership. An uncertainty of 5 percent was
30 assigned to the data reported by each participant in the Partnership. If partners did not report emissions data during
31 the current reporting year, SF6 emissions data were estimated using available emission factor and production
32 information reported in prior years; the extrapolation was based on the average trend for partners reporting in the
33 current reporting year and the year prior. The uncertainty associated with the SF6 usage estimate generated from the
34 extrapolated emission factor and production information was estimated to be 30 percent for each year of
35 extrapolation. The lone sand casting partner did not report in the past two reporting years and its activity and
36 emission factor were held constant at 2005 levels due to a reporting anomaly in 2006 because of malfunctions at the
37 facility. The uncertainty associated with the SF6 usage for the sand casting partner was 52 percent. For those
38 industry processes that are not represented in Partnership, such as permanent mold and wrought casting, SF6
39 emissions were estimated using production and consumption statistics reported by USGS and estimated process-
40 specific emission factors (see Table 4-73). The uncertainties associated with the emission factors and USGS-
Industrial Processes 4-53
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1 reported statistics were assumed to be 75 percent and 25 percent, respectively. Emissions associated with sand
2 casting activities utilized a partner-reported emission factor with an uncertainty of 75 percent. In general, where
3 precise quantitative information was not available on the uncertainty of a parameter, a conservative (upper-bound)
4 value was used.
5 Additional uncertainties exist in these estimates that are not addressed in this methodology, such as the basic
6 assumption that SF6 neither reacts nor decomposes during use. The melt surface reactions and high temperatures
7 associated with molten magnesium could potentially cause some gas degradation. Recent measurement studies have
8 identified SF6 cover gas degradation in die casting applications on the order of 20 percent (Bartos et al. 2007).
9 Sulfur hexafluoride may also be used as a cover gas for the casting of molten aluminum with high magnesium
10 content; however, the extent to which this technique is used in the United States is unknown.
11 The results of this Tier 2 quantitative uncertainty analysis are summarized in Table 4-74. SF6 emissions associated
12 with magnesium production and processing were estimated to be between 1.01 and 1.10 Tg CO2 Eq. at the 95
13 percent confidence level. This indicates a range of approximately 6 percent below to 5 percent above the 2008
14 emission estimate of 1.05 Tg CO2 Eq. The uncertainty estimates for 2009 are lower relative to the 2008 reporting
15 year which is likely due to the fact that emission estimates for this year are based more on actual reported data than
16 last year with two emission sources using projected (highly uncertain) estimates.
17 Table 4-74: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Magnesium Production and
18 Processing (Tg CO2 Eq. and Percent)
2009 Emission
Source Gas Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Magnesium Production SF6 1.05
1.01 1.10 -4% +4%
19 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
20 Planned Improvements
21 Cover gas research conducted by the EPA over the last decade has found that SF6 used for magnesium melt
22 protection can have degradation rates on the order of 20 percent in die casting applications (Bartos et al. 2007).
23 Current emission estimates assume (per the 2006 IPCC Guidelines, IPCC 2006) that all SF6 utilized is emitted to the
24 atmosphere. Additional research may lead to a revision of IPCC Guidelines to reflect this phenomenon and until
25 such time, developments in this sector will be monitored for possible application to the inventory methodology.
26 Another issue that will be addressed in future inventories is the likely adoption of alternate cover gases by U.S.
27 magnesium producers and processors. These cover gases, which include AM-cover™ (containing HFC-134a) and
28 Novec™ 612, have lower GWPs than SF6, and tend to quickly degrade during their exposure to the molten metal.
29 Magnesium producers and processors have already begun using these cover gases for 2006 through 2009 in a limited
30 fashion; because the amounts being used by companies on the whole are low enough that they have a minor effect
31 on the overall emissions from the industry, these emissions are only being monitored and recorded at this time.
32 4.17. Zinc Production (IPCC Source Category 2C5)
33 Zinc production in the United States consists of both primary and secondary processes. Primary production in the
34 United States is conducted through the electrolytic process while secondary techniques used in the United States
35 include the electrothermic and Waelz Kiln processes as well as a range of other metallurgical, hydrometallurgical,
36 and pyrometallurgical processes. Worldwide primary zinc production also employs a pyrometallurgical process
37 using the Imperial Smelting Furnace process; however, this process is not used in the United States (Sjardin 2003).
38 Of the primary and secondary processes used in the United States, only the electrothermic and Waelz Kiln
39 secondary processes result in non-energy CO2 emissions (Viklund-White 2000).
40 During the electrothermic zinc production process, roasted zinc concentrate and secondary zinc products enter a
41 sinter feed where they are burned to remove impurities before entering an electric retort furnace. Metallurgical coke
42 added to the electric retort furnace reduces the zinc oxides and produces vaporized zinc, which is then captured in a
43 vacuum condenser. This reduction process produces non-energy CO2 emissions (Sjardin 2003).
44 In the Waelz Kiln process, EAF dust, which is captured during the recycling of galvanized steel, enters a kiln along
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1 with a reducing agent—often metallurgical coke. When kiln temperatures reach approximately 1100-1200°C, zinc
2 fumes are produced, which are combusted with air entering the kiln. This combustion forms zinc oxide, which is
3 collected in a baghouse or electrostatic precipitator, and is then leached to remove chloride and fluoride. Through
4 this process, approximately 0.33 metric ton of zinc is produced for every metric ton of EAF dust treated (Viklund-
5 White 2000).
6 In 2009, U.S. primary and secondary zinc production were estimated to total 286,000 metric tons (USGS 2010).
7 Since reported activity data for 2009 were not available for all necessary inputs in time for this publication,
8 production values in 2009 were assumed to equal 2008 values in some cases. The resulting emissions of CO2 from
9 zinc production in 2009 were estimated to be 0.97 Tg CO2 Eq. (966 Gg) (see Table 4-75). All 2009 CO2 emissions
10 resulted from secondary zinc production.
11 Table 4-75: CO2 Emissions from Zinc Production (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq.
1990
2000
2005
2006
2007
2008
2009
0.7
1.0
1.1
1.1
1.1
1.2
1.0
Gg
667
997
1088
1088
1081
1230
966
12
13 Emissions from zinc production in the U.S. have increased overall due to a gradual shift from non-emissive primary
14 production to emissive secondary production. In 2009, emissions were estimated to be 45% higher than they were
15 in 1990.
16 Methodology
17 Non-energy CO2 emissions from zinc production result from the electrothermic and Waelz Kiln secondary
18 production processes, which both use metallurgical coke or other C-based materials as reductants. Sjardin (2003)
19 provides an emission factor of 0.43 metric tons CO2/metric ton zinc produced for emissive zinc production
20 processes; however, this emission factor is based on the Imperial Smelting Furnace production process. Because the
21 Imperial Smelting Furnace production process is not used in the United States, emission factors specific to
22 electrothermic and Waelz Kiln processes were needed. Due to the limited amount of information available for these
23 electrothermic processes, only Waelz Kiln process-specific emission factors were developed. These emission
24 factors were applied to both the Waelz Kiln and electrothermic secondary zinc production processes.
25 A Waelz Kiln emission factor based on the amount of zinc produced was developed based on the amount of
26 metallurgical coke consumed for non-energy purposes per ton of zinc produced, 1.19 metric tons coke/metric ton
27 zinc produced (Viklund-White 2000), and the following equation:
\.\9metrictonscoke 0.85 metrictons C ^-^ metric tons CO 3.70 metric tons CO
28 EF . = x x = -
Waelz Kiln metric tons zinc metric ton coke metric ton C metric ton zinc
29 In addition, a Waelz Kiln emission factor based on the amount of EAF dust consumed was developed based on the
30 amount of metallurgical coke consumed per ton of EAF dust consumed, 0.4 metric tons coke/metric ton EAF dust
31 consumed (Viklund-White 2000), and the following equation:114
114 For Waelz Kiln based secondary zinc production, IPCC recommends the use of emission factors based on EAF dust
consumption rather than the amount of zinc produced since the amount of reduction materials used is more directly dependent on
the amount of EAF dust consumed (IPCC 2006).
Industrial Processes 4-55
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OAmetrictonscoke 0.%5metrictonsC 3.67metrictonsCO \.24metrictonsCO
EF
EAFDust metricians EAFdust metrictoncoke metrictonC metrician EAF Dust
3 The only companies in the United States that use emissive technology to produce secondary zinc products are
4 Horsehead Corp and Steel Dust Recycling. For Horsehead Corp, EAF dust is recycled in Waelz Kilns at their
5 Beaumont, TX; Calumet, IL; Palmerton, PA; and Rockwood, TN facilities (and soon to be performed at their new
6 South Carolina facility). These Waelz Kiln facilities produce intermediate zinc products (crude zinc oxide or
7 calcine), most of which is transported to their Monaca, PA facility where the products are smelted into refined zinc
8 using electrothermic technology. Some of Horsehead's intermediate zinc products that are not smelted at Monaca
9 are instead exported to other countries around the world (Horsehead Corp 2010). Steel Dust Recycling recycles
10 EAF dust into intermediate zinc products using Waelz Kilns, and then sells the intermediate products to companies
11 who smelt it into refined products.
12 The total amount of EAF dust consumed by Horsehead Corp at their Waelz Kilns is available from Horsehead
13 financial reports foryears 2006 through 2009 (Horsehead 2010). Consumption levels for 1990 through 2005 are
14 extrapolated using the percentage change in annual refined zinc production at secondary smelters in the U.S. as
15 provided by USGS Minerals Yearbook: Zinc (USGS 1994 through 2010). The EAF dust consumption values for
16 each year are then multiplied by the 1.24 metric tons CO2/metric ton EAF dust consumed emission factor to develop
17 CO2 emission estimates for Horsehead's Waelz Kiln facilities.
18 The amount of EAF dust consumed by the Steel Dust Recycling facility for 2008 and 2009 (the only two years it has
19 been in operation) is not publically available. Therefore, these consumption values are estimated by calculating the
20 2008 and 2009 capacity utilization of Horsehead's Waelz Kilns and multiplying this utilization ratio by the capacity
21 of Steel Dust Recycling's facility, which is available from the company (Steel Dust Recycling LLC 2010). The 1.24
22 metric tons CO2/metric ton EAF dust consumed emission factor is then applied to Steel Dust Recycling's estimated
23 EAF dust consumption to develop CO2 emission estimates for its Waelz Kiln facility.
24 Refined zinc production levels for Horsehead's Monaca, PA facility (utilizing electrothermic technology) are
25 available from the company for years 2005 through 2009 (Horsehead Corp 2010, Horsehead Corp 2008).
26 Production levels for 1990 through 2004 are extrapolated using the percentage changes in annual refined zinc
27 production at secondary smelters in the U.S. as provided by USGS Minerals Yearbook: Zinc (USGS 1994 through
28 2010). The 3.70 metric tons CO2/metric ton zinc emission factor is then applied to the Monaca facility's production
29 levels to estimate CO2 emissions for the facility. The Waelz Kiln production EF is applied in this case rather than
30 the EAF dust consumption EF since Horsehead's Monaca facility does not consume EAF dust.
31 Table 4-76: Zinc Production (Metric Tons)
Year
1990
2000
2005
2006
2007
2008
2009
Primary
262,704
227,800
191,120
113,000
121,000
125,000
125,000
Secondary
95,708
143,000
156,000
156,000
157,000
161,000
161,000
32
33 Uncertainty and Time-Series Consistency
34 The uncertainties contained in these estimates are two-fold, relating to activity data and emission factors used.
35 First, there is uncertainty associated with the amount of EAF dust consumed in the United States to produce
36 secondary zinc using emission-intensive Waelz kilns. The estimate for the total amount of EAF dust consumed in
37 Waelz kilns is based on (1) an EAF dust consumption value reported annually by Horsehead Corporation as part of
38 its financial reporting to the Securities and Exchange Commission (SEC), and (2) an estimate of the amount of EAF
4-56 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 dust consumed at a Waelz kiln facility operated in Alabama by Steel Dust Recycling LLC. Since actual EAF dust
2 consumption information is not available for the Steel Dust Recycling LLC facility, the amount is estimated by
3 multiplying the EAF dust recycling capacity of the facility (available from the company's Web site) by the capacity
4 utilization factor for Horsehead Corporation (which is available from Horsehead's financial reports). Therefore,
5 there is uncertainty associated with the assumption that the capacity utilization of Steel Dust Recycling LLC's
6 Waelz kiln facility is equal to the capacity utilization of Horsehead's Waelz kiln facility. Second, there are
7 uncertainties associated with the emission factors used to estimate CO2 emissions from secondary zinc production
8 processes. The Waelz kiln emission factors are based on materials balances for metallurgical coke and EAF dust
9 consumed as provided by Viklund-White (2000). Therefore, the accuracy of these emission factors depend upon the
10 accuracy of these materials balances. Data limitations prevented the development of emission factors for the
11 electrothermic process. Therefore, emission factors for the Waelz kiln process were applied to both electrothermic
12 and Waelz kiln production processes. The results of the Tier 2 quantitative uncertainty analysis are summarized in
13 Table 4-77. Zinc production CO2 emissions were estimated to be between 0.8 and 1.2 Tg CO2 Eq. at the 95 percent
14 confidence level. This indicates a range of approximately 16 percent below and 19 percent above the emission
15 estimate of 1.0 Tg CO2 Eq.
16 Table 4-77: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Zinc Production (Tg CO2 Eq. and
17 Percent)
Source
2009 Emission
Gas Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Zinc Production CO2 LO 0.8 L2 -16% +19%
18 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
19 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
20 through 2008. Details on the emission trends through time are described in more detail in the Methodology section,
21 above.
22 Planned Improvements
23 Future improvements to the zinc production source category involve evaluating facility level greenhouse gas
24 emissions data as a basis for improving emissions calculations from zinc production. Beginning in 2010, all U.S.
25 zinc producing facilities (both primary and secondary) that emit over 25,000 tons of greenhouse gases (CO2e) will
26 be required to monitor, calculate and report their greenhouse gas emissions to EPA through its Greenhouse Gas
27 Reporting Program. Under the program, EPA will obtain data for 2010 from these facilities based on use of higher
28 tier methods and assess how this data could be used to improve the methodology and emissions factors for
29 calculating emissions from the U.S. zinc production industry.
30 Recalculations Discussion
31 The methodology for estimating CO2 emissions from zinc production was revised for the 1990-2009 inventory based
32 on the availability of new data regarding secondary zinc production in the United States. The previous inventory
33 methodology assumed that two facilities had produced zinc in the U.S. using emissive processes since 1990:
34 Horsehead Corporation's Monaca, PA facility (electrothermic) and Horsehead Corporation's Palmerton, PA facility
35 (Waelz Kiln). The 3.70 metric tons CO2/metric ton zinc emission factor was applied to the estimated refined zinc
36 production at the Monaca, PA electrothermic facility, and the 1.24 metric tons CO2/metric ton EAF dust consumed
37 emission factor was applied to the estimated EAF dust consumption at the Palmerton, PA Waelz Kiln facility. The
38 annual zinc production (for the Monaca facility) and EAF dust consumption (for the Palmerton facility) were
39 estimated using historic values that were published in articles for select years (extrapolation techniques were used
40 for years in which published data was not available). The Monaca, PA facility was assumed to have closed in 2003
41 and not operated since.
42 New data for the industry showed that there were emissive zinc-producing facilities not being captured by the
43 previous inventory methodology. The facilities that were not captured included three Horsehead Corp Waelz Kiln
44 facilities in Beaumont, TX; Calumet, IL; and Rockwood, TN as well as a Waelz Kiln facility commissioned in 2008
45 in Millport, AL by Steel Dust Recycling LLC. Also, research showed that the Monaca, PA facility only closed
Industrial Processes 4-57
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1 temporarily in 2003 and has been operating every year since (the Monaca, PA facility produces refined zinc from
2 intermediary zinc products produced at Horsehead's other facilities). The new methodology utilizes EAF dust
3 consumption values and secondary zinc production values released annually by the main secondary zinc producer in
4 the United States (Horsehead Corp.), and also includes the previously overlooked secondary zinc producing
5 facilities in the emissions estimates.
6 Revising the methodology decreased historical emission estimates by an average of 11% between 1990 and 2002,
7 while increasing emission estimates by an average of 140% between 2003 and 2009. The significant changes in
8 emission estimates for years 2005 through 2008 were largely driven by Horsehead Corp's Monaca, PA facility being
9 captured in the emission calculations for these years.
10 4.18. Lead Production (IPCC Source Category 2C5)
11 Lead production in the United States consists of both primary and secondary processes—both of which emit CO2
12 (Sjardin 2003). Primary lead production, in the form of direct smelting, occurs at a just a single plant in Missouri.
13 Secondary production largely involves the recycling of lead acid batteries at approximately 21 separate smelters in
14 the United States. Fifteen of those secondary smelters have annual capacities of 15,000 tons or more and were
15 collectively responsible for 99% of secondary lead production in 2009 (USGS 2010). Secondary lead production
16 has increased in the United States over the past decade while primary lead production has decreased. In 2009,
17 secondary lead production accounted for approximately 92 percent of total lead production (Guberman 2010).
18 Primary production of lead through the direct smelting of lead concentrate produces CO2 emissions as the lead
19 concentrates are reduced in a furnace using metallurgical coke (Sjardin 2003). U.S. primary lead production
20 decreased by 24 percent from 2008 to 2009 and has decreased by 75 percent since 1990 (Guberman 2010, USGS
21 1995).
22 Secondary lead production, primarily from the recycling of lead-acid batteries, accounted for approximately 92
23 percent of total refined lead production in the United States in 2009 (Guberman 2010). Similar to primary lead
24 production, CO2 emissions result when a reducing agent, usually metallurgical coke, is added to the smelter to aid in
25 the reduction process. CO2 emissions from secondary production also occur through the treatment of secondary raw
26 materials (Sjardin 2003). U.S. secondary lead production decreased from 2008 to 2009 by 3 percent, and has
27 increased by 20 percent since 1990 (Guberman 2010, USGS 1995).
28 At last reporting, the United States was the third largest mine producer of lead in the world, behind China and
29 Australia, accounting for 10 percent of world production in 2009 (USGS 2010). In 2009, U.S. primary and
30 secondary lead production totaled 1,213,000 metric tons (USGS 2010). The resulting emissions of CO2 from 2009
31 production were estimated to be 0.5 Tg CO2 Eq. (525 Gg) (see Table 4-78). The majority of 2009 lead production is
32 from secondary processes, which accounted for 95 percent of total 2009 CO2 emissions.
3 3 Table 4-78: CO2 Emissions from Lead Production (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq. Gg
1990 0.5 516
2000 0.6 594
34
2005
2006
2007
2008
2009
0.6
0.6
0.6
0.6
0.5
553
560
562
551
525
35 After a gradual decrease in total emissions from 1990 to 1995, total emissions have gradually increased since 1995
36 and emissions in 2009 were two percent greater than in 1990. Although primary production has decreased
37 significantly (75 percent since 1990), secondary production has increased by about 20 percent over the same time
38 period. Since secondary production is more emissions-intensive, the increase in secondary production since 1990
39 has resulted in a net increase in emissions despite the sharp decrease in primary production (Guberman 2010, USGS
40 1994).
4-58 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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i Methodology
2 Non-energy CO2 emissions from lead production result from primary and secondary production processes that use
3 metallurgical coke or other C-based materials as reductants. For primary lead production using direct smelting,
4 Sjardin (2003) and the IPCC (2006) provide an emission factor of 0.25 metric tons CO2/metric ton lead. For
5 secondary lead production, Sjardin (2003) and IPCC (2006) provide an emission factor of 0.25 metric tons
6 CO2/metric ton lead for direct smelting as well as an emission factor of 0.2 metric tons CO2/metric ton lead
7 produced for the treatment of secondary raw materials (i.e., pretreatment of lead acid batteries). The direct smelting
8 factor (0.25) and the sum of the direct smelting and pretreatment emission factors (0.45) are multiplied by total U.S.
9 primary and secondary lead production, respectively, to estimate CO2 emissions.
10 The 1990 through 2008 activity data for primary and secondary lead production (see Table 4-79) were obtained
11 through the USGS Mineral Yearbook: Lead (USGS 1994 through 2010), and preliminary 2009 values were provided
12 by USGS commodity specialist David Guberman.
13 Table 4-79: Lead Production (Metric Tons)
Year Primary Secondary
1990 404,000 922,000
2000 341,000 1,130,000
14
2005
2006
2007
2008
2009
143,000
153,000
123,000
135,000
103,000
1,150,000
1,160,000
1,180,000
1,150,000
1,110,000
15 Uncertainty and Time-Series Consistency
16 Uncertainty associated with lead production relates to the emission factors and activity data used. The direct
17 smelting emission factor used in primary production is taken from Sjardin (2003) who averages the values provided
18 by three other studies (Dutrizac et al. 2000, Morris et al. 1983, Ullman 1997). For secondary production, Sjardin
19 (2003) adds a CO2 emission factor associated with battery treatment. The applicability of these emission factors to
20 plants in the United States is uncertain. There is also a smaller level of uncertainty associated with the accuracy of
21 primary and secondary production data provided by the USGS.
22 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-80. Lead production CO2
23 emissions were estimated to be between 0.4 and 0.6 Tg CO2 Eq. at the 95 percent confidence level. This indicates a
24 range of approximately 15 percent below and 15 percent above the emission estimate of 0.5 Tg CO2 Eq.
25 Table 4-80: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Lead Production (Tg CO2 Eq. and
26 Percent)
2009 Emission
Source Gas Estimate Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper
Bound
Lead Production CO2 0.5 0.4 0.6 -15% +15%
27 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
28 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
29 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
30 above.
31 Planned Improvements
32 Future improvements to the lead production source category involve evaluating facility level greenhouse gas
33 emissions data as a basis for improving emissions calculations from lead production. Beginning in 2010, all U.S.
Industrial Processes 4-59
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1 lead producing facilities (primary and secondary) that emit over 25,000 tons of greenhouse gases (CO2e) will be
2 required to monitor, calculate and report their greenhouse gas emissions to EPA through its Greenhouse Gas
3 Reporting Program. Under the program, EPA will obtain data for 2010 from these facilities based on use of higher
4 tier methods and assess how this data could be used to improve the methodology and emissions factors for
5 calculating emissions from the U.S. lead production industry.
6 Recalculations Discussion
7 In previous years, CO2 emissions from secondary lead production were estimated by multiplying secondary lead
8 production values from USGS by an emission factor of 0.2 metric tons CO2/metric ton lead produced. This emission
9 factor is provided by Sjardin (2003) and IPCC (2006) for the treatment of secondary raw materials (i.e., pretreatment
10 of lead acid batteries). Due to a misinterpretation of language in Sjardin (2003) and IPCC (2006), this was the only
11 emission factor applied to secondary lead production even though an emission factor of 0.25 metric tons CO2/metric
12 ton lead for direct smelting should have been applied as well. This issue has been corrected for the current
13 Inventory, and increased 1990 through2008 emissions from lead production by an average of 95 percent per year
14 relative to the previous Inventory.
15 4.19. HCFC-22 Production (IPCC Source Category 2E1)
16 Trifluoromethane (HFC-23 or CHF3) is generated as a by-product during the manufacture of chlorodifluoromethane
17 (HCFC-22), which is primarily employed in refrigeration and air conditioning systems and as a chemical feedstock
18 for manufacturing synthetic polymers. Between 1990 and 2000, U.S. production of HCFC-22 increased
19 significantly as HCFC-22 replaced chlorofluorocarbons (CFCs) in many applications. Since 2000, U.S. production
20 has fluctuated but has generally remained above 1990 levels. Because HCFC-22 depletes stratospheric ozone, its
21 production for non-feedstock uses is scheduled to be phased out by 2020 under the U.S. Clean Air Act.115 Feedstock
22 production, however, is permitted to continue indefinitely.
23 HCFC-22 is produced by the reaction of chloroform (CHC13) and hydrogen fluoride (HF) in the presence of a
24 catalyst, SbCl5. The reaction of the catalyst and HF produces SbClxFy, (where x + y = 5), which reacts with
25 chlorinated hydrocarbons to replace chlorine atoms with fluorine. The HF and chloroform are introduced by
26 submerged piping into a continuous-flow reactor that contains the catalyst in a hydrocarbon mixture of chloroform
27 and partially fluorinated intermediates. The vapors leaving the reactor contain HCFC-21 (CHC12F), HCFC-22
28 (CHC1F2), HFC-23 (CHF3), HC1, chloroform, and HF. The under-fluorinated intermediates (HCFC-21) and
29 chloroform are then condensed and returned to the reactor, along with residual catalyst, to undergo further
30 fluorination. The final vapors leaving the condenser are primarily HCFC-22, HFC-23, HC1 and residual HF. The
31 HC1 is recovered as a useful byproduct, and the HF is removed. Once separated from HCFC-22, the HFC-23 may
32 be released to the atmosphere, recaptured for use in a limited number of applications, or destroyed.
33 Emissions of HFC-23 in 2009 were estimated to be 5.4 Tg CO2 Eq. (0.5 Gg) (Table 4-81). This quantity represents
34 a 60 percent decrease from 2008 emissions and a 85 percent decline from 1990 emissions. The decrease from 2008
35 emissions was caused by a 27 percent decrease in HCFC-22 production and a 46 percent decrease in the HFC-23
36 emission rate. The decline from 1990 emissions is due to a 78 percent decrease in the HFC-23 emission rate since
37 1990. The decrease is primarily attributable to four factors: (a) five plants that did not capture and destroy the HFC-
38 23 generated have ceased production of HCFC-22 since 1990, (b) one plant that captures and destroys the HFC-23
39 generated began to produce HCFC-22, (c) one plant implemented and documented a process change that reduced the
40 amount of HFC-23 generated, and (d) the same plant began recovering HFC-23, primarily for destruction and
41 secondarily for sale. Three HCFC-22 production plants operated in the United States in 2006, two of which used
42 thermal oxidation to significantly lower their HFC-23 emissions.
43 Table 4-81: HFC-23 Emissions from HCFC-22 Production (Tg CO2 Eq. and Gg)
Year TgCO2Eq. Gg
1990 36.4 3
2000 28.6 2
115 As construed, interpreted, and applied in the terms and conditions of the Montreal Protocol on Substances that Deplete the
Ozone Layer. [42 U.S.C. §7671m(b), CAA §614]
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2005
2006
2007
2008
2009
15.8
13.8
17.0
13.6
5.4
1
1
1
1
0.46
1
2 Methodology
3 To estimate their emissions of HFC-23, five of the eight HCFC-22 plants that have operated in the U.S. since 1990
4 use (or, for those plants that have closed, used) methods comparable to the Tier 3 methods in the 2006 IPCC
5 Guidelines (IPCC 2006). The other three plants, the last of which closed in 1993, used methods comparable to the
6 Tier 1 method in the 2006 IPCC Guidelines. Emissions from these three plants have been recalculated using the
7 recommended emission factor for unoptimized plants operating before 1995 (0.04 kg HCFC-23/kg HCFC-22
8 produced). (This recalculation was reflected in the 1990 through 2006 inventory submission.)
9 The five plants that have operated since 1994 measured concentrations of HFC-23 to estimate their emissions of
10 HFC-23. Plants using thermal oxidation to abate their HFC-23 emissions monitor the performance of their oxidizers
11 to verify that the HFC-23 is almost completely destroyed. Plants that release (or historically have released) some of
12 their byproduct HFC-23 periodically measure HFC-23 concentrations in the output stream using gas
13 chromatography. This information is combined with information on quantities of products (e.g., HCFC-22) to
14 estimate HFC-23 emissions.
15 In most years, including 2010, an industry association aggregates and reports to EPA country-level estimates of
16 HCFC-22 production and HFC-23 emissions (ARAP 1997, 1999, 2000, 2001, 2002, 2003, 2004, 2005, 2006, 2007,
17 2008, 2009, 2010). However, in 1997 and 2008, EPA (through a contractor) performed comprehensive reviews of
18 plant-level estimates of HFC-23 emissions and HCFC-22 production (RTI 1997; RTI 2008). These reviews enabled
19 EPA to review, update, and where necessary, correct U.S. totals, and also to perform plant-level uncertainty analyses
20 (Monte-Carlo simulations) for 1990, 1995, 2000, 2005, and 2006. Estimates of annual U.S. HCFC-22 production
21 are presented in Table 4-82.
22 Table 4-82: HCFC-22 Production (Gg)
Year Gg
1990 139
2000 186
2005 156
2006 154
2007 162
2008 126
2009 91
23
24 Uncertainty and Time Series Consistency
25 The uncertainty analysis presented in this section was based on a plant-level Monte Carlo simulation for 2006. The
26 Monte Carlo analysis used estimates of the uncertainties in the individual variables in each plant's estimating
27 procedure. This analysis was based on the generation of 10,000 random samples of model inputs from the
28 probability density functions for each input. A normal probability density function was assumed for all
29 measurements and biases except the equipment leak estimates for one plant; a log-normal probability density
30 function was used for this plant's equipment leak estimates. The simulation for 2006 yielded a 95-percent
31 confidence interval for U.S. emissions of 6.8 percent below to 9.6 percent above the reported total.
32 Because EPA did not have access to plant-level emissions data for 2009, the relative errors yielded by the Monte
33 Carlo simulation for 2006 were applied to the U.S. emission estimate for 2009. The resulting estimates of absolute
34 uncertainty are likely to be accurate because (1) the methods used by the three plants to estimate their emissions are
Industrial Processes 4-61
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1 not believed to have changed significantly since 2006, (2) the distribution of emissions among the plants is not
2 believed to have changed significantly since 2006 (one plant continues to dominate emissions), and (3) the country -
3 level relative errors yielded by the Monte Carlo simulations for 2005 and 2006 were very similar, implying that
4 these errors are not sensitive to small, year-to-year changes.
5 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-83. HFC-23 emissions from
6 HCFC-22 production were estimated to be between 5.0 and 5.9 Tg CO2 Eq. at the 95-percent confidence level. This
7 indicates a range of approximately 7 percent below and 10 percent above the emission estimate of 5.4 Tg CO2 Eq.
8 Table 4-83: Quantitative Uncertainty Estimates for HFC-23 Emissions from HCFC-22 Production (Tg CO2 Eq. and
9 Percent)
2009 Emission
Source Gas Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to Emission Estimate"
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
HCFC-22 Production HFC-23 5.4
5.0 5.9 -7% +10%
10 a Range of emissions reflects a 95 percent confidence interval.
11 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
12 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
13 above.
14 Planned Improvements
15 Beginning in 2010, all U.S. HCFC-22 production facilities will be required to calculate and report their greenhouse
16 gas emissions to EPA through its Greenhouse Gas Reporting Program. Data collected under this program will be
17 used in future inventories to improve the calculation of national emissions from HCFC-22 production.
18
19 4.20. Substitution of Ozone Depleting Substances (IPCC Source Category 2F)
20 Hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs) are used as alternatives to several classes of ozone-
21 depleting substances (OD Ss) that are being phased out under the terms of the Montreal Protocol and the Clean Air
22 Act Amendments of 1990.116 Ozone depleting substances—chlorofluorocarbons (CFCs), halons, carbon
23 tetrachloride, methyl chloroform, and hydrochlorofluorocarbons (HCFCs)—are used in a variety of industrial
24 applications including refrigeration and air conditioning equipment, solvent cleaning, foam production, sterilization,
25 fire extinguishing, and aerosols. Although HFCs and PFCs are not harmful to the stratospheric ozone layer, they are
26 potent greenhouse gases. Emission estimates for HFCs and PFCs used as substitutes for ODSs are provided in Table
27 4-84 and Table 4-85.
28 Table 4-84: Emissions of HFCs and PFCs from OPS Substitutes (Tg CO2 Eq.)
Gas 1990 2000 2005 2006 2007 2008 2009
HFC-23 + + + + + + +
HFC-32 + + 0.3 0.6 0.9 1.2 1.5
HFC-125 + 5.2 10.1 12.4 15.0 17.9 21.1
HFC-134a + 60.4 75.1 75.0 72.3 69.3 66.7
HFC-143a + 4.1 12.2 14.4 16.7 19.2 22.0
HFC-236fa + 0.5 0.8 0.8 0.9 0.9 0.9
CF4 + + + + + + +
Others* 0.3 4.0 5.6 6.0 6.3 6.7 7.0
Total 0.3 74.3 104.2 109.3 112.2 115.2 119.3
29 + Does not exceed 0.05 Tg CO2 Eq.
30 * Others include HFC-152a, HFC-227ea, HFC-245fa, HFC-4310mee, C4F10, and PFC/PFPEs, the latter being a proxy for a
31 diverse collection of PFCs and perfluoropolyethers (PFPEs) employed for solvent applications. For estimating purposes, the
116
[42U.S.C§7671,CAA§601]
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1 GWP value used for PFC/PFPEs was based upon C6F14.
2 Note: Totals may not sum due to independent rounding.
4 Table 4-85: Emissions of HFCs and PFCs from ODS Substitution (Mg)
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Gas 1990
HFC-23 +
HFC-32 +
HFC-125 +
HFC-134a +
HFC-143a +
HFC-236fa +
CF4 +
Others* M
2000
1
27
1,856
46,465
1,089
85
1
M
2005
1
503
3,616
57,777
3,200
125
2
M
2006
1
960
4,442
57,728
3,782
131
2
M
2007
1
1,447
5,374
55,603
4,402
136
2
M
2008
2
1,893
6,402
53,293
5,044
141
2
M
2009
2
2,348
7,538
51,282
5,798
144
2
M
M (Mixture of Gases)
+ Does not exceed 0.5 Mg
* Others include HFC-152a, HFC-227ea, HFC-245fa, HFC-4310mee, C4F10, and PFC/PFPEs, the latter being a proxy for a
diverse collection of PFCs and perfluoropolyethers (PFPEs) employed for solvent applications.
In 1990 and 1991, the only significant emissions of HFCs and PFCs as substitutes to ODSs were relatively small
amounts of HFC-152a—used as an aerosol propellant and also a component of the refrigerant blend R-500 used in
chillers—and HFC-134a in refrigeration end-uses. Beginning in 1992, HFC-134a was used in growing amounts as a
refrigerant in motor vehicle air-conditioners and in refrigerant blends such as R-404A.117 In 1993, the use of HFCs
in foam production began, and in 1994 these compounds also found applications as solvents. In 1995, ODS
substitutes for halons entered widespread use in the United States as halon production was phased-out.
The use and subsequent emissions of HFCs and PFCs as ODS substitutes has been increasing from small amounts in
1990 to 119.3 Tg CO2 Eq. in 2009. This increase was in large part the result of efforts to phase out CFCs and other
ODSs in the United States. In the short term, this trend is expected to continue, and will likely accelerate over the
next decade as HCFCs, which are interim substitutes in many applications, are themselves phased-out under the
provisions of the Copenhagen Amendments to the Montreal Protocol. Improvements in the technologies associated
with the use of these gases and the introduction of alternative gases and technologies, however, may help to offset
this anticipated increase in emissions.
Table 4-86 presents emissions of HFCs and PFCs as ODS substitutes by end-use sector for 1990 through 2009. The
end-use sectors that contributed the most toward emissions of HFCs and PFCs as ODS substitutes in 2009 include
refrigeration and air-conditioning (104.3 Tg CO2 Eq., or approximately 87 percent), aerosols (9.1 Tg CO2 Eq., or
approximately 8 percent), and foams (3.9 Tg CO2 Eq., or approximately 3 percent). Within the refrigeration and air-
conditioning end-use sector, motor vehicle air-conditioning was the highest emitting end-use (45.9 Tg CO2 Eq.),
followed by refrigerated retail food and transport. Each of the end-use sectors is described in more detail below.
29 Table 4-86: Emissions of HFCs and PFCs from ODS Substitutes (Tg CO2 Eq.) by Sector
30
Gas 1990
Refrigeration/ Air Conditioning +
Aerosols 0.3
Foams +
Solvents +
Fire Protection +
Total 0.3
2000
61.6
10.1
0.3
2.1
0.2
74.3
2005
93.1
7.3
1.9
1.3
0.5
104.2
2006
97.6
7.7
2.1
1.3
0.6
109.3
2007
99.8
8.2
2.3
1.3
0.7
112.2
2008
102.0
8.6
2.5
1.3
0.7
115.2
2009
104.3
9.1
3.9
1.3
0.8
119.3
31 Refrigeration/Air Conditioning
32 The refrigeration and air-conditioning sector includes a wide variety of equipment types that have historically used
33 CFCs or HCFCs. End uses within this sector include motor vehicle air-conditioning, retail food refrigeration,
117 R-404A contains HFC-125, HFC-143a, and HFC-134a.
Industrial Processes 4-63
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1 refrigerated transport (e.g., ship holds, truck trailers, railway freight cars), household refrigeration, residential and
2 small commercial air-conditioning/and heat pumps, chillers (large comfort cooling), cold storage facilities, and
3 industrial process refrigeration (e.g., systems used in food processing, chemical, petrochemical, pharmaceutical, oil
4 and gas, and metallurgical industries). As the ODS phaseout is taking effect, most equipment is being or will
5 eventually be retrofitted or replaced to use HFC-based substitutes. Common HFCs in use today in refrigeration/air-
6 conditioning equipment are HFC-134a, R-410A118, R-404A, and R-507A119. These HFCs are emitted to the
7 atmosphere during equipment manufacture and operation (as a result of component failure, leaks, and purges), as
8 well as at servicing and disposal events.
9 Aerosols
10 Aerosol propellants are used in metered dose inhalers (MDIs) and a variety of personal care products and
11 technical/specialty products (e.g., duster sprays and safety horns). Many pharmaceutical companies that produce
12 MDIs—a type of inhaled therapy used to treat asthma and chronic obstructive pulmonary disease—have committed
13 to replace the use of CFCs with HFC-propellant alternatives. The earliest ozone-friendly MDIs were produced with
14 HFC-134a, but the industry has started to use HFC-227ea as well. Conversely, since the use of CFC propellants was
15 banned in 1978, most consumer aerosol products have not transitioned to HFCs, but to "not-in-kind" technologies,
16 such as solid roll-on deodorants and finger-pump sprays. The transition away from ODS in specialty aerosol
17 products has also led to the introduction of non-fluorocarbon alternatives (e.g., hydrocarbon propellants) in certain
18 applications, in addition to HFC-134a or HFC-152a. These propellants are released into the atmosphere as the
19 aerosol products are used.
20 Foams
21 CFCs and HCFCs have traditionally been used as foam blowing agents to produce polyurethane (PU), polystyrene,
22 polyolefin, and phenolic foams, which are used in a wide variety of products and applications. Since the Montreal
23 Protocol, flexible PU foams as well as other types of foam, such as polystyrene sheet, polyolefin, and phenolic foam,
24 have transitioned almost completely away from fluorocompounds, into alternatives such as CO2, methylene
25 chloride, and hydrocarbons. The majority of rigid PU foams have transitioned to HFCs—primarily HFC-134a and
26 HFC-245fa. Today, these HFCs are used to produce polyurethane appliance, PU commercial refrigeration, PU
27 spray, and PU panel foams—used in refrigerators, vending machines, roofing, wall insulation, garage doors, and
28 cold storage applications. In addition, HFC-152a is used to produce polystyrene sheet/board foam, which is used in
29 food packaging and building insulation. Emissions of blowing agents occur when the foam is manufactured as well
30 as during the foam lifetime and at foam disposal, depending on the particular foam type.
31 Solvents
32 CFCs, methyl chloroform (1,1,1-trichloroethane or TCA), and to a lesser extent carbon tetrachloride (CC14) were
33 historically used as solvents in a wide range of cleaning applications, including precision, electronics, and metal
34 cleaning. Since their phaseout, metal cleaning end-use applications have primarily transitioned to non-fluorocarbon
35 solvents and not-in-kind processes. The precision and electronics cleaning end-uses have transitioned in part to high-
36 GWP gases, due to their high reliability, excellent compatibility, good stability, low toxicity, and selective solvency.
37 These applications rely on HFC-4310mee, HFC-365mfc, HFC-245fa, and to a lesser extent, PFCs. Electronics
38 cleaning involves removing flux residue that remains after a soldering operation for printed circuit boards and other
39 contamination-sensitive electronics applications. Precision cleaning may apply to either electronic components or to
40 metal surfaces, and is characterized by products, such as disk drives, gyroscopes, and optical components, that
41 require a high level of cleanliness and generally have complex shapes, small clearances, and other cleaning
42 challenges. The use of solvents yields fugitive emissions of these HFCs and PFCs.
43 Fire Protection
44 Fire protection applications include portable fire extinguishers ("streaming" applications) that originally used halon
45 1211, and total flooding applications that originally used halon 1301, as well as some halon 2402. Since the
118 R-410A contains HFC-32 and HFC-125.
119 R-507A, also called R-507, contains HFC-125 and HFC-143a.
4-64 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 production and sale of halons were banned in the United States in 1994, the halon replacement agent of choice in the
2 streaming sector has been dry chemical, although HFC-236ea is also used to a limited extent. In the total flooding
3 sector, HFC-227ea has emerged as the primary replacement for halon 1301 in applications that require clean agents.
4 Other HFCs, such as HFC-23, HFC-236fa, and HFC-125, are used in smaller amounts. The majority of HFC-227ea
5 in total flooding systems is used to protect essential electronics, as well as in civil aviation, military mobile weapons
6 systems, oil/gas/other process industries, and merchant shipping. As fire protection equipment is tested or
7 deployed, emissions of these HFCs occur.
8 Methodology
9 A detailed Vintaging Model of ODS-containing equipment and products was used to estimate the actual—versus
10 potential—emissions of various ODS substitutes, including HFCs and PFCs. The name of the model refers to the
11 fact that it tracks the use and emissions of various compounds for the annual "vintages" of new equipment that enter
12 service in each end-use. The Vintaging Model predicts ODS and ODS substitute use in the United States based on
13 modeled estimates of the quantity of equipment or products sold each year containing these chemicals and the
14 amount of the chemical required to manufacture and/or maintain equipment and products over time. Emissions for
15 each end-use were estimated by applying annual leak rates and release profiles, which account for the lag in
16 emissions from equipment as they leak over time. By aggregating the data for nearly 60 different end-uses, the
17 model produces estimates of annual use and emissions of each compound. Further information on the Vintaging
18 Model is contained in Annex 3.8.
19 Uncertainty
20 Given that emissions of ODS substitutes occur from thousands of different kinds of equipment and from millions of
21 point and mobile sources throughout the United States, emission estimates must be made using analytical tools such
22 as the Vintaging Model or the methods outlined in IPCC (2006). Though the model is more comprehensive than the
23 IPCC default methodology, significant uncertainties still exist with regard to the levels of equipment sales,
24 equipment characteristics, and end-use emissions profiles that were used to estimate annual emissions for the
25 various compounds.
26 The Vintaging Model estimates emissions from nearly 60 end-uses. The uncertainty analysis, however, quantifies
27 the level of uncertainty associated with the aggregate emissions resulting from the top 21 end-uses, comprising over
28 95 percent of the total emissions, and 5 other end-uses. These 26 end-uses comprise 97 percent of the total
29 emissions. In an effort to improve the uncertainty analysis, additional end-uses are added annually, with the
30 intention that over time uncertainty for all emissions from the Vintaging Model will be fully characterized. Any
31 end-uses included in previous years' uncertainty analysis were included in the current uncertainty analysis, whether
32 or not those end-uses were included in the top 95 percent of emissions from ODS Substitutes.
33 In order to calculate uncertainty, functional forms were developed to simplify some of the complex "vintaging"
34 aspects of some end-use sectors, especially with respect to refrigeration and air-conditioning, and to a lesser degree,
35 fire extinguishing. These sectors calculate emissions based on the entire lifetime of equipment, not just equipment
36 put into commission in the current year, thereby necessitating simplifying equations. The functional forms used
37 variables that included growth rates, emission factors, transition from ODSs, change in charge size as a result of the
38 transition, disposal quantities, disposal emission rates, and either stock for the current year or original ODS
39 consumption. Uncertainty was estimated around each variable within the functional forms based on expert
40 judgment, and a Monte Carlo analysis was performed. The most significant sources of uncertainty for this source
41 category include the emission factors for retail food equipment and refrigerated transport, as well as the percent of
42 non-MDI aerosol propellant that is HFC-152a.
43 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-87. Substitution of ozone
44 depleting substances HFC and PFC emissions were estimated to be between 110.6 and 127.5 Tg CO2 Eq. at the 95
45 percent confidence level. This indicates a range of approximately 7 percent below to 7 percent above the emission
46 estimate of 119.3 Tg CO2 Eq.
47
48
49
Industrial Processes 4-65
-------
1 Table 4-87: Tier 2 Quantitative Uncertainty Estimates for HFC and PFC Emissions from ODS Substitutes (Tg CO2
2 Eq. and Percent)
2009 Emission
Source Gases Estimate
(Tg C02 Eq.)a
Substitution of Ozone
Depleting HFCs and
Substances PFCs 116.6
Uncertainty Range Relative to Emission Estimate1"
(Tg C02 Eq.) (%)
Lower
Bound
107.9
Upper
Bound
124.8
Lower
Bound
-7%
Upper
Bound
+7%
3 a 2009 emission estimates and the uncertainty range presented in this table correspond to selected end uses within the aerosols,
4 foams, solvents, fire extinguishing agents, and refrigerants sectors, but not for other remaining categories. Therefore, because the
5 uncertainty associated with emissions from "other" ODS substitutes was not estimated, they were excluded in the estimates
6 reported in this table.
7 b Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
8 Recalculations Discussion
9 An extensive review of the MDI aerosol, unitary air-conditioning, and domestic refrigerator foams markets resulted
10 in revisions to the Vintaging Model since the previous Inventory. For MDI aerosols, the charge size for both the
11 CFC and HFC propellants was revised. Based on research on substitutes and growth in the market, the percent of the
12 CFC market that transitions to HFCs over the time series and the overall size of the MDI market decreased. For
13 unitary air-conditioning, a review of air conditioner sales data reduced the quantity of air-conditioning equipment
14 introduced into the market for 1990 through!993 and 2008, while increasing the quantity of equipment sold into the
15 market for 1994 through2007. A review of the domestic refrigerator foams market increased the quantity of blowing
16 agent consumed in the foam and decreased the quantity of blowing agent emitted during the foam manufacturing
17 process. Overall, these changes to the Vintaging Model increased GHG emissions on average by 0.5 percent across
18 the time series.
19 4.21. Semiconductor Manufacture (IPCC Source Category 2F6)
20 The semiconductor industry uses multiple long-lived fluorinated gases in plasma etching and plasma enhanced
21 chemical vapor deposition (PECVD) processes to produce semiconductor products. The gases most commonly
22 employed are trifluoromethane (HFC-23 or CHF3), perfluoromethane (CF4), perfluoroethane (C2F6), nitrogen
23 trifluoride (NF3), and sulfur hexafluoride (SF6), although other compounds such as perfluoropropane (C3F8) and
24 perfluorocyclobutane (c-C4F8) are also used. The exact combination of compounds is specific to the process
25 employed.
26 A single 300 mm silicon wafer that yields between 400 to 500 semiconductor products (devices or chips) may
27 require as many as 100 distinct fluorinated-gas-using process steps, principally to deposit and pattern dielectric
28 films. Plasma etching (or patterning) of dielectric films, such as silicon dioxide and silicon nitride, is performed to
29 provide pathways for conducting material to connect individual circuit components in each device. The patterning
30 process uses plasma-generated fluorine atoms, which chemically react with exposed dielectric film to selectively
31 remove the desired portions of the film. The material removed as well as undissociated fluorinated gases flow into
32 waste streams and, unless emission abatement systems are employed, into the atmosphere. PECVD chambers, used
33 for depositing dielectric films, are cleaned periodically using fluorinated and other gases. During the cleaning cycle
34 the gas is converted to fluorine atoms in plasma, which etches away residual material from chamber walls,
35 electrodes, and chamber hardware. Undissociated fluorinated gases and other products pass from the chamber to
36 waste streams and, unless abatement systems are employed, into the atmosphere. In addition to emissions of
37 unreacted gases, some fluorinated compounds can also be transformed in the plasma processes into different
38 fluorinated compounds which are then exhausted, unless abated, into the atmosphere. For example, when C2F6 is
39 used in cleaning or etching, CF4 is generated and emitted as a process by-product. Besides dielectric film etching
40 and PECVD chamber cleaning, much smaller quantities of fluorinated gases are used to etch poly silicon films and
41 refractory metal films like tungsten.
4-66 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1
2
o
6
4
5
6
7
8
9
10
11
12
13
For 2009, total weighted emissions of all fluorinated greenhouse gases by the U.S. semiconductor industry were
estimated to be 5.3 Tg CO2 Eq. Combined emissions of all fluorinated greenhouse gases are presented in Table 4-88
and Table 4-89 below for years 1990, 2000 and the period 2005 to 2009. The rapid growth of this industry and the
increasing complexity (growing number of layers)120 of semiconductor products led to an increase in emissions of
148 percent between 1990 and 1999, when emissions peaked at 7.2 Tg CO2 Eq. The emissions growth rate began to
slow after 1998, and emissions declined by 26 percent between 1999 and 2009. Together, industrial growth and
adoption of emissions reduction technologies, including but not limited to abatement technologies, resulted in a net
increase in emissions of 83 percent between 1990 and 2009.
Table 4-88: PFC, HFC, and SF6 Emissions from Semiconductor Manufacture (Tg CO2 Eq.)
Year
CF4
C2F6
C3F8
C4F8
HFC-23
SF6
NF3*
Total
1990
0.7
1.5
0.0
0.0
0.2
0.5
0.0
2.9
2000 2005
1.8
3.0
0.1
0.0
0.3
1.1
0.2
6.2
Note: Totals may not sum due to independent rounding.
* NF3 emissions are presented for informational purposes, usin^
Table 4-89: PFC,
Year
CF4
C2F6
C3F8
C/iFg
HFC-23
SF6
NF3
1.1
2.0
0.0
0.1
0.2
1.0
0.4
4.4
2006 2007
1.2
2.2
0.0
0.1
0.3
1.0
0.7
4.7
1.3
2.3
0.0
0.1
0.3
0.8
0.5
4.8
I the AR4 GWP of 17,200, and are not
2008
1.4
2.4
0.1
0.1
0.3
0.9
0.6
5.1
included in totals.
2009
1.5
2.5
0.0
0.0
0.3
1.0
0.5
5.3
HFC, and SF6 Emissions from Semiconductor Manufacture (Mg)
1990
115
160
0
0
15
22
3
2000
281
321
18
0
23
45
11
2005
168
216
5
13
18
40
26
2006
181
240
5
13
22
40
40
2007
198
249
6
7
23
34
30
2008
216
261
13
7
25
36
33
2009
227
271
5
4
28
40
30
14
15 Methodology
16 Emissions are based on Partner reported emissions data received through the EPA's PFC Reduction/Climate
17 Partnership and the EPA's PFC Emissions Vintage Model (PEVM), a model which estimates industry emissions in
18 the absence of emission control strategies (Burton and Beizaie 2001).121 The availability and applicability of
19 Partner data differs across the 1990 through 2009 time series. Consequently, emissions from semiconductor
20 manufacturing were estimated using four distinct methods, one each for the periods 1990 through 1994, 1995
21 through 1999, 2000 through 2006, and 2007 through 2009.
22 1990 through 1994
23 From 1990 through 1994, Partnership data was unavailable and emissions were modeled using the PEVM (Burton
24 and Beizaie 2001).122 1990 to 1994 emissions are assumed to be uncontrolled, since reduction strategies such as
120 Complexity is a term denoting the circuit required to connect the active circuit elements (transistors) on a chip. Increasing
miniaturization, for the same chip size, leads to increasing transistor density, which, in turn, requires more complex
interconnections between those transistors. This increasing complexity is manifested by increasing the levels (i.e., layers) of
wiring, with each wiring layer requiring fluorinated gas usage for its manufacture.
121 A Partner refers to a participant in the U.S. EPA PFC Reduction/Climate Partnership for the Semiconductor Industry.
Through a Memorandum of Understanding (MoU) with the EPA, Partners voluntarily report their PFC emissions to the EPA by
way of a third party, which aggregates the emissions.
122 Various versions of the PEVM exist to reflect changing industrial practices. From 1990 to 1994 emissions estimates are from
PEVM vl.O, completed in September 1998. The emission factor used to estimate 1990 to 1994 emissions is an average of the
Industrial Processes 4-67
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1 chemical substitution and abatement were yet to be developed.
2 PEVM is based on the recognition that PFC emissions from semiconductor manufacturing vary with: (1) the number
3 of layers that comprise different kinds of semiconductor devices, including both silicon wafer and metal
4 interconnect layers, and (2) silicon consumption (i.e., the area of semiconductors produced) for each kind of device.
5 The product of these two quantities, Total Manufactured Layer Area (TMLA), constitutes the activity data for
6 semiconductor manufacturing. PEVM also incorporates an emission factor that expresses emissions per unit of
7 layer-area. Emissions are estimated by multiplying TMLA by this emission factor.
8 PEVM incorporates information on the two attributes of semiconductor devices that affect the number of layers: (1)
9 linewidth technology (the smallest manufactured feature size), 123 and (2) product type (discrete, memory or
10 logic).124 For each linewidth technology, a weighted average number of layers is estimated using VLSI product-
11 specific worldwide silicon demand data in conjunction with complexity factors (i.e., the number of layers per
12 Integrated Circuit (1C)) specific to product type (Burton and Beizaie 2001, ITRS 2007). PEVM derives historical
13 consumption of silicon (i.e., square inches) by linewidth technology from published data on annual wafer starts and
14 average wafer size (VLSI Research, Inc. 2010).
15 The emission factor in PEVM is the average of four historical emission factors, each derived by dividing the total
16 annual emissions reported by the Partners for each of the four years between 1996 and 1999 by the total TMLA
17 estimated for the Partners in each of those years. Over this period, the emission factors varied relatively little (i.e.,
18 the relative standard deviation for the average was 5 percent). Since Partners are believed not to have applied
19 significant emission reduction measures before 2000, the resulting average emission factor reflects uncontrolled
20 emissions. The emission factor is used to estimate world uncontrolled emissions using publicly available data on
21 world silicon consumption.
22 1995 through 1999
23 For 1995 through 1999, total U.S. emissions were extrapolated from the total annual emissions reported by the
24 Partners (1995 through 1999). Partner-reported emissions are considered more representative (e.g., in terms of
25 capacity utilization in a given year) than PEVM estimated emissions, and are used to generate total U.S. emissions
26 when applicable. The emissions reported by the Partners were divided by the ratio of the total capacity of the plants
27 operated by the Partners and the total capacity of all of the semiconductor plants in the United States; this ratio
28 represents the share of capacity attributable to the Partnership. This method assumes that Partners and non-Partners
29 have identical capacity utilizations and distributions of manufacturing technologies. Plant capacity data is contained
30 in the World Fab Forecast (WFF) database and its predecessors, which is updated quarterly (Semiconductor
31 Equipment and Materials Industry 2010).
32 2000 through 2006
33 The emission estimate for the years 2000 through 2006—the period during which Partners began the consequential
34 application of PFC-reduction measures—was estimated using a combination of Partner reported emissions and
35 PEVM modeled emissions. The emissions reported by Partners for each year were accepted as the quantity emitted
36 from the share of the industry represented by those Partners. Remaining emissions, those from non-Partners, were
37 estimated using PEVM and the method described above. This is because non-Partners are assumed not to have
38 implemented any PFC-reduction measures, and PEVM models emissions without such measures. The portion of the
39 U.S. total attributed to non-Partners is obtained by multiplying PEVM's total U.S. emissions figure by the non-
1995 and 1996 emissions factors, which were derived from Partner reported data for those years.
123 By decreasing features of Integrated Circuit components, more components can be manufactured per device, which increases
its functionality. However, as those individual components shrink it requires more layers to interconnect them to achieve the
functionality. For example, a microprocessor manufactured with the smallest feature sizes (65 nm) might contain as many as 1
billion transistors and require as many as 11 layers of component interconnects to achieve functionality while a device
manufactured with 130 nm feature size might contain a few hundred million transistors and require 8 layers of component
interconnects (ITRS 2007).
124 Memory devices manufactured with the same feature sizes as microprocessors (a logic device) require approximately one-
half the number of interconnect layers, whereas discrete devices require only a silicon base layer and no interconnect layers
(ITRS 2007). Since discrete devices did not start using PFCs appreciably until 2004, they are only accounted for in the PEVM
emissions estimates from 2004 onwards.
4-68 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Partner share of U. S. total silicon capacity for each year as described above.125>126 Annual updates to PEVM
2 reflect published figures for actual silicon consumption from VLSI Research, Inc., revisions and additions to the
3 world population of semiconductor manufacturing plants, and changes in 1C fabrication practices within the
4 semiconductor industry (see ITRS 2007 and Semiconductor Equipment and Materials Industry 2010).127'128'129
5 2007 through 2009
6 For the years 2007 through 2009, emissions were also estimated using a combination of Partner reported emissions
7 and PEVM modeled emissions; however, two improvements were made to the estimation method employed for the
8 previous years in the time series. First, the 2007 through 2009 emission estimates account for the fact that Partners
9 and non-Partners employ different distributions of manufacturing technologies, with the Partners using
10 manufacturing technologies with greater transistor densities and therefore greater numbers of layers. 13° Second, the
11 scope of the 2007 through 2009 estimates is expanded relative to the estimates for the years 2000 through 2006 to
12 include emissions from Research and Development (R&D) fabs. This was feasible through the use of more detailed
13 data published in the World Fab Forecast. PEVM databases are updated annually as described above. The
14 published world average capacity utilization for 2007 and 2008 was used for production fabs while in 2008 for R&D
15 fabs a 20 percent figure was assumed (SIA 2009).
16 In addition, publicly available actual utilization data was used to account for differences in fab utilization for
17 manufacturers of discrete and 1C products for the emissions in 2009 for non-partners. PEVM estimates were
18 adjusted using technology weighted capacity shares that reflect relative influence of different utilization.
19 Gas-Specific Emissions
20 Two different approaches were also used to estimate the distribution of emissions of specific fluorinated gases.
21 Before 1999, when there was no consequential adoption of fluorinated-gas-reducing measures, a fixed distribution
125 This approach assumes that the distribution of linewidth technologies is the same between Partners and non-Partners. As
discussed in the description of the method used to estimate 2007 emissions, this is not always the case.
126 Generally 5 percent or less of the fields needed to estimate TMLA shares are missing values in the World Fab Watch
databases. In the 2007 World Fab Watch database used to generate the 2006 non-Partner TMLA capacity share, these missing
values were replaced with the corresponding mean TMLA across fabs manufacturing similar classes of products. However, the
impact of replacing missing values on the non-Partner TMLA capacity share was inconsequential.
127 Special attention was given to the manufacturing capacity of plants that use wafers with 300 mm diameters because the actual
capacity of these plants is ramped up to design capacity, typically over a 2-3 year period. To prevent overstating estimates of
partner-capacity shares from plants using 300 mm wafers, design capacities contained in WFW were replaced with estimates of
actual installed capacities for 2004 published by Citigroup Smith Barney (2005). Without this correction, the partner share of
capacity would be overstated, by approximately 5 percent. For perspective, approximately 95 percent of all new capacity
additions in 2004 used 300 mm wafers, and by year-end those plants, on average, could operate at approximately 70 percent of
the design capacity. For 2005, actual installed capacities were estimated using an entry in the World Fab Watch database (April
2006 Edition) called "wafers/month, 8-inch equivalent," which denoted the actual installed capacity instead of the fully-ramped
capacity. For 2006, actual installed capacities of new fabs were estimated using an average monthly ramp rate of 1100 wafer
starts per month (wspm) derived from various sources such as semiconductor fabtech, industry analysts, and articles in the trade
press. The monthly ramp rate was applied from the first-quarter of silicon volume (FQS V) to determine the average design
capacity over the 2006 period.
128 In 2006, the industry trend in co-ownership of manufacturing facilities continued. Several manufacturers, who are Partners,
now operate fabs with other manufacturers, who in some cases are also Partners and in other cases are not Partners. Special
attention was given to this occurrence when estimating the Partner and non-Partner shares of U.S. manufacturing capacity.
129 Two versions of PEVM are used to model non-Partner emissions during this period. For the years 2000 to 2003 PEVM
v3.2.0506.0507 was used to estimate non-Partner emissions. During this time, discrete devices did not use PFCs during
manufacturing and therefore only memory and logic devices were modeled in the PEVM v3.2.0506.0507. From 2004 onwards,
discrete device fabrication started to use PFCs, hence PEVM v4.0.0701.0701, the first version of PEVM to account for PFC
emissions from discrete devices, was used to estimate non-Partner emissions for this time period.
130 EPA considered applying this change to years before 2007, but found that it would be difficult due to the large amount of
data (i.e., technology-specific global and non-Partner TMLA) that would have to be examined and manipulated for each year.
This effort did not appear to be justified given the relatively small impact of the improvement on the total estimate for 2007 and
the fact that the impact of the improvement would likely be lower for earlier years because the estimated share of emissions
accounted for by non-Partners is growing as Partners continue to implement emission-reduction efforts.
Industrial Processes 4-69
-------
1 of fluorinated-gas use was assumed to apply to the entire U.S. industry. This distribution was based upon the
2 average fluorinated-gas purchases made by semiconductor manufacturers during this period and the application of
3 IPCC default emission factors for each gas (Burton and Beizaie 2001). For the 2000 through 2009 period, the 1990
4 through 1999 distribution was assumed to apply to the non-Partners. Partners, however, began reporting gas-
5 specific emissions during this period. Thus, gas-specific emissions for 2000 through 2009 were estimated by adding
6 the emissions reported by the Partners to those estimated for the non-Partners.
7 Data Sources
8 Partners estimate their emissions using a range of methods. For 2009, it is assumed that most Partners used a
9 method at least as accurate as the IPCC's Tier 2a Methodology, recommended in the IPCC Guidelines for National
10 Greenhouse Inventories (2006). Data used to develop emission estimates are attributed in part to estimates provided
11 by the members of the Partnership, and in part from data obtained from PEVM estimates. Estimates of operating
12 plant capacities and characteristics for Partners and non-Partners were derived from the Semiconductor Equipment
13 and Materials Industry (SEMI) World Fab Forecast (formerly World Fab Watch) database (1996 through 2009)
14 (e.g., Semiconductor Materials and Equipment Industry, 2010). Actual world capacity utilizations for 2009 were
15 obtained from Semiconductor International Capacity Statistics (SICAS) (SIA, 2009). Estimates of silicon consumed
16 by linewidth from 1990 through 2009 were derived from information from VLSI Research, Inc. (2010), and the
17 number of layers per linewidth was obtained from International Technology Roadmap for Semiconductors: 2006
18 Update (Burton and Beizaie 2001, ITRS 2007, ITRS 2008).
19 Uncertainty and Time Series Consistency
20 A quantitative uncertainty analysis of this source category was performed using the IPCC-recommended Tier 2
21 uncertainty estimation methodology, the Monte Carlo Stochastic Simulation technique. The equation used to
22 estimate uncertainty is:
23 U.S. emissions = ^Partnership gas-specific submittals + [(non-Partner share of World TMLA) x (PEVM Emission
24 Factor x World TMLA)]
25 The Monte Carlo analysis results presented below relied on estimates of uncertainty attributed to the four quantities
26 on the right side of the equation. Estimates of uncertainty for the four quantities were in turn developed using the
27 estimated uncertainties associated with the individual inputs to each quantity, error propagation analysis, Monte
28 Carlo simulation, and expert judgment. The relative uncertainty associated with World TMLA estimate in 2009 is
29 about ±10 percent, based on the uncertainty estimate obtained from discussions with VLSI, Inc. For the share of
30 World layer-weighted silicon capacity accounted for by non-Partners, a relative uncertainty of ±8 percent was
31 estimated based on a separate Monte Carlo simulation to account for the random occurrence of missing data in the
32 World Fab Watch database. For the aggregate PFC emissions data supplied to the partnership, a relative uncertainty
33 of ±50 percent was estimated for each gas-specific PFC emissions value reported by an individual Partner, and error
34 propagation techniques were used to estimate uncertainty for total Partnership gas-specific submittals.131 A relative
35 uncertainty of approximately ±10 percent was estimated for the PEVM emission factor, based on the standard
36 deviation of the 1996 to 1999 emission factors.132 All estimates of uncertainties are given at 95-percent confidence
37 intervals.
38 In developing estimates of uncertainty, consideration was also given to the nature and magnitude of the potential
39 bias that World activity data (i.e., World TMLA) might have in its estimates of the number of layers associated with
40 devices manufactured at each technology node. The result of a brief analysis indicated that U.S. TMLA overstates
41 the average number of layers across all product categories and all manufacturing technologies for 2004 by 0.12
42 layers or 2.9 percent. The same upward bias is assumed for World TMLA, and is represented in the uncertainty
43 analysis by deducting the absolute bias value from the World activity estimate when it is incorporated into the
44 Monte Carlo analysis.
45 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-90. The emissions estimate for
46 total U.S. PFC emissions from semiconductor manufacturing were estimated to be between 4.8 and 5.9 Tg CO2 Eq.
131 Error propagation resulted in Partnership gas-specific uncertainties ranging from 17 to 27 percent
132 The average of 1996 to 1999 emission factor is used to derive the PEVM emission factor.
4-70 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 at a 95 percent confidence level. This range represents 10 percent below to 11 percent above the 2009 emission
2 estimate of 5.3 Tg CO2 Eq. This range and the associated percentages apply to the estimate of total emissions rather
3 than those of individual gases. Uncertainties associated with individual gases will be somewhat higher than the
4 aggregate, but were not explicitly modeled.
5 Table 4-90: Tier 2 Quantitative Uncertainty Estimates for HFC, PFC, and SF6 Emissions from Semiconductor
6 Manufacture (Tg CO2 Eq. and Percent)
2009 Emission
Source Gas Estimate" Uncertainty Range Relative to Emission Estimate1"
(TgC02Eq.) (TgC02Eq.) (%)
Semiconductor HFC, PFC,
Manufacture and SF6 5.3
Lower
Bound0
4.8
Upper
Bound0
5.9
Lower
Bound
-10%
Upper
Bound
+11%
7 a Because the uncertainty analysis covered all emissions (including NF3), the emission estimate presented here does not match
8 that shown in Table 4-88.
9 b Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
10 ° Absolute lower and upper bounds were calculated using the corresponding lower and upper bounds in percentages.
11 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
12 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
13 above.
14 Planned Improvements
15 With the exception of possible future updates to emission factors, the method to estimate non-Partner related
16 emissions (i.e., PEVM) is not expected to change. Future improvements to the national emission estimates will
17 primarily be associated with determining the portion of national emissions to attribute to Partner report totals (about
18 80 percent in recent years) and improvements in estimates of non-Partner totals. As the nature of the Partner reports
19 change through time and industry-wide reduction efforts increase, consideration will be given to what emission
20 reduction efforts—if any—are likely to be occurring at non-Partner facilities. Currently, none are assumed to occur.
21 Another point of consideration for future national emissions estimates is the inclusion of PFC emissions from heat
22 transfer fluid (HTF) loss to the atmosphere and the production of photovoltaic cells (PVs). Heat transfer fluids, of
23 which some are liquid perfluorinated compounds, are used during testing of semiconductor devices and,
24 increasingly, are used to manage heat during the manufacture of semiconductor devices. Evaporation of these fluids
25 is a source of emissions (EPA 2006). PFCs are also used during manufacture of PV cells that use silicon
26 technology, specifically, crystalline, polycrystalline, and amorphous silicon technologies. PV manufacture is
27 growing in the United States, and therefore may be expected to constitute a growing share of U.S. PFC emissions
28 from the electronics sector.
29 4.22. Electrical Transmission and Distribution (IPCC Source Category 2F7)
30 The largest use of SF6, both in the United States and internationally, is as an electrical insulator and interrupter in
31 equipment that transmits and distributes electricity (RAND 2004). The gas has been employed by the electric power
32 industry in the United States since the 1950s because of its dielectric strength and arc-quenching characteristics. It
33 is used in gas-insulated substations, circuit breakers, and other switchgear. Sulfur hexafluoride has replaced
34 flammable insulating oils in many applications and allows for more compact substations in dense urban areas.
35 Fugitive emissions of SF6 can escape from gas-insulated substations and switchgear through seals, especially from
36 older equipment. The gas can also be released during equipment manufacturing, installation, servicing, and
37 disposal. Emissions of SF6 from equipment manufacturing and from electrical transmission and distribution systems
38 were estimated to be 12.8 Tg CO2 Eq. (0.5 Gg) in 2009. This quantity represents a 55 percent decrease from the
39 estimate for 1990 (see Table 4-91 and Table 4-92). This decrease is believed to have two causes: a sharp increase in
40 the price of SF6 during the 1990s and a growing awareness of the environmental impact of SF6 emissions through
41 programs such as EPA's SF6 Emission Reduction Partnership for Electric Power Systems.
42
Industrial Processes 4-71
-------
1 Table 4-91: SF6 Emissions from Electric Power Systems and Electrical Equipment Manufacturers (Tg CO2 Eq.)
Year Electric Power Electrical Equipment Total
Systems Manufacturers
1990
2000
2005
2006
2007
2008
2009
28.1
15.4
14.1
13.1
12.4
12.1
12.1
0.3
0.7
1.1
1.0
0.8
1.3
0.7
28.4
16.0
15.1
14.1
13.2
13.3
12.8
2 Note: Totals may not sum due to independent rounding.
3 Table 4-92: SF6 Emissions from Electric Power Systems and Electrical Equipment Manufacturers (Gg)
Year
1990
2000
2005
2006
2007
2008
2009
Emissions
1.2
0.7
0.6
0.6
0.6
0.6
0.5
5 Methodology
6 The estimates of emissions from Electric Transmission and Distribution are comprised of emissions from electric
7 power systems and emissions from the manufacture of electrical equipment. The methodologies for estimating both
8 sets of emissions are described below.
9 1999 through 2009 Emissions from Electric Power Systems
10 Emissions from electric power systems from 1999 to 2009 were estimated based on: (1) reporting from utilities
11 participating in EPA's SF6 Emission Reduction Partnership for Electric Power Systems (Partners), which began in
12 1999; and, (2) the relationship between emissions and utilities' transmission miles as reported in the 2001, 2004,
13 2007, and 2010 Utility Data Institute (UDI) Directories of Electric Power Producers and Distributors (UDI2001,
14 2004,2007,2010). (Transmission miles are defined as the miles of lines carrying voltages above 34.5 kV.) Over
15 the period from 1999 to 2009, Partner utilities, which for inventory purposes are defined as utilities that either
16 currently are or previously have been part of the Partnership, represented between 42 percent and 47 percent of total
17 U.S. transmission miles. For each year, the emissions reported by or estimated for Partner utilities were added to the
18 emissions estimated for utilities that have never participated in the Partnership (i.e., non-Partners).133
19 Partner utilities estimated their emissions using a Tier 3 utility-level mass balance approach (IPCC 2006). If a
20 Partner utility did not provide data for a particular year, emissions were interpolated between years for which data
21 were available or extrapolated based on Partner-specific transmission mile growth rates. In 2009, non-reporting
22 Partners accounted for approximately 8 percent of the total emissions attributed to Partner utilities.
23 Emissions from non-Partners in every year since 1999 were estimated using the results of a regression analysis that
24 showed that the emissions from reporting utilities were most strongly correlated with their transmission miles. The
25 results of this analysis are not surprising given that, in the United States, SF6 is contained primarily in transmission
26 equipment rated above 34.5 kV. The equations were developed based on the 1999 SF6 emissions reported by a
27 subset of 42 Partner utilities (representing approximately 23 percent of U.S. transmission miles) and 2000
133 Partners in EPA's SF6 Emission Reduction Partnership reduced their emissions by approximately 61% from 1999 to 2008.
4-72 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 transmission mileage data obtained from the 2001 UDI Directory of Electric Power Producers and Distributors (UDI
2 2001). Two equations were developed, one for small and one for large utilities (i.e., with fewer or more than 10,000
3 transmission miles, respectively). The distinction between utility sizes was made because the regression analysis
4 showed that the relationship between emissions and transmission miles differed for small and large transmission
5 networks. The same equations were used to estimate non-Partner emissions in 1999 and every year thereafter
6 because non-Partners were assumed not to have implemented any changes that would have resulted in reduced
7 emissions since 1999.
8 The regression equations are:
9 Non-Partner small utilities (fewer than 10,000 transmission miles, in kilograms):
10 Emissions (kg) = 1.001 x Transmission Miles
11 Non-Partner large utilities (more than 10,000 transmission miles, in kilograms):
12 Emissions (kg) = 0.58 x Transmission Miles
13 Data on transmission miles for each non-Partner utility for the years 2000, 2003, 2006, and 2009 were obtained from
14 the 2001, 2004, 2007, and 2010 UDI Directories of Electric Power Producers and Distributors, respectively (UDI
15 2001, 2004, 2007, 2010). The U.S. transmission system grew by over 25,000 miles between 2000 and 2003 and by
16 over 52,000 miles between 2003 and 2006. These periodic increases are assumed to have occurred gradually.
17 Therefore, transmission mileage was assumed to increase at an annual rate of 1.3 percent between 2000 and 2003
18 and 2.6 percent between 2003 and 2006. This growth rate slowed to 0.2% from 2006 to 2009 as transmission miles
19 increased by just 4,400 miles (approximately).
20 As a final step, total electric power system emissions were determined for each year by summing the Partner
21 reported and estimated emissions (reported data was available through the EPA's SF6 Emission Reduction
22 Partnership for Electric Power Systems) and the non-Partner emissions (determined using the 1999 regression
23 equations).
24 1990 through 1998 Emissions from Electric Power Systems
25 Because most participating utilities reported emissions only for 1999 through 2009, modeling was used to estimate
26 SF6 emissions from electric power systems for the years 1990 through 1998. To perform this modeling, U.S.
27 emissions were assumed to follow the same trajectory as global emissions from this source during the 1990 to 1999
28 period. To estimate global emissions, the RAND survey of global SF6 sales were used, together with the following
29 equation for estimating emissions, which is derived from the mass-balance equation for chemical emissions
30 (Volume 3, Equation 7.3) in the IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006). 134
31 (Although equation 7.3 of the IPCC Guidelines appears in the discussion of substitutes for ozone-depleting
32 substances, it is applicable to emissions from any long-lived pressurized equipment that is periodically serviced
33 during its lifetime.)
34 Emissions (kilograms SF6) = SF6 purchased to refill existing equipment (kilograms) + nameplate capacity of retiring
35 equipment (kilograms)135
36 Note that the above equation holds whether the gas from retiring equipment is released or recaptured; if the gas is
37 recaptured, it is used to refill existing equipment, thereby lowering the amount of SF6 purchased by utilities for this
38 purpose.
39 Gas purchases by utilities and equipment manufacturers from 1961 through 2003 are available from the RAND
40 (2004) survey. To estimate the quantity of SF6 released or recovered from retiring equipment, the nameplate
41 capacity of retiring equipment in a given year was assumed to equal 81.2 percent of the amount of gas purchased by
42 electrical equipment manufacturers 40 years previous (e.g., in 2000, the nameplate capacity of retiring equipment
43 was assumed to equal 81.2 percent of the gas purchased in 1960). The remaining 18.8 percent was assumed to have
134 Ideally, sales to utilities in the U.S. between 1990 and 1999 would be used as a model. However, this information was not
available. There were only two U.S. manufacturers of SF6 during this time period, so it would not have been possible to conceal
sensitive sales information by aggregation.
135 Nameplate capacity is defined as the amount of SF6 within fully charged electrical equipment.
Industrial Processes 4-73
-------
1 been emitted at the time of manufacture. The 18.8 percent emission factor is an average of IPCC default SF6
2 emission rates for Europe and Japan for 1995 (IPCC 2006). The 40-year lifetime for electrical equipment is also
3 based on IPCC (2006). The results of the two components of the above equation were then summed to yield
4 estimates of global SF6 emissions from 1990 through 1999.
5 U.S. emissions between 1990 and 1999 are assumed to follow the same trajectory as global emissions during this
6 period. To estimate U.S. emissions, global emissions for each year from 1990 through 1998 were divided by the
7 estimated global emissions from 1999. The result was a time series of factors that express each year's global
8 emissions as a multiple of 1999 global emissions. Historical U.S. emissions were estimated by multiplying the
9 factor for each respective year by the estimated U.S. emissions of SF6 from electric power systems in 1999
10 (estimated to be 15.0 Tg CO2 Eq.).
11 Two factors may affect the relationship between the RAND sales trends and actual global emission trends. One is
12 utilities' inventories of SF6 in storage containers. When SF6 prices rise, utilities are likely to deplete internal
13 inventories before purchasing new SF6 at the higher price, in which case SF6 sales will fall more quickly than
14 emissions. On the other hand, when SF6 prices fall, utilities are likely to purchase more SF6 to rebuild inventories,
15 in which case sales will rise more quickly than emissions. This effect was accounted for by applying 3-year
16 smoothing to utility SF6 sales data. The other factor that may affect the relationship between the RAND sales trends
17 and actual global emissions is the level of imports from and exports to Russia and China. SF6 production in these
18 countries is not included in the RAND survey and is not accounted for in any another manner by RAND. However,
19 atmospheric studies confirm that the downward trend in estimated global emissions between 1995 and 1998 was real
20 (see the Uncertainty discussion below).
21 1990 through 2009 Emissions from Manufacture of Electrical Equipment
22 The 1990 to 2009 emission estimates for original equipment manufacturers (OEMs) were derived by assuming that
23 manufacturing emissions equal 10 percent of the quantity of SF6 provided with new equipment. The quantity of SF6
24 provided with new equipment was estimated based on statistics compiled by the National Electrical Manufacturers
25 Association (NEMA). These statistics were provided for 1990 to 2000; the quantities of SF6 provided with new
26 equipment for 2001 to 2009 were estimated using Partner reported data and the total industry SF6 nameplate
27 capacity estimate (137.4 Tg CO2 Eq. in 2009). Specifically, the ratio of new nameplate capacity to total nameplate
28 capacity of a subset of Partners for which new nameplate capacity data was available from 1999 to 2009 was
29 calculated. This ratio was then multiplied by the total industry nameplate capacity estimate to derive the amount of
30 SF6 provided with new equipment for the entire industry. The 10 percent emission rate is the average of the "ideal"
31 and "realistic" manufacturing emission rates (4 percent and 17 percent, respectively) identified in a paper prepared
32 under the auspices of the International Council on Large Electric Systems (CIGRE) in February 2002 (O'Connell et
33 al. 2002).
34 Uncertainty
35 To estimate the uncertainty associated with emissions of SF6 from Electric Transmission and Distribution,
36 uncertainties associated with three quantities were estimated: (1) emissions from Partners, (2) emissions from non-
37 Partners, and (3) emissions from manufacturers of electrical equipment. A Monte Carlo analysis was then applied to
38 estimate the overall uncertainty of the emissions estimate.
39 Total emissions from the SF6 Emission Reduction Partnership include emissions from both reporting and non-
40 reporting Partners. For reporting Partners, individual Partner-reported SF6 data was assumed to have an uncertainty
41 of 10 percent. Based on a Monte Carlo analysis, the cumulative uncertainty of all Partner reported data was
42 estimated to be 5.3 percent. The uncertainty associated with extrapolated or interpolated emissions from non-
43 reporting Partners was assumed to be 20 percent.
44 There are two sources of uncertainty associated with the regression equations used to estimate emissions in 2009
45 from non-Partners: 1) uncertainty in the coefficients (as defined by the regression standard error estimate), and 2)
46 the uncertainty in total transmission miles for non-Partners. In addition, there is uncertainty associated with the
47 assumption that the emission factor used for non-Partner utilities (which accounted for approximately 57 percent of
48 U.S. transmission miles in 2009) will remain at levels defined by Partners who reported in 1999. However, the last
49 source of uncertainty was not modeled.
50 Uncertainties were also estimated regarding (1) the quantity of SF6 supplied with equipment by equipment
4-74 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 manufacturers, which is projected from Partner provided nameplate capacity data and industry SF6 nameplate
2 capacity estimates, and (2) the manufacturers' SF6 emissions rate.
3 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 4-93. Electrical Transmission
4 and Distribution SF6 emissions were estimated to be between 10.2 and 15.7 Tg CO2 Eq. at the 95 percent confidence
5 level. This indicates a range of approximately 21 percent below and 22 percent above the emission estimate of 12.8
6 Tg CO2 Eq.
7 Table 4-93: Tier 2 Quantitative Uncertainty Estimates for SF6 Emissions from Electrical Transmission and
Distribution (Tg CO2 Eq. and percent)
Source
2009 Emission
Gas Estimate
(Tg C02 Eq.)
Uncertainty Range Relative to 2009 Emission Estimate"
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Electrical Transmission
and Distribution SFg 12.8 10.2 15.7 -21% +22%
9 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
10
11 In addition to the uncertainty quantified above, there is uncertainty associated with using global SF6 sales data to
12 estimate U.S. emission trends from 1990 through 1999. However, the trend in global emissions implied by sales of
13 SF6 appears to reflect the trend in global emissions implied by changing SF6 concentrations in the atmosphere. That
14 is, emissions based on global sales declined by 29 percent between 1995 and 1998, and emissions based on
15 atmospheric measurements declined by 27 percent over the same period.
16 Several pieces of evidence indicate that U.S. SF6 emissions were reduced as global emissions were reduced. First,
17 the decreases in sales and emissions coincided with a sharp increase in the price of SF6 that occurred in the mid-
18 1990s and that affected the United States as well as the rest of the world. A representative from DILO, a major
19 manufacturer of SF6 recycling equipment, stated that most U.S. utilities began recycling rather than venting SF6
20 within two years of the price rise. Finally, the emissions reported by the one U.S. utility that reported 1990 through
21 1999 emissions to EPA showed a downward trend beginning in the mid-1990s.
22 Recalculations Discussion
23 SF6 emission estimates for the period 1990 through 2008 were updated based on 1) new data from EPA's SF6
24 Emission Reduction Partnership; 2) revisions to interpolated and extrapolated non-reported Partner data; and 3) a
25 correction made to 2004 transmission mile data for a large Partnership utility that had been interpreted incorrectly
26 from the UDI database in previous years. Updating the 2004 transmission mile data for the Partner changed the
27 annual transmission mile growth rates used to extrapolate total U.S. transmission mile values for years in which a
28 UDI database was not purchased (including 1999). This recalculation impacted emission estimates in two ways.
29 First, the regression coefficients used to estimate emissions for non-Partners are based on 1999 transmission miles
30 and emissions for Partners that reported emissions in 1999, so the change in 1999 transmission miles affected the
31 regression coefficients. The result was that the regression coefficient for utilities with fewer than 10,000
32 transmission miles increased from 0.89 to 1.001 kg of emissions per transmission mile, while the regression
33 coefficient for utilities with more than 10,000 transmission miles increased very slightly from 0.577 to 0.578 kg of
34 emissions per transmission mile. The second impact of the updated annual transmission mile growth rates was that
35 the total non-Partner transmission miles that the regression coefficients are applied to were also affected. Based on
36 the revisions listed above, SF6 emissions from electric transmission and distribution increased between 4 to 9
37 percent for each year from 1990 through 2008.
38 In addition, the method for estimating potential emissions from the sector was updated for the 1990-2009 Inventory.
39 In previous years, potential emissions were assumed to equal total industry SF6 purchases, which were developed
40 from two components: (1) purchases by Partner utilities from bulk gas distributors, and (2) purchases by electrical
41 equipment manufacturers from bulk gas distributors. This previous method led to concerns of double-counting since
42 Partners sometimes were recording all SF6 received in cylinders from any source (including equipment
43 manufacturers) as gas received from bulk distributors. Therefore, SF6 that was purchased by a utility from an
44 equipment manufacturer was sometimes counted as a purchase by both the equipment manufacturer and the utility.
45 The new method still assumes that potential emissions are equal to industry purchases, but estimates total purchases
Industrial Processes 4-75
-------
1 for the industry by adding the total amount of gas purchased by all U. S. utilities from any source (bulk distributor or
2 equipment manufacturer) to estimated emissions from equipment manufacturers. It is assumed that all SF6 purchased
3 by equipment manufacturers is either emitted or sent to utilities.
4 4.23. Industrial Sources of Indirect Greenhouse Gases - TO BE UPDATED
5
6
7
8
9
10
11
12
13
In addition to the main greenhouse gases addressed above, many industrial processes generate emissions of indirect
greenhouse gases. Total emissions of nitrogen oxides (NOX), carbon monoxide (CO), and non-CH4 volatile organic
compounds (NMVOCs) from non-energy industrial processes from 1990 to 2008 are reported inTable 4-94.
Table 4-94: NOX, CO, and NMVOC Emissions from Industrial Processes (Gg)
Gas/Source
NOX
Other Industrial Processes
Chemical & Allied Product
Manufacturing
Metals Processing
Storage and Transport
Miscellaneous*
CO
Metals Processing
Other Industrial Processes
Chemical & Allied Product
Manufacturing
Storage and Transport
Miscellaneous*
NMVOCs
Storage and Transport
Other Industrial Processes
Chemical & Allied Product
Manufacturing
Metals Processing
Miscellaneous*
1990
591
343
152
88
3
5
4,125
2,395
487
1,073
69
101
2,422
1,352
364
575
111
20
1995
3
2
1
2
1
607
362
143
89
5
8
,959
,159
566
,110
23
102
,642
,499
408
599
113
23
2000
626
95
81
14
2
2,216
1,175
537
327
1,773
1,067
412
230
61
3
2005
569
437
\
2
1,555
752
484
189
97
32
1,997
1,308
415
213
44
17
* Miscellaneous includes the following categories: catastrophic/accidental release, other combustion,
towers, and fugitive dust. It does not include a£
Field Burning of Agricultural Residues source.
'ricultural
2006
553
418
57
61
15
2
1,597
788
474
206
100
30
1,933
1,266
398
211
44
14
2007
537
398
59
62
16
2
1,640
824
464
223
103
27
1,869
1,224
383
210
43
10
2008
520
379
61
62
16
2
1,682
859
454
240
104
25
1,804
1,182
367
207
42
7
health services, cooling
fires or slash/prescribed burning, which are accounted for under the
Note: Totals may not sum due to independent rounding.
14 Methodology
15 These emission estimates were obtained from preliminary data (EPA 2009), and disaggregated based on EPA
16 (2003), which, in its final iteration, will be published on the National Emission Inventory (NEI) Air Pollutant
17 Emission Trends web site. Emissions were calculated either for individual categories or for many categories
18 combined, using basic activity data (e.g., the amount of raw material processed) as an indicator of emissions.
19 National activity data were collected for individual categories from various agencies. Depending on the category,
20 these basic activity data may include data on production, fuel deliveries, raw material processed, etc.
21 Activity data were used in conjunction with emission factors, which together relate the quantity of emissions to the
22 activity. Emission factors are generally available from the EPA's Compilation of Air Pollutant Emission Factors,
23 AP-42 (EPA 1997). The EPA currently derives the overall emission control efficiency of a source category from a
24 variety of information sources, including published reports, the 1985 National Acid Precipitation and Assessment
25 Program emissions inventory, and other EPA databases.
26 Uncertainty and Time-Series Consistency
27 Uncertainties in these estimates are partly due to the accuracy of the emission factors used and accurate estimates of
28 activity data. A quantitative uncertainty analysis was not performed.
4-76 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
2 through 2008. Details on the emission trends through time are described in more detail in the Methodology section,
3 above.
Industrial Processes 4-77
-------
Substitution of Ozone Depleting Substances
Iron and Steel Prod. & Metallurgical Coke Prod.
Cement Production
Nitric Acid Production
Electrical Transmission and Distribution
Ammonia Production and Urea Application
Lime Production
Limestone and Dolomite Use
HCFC-22 Production ^H
Semiconductor Manufacture ^^|
Aluminum Production ^^|
Soda Ash Production and Consumption ^^|
Petrochemical Production ^|
Adipic Acid Production |
Carbon Dioxide Consumption |
Ferroalloy Production |
Titanium Dioxide Production |
Magnesium Production and Processing |
Phosphoric Acid Production |
Zinc Production |
Lead Production |
Silicon Carbide Production and Consumption < 0-5
119
Industrial Processes
as a Portion of all Emissions
4.3%
10
20
TgCO2Eq.
30
40
50
Figure 4-1: 2009 Industrial Processes Chapter Greenhouse Gas Sources
-------
i 5. Solvent and Other Product Use
2 Greenhouse gas emissions are produced as a by-product of various solvent and other product uses. In the United
3 States, emissions from Nitrous Oxide (N2O) Product Uses, the only source of greenhouse gas emissions from this
4 sector, accounted for less than 0.1 percent of total U.S. anthropogenic greenhouse gas emissions on a CO2 equivalent
5 basis in 2009 (see Table 5-1). Indirect greenhouse gas emissions also result from solvent and other product use, and
6 are presented in Table 5-5 in gigagrams (Gg).
7 Table 5-1: N2O Emissions from Solvent and Other Product Use (Tg CO2 Eq. and Gg)
Gas/Source 1990 2000 2005 2006 2007 2008 2009
N2O from Product Uses
TgC02
Gg
Eq.
4.4
14
4.9
16
4.4
14
4.4
14
4.4
14
4.4
14
4.4
14
9 5.1. Nitrous Oxide from Product Uses (IPCC Source Category 3D)
10 N2O is a clear, colorless, oxidizing liquefied gas, with a slightly sweet odor. Two companies operate a total of five
11 N2O production facilities in the United States (Airgas 2007; FTC 2001). N2O is primarily used in carrier gases with
12 oxygen to administer more potent inhalation anesthetics for general anesthesia, and as an anesthetic in various dental
13 and veterinary applications. As such, it is used to treat short-term pain, for sedation in minor elective surgeries, and
14 as an induction anesthetic. The second main use of N2O is as a propellant in pressure and aerosol products, the
15 largest application being pressure-packaged whipped cream. Small quantities of N2O also are used in the following
16 applications:
17 • Oxidizing agent and etchant used in semiconductor manufacturing;
18 • Oxidizing agent used, with acetylene, in atomic absorption spectrometry;
19 • Production of sodium azide, which is used to inflate airbags;
20 • Fuel oxidant in auto racing; and
21 • Oxidizing agent in blowtorches used by jewelers and others (Heydorn 1997).
22 Production of N2O in 2009 was approximately 15 Gg (Table 5-2).
23 Table 5-2: N2O Production (Gg)
Year Gg
1990 16
2000 17
2005 15
2006 15
2007 15
2008 15
2009 15
24
25 N2O emissions were 4.4 Tg CO2 Eq. (14 Gg) in 2009 (Table 5-3). Production of N2O stabilized during the 1990s
26 because medical markets had found other substitutes for anesthetics, and more medical procedures were being
27 performed on an outpatient basis using local anesthetics that do not require N2O. The use of N2O as a propellant for
28 whipped cream has also stabilized due to the increased popularity of cream products packaged in reusable plastic
29 tubs (Heydorn 1997).
30 Table 5-3: N2O Emissions from N2O Product Usage (Tg CO2 Eq. and Gg)
Year Tg CO2 Eq. Gg
1990 4.4 14
Solvents and Other Product Use 5-1
-------
2000 4.9 16
2005
2006
2007
2008
2009
4.4
4.4
4.4
4.4
4.4
14
14
14
14
14
1
2 Methodology
3 Emissions from N2O product usage were calculated by first multiplying the total amount of N2O produced in the
4 United States by the share of the total quantity of N2O attributed to each end use. This value was then multiplied by
5 the associated emission rate for each end use. After the emissions were calculated for each end use, they were added
6 together to obtain a total estimate of N2O product usage emissions. Emissions were determined using the following
7 equation:
8 N2O Product Usage Emissions = Zi [Total U.S. Production of N2O] x [Share of Total Quantity of N2O Usage by
9 Sector i] x [Emissions Rate for Sector i]
10 where,
11 i = Sector.
12 The share of total quantity of N2O usage by end use represents the share of national N2O produced that is used by
13 the specific subcategory (i.e., anesthesia, food processing, etc.). In 2009, the medical/dental industry used an
14 estimated 89.5 percent of total N2O produced, followed by food processing propellants at 6.5 percent. All other
15 categories combined used the remainder of the N2O produced. This subcategory breakdown has changed only
16 slightly over the past decade. For instance, the small share of N2O usage in the production of sodium azide has
17 declined significantly during the 1990s. Dueto the lack of information on the specific time period of the phase-out
18 in this market subcategory, most of the N2O usage for sodium azide production is assumed to have ceased after
19 1996, with the majority of its small share of the market assigned to the larger medical/dental consumption
20 subcategory (Heydorn 1997). The N2O was allocated across the following categories: medical applications, food
21 processing propellant, and sodium azide production (pre-1996). A usage emissions rate was then applied for each
22 sector to estimate the amount of N2O emitted.
23 Only the medical/dental and food propellant subcategories were estimated to release emissions into the atmosphere,
24 and therefore these subcategories were the only usage subcategories with emission rates. For the medical/dental
25 subcategory, due to the poor solubility of N2O in blood and other tissues, none of the N2O is assumed to be
26 metabolized during anesthesia and quickly leaves the body in exhaled breath. Therefore, an emission factor of 100
27 percent was used for this subcategory (IPCC 2006). For N2O used as a propellant in pressurized and aerosol food
28 products, none of the N2O is reacted during the process and all of the N2O is emitted to the atmosphere, resulting in
29 an emission factor of 100 percent for this subcategory (IPCC 2006). For the remaining subcategories, all of the N2O
30 is consumed/reacted during the process, and therefore the emission rate was considered to be zero percent (Tupman
31 2002).
32 The 1990 through 1992 N2O production data were obtained from SRI Consulting's Nitrous Oxide, North America
33 report (Heydorn 1997). N2O production data for 1993 through 1995 were not available. Production data for 1996
34 was specified as a range in two data sources (Heydorn 1997, Tupman 2002). In particular, for 1996, Heydorn
35 (1997) estimates N2O production to range between 13.6 and 18.1 thousand metric tons. Tupman (2003) provided a
36 narrower range (15.9 to 18.1 thousand metric tons) for 1996 that falls within the production bounds described by
37 Heydorn (1997). Tupman (2003) data are considered more industry-specific and current. Therefore, the midpoint of
38 the narrower production range was used to estimate N2O emissions foryears 1993 through 2001 (Tupman 2003).
39 The 2002 and 2003 N2O production data were obtained from the Compressed Gas Association Nitrous Oxide Fact
40 Sheet and Nitrous Oxide Abuse Hotline (CGA 2002, 2003). These data were also provided as a range. For
41 example, in 2003, CGA (2003) estimates N2O production to range between 13.6 and 15.9 thousand metric tons. Due
42 to unavailable data, production estimates for years 2004 through 2009 were held at the 2003 value.
43 The 1996 share of the total quantity of N2O used by each subcategory was obtained from SRI Consulting's Nitrous
5-2 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Oxide, North America report (Heydorn 1997). The 1990 through 1995 share of total quantity of N2O used by each
2 subcategory was kept the same as the 1996 number provided by SRI Consulting. The 1997 through 2001 share of
3 total quantity of N2O usage by sector was obtained from communication with a N2O industry expert (Tupman 2002).
4 The 2002 and 2003 share of total quantity of N2O usage by sector was obtained from CGA (2002, 2003). Due to
5 unavailable data, the share of total quantity of N2O usage data for years 2004 through 2009 was assumed to equal
6 the 2003 value. The emissions rate for the food processing propellant industry was obtained from SRI Consulting's
7 Nitrous Oxide, North America report (Heydorn 1997), and confirmed by a N2O industry expert (Tupman 2002).
8 The emissions rate for all other subcategories was obtained from communication with a N2O industry expert
9 (Tupman 2002). The emissions rate for the medical/dental subcategory was obtained from the 2006 IPCC
10 Guidelines.
11 Uncertainty and Time-Series Consistency
12 The overall uncertainty associated with the 2009 N2O emission estimate from N2O product usage was calculated
13 using the IPCC Guidelines for National Greenhouse Gas Inventories (2006) Tier 2 methodology. Uncertainty
14 associated with the parameters used to estimate N2O emissions include production data, total market share of each
15 end use, and the emission factors applied to each end use, respectively.
16 The results of this Tier 2 quantitative uncertainty analysis are summarized in Table 5-4. N2O emissions from N2O
17 product usage were estimated to be between 4. 1 and 4.7 Tg CO2 Eq. at the 95 percent confidence level (or in 19 out
18 of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 8 percent below to 8 percent
19 above the 2009 emissions estimate of 4.4 Tg CO2 Eq.
20 Table 5-4: Tier 2 Quantitative Uncertainty Estimates for N2O Emissions from N2O Product Usage (Tg CO2 Eq. and
21 Percent) _
Source Gas 2009 Emission Uncertainty Range Relative to Emission Estimate"
Estimate
(TgC02Eq.) _ (TgC02Eq.)
N2O Product Usage
N2O
4.4
Lower
Bound
4.1
Upper
Bound
4.7
Lower
Bound
-8%
Upper
Bound
+8%
_ _ _ _ _
22 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
23 Note that this uncertainty range (+/-8 percent) has increased by 12 percent compared to the uncertainty range in last
24 year's Inventory (+1-2 percent), due to a correction to the uncertainty input parameters. Furthermore,
25 methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
26 through 2009. Details on the emission trends through time-series are described in more detail in the Methodology
27 section, above.
28 Planned Improvements
29 Planned improvements include a continued evaluation of alternative production statistics for cross verification, a
30 reassessment of N2O product use subcategories to accurately represent trends, investigation of production and use
3 1 cycles, and the potential need to incorporate a time lag between production and ultimate product use and resulting
32 release of N2O. Additionally, planned improvements include considering imports and exports of N2O for product
33 uses.
34
35 5.2. Indirect Greenhouse Gas Emissions from Solvent Use - TO BE UPDATED
36 The use of solvents and other chemical products can result in emissions of various ozone precursors (i.e., indirect
37 greenhouse gases).136 Non-CH4 volatile organic compounds (NMVOCs), commonly referred to as "hydrocarbons,"
136 Solvent usage in the United States also results in the emission of small amounts of hydrofluorocarbons (HFCs) and
hydrofluoroethers (HFEs), which are included under Substitution of Ozone Depleting Substances in the Industrial Processes
chapter.
Solvents and Other Product Use 5-3
-------
1
2
o
J
4
5
6
7
8
9
10
11
12
13
14
15
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. In the United States,
emissions from solvents are primarily the result of solvent evaporation, whereby the lighter hydrocarbon molecules
in the solvents escape into the atmosphere. The evaporation process varies depending on different solvent uses and
solvent types. The major categories of solvent uses include: degreasing, graphic arts, surface coating, other
industrial uses of solvents (i.e., electronics, etc.), dry cleaning, and non-industrial uses (i.e., uses of paint thinner,
etc.).
Total emissions of NOX, NMVOCs, and CO from 1990 to 2008 are reported in Table 5-5.
Table 5-5: Emissions of NOX, CO, and NMVOC from Solvent Use (Gg)
Activity 1990 2000 2005 2006 2007 2008
NOX
Surface Coating
Graphic Arts
Degreasing
Dry Cleaning
Other Industrial Processes3
Non-Industrial Processes'3
Other
CO
Surface Coating
Other Industrial Processes3
Dry Cleaning
Degreasing
Graphic Arts
Non-Industrial Processes'3
Other
NMVOCs
Surface Coating
Non-Industrial Processes'3
Degreasing
Dry Cleaning
Graphic Arts
Other Industrial Processes3
Other
NA
:
NA
5,216
2,289
1,724
675
195
249
85
4,384
1,766
1,676
II
40
3,851
1,578
1,446
280
230
194
88
36
3,846
1,575
1,444
280
230
193
88
36
3,834
1,571
1,439
279
229
193
87
36
3 Includes rubber and plastics manufacturing, and other miscellaneous applications.
b Includes cutback asphalt, pesticide application adhesives, consumer solvents, and other miscellaneous applications.
Note: Totals may not sum due to independent rounding.
+ Does not exceed 0.5 Gg.
16
17 Emissions were calculated by aggregating solvent use data based on information relating to solvent uses from
18 different applications such as degreasing, graphic arts, etc. Emission factors for each consumption category were
19 then applied to the data to estimate emissions. For example, emissions from surface coatings were mostly due to
20 solvent evaporation as the coatings solidify. By applying the appropriate solvent-specific emission factors to the
21 amount of solvents used for surface coatings, an estimate of emissions was obtained. Emissions of CO and NOX
22 result primarily from thermal and catalytic incineration of solvent-laden gas streams from painting booths, printing
23 operations, and oven exhaust.
24 These emission estimates were obtained from preliminary data (EPA 2009), and disaggregated based on EPA
25 (2003), which, in its final iteration, will be published on the National Emission Inventory (NEI) Air Pollutant
26 Emission Trends web site. Emissions were calculated either for individual categories or for many categories
27 combined, using basic activity data (e.g., the amount of solvent purchased) as an indicator of emissions. National
28 activity data were collected for individual applications from various agencies.
5-4 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Activity data were used in conjunction with emission factors, which together relate the quantity of emissions to the
2 activity. Emission factors are generally available from the EPA's Compilation of Air Pollutant Emission Factors,
3 AP-42 (EPA 1997). The EPA currently derives the overall emission control efficiency of a source category from a
4 variety of information sources, including published reports, the 1985 National Acid Precipitation and Assessment
5 Program emissions inventory, and other EPA databases.
6 Uncertainty and Time-Series Consistency
7 Uncertainties in these estimates are partly due to the accuracy of the emission factors used and the reliability of
8 correlations between activity data and actual emissions.
9 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
10 through 2008. Details on the emission trends through time are described in more detail in the Methodology section,
11 above.
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
Solvents and Other Product Use 5-5
-------
i 6. Agriculture
2 Agricultural activities contribute directly to emissions of greenhouse gases through a variety of processes. This
3 chapter provides an assessment of non-carbon-dioxide emissions from the following source categories: enteric
4 fermentation in domestic livestock, livestock manure management, rice cultivation, agricultural soil management,
5 and field burning of agricultural residues (see Figure 6-1). Carbon dioxide (CO2) emissions and removals from
6 agriculture-related land-use activities, such as liming of agricultural soils and conversion of grassland to cultivated
7 land, are presented in the Land Use, Land-Use Change, and Forestry chapter. Carbon dioxide emissions from on-
8 farm energy use are accounted for in the Energy chapter.
9
10 Figure 6-1: 2009 Agriculture Chapter Greenhouse Gas Emission Sources
11
12 In 2009, the Agriculture sector was responsible for emissions of 419.3 teragrams of CO2 equivalents (Tg CO2 Eq.),
13 or 6 percent of total U.S. greenhouse gas emissions. Methane (CH4) and nitrous oxide (N2O) were the primary
14 greenhouse gases emitted by agricultural activities. Methane emissions from enteric fermentation and manure
15 management represent about 25 percent and 9 percent of total CH4 emissions from anthropogenic activities,
16 respectively. Of all domestic animal types, beef and dairy cattle were by far the largest emitters of CH4. Rice
17 cultivation and field burning of agricultural residues were minor sources of CH4. Agricultural soil management
18 activities such as fertilizer application and other cropping practices were the largest source of U.S. N2O emissions,
19 accounting for 68 percent. Manure management and field burning of agricultural residues were also small sources
20 of N2O emissions.
21 Table 6-1 and Table 6-2 present emission estimates for the Agriculture sector. Between 1990 and 2009, CH4
22 emissions from agricultural activities increased by 14.9 percent, while N2O emissions fluctuated from year to year,
23 but overall increased by 4.8 percent.
24 Table 6-1: Emissions from Agriculture (Tg CO2 Eq.)
Gas/Source
CH4
Enteric Fermentation
Manure Management
Rice Cultivation
Field Burning of
Agricultural Residues
N20
Agricultural Soil
Management
Manure Management
Field Burning of
Agricultural Residues
Total
1990
171.2
132.1
31.7
7.1
0.3
212.4
197.8
14.5
0.1
383.6
2000
186.7
136.5
42.4
7.5
0.3
224.0
206.8
17.1
0.1
410.6
2005
190.1
136.5
46.6
6.8
0.2
228.7
211.3
17.3
0.1
418.8
2006
191.7
138.8
46.7
5.9
0.2
227.1
208.9
18.0
0.1
418.8
2007
198.2
141.0
50.7
6.2
0.2
227.6
209.4
18.1
0.1
425.8
2008
197.5
140.6
49.4
7.2
0.3
228.8
210.7
17.9
0.1
426.3
2009
196.8
139.8
49.5
7.3
0.2
222.5
204.6
17.9
0.1
419.3
25 Note: Totals may not sum due to independent rounding.
26
27 Table 6-2: Emissions from
Gas/Source
CH4
Enteric Fermentation
Manure Management
Rice Cultivation
Field Burning of
Agricultural Residues
N2O
Agricultural Soil
Management
Agriculture (Gg)
1990
8,153
6,290
1,511
339
13
685
638
2000
8,890
6,502
2,019
357
12
722
667
2005
9,052
6,500
2,217
326
9
738
682
2006
9,129
6,611
2,226
282
11
732
674
2007
9,437
6,715
2,416
295
11
734
675
2008
9,405
6,696
2,353
343
13
738
680
2009
9,372
6,655
2,356
349
12
718
660
Agriculture 6-1
-------
35
36
Manure Management
Field Burning of
Agricultural Residues
47
55
56
+
58
+
58
+
58
+
58
+
1 +Lessthan0.5Gg.
2 Note: Totals may not sum due to independent rounding.
3 6.1. Enteric Fermentation (IPCC Source Category 4A)
4 Methane is produced as part of normal digestive processes in animals. During digestion, microbes resident in an
5 animal's digestive system ferment food consumed by the animal. This microbial fermentation process, referred to as
6 enteric fermentation, produces CH4 as a byproduct, which can be exhaled or eructated by the animal. The amount of
7 CH4 produced and emitted by an individual animal depends primarily upon the animal's digestive system, and the
8 amount and type of feed it consumes.
9 Ruminant animals (e.g., cattle, buffalo, sheep, goats, and camels) are the major emitters of CH4 because of their
10 unique digestive system. Ruminants possess a rumen, or large "fore-stomach," in which microbial fermentation
11 breaks down the feed they consume into products that can be absorbed and metabolized. The microbial
12 fermentation that occurs in the rumen enables them to digest coarse plant material that non-ruminant animals cannot.
13 Ruminant animals, consequently, have the highest CH4 emissions among all animal types.
14 Non-ruminant animals (e.g., swine, horses, and mules) also produce CH4 emissions through enteric fermentation,
15 although this microbial fermentation occurs in the large intestine. These non-ruminants emit significantly less CH4
16 on a per-animal basis than ruminants because the capacity of the large intestine to produce CH4 is lower.
17 In addition to the type of digestive system, an animal's feed quality and feed intake also affect CH4 emissions. In
18 general, lower feed quality and/or higher feed intake leads to higher CH4 emissions. Feed intake is positively
19 correlated to animal size, growth rate, and production (e.g., milk production, wool growth, pregnancy, or work).
20 Therefore, feed intake varies among animal types as well as among different management practices for individual
21 animal types (e.g., animals in feedlots or grazing on pasture).
22 Methane emission estimates from enteric fermentation are provided in Table 6-3 and Table 6-4. Total livestock CH4
23 emissions in 2009 were 139.8 Tg CO2 Eq. (6,655 Gg). Beef cattle remain the largest contributor of CH4 emissions
24 from enteric fermentation, accounting for 71 percent in 2009. Emissions from dairy cattle in 2009 accounted for 24
25 percent, and the remaining emissions were from horses, sheep, swine, and goats.
26 From 1990 to 2009, emissions from enteric fermentation have increased by 5.8 percent. Generally, emissions
27 decreased from 1996 to 2003, though with a slight increase in 2002. This trend was mainly due to decreasing
28 populations of both beef and dairy cattle and increased digestibility of feed for feedlot cattle. Emissions increased
29 from 2004 through 2007, as both dairy and beef populations have undergone increases and the literature for dairy
30 cow diets indicated a trend toward a decrease in feed digestibility for those years. Emissions decreased again in
31 2008 and 2009 as beef cattle populations decreased again. During the timeframe of this analysis, populations of
32 sheep have decreased 49 percent since 1990 while horse populations have increased over 87 percent, mostly since
33 1999. Goat and swine populations have increased 25 percent and 23 percent, respectively, during this timeframe.
34 Table 6-3: CH4 Emissions from Enteric Fermentation (Tg CO2 Eq.)
Livestock Type 1990 2000
Beef Cattle 94.5 100.6
Dairy Cattle 31.8 30.7
Horses 1.9 2.0
Sheep 1.9 1.2
Swine 1.7 1.9
Goats 0.3 0.3
Total 132.1 136.5
Note: Totals may not sum due to independent rounding.
Table 6-4: CH4 Emissions from Enteric Fermentation
Livestock Type 1990 2000
Beef Cattle 4,502 4,790
Dairy Cattle 1,513 1,460
2005
99.3
30.4
3.5
1.0
1.9
0.3
136.5
(Gg)
2005
4,731
1,449
2006
100.9
31.1
3.6
1.0
1.9
0.3
138.8
2006
4,803
1,479
2007
101.6
32.4
3.6
1.0
2.1
0.3
141.0
2007
4,837
1,544
2008
100.7
32.9
3.6
1.0
2.1
0.3
140.6
2008
4,796
1,564
2009
99.6
33.2
3.6
1.0
2.1
0.3
139.8
2009
4,742
1,581
6-2 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Horses
Sheep
Swine
Goats
Total
91
91
81
13
6,290
94
56
88
12
6,502
166
49
92
14
6,500
171
50
93
15
6,611
171
49
98
16
6,715
171
48
101
16
6,696
171
46
99
16
6,655
1 Note: Totals may not sum due to independent rounding.
2 Methodology
3 Livestock emission estimate methodologies fall into two categories: cattle and other domesticated animals. Cattle,
4 due to their large population, large size, and particular digestive characteristics, account for the majority of CH4
5 emissions from livestock in the United States. A more detailed methodology (i.e., IPCC Tier 2) was therefore
6 applied to estimate emissions for all cattle except for bulls. Emission estimates for other domesticated animals
7 (horses, sheep, swine, goats, and bulls) were handled using a less detailed approach (i.e., IPCC Tier 1).
8 While the large diversity of animal management practices cannot be precisely characterized and evaluated,
9 significant scientific literature exists that provides the necessary data to estimate cattle emissions using the IPCC
10 Tier 2 approach. The Cattle Enteric Fermentation Model (CEFM), developed by EPA and used to estimate cattle
11 CH4 emissions from enteric fermentation, incorporates this information and other analyses of livestock population,
12 feeding practices, and production characteristics.
13 National cattle population statistics were disaggregated into the following cattle sub-populations:
14 • Dairy Cattle
15 o Calves
16 o Heifer Replacements
17 o Cows
18 • Beef Cattle
19 o Calves
20 o Heifer Replacements
21 o Heifer and Steer Stackers
22 o Animals in Feedlots (Heifers and Steers)
23 o Cows
24 o Bulls
25 Calf birth rates, end-of-year population statistics, detailed feedlot placement information, and slaughter weight data
26 were used to create a transition matrix that models cohorts of individual animal types and their specific emission
27 profiles. The key variables tracked for each of the cattle population categories are described in Annex 3.9. These
28 variables include performance factors such as pregnancy and lactation as well as average weights and weight gain.
29 Annual cattle population data were obtained from the U.S. Department of Agriculture's (USDA) National
30 Agricultural Statistics Service (NASS) QuickStats database (USDA 2010).
31 Diet characteristics were estimated by region for U.S. dairy, beef, and feedlot cattle. These estimates were used to
32 calculate Digestible Energy (DE) values (expressed as the percent of gross energy intake digested by the animal) and
33 CH4 conversion rates (Ym) (expressed as the fraction of gross energy converted to CH4) for each population
34 category. The IPCC recommends Ym values of 3.0±1.0 percent for feedlot cattle and 6.5±1.0 percent for other well-
35 fed cattle consuming temperate-climate feed types (IPCC 2006). Given the availability of detailed diet information
36 for different regions and animal types in the United States, DE and Ym values unique to the United States were
37 developed, rather than using the recommended IPCC values. The diet characterizations and estimation of DE and
38 Ym values were based on information from state agricultural extension specialists, a review of published forage
39 quality studies and scientific literature, expert opinion, and modeling of animal physiology. The diet characteristics
40 for dairy cattle were based on Donovan (1999) and an extensive review of nearly 20 years of literature. Dairy
41 replacement heifer diet assumptions were based on the observed relationship in the literature between dairy cow and
Agriculture 6-3
-------
1 dairy heifer diet characteristics. The diet assumptions for beef cattle were derived from NRC (2000). For feedlot
2 animals, the DE and Ym values used for 1990 were recommended by Johnson (1999). Values for DE and Ym for
3 1991 through 1999 were linearly extrapolated based on the 1990 and 2000 data. DE and Ym values for 2000 onwards
4 were based on survey data in Galyean and Gleghorn (2001) and Vasconcelos and Galyean (2007). For grazing beef
5 cattle, DE values were based on diet information in NRC (2000) and Ym values were based on Johnson (2002).
6 Weight and weight gains for cattle were estimated from Holstein Association USA (2010), Enns (2008), Lippke et
7 al. (2000), Pinchack et al., (2004), Platter et al. (2003), Skogerboe et al. (2000), and expert opinion. See Annex 3.9
8 for more details on the method used to characterize cattle diets and weights in the United States.
9 To estimate CH4 emissions from all cattle types except bulls and calves younger than 7 months,137 the population
10 was divided into state, age, sub-type (i.e., dairy cows and replacements, beef cows and replacements, heifer and
11 steer stackers, and heifers and steers in feedlots), and production (i.e., pregnant, lactating) groupings to more fully
12 capture differences in CH4 emissions from these animal types. The transition matrix was used to simulate the age
13 and weight structure of each sub-type on a monthly basis, to more accurately reflect the fluctuations that occur
14 throughout the year. Cattle diet characteristics were then used in conjunction with Tier 2 equations from IPCC
15 (2006) to produce CH4 emission factors for the following cattle types: dairy cows, beef cows, dairy replacements,
16 beef replacements, steer stackers, heifer stackers, steer feedlot animals, and heifer feedlot animals. To estimate
17 emissions from cattle, population data from the transition matrix were multiplied by the calculated emission factor
18 for each cattle type. More details are provided in Annex 3.9.
19 Emission estimates for other animal types were based on average emission factors representative of entire
20 populations of each animal type. Methane emissions from these animals accounted for a minor portion of total CH4
21 emissions from livestock in the United States from 1990 through 2009. Also, the variability in emission factors for
22 each of these other animal types (e.g., variability by age, production system, and feeding practice within each animal
23 type) is less than that for cattle. Annual livestock population data for these other livestock types, except horses and
24 goats, as well as feedlot placement information were obtained for all years from USDA NASS (USDA 2010). Horse
25 population data were obtained from the Food and Agriculture Organization of the United Nations (F AO) FAOSTAT
26 database (FAO 2010), because USDA does not estimate U.S. horse populations annually. Goat population data
27 were obtained for 1992, 1997, 2002, and 2007 (USDA 2010); these data were interpolated and extrapolated to derive
28 estimates for the other years. Methane emissions from sheep, goats, swine, and horses were estimated by using
29 emission factors utilized in Crutzen et al. (1986, cited in IPCC 2006). These emission factors are representative of
30 typical animal sizes, feed intakes, and feed characteristics in developed countries. The methodology is the same as
31 that recommended by IPCC (2006).
32 See Annex 3.9 for more detailed information on the methodology and data used to calculate CH4 emissions from
33 enteric fermentation.
34 Uncertainty and Time-Series Consistency
35 A quantitative uncertainty analysis for this source category was performed through the IPCC-recommended Tier 2
36 uncertainty estimation methodology, Monte Carlo Stochastic Simulation technique as described in ICF (2003).
37 These uncertainty estimates were developed for the 1990 through 2001 Inventory report. No significant changes
38 occurred in the method of data collection, data estimation methodology, or other factors that influence the
39 uncertainty ranges around the 2009 activity data and emission factor input variables used in the current submission.
40 Consequently, these uncertainty estimates were directly applied to the 2009 emission estimates.
41 A total of 185 primary input variables (177 for cattle and 8 for non-cattle) were identified as key input variables for
42 the uncertainty analysis. A normal distribution was assumed for almost all activity- and emission factor-related
43 input variables. Triangular distributions were assigned to three input variables (specifically, cow-birth ratios for the
44 three most recent years included in the 2001 model run) to capture the fact that these variables cannot be negative.
45 For some key input variables, the uncertainty ranges around their estimates (used for inventory estimation) were
46 collected from published documents and other public sources; others were based on expert opinion and best
47 estimates. In addition, both endogenous and exogenous correlations between selected primary input variables were
137 Emissions from bulls are estimated using a Tier 1 approach because it is assumed there is minimal variation in population and
diets. Because calves younger than 7 months consume mainly milk and the IPCC recommends the use of methane conversion
factor of zero for all juveniles consuming only milk, this results in no methane emissions from this subcategory of cattle.
6-4 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 modeled. The exogenous correlation coefficients between the probability distributions of selected activity-related
2 variables were developed through expert judgment.
3 The uncertainty ranges associated with the activity data-related input variables were plus or minus 10 percent or
4 lower. However, for many emission factor-related input variables, the lower- and/or the upper-bound uncertainty
5 estimates were over 20 percent. The results of the quantitative uncertainty analysis are summarized in Table 6-5.
6 Enteric fermentation CH4 emissions in 2009 were estimated to be between 124.4 and 165.0 Tg CO2 Eq. at a 95
7 percent confidence level, which indicates a range of 11 percent below to 18 percent above the 2009 emission
8 estimate of 139.8 Tg CO2 Eq. Among the individual cattle sub-source categories, beef cattle account for the largest
9 amount of CH4 emissions as well as the largest degree of uncertainty in the inventory emission estimates. Among
10 non-cattle, horses account for the largest degree of uncertainty in the inventory emission estimates because there is a
11 higher degree of uncertainty among the FAO population estimates used for horses than for the USD A population
12 estimates used for swine, goats, and sheep.
13 Table 6-5: Quantitative Uncertainty Estimates for CH4 Emissions from Enteric Fermentation (Tg CO2 Eq. and
14 Percent)
Source Gas 2009 Emission Uncertainty Range Relative to Emission Estimate3'b
Estimate
(Tg C02 Eq.) (TgC02Eq.)
Enteric Fermentation
CH4
139.8
Lower
Bound
124.4
Upper
Bound
165.0
Lower
Bound
-11%
Upper
Bound
+18%
15 a Range of emissions estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
16 b Note that the relative uncertainty range was estimated with respect to the 2001 emission estimates submitted in 2003 and
17 applied to the 2009 estimates.
18 Methodological recalculations were applied to the entire time series to ensure time-series consistency from 1990
19 through 2009. Details on the emission trends through time are described in more detail in the Methodology section.
20 QA/QC and Verification
21 In order to ensure the quality of the emission estimates from enteric fermentation, the IPCC Tier 1 and Tier 2
22 Quality Assurance/Quality Control (QA/QC) procedures were implemented consistent with the U.S. QA/QC plan.
23 Tier 2 QA procedures included independent peer review of emission estimates. Because there were no major
24 modifications to the CEFM for 2009, QA/QC emphasis for the current Inventory was placed on cleaning up
25 documentation and references within the model, and review of external data sources. For example, during the
26 course of the QA/QC activities for this source category, it was noted that the U.S. total for 2009 Cattle On Feed data
27 provided via USDA's Quickstats database did not match the total calculated from summing all individual states.
28 The appropriate party was contacted at USD A, and it was determined that data for New Mexico and North Carolina
29 were included individually, as well as within the "Other States" aggregate number, so they were being double
30 counted in the U.S. total. This issue was quickly resolved.
31 In addition, over the past few years, particular importance has been placed on harmonizing the data exchange
32 between the enteric fermentation and manure management source categories. The current inventory submission now
33 utilizes the transition matrix from the CEFM for estimating cattle populations and weights for both source
34 categories, and the CEFM is used to output volatile solids and nitrogen (N) excretion estimates using the diet
35 assumptions in the model in conjunction with the energy balance equations from the IPCC (2006). This approach
36 should complete the resolution of the discrepancies noted in previous reviews of these sectors, and facilitate the
37 QA/QC process for both of these source categories.
38 Recalculations Discussion
39 There were several modifications to the estimates relative to the previous Inventory that had an effect on emission
40 estimates, including the following:
41 • The average weight assumed for mature dairy cows has changed from the 1,550 pounds used in previous
42 inventories to 1,500 pounds (Johnson 2010; Holstein Association 2010).
43 • The USDA published revised estimates in several categories that affected historical emissions estimated for
Agriculture 6-5
-------
1 cattle and swine for 2008. Calves, beef replacements, and feedlot cattle all saw slight modifications to their
2 2008 populations, while swine population categories were modified so that the categories "<60 pounds" and
3 "60-119 pounds" were replaced with "<50 pounds" and "50-119" pounds. Additionally, 2008 lactation
4 estimates for Arkansas, Connecticut, Indiana, Nebraska, New Jersey, Oklahoma, South Carolina, and Vermont
5 were updated by USD A.
6 • For the 1990-2009 inventory, EPA obtained goat population data from the 2007 Census of Agriculture. For
7 2007 population values, EPA used the Census's 2007 "Total Goat" population for each state. Using the 2002
8 and 2007 data points, EPA interpolated the population for the intervening years, and the population for 2008
9 and 2009 were set equal to the population for 2007. The updated Census data resulted in a change in population
10 values from 2003 through 2008 as populations for these years were previously set equal to the 2002 population.
11 As a result of these changes, dairy cattle emissions decreased an average of 11.5 Gg (0.8 percent) per year and beef
12 cattle emissions decreased an average of 0.13 Gg (less than 0.01 percent) per year over the entire time series relative
13 to the previous Inventory. Historical emission estimates for 2008 increased by 1.3 percent for goats as a result of the
14 USDA population revisions described above.
15 Planned Improvements
16 Continued research and regular updates are necessary to maintain a current model of cattle diet characterization,
17 feedlot placement data, rates of weight gain and calving, among other data inputs. Ongoing revisions could include
18 some of the following options:
19 • Reviewing and updating the diet assumptions for foraging beef cattle;
20 • Estimating bull emissions using the IPCC Tier 2 approach;
21 • Updating input variables that are from older data sources, such as beef births by month and beef cow lactation
22 rates;
23 • The possible breakout of other animal types (i.e., sheep, swine, goats, horses) from national estimates to state-
24 level estimates; and
25 • Including bison in the estimates for other domesticated animals.
26 In addition, recent changes that have been implemented to the CEFM warrant an assessment of the current
27 uncertainty analysis, therefore a revision of the quantitative uncertainty surrounding emission estimates from this
28 source category will be initiated.
29 6.2. Manure Management (IPCC Source Category 4B)
30 The management of livestock manure can produce anthropogenic CH4 and N2O emissions. Methane is produced by
31 the anaerobic decomposition of manure. Direct N2O emissions are produced as part of the N cycle through the
32 nitrification and denitrification of the organic N in livestock dung and urine.138 Indirect N2O emissions are produced
33 as result of the volatilization of N as NH3 and NOX and runoff and leaching of N during treatment, storage and
34 transportation.
35 When livestock or poultry manure are stored or treated in systems that promote anaerobic conditions (e.g., as a
36 liquid/slurry in lagoons, ponds, tanks, or pits), the decomposition of materials in the manure tends to produce CH4.
37 When manure is handled as a solid (e.g., in stacks or drylots) or deposited on pasture, range, or paddock lands, it
38 tends to decompose aerobically and produce little or no CH4. Ambient temperature, moisture, and manure storage
39 or residency time affect the amount of CH4 produced because they influence the growth of the bacteria responsible
40 for CH4 formation. For non-liquid-based manure systems, moist conditions (which are a function of rainfall and
41 humidity) can promote CH4 production. Manure composition, which varies by animal diet, growth rate, and type,
138 Direct and indirect N2O emissions from dung and urine spread onto fields either directly as daily spread or after it is removed
from manure management systems (e.g., lagoon, pit, etc.) and from livestock dung and urine deposited on pasture, range, or
paddock lands are accounted for and discussed in the Agricultural Soil Management source category within the Agriculture
sector.
6-6 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 including the animal's digestive system, also affects the amount of CH4 produced. In general, the greater the energy
2 content of the feed, the greater the potential for CH4 emissions. However, some higher-energy feeds also are more
3 digestible than lower quality forages, which can result in less overall waste excreted from the animal.
4 The production of direct N2O emissions from livestock manure depends on the composition of the manure and urine,
5 the type of bacteria involved in the process, and the amount of oxygen and liquid in the manure system. For direct
6 N2O emissions to occur, the manure must first be handled aerobically where ammonia (NH3) or organic N is
7 converted to nitrates and nitrites (nitrification), and then handled anaerobically where the nitrates and nitrites are
8 reduced to dinitrogen gas (N2), with intermediate production of N2O and nitric oxide (NO) (denitrification)
9 (Groffman et al. 2000). These emissions are most likely to occur in dry manure handling systems that have aerobic
10 conditions, but that also contain pockets of anaerobic conditions due to saturation. A very small portion of the total
11 N excreted is expected to convert to N2O in the waste management system (WMS). Indirect N2O emissions are
12 produced when nitrogen is lost from the system through volatilization (as NH3 or NOX) or through runoff and
13 leaching. The vast majority of volatilization losses from these operations are NH3. Although there are also some
14 small losses of NOX, there are no quantified estimates available for use, so losses due to volatilization are only based
15 on NH3 loss factors. Runoff losses would be expected from operations that house animals or store manure in a
16 manner that is exposed to weather. Runoff losses are also specific to the type of animal housed on the operation due
17 to differences in manure characteristics. Little information is known about leaching from manure management
18 systems as most research focuses on leaching from land application systems. Since leaching losses are expected to
19 be minimal, leaching losses are coupled with runoff losses and the runoff/leaching estimate does not include any
20 leaching losses.
21 Estimates of CH4 emissions in 2009 were 49.5 Tg CO2 Eq. (2,356 Gg), 56 percent higher than in 1990. Emissions
22 increased on average by 0.9 Tg CO2 Eq. (2.5 percent) annually over this period. The majority of this increase was
23 from swine and dairy cow manure, where emissions increased 45 and 95 percent, respectively. Although the
24 majority of manure in the United States is handled as a solid, producing little CH4, the general trend in manure
25 management, particularly for dairy and swine (which are both shifting towards larger facilities), is one of increasing
26 use of liquid systems. Also, new regulations limiting the application of manure nutrients have shifted manure
27 management practices at smaller dairies from daily spread to manure managed and stored on site. Although national
28 dairy animal populations have been generally decreasing, some states have seen increases in their dairy populations
29 as the industry becomes more concentrated in certain areas of the country. These areas of concentration, such as
30 California, New Mexico, and Idaho, tend to utilize more liquid-based systems to manage (flush or scrape) and store
31 manure. Thus the shift toward larger facilities is translated into an increasing use of liquid manure management
32 systems, which have higher potential CH4 emissions than dry systems. This shift was accounted for by
33 incorporating state and WMS-specific CH4 conversion factor (MCF) values in combination with the 1992, 1997, and
34 2002 farm-size distribution data reported in the Census of Agriculture (USDA 2009a). Methane emissions from
35 sheep have decreased significantly since 1990 (a 54 percent decrease from 1990 to 2009); however, this is mainly
36 due to population changes. Overall, sheep contribute less than one percent of CH4 emissions from animal manure
37 management. From 2008 to 2009, there was a less than 1 percent increase in total CH4 emissions, due to minor
38 shifts in the animal populations and the resultant effects on manure management system allocations.
39 In 2009, total N2O emissions were estimated to be 17.9 Tg CO2 Eq. (58 Gg); in 1990, emissions were 14.5 Tg CO2
40 Eq. (47 Gg). These values include both direct and indirect N2O emissions from manure management. Nitrous oxide
41 emissions have remained fairly steady since 1990. Small changes in N2O emissions from individual animal groups
42 exhibit the same trends as the animal group populations, with the overall net effect that N2O emissions showed a 23
43 percent increase from 1990 to 2009 and a less than 1 percent decrease from 2008 through 2009.
44 Table 6-6 and Table 6-7 provide estimates of CH4 and N2O emissions from manure management by animal
45 category.
46 Table 6-6: CH4 and N2O Emissions from Manure Management (Tg CO2Eq.)
Gas/Animal Type
CH4a
Dairy Cattle
Beef Cattle
Swine
Sheep
1990
31.7
12.6
2.7
13.1
0.1
2000
42.4
18.9
2.8
17.5
0.1
2005
46.6
21.4
2.8
19.0
0.1
2006
46.7
21.7
2.9
18.7
0.1
2007
50.7
24.2
2.9
20.3
0.1
2008
49.4
24.1
2.8
19.3
0.1
2009
49.5
24.5
2.7
19.0
0.1
Goats + + + + +
Agriculture 6-7
-------
Poultry
Horses
N2Ob
Dairy Cattle
Beef Cattle
Swine
Sheep
Goats
Poultry
Horses
Total
2.8
0.5
14.5
5.3
6.1
1.2
0.1
+
1.5
0.2
46.2
2.7
0.4
17.1
5.6
7.8
1.6
0.3
+
1.6
0.2
59.5
2.7
0.6
17.3
5.6
7.5
1.8
0.4
+
1.7
0.3
63.8
2.7
0.6
18.0
5.8
8.0
1.8
0.4
+
1.7
0.3
64.8
2.8
0.6
18.1
5.8
7.9
1.9
0.4
+
1.7
0.3
68.9
2.7
0.5
17.9
5.7
7.8
2.0
0.4
+
1.7
0.3
67.3
2.7
0.5
17.9
5.8
7.8
2.0
0.3
+
1.6
0.3
67.3
1 + Less than 0.05 Tg CO2 Eq.
2 aAccounts for CH4 reductions due to capture and destruction of CH4 at facilities using anaerobic digesters.
3 Includes both direct and indirect N2O emissions.
4 Note: Totals may not sum due to independent rounding.
5
Table 6-7: CH4 and N2O Emissions from Manure Management (Gg)
7
8
9
10
Gas/Animal Type 1990 2000
CH4a 1,511 2,019
Dairy Cattle 599 900
Beef Cattle 128 133
Swine 624 834
Sheep 7 4
Goats 1 1
Poultry 131 127
Horses 22 20
N2Ob 47 55
Dairy Cattle 17 18
Beef Cattle 20 25
Swine 4 5
Sheep + 1
Goats + +
Poultry 5 5
Horses 1 1
+ Less than 0.5 Gg.
aAccounts for CH4 reductions due to capture and destruction
blncludes both direct and indirect N2O emissions.
Note: Totals may not sum due to independent rounding.
2005
2,217
1,018
132
905
o
3
i
129
28
56
18
24
6
1
+
5
1
2006
2,226
1,034
139
889
o
3
i
131
28
58
19
26
6
1
+
5
1
2007
2,416
1,151
136
965
3
1
134
27
58
19
26
6
1
+
5
1
2008
2,353
1,147
131
918
o
5
i
129
24
58
18
25
6
1
+
5
1
2009
2,356
1,168
130
903
3
1
127
24
58
19
25
6
1
+
5
1
of CH4 at facilities using anaerobic digesters.
11 Methodology
12 The methodologies presented in IPCC (2006) form the basis of the CH4 and N2O emission estimates for each animal
13 type. This section presents a summary of the methodologies used to estimate CH4 and N2O emissions from manure
14 management for this Inventory. See Annex 3.10 for more detailed information on the methodology and data used to
15 calculate CH4 and N2O emissions from manure management.
16 Methane Calculation Methods
17 The following inputs were used in the calculation of CH4 emissions:
18 • Animal population data (by animal type and state);
19 • Typical animal mass (TAM) data (by animal type);
20 • Portion of manure managed in each waste management system (WMS), by state and animal type;
21 • Volatile solids (VS) production rate (by animal type and state or United States);
22 • Methane producing potential (B0) of the volatile solids (by animal type); and
23 • Methane conversion factors (MCF), the extent to which the CH4 producing potential is realized for each
24 type of WMS (by state and manure management system, including the impacts of any biogas collection
25 efforts).
6-8 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Methane emissions were estimated by first determining activity data, including animal population, TAM, WMS
2 usage, and waste characteristics. The activity data sources are described below:
3 • Annual animal population data for 1990 through 2009 for all livestock types, except horses and goats were
4 obtained from USDA NASS. For cattle, the USD A populations were utilized in conjunction with birth
5 rates, detailed feedlot placement information, and slaughter weight data to create the transition matrix in the
6 CEFM that models cohorts of individual animal types and their specific emission profiles. The key
7 variables tracked for each of the cattle population categories are described in Section 6.1 and in more detail
8 in Annex 3.9. Horse population data were obtained from the FAOSTAT database (FAO 2010). Goat
9 population data for 1992, 1997, 2002, and 2007 were obtained from the Census of Agriculture (USDA
10 2009a).
11 • The TAM is an annual average weight which was obtained for animal types other than cattle from
12 information in USD A' ?, Agricultural Waste Management Field Handbook (USD A 1996a), the American
13 Society of Agricultural Engineers, Standard D384.1 (ASAE 1999) and others (EPA 1992, Safley 2000,
14 ERG 2010a). For a description of the TAM used for cattle, please see section 6.1, Enteric Fermentation.
15 • WMS usage was estimated for swine and dairy cattle for different farm size categories using data from
16 USDA (USDA 1996b, 1998b, 2000a) and EPA (ERG 2000a, EPA 2002a, 2002b). For beef cattle and
17 poultry, manure management system usage data were not tied to farm size but were based on other data
18 sources (ERG 2000a, USDA 2000b, UEP 1999). For other animal types, manure management system
19 usage was based on previous estimates (EPA 1992).
20 • VS production rates for all cattle except for bulls and calves were calculated by head for each state and
21 animal type in the CEFM. VS production rates by animal mass for all other animals were determined using
22 data from USD A's Agricultural Waste Management Field Handbook (USDA 1996a, 2008) and data from
23 the American Society of Agricultural Engineers, Standard D384.1 (ASAE 1998).
24 • The maximum CH4 producing capacity of the VS (B0) was determined for each animal type based on
25 literature values (Morris 1976, Bryant et al, 1976, Hashimoto 1981, Hashimoto 1984, EPA 1992, Hill 1982,
26 and Hill 1984).
27 • MCFs for dry systems were set equal to default IPCC factors based on state climate for each year (IPCC
28 2006). MCFs for liquid/slurry, anaerobic lagoon, and deep pit systems were calculated based on the
29 forecast performance of biological systems relative to temperature changes as predicted in the van't Hoff-
30 Arrhenius equation which is consistent with IPCC (2006) Tier 2 methodology.
31 • Anaerobic digestion system data were obtained from the EPA AgSTAR Program, including information
32 presented in the AgSTAR Digest (EPA 2000, 2003b, 2006). Anearobic digester emissions were calculated
33 based on estimated methane production and collection and destruction efficiency assumptions (ERG 2008).
34 To estimate CH4 emissions for cattle, the estimated amount of VS (kg per animal-year) managed in each WMS for
35 each animal type, state and year were taken from the CEFM. For animals other than cattle, the annual amount of VS
36 (kg per year) from manure excreted in each WMS was calculated for each animal type, state, and year. This
37 calculation multiplied the animal population (head) by the VS excretion rate (kg VS per 1,000 kg animal mass per
38 day), the TAM (kg animal mass per head) divided by 1,000, the WMS distribution (percent), and the number of days
39 per year (365.25).
40 The estimated amount of VS managed in each WMS was used to estimate the CH4 emissions (kg CH4 per year)
41 from each WMS. The amount of VS (kg per year) were multiplied by the maximum CH4 producing capacity of the
42 VS (B0) (m3 CH4 per kg VS), the MCF for that WMS (percent), and the density of CH4 (kg CH4 per m3 CH4). The
43 CH4 emissions for each WMS, state, and animal type were summed to determine the total U.S. CH4 emissions.
44 Nitrous Oxide Calculation Methods
45 The following inputs were used in the calculation of direct and indirect N2O emissions:
46 • Animal population data (by animal type and state);
47 • TAM data (by animal type);
48 • Portion of manure managed in each WMS (by state and animal type);
49 • Total Kjeldahl N excretion rate (Nex);
50 • Direct N2O emission factor (EFWMS);
Agriculture 6-9
-------
1 • Indirect N2O emission factor for volitalization(EFvoiltailzatlon);
2 • Indirect N2O emission factor for runoff and leaching (EFrunoff/ie^h);
3 • Fraction of nitrogen loss from volitalization of NH3 and NOX (Fracgas); and
4 • Fraction of nitrogen loss from runoff and leaching (FraCmnoff/ieach)-
5
6 N2O emissions were estimated by first determining activity data, including animal population, TAM, WMS usage,
7 and waste characteristics. The activity data sources (except for population, TAM, and WMS, which were described
8 above) are described below:
9 • Nex rates for all cattle except for bulls and calves were calculated by head for each state and animal type in
10 the CEFM. Nex rates by animal mass for all other animals were determined using data from USDA's
11 Agricultural Waste Management Field Handbook (USD A 1996a, 2008) and data from the American
12 Society of Agricultural Engineers, Standard D384.1 (ASAE 1998).
13 • All N2O emission factors (direct and indirect) were taken from IPCC (2006).
14 • Country-specific estimates for the fraction of N loss from volatilization (Fracgas) and runoff and leaching
15 (FraCrunoff/ieach) were developed. Fracgas values were based on WMS-specific volatilization values as
16 estimated from EPA's National Emission Inventory -Ammonia Emissions from Animal Agriculture
17 Operations (EPA 2005). FraCrunoff/kaching values were based on regional cattle runoff data from EPA's
18 Office of Water (EPA 2002b; see Annex 3.1).
19 To estimate N2O emissions for cattle, EPA used the estimated amount of N excreted (kg per animal-year) managed
20 in each WMS for each animal type, state and year were taken from the CEFM. For animals other than cattle, the
21 amount of N excreted (kg per year) in manure in each WMS for each animal type, state, and year was calculated.
22 The population (head) for each state and animal was multiplied by TAM (kg animal mass per head) divided by
23 1,000, the nitrogen excretion rate (Nex, in kg N per 1000 kg animal mass per day), WMS distribution (percent), and
24 the number of days per year.
25 Direct N2O emissions were calculated by multiplying the amount of N excreted (kg per year) in each WMS by the
26 N2O direct emission factor for that WMS (EFwMS, in kg N2O-N per kg N) and the conversion factor of N2O-N to
27 N2O. These emissions were summed over state, animal and WMS to determine the total direct N2O emissions (kg of
28 N2O per year).
29 Next, indirect N2O emissions from volatilization (kg N2O per year) were calculated by multiplying the amount of N
30 excreted (kg per year) in each WMS by the fraction of nitrogen lost through volatilization (Fractas) divided by 100,
31 and the emission factor for volatilization (EFvoiatlilzatlon, in kg N2O per kg N), and the conversion factor of N2O-N to
32 N2O. Indirect N2O emissions from runoff and leaching (kg N2O per year) were then calculated by multiplying the
3 3 amount of N excreted (kg per year) in each WMS by the fraction of N lost through runoff and leaching
34 (FraCrunoff/ieach) divided by 100, and the emission factor for runoff and leaching (EFrunoff/ie^h, in kg N2O per kg N), and
35 the conversion factor of N2O-N to N2O. The indirect N2O emissions from volatilization and runoff and leaching
36 were summed to determine the total indirect N2O emissions.
37 The direct and indirect N2O emissions were summed to determine total N2O emissions (kg N2O per year).
38 Uncertainty and Time-Series Consistency
39 An analysis was conducted for the manure management emission estimates presented in EPA's Inventory of U.S.
40 Greenhouse Gas Emissions and Sinks: 1990-2001 (EPA 2003a, ERG 2003) to determine the uncertainty associated
41 with estimating CH4 and N2O emissions from livestock manure management. The quantitative uncertainty analysis
42 for this source category was performed in 2002 through the IPCC-recommended Tier 2 uncertainty estimation
43 methodology, the Monte Carlo Stochastic Simulation technique. The uncertainty analysis was developed based on
44 the methods used to estimate CH4 and N2O emissions from manure management systems. A normal probability
45 distribution was assumed for each source data category. The series of equations used were condensed into a single
46 equation for each animal type and state. The equations for each animal group contained four to five variables
47 around which the uncertainty analysis was performed for each state.
48 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 6-8. Manure management CH4
49 emissions in 2009 were estimated to be between 40.6 and 59.4 Tg CO2 Eq. at a 95 percent confidence level, which
6-10 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 indicates a range of 18 percent below to 20 percent above the actual 2009 emission estimate of 49.5 Tg CO2 Eq. At
2 the 95 percent confidence level, N2O emissions were estimated to be between 15.0 and 22.1 Tg CO2 Eq. (or
3 approximately 16 percent below and 24 percent above the actual 2009 emission estimate of 17.9 Tg CO2 Eq.).
4 Table 6-8: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O (Direct and Indirect) Emissions from Manure
5 Management (Tg CO2 Eq. and Percent)
Source
Manure Management
Manure Management
2009 Emission
Gas Estimate
(TgC02Eq.)
CH4 49.5
N2O 17.9
Uncertainty Range Relative to Emission
Estimate"
(TgC02Eq.) (%)
Lower
Bound
40.6
15.0
Upper
Bound
59.4
22.1
Lower
Bound
-18%
-16%
Upper
Bound
+20%
+24%
6 aRange of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
7
8 QA/QC and Verification
9 Tier 1 and Tier 2 QA/QC activities were conducted consistent with the U.S. QA/QC plan. Tier 2 activities focused
10 on comparing estimates for the previous and current inventories for N2O emissions from managed systems and CH4
11 emissions from livestock manure. All errors identified were corrected. Order of magnitude checks were also
12 conducted, and corrections made where needed. Manure N data were checked by comparing state-level data with
13 bottom up estimates derived at the county level and summed to the state level. Similarly, a comparison was made
14 by animal and WMS type for the full time series, between national level estimates for nitrogen excreted and the sum
15 of county estimates for the full time series.
16 Recalculations Discussion
17 The CEFM produces VS and Nex data for cattle that are used in the manure management inventory. The CEFM
18 team implemented changes to the estimated diet characteristics for feedlot and dairy cattle, as well as other minor
19 data updates, which created changes in VS and Nex data and changes in the amount of CH4 and N2O estimated for
20 manure management (See section 6.1 Enteric Fermentation). In addition to standardize the estimates of TAM
21 between the CEFM and the manure management source category, the total VS and Nex estimates in units of kg per
22 head per year from the CEFM were used in the manure management calculations in the current Inventory. With
23 these changes, CH4 and N2O emission estimates from manure management systems are higher than reported in the
24 previous Inventory for both beef and dairy cattle. Methane emissions from beef and dairy cattle were higher by 7
25 and 24 percent, respectively, while N2O emissions were higher by 1 and 5 percent for beef and dairy cattle,
26 respectively, averaged over the 1990 to 2008 time series.
27 In addition to changes in cattle Nex and VS data, EPA updated the VS and Nex for other animal types using data
28 from USD A's updated Agricultural Waste Management Field Handbook (USD A 2008). EPA used data from both
29 the previous Handbook and the updated the Handbook to create a time series of VS and Nex data across all
30 inventory years for all animals (ERG 2010b). The VS and Nex updates for all animals contributed to an average
31 emission increase of 9.5 percent for CH4 and 2.7 percent for N2O across the time series.
32 For the current Inventory, USDA population data were used that included updated market swine categories. USDA
33 changed the "market swine under 60 Ibs." category to "market swine under 50 Ibs." for years 2008 and 2009. In
34 addition, USDA changed the "market swine from 60-119 Ibs." to "market swine from 50-119 Ibs." for the same
35 years. This update resulted in a change in TAM estimates for those two swine categories which contributed to an
36 overall decrease in CH4 emissions from swine of 1.6 percent and an overall increase in N2O emissions from swine of
37 20.9 percent in 2008.
38 The goat population was updated to reflect the USDA 2007 Census of Agriculture. This change resulted in an
39 increase in both CH4and N2O emissions for goats from the years 2003 through 2008 by 13 percent and 16 percent on
40 average, respectively.
Agriculture 6-11
-------
i Planned Improvements
2 A recent journal article (Lory et al., 2010) criticized the IPCC and EPA methodology used to estimate greenhouse
3 gas emissions from manure management. After review of the methodologies, EPA does not feel that any changes to
4 the IPCC inventory methodologies are required as a result of this article; for more specific information, please see
5 EPA's detailed response to the article (Bartram et al., 2010). EPA will continue to investigate any new or additional
6 data sources identified that contain updated information that can be used to improve the inventory emission
7 estimates. Also, EPA will continue to seek empirical data to compare inventory estimates to specific systems, in
8 order to improve the methodology used to estimate greenhouse gas emissions from manure management.
9 USDA's 2007 Census of Agriculture data are finalized and available. These data will be incorporated into the
10 county-level population estimates used for the Agricultural Soils source category and the estimates of MCF and
11 utilize it to update the WMS distributions for swine and dairy animals.
12 Due to time constraints, the temperature data used to estimate MCFs were not updated for the current Inventory.
13 Updated temperature data will be obtained and applied for subsequent Inventory reports.
14 The uncertainty analysis will be updated in the future to more accurately assess uncertainty of emission calculations.
15 This update is necessary due to the extensive changes in emission calculation methodology that was made in the
16 1990 through 2006 Inventory, including estimation of emissions at the WMS level and the use of new calculations
17 and variables for indirect N2O emissions.
is 6.3. Rice Cultivation (IPCC Source Category 4C)
19 Most of the world's rice, and all rice in the United States, is grown on flooded fields. When fields are flooded,
20 aerobic decomposition of organic material gradually depletes most of the oxygen present in the soil, causing
21 anaerobic soil conditions. Once the environment becomes anaerobic, CH4 is produced through anaerobic
22 decomposition of soil organic matter by methanogenic bacteria. As much as 60 to 90 percent of the CH4 produced is
23 oxidized by aerobic methanotrophic bacteria in the soil (some oxygen remains at the interfaces of soil and water, and
24 soil and root system) (Holzapfel-Pschorn et al. 1985, Sass et al. 1990). Some of the CH4 is also leached away as
25 dissolved CH4 in floodwater that percolates from the field. The remaining un-oxidized CH4 is transported from the
26 submerged soil to the atmosphere primarily by diffusive transport through the rice plants. Minor amounts of CH4
27 also escape from the soil via diffusion and bubbling through floodwaters.
28 The water management system under which rice is grown is one of the most important factors affecting CH4
29 emissions. Upland rice fields are not flooded, and therefore are not believed to produce CH4. In deepwater rice
30 fields (i.e., fields with flooding depths greater than one meter), the lower stems and roots of the rice plants are dead,
31 so the primary CH4 transport pathway to the atmosphere is blocked. The quantities of CH4 released from deepwater
32 fields, therefore, are believed to be significantly less than the quantities released from areas with shallower flooding
33 depths. Some flooded fields are drained periodically during the growing season, either intentionally or accidentally.
34 If water is drained and soils are allowed to dry sufficiently, CH4 emissions decrease or stop entirely. This is due to
35 soil aeration, which not only causes existing soil CH4 to oxidize but also inhibits further CH4 production in soils.
36 All rice in the United States is grown under continuously flooded conditions; none is grown under deepwater
37 conditions. Mid-season drainage does not occur except by accident (e.g., due to levee breach).
38 Other factors that influence CH4 emissions from flooded rice fields include fertilization practices (especially the use
39 of organic fertilizers), soil temperature, soil type, rice variety, and cultivation practices (e.g., tillage, seeding, and
40 weeding practices). The factors that determine the amount of organic material available to decompose (i.e., organic
41 fertilizer use, soil type, rice variety,139 and cultivation practices) are the most important variables influencing the
42 amount of CH4 emitted over the growing season; the total amount of CH4 released depends primarily on the amount
43 of organic substrate available. Soil temperature is known to be an important factor regulating the activity of
44 methanogenic bacteria, and therefore the rate of CH4 production. However, although temperature controls the
45 amount of time it takes to convert a given amount of organic material to CH4, that time is short relative to a growing
46 season, so the dependence of total emissions over an entire growing season on soil temperature is weak. The
47 application of synthetic fertilizers has also been found to influence CH4 emissions; in particular, both nitrate and
139 The roots of rice plants shed organic material, which is referred to as "root exudate." The amount of root exudate produced by
a rice plant over a growing season varies among rice varieties.
6-12 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 sulfate fertilizers (e.g., ammonium nitrate and ammonium sulfate) appear to inhibit CH4 formation.
2 Rice is cultivated in eight states: Arkansas, California, Florida, Louisiana, Mississippi, Missouri, Oklahoma, and
3 Texas. 14° Soil types, rice varieties, and cultivation practices for rice vary from state to state, and even from farm to
4 farm. However, most rice farmers apply organic fertilizers in the form of residue from the previous rice crop, which
5 is left standing, disked, or rolled into the fields. Most farmers also apply synthetic fertilizer to their fields, usually
6 urea. Nitrate and sulfate fertilizers are not commonly used in rice cultivation in the United States. In addition, the
7 climatic conditions of southwest Louisiana, Texas, and Florida often allow for a second, or ratoon, rice crop. Ratoon
8 crops are much less common or non-existent in Arkansas, California, Mississippi, Missouri, Oklahoma, and northern
9 areas of Louisiana. Methane emissions from ratoon crops have been found to be considerably higher than those
10 from the primary crop. This second rice crop is produced from regrowth of the stubble after the first crop has been
11 harvested. Because the first crop's stubble is left behind in ratooned fields, and there is no time delay between
12 cropping seasons (which would allow the stubble to decay aerobically), the amount of organic material that is
13 available for anaerobic decomposition is considerably higher than with the first (i.e., primary) crop.
14 Rice cultivation is a small source of CH4 in the United States (Table 6-9 and Table 6-10). In 2009, CH4 emissions
15 from rice cultivation were 7.3 Tg CO2 Eq. (349 Gg). Annual emissions fluctuated unevenly between the years 1990
16 and 2009, ranging from an annual decrease of 14 percent to an annual increase of 17 percent. There was an overall
17 decrease of 17 percent between 1990 and 2006, due to an overall decrease in primary crop area.141 However,
18 emissions levels increased again by 24 percent between 2006 and 2009 due to a slight increase in rice crop area in
19 all states. The factors that affect the rice acreage in any year vary from state to state, although the price of rice
20 relative to competing crops is the primary controlling variable in most states.
21 Table 6-9: CH4 Emissions from Rice Cultivation (Tg CO2 Eq.)
22
23
24
State
Primary
Arkansas
California
Florida
Louisiana
Mississippi
Missouri
Oklahoma
Texas
Ratoon
Arkansas
Florida
Louisiana
Texas
Total
1990
5.1
2.1
0.7
+
1.0
0.4
0.1
+
0.6
2.1
+
+
1.1
0.9
7.1
+ Less than 0.05 Tg CO2 Eq.
Note: Totals may not sum due to
2000
5.5
2.5
1.0
+
0.9
0.4
0.3
+
0.4
2.0
+
0.1
1.3
0.7
7.5
independent rounding.
2005
6.0
2.9
0.9
+
0.9
0.5
0.4
+
0.4
0.8
+
+
0.5
0.4
6.8
2006
5.1
2.5
0.9
+
0.6
0.3
0.4
+
0.3
0.9
+
+
0.5
0.4
5.9
2007
4.9
2.4
1.0
+
0.7
0.3
0.3
0.0
0.3
1.3
+
+
0.9
0.3
6.2
2008
5.3
2.5
0.9
+
0.8
0.4
0.4
0.0
0.3
1.9
+
+
1.2
0.6
7.2
2009
5.6
2.6
1.0
+
0.8
0.4
0.4
0.0
0.3
1.8
+
+
1.1
0.7
7.3
25 Table 6-10: CH4 Emissions from Rice Cultivation (Gg)
State
Primary
Arkansas
California
Florida
Louisiana
1990
241
102
34
1
46
2000
260
120
47
2
41
2005
287
139
45
1
45
2006
241
119
44
1
29
2007
235
113
45
1
32
2008
254
119
44
1
39
2009
265
125
47
1
39
A very small amount of rice is grown on about 20 acres in South Carolina; however, this amount was determined to be too
insignificant to warrant inclusion in national emission estimates.
141 The 14 percent decrease occurred between 2005 and 2006; the 17 percent increase happened between 1993 and 1994.
Agriculture 6-13
-------
Mississippi
Missouri
Oklahoma
Texas
Ratoon
Arkansas
Florida
Louisiana
Texas
Total
21
7
+
30
98
+
2
52
45
339
19
14
+
18
97
+
2
61
34
357
22
18
+
17
39
1
+
22
17
326
16
18
+
13
41
+
1
22
18
282
16
15
0
12
60
+
1
42
16
295
19
17
+
15
89
+
1
59
29
343
21
17
+
14
84
+
2
51
31
349
+ Lessthan0.5Gg
Note: Totals may not sum due to independent rounding.
Methodology
4 IPCC (2006) recommends using harvested rice areas, area-based daily emission factors (i.e., amount of CH4 emitted
5 per day per unit harvested area), and length of growing season to estimate annual CH4 emissions from rice
6 cultivation. This Inventory uses the recommended methodology and employs Tier 2 U.S. -specific emission factors
7 derived from rice field measurements. State-specific and daily emission factors were not available, however, so
8 average U.S. seasonal emission factors were used. Seasonal emissions have been found to be much higher for
9 ratooned crops than for primary crops, so emissions from ratooned and primary areas are estimated separately using
10 emission factors that are representative of the particular growing season. This approach is consistent with IPCC
11 (2006).
12 The harvested rice areas for the primary and ratoon crops in each state are presented in Table 6-11, and the area of
13 ratoon crop area as a percent of primary crop area is shown in Table 6-12. Primary crop areas for 1990 through
14 2009 for all states except Florida and Oklahoma were taken from U.S. Department of Agriculture's Field Crops
15 Final Estimates 1987-1992 (USDA 1994), Field Crops Final Estimates 1992-1997 (USDA 1998), Field Crops Final
16 Estimates 1997-2002 (USDA 2003), and Crop Production Summary (USDA 2005 through 2010). Source data for
17 non-USDA sources of primary and ratoon harvest areas are shown in Table 6-13. California, Mississippi, Missouri,
18 and Oklahoma have not ratooned rice over the period 1990 through 2009 (Guethle 1999 through 2010; Lee 2003
19 through 2007; Mutters 2002 through 2005; Street 1999 through 2003; Walker 2005, 2007 through 2008; Buehring
20 2009 through 20 10).
2 1 Table 6-11: Rice Areas Harvested (Hectares)
State/Crop
Arkansas
Primary
Ratoon3
California
Florida
Primary
Ratoon
Louisiana
Primary
Ratoon
Mississippi
Missouri
Oklahoma
Texas
Primary
Ratoon
Total Primary
1990
485,633
-
159,854
4,978
2,489
220,558
66,168
101,174
32,376
617
142,857
57,143
1,148,047
2000
570,619
-
221,773
7,801
3,193
194,253
77,701
88,223
68,393
283
86,605
43,302
7,237,957
2005
661,675
662
212,869
4,565
0
212,465
27,620
106,435
86,605
271
81,344
21,963
1,366,228
2006
566,572
6
211,655
4,575
1,295
139,620
27,924
76,487
86,605
17
60,704
23,675
1,146,235
2007
536,220
5
215,702
6,242
1,873
152,975
53,541
76,487
72,036
0
58,681
21,125
1,118,343
2008
564,549
6
209,227
5,463
1,639
187,778
75,111
92,675
80,534
77
69,607
36,892
1,209,911
2009
594,901
6
225,010
5,664
2,266
187,778
65,722
98,341
80,939
0
68,798
39,903
1,261,431
6-14 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Total Ratoon
125,799
124,197
50,245
52,899
76,544 113,648 107,897
Total
1,273,847
1,362,148
1,416,473 1,199,135 1,194,887 1,323,559 1,369,328
a Arkansas ratooning occurred only in 1998, 1999, and 2005 through 2009.
Note: Totals may not sum due to independent rounding.
Table 6-12: Ratooned Area as Percent of Primary Growth Area
5
6
7
State
Arkansas
Florida
Louisiana
Texas
1990 1997 1998 1999 2000
0% + +
50% 65% 41%
30% 40%
40% 50%
2001 2002
60%
30%
40%
+ Indicates ratooning rate less than 0. 1 percent.
Table 6-13 : Non-USD A Data Sources for Rice Harvest
0%
54%
15%
37%
2003
100%
35%
38%
2004
77%
30%
35%
2005
0.1%
0%
13%
27%
2006
+
28%
20%
39%
2007
+
30%
35%
36%
2008
+
30%
40%
53%
2009
+
40%
35%
58%
Information
State/Crop 1990
2000 2001 2002 2003
2004 2005 2006 2007 2008 2009
Arkansas
Ratoon
Wilson (2002 - 2007, 2009 - 2010)
Florida
Primary
Ratoon
Scheuneman
(1999-2001)
Scheuneman
(1999)
Deren
(2002)
Deren
(2002)
Kirstein (2003, 2006)
Kirstein(2003- Cantens
2004) (2005)
Gonzales (2006
Gonzales (2006
-2010)
-2010)
Louisiana
Ratoon
Bollich
(2000)
Linscombe (1999, 2001
-2010)
Oklahoma
Primary
Lee (2003-2007)
Anderson (2008-2010)
Texas
Ratoon
Klosterboer (1999 - 2003)
Stansel (2004 - Texas Ag Experiment Station (2006 -
2005) 2010)
9 To determine what CH4 emission factors should be used for the primary and ratoon crops, CH4 flux information
10 from rice field measurements in the United States was collected. Experiments that involved atypical or
11 nonrepresentative management practices (e.g., the application of nitrate or sulfate fertilizers, or other substances
12 believed to suppress CH4 formation), as well as experiments in which measurements were not made over an entire
13 flooding season or floodwaters were drained mid-season, were excluded from the analysis. The remaining
14 experimental results142 were then sorted by season (i.e., primary and ratoon) and type of fertilizer amendment (i.e.,
15 no fertilizer added, organic fertilizer added, and synthetic and organic fertilizer added). The experimental results
16 from primary crops with added synthetic and organic fertilizer (Bossio et al. 1999; Cicerone et al. 1992; Sass et al.
17 1991a, 1991b) were averaged to derive an emission factor for the primary crop, and the experimental results from
18 ratoon crops with added synthetic fertilizer (Lindau and Bollich 1993, Lindau et al. 1995) were averaged to derive
19 an emission factor for the ratoon crop. The resultant emission factor for the primary crop is 210 kg CH^hectare-
20 season, and the resultant emission factor for the ratoon crop is 780 kg CHVhectare-season.
21 Uncertainty and Time-Series Consistency
22 The largest uncertainty in the calculation of CH4 emissions from rice cultivation is associated with the emission
23 factors. Seasonal emissions, derived from field measurements in the United States, vary by more than one order of
142 In some of these remaining experiments, measurements from individual plots were excluded from the analysis because of the
aforementioned reasons. In addition, one measurement from the ratooned fields (i.e., the flux of 1,490 kg CH4/hectare-season in
Lindau and Bollich 1993) was excluded, because this emission rate is unusually high compared to other flux measurements in the
United States, as well as IPCC (2006) default emission factors.
Agriculture 6-15
-------
1 magnitude. This inherent variability is due to differences in cultivation practices, particularly fertilizer type,
2 amount, and mode of application; differences in cultivar type; and differences in soil and climatic conditions. A
3 portion of this variability is accounted for by separating primary from ratooned areas. However, even within a
4 cropping season or a given management regime, measured emissions may vary significantly. Of the experiments
5 used to derive the emission factors applied here, primary emissions ranged from 22 to 479 kg CH^hectare-season
6 and ratoon emissions ranged from 481 to 1,490 kg CH^hectare-season. The uncertainty distributions around the
7 primary and ratoon emission factors were derived using the distributions of the relevant primary or ratoon emission
8 factors available in the literature and described above. Variability about the rice emission factor means was not
9 normally distributed for either primary or ratooned crops, but rather skewed, with a tail trailing to the right of the
10 mean. A lognormal statistical distribution was, therefore, applied in the Tier 2 Monte Carlo analysis.
11 Other sources of uncertainty include the primary rice-cropped area for each state, percent of rice-cropped area that is
12 ratooned, and the extent to which flooding outside of the normal rice season is practiced. Expert judgment was used
13 to estimate the uncertainty associated with primary rice-cropped area for each state at 1 to 5 percent, and a normal
14 distribution was assumed. Uncertainties were applied to ratooned area by state, based on the level of reporting
15 performed by the state. No uncertainties were calculated for the practice of flooding outside of the normal rice
16 season because CH4 flux measurements have not been undertaken over a sufficient geographic range or under a
17 broad enough range of representative conditions to account for this source in the emission estimates or its associated
18 uncertainty.
19 To quantify the uncertainties for emissions from rice cultivation, a Monte Carlo (Tier 2) uncertainty analysis was
20 performed using the information provided above. The results of the Tier 2 quantitative uncertainty analysis are
21 summarized in Table 6-14. Rice cultivation CH4 emissions in 2009 were estimated to be between 2.5 and 18.0 Tg
22 CO2 Eq. at a 95 percent confidence level, which indicates a range of 65 percent below to 146 percent above the
23 actual 2009 emission estimate of 7.3 Tg CO2 Eq.
24 Table 6-14: Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Rice Cultivation (Tg CO2 Eq. and
25 Percent)
Source Gas 2009 Emission Uncertainty Range Relative to Emission
Estimate
(TgC02Eq.) (TgC02Eq.) (»/
Lower
Bound
Upper
Bound
Lower
Bound
Estimate"
Upper
Bound
Rice Cultivation CH4 7.3 2.5 18.0 -65% +146%
26 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
27 Methodological recalculations were applied to the entire time series to ensure time-series consistency from 1990
28 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
29 above.
30 QA/QC and Verification
31 A source-specific QA/QC plan for rice cultivation was developed and implemented. This effort included a Tier 1
32 analysis, as well as portions of a Tier 2 analysis. The Tier 2 procedures focused on comparing trends across years,
33 states, and cropping seasons to attempt to identify any outliers or inconsistencies. No problems were found.
34 Planned Improvements
35 A possible future improvement is to create region-specific emission factors for rice cultivation. The current
36 methodology uses a nationwide average emission factor, derived from several studies done in a number of states.
37 The prospective improvement would take the same studies and average them by region, presumably resulting in
38 more spatially specific emission factors.
6-16 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
i 6.4. Agricultural Soil Management (IPCC Source Category 4D)
143
2 Nitrous oxide is produced naturally in soils through the microbial processes of nitrification and denitrification. A
3 number of agricultural activities increase mineral N availability in soils, thereby increasing the amount available for
4 nitrification and denitrification, and ultimately the amount of N2O emitted. These activities increase soil mineral N
5 either directly or indirectly (see Figure 6-2). Direct increases occur through a variety of management practices that
6 add or lead to greater release of mineral N to the soil, including fertilization; application of managed livestock
7 manure and other organic materials such as sewage sludge; deposition of manure on soils by domesticated animals
8 in pastures, rangelands, and paddocks (PRP) (i.e., by grazing animals and other animals whose manure is not
9 managed); production of N-fixing crops and forages; retention of crop residues; and drainage and cultivation of
10 organic cropland soils (i.e., soils with a high organic matter content, otherwise known as histosols).144 Other
11 agricultural soil management activities, including irrigation, drainage, tillage practices, and fallowing of land, can
12 influence N mineralization in soils and thereby affect direct emissions. Mineral N is also made available in soils
13 through decomposition of soil organic matter and plant litter, as well as asymbiotic fixation of N from the
14 atmosphere,145 and these processes are influenced by agricultural management through impacts on moisture and
15 temperature regimes in soils. These additional sources of mineral N are included at the recommendation of IPCC
16 (2006) for complete accounting of management impacts on greenhouse gas emissions, as discussed in the
17 Methodology section. Indirect emissions of N2O occur through two pathways: (1) volatilization and subsequent
18 atmospheric deposition of applied/mineralized N,146 and (2) surface runoff and leaching of applied/mineralized N
19 into groundwater and surface water. Direct emissions from agricultural lands (i.e., cropland and grassland) are
20 included in this section, while direct emissions from forest lands and settlements are presented in the Land Use,
21 Land-Use Change, and Forestry chapter. However, indirect N2O emissions from all land-uses (cropland, grassland,
22 forest lands, and settlements) are reported in this section.
23 Figure 6-2: Sources and Pathways of N that Result in N2O Emissions from Agricultural Soil Management
24
25 Agricultural soils produce the majority of N2O emissions in the United States. Estimated emissions from this source
26 in 2009 were 204.6 Tg CO2 Eq. (660 Gg N2O) (see Table 6-15 and Table 6-16). Annual N2O emissions from
27 agricultural soils fluctuated between 1990 and 2009, although overall emissions were 3 percent higher in 2009 than
28 in 1990. Year-to-year fluctuations are largely a reflection of annual variation in weather patterns, synthetic fertilizer
29 use, and crop production. On average, cropland accounted for approximately 70 percent of total direct emissions,
30 while grassland accounted for approximately 30 percent. These percentages are about the same for indirect
31 emissions since forest lands and settlements account for such a small percentage of total indirect emissions.
32 Estimated direct and indirect N2O emissions by sub-source category are shown in Table 6-17 and Table 6-18.
33 Table 6-15: N2O Emissions from Agricultural Soils (Tg CO2 Eq.)
Activity
Direct
Cropland
Grassland
Indirect (All Land-Use
Types)
Cropland
Grassland
1990
153.8
102.9
50.9
44.0
37.5
6.1
2000
162.6
115.6
47.1
44.1
37.7
5.8
2005
167.5
118.1
49.4
43.9
36.8
6.3
2006
163.7
115.6
48.1
45.2
38.6
5.9
2007
165.1
117.8
47.3
44.3
37.6
5.9
2008
166.6
117.9
48.7
44.1
37.5
5.9
2009
160.2
112.0
48.2
44.4
37.5
6.2
143 Nitrification and denitrification are driven by the activity of microorganisms in soils. Nitrification is the aerobic microbial
oxidation of ammonium (NH4+) to nitrate (NO3~), and denitrification is the anaerobic microbial reduction of nitrate to N2. Nitrous
oxide is a gaseous intermediate product in the reaction sequence of denitrification, which leaks from microbial cells into the soil
and then into the atmosphere. Nitrous oxide is also produced during nitrification, although by a less well-understood mechanism
(Nevison 2000).
144 Drainage and cultivation of organic soils in former wetlands enhances mineralization of N-rich organic matter, thereby
increasing N2O emissions from these soils.
145 Asymbiotic N fixation is the fixation of atmospheric N2 by bacteria living in soils that do not have a direct relationship with
plants.
146 jjjggg processes entail volatilization of applied or mineralized N as NH3 and NOX, transformation of these gases within the
atmosphere (or upon deposition), and deposition of the N primarily in the form of particulate NH4+, nitric acid (HNO3), and NOX.
Agriculture 6-17
-------
1
2
o
6
4
5
6
7
8
9
10
11
12
13
Forest Land + 0.1 0.1 0.1 0.1
Settlements 0.3 0.4 0.6 0.6 0.6
Total 197.8 206.8 211.3 208.9 209.4
+ Less than 0.05 Tg CO2 Eq.
Table 6-16: N2O Emissions from Agricultural Soils (Gg)
Activity 1990 2000 2005 2006 2007
Direct 496 525 540 528 533
Cropland 332 373 381 373 380
Grassland 164 152 159 155 152
Indirect (All Land-Use
Types) 142 142 142 146 143
Cropland 121 122 119 125 121
Grassland 20 19 20 19 19
Forest Land 0 + + + +
Settlements 1 1 222
Total 638 667 682 674 675
+ Lessthan0.5GgN2O
Table 6-17: Direct N2O Emissions from Agricultural Soils by Land Use Type and N Input Type
Activity 1990 2000 2005 2006 2007
Cropland 102.9 115.6 118.1 115.6 117.8
Mineral Soils 100.1 112.7 115.2 112.7 114.9
Synthetic Fertilizer 32.3 36.0 38.6 36.7 37.4
Organic Amendments3 10.8 11.8 12.3 12.5 12.8
Residue Nb 12.4 14.3 13.7 13.8 13.9
Mineralization and
Asymbiotic Fixation 44.6 50.6 50.5 49.7 50.9
Organic Soils 2.9 2.9 2.9 2.9 2.9
Grassland 50.9 47.1 49.4 48.1 47.3
Synthetic Fertilizer 3.9 3.9 4.1 4.0 3.9
PRP Manure 8.1 7.9 8.2 8.1 8.0
Managed Manure0 1.5 1.6 1.6 1.6 1.6
Sewage Sludge 0.3 0.4 0.5 0.5 0.5
Residue Nd 15.6 13.8 14.6 14.2 13.9
Mineralization and Asymbiotic
Fixation 21.5 19.5 20.4 19.7 19.3
Total 153.8 115.6 167.5 163.7 165.1
0.1
0.6
210.7
2008
538
380
157
142
121
19
+
2
680
(TgC02Eq.)
2008
117.9
115.0
37.3
12.5
14.3
50.9
2.9
48.7
4.0
8.2
1.6
0.5
14.4
20.0
166.6
0.1
0.6
204.6
2009
517
361
155
143
121
20
+
2
660
2009
112.0
109.1
36.9
12.1
13.1
47.1
2.9
48.2
3.9
7.9
1.6
0.5
14.1
20.1
160.2
a Organic amendment inputs include managed manure amendments, daily spread manure amendments, and commercial organic
fertilizers (i.e., dried blood, dried manure, tankage, compost, and other).
b Cropland residue N inputs include N in unharvested legumes as well as crop residue N.
0 Accounts for managed manure and daily spread manure amendments that are applied to grassland soils.
d Grassland residue N inputs include N in ungrazed legumes as well as ungrazed grass residue N
Table 6-18: Indirect N2O Emissions from all Land-Use Types (Tg CO2 Eq.)
Activity 1990 2000 2005 2006 2007
Cropland 37.5 37.7 36.8 38.6 37.6
Volatilization & Atm. Deposition 11.6 12.7 13.1 14.2 12.8
Surface Leaching & Run-Off 25.8 25.0 23.7 24.4 24.9
Grassland 6.1 5.8 6.3 5.9 5.9
Volatilization & Atm. Deposition 5.1 4.7 4.8 4.8 4.7
Surface Leaching & Run-Off 1.0 1.2 1.5 1.1 1.2
Forest Land + 0.1 0.1 0.1 0.1
2008
37.5
12.9
24.5
5.9
4.7
1.2
0.1
2009
37.5
13.4
24.1
6.2
4.7
1.5
0.1
6-18 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Volatilization & Atm. Deposition
Surface Leaching & Run-Off
Settlements
Volatilization & Atm. Deposition
Surface Leaching & Run-Off
Total
+
+
0.3
0.1
0.2
44.0
+
0.1
0.4
0.1
0.3
44.1
+
0.1
0.6
0.2
0.4
43.9
+
0.1
0.6
0.2
0.4
45.2
+
0.1
0.6
0.2
0.4
44.3
+
0.1
0.6
0.2
0.4
44.1
+
0.1
0.6
0.2
0.4
44.4
1 + Less than 0.05 Tg CO2 Eq.
2
3 Figure 6-3 through Figure 6-6 show regional patterns in direct N2O emissions, and also show N losses from
4 volatilization, leaching, and runoff that lead to indirect N2O emissions. Average annual emissions and N losses are
5 shown for croplands that produce major crops and from grasslands in each state. Direct N2O emissions from
6 croplands tend to be high in the Corn Belt (Illinois, Iowa, Indiana, Ohio, southern Minnesota, southern Wisconsin,
7 and eastern Nebraska), where a large portion of the land is used for growing highly fertilized corn and N-fixing
8 soybean crops. Direct emissions are also high in Missouri, Kansas, and Texas, primarily from irrigated cropping in
9 western Texas, dryland wheat in Kansas, and hay cropping in eastern Texas and Missouri. Direct emissions are low
10 in many parts of the eastern United States because a small portion of land is cultivated, and also low in many
11 western states where rainfall and access to irrigation water are limited.
12 Direct emissions (Tg CO2 Eq./state/year) from grasslands are highest in the central and western United States
13 (Figure 6-4) where a high proportion of the land is used for cattle grazing. Some areas in the Great Lake states, the
14 Northeast, and Southeast have moderate to low emissions even though emissions from these areas tend to be high on
15 a per unit area basis, because the total amount of grassland is much lower than in the central and western United
16 States.
17 Indirect emissions from croplands and grasslands (Figure 6-5 and Figure 6-6) show patterns similar to direct
18 emissions, because the factors that control direct emissions (N inputs, weather, soil type) also influence indirect
19 emissions. However, there are some exceptions, because the processes that contribute to indirect emissions (NO3~
20 leaching, N volatilization) do not respond in exactly the same manner as the processes that control direct emissions
21 (nitrification and denitrification). For example, coarser-textured soils facilitate relatively high indirect emissions in
22 Florida grasslands due to high rates of N volatilization and NO3" leaching, even though they have only moderate
23 rates of direct N2O emissions.
24
25 Figure 6-3: Major Crops, Average Annual Direct N2O Emissions Estimated Using the DAYCENT Model, 1990-
26 2009(TgCO2Eq./year)
27 [Figure will be provided in public review]
28
29 Figure 6-4: Grasslands, Average Annual Direct N2O Emissions Estimated Using the DAYCENT Model, 1990-2009
30 (Tg CO2 Eq./year)
31 [Figure will be provided in public review]
32
33 Figure 6-5: Major Crops, Average Annual N Losses Leading to Indirect N2O Emissions Estimated Using the
34 DAYCENT Model, 1990-2009 (Gg N/year)
35 [Figure will be provided in public review]
36
37 Figure 6-6: Grasslands, Average Annual N Losses Leading to Indirect N2O Emissions Estimated Using the
3 8 DAYCENT Model, 1990-2009 (Gg N/year)
39 [Figure will be provided in public review]
40
41 Methodology
42 The 2006IPCC Guidelines (IPCC 2006) divide the Agricultural Soil Management source category into four
43 components: (1) direct emissions due to N additions to cropland and grassland mineral soils, including synthetic
44 fertilizers, sewage sludge applications, crop residues, organic amendments, and biological N fixation associated with
45 planting of legumes on cropland and grassland soils; (2) direct emissions from drainage and cultivation of organic
Agriculture 6-19
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1 cropland soils; (3) direct emissions from soils due to the deposition of manure by livestock on PRP grasslands; and
2 (4) indirect emissions from soils and water due to N additions and manure deposition to soils that lead to
3 volatilization, leaching, or runoff of N and subsequent conversion to N2O.
4 The United States has adopted recommendations from IPCC (2006) on methods for agricultural soil management.
5 These recommendations include (1) estimating the contribution of N from crop residues to indirect soil N2O
6 emissions; (2) adopting a revised emission factor for direct N2O emissions to the extent that Tier 1 methods are used
7 in the Inventory (described later in this section); (3) removing double counting of emissions from N-fixing crops
8 associated with the biological N fixation and crop residue N input categories; (4) using revised crop residue statistics
9 to compute N inputs to soils based on harvest yield data to the extent that Tier 1 methods are used in the Inventory;
10 (5) accounting for indirect as well as direct emissions from N made available via mineralization of soil organic
11 matter and litter, in addition to asymbiotic fixation147 (i.e., computing total emissions from managed land); and (6)
12 reporting all emissions from managed lands, largely because management affects all processes leading to soil N2O
13 emissions. One recommendation from IPCC (2006) that has not been adopted is the accounting of emissions from
14 pasture renewal, which involves occasional plowing to improve forage production. This practice is not common in
15 the United States, and is not estimated.
16 The methodology used to estimate emissions from agricultural soil management in the United States is based on a
17 combination of IPCC Tier 1 and 3 approaches. A Tier 3, process-based model (DAYCENT) was used to estimate
18 direct emissions from major crops on mineral (i.e., non-organic) soils; as well as most of the direct emissions from
19 grasslands. The Tier 3 approach has been specifically designed and tested to estimate N2O emissions in the United
20 States, accounting for more of the environmental and management influences on soil N2O emissions than the IPCC
21 Tier 1 method (see Box 6-1 for further elaboration). The Tier 1 IPCC (2006) methodology was used to estimate (1)
22 direct emissions from non-major crops on mineral soils (e.g., barley, oats, vegetables, and other crops); (2) the
23 portion of the grassland direct emissions that were not estimated with the Tier 3 DAYCENT model (i.e., federal
24 grasslands); and (3) direct emissions from drainage and cultivation of organic cropland soils. Indirect emissions
25 were also estimated with a combination of DAYCENT and the IPCC Tier 1 method.
26 In past Inventories, attempts were made to subtract "background" emissions that would presumably occur if the
27 lands were not managed. However, this approach is likely to be inaccurate for estimating the anthropogenic
28 influence on soil N2O emissions. Moreover, if background emissions could be measured or modeled based on
29 processes unaffected by anthropogenic activity, they would be a very small portion of the total emissions, due to the
30 high inputs of N to agricultural soils from fertilization and legume cropping. Given the recommendation from IPCC
31 (2006) and the influence of management on all processes leading to N2O emissions from soils in agricultural
32 systems, the decision was made to report total emissions from managed lands for this source category. Annex 3.11
33 provides more detailed information on the methodologies and data used to calculate N2O emissions from each
34 component.
35
36 [BEGIN BOX]
37
38 Box 6-1. Tier 1 vs. Tier 3 Approach for Estimating N2O Emissions
39
40 The IPCC (2006) Tier 1 approach is based on multiplying activity data on different N inputs (e.g., synthetic
41 fertilizer, manure, N fixation, etc.) by the appropriate default IPCC emission factors to estimate N2O emissions on
42 an input-by-input basis. The Tier 1 approach requires a minimal amount of activity data, readily available in most
43 countries (e.g., total N applied to crops); calculations are simple; and the methodology is highly transparent. In
44 contrast, the Tier 3 approach developed for this Inventory employs a process-based model (i.e., DAYCENT) that
45 represents the interaction of N inputs and the environmental conditions at specific locations. Consequently, the Tier
46 3 approach is likely to produce more accurate estimates; it accounts more comprehensively for land-use and
47 management impacts and their interaction with environmental factors (i.e., weather patterns and soil characteristics),
147 N inputs from asymbiotic N fixation are not directly addressed in 2006 IPCC Guidelines, but are a component of the total
emissions from managed lands and are included in the Tier 3 approach developed for this source.
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1 which will enhance or dampen anthropogenic influences. However, the Tier 3 approach requires more detailed
2 activity data (e.g., crop-specific N amendment rates), additional data inputs (e.g., daily weather, soil types, etc.), and
3 considerable computational resources and programming expertise. The Tier 3 methodology is less transparent, and
4 thus it is critical to evaluate the output of Tier 3 methods against measured data in order to demonstrate the
5 adequacy of the method for estimating emissions (IPCC 2006). Another important difference between the Tier 1
6 and Tier 3 approaches relates to assumptions regarding N cycling. Tier 1 assumes that N added to a system is
7 subject to N2O emissions only during that year and cannot be stored in soils and contribute to N2O emissions in
8 subsequent years. This is a simplifying assumption that is likely to create bias in estimated N2O emissions for a
9 specific year. In contrast, the process-based model used in the Tier 3 approach includes such legacy effects when N
10 added to soils is re-mineralized from soil organic matter and emitted as N2O during subsequent years.
11
12 [END BOX]
13
14 Direct N2O Emissions from Cropland Soils
15 Major Crop Types on Mineral Cropland Soils
16 The DAYCENT ecosystem model (Del Grosso et al. 2001, Parton et al. 1998) was used to estimate direct N2O
17 emissions from mineral cropland soils that are managed for production of major crops—specifically corn, soybeans,
18 wheat, alfalfa hay, other hay, sorghum, and cotton—representing approximately 90 percent of total croplands in the
19 United States. For these croplands, DAYCENT was used to simulate crop growth, soil organic matter
20 decomposition, greenhouse gas fluxes, and key biogeochemical processes affecting N2O emissions, and the
21 simulations were driven by model input data generated from daily weather records (Thornton et al. 1997, 2000;
22 Thornton and Running 1999), land management surveys (see citations below), and soil physical properties
23 determined from national soil surveys (Soil Survey Staff 2005). Note that the influence of land-use change on soil
24 N2O emissions was not addressed in this analysis, but is a planned improvement.
25 DAYCENT simulations were conducted for each major crop at the county scale in the United States. Simulating
26 N2O emissions at the county scale was facilitated by soil and weather data that were available for every county with
27 more than 100 acres of agricultural land, and by land management data (e.g., timing of planting, harvesting, and
28 intensity of cultivation) that were available at the agricultural-region level as defined by the Agricultural Sector
29 Model (McCarl et al. 1993). ASM has 63 agricultural regions in the contiguous United States. Most regions
30 correspond to one state, except for those states with greater heterogeneity in agricultural practices; in such cases,
31 more than one region is assigned to a state. While cropping systems were simulated for each county, the results best
32 represent emissions at regional (i.e., state) and national levels due to the regional scale of management data, which
33 include model parameters that determined the influence of management activities on soil N2O emissions (e.g., when
34 crops were planted/harvested).
35 Nitrous oxide emissions from managed agricultural lands are the result of interactions among anthropogenic
36 activities (e.g., N fertilization, manure application, tillage) and other driving variables, such as weather and soil
37 characteristics. These factors influence key processes associated with N dynamics in the soil profile, including
38 immobilization of N by soil microbial organisms, decomposition of organic matter, plant uptake, leaching, runoff,
39 and volatilization, as well as the processes leading to N2O production (nitrification and denitrification). It is not
40 possible to partition N2O emissions into each anthropogenic activity directly from model outputs due to the
41 complexity of the interactions (e.g., N2O emissions from synthetic fertilizer applications cannot be distinguished
42 from those resulting from manure applications). To approximate emissions by activity, the amount of mineral N
43 added to the soil for each of these sources was determined and then divided by the total amount of mineral N that
44 was made available in the soil according to the DAYCENT model. The percentages were then multiplied by the
45 total of direct N2O emissions in order to approximate the portion attributed to key practices. This approach is only
46 an approximation because it assumes that all N made available in soil has an equal probability of being released as
47 N2O, regardless of its source, which is unlikely to be the case (Delgado et al., 2009). However, this approach allows
48 for further disaggregation of emissions by source of N, which is valuable for reporting purposes and is analogous to
49 the reporting associated with the IPCC (2006) Tier 1 method, in that it associates portions of the total soil N2O
50 emissions with individual sources of N.
Agriculture 6-21
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1 DAYCENT was used to estimate direct N2O emissions due to mineral N available from: (1) the application of
2 synthetic fertilizers; (2) the application of livestock manure; (3) the retention of crop residues (i.e., leaving residues
3 in the field after harvest instead of burning or collecting residues); and (4) mineralization of soil organic matter and
4 litter, in addition to asymbiotic fixation. Note that commercial organic fertilizers are addressed with the Tier 1
5 method because county-level application data would be needed to simulate applications in DAYCENT, and
6 currently data are only available at the national scale. The third and fourth sources are generated internally by the
7 DAYCENT model. For the first two practices, annual changes in soil mineral N due to anthropogenic activity were
8 obtained or derived from the following sources:
9 • Crop-specific N-fertilization rates: Data sources for fertilization rates include Alexander and Smith (1990),
10 Anonymous (1924), Battaglin and Goolsby (1994), Engle and Makela (1947), ERS (1994, 2003), Fraps and
11 Asbury (1931), Ibach and Adams (1967), Ibach et al. (1964), NFA (1946), NRIAI (2003), Ross and Mehring
12 (1938), Skinner (1931), Smalley et al. (1939), Taylor (1994), and USDA (1966, 1957, 1954, 1946).
13 Information on fertilizer use and rates by crop type for different regions of the United States were obtained
14 primarily from the USDA Economic Research Service Cropping Practices Survey (ERS 1997) with additional
15 data from other sources, including the National Agricultural Statistics Service (NASS 1992, 1999, 2004).
16 • Managed manure production and application to croplands and grasslands: Manure N amendments and daily
17 spread manure N amendments applied to croplands and grasslands (not including PRP manure) were
18 determined using USDA Manure N Management Databases for 1997 (Kellogg et al. 2000; Edmonds et al.
19 2003). Amendment data for 1997 were scaled to estimate values for other years based on the availability of
20 managed manure N for application to soils in 1997 relative to other years. The amount of available N from
21 managed manure for each livestock type was calculated as described in the Manure Management section
22 (Section 6.2) and Annex 3.10.
23 • Retention of crop residue, N mineralization from soil organic matter, and asymbiotic N fixation from the
24 atmosphere: The IPCC approach considers crop residue N and N mineralized from soil organic matter as
25 activity data. However, they are not treated as activity data in DAYCENT simulations because residue
26 production, N fixation, mineralization of N from soil organic matter, and asymbiotic fixation are internally
27 generated by the model as part of the simulation. In other words, DAYCENT accounts for the influence of N
28 fixation, mineralization of N from soil organic matter, and retention of crop residue on N2O emissions, but these
29 are not model inputs. The DAYCENT simulations also accounted for the approximately 3 percent of grain crop
30 residues that were assumed to be burned based on state inventory data (ILENR 1993, Oregon Department of
31 Energy 1995, Noller 1996, Wisconsin Department of Natural Resources 1993, and Cibrowski 1996), and
32 therefore did not contribute to soil N2O emissions.
33 • Historical and modern crop rotation and management information (e.g., timing and type of cultivation, timing of
34 planting/harvest, etc.): These activity data were derived from Kurd (1930, 1929), Latta (1938), Iowa State
35 College Staff Members (1946), Bogue (1963), Hurt (1994), USDA (2000a) as extracted by Eve (2001) and
36 revised by Ogle (2002), CTIC (1998), Piper et al. (1924), Hardies and Hume (1927), Holmes (1902, 1929),
37 Spillman (1902, 1905, 1907, 1908), Chilcott (1910), Smith (1911), Kezer (ca. 1917), Hargreaves (1993), ERS
38 (2002), Warren (1911), Langston et al. (1922), Russell et al. (1922), Elliott and Tapp (1928), Elliott (1933),
39 Ellsworth (1929), Garey (1929), Hodges et al. (1930), Bonnen and Elliott (1931), Brenner et al. (2002, 2001),
40 and Smith et al. (2002).
41 DAYCENT simulations produced per-area estimates of N2O emissions (g N2O-N/m2) for major crops in each
42 county, which were multiplied by the cropland areas in each county to obtain county-scale emission estimates.
43 Cropland area data were from NASS (USDA 20 lOa, 20 lOb). The emission estimates by reported crop areas in the
44 county were scaled to the regions (and states for mapping purposes when there was more than one region in a state),
45 and the national estimate was calculated by summing results across all regions. DAYCENT is sensitive to
46 interannual variability in weather patterns and other controlling variables, so emissions associated with individual
47 activities vary through time even if the management practices remain the same (e.g., if N fertilization remains the
48 same for two years). In contrast, Tier 1 methods do not capture this variability and rather have a linear, monotonic
49 response that depends solely on management practices. DAYCENT's ability to capture these interactions between
50 management and environmental conditions produces more accurate estimates of N2O emissions than the Tier 1
51 method.
52 Non-Major Crop Types on Mineral Cropland Soils
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1 The IPCC (2006) Tier 1 methodology was used to estimate direct N2O emissions for mineral cropland soils that are
2 managed for production of non-major crop types, including barley, oats, tobacco, sugarcane, sugar beets,
3 sunflowers, millet, rice, peanuts, and other crops that were not included in the DAYCENT simulations. Estimates of
4 direct N2O emissions from N applications to non-major crop types were based on mineral soil N that was made
5 available from the following practices: (1) the application of synthetic commercial fertilizers; (2) application of
6 managed manure and non-manure commercial organic fertilizers;148 and (3) the retention of above- and below-
7 ground crop residues in agricultural fields (i.e., crop biomass that is not harvested). Non-manure organic
8 amendments were not included in the DAYCENT simulations because county-level data were not available.
9 Consequently, non-manure organic amendments, as well as additional manure that was not added to major crops in
10 the DAYCENT simulations, were included in the Tier 1 analysis. The influence of land-use change on soil N2O
11 emissions from non-major crops has not been addressed in this analysis, but is a planned improvement. The
12 following sources were used to derive activity data:
13 • A process-of-elimination approach was used to estimate synthetic N fertilizer additions for non-major crops,
14 because little information exists on their fertilizer application rates. The total amount of fertilizer used on farms
15 has been estimated by the USGS from sales records (Ruddy et al. 2006), and these data were aggregated to
16 obtain state-level N additions to farms. After subtracting the portion of fertilizer applied to major crops and
17 grasslands (see sections on Major Crops and Grasslands for information on data sources), the remainder of the
18 total fertilizer used on farms was assumed to be applied to non-major crops.
19 • A process-of-elimination approach was used to estimate manure N additions for non-major crops, because little
20 information exists on application rates for these crops. The amount of manure N applied to major crops and
21 grasslands was subtracted from total manure N available for land application (see sections on Major Crops and
22 Grasslands for information on data sources), and this difference was assumed to be applied to non-major crops.
23 • Non-manure, non-sewage-sludge commercial organic fertilizer additions were based on organic fertilizer
24 consumption statistics, which were converted to units of N using average organic fertilizer N content (TVA
25 1991 through 1994; AAPFCO 1995 through 2009. Manure and sewage sludge components were subtracted
26 from total commercial organic fertilizers to avoid double counting.
27 • Crop residue N was derived by combining amounts of above- and below-ground biomass, which were
28 determined based on crop production yield statistics (USDA 1994, 1998, 2003, 2005, 2006, 2008, 2009, 2010a),
29 dry matter fractions (IPCC 2006), linear equations to estimate above-ground biomass given dry matter crop
30 yields from harvest (IPCC 2006), ratios of below-to-above-ground biomass (IPCC 2006), and N contents of the
31 residues (IPCC 2006). Approximately 3 percent of the crop residues were burned and therefore did not
32 contribute to soil N2O emissions, based on state inventory data (ILENR 1993, Oregon Department of Energy
33 1995, Noller 1996, Wisconsin Department of Natural Resources 1993, and Cibrowski 1996).
34 The total increase in soil mineral N from applied fertilizers and crop residues was multiplied by the IPCC (2006)
35 default emission factor to derive an estimate of direct N2O emissions from non-major crop types.
36 Drainage and Cultivation of Organic Cropland Soils
37 The IPCC (2006) Tier 1 methods were used to estimate direct N2O emissions due to drainage and cultivation of
38 organic soils at a state scale. State-scale estimates of the total area of drained and cultivated organic soils were
3 9 obtained from the National Resources Inventory (NRI) (USDA 2000a, as extracted by Eve 2001 and amended by
40 Ogle 2002). Temperature data from Daly et al. (1994, 1998) were used to subdivide areas into temperate and sub-
41 tropical climates using the climate classification from IPCC (2006). Data were available for 1982, 1992 and 1997.
42 To estimate annual emissions, the total temperate area was multiplied by the IPCC default emission factor for
43 temperate regions, and the total sub-tropical area was multiplied by the average of the IPCC default emission factors
44 for temperate and tropical regions (IPCC 2006).
148 Commercial organic fertilizers include dried blood, tankage, compost, and other; dried manure and sewage sludge that are
used as commercial fertilizer have been excluded to avoid double counting. The dried manure N is counted with the non-
commercial manure applications, and sewage sludge is assumed to be applied only to grasslands.
Agriculture 6-23
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1 Direct N2O Emissions from Grassland Soils
2 As with N2O from croplands, the Tier 3 process-based DAYCENT model and Tier 1 method described in IPCC
3 (2006) were combined to estimate emissions from grasslands. Grasslands include pastures and rangelands used for
4 grass forage production, where the primary use is livestock grazing. Rangelands are typically extensive areas of
5 native grasslands that are not intensively managed, while pastures are often seeded grasslands, possibly following
6 tree removal, which may or may not be improved with practices such as irrigation and interseeding legumes.
7 DAYCENT was used to simulate county-scale N2O emissions from non-federal grasslands resulting from manure
8 deposited by livestock directly onto pastures and rangelands (i.e., PRP manure), N fixation from legume seeding,
9 managed manure amendments (i.e., manure other than PRP manure), and synthetic fertilizer application. Other N
10 inputs were simulated within the DAYCENT framework, including N input from mineralization due to
11 decomposition of soil organic matter and N inputs from senesced grass litter, as well as asymbiotic fixation of N
12 from the atmosphere. The simulations used the same weather, soil, and synthetic N fertilizer data as discussed under
13 the section for Major Crop Types on Mineral Cropland Soils. Managed manure N amendments to grasslands were
14 estimated from Edmonds et al. (2003) and adjusted for annual variation using data on the availability of managed
15 manure N for application to soils, according to methods described in the Manure Management section (Section 6.2)
16 and Annex 3.10. Biological N fixation is simulated within DAYCENT and therefore was not an input to the model.
17 Manure N deposition from grazing animals (i.e., PRP manure) is another key input of N to grasslands. The amounts
18 of PRP manure N applied on non-federal and federal grasslands in each county were based on the proportion of non-
19 federal to federal grassland area (See below for more information on area data). The amount of PRP manure applied
20 on non-federal grasslands was an input to the DAYCENT model (see Annex 3.10), and included approximately 91
21 percent of total PRP manure. The remainder of the PRP manure N excretions in each county was assumed to be
22 excreted on federal grasslands (i.e., DAYCENT simulations were only conducted for non-federal grasslands), and
23 the N2O emissions were estimated using the IPCC (2006) Tier 1 method with IPCC default emission factors.
24 Sewage sludge was assumed to be applied on grasslands because of the heavy metal content and other pollutants in
25 human waste that limit its use as an amendment to croplands. Sewage sludge application was estimated from data
26 compiled by EPA (1993, 1999, 2003), McFarland (2001), and NEBRA (2007). Sewage sludge data on soil
27 amendments to agricultural lands were only available at the national scale, and it was not possible to associate
28 application with specific soil conditions and weather at the county scale. Therefore, DAYCENT could not be used
29 to simulate the influence of sewage sludge amendments on N2O emissions from grassland soils, and consequently,
30 emissions from sewage sludge were estimated using the IPCC (2006) Tier 1 method.
31 Grassland area data were consistent with the Land Representation reported in Section 7.1. Data were obtained from
32 the U.S. Department of Agriculture National Resources Inventory (USDA 2000a, Nusser and Goebel 1997,
33 http://www.ncgc.nrcs.usda.gov/products/nri/index.htm) and the U.S. Geological Survey (USGS) National Land
34 Cover Dataset (NLCD, Vogelman et al. 2001, http://www.mrlc.gov), which were reconciled with the Forest
35 Inventory and Analysis Data (http://fia.fs.us/tools-data/data). The area data for pastures and rangeland were
36 aggregated to the county level to estimate non-federal and federal grassland areas.
37 DAYCENT simulations produced per-area estimates of N2O emissions (g N2O-N/m2) for pasture and rangelands,
38 which were multiplied by the non-federal grassland areas in each county. The county-scale N2O emission estimates
39 for non-federal grasslands were scaled to the 63 agricultural regions (and to the state level for mapping purposes if
40 there was more than one region in a state), and the national estimate was calculated by summing results across all
41 regions. Tier 1 estimates of N2O emissions for the PRP manure N deposited on federal grasslands and applied
42 sewage sludge N were produced by multiplying the N input by the appropriate emission factor. Tier 1 estimates for
43 emissions from manure N were calculated at the state level and aggregated to the entire country but emission from
44 sewage sludge N were calculated exclusively at the national scale.
45 Total Direct N2O Emissions from Cropland and Grassland Soils
46 Annual direct emissions from major and non-major crops on mineral cropland soils, from drainage and cultivation of
47 organic cropland soils, and from grassland soils were summed to obtain the total direct N2O emissions from
48 agricultural soil management (see Table 6-15 and Table 6-16).
49 Indirect N2O Emissions from Managed Soils of all Land-Use Types
50 This section describes the methods used for estimating indirect soil N2O emissions from all land-use types (i.e.,
6-24 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 croplands, grasslands, forest lands, and settlements). Indirect N2O emissions occur when mineral N made available
2 through anthropogenic activity is transported from the soil either in gaseous or aqueous forms and later converted
3 into N2O. There are two pathways leading to indirect emissions. The first pathway results from volatilization of N
4 as NOX and NH3 following application of synthetic fertilizer, organic amendments (e.g., manure, sewage sludge),
5 and deposition of PRP manure. N made available from mineralization of soil organic matter and asymbiotic fixation
6 also contributes to volatilized N emissions. Volatilized N can be returned to soils through atmospheric deposition,
7 and a portion of the deposited N is emitted to the atmosphere as N2O. The second pathway occurs via leaching and
8 runoff of soil N (primarily in the form of NO3") that was made available through anthropogenic activity on managed
9 lands, mineralization of soil organic matter, and asymbiotic fixation. The NO3" is subject to denitrification in water
10 bodies, which leads to N2O emissions. Regardless of the eventual location of the indirect N2O emissions, the
11 emissions are assigned to the original source of the N for reporting purposes, which here includes croplands,
12 grasslands, forest lands, and settlements.
13 Indirect N2O Emissions from Atmospheric Deposition of Volatilized N from Managed Soils
14 As in the direct emissions calculation, the Tier 3 DAYCENT model and IPCC (2006) Tier 1 methods were
15 combined to estimate the amount of N that was volatilized and eventually emitted as N2O. DAYCENT was used to
16 estimate N volatilization for land areas whose direct emissions were simulated with DAYCENT (i.e., major
17 croplands and most grasslands). The N inputs included are the same as described for direct N2O emissions in the
18 sections on major crops and grasslands. Nitrogen volatilization for all other areas was estimated using the Tier 1
19 method and default IPCC fractions for N subject to volatilization (i.e., N inputs on non-major croplands, PRP
20 manure N excretion on federal grasslands, sewage sludge application on grasslands). The Tier 1 method and default
21 fractions were also used to estimate N subject to volatilization from N inputs on settlements and forest lands (see the
22 Land Use, Land-Use Change, and Forestry chapter). For the volatilization data generated from both the DAYCENT
23 and Tier 1 approaches, the IPCC (2006) default emission factor was used to estimate indirect N2O emissions
24 occurring due to re-deposition of the volatilized N (Table 6-18).
25 Indirect N2O Emissions from Leaching/Runoff
26 As with the calculations of indirect emissions from volatilized N, the Tier 3 DAYCENT model and IPCC (2006)
27 Tier 1 method were combined to estimate the amount of N that was subject to leaching and surface runoff into water
28 bodies, and eventually emitted as N2O. DAYCENT was used to simulate the amount of N transported from lands
29 used to produce major crops and most grasslands. N transport from all other areas was estimated using the Tier 1
30 method and the IPCC (2006) default factor for the proportion of N subject to leaching and runoff. This N transport
31 estimate includes N applications on croplands that produce non-major crops, sewage sludge amendments on
32 grasslands, PRP manure N excreted on federal grasslands, and N inputs on settlements and forest lands. For both
33 the DAYCENT and IPCC (2006) Tier 1 methods, nitrate leaching was assumed to be an insignificant source of
34 indirect N2O in cropland and grassland systems in arid regions as discussed in IPCC (2006). In the United States,
35 the threshold for significant nitrate leaching is based on the potential evapotranspiration (PET) and rainfall amount,
36 similar to IPCC (2006), and is assumed to be negligible in regions where the amount of precipitation plus irrigation
37 does not exceed 80 percent of PET. For leaching and runoff data estimated by the DAYCENT and Tier 1
38 approaches, the IPCC (2006) default emission factor was used to estimate indirect N2O emissions that occur in
39 groundwater and waterways (Table 6-18).
40 Uncertainty and Time-Series Consistency
41 Uncertainty was estimated for each of the following five components of N2O emissions from agricultural soil
42 management: (1) direct emissions calculated by DAYCENT; (2) the components of indirect emissions (N
43 volatilized and leached or runoff) calculated by DAYCENT; (3) direct emissions calculated with the IPCC (2006)
44 Tier 1 method; (4) the components of indirect emissions (N volatilized and leached or runoff) calculated with the
45 IPCC (2006) Tier 1 method; and (5) indirect emissions calculated with the IPCC (2006) Tier 1 method. Uncertainty
46 in direct emissions, which account for the majority of N2O emissions from agricultural management, as well as the
47 components of indirect emissions calculated by DAYCENT were estimated with a Monte Carlo Analysis,
48 addressing uncertainties in model inputs and structure (i.e., algorithms and parameterization) (Del Grosso et al.,
49 2010). Uncertainties in direct emissions calculated with the IPCC (2006) Tier 1 method, the proportion of
50 volatilization and leaching or runoff estimated with the IPCC (2006) Tier 1 method, and indirect N2O emissions
51 were estimated with a simple error propagation approach (IPCC 2006). Additional details on the uncertainty
Agriculture 6-25
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1 methods are provided in Annex 3.11.
2 Uncertainties from the Tier 1 and Tier 3 (i.e., DAYCENT) estimates were combined using simple error propagation
3 (IPCC 2006), and the results are summarized in Table 6-19. Agricultural direct soil N2O emissions in 2009 were
4 estimated to be between 118.3 and 250.6 Tg CO2 Eq. at a 95 percent confidence level. This indicates a range of 26
5 percent below and 56 percent above the 2009 emission estimate of 160.2 Tg CO2 Eq. The indirect soil N2O
6 emissions in 2009 were estimated to range from 22.4 to 111.6 Tg CO2 Eq. at a 95 percent confidence level,
7 indicating an uncertainty of 50 percent below and 151 percent above the 2009 emission estimate of 44.4 Tg CO2 Eq.
8 Table 6-19: Quantitative Uncertainty Estimates of N2O Emissions from Agricultural Soil Management in 2009 (Tg
9 CO2 Eq. and Percent)
2009 Emission Uncertainty Range Relative to Emission
Source Gas Estimate Estimate
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Direct Soil N2O Emissions N2O
Indirect Soil N2O Emissions N2O
Lower
Bound
160.2 118.3
44.4 22.4
Upper
Bound
250.6
111.6
Lower
Bound
-26%
-50%
Upper
Bound
+56%
+151%
10 Note: Due to lack of data, uncertainties in areas for major crops, managed manure N production, PRP manure N production, other
11 organic fertilizer amendments, indirect losses of N in the DAYCENT simulations, and sewage sludge amendments to soils are
12 currently treated as certain; these sources of uncertainty will be included in future Inventories.
13 Methodological recalculations were applied to the entire time series to ensure time-series consistency from 1990
14 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
15 above.
16 QA/QC and Verification
17 For quality control, DAYCENT results for N2O emissions and NO3" leaching were compared with field data
18 representing various cropland and grassland systems, soil types, and climate patterns (Del Grosso et al. 2005, Del
19 Grosso et al. 2008), and further evaluated by comparing to emission estimates produced using the IPCC (2006) Tier
20 1 method for the same sites. Nitrous oxide measurement data were available for 11 sites in the United States and
21 one in Canada, representing 30 different combinations of fertilizer treatments and cultivation practices. DAYCENT
22 estimates of N2O emissions were closer to measured values at all sites compared to the IPCC Tier 1 estimate, except
23 for Colorado dryland cropping (Figure 6-7). In general, IPCC Tier 1 methodology tends to over-estimate emissions
24 when observed values are low and under-estimate emissions when observed values are high, while DAYCENT
25 estimates are less biased. This is not surprising because DAYCENT accounts for site-level factors (weather, soil
26 type) that influence N2O emissions. Nitrate leaching data were available for three sites in the United States
27 representing nine different combinations of fertilizer amendments. Linear regressions of simulated vs. observed
28 emission and leaching data yielded correlation coefficients of 0.89 and 0.94 for annual N2O emissions and NO3"
29 leaching, respectively. This comparison demonstrates that DAYCENT provides relatively high predictive capability
30 for N2O emissions and NO3" leaching, and is an improvement over the IPCC Tier 1 method (see additional
31 information in Annex 3.11).
32
33 Figure 6-7: Comparison of Measured Emissions at Field Sites and Modeled Emissions Using the DAYCENT
34 Simulation Model
35
36 Spreadsheets containing input data and probability distribution functions required for DAYCENT simulations of
37 major croplands and grasslands and unit conversion factors were checked, as were the program scripts that were
38 used to run the Monte Carlo uncertainty analysis. Several errors were identified following re-organization of the
3 9 calculation spreadsheets, and corrective actions have been taken. In particular, some of the links between
40 spreadsheets were missing or needed to be modified. Spreadsheets containing input data, emission factors, and
41 calculations required for the Tier 1 approach were checked and no errors were found.
6-26 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
i Recalculations Discussion
2 Two major revisions were made in the Agricultural Soil Management section for the current Inventory.
3 First, the methodology used to estimate grassland areas was updated and revised to be consistent with the Land
4 Representation used in the Land Use, Land Use Change and Forestry sector (see Section 7.1). This led to an overall
5 decrease in grassland area, and lower emissions than reported in the prior Inventory. Second, the methodology used
6 to calculate livestock manure N was changed such that total manure N added to soils increased by approximately 11
7 percent (see Section 6.2 for details).
8 The recalculations had opposite impacts on the emissions, with less grassland area tending to decrease emissions and
9 higher manure N inputs tending to increase emissions. In some years emissions were higher overall, but on average,
10 these changes led to a lower amount of N2O emissions from agricultural soil management by about 1.5 percent over
11 the time series relative to the previous Inventory.
12 Planned Improvements
13 A key improvement is underway for Agricultural Soil Management to incorporate more land-use survey data from
14 the NRI (USDA 2000a) into the DAYCENT simulation analysis, beyond the area estimates for rangeland and
15 pasture that are currently used to estimate emissions from grasslands. NRI has a record of land-use activities since
16 1979 for all U.S. agricultural land, which is estimated at about 386 Mha. NASS is used as the basis for land-use
17 records in the current Inventory, and there are three major disadvantages to this dataset. First, most crops are grown
18 in rotation with other crops (e.g., corn-soybean), but NASS data provide no information regarding rotation histories.
19 In contrast, NRI is designed to track rotation histories, which is important because emissions from any particular
20 year can be influenced by the crop that was grown the previous year. Second, NASS does not conduct a complete
21 survey of cropland area each year, leading to gaps in the land base. NRI provides a complete history of cropland
22 areas for four out of every five years from 1979 to 1997, and then every year after 1998. Third, the current
23 Inventory based on NASS does not quantify the influence of land-use change on emissions, which can be addressed
24 using the NRI survey records. NRI also provides additional information on pasture land management that can be
25 incorporated into the analysis (particularly the use of irrigation). Using NRI data will also make the Agricultural
26 Soil Management methods more consistent with the methods used to estimate C stock changes for agricultural soils.
27 The structure of model input files that contain land management data are currently being extensively revised to
28 facilitate use of the annualized NRI data. This improvement is planned for completion by the next Inventory.
29 Another improvement is to reconcile the amount of crop residues burned with the Field Burning of Agricultural
30 Residues source category (Section 6.5). This year the methodology for Field Burning of Agricultural Residues was
31 significantly updated, but the changes were implemented too late for the new estimates of crop residues burned to be
32 incorporated into the DAYCENT runs for the Agricultral Soil Management source. Next year the estimates will be
33 reconciled; meanwhile the estimates presented in this section use the previous year's methodology for determining
34 crop residues burned.
35 Other planned improvements are minor but will lead to more accurate estimates, including updating DAYMET
36 weather data for more recent years following the release of new data, and using a rice-crop-specific emission factor
37 for N amendments to rice areas.
38 6.5. Field Burning of Agricultural Residues (IPCC Source Category 4F)
39 Farming activities produce large quantities of agricultural crop residues, and farmers use or dispose of these residues
40 in a variety of ways. For example, agricultural residues can be left on or plowed into the field; composted and then
41 applied to soils; landfilled; or burned in the field. Alternatively, they can be collected and used as fuel, animal
42 bedding material, supplemental animal feed, or construction material. Field burning of crop residues is not
43 considered a net source of CO2, because the C released to the atmosphere as CO2 during burning is assumed to be
44 reabsorbed during the next growing season. Crop residue burning is, however, a net source of CH4, N2O, CO, and
45 NOX, which are released during combustion.
46 Field burning is not a common method of agricultural residue disposal in the United States. The primary crop types
47 whose residues are typically burned in the United States are corn, cotton, lentils, rice, soybeans, sugarcane, and
48 wheat (McCarty 2009). In 2009, CH4 and N2O emissions from field burning were 0.2 Tg CO2 Eq. (12 Gg) and 0.1
49 Tg. CO2 Eq. (0.3 Gg), respectively. Annual emissions from this source over the period 1990 to 2009 have remained
Agriculture 6-27
-------
1 relatively constant, averaging approximately 0.2 Tg CO2 Eq. (1 Gg) of CH4 and 0.1 Tg CO2 Eq. (0.3 Gg) of N2O
2 (see Table 6-20 and Table 6-21).
3 Table 6-20: CH4 and N2O Emissions from Field Burning of Agricultural Residues (Tg CO2 Eq.)
4
5
6
7
8
9
Gas/Crop Type 1990 2000 2005 2006 2007 2008
CH4 0.3 0.3 0.2 0.2 0.2 0.3
Corn + + + + + +
Cotton + + + + + +
Lentils + + + + + +
Rice + + + + 0.1 +
Soybeans + + + + + +
Sugarcane 0.1 0.1 + 0.1 + +
Wheat 0.1 0.1 0.1 0.1 0.1 0.1
N2O 0.1 0.1 0.1 0.1 0.1 0.1
Corn + + + + + +
Cotton + + + + + +
Lentils + + + + + +
Rice + + + + + +
Soybeans + + + + + +
Sugarcane + + + + + +
Wheat + + + + + +
Total 0.4 0.4 0.3 0.3 0.3 0.4
+ Less than 0.05 Tg CO2 Eq.
Note: Totals may not sum due to independent rounding.
Table 6-2 1 : CH4, N2O, CO, and NOX Emissions from Field Burning of Agricultural Residues (Gg)
Gas/Crop Type 1990 2000 2005 2006 2007 2008
CH4 13 12 9 11 11 13
Corn 1 1 1211
Cotton + + + + + +
Lentils + + + + + +
Rice 2 2 2232
Soybeans 1 1 1111
Sugarcane 3 2 1312
Wheat 6 6 4456
N2O + + + + + +
Corn + + + + + +
Cotton + + + + + +
Lentils + + + + + +
Rice + + + + + +
Soybeans + + + + + +
Sugarcane + + + + + +
Wheat + + + + + +
CO 268 259 184 233 237 270
NOX 8 8 6788
+ Less than 0.5 Gg
Note: Totals may not sum due to independent rounding.
2009
0.2
+
+
+
+
0.1
0.1
+
+
+
+
+
+
+
0.4
2009
12
2
+
+
2
1
2
5
+
+
+
+
+
+
+
+
247
8
10 Methodology
11 The Tier 2 methodology used for estimating greenhouse gas emissions from field burning of agricultural residues in
12 the United States is consistent with IPCC (2006) (for more details, see Box 6-2). In order to estimate the amounts of
13 C and N released during burning, the following equation was used:
14
15 C or N released = £ over all crop types and states (Area Burned -^ Crop Area Harvested x Crop Production x
6-28 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Residue/Crop Ratio x Dry Matter Fraction x Burning Efficiency x Combustion Efficiency x Fraction of C or N)
2 where,
3 Area Burned = Total area of crop burned, by state
4 Crop Area Harvested = Total area of crop harvested, by state
5 Crop Production = Annual production of crop in Gg, by state
6 Residue/Crop Ratio = Amount of residue produced per unit of crop production, by state
7 Dry Matter Fraction = Amount of dry matter per unit of biomass for a crop
8 Fraction of C or N = Amount of C or N per unit of dry matter for a crop
9 Burning Efficiency = The proportion of prefire fuel biomass consumed149
10 Combustion Efficiency = The proportion of C or N released with respect to the total amount of C or N
11 available in the burned material, respectively149
12
13 Crop production and area harvested were available by state and year from USD A (2010) for all crops (except rice in
14 Florida and Oklahoma, as detailed below). The amount C or N released was used in the following equation to
15 determine the CH4, CO, N2O and NOX emissions from the field burning of agricultural residues:
16 CH4 and CO, or N2O and NOX Emissions from Field Burning of Agricultural Residues = (C or N Released) x
17 (Emissions Ratio for C or N) x (Conversion Factor)
18 where,
19 Emissions Ratio = g CH4-C or CO-C/g C released, or g N2O-N or NOx-N/g N released
20 Conversion Factor = conversion, by molecular weight ratio, of CH4-C to C (16/12), or CO-C to C (28/12),
21 or N2O-N to N (44/28), or NOX-N to N (30/14)
22
23 [BEGIN BOX]
24
25 Box 6-2: Comparison of Tier 2 U.S. Inventory Approach and IPCC (2006) Default Approach
26
27 This Inventory calculates emissions from Burning of Agricultural Residues using a Tier 2 methodology that is based
28 on rPCC/UNEP/OECD/TEA (1997) and incorporates crop- and country-specific emission factors and variables. The
29 equation used in this Inventory varies slightly in form from the one presented in the IPCC (2006) guidelines, but
30 both equations rely on the same underlying variables. The IPCC (2006) equation was developed to be broadly
31 applicable to all types of biomass burning, and, thus, is not specific to agricultural residues. IPCC (2006) default
32 factors are provided only for four crops (wheat, corn, rice, and sugarcane), while this Inventory analyzes emissions
33 from seven crops. A comparison of the methods and factors used in (1) the current Inventory and (2) the default
34 IPCC (2006) approach was undertaken to determine the magnitude of the difference in overall estimates resulting
35 from the two approaches. The IPCC (2006) approach was not used because crop-specific emission factors for N2O
36 were not available for all crops. In order to maintain consistency of methodology, the IPCC/UNEP/OECD/iEA
37 (1997) approach presented in the Methodology section was used.
38 The IPCC (2006) default approach resulted in 12 percent higher emissions of CH4 and 25 percent higher emissions
39 of N2O than the current estimates in this Inventory. It is reasonable to maintain the current methodology, since the
40 IPCC (2006) defaults are only available for four crops and are worldwide average estimates, while current inventory
41 estimates are based on U.S.-specific, crop-specific, published data.
42
43 [END BOX]
149 In IPCC/UNEP/OECD/IEA (1997), the equation for C or N released contains the variable ' fraction oxidized in burning.'
This variable is equivalent to (burning efficiency x combustion efficiency).
Agriculture 6-29
-------
2 Crop production data for all crops except rice in Florida and Oklahoma were taken from USDA's QuickStats service
3 (USDA 2010). Rice production and area data for Florida and Oklahoma, which are not collected by USD A, were
4 estimated separately. Average primary and ratoon crop yields for Florida (Schueneman and Deren 2002) were
5 applied to Florida acreages (Schueneman 1999, 2001; Deren 2002; Kirstein 2003, 2004; Cantens 2004, 2005;
6 Gonzalez 2007 through 2010), and crop yields for Arkansas (USDA 2010) were applied to Oklahoma acreages150
7 (Lee 2003 through 2006; Anderson 2008 through 2010). The production data for the crop types whose residues are
8 burned are presented in Table 6-22.
9 The fraction of crop area burned was calculated using data on area burned by crop type and state151 from McCarty
10 (2010) for corn, cotton, lentils, rice, soybeans, sugarcane, and wheat.152 McCarty (2010) used remote sensing data
11 from Moderate Resolution Imaging Spectroradiometer (MODIS) to estimate area burned by crop. For the inventory
12 analysis, the state-level area burned data were divided by state-level crop area harvested data to estimate the percent
13 of crop area burned by crop and by state. The average fraction of area burned by crop across all states is shown in
14 Table 6-23. All crop area harvested data were from USDA (2010), except for rice acreage in Florida and Oklahoma,
15 which is not measured by USDA (Schueneman 1999, 2001; Deren 2002; Kirstein 2003, 2004; Cantens 2004, 2005;
16 Gonzalez 2007 through 2010; Lee 2003 through 2006; Anderson 2008 through 2010). Data on crop area burned
17 were only available from McCarty (2010) for the years 2003 through 2007. For other years in the time series, the
18 percent area burned was assumed to be equal to the average percent area burned from the 5 years for which data
19 were available. This average was taken at the crop and state level. Table 6-23 shows these percent area estimates
20 aggregated for the U.S. as a whole, at the crop level.
21 All residue/crop product mass ratios except sugarcane and cotton were obtained from Strehler and Stiitzle (1987).
22 The datum for sugarcane is from Kinoshita (1988) and that of cotton from Huang et al. (2007). The residue/crop
23 ratio for lentils was assumed to be equal to the average of the values for peas and beans. Residue dry matter
24 fractions for all crops except soybeans, lentils, and cotton were obtained from Turn et al. (1997). Soybean and lentil
25 dry matter fractions were obtained from Strehler and Stiitzle (1987); the value for lentil residue was assumed to
26 equal the value for bean straw. The cotton dry matter fraction was taken from Huang et al. (2007). The residue C
27 contents and N contents for all crops except soybeans and cotton are from Turn et al. (1997). The residue C content
28 for soybeans is the IPCC default (IPCC/UNEP/OECD/IEA 1997). The N content of soybeans is from Barnard and
29 Kristoferson(1985). The C and N contents of lentils were assumed to equal those of soybeans. The C and N
30 contents of cotton are from Lachnicht et al. (2004). These data are listed in Table 6-24. The burning efficiency was
31 assumed to be 93 percent, and the combustion efficiency was assumed to be 88 percent, for all crop types, except
32 sugarcane (EPA 1994). For sugarcane, the burning efficiency was assumed to be 81 percent (Kinoshita 1988) and
33 the combustion efficiency was assumed to be 68 percent (Turn et al. 1997). Emission ratios and conversion factors
34 for all gases (see Table 6-25) were taken from the Revised 1996IPCC Guidelines (IPCC/UNEP/OECD/IEA 1997).
35 Table 6-22: Agricultural Crop Production (Gg of Product)
36
37
Crop
Corn3
Cotton
Lentils
Rice
Soybeans
Sugarcane
Wheat
a Corn for grain (i.e.
1990
201,534
3,376
40
7,114
52,416
25,525
74,292
, excludes corn
2000
251,854
3,742
137
8,705
75,055
32,763
60,641
for silage).
2005
282,263
5,201
238
10,132
83,507
24,137
57,243
2006
267,503
4,700
147
8,843
87,001
26,820
49,217
2007
331,177
4,182
166
9,033
72,859
27,188
55,821
2008
307,142
2,790
109
9,272
80,749
25,041
68,016
2009
333,011
2,654
266
9,972
91,417
27,608
60,366
150 Rice production yield data are not available for Oklahoma, so the Arkansas values are used as a proxy.
151 Alaska and Hawaii were excluded.
152 McCarty (2009) also examined emissions from burning of Kentucky bluegrass and a general "other crops/fallow" category,
but USDA crop area and production data were insufficient to estimate emissions from these crops using the methodology
employed in the Inventory. McCarty (2009) estimates that approximately 18 percent of crop residue emissions result from
burning of the Kentucky bluegrass and "other" categories.
6-30 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Table 6-23: U.S. Average Percent Crop Area Burned by Crop (Percent)
2
3
State
Corn
Cotton
Lentils
Rice
Soybeans
Sugarcane
Wheat
+ Less than 0.5 percent
1990
+
1
3
10
+
59
3
2000
+
1
2
10
+
40
3
2005
+
1
+
6
+
26
2
2006
+
1
2
8
+
56
3
2007
+
1
1
12
+
26
3
2008
+
2
1
9
+
39
3
2009
+
1
1
9
+
37
3
Table 6-24: Key Assumptions for Estimating Emissions from Field Burning of Agricultural Residues
Crop Residue/Crop Dry Matter C Fraction N Fraction Burning Combustion
Ratio Fraction Efficiency Efficiency
(Fraction) (Fraction)
10
11
12
13
14
15
16
17
18
19
20
21
5
6
7
8
Corn
Cotton
Lentils
Rice
Soybeans
Sugarcane
Wheat
1.0
1.6
2.0
1.4
2.1
0.2
1.3
Table 6-25: Greenhouse Gas
Gas
CH4:C
CO:C
N2O:N
NOX:N
"Mass of C
b Mass of N
Emission Ratio
0.0053
0.0603
0.007b
0.121b
0.91
0.90
0.85
0.91
0.87
0.62
0.93
Emission Ratios and
Conversion
Factor
16/12
28/12
44/28
30/14
0
0
.448
.445
0.450
0.381
0.450
0.424
0.443
0
0
0
0
0
0
0
.006
.012
.023
.007
.023
.004
.006
0
0
0
0
0
0
0
.93
.93
.93
.93
.93
.81
.93
0.
0.
0.
0.
0.
.88
.88
.88
.88
.88
0.68
0.
.88
Conversion Factors
compound released (units of C) relative to mass of total C released from burning
compound released (
units of N) relative to n
lass of
total N releasei
ii
from burning
(units of C).
(units
of N).
9 Uncertainty and Time-Series Consistency
Due to data and time limitations, uncertainty resulting from the fact that emissions from burning of Kentucky
bluegrass and "other" residues are not included in the emissions estimates was not incorporated into the uncertainty
analysis. The results of the Tier 2 Monte Carlo uncertainty analysis are summarized in Table 6-26. Methane
emissions from field burning of agricultural residues in 2009 were estimated to be between 0.15 and 0.35 Tg CO2
Eq. at a 95 percent confidence level. This indicates a range of 40 percent below and 42 percent above the 2009
emission estimate of 0.25 Tg CO2 Eq. Also at the 95 percent confidence level, N2O emissions were estimated to be
between 0.07 and 0.14 Tg CO2 Eq. (or approximately 30 percent below and 31 percent above the 2009 emission
estimate of 0.10 Tg CO2 Eq.).
Table 6-26: Tier 2 Quantitative Uncertainty Estimates for CH4 and N2O Emissions from Field Burning of
Agricultural Residues (Tg CO2 Eq. and Percent)
Source
Gas 2009 Emission Uncertainty Range Relative to
Estimate Emission Estimate"
(TgC02Eq.) (TgC02Eq.)
Lower
Bound
Field Burning
Field Burning
of Aj
of Aj
picultural
picultural
Residues
Residues
CH4
N2O
0
0
.25
.10
0
0
.15
.07
Upper
Bound
0.35
0.14
Lower
Bound
-40%
-30%
Upper
Bound
+42%
+31%
aRange of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
Methodological recalculations were applied to the entire time series to ensure time-series consistency from 1990
Agriculture 6-31
-------
1 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
2 above.
3 QA/QC and Verification
4 A source-specific QA/QC plan for field burning of agricultural residues was implemented. This effort included a
5 Tier 1 analysis, as well as portions of a Tier 2 analysis. The Tier 2 procedures focused on comparing trends across
6 years, states, and crops to attempt to identify any outliers or inconsistencies. For some crops and years in Florida
7 and Oklahoma, the total area burned as measured by McCarty (2010) was greater than the area estimated for that
8 crop, year, and state by USDA (2010), leading to a percent area burned estimate of greater than 100 percent. In such
9 cases, it was assumed that the percent crop area burned for that state was 100 percent.
10 Recalculations Discussion
11 The methodology over the entire time series was revised relative to the previous Inventory to incorporate state- and
12 crop-level data on area burned from McCarty (2010). (1) Cotton and lentils were added as crops; peanuts and barley
13 were removed, because McCarty (2009) indicated that their residues are not burned in significant quantities in the
14 United States; (2) fraction of residue burned was calculated at the state and crop level based on McCarty (2010) and
15 USDA (2010) data, rather than a blanket application of 3 percent burned for all crops except rice and sugarcane, as
16 was used in the previous Inventory; (3) since data from McCarty (2010) were only available for 5 years, the percent
17 area burned for those 5 years was averaged by crop and state and used as an estimate for the remaining years in the
18 time series. Because the percent area burned was lower than previously assumed for almost all crops, these
19 recalculations have resulted in an average decrease in CH4 emissions of 71 percent and an average decrease in N2O
20 emissions of 79 percent across the time series, relative to the previous Inventory.
21 Planned Improvements
22 Further investigation will be made into inconsistent data from Florida and Oklahoma as mentioned in the QA/QC
23 and verification section, and attempts will be made to revise or further justify the assumption of 100 percent of area
24 burned for those crops and years where the estimated percent area burned exceeded 100 percent. The availability of
25 useable area harvested and other data for bluegrass and the "other crops" category in McCarty (2010) will also be
26 investigated, in order to try to incorporate these emissions into the Inventory.
6-32 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Agricultural Soil Management
Enteric Fermentation
Manure Management
Rice Cultivation I
Field Burning of Agricultural Residues < 0.5
Agriculture as a Portion of all
Emissions
6.3%
o
0 50 100 150
TgCO2Eq.
Figure 6-1: 2009 Agriculture Chapter Greenhouse Gas Sources
200
250
-------
Figure 6-2
Sources and Pathways of N that Result in N20 Emissions from Agricultural Soil Management
Synthetic N Fertilizers
Synthetic N fertilizer applied to soil
Organic
Amendments
Includes both commercial and
non-co,mmercisl fertilizers (i.e.,
animal manure,compost,
sewage sludge, tankage, etc.
N Volatilization
and Deposition
Urine and Dunq from
Grazing Animals
Manure deposited on pasture, range,
and paddock
Includes above- and belowground
residues for a II crops (non-N and N-
fixing (and from perennial forage
crops and pastures following renewa
Mineralization of
Soil Organic Matter
Includes N converted to mineral form
upon decomposition of soil organic
Asymbiotic Fixation
Fixation of atmospheric N2 by bacteria
living in soils that do not have a direct
relationship with plants
This graphic illustrates the sources and pathways of nitrogen that result
in direct and indirect N20 emissions from soils using the methodologies
described in this Inventory. Emission pathways are 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.
-------
Figure 6-3
Major Crops, Average Annual Direct N20 Emissions Estimated Using the DAYCENT Model, 1990-2009
(Tg C02 Eq/year)
-------
Figure 6-4
Grasslands, Average Annual Direct N20 Emissions Estimated Using the DAYCENT Model, 1990-2009
(Tg C02 Eq./year)
Tg C02 Eq./year
H < 0.25
Zl 0.25 to 0.5
H 0.5 to 0.75
Zl 0.75 to 1
• 1to2
|2 to 4
• >4
-------
Figure 6-5
Major Crops, Average Annual N Losses Leading to Indirect N20 Emissions
Using the DAYCENT Model, 1990-2009 (Gg N/year)
-------
Figure 6-6
Grasslands, Average Annual N Losses Leading to Indirect N20 Emissions
Using the DAYCENT Model, 1990-2009 (Gg N/year)
-------
Figure 6-7
Comparison of Measured Emissions at Field Sites with Modeled Emissions
Using the DAYCENT Simulation Model
CO
T3
O)
O
40
35
30
25
20
15
10
5
0
D measured
DAYCENT
• IPCC
0°
0°
-------
2 7. Land Use, Land-Use Change, and Forestry
3 This chapter provides an assessment of the net greenhouse gas flux153 resulting from the uses and changes in land
4 types and forests in the United States. The Intergovernmental Panel on Climate Change 2006 Guidelines for
5 National Greenhouse Gas Inventories (IPCC 2006) recommends reporting fluxes according to changes within and
6 conversions between certain land-use types termed forest land, cropland, grassland, and settlements (as well as
7 wetlands). The greenhouse gas flux from Forest Land Remaining Forest Land is reported using estimates of
8 changes in forest carbon (C) stocks, non-carbon dioxide (CO2) emissions from forest fires, and the application of
9 synthetic fertilizers to forest soils. The greenhouse gas flux reported in this chapter from agricultural lands (i.e.,
10 cropland and grassland) includes changes in organic C stocks in mineral and organic soils due to land use and
11 management, and emissions of CO2 due to the application of crushed limestone and dolomite to managed land (i.e.,
12 soil liming) and urea fertilization. Fluxes are reported for four agricultural land use/land-use change categories:
13 Cropland Remaining Cropland, Land Converted to Cropland, Grassland Remaining Grassland, and Land
14 Converted to Grassland. Fluxes resulting from Settlements Remaining Settlements include those from urban trees
15 and soil fertilization. Landfilled yard trimmings and food scraps are accounted for separately under Other.
16 The estimates in this chapter, with the exception of CO2 fluxes from wood products and urban trees, and CO2
17 emissions from liming and urea fertilization, are based on activity data collected at multiple-year intervals, which
18 are in the form of forest, land-use, and municipal solid waste surveys. CO2 fluxes from forest C stocks (except the
19 wood product components) and from agricultural soils (except the liming component) are calculated on an average
20 annual basis from data collected in intervals ranging from 1 to 10 years. The resulting annual averages are applied
21 to years between surveys. Calculations of non-CO2 emissions from forest fires are based on forest CO2 flux data.
22 For the landfilled yard trimmings and food scraps source, periodic solid waste survey data were interpolated so that
23 annual storage estimates could be derived. This flux has been applied to the entire time series, and periodic U.S.
24 census data on changes in urban area have been used to develop annual estimates of CO2 flux.
25 Land use, land-use change, and forestry activities in 2009 resulted in a net C sequestration of 1015.1 Tg CO2 Eq.
26 (276.8 Tg C) (Table 7-1 and Table 7-2). This represents an offset of approximately 18.4 percent of total U.S. CO2
27 emissions. Total land use, land-use change, and forestry net C sequestration154 increased by approximately 17.8
28 percent between 1990 and 2009. This increase was primarily due to an increase in the rate of net C accumulation in
29 forest C stocks. Net C accumulation in Forest Land Remaining Forest Land, Land Converted to Grassland, and
30 Settlements Remaining Settlements increased, while net C accumulation in Cropland Remaining Cropland,
31 Grassland Remaining Grassland, and landfilled yard trimmings and food scraps slowed over this period. Emissions
32 from Land Converted to Cropland increased between 1990 and 2009.
33 Table 7-1: Net CO2 Flux from Carbon Stock Changes in Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.)
Sink Category
Forest Land Remaining Forest
Land1
Cropland Remaining Cropland
Land Converted to Cropland
Grassland Remaining
Grassland
Land Converted to Grassland
Settlements Remaining
Settlements2
Other (Landfilled Yard
Trimmings and Food Scraps)
1990
(681.1)
(29.4)
2.2
(52.2)
(19.8)
(57.1)
(24.2)
2000
(378.3)
(30.2)
2.4
(52.6)
(27.2)
(77.5)
(13.2)
2005
(911.5)
(18.3)
5.9
(8.9)
(24.4)
(87.8)
(11.5)
2006
(917.5)
(19.1)
5.9
(8.8)
(24.2)
(89.8)
(11.0)
2007
(911.9)
(19.7)
5.9
(8.6)
(24.0)
(91.9)
(10.9)
2008
(891.0)
(18.1)
5.9
(8.5)
(23.8)
(93.9)
(11.2)
2009
(863.1)
(17.4)
5.9
(8.3)
(23.6)
(95.9)
(12.6)
153 The term "flux" is used here to encompass both emissions of greenhouse gases to the atmosphere, and removal of C from the
atmosphere. Removal of C from the atmosphere is also referred to as "carbon sequestration."
154 Carbon sequestration estimates are net figures. The C stock in a given pool fluctuates due to both gains and losses. When
losses exceed gains, the C stock decreases, and the pool acts as a source. When gains exceed losses, the C stock increases, and
the pool acts as a sink. This is also referred to as net C sequestration.
Land Use, Land Use Change, and Forestry 7-1
-------
Total (861.5) (576.6) (1,056.5) (1,064.3) (1,060.9) (1,040.5) (1,015.1)
1 Note: Parentheses indicate net sequestration. Totals may not sum due to independent rounding.
2 ' Estimates include C stock changes on both Forest Land Remaining Forest Land and Land Converted to Forest Land.
3 2 Estimates include C stock changes on both Settlements Remaining Settlements and Land Converted to Settlements.
4
5 Table 7-2: Net CO2 Flux from Carbon Stock Changes in Land Use, Land-Use Change, and Forestry (Tg C)
Sink Category 1990 2000 2005 2006 2007 2008 2009
Forest Land Remaining Forest
Land1 (185.7)
Cropland Remaining Cropland (8.0)
Land Converted to Cropland 0.6
Grassland Remaining
Grassland (14.2)
Land Converted to Grassland (5.4)
Settlements Remaining
Settlements2 (15.6)
Other (Landfilled Yard
Trimmings and Food Scraps) (6.6)
Total (235.0)
(103.2)
(8.2)
0.6
(14.3)
(7.4)
(21.1)
(3.6)
(157.3)
(248.6) (250.2) (248.7) (243.0) (235.4)
(5.0) (5.2) (5.4) (4.9) (4.7)
1.6 1.6 1.6 1.6 1.6
(2.4) (2.4) (2.3) (2.3) (2.3)
(6.7) (6.6) (6.5) (6.5) (6.4)
(23.9) (24.5) (25.1) (25.6) (26.2)
(3.1) (3.0) (3.0) (3.1) (3.4)
(288.1) (290.3) (289.3) (283.8) (276.8)
6 Note: 1 Tg C = 1 teragram C = 1 million metric tons C. Parentheses indicate net sequestration. Totals may not sum due to
7 independent rounding.
8 ' Estimates include C stock changes on both Forest Land Remaining Forest Land and Land Converted to Forest Land.
9 2 Estimates include C stock changes on both Settlements Remaining Settlements and Land Converted to Settlements.
10
11 Emissions from Land Use, Land-Use Change, and Forestry are shown in Table 7-3 and Table 7-4. Liming of
12 agricultural soils and urea fertilization in 2009 resulted in CO2 emissions of 4.2 Tg CO2 Eq. (4,221 Gg) and 3.6 Tg
13 CO2Eq. (3,612 Gg), respectively. Lands undergoing peat extraction (i.e., Peatlands Remaining Peatlands) resulted
14 in CO2 emissions of 1.1 Tg CO2 Eq. (1,090 Gg), and nitrous oxide (N2O) emissions of less than 0.05 Tg CO2 Eq.
15 The application of synthetic fertilizers to forest soils in 2009 resulted in direct N2O emissions of 0.4 Tg CO2 Eq. (1
16 Gg). Direct N2O emissions from fertilizer application to forest soils have increased by 455 percent since 1990, but
17 still account for a relatively small portion of overall emissions. Additionally, direct N2O emissions from fertilizer
18 application to settlement soils in 2009 accounted for 1.5 Tg CO2 Eq. (5 Gg) in 2009. This represents an increase of
19 55 percent since 1990. Forest fires in 2009 resulted in methane (CH4) emissions of 7.8 Tg CO2 Eq. (372 Gg), and in
20 N2O emissions of 6.4 Tg CO2 Eq. (21 Gg).
21 Table 7-3: Emissions from Land Use, Land-Use Change, and Forestry (Tg CO2 Eq.)
Source Category 1990 2000 2005 2006 2007 2008 2009
CO2 8.1 8.8 8.9 8.8 9.2 9.6 8.9
Cropland Remaining Cropland:
Liming of Agricultural Soils 4.7 4.3 4.3 4.2 4.5 5.0 4.2
Urea Fertilization 2.4 3.2 3.5 3.7 3.7 3.6 3.6
Wetlands Remaining Wetlands:
Peatlands Remaining Peatlands 1.0 1.2 1.1 0.9 1.0 1.0 1.1
CH4 3.2 14.3 9.8 21.6 20.0 11.9 7.8
Forest Land Remaining Forest
Land: Forest Fires 3.2 14.3 9.8 21.6 20.0 11.9 7.8
N2O 3.7 13.2 9.8 19.5 18.3 11.6 8.3
Forest Land Remaining Forest
Land: Forest Fires 2.6 11.7 8.0 17.6 16.3 9.8 6.4
Forest Land Remaining Forest
Land: Forest Soils1 0.1 0.4 0.4 0.4 0.4 0.4 0.4
Settlements Remaining
Settlements: Settlement Soils2 1.0 1.1 1.5 1.5 1.6 1.5 1.5
Wetlands Remaining Wetlands:
Peatlands Remaining Peatlands + + + + + + +
Total 15.0 36.3 28.6 49.8 47.5 33.2 25.0
7-2 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 + Less than 0.05 Tg CO2 Eq.
2 Note: These estimates include direct emissions only. Indirect N2O emissions are reported in the Agriculture chapter. Totals may
3 not sum due to independent rounding.
4 ' Estimates include emissions from N fertilizer additions on both Forest Land Remaining Forest Land, and Land Converted to
5 Forest Land, but not from land-use conversion.
6 2 Estimates include emissions from N fertilizer additions on both Settlements Remaining Settlements, and Land Converted to
7 Settlements, but not from land-use conversion.
8
9 Table 7-4: Emissions from Land Use, Land-Use Change, and Forestry (Gg)
Source Category
CO2
Cropland Remaining Cropland:
Liming of Agricultural Soils
Urea Fertilization
Wetlands Remaining Wetlands:
Peatlands Remaining Peatlands
CH4
Forest Land Remaining Forest
Land: Forest Fires
N2O
Forest Land Remaining Forest
Land: Forest Fires
Forest Land Remaining Forest
Land: Forest Soils1
Settlements Remaining
Settlements: Settlement Soils2
Wetlands Remaining Wetlands:
Peatlands Remaining Peatlands
1990
8,117
4,667
2,417
1,033
152
152
12
8
+
3
+
2000
8,768
4,328
3,214
1,227
682
682
43
38
1
4
+
2005
8,933
4,349
3,504
1,079
467
467
32
26
1
5
0
2006
8,754
4,220
3,656
879
1,027
1,027
63
57
1
5
0
2007
9,214
4,464
3,738
1,012
953
953
59
53
1
5
0
2008
9,646
5,042
3,612
992
569
569
37
31
1
5
0
2009
8,922
4,221
3,612
1,090
372
372
27
21
1
5
0
10 +Lessthan0.5Gg
11 Note: These estimates include direct emissions only. Indirect N2O emissions are reported in the Agriculture chapter. Totals may
12 not sum due to independent rounding.
13 ' Estimates include emissions from N fertilizer additions on both Forest Land Remaining Forest Land, and Land Converted to
14 Forest Land, but not from land-use conversion.
15 2 Estimates include emissions from N fertilizer additions on both Settlements Remaining Settlements, and Land Converted to
16 Settlements, but not from land-use conversion.
17 [BEGIN BOX]
18 Box 7-1: Methodological approach for estimating and reporting U.S. emissions and sinks
19
20 In following the UNFCCC requirement under Article 4.1 to develop and submit national greenhouse gas emissions
21 inventories, the emissions and sinks presented in this report are organized by source and sink categories and
22 calculated using internationally-accepted methods provided by the Intergovernmental Panel on Climate Change
23 (IPCC) (http://www.ipcc-nggip.iges.or.jp/public/index.html'). Additionally, the calculated emissions and sinks in a
24 given year for the U. S. are presented in a common manner in line with the UNFCCC reporting guidelines for the
25 reporting of inventories under this international agreement
26 (http://unfccc.int/national reports/annex ighg inventories/national inventories submissions/items/5270.phpX The
27 use of consistent methods to calculate emissions and sinks by all nations providing their inventories to the UNFCCC
28 ensures that these reports are comparable. In this regard, U.S. emissions and sinks reported in this inventory report
29 are comparable to emissions and sinks reported by other countries. Emissions and sinks provided in this inventory
30 do not preclude alternative examinations, but rather this inventory report presents emissions and sinks in a common
31 format consistent with how countries are to report inventories under the UNFCCC. The report itself follows this
32 standardized format, and provides an explanation of the IPCC methods used to calculate emissions and sinks, and
33 the manner in which those calculations are conducted.
34
35 [END BOX]
Land Use, Land Use Change, and Forestry 7-3
-------
2 7.1. Representation of the U.S. Land Base
3 A national land-use categorization system that is consistent and complete both temporally and spatially is needed in
4 order to assess land use and land-use change status and the associated greenhouse gas fluxes over the inventory time
5 series. This system should be consistent with IPCC (2006), such that all countries reporting on national greenhouse
6 gas fluxes to the UNFCCC should (1) describe the methods and definitions used to determine areas of managed and
7 unmanaged lands in the country, (2) describe and apply a consistent set of definitions for land-use categories over
8 the entire national land base and time series associated with the greenhouse gas inventory, such that increases in the
9 land areas within particular land-use categories are balanced by decreases in the land areas of other categories, and
10 (3) account for greenhouse gas fluxes on all managed lands. The implementation of such a system helps to ensure
11 that estimates of greenhouse gas fluxes are as accurate as possible. This section of the Inventory has been developed
12 in order to comply with this guidance.
13 Multiple databases are used to track land management in the United States, which are also used as the basis to
14 classify U.S. land area into the six IPCC land-use categories (i.e., Forest Land Remaining Forest Land, Cropland
15 Remaining Cropland, Grassland Remaining Grassland, Wetlands Remaining Wetlands, Settlements Remaining
16 Settlements and Other Land Remaining Other Land) and thirty land-use change categories (e.g., Cropland
17 Converted to Forest Land, Grassland Converted to Forest Land, Wetlands Converted to Forest Land, Settlements
18 Converted to Forest Land, Other Land Converted to Forest Zawcfe)155 (IPCC 2006). The primary databases are the
19 U.S. Department of Agriculture (USDA) National Resources Inventory (NRI)156 and the USDA Forest Service
20 (USFS) Forest Inventory and Analysis (FIA)157 Database. The U.S. Geological Survey (USGS) National Land
21 Cover Dataset (NLCD)158 is also used to identify land uses in regions that were not included in the NRI or FIA. The
22 total land area included in the U.S. Inventory is 786 million hectares, and this entire land base is considered
23 managed. *59 In 2009, the United States had a total of 274 million hectares of Forest Land (a 4 percent increase
24 since 1990), 163 million hectares of Cropland (down 4.4 percent since 1990), 258 million hectares of Grassland
25 (down 4.2 percent since 1990), 26 million hectares of Wetlands (down 4.9 percent since 1990), 49 million hectares
26 of Settlements (up 24.5 percent since 1990), and 14 million hectares of Other Land. It is important to note that the
27 land base formally classified for the Inventory (see Table 7-5) is considered managed. Alaska is not formally
28 included in the current land representation, but there is a planned improvement underway to include this portion of
29 the United States in future inventories. In addition, wetlands are not differentiated between managed and
30 unmanaged, although some wetlands would be unmanaged according to the U.S. definition (see definition later in
31 this section). Future improvements will include a differentiation between managed and unmanaged wetlands. In
32 addition, carbon stock changes are not currently estimated for the entire land base, which leads to discrepancies
33 between the area data presented here and in the subsequent sections of the NIR. Planned improvements are
34 underway or in development phases to conduct an inventory of carbon stock changes on all managed land (e.g.,
35 federal grasslands).
36 Dominant land uses vary by region, largely due to climate patterns, soil types, geology, proximity to coastal regions,
37 and historical settlement patterns, although all land-uses occur within each of the fifty states (Figure 7-1). Forest
38 Land tends to be more common in the eastern states, mountainous regions of the western United States, and Alaska.
39 Cropland is concentrated in the mid-continent region of the United States, and Grassland is more common in the
40 western United States. Wetlands are fairly ubiquitous throughout the United States, though they are more common
41 in the upper Midwest and eastern portions of the country. Settlements are more concentrated along the coastal
42 margins and in the eastern states.
43 Table 7-5: Size of Land Use and Land-Use Change Categories on Managed Land Area by Land Use and Land Use
44 Change Categories (thousands of hectares)
155 Land-use category definitions are provided in the Methodology section.
156 NRI data is available at .
157 FIA data is available at .
158 NLCD data is available at .
159 The current land representation does not include areas from Alaska or U.S. territories, but there are planned improvements to
include these regions in future reports.
7-4 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Land Use & Land-
Use Change
Categories"
Total Forest Land
FF
CF
GF
WF
SF
OF
Total Cropland
CC
FC
GC
we
sc
oc
Total Grassland
GG
FG
CG
WG
SG
OG
Total Wetlands
WW
FW
CW
GW
SW
OW
Total Settlements
SS
FS
cs
GS
ws
OS
Total Other Land
OO
FO
CO
GO
WO
so
Grand Total
1990
263,878
257,180
1,266
4,879
63
101
389
170,632
155,433
1,105
13,298
163
470
162
269,643
260,064
1,463
7,502
230
129
255
27,788
27,179
138
134
286
<1
51
39,518
34,742
1,842
1,373
1,498
3
60
14,385
13,397
193
279
458
55
3
785,845
2000
268,790
253,080
2,793
11,347
201
268
1,102
164,401
144,004
1,101
17,834
264
886
311
263,092
245,460
3,048
13,303
373
255
653
27,560
26,155
378
348
633
o
J
43
47,558
34,055
5,480
3,599
4,183
29
212
14,443
12,286
506
440
1,085
115
11
785,845
2005
271,322
255,444
2,976
11,122
205
303
1,273
163,192
145,531
805
15,513
234
825
283
260,565
243,839
2,787
12,632
339
255
714
27,173
25,701
401
351
675
o
J
43
49,247
34,975
5,872
3,673
4,479
32
217
14,346
12,104
559
499
1,058
114
12
785,845
2006
272,107
256,181
2,983
11,157
205
304
1,276
163,178
145,518
804
15,513
234
825
283
260,012
243,395
2,773
12,541
338
253
712
26,983
25,519
398
348
672
3
42
49,238
34,966
5,872
3,672
4,479
32
217
14,327
12,087
559
499
1,057
114
12
785,845
2007
272,891
256,917
2,991
11,193
206
305
1,279
163,164
145,506
803
15,513
234
825
283
259,458
242,951
2,759
12,451
338
252
709
26,793
25,338
395
344
670
o
J
42
49,229
34,958
5,872
3,672
4,479
32
217
14,309
12,069
559
499
1,057
114
12
785,845
2008
273,677
257,655
2,998
11,229
207
306
1,282
163,151
145,493
802
15,512
234
825
283
258,904
242,506
2,745
12,360
337
250
706
26,603
25,157
393
341
668
o
J
42
49,220
34,949
5,871
3,672
4,479
32
217
14,290
12,051
559
499
1,056
114
12
785,845
2009
274,462
258,392
3,006
11,264
207
307
1,285
163,137
145,481
802
15,512
234
825
283
258,350
242,061
2,730
12,270
336
249
704
26,412
24,976
390
338
665
3
42
49,212
34,941
5,871
3,672
4,479
32
217
14,272
12,033
559
499
1,056
113
12
785,845
1 aThe abbreviations are "F" for Forest Land, "C" for Cropland, "G" for Grassland, "W" for Wetlands, "S" for Settlements, and
2 "O" for Other Lands. Lands remaining in the same land use category are identified with the land use abbreviation given twice
3 (e-g-, "FF" is Forest Land Remaining Forest Land), and land use change categories are identified with the previous land use
4 abbreviation followed by the new land use abbreviation (e.g., "CF" is Cropland Converted to Forest Land).
5 Notes: All land areas reported in this table are considered managed. A planned improvement is underway to deal with an
6 exception for wetlands which includes both managed and unmanaged lands based on the definitions for the current U.S. Land
7 Representation Assessment. In addition, U. S. Territories have not been classified into land uses and are not included in the U. S.
8 Land Representation Assessment. See Planned Improvements for discussion on plans to include Alaska and territories in future
9 Inventories.
10 Figure 7-1. Percent of Total Land Area in the General Land-Use Categories for 2009
Land Use, Land Use Change, and Forestry 7-5
-------
i Methodology
2 IPCC Approaches for Representing Land Areas
3 IPCC (2006) describes three approaches for representing land areas. Approach 1 provides data on the total area for
4 each individual land-use category, but does not provide detailed information on changes of area between categories
5 and is not spatially explicit other than at the national or regional level. With Approach 1, total net conversions
6 between categories can be detected, but not the individual changes between the land-use categories that led to those
7 net changes. Approach 2 introduces tracking of individual land-use changes between the categories (e.g., Forest
8 Land to Cropland, Cropland to Forest Land, Grassland to Cropland, etc.), using surveys or other forms of data that
9 do not provide location data on specific parcels of land. Approach 3 extends Approach 2 by providing location data
10 on specific parcels of land, such as maps, along with the land-use history. The three approaches are not presented as
11 hierarchical tiers and are not mutually exclusive.
12 According to IPCC (2006), the approach or mix of approaches selected by an inventory agency should reflect
13 calculation needs and national circumstances. For this analysis, the NRI, FIA, and the NLCD have been combined
14 to provide a complete representation of land use for managed lands. These data sources are described in more detail
15 later in this section. All of these datasets have a spatially-explicit time series of land-use data, and therefore
16 Approach 3 is used to provide a full representation of land use in the U.S. Inventory. Lands are treated as remaining
17 in the same category (e.g., Cropland Remaining Cropland) if a land-use change has not occurred in the last 20 years.
18 Otherwise, the land is classified in a land-use-change category based on the current use and most recent use before
19 conversion to the current use (e.g., Cropland Converted to Forest Land).
20 Definitions of Land Use in the United States
21 Managed and Unmanaged Land
22 The U.S. definitions of managed and unmanaged lands are similar to the basic IPCC (2006) definition of managed
23 land, but with some additional elaboration to reflect national circumstances. Based on the following definitions,
24 most lands in the United States are classified as managed:
25 • Managed Land: Land is considered managed if direct human intervention has influenced its condition.
26 Direct intervention includes altering or maintaining the condition of the land to produce commercial or
27 non-commercial products or services; to serve as transportation corridors or locations for buildings,
28 landfills, or other developed areas for commercial or non-commercial purposes; to extract resources or
29 facilitate acquisition of resources; or to provide social functions for personal, community or societal
30 objectives. Managed land also includes legal protection of lands (e.g., wilderness, preserves, parks, etc.)
31 for conservation purposes (i.e., meets societal objectives).160
32 • Unmanaged Land: All other land is considered unmanaged. Unmanaged land is largely comprised of areas
33 inaccessible to human intervention due to the remoteness of the locations, or lands with essentially no
34 development interest or protection due to limited personal, commercial or social value. Though these lands
35 may be influenced indirectly by human actions such as atmospheric deposition of chemical species
36 produced in industry, they are not influenced by a direct human intervention.161
37 Land-Use Categories
38 As with the definition of managed lands, IPCC (2006) provides general non-prescriptive definitions for the six main
160 Wetlands are an exception to this general definition, because these lands, as specified by IPCC (2006), are only considered
managed if they are created through human activity, such as dam construction, or the water level is artificially altered by human
activity. Distinguishing between managed and unmanaged wetlands is difficult, however, due to limited data availability.
Wetlands are not characterized by use within the NRI. Therefore, unless wetlands are managed for cropland or grassland, it is
not possible to know if they are artificially created or if the water table is managed based on the use of NRI data. See the Planned
Improvements section of the Inventory for work being done to refine the Wetland area estimates.
161 There will be some areas that qualify as Forest Land or Grassland according to the land use criteria, but are classified as
unmanaged land due to the remoteness of their location.
7-6 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 land-use categories: Forest Land, Cropland, Grassland, Wetlands, Settlements and Other Land. In order to reflect
2 U.S. circumstances, country-specific definitions have been developed, based predominantly on criteria used in the
3 land-use surveys for the United States. Specifically, the definition of Forest Land is based on the FIA definition of
4 forest,162 while definitions of Cropland, Grassland, and Settlements are based on the NRI.163 The definitions for
5 Other Land and Wetlands are based on the IPCC (2006) definitions for these categories.
6 • Forest Land: A land-use category that includes areas at least 36.6m wide and 0.4 ha in size with at least 10
7 percent cover (or equivalent stocking) by live trees of any size, including land that formerly had such tree
8 cover and that will be naturally or artificially regenerated. Forest land includes transition zones, such as
9 areas between forest and non-forest lands that have at least 10 percent cover (or equivalent stocking) with
10 live trees and forest areas adjacent to urban and built-up lands. Roadside, streamside, and shelterbelt strips
11 of trees must have a crown width of at least 36.6m and continuous length of at least 110.6 m to qualify as
12 forest land. Unimproved roads and trails, streams, and clearings in forest areas are classified as forest if
13 they are less than 36.6 m wide or 0.4 ha in size, otherwise they are excluded from Forest Land and
14 classified as Settlements. Tree-covered areas in agricultural production settings, such as fruit orchards, or
15 tree-covered areas in urban settings, such as city parks, are not considered forest land (Smith et al. 2009).
16 NOTE: This definition applies to all U.S. lands and territories. However, at this time, data availability is
17 limited for remote or inaccessible areas such as interior Alaska
18 • Cropland: A land-use category that includes areas used for the production of adapted crops for harvest; this
19 category includes both cultivated and non-cultivated lands.164 Cultivated crops include row crops or close-
20 grown crops and also hay or pasture in rotation with cultivated crops. Non-cultivated cropland includes
21 continuous hay, perennial crops (e.g., orchards) and horticultural cropland. Cropland also includes land
22 with alley cropping and windbreaks,165 as well as lands in temporary fallow or enrolled in conservation
23 reserve programs (i.e., set-asides166). Roads through Cropland, including interstate highways, state
24 highways, other paved roads, gravel roads, dirt roads, and railroads are excluded from Cropland area
25 estimates and are, instead, classified as Settlements.
26 • Grassland: A land-use category on which the plant cover is composed principally of grasses, grass-like
27 plants, forbs, or shrubs suitable for grazing and browsing, and includes both pastures and native
28 rangelands.167 This includes areas where practices such as clearing, burning, chaining, and/or chemicals are
29 applied to maintain the grass vegetation. Savannas, some wetlands and deserts, in addition to tundra are
30 considered Grassland.168 Woody plant communities of low forbs and shrubs, such as mesquite, chaparral,
31 mountain shrub, and pinyon-juniper, are also classified as Grassland if they do not meet the criteria for
32 Forest Land. Grassland includes land managed with agroforestry practices such as silvipasture and
33 windbreaks, assuming the stand or woodlot does not meet the criteria for Forest Land. Roads through
34 Grassland, including interstate highways, state highways, other paved roads, gravel roads, dirt roads, and
35 railroads are excluded from Grassland area estimates and are, instead, classified as Settlements.
36 • Wetlands: A land-use category that includes land covered or saturated by water for all or part of the year.
37 Managed Wetlands are those where the water level is artificially changed, or were created by human
38 activity. Certain areas that fall under the managed Wetlands definition are covered in other areas of the
39 IPCC guidance and/or the inventory, including Cropland (e.g., rice cultivation), Grassland, and Forest Land
162 See .
163 See .
164 A minor portion of Cropland occurs on federal lands, and is not currently included in the C stock change inventory. A
planned improvement is underway to include these areas in future C inventories.
165 Currently, there is no data source to account for biomass C stock change associated with woody plant growth and losses in
alley cropping systems and windbreaks in cropping systems, although these areas are included in the cropland land base.
166 A set-aside is cropland that has been taken out of active cropping and converted to some type of vegetative cover, including,
for example, native grasses or trees.
167 Grasslands on federal lands are included in the managed land base, but C stock changes are not estimated on these lands.
Federal grassland areas have been assumed to have negligible changes in C due to limited land use and management change, but
planned improvements are underway to further investigate this issue and include these areas in future C inventories.
168 (2006) guidelines do not include provisions to separate desert and tundra as land categories.
Land Use, Land Use Change, and Forestry 7-7
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1 (including drained or undrained forested wetlands).
2 • Settlements: A land-use category representing developed areas consisting of units of 0.25 acres (0.1 ha) or
3 more that includes residential, industrial, commercial, and institutional land; construction sites; public
4 administrative sites; railroad yards; cemeteries; airports; golf courses; sanitary landfills; sewage treatment
5 plants; water control structures and spillways; parks within urban and built-up areas; and highways,
6 railroads, and other transportation facilities. Also included are tracts of less than 10 acres (4.05 ha) that may
7 meet the definitions for Forest Land, Cropland, Grassland, or Other Land but are completely surrounded by
8 urban or built-up land, and so are included in the settlement category. Rural transportation corridors
9 located within other land uses (e.g., Forest Land, Cropland) are also included in Settlements.
10 • Other Land: A land-use category that includes bare soil, rock, ice, non-settlement transportation corridors,
11 and all land areas that do not fall into any of the other five land-use categories. It allows the total of
12 identified land areas to match the managed national area.
13 Land-Use Data Sources: Description and Application to U.S. Land Area Classification
14 U.S. Land-Use Data Sources
15 The three main data sources for land area and use data in the United States are the NRI, FIA, and the NLCD. For
16 the Inventory, the NRI is the official source of data on all land uses on non-federal lands (except forest land), and is
17 also used as the resource to determine the total land base for the conterminous United States and Hawaii. The NRI is
18 conducted by the USD A Natural Resources Conservation Service and is designed to assess soil, water, and related
19 environmental resources on non-federal lands. The NRI has a stratified multi-stage sampling design, where primary
20 sample units are stratified on the basis of county and township boundaries defined by the U.S. Public Land Survey
21 (Nusser and Goebel 1997). Within a primary sample unit (typically a 160-acre [64.75 ha] square quarter-section),
22 three sample points are selected according to a restricted randomization procedure. Each point in the survey is
23 assigned an area weight (expansion factor) based on other known areas and land-use information (Nusser and
24 Goebel 1997). The NRI survey utilizes data derived from remote sensing imagery and site visits in order to provide
25 detailed information on land use and management, particularly for croplands and grasslands, and is used as the basis
26 to account for C stock changes in agricultural lands (except federal Grasslands). The NRI survey was conducted
27 every 5 years between 1982 and 1997, but shifted to annualized data collection in 1998. This Inventory incorporates
28 data through 2003 from the NRI.
29 The FIA program, conducted by the USFS, is the official source of data on Forest Land area and management data
30 for the Inventory. FIA engages in a hierarchical system of sampling, with sampling categorized as Phases 1 through
31 3, in which sample points for phases are subsets of the previous phase. Phase 1 refers to collection of remotely -
32 sensed data (either aerial photographs or satellite imagery) primarily to classify land into forest or non-forest and to
33 identify landscape patterns like fragmentation and urbanization. Phase 2 is the collection of field data on a network
34 of ground plots that enable classification and summarization of area, tree, and other attributes associated with forest
35 land uses. Phase 3 plots are a subset of Phase 2 plots where data on indicators of forest health are measured. Data
36 from all three phases are also used to estimate C stock changes for forest land. Historically, FIA inventory surveys
37 had been conducted periodically, with all plots in a state being measured at a frequency of every 5 to 14 years. A
38 new national plot design and annual sampling design was introduced by FIA about ten years ago. Most states,
39 though, have only recently been brought into this system. Annualized sampling means that a portion of plots
40 throughout each state is sampled each year, with the goal of measuring all plots once every 5 years. See Annex 3.12
41 to see the specific survey data available by state. The most recent year of available data varies state by state (2002
42 through 2009).
43 Though NRI provides land-area data for both federal and non-federal lands, it only includes land-use data on non-
44 federal lands, and FIA only records data for forest land.169 Consequently, major gaps exist when the datasets are
45 combined, such as federal grassland operated by the Bureau of Land Management (BLM), USD A, and National
46 Park Service, as well as most of Alaska.170 The NLCD is used as a supplementary database to account for land use
169 FIA does collect some data on non-forest land use, but these are held in regional databases versus the national database. The
status of these data is being investigated.
170 The survey programs also do not include U.S. Territories with the exception of non-federal lands in Puerto Rico, which are
7-8 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 on federal lands that are not included in the NRI and FIA databases. The NLCD land-cover classification scheme,
2 available for 1992 and 2001, has been applied over the conterminous United States (Homer et al. 2007). The 2001
3 product also provides land use data that has been used for Hawaii federal lands. For this analysis, the NLCD
4 Retrofit Land Cover Change Product was used in order to represent both land use and land-use change for federal
5 lands in the conterminous U.S. (Homer et al. 2007). It is based primarily on Landsat Thematic Mapper imagery.
6 The NLCD contains 21 categories of land-cover information, which have been aggregated into the IPCC land-use
7 categories, and the data are available at a spatial resolution of 30 meters. The federal land portion of the NLCD was
8 extracted from the dataset using the federal land area boundary map from the National Atlas (2005). This map
9 represents federal land boundaries in 2005, so as part of the analysis, the federal land area was adjusted annually
10 based on the NPJ federal land area estimates (i.e., land is periodically transferred between federal and non-federal
11 ownership). Consequently, the portion of the land base categorized with NLCD data varied from year to year,
12 corresponding to an increase or decrease in the federal land base. The NLCD is strictly a source of land-cover
13 information, however, and does not provide the necessary site conditions, crop types, and management information
14 from which to estimate C stock changes on those lands.
15 Another step in the analysis is to address gaps as well as overlaps in the representation of the U.S. land base between
16 the Agricultural Carbon Stock Inventory (Cropland Remaining Cropland, Land Converted to Cropland, Grassland
17 Remaining Grassland, Land Converted to Grassland) and Forest Land Carbon Stock Inventory (Forest Land
18 Remaining Forest Land and Land Converted to Forest Land), which are based on the NRI and FIA databases,
19 respectively. NRI and FIA have different criteria for classifying forest land and sampling designs, leading to
20 discrepancies in the resulting estimates of Forest Land area on non-federal land. Similarly, there are discrepancies
21 between the NLCD and FIA data for defining and classifying Forest Land on federal lands. Moreover, dependence
22 exists between the Forest Land area and the amount of land designated as other land uses in both the NRI and the
23 NLCD, such as the amount of Grassland, Cropland, and Wetlands, relative to the Forest Land area. This results in
24 inconsistencies among the three databases for estimated Forest Land area, as well as for the area estimates for other
25 land-use categories. FIA is the main database for forest statistics, and consequently, the NRI and NLCD were
26 adjusted to achieve consistency with FIA estimates of Forest Land. The adjustments were made at a state-scale, and
27 it was assumed that the majority of the discrepancy in forest area was associated with an under- or over-prediction of
28 Grassland and Wetland area in the NRI and NLCD due to differences in Forest Land definitions. Specifically, the
29 Forest Land area for a given state according to the NRI and NLCD was adjusted to match the FIA estimates of
30 Forest Land for non-federal and federal land, respectively. In a second step, corresponding increases or decreases
31 were made in the area estimates of Grassland and Wetland from the NRI and NLCD, in order to balance the change
32 in forest area, and therefore not change the overall amount of managed land within an individual state. The
33 adjustments were based on the proportion of land within each of these land-use categories at the state-level, (i.e., a
34 higher proportion of Grassland led to a larger adjustment in Grassland area).
35 As part of Quality Assurance /Quality Control (QA/QC), the land base derived from the NRI, FIA and NLCD was
36 compared to the Topologically Integrated Geographic Encoding and Referencing (TIGER) survey (U.S. Census
37 Bureau 2010). The U.S. Census Bureau gathers data on the U.S. population and economy, and has a database of
38 land areas for the country. The land area estimates from the U.S. Census Bureau differ from those provided by the
39 land-use surveys used in the Inventory because of discrepancies in the reporting approach for the census and the
40 methods used in the NRI, FIA, and NLCD. The area estimates of land-use categories, based on NRI, FIA, and
41 NLCD, are derived from remote sensing data instead of the land survey approach used by the U.S. Census Survey.
42 More importantly, the U.S. Census Survey does not provide a time series of land-use change data or land
43 management information, which is critical for conducting emission inventories and is provided from the NRI and
44 FIA surveys. Consequently, the U.S. Census Survey was not adopted as the official land area estimate for the
45 Inventory. Rather, the NRI data were adopted because this database provides full coverage of land area and land use
46 for the conterminous United States and Hawaii. Regardless, the total difference between the U.S. Census Survey
47 and the data sources used in the Inventory is about 25 million hectares for the total land base of about 786 million
48 hectares currently included in the Inventory, or a 3.1 percent difference. Much of this difference is associated with
49 open waters in coastal regions and the Great Lakes. NRI does not include as much of the area of open waters in
50 these regions as the U.S. Census Survey.
included in the NRI survey. Furthermore, NLCD does not include coverage for U.S. Territories.
Land Use, Land Use Change, and Forestry 7-9
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1 Approach for Combining Data Sources
2 The managed land base in the United States has been classified into the six IPCC land-use categories using
3 definitions171 developed to meet national circumstances, while adhering to IPCC (2006). In practice, the land was
4 initially classified into a variety of land-use categories using the NRI, FIA and NLCD, and then aggregated into the
5 thirty-six broad land use and land-use-change categories identified in IPCC (2006). Details on the approach used to
6 combine data sources for each land use are described below as are the gaps that will be reconciled as part of ongoing
7 planned improvements:
8 • Forest Land: Both non-federal and federal forest lands in both the continental United States and coastal
9 Alaska are covered by FIA. FIA is used as the basis for both Forest Land area data as well as to estimate C
10 stocks and fluxes on Forest Land. Interior Alaska is not currently surveyed by FIA, but NLCD has a new
11 product for Alaska that will be incorporated into the assessment as a planned improvement for future
12 reports. Forest Lands in U.S. territories are currently excluded from the analysis, but FIA surveys are
13 currently being conducted on U.S. territories and will become available in the future. NRI is being used in
14 the current report to provide Forest Land areas on non-federal lands in Hawaii. Currently, federal forest
15 land in Hawaii is evaluated with the 2001 NLCD, but FIA data will be collected in Hawaii in the future.
16 • Cropland: Cropland is classified using the NRI, which covers all non-federal lands within 49 states
17 (excluding Alaska), including state and local government-owned land as well as tribal lands. NRI is used
18 as the basis for both Cropland area data as well as to estimate C stocks and fluxes on Cropland. Croplands
19 in U.S. territories are excluded from both NRI data collection and the NLCD. NLCD has a new product for
20 Alaska that will be incorporated into the assessment as a planned improvement for future reports.
21 • Grassland: Grassland on non-federal lands is classified using the NRI within 49 states (excluding Alaska),
22 including state and local government-owned land as well as tribal lands. NRI is used as the basis for both
23 Grassland area data as well as to estimate C stocks and fluxes on Grassland. U.S. territories are excluded
24 from both NRI data collection and the current release of the NLCD product. Grassland on federal Bureau
25 of Land Management lands, Department of Defense lands, National Parks and within USFS lands are
26 covered by the NLCD. In addition, federal and non-federal grasslands in Alaska are currently excluded
27 from the analysis, but NLCD has a new product for Alaska that will be incorporated into the assessment for
28 future reports.
29 • Wetlands: NRI captures wetlands on non-federal lands within 49 states (excluding Alaska), while federal
30 wetlands are covered by the NLCD. Alaska and U.S. territories are excluded. This currently includes both
31 managed and unmanaged wetlands as no database has yet been applied to make this distinction. See
32 Planned Improvements for details.
33 • Settlements: The NRI captures non-federal settlement area in 49 states (excluding Alaska). If areas of
34 Forest Land or Grassland under 10 acres (4.05 ha) are contained within settlements or urban areas, they are
35 classified as Settlements (urban) in the NRI database. If these parcels exceed the 10 acre (4.05 ha)
36 threshold and are Grassland, they will be classified as such by NRI. Regardless of size, a forested area is
37 classified as non-forest by FIA if it is located within an urban area. Settlements on federal lands are
38 covered by NLCD. Settlements in U.S. territories are currently excluded from NRI and NLCD. NLCD has
39 a new product for Alaska that will be incorporated into the assessment as a planned improvement for future
40 reports.
41 • Other Land: Any land not falling into the other five land categories and, therefore, categorized as Other
42 Land is classified using the NRI for non-federal areas in the 49 states (excluding Alaska) and NLCD for the
43 federal lands. Other land in U.S. territories is excluded from the NLCD. NLCD has a new product for
44 Alaska that will be incorporated into the assessment as a planned improvement for future reports.
45 Some lands can be classified into one or more categories due to multiple uses that meet the criteria of more than one
46 definition. However, a ranking has been developed for assignment priority in these cases. The ranking process is
47 initiated by distinguishing between managed and unmanaged lands. The managed lands are then assigned, from
48 highest to lowest priority, in the following manner:
171
Definitions are provided in the previous section.
7-10 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Settlements > Cropland > Forest Land > Grassland > Wetlands > Other Land
1 Settlements are given the highest assignment priority because they are extremely heterogeneous with a mosaic of
3 patches that include buildings, infrastructure and travel corridors, but also open grass areas, forest patches, riparian
4 areas, and gardens. The latter examples could be classified as Grassland, Forest Land, Wetlands, and Cropland,
5 respectively, but when located in close proximity to settlement areas they tend to be managed in a unique manner
6 compared to non-settlement areas. Consequently, these areas are assigned to the Settlements land-use category.
7 Cropland is given the second assignment priority, because cropping practices tend to dominate management
8 activities on areas used to produce food, forage or fiber. The consequence of this ranking is that crops in rotation
9 with grass will be classified as Cropland, and land with woody plant cover that is used to produce crops (e.g.,
10 orchards) is classified as Cropland, even though these areas may meet the definitions of Grassland or Forest Land,
11 respectively. Similarly, Wetlands are considered Croplands if they are used for crop production, such as rice or
12 cranberries. Forest Land occurs next in the priority assignment because traditional forestry practices tend to be the
13 focus of the management activity in areas with woody plant cover that are not croplands (e.g., orchards) or
14 settlements (e.g., housing subdivisions with significant tree cover). Grassland occurs next in the ranking, while
15 Wetlands and Other Land complete the list.
16 The assignment priority does not reflect the level of importance for reporting greenhouse gas emissions and
17 removals on managed land, but is intended to classify all areas into a single land use. Currently, the IPCC does not
18 make provisions in the guidelines for assigning land to multiple uses. For example, a Wetland is classified as Forest
19 Land if the area has sufficient tree cover to meet the stocking and stand size requirements. Similarly, Wetlands are
20 classified as Cropland if they are used for crop production, such as rice or cranberries. In either case, emissions
21 from Wetlands are included in the Inventory if human interventions are influencing emissions from Wetlands, in
22 accordance with the guidance provided in IPCC (2006).
23 Recalculations Discussion
24 No major revisions were made to the time series for the current Inventory. However, new data were incorporated
25 from FIA on forestland areas, which was used to make minor adjustments to the time series. FIA conducts a survey
26 of plots annually so that each plot is visited every 5 years (Note: some states have not initiated the annual sampling
27 regime as discussed previously). Consequently, the time series is updated each year as new data are collected over
28 the 5 year cycles.
29 Planned Improvements
30 Area data by land-use category are not estimated for major portions of Alaska or any of the U.S. territories. A key
31 planned improvement is to incorporate land-use data from these areas into the Inventory. For Alaska, a new NLCD
32 2001 data product will be used to cover those land areas presently omitted. Fortunately, most of the managed land
33 in the United States is included in the current land-use statistics, but a complete accounting is a key goal for the near
34 future. Data sources will also be evaluated for representing land use on federal and non-federal lands in U.S.
35 territories.
36 Additional work will be done to reconcile differences in Forest Land estimates between the NRI and FIA, evaluating
37 the assumption that the majority of discrepancies in Forest Land areas are associated with an over- or under-
38 estimation of Grassland and Wetland area. In some regions of the United States, a discrepancy in Forest Land areas
39 between NPJ and FIA may be associated with an over- or under-prediction of other land uses, and an analysis is
40 planned to develop region-specific adjustments.
41 There are also other databases that may need to be reconciled with the NPJ and NLCD datasets, particularly for
42 Settlements and Wetlands. Urban area estimates, used to produce C stock and flux estimates from urban trees, are
43 currently based on population data (1990 and 2000 U.S. Census data). Using the population statistics, "urban
44 clusters" are defined as areas with more than 500 people per square mile. The USFS is currently moving ahead with
45 an urban forest inventory program so that urban forest area estimates will be consistent with FIA forest area
46 estimates outside of urban areas, which would be expected to reduce omissions and overlap of forest area estimates
47 along urban boundary areas.
Land Use, Land Use Change, and Forestry 7-11
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i 7.2. Forest Land Remaining Forest Land
2 Changes in Forest Carbon Stocks (IPCC Source Category 5A1)
3 For estimating C stocks or stock change (flux), C in forest ecosystems can be divided into the following five storage
4 pools (IPCC 2003):
5 • Aboveground biomass, which includes all living biomass above the soil including stem, stump, branches,
6 bark, seeds, and foliage. This category includes live understory.
7 • Belowground biomass, which includes all living biomass of coarse living roots greater than 2 mm diameter.
8 • Dead wood, which includes all non-living woody biomass either standing, lying on the ground (but not
9 including litter), or in the soil.
10 • Litter, which includes the litter, fumic, and humic layers, and all non-living biomass with a diameter less
11 than 7.5 cm at transect intersection, lying on the ground.
12 • Soil organic C (SOC), including all organic material in soil to a depth of 1 meter but excluding the coarse
13 roots of the aboveground pools.
14 In addition, there are two harvested wood pools necessary for estimating C flux:
15 • Harvested wood products (HWP) in use.
16 • HWP in solid waste disposal sites (SWDS).
17 C is continuously cycled among these storage pools and between forest ecosystems and the atmosphere as a result of
18 biological processes in forests (e.g., photosynthesis, respiration, growth, mortality, decomposition, and disturbances
19 such as fires or pest outbreaks) and anthropogenic activities (e.g., harvesting, thinning, clearing, and replanting). As
20 trees photosynthesize and grow, C is removed from the atmosphere and stored in living tree biomass. As trees die
21 and otherwise deposit litter and debris on the forest floor, C is released to the atmosphere or transferred to the soil by
22 organisms that facilitate decomposition.
23 The net change in forest C is not equivalent to the net flux between forests and the atmosphere because timber
24 harvests do not cause an immediate flux of C of all vegetation C to the atmosphere. Instead, harvesting transfers a
25 portion of the C stored in wood to a "product pool." Once in a product pool, the C is emitted over time as CO2 when
26 the wood product combusts or decays. The rate of emission varies considerably among different product pools. For
27 example, if timber is harvested to produce energy, combustion releases C immediately. Conversely, if timber is
28 harvested and used as lumber in a house, it may be many decades or even centuries before the lumber decays and C
29 is released to the atmosphere. If wood products are disposed of in SWDS, the C contained in the wood may be
30 released many years or decades later, or may be stored almost permanently in the SWDS.
31 This section quantifies the net changes in C stocks in the five forest C pools and two harvested wood pools. The net
32 change in stocks for each pool is estimated, and then the changes in stocks are summed over all pools to estimate
33 total net flux. The focus on C implies that all C-based greenhouse gases are included, and the focus on stock change
34 suggests that specific ecosystem fluxes do not need to be separately itemized in this report. Disturbances from forest
35 fires and pest outbreaks are implicitly included in the net changes. For instance, an inventory conducted after fire
36 counts only the trees that are left. The change between inventories thus accounts for the C changes due to fires;
37 however, it may not be possible to attribute the changes to the disturbance specifically. The IPCC (2003)
38 recommends reporting C stocks according to several land-use types and conversions, specifically Forest Land
3 9 Remaining Forest Land and Land Converted to Forest Land. Currently, consistent datasets are just becoming
40 available for the conterminous United States to allow forest land conversions and forest land remaining forest land
41 to be identified, and research is ongoing to properly use that information based on research results. Thus, net
42 changes in all forest-related land, including non-forest land converted to forest and forests converted to non-forest,
43 are reported here.
44 Forest C storage pools, and the flows between them via emissions, sequestration, and transfers, are shown in Figure
45 7-2. In the figure, boxes represent forest C storage pools and arrows represent flows between storage pools or
46 between storage pools and the atmosphere. Note that the boxes are not identical to the storage pools identified in
47 this chapter. The storage pools identified in this chapter have been refined in this graphic to better illustrate the
7-12 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 processes that result in transfers of C from one pool to another, and emissions to as well as uptake from the
2 atmosphere.
3
4 Figure 7-2: Forest Sector Carbon Pools and Flows
5
6 Approximately 33 percent (304 million hectares) of the U.S. land area is forested (Smith et al. 2009). The current
7 forest carbon inventory includes 271 million hectares in the conterminous 48 states (USDA Forest Service 2010a,
8 20 lOb) that are considered managed and are included in this inventory. An additional 6.1 million hectares of
9 southeast and south central Alaskan forest are inventoried and are included here. Three notable differences exist in
10 forest land defined in Smith et al. (2009) and the forest land included in this report, which is based on USDA Forest
11 Service (20 lOb). Survey data are not yet available from Hawaii and a large portion of interior Alaska, but estimates
12 of these areas are included in Smith et al. (2009). Alternately, survey data for west Texas has only recently become
13 available, and these forests contribute to overall carbon stock reported below. While Hawaii and U.S. territories
14 have relatively small areas of forest land and will thus probably not influence the overall C budget substantially,
15 these regions will be added to the C budget as sufficient data become available. Agroforestry systems are also not
16 currently accounted for in the inventory, since they are not explicitly inventoried by either the Forest Inventory and
17 Analysis (FIA) program of the U. S. Department of Agriculture (USDA) Forest Service or the National Resources
18 Inventory (NRI) of the USDA Natural Resources Conservation Service (Perry et al. 2005).
19 Sixty-eight percent of U.S. forests (208 million hectares) are classified as timberland, meaning they meet minimum
20 levels of productivity. Nine percent of Alaska forests overall and 81 percent of forests in the conterminous United
21 States are classified as timberlands. Of the remaining nontimberland forests, 30 million hectares are reserved forest
22 lands (withdrawn by law from management for production of wood products) and 66 million hectares are lower
23 productivity forest lands (Smith et al. 2009). Historically, the timberlands in the conterminous 48 states have been
24 more frequently or intensively surveyed than other forest lands.
25 Forest land area declined by approximately 10 million hectares over the period from the early 1960s to the late
26 1980s. Since then, forest area has increased by about 12 million hectares. Current trends in forest area represent
27 average annual change of less than 0.2 percent. Given the low rate of change in U.S. forest land area, the major
28 influences on the current net C flux from forest land are management activities and the ongoing impacts of previous
29 land-use changes. These activities affect the net flux of C by altering the amount of C stored in forest ecosystems.
30 For example, intensified management of forests that leads to an increased rate of growth increases the eventual
31 biomass density of the forest, thereby increasing the uptake of C.172 Though harvesting forests removes much of the
32 aboveground C, on average the volume of annual net growth nationwide is about 72 percent higher than the volume
33 of annual removals on timberlands (Smith et al. 2009). The reversion of cropland to forest land increases C storage
34 in biomass, forest floor, and soils. The net effects of forest management and the effects of land-use change
35 involving forest land are captured in the estimates of C stocks and fluxes presented in this chapter.
36 In the United States, improved forest management practices, the regeneration of previously cleared forest areas, and
37 timber harvesting and use have resulted in net uptake (i.e., net sequestration) of C each year from 1990 through
38 2009. The rate of forest clearing begun in the 17th century following European settlement had slowed by the late
39 19th century. Through the later part of the 20th century many areas of previously forested land in the United States
40 were allowed to revert to forests or were actively reforested. The impacts of these land-use changes still influence C
41 fluxes from these forest lands. More recently, the 1970s and 1980s saw a resurgence of federally-sponsored forest
42 management programs (e.g., the Forestry Incentive Program) and soil conservation programs (e.g., the Conservation
43 Reserve Program), which have focused on tree planting, improving timber management activities, combating soil
44 erosion, and converting marginal cropland to forests. In addition to forest regeneration and management, forest
45 harvests have also affected net C fluxes. Because most of the timber harvested from U.S. forests is used in wood
46 products, and many discarded wood products are disposed of in SWDS rather than by incineration, significant
47 quantities of C in harvested wood are transferred to long-term storage pools rather than being released rapidly to the
48 atmosphere (Skog and Nicholson 1998, Skog 2008). The size of these long-term C storage pools has increased
172 The term "biomass density" refers to the mass of live vegetation per unit area. It is usually measured on a dry-weight basis.
Dry biomass is 50 percent C by weight.
Land Use, Land Use Change, and Forestry 7-13
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1 during the last century.
2 Changes in C stocks in U.S. forests and harvested wood were estimated to account for net sequestration of 863 Tg
3 CO2Eq. (235 Tg C) in 2009 (Table 7-6, Table 7-7, and Table 7-8). In addition to the net accumulation of C in
4 harvested wood pools, sequestration is a reflection of net forest growth and increasing forest area over this period.
5 Overall, average C in forest ecosystem biomass (aboveground and belowground) increased from 67 to 73 Mg C/ha
6 between 1990 and 2010 (see Annex 3-12 for average C densities by specific regions and forest types). Continuous,
7 regular annual surveys are not available over the period for each state; therefore, estimates for non-survey years
8 were derived by interpolation between known data points. Survey years vary from state to state, and national
9 estimates are a composite of individual state surveys. Therefore, changes in sequestration over the interval 1990 to
10 2009 are the result of the sequences of new inventories for each state. C in forest ecosystem biomass had the
11 greatest effect on total change through increases in C density and total forest land. Management practices that
12 increase C stocks on forest land, as well as afforestation and reforestation efforts, influence the trends of increased C
13 densities in forests and increased forest land in the United States.
14 The decline in net additions to HWP carbon stocks continued though 2009 from the recent high point in 2006. This
15 is due to sharp declines in U.S. production of solidwood and paper products in 2009 primarily due to the decline in
16 housing construction. The low level of gross additions to solidwood and paper products in use in 2009 was exceeded
17 by discards from uses. The result is a net reduction in the amount of HWP carbon that is held in products in use
18 during 2009. For 2009, additions to landfills still exceeded emissions from landfills and the net additions to landfills
19 have remained relatively stable. Overall, there were net carbon additions to HWP in use and in landfills combined
20 in 2009.
21 Table 7-6: Net Annual Changes in C Stocks (Tg CO2/yr) in Forest and Harvested Wood Pools
Carbon Pool 1990 2000 2005 2006 2007 2008 2009
22
23
24
25
26
27
28
Forest (549.3)
Aboveground
Biomass (360.0)
Belowground
Biomass (70.9)
Dead Wood (31.6)
Litter (32.2)
Soil Organic
Carbon (54.7)
Harvested Wood (131.8)
Products in Use (64.8)
SWDS (67.0)
Total Net Flux (681.1)
(265.4) (806.1) (808.9)
(287.0) (447.9) (447.9)
(57.5) (88.4) (88.4)
(12.9) (30.8) (33.5)
27.5 (41.9) (41.9)
64.6 (197.2) (197.2)
(112.9) (105.4) (108.6)
(47.0) (45.4) (45.1)
(65.9) (59.9) (63.4)
(378.3) (911.5) (917.5)
(808.9) (808.9) (808.9)
(447.9) (447.9) (447.9)
(88.4) (88.4) (88.4)
(33.5) (33.5) (33.5)
(41.9) (41.9) (41.9)
(197.2) (197.2) (197.2)
(103.0) (82.1) (54.3)
(39.1) (19.1) 6.8
(63.8) (63.0) (61.1)
(911.9) (891.0) (863.1)
Note: Forest C stocks do not include forest stocks in U.S. territories, Hawaii, a portion of managed forests in Alaska, or trees on
non-forest land (e.g., urban trees, agroforestry systems). Parentheses indicate net C sequestration (i.e., a net removal of C from
the atmosphere). Total net flux is an estimate of the actual net flux between the total forest C
pool and the atmosphere. Forest
area estimates are based on interpolation and extrapolation of inventory data as described in the text and in Annex 3.12.
Harvested wood estimates are based on results from annual surveys and models. Totals may
rounding.
not sum due to independent
29 Table 7-7: Net Annual Changes in C Stocks (Tg C/yr) in Forest and Harvested Wood Pools
Carbon Pool
Forest
Aboveground
Biomass
Belowground
Biomass
Dead Wood
Litter
Soil Organic C
Harvested Wood
Products in Use
1990
(149.8)
(98.2)
(19.3)
(8.6)
(8.8)
(14.9)
(35.9)
(17.7)
2000
(72.4)
(78.3)
(15.7)
(3.5)
7.5
17.6
(30.8)
(12.8)
2005
(219.9)
(122.1)
(24.1)
(8.4)
(11.4)
(53.8)
(28.7)
(12.4)
2006
(220.6)
(122.1)
(24.1)
(9.1)
(11.4)
(53.8)
(29.6)
(12.3)
2007
(220.6)
(122.1)
(24.1)
(9.1)
(11.4)
(53.8)
(28.1)
(10.7)
2008
(220.6)
(122.1)
(24.1)
(9.1)
(11.4)
(53.8)
(22.4)
(5.2)
2009
(220.6)
(122.1)
(24.1)
(9.1)
(11.4)
(53.8)
(14.8)
1.9
7-14 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
SWDS
Total Net Flux
(18.3)
(185.7)
(18.0)
(103.2)
(16.3)
(17.3)
(17.4)
(17.2)
(16.7)
(248.6) (250.2) (248.7) (243.0) (235.4)
1 Note: Forest C stocks do not include forest stocks in U.S. territories, Hawaii, a portion of managed lands in Alaska, or trees on
2 non-forest land (e.g., urban trees, agroforestry systems). Parentheses indicate net C sequestration (i.e., a net removal of C from
3 the atmosphere). Total net flux is an estimate of the actual net flux between the total forest C pool and the atmosphere.
4 Harvested wood estimates are based on results from annual surveys and models. Totals may not sum due to independent
5 rounding.
6
7 Stock estimates for forest and harvested wood C storage pools are presented in Table 7-8. Together, the
8 aboveground live and forest soil pools account for a large proportion of total forest C stocks. C stocks in all non-soil
9 pools increased over time. Therefore, C sequestration was greater than C emissions from forests, as discussed
10 above. Figure 7-4 shows county-average C densities for live trees on forest land, including both above- and
11 belowground biomass.
12 Table 7-8: Forest area (1000 ha) and C Stocks (Tg C) in Forest and Harvested Wood Pools
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Forest Area
(1000 ha)
Carbon Pools
(TgC)
Forest
Aboveground
Biomass
Belowground
Biomass
Dead Wood
Litter
Soil Organic C
Harvested
Wood
Products in Use
SWDS
Total C Stock
1990
269,137
42,783
15,072
2,995
2,960
4,791
16,96
1,859
1,231
628
44,643
2000
274,183
44,108
16,024
3,183
3,031
4,845
17,025
2,187
1,382
805
46,296
2005
276,769
44,886
16,536
3,285
3,060
4,862
17,143
2,325
1,436
890
47,211
2006
277,561
45,105
16,658
3,309
3,068
4,873
17,197
2,354
1,448
906
47,459
2007
278,354
45,326
16,780
3,333
3,077
4,885
17,251
2,383
1,460
923
47,710
2008
279,147
45,547
16,902
3,357
3,086
4,896
17,304
2,412
1,471
941
47,958
2009
279,939
45,767
17,024
3,381
3,096
4,908
17,358
2,434
1,476
958
48,201
2010
280,732
45,988
17,147
3,405
3,105
4,919
17,412
2,449
1,474
974
48,437
Note: Forest area estimates include portions of managed forests in Alaska for which survey data are available. Forest C stocks do
not include forest stocks in U.S. territories, Hawaii, a large portion of Alaska, or trees on non-forest land (e.g., urban trees,
agroforestry systems). Wood product stocks include exports, even if the logs are processed in other countries, and exclude
imports. Forest area estimates are based on interpolation and extrapolation of inventory data as described in Smith et al. (2010)
and in Annex 3.12. Harvested wood estimates are based on results from annual surveys and models. Totals may not sum due to
independent rounding. Inventories are assumed to represent stocks as of January 1 of the inventory year. Flux is the net annual
change in stock. Thus, an estimate of flux for 2006 requires estimates of C stocks for 2006 and 2007.
Figure 7-3: Estimates of Net Annual Changes in C Stocks for Major C Pools
Figure 7-4: Average C Density in the Forest Tree Pool in the Conterminous United States, 2009
[BEGIN BOX]
Box 7-2: CO2 Emissions from Forest Fires
As stated previously, the forest inventory approach implicitly accounts for emissions due to disturbances such as
forest fires, because only C remaining in the forest is estimated. Net C stock change is estimated by subtracting
consecutive C stock estimates. A disturbance removes C from the forest. The inventory data on which net C stock
Land Use, Land Use Change, and Forestry 7-15
-------
1 estimates are based already reflect this C loss. Therefore, estimates of net annual changes in C stocks for U.S.
2 forestland already account for CO2 emissions from forest fires occurring in the lower 48 states as well as in the
3 proportion of Alaska's managed forest land captured in this inventory. Because it is of interest to quantify the
4 magnitude of CO2 emissions from fire disturbance, these estimates are being highlighted here, using the full extent
5 of available data. Non-CO2 greenhouse gas emissions from forest fires are also quantified in a separate section
6 below.
7 The IPCC (2003) methodology and IPCC (2006) default combustion factor for wildfire were employed to estimate
8 CO2 emissions from forest fires. CO2 emissions for wildfires and prescribed fires in the lower 48 states and wildfires
9 in Alaska in 2009 were estimated to be 124.3 Tg CO2/yr. This amount is masked in the estimate of net annual forest
10 carbon stock change for 2009, however, because this net estimate accounts for the amount sequestered minus any
11 emissions.
12 Table 7-9: Estimates of CO2 (Tg/yr) emissions for the lower 48 states and Alaska1
13
14
15
16
CO2 emitted
from Wildfires in
CO2 emitted
from Prescribed
CO2 emitted
Year
1990
2000
2005
2006
2007
2008
2009
Lower 48 States
(Tg/yr)
42.1
225.1
131.0
313.6
284.1
169.0
97.1
Fires in Lower 48 from Wildfires in
States (Tg/yr) Alaska (Tg/yr)
8.5 +
2.1 +
24.8 +
29.3 +
34.0 +
20.8 +
27.3 +
Total CO2
emitted (Tg/yr)
50.7
227.3
155.9
342.9
318.1
189.8
124.3
+ Does not exceed 0.05 Tg CO2 Eq.
1 Note that these emissions have already been accounted for in the estimates of net annual changes in C stocks, which account for
the amount sequestered minus any emissions.
17 [END BOX]
18
19 Methodology and Data Sources
20 The methodology described herein is consistent with IPCC (2003, 2006) and IPCC/UNEP/OECD/IEA (1997).
21 Forest ecosystem C stocks and net annual C stock change are determined according to stock-difference methods,
22 which involve applying C estimation factors to forest inventory data and interpolating between successive
23 inventory-based estimates of C stocks. Harvested wood C estimates are based on factors such as the allocation of
24 wood to various primary and end-use products as well as half-life (the time at which half of amount placed in use
25 will have been discarded from use) and expected disposition (e.g., product pool, SWDS, combustion). An overview
26 of the different methodologies and data sources used to estimate the C in forest ecosystems or harvested wood
27 products is provided here. See Annex 3.12 for details and additional information related to the methods and data.
28 Forest Ecosystem Carbon from Forest Inventory
29 Forest ecosystem stock and flux estimates are based on the stock-difference method and calculations for all
30 estimates are in units of C. Separate estimates are made for the five IPCC C storage pools described above. All
31 estimates are based on data collected from the extensive array of permanent forest inventory plots in the United
32 States as well as models employed to fill gaps in field data. Carbon conversion factors are applied at the
33 disaggregated level of each inventory plot and then appropriately expanded to population estimates. A combination
34 of tiers as outlined by IPCC (2006) is used. The Tier 3 biomass C values are from forest inventory tree-level data.
35 The Tier 2 dead organic and soil C pools are based on empirical or process models from the inventory data. All
36 carbon conversion factors are specific to regions or individual states within the U.S., which are further classified
37 according to characteristic forest types within each region.
7-16 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 The first step in developing forest ecosystem estimates is to identify useful inventory data and resolve any
2 inconsistencies among datasets. Forest inventory data were obtained from the USDA Forest Service FIA program
3 (Prayer and Furnival 1999, USDA Forest Service 2010b). Inventories include data collected on permanent
4 inventory plots on forest lands173 and are organized as a number of separate datasets, each representing a complete
5 inventory, or survey, of an individual state at a specified time. Some of the more recent annual inventories reported
6 for some states include "moving window" averages, which means that a portion—but not all—of the previous year's
7 inventory is updated each year (USDA Forest Service 2010d). Forest C calculations are organized according to
8 these state surveys, and the frequency of surveys varies by state. All available data sets are identified for each state
9 starting with pre-1990 data, and all unique surveys are identified for stock and change calculations. Since C stock
10 change is based on differences between successive surveys within each state, accurate estimates of net C flux thus
11 depend on consistent representation of forest land between these successive inventories. In order to achieve this
12 consistency from 1990 to the present, states are sometimes subdivided into sub-state areas where the sum of sub-
13 state inventories produces the best whole-state representation of C change as discussed in Smith et al. (2010).
14 The principal FIA datasets employed are freely available for download at USDA Forest Service (2010b) as the
15 Forest Inventory and Analysis Database (FIADB) Version 4.0. However, to achieve consistent representation
16 (spatial and temporal), two other general sources of past FIA data are included as necessary. First, older FIA plot-
17 and tree-level data—not in the current FIADB format—are used if available. Second, Resources Planning Act
18 Assessment (RPA) databases, which are periodic, plot-level only, summaries of state inventories, are used mostly to
19 provide the data at or before 1990. An additional forest inventory data source is the Integrated Database (IDE),
20 which is a compilation of periodic forest inventory data from the 1990s for California, Oregon, and Washington
21 (Waddell and Hiserote 2005). These data were identified by Heath et al. (submitted) as the most appropriate non-
22 FIADB sources for these states and are included in this inventory. See USDA Forest Service (2010a) for
23 information on current and older data as well as additional FIA Program features. A detailed list of the specific
24 forest inventory data used in this inventory is in Annex 3.12.
25 Forest C stocks are estimated from inventory data by a collection of conversion factors and models (Birdsey and
26 Heath 1995, Birdsey and Heath 2001, Heath et al. 2003, Smith et al. 2004, Smith et al. 2006), which have been
27 formalized in an FIADB-to-carbon calculator (Smith et al. 2010). The conversion factors and model coefficients are
28 categorized by region and forest type, and forest C stock estimates are calculated from application of these factors at
29 the scale of FIA inventory plots. The results are estimates of C density (Mg C per hectare) for six forest ecosystem
30 pools: live trees, standing dead trees, understory vegetation, down dead wood, forest floor, and soil organic matter.
31 The six carbon pools used in the FIADB-to-carbon calculator are aggregated to the 5 carbon pools defined by IPCC
32 (2006): aboveground biomass, belowground biomass, dead wood, litter, and soil organic matter. All non-soil pools
33 except forest floor are separated into aboveground and belowground components. The live tree and understory C
34 pools are pooled as biomass, and standing dead trees and down dead wood are pooled as dead wood, in accordance
35 with IPCC (2006).
36 Once plot-level C stocks are calculated as C densities on Forest Land Remaining Forest LandTor the five IPCC
37 (2006) reporting pools, the stocks are expanded to population estimates according to methods appropriate to the
38 respective inventory data (for example, see Bechtold and Patterson (2005)). These expanded C stock estimates are
39 summed to state or sub-state total C stocks. Annualized estimates of C stocks are developed by using available FIA
40 inventory data and interpolating or extrapolating to assign a C stock to each year in the 1990 through2010 time
41 series. Flux, or net annual stock change, is estimated by calculating the difference between two successive years and
42 applying the appropriate sign convention; net increases in ecosystem C are identified as negative flux. By
43 convention, inventories are assigned to represent stocks as of January 1 of the inventory year; an estimate of flux for
44 1996 requires estimates of C stocks for 1996 and 1997, for example. Additional discussion of the use of FIA
45 inventory data and the C conversion process is in Annex 3.12.
46 Carbon in Biomass
47 Live tree C pools include aboveground and belowground (coarse root) biomass of live trees with diameter at
48 diameter breast height (d.b.h.) of at least 2.54 cm at 1.37 m above the forest floor. Separate estimates are made for
49 full-tree and aboveground-only biomass in order to estimate the belowground component. If inventory plots include
173 Forest land in the United States includes land that is at least 10 percent stocked with trees of any size. Timberland is the most
productive type of forest land, which is on unreserved land and is producing or capable of producing crops of industrial wood.
Land Use, Land Use Change, and Forestry 7-17
-------
1 data on individual trees, tree C is based on Jenkins et al. (2003) and is a function of species and diameter. Some
2 inventory data do not provide measurements of individual trees; tree C in these plots is estimated from plot-level
3 volume of merchantable wood, or growing-stock volume, of live trees, which is calculated from updates of Smith et
4 al. (2003). These biomass conversion and expansion factors (BCEFs) are applied to about 3 percent of the inventory
5 records, all of which are pre-1998 data. Some inventory data, particularly some of the older datasets, may not
6 include sufficient information to calculate tree C because of incomplete or missing tree or volume data; C estimates
7 for these plots are based on averages from similar, but more complete, inventory data. This applies to an additional
8 2 percent of inventory records, which represent older (pre-1998) non-timberlands.
9 Understory vegetation is a minor component of biomass, which is defined as all biomass of undergrowth plants in a
10 forest, including woody shrubs and trees less than 2.54 cm d.b.h. In the current inventory, it is assumed that 10
11 percent of total understory C mass is belowground. Estimates of C density are based on information in Birdsey
12 (1996). Understory frequently represents over 1 percent of C in biomass, but its contribution rarely exceeds 2
13 percent of the total.
14 Carbon in Dead Organic Matter
15 Dead organic matter is initially calculated as three separate pools with C stocks modeled from inventory data.
16 Estimates are specific to regions and forest types within each region, and stratification of forest land for dead
17 organic matter calculations is identical to that used for biomass through the state and sub-state use of FIA data as
18 discussed above. The two components of dead wood—standing dead trees and down dead wood—are estimated
19 separately. The standing dead tree C pools include aboveground and belowground (coarse root) mass and include
20 trees of at least 2.54 cm d.b.h. Calculations are BCEF-like factors based on updates of Smith et al. (2003). Down
21 dead wood is defined as pieces of dead wood greater than 7.5 cm diameter, at transect intersection, that are not
22 attached to live or standing dead trees. Down dead wood includes stumps and roots of harvested trees. Ratios of
23 down dead wood to live tree are used to estimate this quantity. Litter C is the pool of organic C (also known as duff,
24 humus, and fine woody debris) above the mineral soil and includes woody fragments with diameters of up to 7.5 cm.
25 Estimates are based on equations of Smith and Heath (2002).
26 Carbon in Forest Soil
27 Soil organic C (SOC) includes all organic material in soil to a depth of 1 meter but excludes the coarse roots of the
28 biomass or dead wood pools. Estimates of SOC are based on the national STATSGO spatial database (USDA
29 1991), which includes region and soil type information. SOC determination is based on the general approach
30 described by Amichev and Galbraith (2004). Links to FIA inventory data were developed with the assistance of the
31 USDA Forest Service FIA Geospatial Service Center by overlaying FIA forest inventory plots on the soil C map.
32 This method produced mean SOC densities stratified by region and forest type group. It did not provide separate
33 estimates for mineral or organic soils but instead weighted their contribution to the overall average based on the
34 relative amount of each within forest land. Thus, forest SOC is a function of species and location, and net change
35 also depends on these two factors as total forest area changes. In this respect, SOC provides a country-specific
36 reference stock for 1990-present, but it does not reflect effects of past land use.
37 Harvested Wood Carbon
38 Estimates of the HWP contribution to forest C sinks and emissions (hereafter called "HWP Contribution") are based
39 on methods described in Skog (2008) using the WOODCARB II model. These methods are based on IPCC (2006)
40 guidance for estimating HWP C. IPCC (2006) provides methods that allow Parties to report HWP Contribution
41 using one of several different accounting approaches: production, stock change and atmospheric flow, as well as a
42 default method that assumes there is no change in HWP C stocks (see Annex 3.12 for more details about each
43 approach). The United States uses the production accounting approach to report HWP Contribution. Under the
44 production approach, C in exported wood is estimated as if it remains in the United States, and C in imported wood
45 is not included in inventory estimates. Though reported U.S. HWP estimates are based on the production approach,
46 estimates resulting from use of the two alternative approaches, the stock change and atmospheric flow approaches,
47 are also presented for comparison (see Annex 3.12). Annual estimates of change are calculated by tracking the
48 additions to and removals from the pool of products held in end uses (i.e., products in use such as housing or
49 publications) and the pool of products held in solid waste disposal sites (SWDS).
50 Solidwood products added to pools include lumber and panels. End-use categories for solidwood include single and
7-18 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 multifamily housing, alteration and repair of housing, and other end-uses. There is one product category and one
2 end-use category for paper. Additions to and removals from pools are tracked beginning in 1900, with the exception
3 that additions of softwood lumber to housing begins in 1800. Solidwood and paper product production and trade
4 data are from USDA Forest Service and other sources (Hair and Ulrich 1963; Hair 1958; USDC Bureau of Census;
5 1976; Ulrich, 1985, 1989; Steer 1948; AF&PA 2006a 2006b; Howard 2003, 2007). Estimates for disposal of
6 products reflect the change over time in the fraction of products discarded to SWDS (as opposed to burning or
7 recycling) and the fraction of SWDS that are in sanitary landfills versus dumps.
8 There are five annual HWP variables that are used in varying combinations to estimate HWP Contribution using any
9 one of the three main approaches listed above. These are:
10 (1 A) annual change of C in wood and paper products in use in the United States,
11 (IB) annual change of C in wood and paper products in SWDS in the United States,
12 (2A) annual change of C in wood and paper products in use in the United States and other countries where
13 the wood came from trees harvested in the United States,
14 (2B) annual change of C in wood and paper products in SWDS in the United States and other countries
15 where the wood came from trees harvested in the United States,
16 (3) C in imports of wood, pulp, and paper to the United States,
17 (4) C in exports of wood, pulp and paper from the United States, and
18 (5) C in annual harvest of wood from forests in the United States.
19 The sum of variables 2 A and 2B yields the estimate for HWP Contribution under the production accounting
20 approach. A key assumption for estimating these variables is that products exported from the United States and held
21 in pools in other countries have the same half lives for products in use, the same percentage of discarded products
22 going to SWDS, and the same decay rates in SWDS as they would in the United States.
23 Uncertainty and Time Series Consistency
24
25
26
27
28
29
30
31
32
33
34
35
A quantitative uncertainty analysis placed bounds on current flux for forest ecosystems as well as carbon in
harvested wood products through Monte Carlo simulation of the Methods described above and probabilistic
sampling of carbon conversion factors and inventory data. See Annex 3.12 for additional information. The 2009
flux estimate for forest C stocks is estimated to be between -714 and -1,014 Tg CO2 Eq. at a 95 percent confidence
level. This includes a range of -662 to -959 Tg CO2 Eq. in forest ecosystems and -41 to -69 Tg CO2 Eq. for HWP.
Table 7-10: Tier 2 Quantitative Uncertainty Estimates for Net CO2 Flux from Forest Land Remaining Forest Land:
Changes in Forest C Stocks (Tg CO2 Eq. and Percent)
Source
Forest Ecosystem
Harvested Wood
Products
Total Forest
2009 Flux
Gas Estimate Uncertainty Range Relative to Flux Estimate"
(TgC02
Eq.) (Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
CO2 (808.9) (959.4) (661.7) -19% -18%
CO2 (54.3) (68.6) (41.0) -27% -24%
CO2 (863.1) (1,014.4) (713.9) -18% -17%
Note: Parentheses indicate negative values or net sequestration.
aRange of flux estimates predicted by Monte Carlo stochastic simulation for a 95 percent confidence interval.
Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
above.
36 QA/QC and Verification
37 As discussed above, the FIA program has conducted consistent forest surveys based on extensive statistically-based
Land Use, Land Use Change, and Forestry 7-19
-------
1 sampling of most of the forest land in the conterminous United States, dating back to 1952. The main purpose of the
2 FIA program has been to estimate areas, volume of growing stock, and timber products output and utilization
3 factors. The FIA program includes numerous quality assurance and quality control (QA/QC) procedures, including
4 calibration among field crews, duplicate surveys of some plots, and systematic checking of recorded data. Because
5 of the statistically-based sampling, the large number of survey plots, and the quality of the data, the survey databases
6 developed by the FIA program form a strong foundation for C stock estimates. Field sampling protocols, summary
7 data, and detailed inventory databases are archived and are publicly available on the Internet (USD A Forest Service
8 2010d).
9 Many key calculations for estimating current forest C stocks based on FIA data were developed to fill data gaps in
10 assessing forest carbon and have been in use for many years to produce national assessments of forest C stocks and
11 stock changes (see additional discussion and citations in the Methodology section above and in Annex 3.12).
12 General quality control procedures were used in performing calculations to estimate C stocks based on survey data.
13 For example, the derived C datasets, which include inventory variables such as areas and volumes, were compared
14 to standard inventory summaries such as the forest resource statistics of Smith et al. (2009) or selected population
15 estimates generated from FIADB 4.0, which are available at an FIA internet site (USDA Forest Service 2009b).
16 Agreement between the C datasets and the original inventories is important to verify accuracy of the data used.
17 Finally, C stock estimates were compared with previous inventory report estimates to ensure that any differences
18 could be explained by either new data or revised calculation methods (see the "Recalculations" discussion, below).
19 Estimates of the HWP variables and the HWP contribution under the production accounting approach use data from
20 U.S. Census and USDA Forest Service surveys of production and trade. Factors to convert wood and paper to units
21 C are based on estimates by industry and Forest Service published sources. The WOODCARB II model uses
22 estimation methods suggested by IPCC (2006). Estimates of annual C change in solidwood and paper products in
23 use were calibrated to meet two independent criteria. The first criterion is that the WOODCARB II model estimate
24 of C in houses standing in 2001 needs to match an independent estimate of C in housing based on U. S. Census and
25 USDA Forest Service survey data. Meeting the first criterion resulted in an estimated half life of about 80 years for
26 single family housing built in the 1920s, which is confirmed by other U.S. Census data on housing. The second
27 criterion is that the WOODCARB II model estimate of wood and paper being discarded to SWDS needs to match
28 EPA estimates of discards each year over the period 1990 to 2000 (EPA 2006). These criteria help reduce
29 uncertainty in estimates of annual change in C in products in use in the United States and, to a lesser degree, reduce
30 uncertainty in estimates of annual change in C in products made from wood harvested in the United States. In
31 addition, WOODCARB II landfill decay rates have been validated by ensuring that estimates of CH4 emissions from
32 landfills based on EPA (2006) data are reasonable in comparison with CH4 estimates based on WOODCARB II
33 landfill decay rates.
34 Recalculations Discussion
35 The basic models used to estimate forest ecosystem and HWP C stocks and change are unchanged from the previous
36 Inventory (Smith et al. 2010, Skog 2008). Many of the state-level estimates for 1990 through the present are
37 relatively similar to the values previously reported (EPA 2010). Recent forest inventory additions to the FIADB
38 include newer annual inventory data for most states including Oklahoma, which had the effect of increasing overall
39 net sequestration estimated for the interval from 2000 through 2008. An additional change to the FIADB was the
40 addition of some older periodic inventories for some southern states; these were incorporated into the calculations
41 but did not appreciably affect national trends. The addition of the IDE forest inventories for a part of the series for
42 California, Oregon, and Washington did affect recalculations for those states and the United States as a whole; it
43 tended to decrease net sequestration throughout the 1990 to 2008 interval. However, the decreased sequestration
44 associated with the use of the IDE was offset by the increased sequestration associated with newer annual inventory
45 data for the post-2000 interval.
46 Planned Improvements
47 The ongoing annual surveys by the FIA Program will improve precision of forest C estimates as new state surveys
48 become available (USDA Forest Service 2010b), particularly in western states. The annual surveys will eventually
49 include all states. To date, three states are not yet reporting any data from the annualized sampling design of FIA:
50 Hawaii, New Mexico and Wyoming. Estimates for these states are currently based on older, periodic data. Hawaii
51 and U.S. territories will also be included when appropriate forest C data are available. In addition, the more
52 intensive sampling of down dead wood, litter, and soil organic C on some of the permanent FIA plots continues and
7-20 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 will substantially improve resolution of C pools at the plot level for all U.S. forest land as this information becomes
2 available (Woodall et al. in press). Improved resolution, incorporating more of Alaska's forests, and using
3 annualized sampling data as it becomes available for those states currently not reporting are planned for future
4 reporting.
5 As more information becomes available about historical land use, the ongoing effects of changes in land use and
6 forest management will be better accounted for in estimates of soil C (Birdsey and Lewis 2003, Woodbury et al.
7 2006, Woodbury et al. 2007). Currently, soil C estimates are based on the assumption that soil C density depends
8 only on broad forest type group, not on land-use history, but long-term residual effects on soil and forest floor C
9 stocks are likely after land-use change. Estimates of such effects depend on identifying past land use changes
10 associated with forest lands.
11 Similarly, agroforestry practices, such as windbreaks or riparian forest buffers along waterways, are not currently
12 accounted for in the inventory. In order to properly account for the C stocks and fluxes associated with agroforestry,
13 research will be needed that provides the basis and tools for including these plantings in a nation-wide inventory, as
14 well as the means for entity-level reporting.
15 Non-CCb Emissions from Forest Fires
16
17
18
19
20
21
22
23
24
25
26
Emissions of non-CO2 gases from forest fires were estimated using the default IPCC (2003) methodology
incorporating default IPCC (2006) emissions factors and combustion factor for wildfires. Emissions from this
source in 2009 were estimated to be 7.8 Tg CO2 Eq. of CH4 and 6.4 Tg CO2 Eq. of N2O, as shown in Table 7-1 1 and
Table 7-12. The estimates of non-CO2 emissions from forest fires account for wildfires in the lower 48 states and
Alaska as well as prescribed fires in the lower 48 states.
Table 7-11: Estimated Non-CO2 Emissions from Forest Fires (Tg CO2 Eq.) for U.S. Forests1
Gas
CH4
N2O
Total
1990
3.2
2.6
5.8
2000
14.3
11.7
26.0
2005
9.8
8.0
17.8
2006
21.6
17.6
39.2
2007
20.0
16.3
36.3
Calculated based on C emission estimates in Changes in Forest Carbon Stocks and default factors in IPCC
Table 7-12: Estimated Non-CO2 Emissions from Forest Fires (Gg Gas) for U.S. Forests1
Gas
CH4
N2O
1 Calculated based
1990
152
8
on C emission
2000
682
38
2005
467
26
2006
1,027
57
estimates in Changes in Forest Carbon Stocks and default
2007
953
53
factors in IPCC
2008
11.9
9.8
21.7
(2003, 2006).
2008
569
31
(2003, 2006).
2009
7.8
6.4
14.2
2009
372
21
27 Methodology
28 The IPCC (2003) Tier 2 default methodology was used to calculate non-CO2 emissions from forest fires. However,
29 more up-to-date default emission factors from IPCC (2006) were converted into gas-specific emission ratios and
30 incorporated into the methodology. Estimates of CH4 and N2O emissions were calculated by multiplying the total
31 estimated CO2 emitted from forest burned by the gas-specific emissions ratios. CO2 emissions were estimated by
32 multiplying total C emitted (Table 7-13) by the C to CO2 conversion factor of 44/12 and by 92.8 percent, which is
33 the estimated proportion of C emitted as CO2 (Smith 2008a). The equations used were:
34 CH4 Emissions = (C released) x 92.8% x (44/12) x (CH4 to CO2 emission ratio)
35 N2O Emissions = (C released) x 92.8% x (44/12) x (N2O to CO2 emission ratio)
36 Estimates for C emitted from forest fires are the same estimates used to generate estimates of CO2 presented earlier
37 in Box 7-1. Estimates for C emitted include emissions from wildfires in both Alaska and the lower 48 states as well
38 as emissions from prescribed fires in the lower 48 states only (based on expert judgment that prescribed fires only
39 occur in the lower 48 states) (Smith 2008a). The IPCC (2006) default combustion factor of 0.45 for "all 'other'
40 temperate forests" was applied in estimating C emitted from both wildfires and prescribed fires. See the explanation
41 in Annex 3.12 for more details on the methodology used to estimate C emitted from forest fires.
Land Use, Land Use Change, and Forestry 7-21
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Table 7-13: Estimated Carbon Released from Forest Fires for U.S. Forests
Year
1990
2000
2005
2006
2007
2008
2009
C Emitted (Tg/yr)
14.9
66.8
45.8
100.8
93.5
55.8
36.5
Uncertainty and Time-Series Consistency
o
J
4
5
6
7
8
9
10
11
12
13
Non-CO2 gases emitted from forest fires depend on several variables, including: forest area for Alaska and the lower
48 states; average C densities for wildfires in Alaska, wildfires in the lower 48 states, and prescribed fires in the
lower 48 states; emission ratios; and combustion factor values (proportion of biomass consumed by fire). To
quantify the uncertainties for emissions from forest fires, a Monte Carlo (Tier 2) uncertainty analysis was performed
using information about the uncertainty surrounding each of these variables. The results of the Tier 2 quantitative
uncertainty analysis are summarized in Table 7-14.
Table 7-14: Tier 2 Quantitative Uncertainty Estimates of Non-CO2 Emissions from Forest Fires in Forest Land
Remaining Forest Land (Tg CO2 Eq. and Percent)
Source
Non-CO2 Emissions from Forest Fires
Non-CO2 Emissions from Forest Fires
2009 Emission
Gas Estimate
(Tg C02 Eq.)
CH4 7.8
N2O 6.4
Uncertainty Range Relative to Emission
Estimate
(TgC02Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
2.2 19.2 -72% +145%
1.8 15.7 -72% +145%
Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
above.
14 QA/QC and Verification
15 Tier 1 and Tier 2 QA/QC activities were conducted consistent with the U.S. QA/QC plan. Source-specific quality
16 control measures for forest fires included checking input data, documentation, and calculations to ensure data were
17 properly handled through the inventory process. Errors that were found during this process were corrected as
18 necessary.
19 Recalculations Discussion
20 This is the second year in which non-CO2 emissions were calculated using the 2006 IPCC default emission factors
21 for CH4 and N2O instead of the 2003 IPCC default emission factors. These default emission factors were converted
22 to CH4to CO2 and N2O to CO2 emission ratios and then multiplied by CO2 emissions to estimate CH4 and N2O
23 emissions. The previous 2003 IPCC methodology provides emission ratios that are multiplied by total carbon
24 emitted.
25 Planned Improvements
26 The default combustion factor of 0.45 from IPCC (2006) was applied in estimating C emitted from both wildfires
27 and prescribed fires. Additional research into the availability of a combustion factor specific to prescribed fires is
28 being conducted.
7-22 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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i Direct N20 Fluxes from Forest Soils (IPCC Source Category 5A1)
2 Of the synthetic N fertilizers applied to soils in the United States, no more than one percent is applied to forest soils.
3 Application rates are similar to those occurring on cropped soils, but in any given year, only a small proportion of
4 total forested land receives N fertilizer. This is because forests are typically fertilized only twice during their
5 approximately 40-year growth cycle (once at planting and once approximately 20 years later). Thus, while the rate
6 of N fertilizer application for the area of forests that receives N fertilizer in any given year is relatively high, the
7 average annual application is quite low as inferred by dividing all forest land that may undergo N fertilization at
8 some point during its growing cycle by the amount of N fertilizer added to these forests in a given year. Direct N2O
9 emissions from forest soils in 2009 were 0.4 Tg CO2 Eq. (1 Gg). Emissions have increased by 455 percent from
10 1990 to 2009 as a result of an increase in the area of N fertilized pine plantations in the southeastern United States
11 and Douglas-fir timberland in western Washington and Oregon. Total forest soil N2O emissions are summarized in
12 Table 7-15.
13 Table 7-15: Direct N2O Fluxes from Soils in Forest Land Remaining Forest Land (Tg CO2 Eq. and Gg N2O)
Year Tg CO2 Eq. Gg
1990 0.1 0.2
2000 0.4 1.3
14
15
16
17
2005 0.4 1.2
2006 0.4 1.2
2007 0.4 1.2
2008 0.4 1.2
2009 0.4 1.2
Note: These estimates include direct N2O emissions fromN fertilizer additions only.
additions are reported in the Agriculture chapter. These estimates include emissions
Land and from Land Converted to Forest Land.
Indirect N2O emissions from fertilizer
from both Forest Land Remaining Forest
18 Methodology
19 The IPCC Tier 1 approach was used to estimate N2O from soils within Forest Land Remaining Forest Land.
20 According to U.S. Forest Service statistics for 1996 (USDA Forest Service 2001), approximately 75 percent of trees
21 planted were for timber, and about 60 percent of national total harvested forest area is in the southeastern United
22 States. Although southeastern pine plantations represent the majority of fertilized forests in the United States, this
23 Inventory also accounted for N fertilizer application to commercial Douglas-fir stands in western Oregon and
24 Washington. For the Southeast, estimates of direct N2O emissions from fertilizer applications to forests were based
25 on the area of pine plantations receiving fertilizer in the southeastern United States and estimated application rates
26 (Albaugh et al. 2007). Not accounting for fertilizer applied to non-pine plantations is justified because fertilization
27 is routine for pine forests but rare for hardwoods (Binkley et al. 1995). For each year, the area of pine receiving N
28 fertilizer was multiplied by the weighted average of the reported range of N fertilization rates (121 Ibs. N per acre).
29 Area data for pine plantations receiving fertilizer in the Southeast were not available for 2005, 2006, 2007 and 2008,
30 so data from 2004 were used for these years. For commercial forests in Oregon and Washington, only fertilizer
31 applied to Douglas-fir was accounted for, because the vast majority (~95 percent) of the total fertilizer applied to
32 forests in this region is applied to Douglas-fir (Briggs 2007). Estimates of total Douglas-fir area and the portion of
33 fertilized area were multiplied to obtain annual area estimates of fertilized Douglas-fir stands. The annual area
34 estimates were multiplied by the typical rate used in this region (200 Ibs. N per acre) to estimate total N applied
35 (Briggs 2007), and the total N applied to forests was multiplied by the IPCC (2006) default emission factor of 1
36 percent to estimate direct N2O emissions. The volatilization and leaching/runoff N fractions for forest land,
37 calculated according to the IPCC default factors of 10 percent and 30 percent, respectively, were included with the
38 indirect emissions in the Agricultural Soil Management source category (consistent with reporting guidance that all
39 indirect emissions are included in the Agricultural Soil Management source category).
40 Uncertainty and Time-Series Consistency
41 The amount of N2O emitted from forests depends not only on N inputs and fertilized area, but also on a large
42 number of variables, including organic C availability, oxygen gas partial pressure, soil moisture content, pH,
Land Use, Land Use Change, and Forestry 7-23
-------
1 temperature, and tree planting/harvesting cycles. The effect of the combined interaction of these variables on N2O
2 flux is complex and highly uncertain. IPCC (2006) does not incorporate any of these variables into the default
3 methodology, except variation in estimated fertilizer application rates and estimated areas of forested land receiving
4 N fertilizer. All forest soils are treated equivalently under this methodology. Furthermore, only synthetic N
5 fertilizers are captured, so applications of organic N fertilizers are not estimated. However, the total quantity of
6 organic N inputs to soils is included in the Agricultural Soil Management and Settlements Remaining Settlements
7 sections.
8 Uncertainties exist in the fertilization rates, annual area of forest lands receiving fertilizer, and the emission factors.
9 Fertilization rates were assigned a default level174 of uncertainty at ±50 percent, and area receiving fertilizer was
10 assigned a ±20 percent according to expert knowledge (Binkley 2004). IPCC (2006) provided estimates for the
11 uncertainty associated with direct N2O emission factor for synthetic N fertilizer application to soils. Quantitative
12 uncertainty of this source category was estimated through the IPCC-recommended Tier 2 uncertainty estimation
13 methodology. The uncertainty ranges around the 2005 activity data and emission factor input variables were
14 directly applied to the 2009 emissions estimates. The results of the quantitative uncertainty analysis are summarized
15 in Table 7-16. N2O fluxes from soils were estimated to be between 0.1 and 1.1 TgCO2Eq. at a 95 percent
16 confidence level. This indicates a range of 59 percent below and 211 percent above the 2009 emission estimate of
17 0.4 Tg CO2 Eq.
18 Table 7-16: Quantitative Uncertainty Estimates of N2O Fluxes from Soils in Forest Land Remaining Forest Land
19 (Tg CO2 Eq. and Percent)
2009 Emission Uncertainty Range Relative to Emission
Source Gas Estimate Estimate
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper
Bound
Forest Land Remaining Forest Land:
N2O Fluxes from Soils N2O 0.4 0.1 1.1 -59% +211%
20 Note: This estimate includes direct N2O emissions from N fertilizer additions to both Forest Land Remaining Forest Land and
21 Land Converted to Forest Land.
22 Planned Improvements
23 State-level area data will be acquired for southeastern pine plantations and northwestern Douglas-fir forests
24 receiving fertilizer to estimate soil N2O emission by state and provide information about regional variation in
25 emission patterns.
26 7.3. Land Converted to Forest Land (IPCC Source Category 5A2)
27 Land-use change is constantly occurring, and areas under a number of differing land-use types are converted to
28 forest each year, just as forest land is converted to other uses. However, the magnitude of these changes is not
29 currently known. Given the paucity of available land-use information relevant to this particular IPCC source
30 category, it is not possible to separate CO2 or N2O fluxes on Land Converted to Forest Land from fluxes on Forest
31 Land Remaining Forest Land at this time.
32 7.4. Cropland Remaining Cropland (IPCC Source Category 5B1)
33 Mineral and Organic Soil Carbon Stock Changes
34 Soils contain both organic and inorganic forms of C, but soil organic C (SOC) stocks are the main source and sink
35 for atmospheric CO2 in most soils. Changes in inorganic C stocks are typically minor. In addition, soil organic C is
36 the dominant organic C pool in cropland ecosystems, because biomass and dead organic matter have considerably
37 less C and those pools are relatively ephemeral. IPCC (2006) recommends reporting changes in soil organic C
174 Uncertainty is unknown for the fertilization rates so a conservative value of ±50% was used in the analysis.
7-24 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 stocks due to agricultural land-use and management activities on mineral and organic soils.175
2 Typical well-drained mineral soils contain from 1 to 6 percent organic C by weight, although mineral soils that are
3 saturated with water for substantial periods during the year may contain significantly more C (NRCS 1999).
4 Conversion of mineral soils from their native state to agricultural uses can cause as much as half of the SOC to be
5 decomposed and the C lost to the atmosphere. The rate and ultimate magnitude of C loss will depend on pre-
6 conversion conditions, conversion method and subsequent management practices, climate, and soil type. In the
7 tropics, 40 to 60 percent of the C loss generally occurs within the first 10 years following conversion; C stocks
8 continue to decline in subsequent decades but at a much slower rate. In temperate regions, C loss can continue for
9 several decades, reducing stocks by 20 to 40 percent of native C levels. Eventually, the soil can reach a new
10 equilibrium that reflects a balance between C inputs (e.g., decayed plant matter, roots, and organic amendments such
11 as manure and crop residues) and C loss through microbial decomposition of organic matter. However, land use,
12 management, and other conditions may change before the new equilibrium is reached. The quantity and quality of
13 organic matter inputs and their rate of decomposition are determined by the combined interaction of climate, soil
14 properties, and land use. Land use and agricultural practices such as clearing, drainage, tillage, planting, grazing,
15 crop residue management, fertilization, and flooding can modify both organic matter inputs and decomposition, and
16 thereby result in a net flux of C to or from the pool of soil C.
17 Organic soils, also referred to as histosols, include all soils with more than 12 to 20 percent organic C by weight,
18 depending on clay content (NRCS 1999, Brady and Weil 1999). The organic layer of these soils can be very deep
19 (i.e., several meters), forming under inundated conditions in which minimal decomposition of plant residue occurs.
20 When organic soils are prepared for crop production, they are drained and tilled, leading to aeration of the soil,
21 which accelerates the rate of decomposition and CO2 emissions. Because of the depth and richness of the organic
22 layers, C loss from drained organic soils can continue over long periods of time. The rate of CO2 emissions varies
23 depending on climate and composition (i.e., decomposability) of the organic matter. Also, the use of organic soils
24 for annual crop production leads to higher C loss rates than drainage of organic soils in grassland or forests, due to
25 deeper drainage and more intensive management practices in cropland (Armentano and Verhoeven 1990, as cited in
26 IPCC/UNEP/OECD/IEA 1997). Carbon losses are estimated from drained organic soils under both grassland and
27 cropland management in this Inventory.
28 Cropland Remaining Cropland includes all cropland in an inventory year that had been cropland for the last 20
29 years176 according to the USDA NRI land-use survey (USDA-NRCS 2000). The Inventory includes all privately-
30 owned croplands in the conterminous United States and Hawaii, but there is a minor amount of cropland on federal
31 lands that is not currently included in the estimation of C stock changes, leading to a discrepancy between the total
32 amount of managed area in Cropland Remaining Cropland (see Section 7.1) and the cropland area included in the
33 Inventory. It is important to note that plans are being made to include federal croplands in future C inventories.
34 The area of Cropland Remaining Cropland changes through time as land is converted to or from cropland
35 management. CO2 emissions and removals177 due to changes in mineral soil C stocks are estimated using a Tier 3
36 approach for the majority of annual crops. A Tier 2 IPCC method is used for the remaining crops (vegetables,
37 tobacco, perennial/horticultural crops, and rice) not included in the Tier 3 method. In addition, a Tier 2 method is
38 used for very gravelly, cobbly, or shaley soils (i.e., classified as soils that have greater than 35 percent of soil
39 volume comprised of gravel, cobbles, or shale) and for additional changes in mineral soil C stocks that were not
40 addressed with the Tier 3 approach (i.e., change in C stocks after 2003 due to Conservation Reserve Program
41 enrollment). Emissions from organic soils are estimated using a Tier 2 IPCC method.
42 Of the two sub-source categories, land-use and land management of mineral soils was the most important
43 component of total net C stock change between 1990 and 2009 (see Table 7-17 and Table 7-18). In 2009, mineral
44 soils were estimated to remove 45.1 Tg CO2 Eq. (12.3 Tg C). This rate of C storage in mineral soils represented
45 about a 20 percent decrease in the rate since the initial reporting year of 1990. Emissions from organic soils were
46 27.7 Tg CO2 Eq. (7.5 Tg C) in 2009. In total, U.S. agricultural soils in Cropland Remaining Cropland removed
47 approximately 17.4 Tg CO2 Eq. (4.7 Tg C) in 2009.
175 CO2 emissions associated with liming are also estimated but are included in a separate section of the report.
176 NRI points were classified according to land-use history records starting in 1982 when the NRI survey began, and
consequently the classifications were based on less than 20 years from 1990 to 2001.
177 Note that removals occur through crop and forage uptake of CO2 into biomass C that is later incorporated into soil pools.
Land Use, Land Use Change, and Forestry 7-25
-------
1 Table 7-17: Net CO2 Flux from Soil C Stock Changes in Cropland Remaining, Cropland (Tg CO2 Eq.)
Soil Type 1990 2000 2005 2006 2007 2008 2009
Mineral Soils (56.8) (57.9) (45.9) (46.8) (47.3) (45.7) (45.1)
Organic Soils 27.4 27.7 27.7 27.7 27.7 27.7 27.7
Total Net Flux (29.4) (30.2) (18.3) (19.1) (19.7) (18.1) (17.4)
2 Note: Parentheses indicate net sequestration. Shaded areas indicate values based on a combination of historical data and
3 projections. All other values are based on historical data only. Totals may not sum due to independent rounding.
4
5 Table 7-18: Net CO2 Flux from Soil C Stock Changes in Cropland Remaining, Cropland (Tg C)
Soil Type 1990 2000 2005 2006 2007 2008 2009
Mineral Soils (15.5) (15.8) (12.5) (12.8) (12.9) (12.5) (12.3)
Organic Soils 7.5 7.5 7.5 7.5 7.5 7.5 7.5
Total Net Flux (8.0) (8.2) (5.0) (5.2) (5.4) (4.9) (4.7)
6 Note: Parentheses indicate net sequestration. Shaded areas indicate values based on a combination of historical data and
7 projections. All other values are based on historical data only. Totals may not sum due to independent rounding.
8 The net reduction in soil C accumulation over the time series (39 percent from 1990 to 2009) was largely due to the
9 declining influence of annual cropland enrolled in the Conservation Reserve Program, which began in the late
10 1980s. However, there were still positive increases in C stocks from land enrolled in the reserve program, as well as
11 intensification of crop production by limiting the use of bare-summer fallow in semi-arid regions, increased hay
12 production, and adoption of conservation tillage (i.e., reduced- and no-till practices).
13 The spatial variability in annual CO2 flux associated with C stock changes in mineral and organic soils is displayed
14 in Figure 7-5 and Figure 7-6. The highest rates of net C accumulation in mineral soils occurred in the Midwest,
15 which is the area with the largest amounts of cropland managed with conservation tillage. Rates were also high in
16 the Great Plains due to enrollment in the Conservation Reserve Program. Emission rates from drained organic soils
17 were highest along the southeastern coastal region, in the northeast central United States surrounding the Great
18 Lakes, and along the central and northern portions of the West Coast.
19
20 Figure 7-5: Total Net Annual CO2 Flux for Mineral Soils under Agricultural Management within States, 2009,
21 Cropland Remaining Cropland
22
23 Figure 7-6: Total Net Annual CO2 Flux for Organic Soils under Agricultural Management within States, 2009,
24 Cropland Remaining Cropland
25
26 Methodology
27 The following section includes a description of the methodology used to estimate changes in soil C stocks due to: (1)
28 agricultural land-use and management activities on mineral soils; and (2) agricultural land-use and management
29 activities on organic soils for Cropland Remaining Cropland.
30 Soil C stock changes were estimated for Cropland Remaining Cropland (as well as agricultural land falling into the
31 IPCC categories Land Converted to Cropland, Grassland Remaining Grassland, and Land Converted to Grassland)
32 according to land-use histories recorded in the USDA National Resources Inventory (NRI) survey (USDA-NRCS
33 2000). The NRI is a statistically-based sample of all non-federal land, and includes approximately 260,000 points in
34 agricultural land for the conterminous United States and Hawaii.178 Each point is associated with an "expansion
35 factor" that allows scaling of C stock changes from NRI points to the entire country (i.e., each expansion factor
36 represents the amount of area with the same land-use/management history as the sample point). Land-use and some
37 management information (e.g., crop type, soil attributes, and irrigation) were originally collected for each NRI point
38 on a 5-year cycle beginning in 1982. For cropland, data were collected for 4 out of 5 years in the cycle (i.e., 1979-
178
NRI points were classified as agricultural if under grassland or cropland management between 1990 and 2003.
7-26 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 1982, 1984-1987, 1989-1992, and 1994-1997). However, the NRI program began collecting annual data in 1998,
2 and data are currently available through 2003. NRI points were classified as Cropland Remaining Cropland in a
3 given year between 1990 and 2009 if the land use had been cropland for 20 years.179 Cropland includes all land
4 used to produce food and fiber, or forage that is harvested and used as feed (e.g., hay and silage).
5 Mineral Soil Carbon Stock Changes
6 An IPCC Tier 3 model-based approach was applied to estimate C stock changes for mineral soils used to produce a
7 majority of annual crops in the United States (Ogle et al. 2010). The remaining crops on mineral soils were
8 estimated using an IPCC Tier 2 method (Ogle et al. 2003), including vegetables, tobacco, perennial/horticultural
9 crops, rice, and crops rotated with these crops. The Tier 2 method was also used for very gravelly, cobbly, or shaley
10 soils (greater than 35 percent by volume). Mineral SOC stocks were estimated using a Tier 2 method for these areas
11 because the Century model, which is used for the Tier 3 method, has not been fully tested to address its adequacy for
12 estimating C stock changes associated with certain crops and rotations, as well as cobbly, gravelly, or shaley soils.
13 An additional stock change calculation was made for mineral soils using Tier 2 emission factors, accounting for
14 enrollment patterns in the Conservation Reserve Program after 2003, which was not addressed by the Tier 3
15 methods.
16 Further elaboration on the methodology and data used to estimate stock changes from mineral soils are described
17 below and in Annex 3.13.
18 Tier 3 Approach
19 Mineral SOC stocks and stock changes were estimated using the Century biogeochemical model (Parton et al. 1987,
20 1988, 1994; Metherell et al. 1993), which simulates the dynamics of C and other elements in cropland, grassland,
21 forest, and savanna ecosystems. It uses monthly weather data as an input, along with information about soil physical
22 properties. Input data on land use and management are specified at monthly resolution and include land-use type,
23 crop/forage type, and management activities (e.g., planting, harvesting, fertilization, manure amendments, tillage,
24 irrigation, residue removal, grazing, and fire). The model computes net primary productivity and C additions to soil,
25 soil temperature, and water dynamics, in addition to turnover, stabilization, and mineralization of soil organic matter
26 C and nutrient (N, K, S) elements. This method is more accurate than the Tier 1 and 2 approaches provided by the
27 IPCC, because the simulation model treats changes as continuous over time rather than the simplified discrete
28 changes represented in the default method (see Box 7-3 for additional information). National estimates were
29 obtained by simulating historical land-use and management patterns as recorded in the USDA National Resources
30 Inventory (NRI) survey.
31
32 [BEGIN BOX]
33
34 Box 7-3: Tier 3 Approach for Soil C Stocks Compared to Tier 1 or 2 Approaches
35
36 A Tier 3 model-based approach is used to inventory soil C stock changes on the majority of agricultural land with
37 mineral soils. This approach entails several fundamental differences compared to the IPCC Tier 1 or 2 methods,
38 which are based on a classification of land areas into a number of discrete classes based on a highly aggregated
39 classification of climate, soil, and management (i.e., only six climate regions, seven soil types and eleven
40 management systems occur in U.S. agricultural land under the IPCC classification). Input variables to the Tier 3
41 model, including climate, soils, and management activities (e.g., fertilization, crop species, tillage, etc.), are
42 represented in considerably more detail both temporally and spatially, and exhibit multi-dimensional interactions
43 through the more complex model structure compared with the IPCC Tier 1 or 2 approach. The spatial resolution of
44 the analysis is also finer in the Tier 3 method compared to the lower tier methods as implemented in the United
45 States for previous Inventories (e.g., 3,037 counties versus 181 Major Land Resource Areas (MLRAs),
179 NRI points were classified according to land-use history records starting in 1982 when the NRI survey began. Therefore, the
classification prior to 2002 was based on less than 20 years of recorded land-use history for the time series.
Land Use, Land Use Change, and Forestry 7-27
-------
1 respectively).
2 In the Century model, soil C dynamics (and CO2 emissions and uptake) are treated as continuous variables, which
3 change on a monthly time step. Carbon emissions and removals are an outcome of plant production and
4 decomposition processes, which are simulated in the model structure. Thus, changes in soil C stocks are influenced
5 by not only changes in land use and management but also inter-annual climate variability and secondary feedbacks
6 between management activities, climate, and soils as they affect primary production and decomposition. This latter
7 characteristic constitutes one of the greatest differences between the methods, and forms the basis for a more
8 complete accounting of soil C stock changes in the Tier 3 approach compared with Tier 2 methodology.
9 Because the Tier 3 model simulates a continuous time period rather than the equilibrium step change used in the
10 IPCC methodology (Tier 1 and 2), the Tier 3 model addresses the delayed response of soils to management and
11 land-use changes. Delayed responses can occur due to variable weather patterns and other environmental
12 constraints that interact with land use and management and affect the time frame over which stock changes occur.
13 Moreover, the Tier 3 method also accounts for the overall effect of increasing yields and, hence, C input to soils that
14 have taken place across management systems and crop types within the United States. Productivity has increased by
15 1 to 2 percent annually over the past 4 to 5 decades for most major crops in the United States (Reilly and Fuglie
16 1998), which is believed to have led to increases in cropland soil C stocks (e.g., Allmaras et al. 2000). This is a
17 major difference from the IPCC-based Tier 1 and 2 approaches, in which trends in soil C stocks only capture
18 discrete changes in management and/or land use, rather than a longer term trend such as gradual increases in crop
19 productivity.
20
21 [END BOX]
22
23 Additional sources of activity data were used to supplement the land-use information from NPJ. The Conservation
24 Technology Information Center (CTIC 1998) provided annual data on tillage activity at the county level since 1989,
25 with adjustments for long-term adoption of no-till agriculture (Towery 2001). Information on fertilizer use and rates
26 by crop type for different regions of the United States were obtained primarily from the USD A Economic Research
27 Service Cropping Practices Survey (ERS 1997) with additional data from other sources, including the National
28 Agricultural Statistics Service (NASS 1992, 1999, 2004). Frequency and rates of manure application to cropland
29 during 1997 were estimated from data compiled by the USD A Natural Resources Conservation Service (Edmonds et
30 al. 2003), and then adjusted using county-level estimates of manure available for application in other years.
31 Specifically, county-scale ratios of manure available for application to soils in other years relative to 1997 were used
32 to adjust the area amended with manure (see Annex 3.13 for further details). Greater availability of managed
33 manure N relative to 1997 was, thus, assumed to increase the area amended with manure, while reduced availability
34 of manure N relative to 1997 was assumed to reduce the amended area. The amount of manure produced by each
35 livestock type was calculated for managed and unmanaged waste management systems based on methods described
36 in the Manure Management section (Section 6.2) and annex (Annex 3.10).
37 Manure amendments were an input to the Century Model based on manure N available for application from all
38 managed or unmanaged systems except Pasture/Range/Paddock.180 Data on the county-level N available for
39 application were estimated for managed systems based on the total amount of N excreted in manure minus N losses
40 during storage and transport, and including the addition of N from bedding materials. Nitrogen losses include direct
41 nitrous oxide emissions, volatilization of ammonia and NOX, runoff and leaching, and poultry manure used as a feed
42 supplement. More information on these losses is available in the description of the Manure Management source
43 category. For unmanaged systems, it is assumed that no N losses or additions occur prior to the application of
44 manure to the soil.
45 Monthly weather data were used as an input in the model simulations, based on an aggregation of gridded weather
46 data to the county scale from the Parameter-elevation Regressions on Independent Slopes Model (PRISM) database
47 (Daly et al. 1994). Soil attributes, which were obtained from an NRI database, were assigned based on field visits
48 and soil series descriptions. Each NRI point was run 100 times as part of the uncertainty assessment, yielding a total
180 Pasture/Range/Paddock manure additions to soils are addressed in the Grassland Remaining Grassland and Land Converted
to Grassland categories.
7-28 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 of over 18 million simulation runs for the analysis. Carbon stock estimates from Century were adjusted using a
2 structural uncertainty estimator accounting for uncertainty in model algorithms and parameter values (Ogle et al.
3 2007, 2010). C stocks and 95 percent confidence intervals were estimated for each year between 1990 and 2003, but
4 C stock changes from 2004 to 2009 were assumed to be similar to 2003 because no additional activity data are
5 currently available from the NRI for the latter years.
6 Tier 2 Approach
1 In the IPCC Tier 2 method, data on climate, soil types, land-use, and land management activity were used to classify
8 land area to apply appropriate stock change factors. MLRAs formed the base spatial unit for mapping climate
9 regions in the United States; each MLRA represents a geographic unit with relatively similar soils, climate, water
10 resources, and land uses (NRCS 1981). MLRAs were classified into climate regions according to the IPCC
11 categories using the PRISM climate database of Daly et al. (1994).
12 Reference C stocks were estimated using the National Soil Survey Characterization Database (NRCS 1997) with
13 cultivated cropland as the reference condition, rather than native vegetation as used in IPCC (2003, 2006).
14 Changing the reference condition was necessary because soil measurements under agricultural management are
15 much more common and easily identified in the National Soil Survey Characterization Database (NRCS 1997) than
16 those that are not considered cultivated cropland.
17 U. S.-specific stock change factors were derived from published literature to determine the impact of management
18 practices on SOC storage, including changes in tillage, cropping rotations and intensification, and land-use change
19 between cultivated and uncultivated conditions (Ogle et al. 2003, Ogle et al. 2006). U.S. factors associated with
20 organic matter amendments were not estimated because there were an insufficient number of studies to analyze
21 those impacts. Instead, factors from IPCC (2003) were used to estimate the effect of those activities. Euliss and
22 Gleason (2002) provided the data for computing the change in SOC storage resulting from restoration of wetland
23 enrolled in the Conservation Reserve Program.
24 Activity data were primarily based on the historical land-use/management patterns recorded in the NRI. Each NRI
25 point was classified by land use, soil type, climate region (using PRISM data, Daly et al. 1994) and management
26 condition. Classification of cropland area by tillage practice was based on data from the Conservation Tillage
27 Information Center (CTIC 1998, Towery 2001) as described above. Activity data on wetland restoration of
28 Conservation Reserve Program land were obtained from Euliss and Gleason (2002). Manure N amendments over
29 the inventory time period were based on application rates and areas amended with manure N from Edmonds et al.
30 (2003), in addition to the managed manure production data discussed in the previous methodology subsection on the
31 Tier 3 analysis for mineral soils.
32 Combining information from these data sources, SOC stocks for mineral soils were estimated 50,000 times for 1982,
33 1992, and 1997, using a Monte Carlo simulation approach and the probability distribution functions for U.S.-specific
34 stock change factors, reference C stocks, and land-use activity data (Ogle et al. 2002, Ogle et al. 2003). The annual
35 C flux for 1990 through 1992 was determined by calculating the average annual change in stocks between 1982 and
36 1992; annual C flux for 1993 through 2009 was determined by calculating the average annual change in stocks
37 between 1992 and 1997.
38 Additional Mineral C Stock Change
39 Annual C flux estimates for mineral soils between 1990 and 2009 were adjusted to account for additional C stock
40 changes associated with gains or losses in soil C after 2003 due to changes in Conservation Reserve Program
41 enrollment. The change in enrollment acreage relative to 2003 was based on data from USDA-FSA (2009) for 2004
42 through 2009, and the differences in mineral soil areas were multiplied by 0.5 metric tons C per hectare per year to
43 estimate the net effect on soil C stocks. The stock change rate is based on estimations using the IPCC method (see
44 Annex 3.13 for further discussion).
45 Organic Soil Carbon Stock Changes
46 Annual C emissions from drained organic soils in Cropland Remaining Cropland were estimated using the Tier 2
47 method provided in IPCC (2003, 2006), with U.S.-specific C loss rates (Ogle et al. 2003) rather than default IPCC
48 rates. The final estimates included a measure of uncertainty as determined from the Monte Carlo simulation with
49 50,000 iterations. Emissions were based on the 1992 and 1997 Cropland Remaining Cropland areas from the 1997
Land Use, Land Use Change, and Forestry 7-29
-------
1 National Resources Inventory (USDA-NRCS 2000). The annual flux estimated for 1992 was applied to 1990
2 through 1992, and the annual flux estimated for 1997 was applied to 1993 through 2009.
4
5
6
7
8
9
10
11
12
13
14
15
16
Uncertainty and Time-Series Consistency
Uncertainty associated with the Cropland Remaining Cropland land-use category was addressed for changes in
agricultural soil C stocks (including both mineral and organic soils). Uncertainty estimates are presented in Table
7-19 for mineral soil C stocks and organic soil C stocks disaggregated to the level of the inventory methodology
employed (i.e., Tier 2 and Tier 3). Uncertainty for the portions of the Inventory estimated with Tier 2 and 3
approaches was derived using a Monte Carlo approach (see Annex 3.13 for further discussion). A combined
uncertainty estimate for changes in soil C stocks is also included. Uncertainty estimates from each component were
combined using the error propagation equation in accordance with IPCC (2006). The combined uncertainty was
calculated by taking the square root of the sum of the squares of the standard deviations of the uncertain quantities.
More details on how the individual uncertainties were developed are in Annex 3.13. The combined uncertainty for
soil C stocks in Cropland Remaining Cropland ranged from 172 percent below to 167 percent above the 2009 stock
change estimate of -17.4 Tg CO2 Eq.
Table 7-19: Tier 2 Quantitative Uncertainty Estimates for Soil C Stock Changes occurring within Cropland
Remaining Cropland (Tg CO2 Eq. and Percent)
Source
Mineral Soil C Stocks: Cropland Remaining
Cropland, Tier 3 Inventory Methodology
Mineral Soil C Stocks: Cropland Remaining
Cropland, Tier 2 Inventory Methodology
Mineral Soil C Stocks: Cropland Remaining
Cropland (Change in CRP enrollment relative to
2003)
Organic Soil C Stocks: Cropland Remaining
Cropland, Tier 2 Inventory Methodology
Combined Uncertainty for Flux associated with
Agricultural Soil Carbon Stock Change in
Cropland Remaining Cropland
2009 Flux
Estimate
(TgC02Eq.)
(42.3)
(3.0)
(0.3)
27.7
(17.4)
Uncertainty Range Relative to Flux
Estimate
(Tg C02 Eq.) (%)
Lower
Bound
(69.6)
(6.9)
(0.1)
15.8
(47.3)
Upper Lower Upper
Bound Bound Bound
(15.1) -64% +64%
0.8 -127% +128%
(0.4) -50% +50%
36.9 -43% +33%
11.6 -172% +167%
17 Note: Parentheses indicate net sequestration. Totals may not sum due to independent rounding.
18 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
19 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
20 above.
21 QA/QC and Verification
22 Quality control measures included checking input data, model scripts, and results to ensure data were properly
23 handled throughout the inventory process. As discussed in the uncertainty section, results were compared to field
24 measurements, and a statistical relationship was developed to assess uncertainties in the model's predictive
25 capability. The comparisons included over 40 long-term experiments, representing about 800 combinations of
26 management treatments across all of the sites (Ogle et al. 2007). Inventory reporting forms and text were reviewed
27 and revised as needed to correct transcription errors.
28 Planned Improvements
29 The first improvement is to update the Tier 2 inventory analysis with the latest annual National Resources Inventory
30 (NRI) data. While the land base for the Tier 3 approach uses the latest available data from the NRI, the Tier 2
31 portion of the Inventory has not updated and is based on the Revised 1997 NRI data product (USDA-NRCS 2000).
32 This improvement will extend the time series of the land use data from 1997 through 2003 for the Tier 2 portion of
33 the Inventory.
7-30 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 The second improvement is to incorporate remote sensing in the analysis for estimation of crop and forage
2 production, and conduct the Tier 3 assessment of soil C stock changes and soil nitrous oxide emissions in a single
3 analysis. Specifically, the Enhanced Vegetation Index (EVI) product that is derived from MODIS satellite imagery
4 is being used to refine the production estimation for the Tier 3 assessment framework based on the DAYCENT
5 simulation model. EVI reflects changes in plant "greenness" over the growing season and can be used to compute
6 production based on the light use efficiency of the crop or forage (Potter etal. 1993). In the current framework,
7 production is simulated based on the weather data, soil characteristics, and the genetic potential of the crop. While
8 this method produces reasonable results, remote sensing can be used to refine the productivity estimates and reduce
9 biases in crop production and subsequent C input to soil systems. It is anticipated that precision in the Tier 3
10 assessment framework will be increased by 25 percent or more with the new method. In addition, DAYCENT is
11 currently used for estimating soil nitrous oxide emissions in the Inventory, and can also be used to estimate soil
12 organic C stock changes using the same algorithms in the CENTURY model. Simulating both soil C stock changes
13 and nitrous oxide emissions in a single analysis will ensure consistency in the treatment of these sources, which are
14 coupled through the nitrogen and carbon cycles in agricultural systems.
15 C02 Emissions from Agricultural Liming
16 IPCC (2006) recommends reporting CO2 emissions from lime additions (in the form of crushed limestone (CaCO3)
17 and dolomite (CaMg(CO3)2) to agricultural soils. Limestone and dolomite are added by land managers to ameliorate
18 acidification. When these compounds come in contact with acid soils, they degrade, thereby generating CO2. The
19 rate and ultimate magnitude of degradation of applied limestone and dolomite depends on the soil conditions,
20 climate regime, and the type of mineral applied. Emissions from liming have fluctuated over the past nineteen
21 years, ranging from 3.8 Tg CO2 Eq. to 5.0 Tg CO2 Eq. In 2009, liming of agricultural soils in the United States
22 resulted in emissions of 4.2 Tg CO2 Eq. (1.2 Tg C), representing about a 10 percent decrease in emissions since
23 1990 (see Table 7-20 and Table 7-21). The trend is driven entirely by the amount of lime and dolomite estimated to
24 have been applied to soils over the time period.
25 Table 7-20: Emissions from Liming of Agricultural Soils (Tg CO2 Eq.)
Source 1990 2000 2005 2006 2007 2008 2009
26
27
28
29
30
Liming of Soils1 4.7 4.3 4.3 4.2 4.5 5.0 4.2
Note: Shaded areas indicate values based on a combination of data and projections. All other values are based on data only.
1 Also includes emissions from liming on Land Converted to Cropland, Grassland Remaining Grassland, Land Converted to
Grassland, and Settlements Remaining Settlements.
Table 7-21: Emissions from Liming of Agricultural Soils (Tg C)
Source 1990 2000 2005 2006 2007 2008 2009
Liming of Soils1 13 L2 1.2 1.2 1.2 1.4 1.2
31 Note: Shaded areas indicate values based on a combination of data and projections. All other values are based on data only.
32 ' Also includes emissions from liming on Land Converted to Cropland, Grassland Remaining Grassland, Land Converted to
3 3 Grassland, and Settlements Remaining Settlements.
34 Methodology
35 CO2 emissions from degradation of limestone and dolomite applied to agricultural soils were estimated using a Tier
36 2 methodology consistent with IPCC (2006). The annual amounts of limestone and dolomite applied (see Table
37 7-22) were multiplied by CO2 emission factors from West and McBride (2005). These emission factors (0.059
38 metric ton C/metric ton limestone, 0.064 metric ton C/metric ton dolomite) are lower than the IPCC default emission
39 factors because they account for the portion of agricultural lime that may leach through the soil and travel by rivers
40 to the ocean (West and McBride 2005). This analysis of lime dissolution is based on liming occurring in the
41 Mississippi River basin, where the vast majority of all U.S. liming takes place (West 2008). U.S. liming that does
42 not occur in the Mississippi River basin tends to occur under similar soil and rainfall regimes, and, thus, the
43 emission factor is appropriate for use across the United States (West 2008). The annual application rates of
44 limestone and dolomite were derived from estimates and industry statistics provided in the Minerals Yearbook and
45 Mineral Industry Surveys (Tepordei 1993 through 2006; Willett 2007a, b, 2009 through 2010; USGS 2008 through
46 2010). To develop these data, the U.S. Geological Survey (USGS; U.S. Bureau of Mines prior to 1997) obtained
47 production and use information by surveying crushed stone manufacturers. Because some manufacturers were
48 reluctant to provide information, the estimates of total crushed limestone and dolomite production and use were
Land Use, Land Use Change, and Forestry 7-31
-------
1 divided into three components: (1) production by end-use, as reported by manufacturers (i.e., "specified"
2 production); (2) production reported by manufacturers without end-uses specified (i.e., "unspecified" production);
3 and (3) estimated additional production by manufacturers who did not respond to the survey (i.e., "estimated"
4 production).
5 The "unspecified" and "estimated" amounts of crushed limestone and dolomite applied to agricultural soils were
6 calculated by multiplying the percentage of total "specified" limestone and dolomite production applied to
7 agricultural soils by the total amounts of "unspecified" and "estimated" limestone and dolomite production. In other
8 words, the proportion of total "unspecified" and "estimated" crushed limestone and dolomite that was applied to
9 agricultural soils (as opposed to other uses of the stone) was assumed to be proportionate to the amount of
10 "specified" crushed limestone and dolomite that was applied to agricultural soils. In addition, data were not
11 available for 1990, 1992, and 2009 on the fractions of total crushed stone production that were limestone and
12 dolomite, and on the fractions of limestone and dolomite production that were applied to soils. To estimate the 1990
13 and 1992 data, a set of average fractions were calculated using the 1991 and 1993 data. These average fractions
14 were applied to the quantity of "total crushed stone produced or used" reported for 1990 and 1992 in the 1994
15 Minerals Yearbook (Tepordei 1996). To estimate 2009 data, the previous year's fractions were applied to a 2009
16 estimate of total crushed stone presented in the USGS Mineral Industry Surveys: Crushed Stone and Sand and
17 Gravel in the First Quarter of 2010 (USGS 2010); thus, the 2009 data in Table 7-20 through Table 7-22 are shaded
18 to indicate that they are based on a combination of data and projections.
19 The primary source for limestone and dolomite activity data is the Minerals Yearbook, published by the Bureau of
20 Mines through 1994 and by the USGS from 1995 to the present. In 1994, the "Crushed Stone" chapter in the
21 Minerals Yearbook began rounding (to the nearest thousand metric tons) quantities for total crushed stone produced
22 or used. It then reported revised (rounded) quantities for each of the years from 1990 to 1993. In order to minimize
23 the inconsistencies in the activity data, these revised production numbers have been used in all of the subsequent
24 calculations. Since limestone and dolomite activity data are also available at the state level, the national-level
25 estimates reported here were broken out by state, although state-level estimates are not reported here.
26 Table 7-22: Applied Minerals (Million Metric Tons)
Mineral
Limestone
Dolomite
1990
19.01
2.36
2000
15.86
3.81
2005
18.09
1.85
2006
16.54
2.73
2007
17.46
2.92
2008
20.55
2.54
2009
17.20
2.13
27 Note: These numbers represent amounts applied to Cropland Remaining Cropland, Land Converted to Cropland, Grassland
28 Remaining Grassland, Land Converted to Grassland, and Settlements Remaining Settlements. Shaded areas indicate values
29 based on a combination of data and projections. All other values are based on data only.
30
31 Uncertainty and Time-Series Consistency
32 Uncertainty regarding limestone and dolomite activity data inputs was estimated at ±15 percent and assumed to be
33 uniformly distributed around the inventory estimate (Tepordei 2003b). Analysis of the uncertainty associated with
34 the emission factors included the following: the fraction of agricultural lime dissolved by nitric acid versus the
35 fraction that reacts with carbonic acid, and the portion of bicarbonate that leaches through the soil and is transported
36 to the ocean. Uncertainty regarding the time associated with leaching and transport was not accounted for, but
37 should not change the uncertainty associated with CO2 emissions (West 2005). The uncertainties associated with the
3 8 fraction of agricultural lime dissolved by nitric acid and the portion of bicarbonate that leaches through the soil were
39 each modeled as a smoothed triangular distribution between ranges of zero percent to 100 percent. The uncertainty
40 surrounding these two components largely drives the overall uncertainty estimates reported below. More
41 information on the uncertainty estimates for Liming of Agricultural Soils is contained within the Uncertainty Annex.
42 A Monte Carlo (Tier 2) uncertainty analysis was applied to estimate the uncertainty of CO2 emissions from liming.
43 The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 7-23. CO2 emissions from
44 Liming of Agricultural Soils in 2008 were estimated to be between 0.1 and 8.4 Tg CO2 Eq. at the 95 percent
45 confidence level. This indicates a range of 97 percent below to 99 percent above the 2009 emission estimate of 4.2
46 Tg C02 Eq.
47
48
7-32 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Table 7-23: Tier 2 Quantitative Uncertainty Estimates for CO2 Emissions from Liming of Agricultural Soils (Tg
2 CO2 Eq. and Percent)
2009 Emission
Source Estimate
Gas (Tg CO2 Eq.)
Uncertainty Range Relative to Emissions
Estimate3
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Liming of Agricultural Soils1 CO2 4.2
0.1 8.4 -97% +99%
3 aRange of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
4 ' Also includes emissions from liming on Land Converted to Cropland, Grassland Remaining Grassland, Land Converted to
5 Grassland, and Settlements Remaining Settlements.
6 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
7 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
8 above.
9 QA/QC and Verification
10 A QA/QC analysis was performed for data gathering and input, documentation, and calculation. The QA/QC
11 analysis did not reveal any inaccuracies or incorrect input values.
12 Recalculations Discussion
13 Several adjustments were made in the current Inventory to improve the results. The quantity of applied minerals
14 reported in the previous Inventory for 2007 has been revised; the updated activity data for 2007 are approximately
15 1,480 thousand metric tons greater than the data used last year, consequently, the reported emissions resulting from
16 liming in 2007 increased by about 8.4 percent. In the previous Inventory, to estimate 2008 data, the previous year's
17 fractions were applied to a 2008 estimate of total crushed stone presented in the USGS Mineral Industry Surveys:
18 Crushed Stone and Sand and Gravel in the First Quarter of 2009 (USGS 2009). Since publication of the previous
19 Inventory, the Minerals Yearbook has published actual quantities of crushed stone sold or used by producers in the
20 United States in 2008. These values have replaced those used in the previous Inventory to calculate the quantity of
21 minerals applied to soil and the emissions from liming. The updated activity data for 2008 are approximately 5,460
22 thousand metric tons greater than the data used in the previous Inventory. As a result, the reported emissions from
23 liming in 2008 increased by about 36 percent.
24 C02 Emissions from Urea Fertilization
25 The use of urea (CO(NH2)2) as fertilizer leads to emissions of CO2 that was fixed during the industrial production
26 process. Urea in the presence of water and urease enzymes is converted into ammonium (NH4+), hydroxyl ion
27 (OH"), and bicarbonate (HCO3~). The bicarbonate then evolves into CO2 and water. Emissions from urea
28 fertilization in the United States totaled 3.6 Tg CO2 Eq. (1.0 Tg C) in 2009 (Table 7-24 and Table 7-25). Emissions
29 from urea fertilization have grown 49 percent between 1990 and 2009, due to an increase in the use of urea as
30 fertilizer.
31 Table 7-24: CO2 Emissions from Urea Fertilization in Cropland Remaining, Cropland (Tg CO2 Eq.)
Source 1990 2000 2005 2006 2007 2008 2009
Urea Fertilization1 2.4 3.2 3.5 3.7 3.7 3.6 3.6
32 Note: Shaded areas indicate values based on a combination of data and projections. All other values are based on data only.
33 ' Also includes emissions from urea fertilization on Land Converted to Cropland, Grassland Remaining Grassland, Land
3 4 Converted to Grassland, Settlements Remaining Settlements, and Forest Land Remaining Forest Land.
35
36 Table 7-25: CO2 Emissions from Urea Fertilization in Cropland Remaining Cropland (Tg C)
Source 1990 2000 2005 2006 2007 2008 2009
Urea Fertilization1 (XT 0.9 1.0 1.0 1.0 1.0 1.0
37 Note: Shaded areas indicate values based on a combination of data and projections. All other values are based on data only.
38 ' Also includes emissions from urea fertilization on Land Converted to Cropland, Grassland Remaining Grassland, Land
3 9 Converted to Grassland, Settlements Remaining Settlements, and Forest Land Remaining Forest Land.
Land Use, Land Use Change, and Forestry 7-33
-------
1 Methodology
2 Carbon dioxide emissions from the application of urea to agricultural soils were estimated using the IPCC (2006)
3 Tier 1 methodology. The annual amounts of urea fertilizer applied (see Table 7-26) were derived from state-level
4 fertilizer sales data provided in Commercial Fertilizers (TVA 1991, 1992, 1993, 1994; AAPFCO 1995 through
5 2010) and were multiplied by the default IPCC (2006) emission factor of 0.20, which is equal to the C content of
6 urea on an atomic weight basis. Because fertilizer sales data are reported in fertilizer years (July through June), a
7 calculation was performed to convert the data to calendar years (January through December). According to historic
8 monthly fertilizer use data (TVA 1992b), 65 percent of total fertilizer used in any fertilizer year is applied between
9 January and June of that calendar year, and 3 5 percent of total fertilizer used in any fertilizer year is applied between
10 July and December of the previous calendar year. Fertilizer sales data for the 2009 fertilizer year were not available
11 in time for publication. Accordingly, urea application in the 2009 fertilizer year was assumed to be equal to that of
12 the 2008 fertilizer year. Since 2010 fertilizer year data were not available, July through December 2009 fertilizer
13 consumption was assumed to be equal to July through December 2008 fertilizer consumption; thus, the 2009 data in
14 Table 7-24 through Table 7-26 are shaded to indicate that they are based on a combination of data and projections.
15 State-level estimates of CO2 emissions from the application of urea to agricultural soils were summed to estimate
16 total emissions for the entire United States.
17 Table 7-26: Applied Urea (Million Metric Tons)
1990 2000 2005 2006 2007 2008 2009
Urea Fertilizer1 3.30 4.38 4.78 4.98 5.10 4.92 4.92
18 Note: Shaded areas indicate values based on a combination of data and projections. All other values are based on data only.
19 'These numbers represent amounts applied to all agricultural land, including Land Converted to Cropland, Grassland Remaining
20 Grassland, Land Converted to Grassland, Settlements Remaining Settlements, and Forest Land Remaining Forest Land.
21 Uncertainty and Time-Series Consistency
22 Uncertainty estimates are presented in Table 7-27 for Urea Fertilization. A Tier 2 Monte Carlo analysis was
23 completed. The largest source of uncertainty was the default emission factor, which assumes that 100 percent of the
24 C applied to soils is ultimately emitted into the environment as CO2. This factor does not incorporate the possibility
25 that some of the C may be retained in the soil. The emission estimate is, thus, likely to be high. In addition, each
26 urea consumption data point has an associated uncertainty. Urea for non-fertilizer use, such as aircraft deicing, may
27 be included in consumption totals; it was determined through personal communication with Fertilizer Regulatory
28 Program Coordinator David L. Terry (2007), however, that this amount is most likely very small. Research into
29 aircraft deicing practices also confirmed that urea is used minimally in the industry; a 1992 survey found a known
30 annual usage of approximately 2,000 tons of urea for deicing; this would constitute 0.06 percent of the 1992
31 consumption of urea (EPA 2000). Similarly, surveys conducted from 2002 to 2005 indicate that total urea use for
32 deicing at U.S. airports is estimated to be 3,740 MT peryear, or less than 0.07 percent of the fertilizer total for 2007
33 (Itle 2009). Lastly, there is uncertainty surrounding the assumptions behind the calculation that converts fertilizer
34 years to calendar years. CO2 emissions from urea fertilization of agricultural soils in 2009 were estimated to be
35 between 2.1 and 3.7 Tg CO2Eq. at the 95 percent confidence level. This indicates a range of 43 percent below to 3
36 percent above the 2009 emission estimate of 3.6 Tg CO2 Eq.
37 Table 7-27: Quantitative Uncertainty Estimates for CO2 Emissions from Urea Fertilization (Tg CO2 Eq. and Percent)
2009 Emission
Estimate Uncertainty Range Relative to Emissions Estimate"
Source Gas (Tg CO2 Eq.) (Tg CO2 Eq.) (%)
Urea Fertilization
CO2 3.6
Lower Upper Lower
Bound Bound Bound
2.1 3.7 -43%
Upper
Bound
+3%
38 aRange of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
39 Note: These numbers represent amounts applied to all agricultural land, including Land Converted to Cropland, Grassland
40 Remaining Grassland, Land Converted to Grassland, Settlements Remaining Settlements, and Forest Land Remaining Forest
41 Land.
42 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
43 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
44 above.
7-34 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 QA/QC and Verification
2 A QA/QC analysis was performed for data gathering and input, documentation, and calculation. Inventory reporting
3 forms and text were reviewed. No errors were found.
4 Recalculations Discussion
5 July to December 2007 urea application data were updated with assumptions for fertilizer year 2008, and the 2007
6 emission estimate was revised accordingly. The activity data decreased about 800,000 metric tons for 2007 and this
7 change resulted in an approximately 3 percent decrease in emissions in 2007 relative to the previous Inventory. In
8 the previous Inventory, the application for this period was calculated based on application during July to December
9 2006. January to June 2008 data were also used to update 2008 emission estimates. The activity data decreased
10 about 270,000 metric tons for 2008, resulting in an approximately 5 percent decrease in emissions in 2008 relative to
11 the previous Inventory.
12 Planned Improvements
13 The primary planned improvement is to investigate using a Tier 2 or Tier 3 approach, which would utilize country -
14 specific information to estimate a more precise emission factor.
15 7.5. Land Converted to Cropland (IPCC Source Category 5B2)
16 Land Converted to Cropland includes all cropland in an inventory year that had been another land use at any point
17 during the previous 20 years181 according to the USDA NRI land-use survey (USDA-NRCS 2000). Consequently,
18 lands are retained in this category for 20 years as recommended by the IPCC guidelines (IPCC 2006) unless there is
19 another land-use change. The Inventory includes all privately-owned croplands in the conterminous United States
20 and Hawaii, but there is a minor amount of cropland on federal lands that is not currently included in the estimation
21 of C stock changes, leading to a discrepancy between the total amount of managed area in Land Converted to
22 Cropland (see Section 7.1) and the cropland area included in the Inventory. It is important to note that plans are
23 being made to include these areas in future C inventories.
24 Background on agricultural C stock changes is provided in Cropland Remaining Cropland and will only be
25 summarized here for Land Converted to Cropland. Soils are the largest pool of C in agricultural land, and also have
26 the greatest potential for storage or release of C, because biomass and dead organic matter C pools are relatively
27 small and ephemeral compared with soils. The IPCC (2006) recommends reporting changes in soil organic C stocks
28 due to: (1) agricultural land-use and management activities on mineral soils, and (2) agricultural land-use and
29 management activities on organic soils.182
30 Land-use and management of mineral soils in Land Converted to Cropland generally led to relatively small
31 increases in soil C during the 1990s but the pattern changed to small losses of C through the latter part of the time
32 series (Table 7-28 and Table 7-29). The total rate of change in soil C stocks was 5.9 Tg CO2 Eq. (1.6 Tg C) in 2009.
33 Mineral soils were estimated to lose 3.3 Tg CO2 Eq. (0.9 Tg C) in 2009, while drainage and cultivation of organic
34 soils led to annual losses of 2.6 Tg CO2 Eq. (0.7 Tg C) in 2009.
35 Table 7-28: Net CO2 Flux from Soil C Stock Changes in Land Converted to Cropland (Tg CO2 Eq.)
Soil Type 1990 2000 2005 2006 2007 2008 2009
Mineral Soils (0.3) (0.3) 3.3 3.3 3.3 3.3 3.3
Organic Soils 2A 2.6 2.6 2.6 2.6 2.6 2.6
Total Net Flux 2.2 2.4 5.9 5.9 5.9 5.9 5.9
36 Note: Parentheses indicate net sequestration. Shaded areas indicate values based on a combination of historical data and
37 projections. All other values are based on historical data only. Totals may not sum due to independent rounding.
38
39 Table 7-29: Net CO2 Flux from Soil C Stock Changes in Land Converted to Cropland (Tg C)
181 NRI points were classified according to land-use history records starting in 1982 when the NRI survey began, and
consequently the classifications were based on less than 20 years from 1990 to 2001.
182 CO2 emissions associated with liming are also estimated but included in a separate section of the report.
Land Use, Land Use Change, and Forestry 7-35
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Soil Type 1990 2000 2005 2006 2007 2008 2009
Mineral Soils (0.1) (0.1) 0.9 0.9 0.9 0.9 0.9
Organic Soils 0/7 0/7 0.7 0.7 0.7 0.7 0.7
Total Net Flux 0.6 0.6 1.6 1.6 1.6 1.6 1.6
1 Note: Parentheses indicate net sequestration. Shaded areas indicate values based on a combination of historical data and
2 projections. All other values are based on historical data only. Totals may not sum due to independent rounding.
o
J
4 The spatial variability in annual CO2 flux associated with C stock changes in mineral and organic soils for Land
5 Converted to Cropland is displayed in Figure 7-7 and Figure 7-8. While a large portion of the United States had net
6 losses of soil C for Land Converted to Cropland, there were some notable areas with net C accumulation in the
7 Great Plains, Midwest, mid-Atlantic states. These areas were gaining C following conversion, because the land had
8 been brought into hay production, including grass and legume hay, leading to enhanced plant production relative to
9 the previous land use, and thus higher C input to the soil. Emissions from organic soils were largest in California,
10 Florida, and the upper Midwest, which coincided with largest concentrations of cultivated organic soils in the United
11 States.
12
13 Figure 7-7: Total Net Annual CO2 Flux for Mineral Soils under Agricultural Management within States, 2009,
14 Land Converted to Cropland
15
16 Figure 7-8: Total Net Annual CO2 Flux for Organic Soils under Agricultural Management within States, 2009, Land
17 Converted to Cropland
18
19 Methodology
20 The following section includes a brief description of the methodology used to estimate changes in soil C stocks due
21 to agricultural land-use and management activities on mineral and organic soils for Land Converted to Cropland.
22 Further elaboration on the methodologies and data used to estimate stock changes for mineral and organic soils are
23 provided in the Cropland Remaining Cropland section and Annex 3.13.
24 Soil C stock changes were estimated for Land Converted to Cropland according to land-use histories recorded in the
25 USDA NRI survey (USDA-NRCS 2000). Land-use and some management information (e.g., crop type, soil
26 attributes, and irrigation) were originally collected for each NRI point on a 5-year cycle beginning in 1982.
27 However, the NRI program initiated annual data collection in 1998, and the annual data are currently available
28 through 2003. NRI points were classified as Land Converted to Cropland in a given year between 1990 and 2009 if
29 the land use was cropland but had been another use during the previous 20 years. Cropland includes all land used to
30 produce food or fiber, or forage that is harvested and used as feed (e.g., hay and silage).
31 Mineral Soil Carbon Stock Changes
32 A Tier 3 model-based approach was applied to estimate C stock changes for soils on Land Converted to Cropland
33 used to produce a majority of all crops (Ogle et al. 2010). Soil C stock changes on the remaining soils were
34 estimated with the IPCC Tier 2 method (Ogle et al. 2003), including land used to produce vegetable, tobacco,
35 perennial/horticultural crops, and rice; land on very gravelly, cobbly, or shaley soils (greater than 35 percent by
36 volume); and land converted from forest or federal ownership.183
37 Tier 3 Approach
38 Mineral SOC stocks and stock changes were estimated using the Century biogeochemical model for the Tier 3
183 pgderal jancj js not a land US6j but rather an ownership designation that is treated as forest or nominal grassland for purposes
of these calculations. The specific use for federal lands is not identified in the NRI survey (USDA-NRCS 2000).
7-36 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 methods. National estimates were obtained by using the model to simulate historical land-use change patterns as
2 recorded in the USDA National Resources Inventory (USDA-NRCS 2000). The methods used for Land Converted
3 to Cropland are the same as those described in the Tier 3 portion of Cropland Remaining Cropland section for
4 mineral soils (see Cropland Remaining Cropland Tier 3 methods section and Annex 3.13 for additional
5 information).
6 Tier 2 Approach
7 For the mineral soils not included in the Tier 3 analysis, SOC stock changes were estimated using a Tier 2 Approach
8 for Land Converted to Cropland as described in the Tier 2 portion of Cropland Remaining Cropland section for
9 mineral soils (see Cropland Remaining Cropland Tier 2 methods section for additional information).
10 Organic Soil Carbon Stock Changes
11 Annual C emissions from drained organic soils in Land Converted to Cropland were estimated using the Tier 2
12 method provided in IPCC (2003, 2006), with U.S.-specific C loss rates (Ogle et al. 2003) rather than default IPCC
13 rates. The final estimates included a measure of uncertainty as determined from the Monte Carlo simulation with
14 50,000 iterations. Emissions were based on the 1992 and 1997 Land Converted to Cropland areas from the 1997
15 National Resources Inventory (USDA-NRCS 2000). The annual flux estimated for 1992 was applied to 1990
16 through 1992, and the annual flux estimated for 1997 was applied to 1993 through 2009.
17 Uncertainty and Time-Series Consistency
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
Uncertainty analysis for mineral soil C stock changes using the Tier 3 and Tier 2 approaches were based on the same
method described for Cropland Remaining Cropland, except that the uncertainty inherent in the structure of the
Century model was not addressed. The uncertainty for annual C emission estimates from drained organic soils in
Land Converted to Cropland was estimated using the Tier 2 approach, as described in the Cropland Remaining
Cropland section.
Uncertainty estimates are presented in Table 7-30 for each subsource (i.e., mineral soil C stocks and organic soil C
stocks) disaggregated to the level of the inventory methodology employed (i.e., Tier 2 and Tier 3). Uncertainty for
the portions of the Inventory estimated with Tier 2 and 3 approaches was derived using a Monte Carlo approach (see
Annex 3.13 for further discussion). A combined uncertainty estimate for changes in agricultural soil C stocks is also
included. Uncertainty estimates from each component were combined using the error propagation equation in
accordance with IPCC (2006), i.e., by taking the square root of the sum of the squares of the standard deviations of
the uncertain quantities. The combined uncertainty for soil C stocks in Land Converted to Cropland was estimated
to be 40 percent below and 36 percent above the inventory estimate of 5.9 Tg CO2 Eq.
Table 7-30: Tier 2 Quantitative Uncertainty Estimates for Soil C Stock Changes occurring within Land Converted to
Cropland (Tg CO2 Eq. and Percent)
Source
2009 Flux Uncertainty Range Relative to Flux
Estimate Estimate
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Mineral Soil C Stocks: Land Converted to
Cropland, Tier 3 Inventory Methodology
Mineral Soil C Stocks: Land Converted to
Cropland, Tier 2 Inventory Methodology
Organic Soil C Stocks: Land Converted to
Cropland, Tier 2 Inventory Methodology
(0.8)
4.1
2.6
(1.5)
2.3
1.2
(0.1)
5.8
3.7
-84%
-44%
-53%
+84%
+41%
+41%
Combined Uncertainty for Flux associated
with Soil Carbon Stock Change in Land
Converted to Cropland
5.9
3.5
8.1
-40%
+36%
33 Note: Parentheses indicate net sequestration. Totals may not sum due to independent rounding.
34 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
35 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
Land Use, Land Use Change, and Forestry 7-37
-------
1 above.
2 QA/QC and Verification
3 See QA/QC and Verification section under Cropland Remaining Cropland.
4 Planned Improvements
5 The empirically-based uncertainty estimator described in the Cropland Remaining Cropland section for the Tier 3
6 approach has not been developed to estimate uncertainties related to the structure of the Century model for Land
1 Converted to Cropland, but this is a planned improvement. This improvement will produce a more rigorous
8 assessment of uncertainty. See Planned Improvements section under Cropland Remaining Cropland^ additional
9 planned improvements.
10 7.6. Grassland Remaining Grassland (IPCC Source Category 5C1)
11 Grassland Remaining Grassland includes all grassland in an inventory year that had been grassland for the previous
12 20 years184 according to the USDA NRI land use survey (USDA-NRCS 2000). The Inventory includes all
13 privately-owned grasslands in the conterminous United States and Hawaii, but does not address changes in C stocks
14 for grasslands on federal lands, leading to a discrepancy between the total amount of managed area in Grassland
15 Remaining Grassland (see Section 7.1) and the grassland area included in the Inventory. While federal grasslands
16 probably have minimal changes in land management and C stocks, plans are being made to further evaluate and
17 potentially include these areas in future C inventories.
18 Background on agricultural C stock changes is provided in the Cropland Remaining Cropland section and will only
19 be summarized here for Grassland Remaining Grassland. Soils are the largest pool of C in agricultural land, and
20 also have the greatest potential for storage or release of C, because biomass and dead organic matter C pools are
21 relatively small and ephemeral compared to soils. IPCC (2006) recommends reporting changes in soil organic C
22 stocks due to: (1) agricultural land-use and management activities on mineral soils, and (2) agricultural land-use and
23 management activities on organic soils.185
24 Land-use and management of mineral soils in Grassland Remaining Grassland increased soil C, while organic soils
25 lost relatively small amounts of C in each year 1990 through 2009. Due to the pattern for mineral soils, the overall
26 trend was a gain in soil C over the time series although the rates varied from year to year, with a net removal of 8.3
27 Tg CO2 Eq. (2.3 Tg C) in 2009. There was considerable variation over the time series driven by variability in
28 weather patterns and associated interaction with land management activity. The change rates on per hectare basis
29 were small, however, even in the years with larger total changes in stocks. Overall, flux rates declined by 43.8 Tg
30 CO2 Eq. (12.0 Tg C) when comparing the net change in soil C for 1990 and 2009.
31 Table 7-31: Net CO2 Flux from Soil C Stock Changes in Grassland Remaining Grassland (Tg CO2 Eq.)
Soil Type 1990 2000 2005 2006 2007 2008 2009
Mineral Soils (56.0) (56.3) (12.6) (12.4) (12.3) (12.2) (12.0)
Organic Soils 3.9 3/7 3.7 3.7 3.7 3.7 3.7
Total Net Flux (52.2) (52.6) (8.9) (8.8) (8.6) (8.5) (8.3)
32 Note: Parentheses indicate net sequestration. Shaded areas indicate values based on a combination of historical data and
33 projections. All other values are based on historical data only. Totals may not sum due to independent rounding.
34
35 Table 7-32: Net CO2 Flux from Soil C Stock Changes in Grassland Remaining Grassland (Tg C)
Soil Type
Mineral Soils
Organic Soils
Total Net Flux
1990
(15.3)
1.1
(14.2)
2000
(15.3)
1.0
(14.3)
2005
(3.4)
1.0
(2.4)
2006
(3.4)
1.0
(2.4)
2007
(3.4)
1.0
(2.3)
2008
(3.3)
1.0
(2.3)
2009
(3.3)
1.0
(2.3)
184 NRI points were classified according to land-use history records starting in 1982 when the NRI survey began, and
consequently the classifications were based on less than 20 years from 1990 to 2001.
185 CO2 emissions associated with liming are also estimated but included in a separate section of the report.
7-38 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Note: Parentheses indicate net sequestration. Shaded areas indicate values based on a combination of historical data and
2 projections. All other values are based on historical data only. Totals may not sum due to independent rounding.
o
J
4 The spatial variability in annual CO2 flux associated with C stock changes in mineral and organic soils is displayed
5 in Figure 7-9 and Figure 7-10. Grassland gained soil organic C in several regions during 2009, including the
6 Northeast, Midwest, Southwest and far western states; although these were relatively small increases in C on a per-
7 hectare basis. Emission rates from drained organic soils were highest along the southeastern coastal region, in the
8 northeast central United States surrounding the Great Lakes, and along the central and northern portions of the West
9 Coast.
10
11 Figure 7-9: Total Net Annual CO2 Flux for Mineral Soils under Agricultural Management within States, 2009,
12 Grassland Remaining Grassland
13
14 Figure 7-10: Total Net Annual CO2 Flux for Organic Soils under Agricultural Management within States, 2009,
15 Grassland Remaining Grassland
16
17 Methodology
18 The following section includes a brief description of the methodology used to estimate changes in soil C stocks due
19 to agricultural land-use and management activities on mineral and organic soils for Grassland Remaining
20 Grassland. Further elaboration on the methodologies and data used to estimate stock changes from mineral and
21 organic soils are provided in the Cropland Remaining Cropland section and Annex 3.13.
22 Soil C stock changes were estimated for Grassland Remaining Grassland according to land-use histories recorded in
23 the USDA NRI survey (USDA-NRCS 2000). Land-use and some management information (e.g., crop type, soil
24 attributes, and irrigation) were originally collected for each NRI point on a 5-year cycle beginning in 1982.
25 However, the NRI program initiated annual data collection in 1998, and the annual data are currently available
26 through 2003. NRI points were classified as Grassland Remaining Grassland in a given year between 1990 and
27 2009 if the land use had been grassland for 20 years. Grassland includes pasture and rangeland used for grass forage
28 production, where the primary use is livestock grazing. Rangelands are typically extensive areas of native grassland
29 that are not intensively managed, while pastures are often seeded grassland, possibly following tree removal, that
30 may or may not be improved with practices such as irrigation and interseeding legumes.
31 Mineral Soil Carbon Stock Changes
32 An IPCC Tier 3 model-based approach was applied to estimate C stock changes for most mineral soils in Grassland
33 Remaining Grassland. The C stock changes for the remaining soils were estimated with an IPCC Tier 2 method
34 (Ogle et al. 2003), including gravelly, cobbly, or shaley soils (greater than 35 percent by volume) and additional
35 stock changes associated with sewage sludge amendments.
36 Tier 3 Approach
37 Mineral soil organic C stocks and stock changes for Grassland Remaining Grassland were estimated using the
38 Century biogeochemical model, as described in Cropland Remaining Cropland. Historical land-use and
39 management patterns were used in the Century simulations as recorded in the USDA National Resources Inventory
40 (NRI) survey, with supplemental information on fertilizer use and rates from the USDA Economic Research Service
41 Cropping Practices Survey (ERS 1997) and National Agricultural Statistics Service (NASS 1992, 1999, 2004).
42 Frequency and rates of manure application to grassland during 1997 were estimated from data compiled by the
43 USDA Natural Resources Conservation Service (Edmonds, et al. 2003), and then adjusted using county-level
44 estimates of manure available for application in other years. Specifically, county-scale ratios of manure available
45 for application to soils in other years relative to 1997 were used to adjust the area amended with manure (see Annex
46 3.13 for further details). Greater availability of managed manure N relative to 1997 was, thus, assumed to increase
47 the area amended with manure, while reduced availability of manure N relative to 1997 was assumed to reduce the
Land Use, Land Use Change, and Forestry 7-39
-------
amended area.
2 The amount of manure produced by each livestock type was calculated for managed and unmanaged waste
3 management systems based on methods described in the Manure Management Section (Section 6.2) and Annex
4 (Annex 3.10). In contrast to manure amendments, Pasture/Range/Paddock (PRP) manure N deposition was
5 estimated internally in the Century model, as part of the grassland system simulations (i.e., PRP manure deposition
6 was not an external input into the model). See the Tier 3 methods in Cropland Remaining Cropland section for
7 additional discussion on the Tier 3 methodology for mineral soils.
8 Tier 2 Approach
9 The Tier 2 approach is based on the same methods described in the Tier 2 portion of Cropland Remaining Cropland
10 section for mineral soils (see Cropland Remaining Cropland Tier 2 methods section and Annex 3.13 for additional
11 information).
12 Additional Mineral C Stock Change Calculations
13 Annual C flux estimates for mineral soils between 1990 and 2009 were adjusted to account for additional C stock
14 changes associated with sewage sludge amendments using a Tier 2 method. Estimates of the amounts of sewage
15 sludge N applied to agricultural land were derived from national data on sewage sludge generation, disposition, and
16 nitrogen content. Total sewage sludge generation data for 1988, 1996, and 1998, in dry mass units, were obtained
17 from an EPA report (EPA 1999) and estimates for 2004 were obtained from an independent national biosolids
18 survey (NEBRA 2007). These values were linearly interpolated to estimate values for the intervening years. N
19 application rates from Kellogg et al. (2000) were used to determine the amount of area receiving sludge
20 amendments. Although sewage sludge can be added to land managed for other land uses, it was assumed that
21 agricultural amendments occur in grassland. Cropland is assumed to rarely be amended with sewage sludge due to
22 the high metal content and other pollutants in human waste. The soil C storage rate was estimated at 0.38 metric
23 tons C per hectare per year for sewage sludge amendments to grassland. The stock change rate is based on country -
24 specific factors and the IPCC default method (see Annex 3.13 for further discussion).
25 Organic Soil Carbon Stock Changes
26 Annual C emissions from drained organic soils in Grassland Remaining Grassland were estimated using the Tier 2
27 method provided in IPCC (2003, 2006), which utilizes U.S.-specific C loss rates (Ogle et al. 2003) rather than
28 default IPCC rates. Emissions were based on the 1992 and 1997 Grassland Remaining Grassland areas from the
29 1997 National Resources Inventory (USDA-NRCS 2000). The annual flux estimated for 1992 was applied to 1990
30 through 1992, and the annual flux estimated for 1997 was applied to 1993 through 2009.
31 Uncertainty and Time-Series Consistency
32 Uncertainty estimates are presented in Table 7-33 for each subsource (i.e., mineral soil C stocks and organic soil C
33 stocks) disaggregated to the level of the inventory methodology employed (i.e., Tier 2 and Tier 3). Uncertainty for
34 the portions of the Inventory estimated with Tier 2 and 3 approaches was derived using a Monte Carlo approach (see
35 Annex 3.13 for further discussion). A combined uncertainty estimate for changes in agricultural soil C stocks is also
36 included. Uncertainty estimates from each component were combined using the error propagation equation in
37 accordance with IPCC (2006), i.e., by taking the square root of the sum of the squares of the standard deviations of
38 the uncertain quantities. The combined uncertainty for soil C stocks in Grassland Remaining Grassland was
39 estimated to be 32 percent below and 25 percent above the inventory estimate of -8.3 Tg CO2 Eq.
40 Table 7-33: Tier 2 Quantitative Uncertainty Estimates for C Stock Changes occurring within Grassland Remaining
41 Grassland (Tg CO2 Eq. and Percent)
2009 Flux Uncertainty Range Relative to Flux
Estimate Estimate
Source (Tg CO2 Eq.) (Tg CO2 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Mineral Soil C Stocks Grassland Remaining
Grassland, Tier 3 Methodology
(10.6)
(11.4)
(9.8)
-7%
+7%
7-40 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Mineral Soil C Stocks: Grassland Remaining
Grassland, Tier 2 Methodology (0.2)
Mineral Soil C Stocks: Grassland Remaining
Grassland, Tier 2 Methodology (Change in Soil
C due to Sewage Sludge Amendments) (1.2)
Organic Soil C Stocks: Grassland Remaining
Grassland, Tier 2 Methodology 3.7
(0.3)
0.0
-89% +127%
(1.9) (0.6) -50% +50%
1.2 5.5 -66% +49%
1
Combined Uncertainty for Flux Associated
with Agricultural Soil Carbon Stock Change
in Grassland Remaining Grassland
(8.3)
(11.0) (6.3) -32% +25%
Note: Parentheses indicate net sequestration. Totals may not sum due to independent rounding.
2 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
3 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
4 above.
5 Uncertainties in Mineral Soil Carbon Stock Changes
6 The uncertainty analysis for Grassland Remaining Grassland using the Tier 3 approach and Tier 2 approach were
7 based on the same method described for Cropland Remaining Cropland, except that the uncertainty inherent in the
8 structure of the Century model was not addressed. See the Tier 3 approach for mineral soils under the Cropland
9 Remaining Cropland section for additional discussion.
10 A ±50 percent uncertainty was assumed for additional adjustments to the soil C stocks between 1990 and 2009 to
11 account for additional C stock changes associated with amending grassland soils with sewage sludge.
12 Uncertainties in Soil Carbon Stock Changes for Organic Soils
13 Uncertainty in C emissions from organic soils was estimated using country-specific factors and a Monte Carlo
14 analysis. Probability distribution functions for emission factors were derived from a synthesis of 10 studies, and
15 combined with uncertainties in the NRI land use and management data for organic soils in the Monte Carlo analysis.
16 See the Tier 2 section under minerals soils of Cropland Remaining Cropland for additional discussion.
17 QA/QC and Verification
18 Quality control measures included checking input data, model scripts, and results to ensure data were properly
19 handled through the inventory process. A minor error was found in the post-processing results to compute the final
20 totals, which was corrected. No additional errors were found through quality control.
21 Recalculations Discussion
22 There were minor changes in the estimated area of grasslands associated with reconciling the forestland areas from
23 the Forest Inventory and Analysis (FIA) survey with the data from the National Resources Inventory (NRI) (see
24 section 7.1 for more information. The revised areas led to small changes in the soil C stock changes for Grassland
25 Remaining Grassland.
26 Planned Improvements
27 The main planned improvement for the next Inventory is to integrate the assessments of soil C stock changes and
28 soil N2O emissions into a single analysis. This improvement will ensure that the N and C cycles are treated
29 consistently in the Inventory, which is important because the cycles of these elements are linked through plant and
30 soil processes in agricultural lands. This improvement will include the development of an empirically-based
31 uncertainty analysis, which will provide a more rigorous assessment of uncertainty. See Planned Improvements
32 section under Cropland Remaining Cropland for additional planned improvements.
Land Use, Land Use Change, and Forestry 7-41
-------
i 7.7. Land Converted to Grassland (IPCC Source Category 5C2)
2 Land Converted to Grassland includes all grassland in an inventory year that had been in another land use at any
3 point during the previous 20 years186 according to the USDA NRI land-use survey (USDA-NRCS 2000).
4 Consequently, lands are retained in this category for 20 years as recommended by IPCC (2006) unless there is
5 another land use change. The Inventory includes all privately-owned grasslands in the conterminous United States
6 and Hawaii, but does not address changes in C stocks for grasslands on federal lands, leading to a discrepancy
7 between the total amount of managed area for Land Converted to Grassland (see Section 7.1) and the grassland area
8 included in the Inventory. It is important to note that plans are being made to include these areas in future C
9 inventories.
10 Background on agricultural C stock changes is provided in Cropland Remaining Cropland and will only be
11 summarized here for Land Converted to Grassland. Soils are the largest pool of C in agricultural land, and also
12 have the greatest potential for storage or release of C, because biomass and dead organic matter C pools are
13 relatively small and ephemeral compared with soils. IPCC (2006) recommend reporting changes in soil organic C
14 stocks due to: (1) agricultural land-use and management activities on mineral soils, and (2) agricultural land-use and
15 management activities on organic soils.187
16 Land-use and management of mineral soils in Land Converted to Grassland led to an increase in soil C stocks from
17 1990 through 2009, which was largely due to annual cropland conversion to pasture (see Table 7-34 and Table
18 7-35). For example, the stock change rates were estimated to remove 20.3 Tg CO2 Eq./yr (5.5 Tg C) and 24.5 Tg
19 CO2 Eq./yr (6.7 Tg C) from mineral soils in 1990 and 2009, respectively. Drainage of organic soils for grazing
20 management led to losses varying from 0.5 to 0.9 Tg CO2 Eq./yr (0.1 to 0.2 Tg C).
21 Table 7-34: Net CO2 Flux from Soil C Stock Changes for Land Converted to Grassland (Tg CO2 Eq.)
Soil Type 1990 2000 2005 2006 2007 2008 2009
Mineral Soils3 (20.3) (28.1) (25.3) (25.1) (24.9) (24.7) (24.5)
Organic Soils 0.5 0.9 0.9 0.9 0.9 0.9 0.9
Total Net Flux (19.8) (27.2) (24.4) (24.2) (24.0) (23.8) (23.6)
22 Note: Parentheses indicate net sequestration. Shaded areas indicate values based on a combination of historical data and
23 projections. All other values are based on historical data only. Totals may not sum due to independent rounding.
24 a Stock changes due to application of sewage sludge are reported in Grassland Remaining Grassland.
25
26 Table 7-35: Net CO2 Flux from Soil C Stock Changes for Land Converted to Grassland (Tg C)
Soil Type
Mineral Soils3
Organic Soils
Total Net Flux
1990
(5.5)
0.1
(5.4)
2000
(7.7)
0.2
(7.4)
2005
(6.9)
0.2
(6.7)
2006
(6.8)
0.2
(6.6)
2007
(6.8)
0.2
(6.5)
2008
(6.7)
0.2
(6.5)
2009
(6.7)
0.2
(6.4)
27 Note: Parentheses indicate net sequestration. Shaded areas indicate values based on a combination of historical data and
28 projections. All other values are based on historical data only. Totals may not sum due to independent rounding.
29 a Stock changes due to application of sewage sludge in Land Converted to Grassland are reported in Grassland Remaining
30 Grassland.
31
32 The spatial variability in annual CO2 flux associated with C stock changes in mineral soils is displayed in Figure
33 7-1 land Figure 7-12. Soil C stock increased in most states for Land Converted to Grassland. The largest gains
34 were in the South-Central region, Midwest, and northern Great Plains. The patterns were driven by conversion of
35 annual cropland into continuous pasture. Emissions from organic soils were largest in California, Florida, and the
36 upper Midwest, coinciding with largest concentrations of organic soils in the United States that are used for
37 agricultural production.
38
39 Figure 7-11: Total Net Annual CO2 Flux for Mineral Soils under Agricultural Management within States, 2009,
186 NRI points were classified according to land-use history records starting in 1982 when the NRI survey began, and
consequently the classifications were based on less than 20 years from 1990 to 2001.
187 CO2 emissions associated with liming are also estimated but included in a separate section of the report.
7-42 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Land Converted to Grassland
2
3 Figure 7-12: Total Net Annual CO2 Flux for Organic Soils under Agricultural Management within States, 2009,
4 Land Converted to Grassland
6 Methodology
7 This section includes a brief description of the methodology used to estimate changes in soil C stocks due to
8 agricultural land-use and management activities on mineral soils for Land Converted to Grassland. Biomass C
9 stock changes are not explicitly included in this category but losses of associated with conversion of forest to
10 grassland are included in the Forest Land Remaining Forest Land section. Further elaboration on the methodologies
11 and data used to estimate stock changes from mineral and organic soils are provided in the Cropland Remaining
12 Cropland section and Annex 3.13.
13 Soil C stock changes were estimated for Land Converted to Grassland according to land-use histories recorded in
14 the USDA NRI survey (USDA-NRCS 2000). Land-use and some management information (e.g., crop type, soil
15 attributes, and irrigation) were originally collected for each NRI point on a 5-year cycle beginning in 1982.
16 However, the NRI program initiated annual data collection in 1998, and the annual data are currently available
17 through 2003. NRI points were classified as Land Converted to Grassland in a given year between 1990 and 2009 if
18 the land use was grassland, but had been another use in the previous 20 years. Grassland includes pasture and
19 rangeland used for grass forage production, where the primary use is livestock grazing. Rangeland typically
20 includes extensive areas of native grassland that are not intensively managed, while pastures are often seeded
21 grassland, possibly following tree removal, that may or may not be improved with practices such as irrigation and
22 interseeding legumes.
23 Mineral Soil Carbon Stock Changes
24 An IPCC Tier 3 model-based approach was applied to estimate C stock changes for Land Converted to Grassland
25 on most mineral soils. C stock changes on the remaining soils were estimated with an IPCC Tier 2 approach (Ogle
26 et al. 2003), including prior cropland used to produce vegetables, tobacco, perennial/horticultural crops, and rice;
27 land areas with very gravelly, cobbly, or shaley soils (greater than 35 percent by volume); and land converted from
28 forest or federal ownership.188 A Tier 2 approach was also used to estimate additional changes in mineral soil C
29 stocks due to sewage sludge amendments. However, stock changes associated with sewage sludge amendments are
30 reported in the Grassland Remaining Grassland section.
31 Tier 3 Approach
32 Mineral SOC stocks and stock changes were estimated using the Century biogeochemical model as described for
33 Grassland Remaining Grassland. Historical land-use and management patterns were used in the Century
34 simulations as recorded in the NRI survey, with supplemental information on fertilizer use and rates from the USDA
35 Economic Research Service Cropping Practices Survey (ERS 1997) and the National Agricultural Statistics Service
36 (NASS 1992, 1999, 2004) (see Grassland Remaining Grassland Tier 3 methods section for additional information).
37 Tier 2 Approach
38 The Tier 2 approach used for Land Converted to Grassland on mineral soils is the same as described for Cropland
3 9 Remaining Cropland (See Cropland Remaining Cropland Tier 2 Approach and Annex 3.13 for additional
40 information).
188 pgderal jancj js not a land US6j but rather an ownership designation that is treated as forest or nominal grassland for purposes
of these calculations. The specific use for federal lands is not identified in the NRI survey (USDA-NRCS 2000).
Land Use, Land Use Change, and Forestry 7-43
-------
1 Organic Soil Carbon Stock Changes
2
3
4
5
6
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
Annual C emissions from drained organic soils in Land Converted to Grassland were estimated using the Tier 2
method provided in IPCC (2003, 2006), which utilizes U.S.-specific C loss rates (Ogle et al. 2003) rather than
default IPCC rates. Emissions were based on the 1992 and 1997 Land Converted to Grassland 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 2009.
Uncertainty and Time-Series Consistency
Uncertainty analysis for mineral soil C stock changes using the Tier 3 and Tier 2 approaches were based on the same
method described in Cropland Remaining Cropland, except that the uncertainty inherent in the structure of the
Century model was not addressed. The uncertainty or annual C emission estimates from drained organic soils in
Land Converted to Grassland was estimated using the Tier 2 approach, as described in the Cropland Remaining
Cropland section.
Uncertainty estimates are presented in Table 7-36 for each subsource (i.e., mineral soil C stocks and organic soil C
stocks), disaggregated to the level of the inventory methodology employed (i.e., Tier 2 and Tier 3). Uncertainty for
the portions of the Inventory estimated with Tier 2 and 3 approaches was derived using a Monte Carlo approach (see
Annex 3.13 for further discussion). A combined uncertainty estimate for changes in agricultural soil C stocks is also
included. Uncertainty estimates from each component were combined using the error propagation equation in
accordance with IPCC (2006), (i.e., by taking the square root of the sum of the squares of the standard deviations of
the uncertain quantities). The combined uncertainty for soil C stocks in Land Converted to Grassland ranged from
15 percent below to 15 percent above the 2009 estimate of -23.6 Tg CO2 Eq.
Table 7-36: Tier 2 Quantitative Uncertainty Estimates for Soil C Stock Changes occurring within Land Converted to
Grassland (Tg CO2 Eq. and Percent)
Source
Mineral Soil C Stocks: Land Converted to
Grassland, Tier 3 Inventory Methodology
Mineral Soil C Stocks: Land Converted to
Grassland, Tier 2 Inventory Methodology
Organic Soil C Stocks: Land Converted to
Grassland, Tier 2 Inventory Methodology
2009 Flux
Estimate
(TgC02Eq.)
(19.5)
(5.0)
0.9
Uncertainty Range Relative to Flux
Estimate
(TgC02Eq.)
Lower Upper
Bound Bound
(22.2) (16.7)
(7.0) (2.8)
0.2 1.8
(°/
Lower
Bound
-14%
-39%
-76%
°)
Upper
Bound
+14%
+43%
+104%
Combined Uncertainty for Flux associated with
Agricultural Soil Carbon Stocks in Land
Converted to Grassland
(23.6)
(27.0) (20.0) -15% +15%
Note: Parentheses indicate net sequestration. Totals may not sum due to independent rounding.
Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
above.
28 QA/QC and Verification
29 See the QA/QC and Verification section under Grassland Remaining Grassland.
30 Recalculations Discussion
31 There were minor changes in the estimated area of grasslands associated with reconciling the forestland areas from
32 the Forest Inventory and Analysis (FIA) survey with the data from the National Resources Inventory (NRI) (see
33 section 7.1 for more information). The revised areas led to small changes in the soil C stock changes for Land
34 Converted to Grassland.
7-44 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
i Planned Improvements
2 The main planned improvement for the next Inventory is to integrate the assessments of soil C stock changes and
3 soil nitrous oxide emissions into a single analysis. This improvement will ensure that the nitrogen and carbon cycles
4 are treated consistently in the national inventory, which is important because the cycles of these elements are linked
5 through plant and soil processes in agricultural lands. This improvement will include the development of an
6 empirically-based uncertainty analysis, which will provide a more rigorous assessment of uncertainty. See Planned
7 Improvements section under Cropland Remaining Cropland for additional planned improvements.
8 7.8. Wetlands Remaining Wetlands
9 Peatlands Remaining Peatlands
10 Emissions from Managed Peatlands
11 Managed peatlands are peatlands which have been cleared and drained for the production of peat. The production
12 cycle of a managed peatland has three phases: land conversion in preparation for peat extraction (e.g., draining, and
13 clearing surface biomass), extraction (which results in the emissions reported under Peatlands Remaining
14 Peatlands), and abandonment, restoration or conversion of the land to another use.
15 CO2 emissions from the removal of biomass and the decay of drained peat constitute the major greenhouse gas flux
16 from managed peatlands. Managed peatlands may also emit CH4 and N2O. The natural production of CH4 is largely
17 reduced but not entirely shut down when peatlands are drained in preparation for peat extraction (Strack et al., 2004
18 as cited in IPCC 2006); however, methane emissions are assumed to be insignificant under Tier 1 (IPCC, 2006).
19 N2O emissions from managed peatlands depend on site fertility. In addition, abandoned and restored peatlands
20 continue to release GHG emissions, and at present no methodology is provided by IPCC (2006) to estimate GHG
21 emissions or removals from restored peatlands. This inventory estimates both CO2 and N2O emissions from
22 Peatlands Remaining Peatlands in accordance with Tier 1 IPCC (2006) guidelines.
23 CO2 and N2O Emissions from Peatlands Remaining Peatlands
24 IPCC (2006) recommends reporting CO2 and N2O emissions from lands undergoing active peat extraction (i.e.,
25 Peatlands Remaining Peatlands) as part of the estimate for emissions from managed wetlands. Peatlands occur in
26 wetland areas where plant biomass has sunk to the bottom of water bodies and water-logged areas and exhausted the
27 oxygen supply below the water surface during the course of decay. Due to these anaerobic conditions, much of the
28 plant matter does not decompose but instead forms layers of peat over decades and centuries. In the United States,
29 peat is extracted for horticulture and landscaping growing media, and for a wide variety of industrial, personal care,
30 and other products. It has not been used for fuel in the United States for many decades. Peat is harvested from two
31 types of peat deposits in the United States: sphagnum bogs in northern states and wetlands in states further south.
32 The peat from sphagnum bogs in northern states, which is nutrient poor, is generally corrected for acidity and mixed
33 with fertilizer. Production from more southerly states is relatively coarse (i.e., fibrous) but nutrient rich.
34 IPCC (2006) recommends considering both on-site and off-site emissions when estimating CO2 emissions from
35 Peatlands Remaining Peatlands using the Tier 1 approach. Current methodologies estimate only on-site N2O
36 emissions, since off-site N2O estimates are complicated by the risk of double-counting emissions from nitrogen
37 fertilizers added to horticultural peat. On-site emissions from managed peatlands occur as the land is cleared of
38 vegetation and the underlying peat is exposed to sun and weather. As this occurs, some peat deposit is lost and CO2
39 is emitted from the oxidation of the peat. On-site N2O is emitted during draining depending on site fertility and if
40 the deposit contains significant amounts of organic nitrogen in inactive form. Draining land in preparation for peat
41 extraction allows bacteria to convert the nitrogen into nitrates which leach to the surface where they are reduced to
42 N2O.
43 Off-site CO2 emissions from managed peatlands occur from the horticultural and landscaping use of peat. CO2
44 emissions occur as the nutrient-poor (but now fertilizer-enriched) peat is used in bedding plants, other greenhouse
45 and plant nursery production, and by consumers, and as nutrient-rich (but relatively coarse) peat is used directly in
46 landscaping, athletic fields, golf courses, and plant nurseries. Most of the CO2 emissions from peat occur off-site, as
47 the peat is processed and sold to firms which, in the United States, use it predominately for horticultural purposes.
48 The magnitude of the CO2 emitted from peat depends on whether the peat has been extracted from nutrient-rich or
Land Use, Land Use Change, and Forestry 7-45
-------
1 nutrient-poor peat deposits.
2 Total emissions from Peatlands Remaining Peatlands were estimated to be 1.095 Tg CO2 Eq. in 2009 (see Table
3 7-37) comprising 1.090 Tg CO2 Eq. (1,090 Gg) of CO2 and 0.005 Tg CO2 Eq. (0.016 Gg) of N2O. Total emissions
4 in 2009 were about 10 percent larger than total emissions in 2008, with the increase due to the higher peat
5 production reported in Alaska in 2009.
6 Total emissions from Peatlands Remaining Peatlands have fluctuated between 0.88 and 1.23 Tg CO2 Eq. across the
7 time series with a decreasing trend from 1990 until 1994 followed by an increasing trend through 2000. Since 2000,
8 total emissions show a decreasing trend until 2006 followed by an increasing trend in recent years. CO2 emissions
9 from Peatlands Remaining Peatlands have fluctuated between 0.88 and 1.23 Tg CO2 across the time series and drive
10 the trends in total emissions. N2O emissions remained close to zero across the time series with a decreasing trend
11 from 1990 until 1995 followed by an increasing trend through 2000. N2O emissions show a decreasing trend
12 between 2000 and 2008 followed by a leveling off in 2009.
13 Table 7-37: Emissions from Peatlands Remaining Peatlands (Tg CO2 Eq.)
Gas 1990 1995 2000 2005 2006 2007 2008 2009
C02
N2O
1.0
1.0
1.2
1.1 0.9
1.0
1.0
1.1
Total LO LO 1.2 LI 0.9 LO 1.0 1.1
14 + Less than 0.01 Tg CO2 Eq.
15 Note: These numbers are based on U.S. production data in accordance with Tier 1 guidelines, which does not take into account
16 imports, exports and stockpiles (i.e., apparent consumption).
17
18 Table 7-38: Emissions from Peatlands Remaining Peatlands (Gg)
19
20
21
22
Gas 1990 1995 2000
CO2 1,033 1,018 1,227
N2O + + +
2005 2006
1,079 879
2007 2008
1,012 992
2009
1,090
+ Less than 0.05 Gg
Note: These numbers are based on U.S. production data in accordance with Tier 1 guidelines, which does not take into account
imports, exports and stockpiles (i.e., apparent consumption).
23 Methodology
24 Off-site CO2 Emissions
25 CO2 emissions from domestic peat production were estimated using a Tier 1 methodology consistent with IPCC
26 (2006). Off-site CO2 emissions from Peatlands Remaining Peatlands were calculated by apportioning the annual
27 weight of peat produced in the United States (Table 7-39) into peat extracted from nutrient-rich deposits and peat
28 extracted from nutrient-poor deposits using annual percentage by weight figures. These nutrient-rich and nutrient-
29 poor production values were then multiplied by the appropriate default carbon fraction conversion factor taken from
30 IPCC (2006) in order to obtain off-site emission estimates. For the lower 48 states, both annual percentages of peat
31 type by weight and domestic peat production data were sourced from estimates and industry statistics provided in
32 the Minerals Yearbook and. Mineral Commodity Summaries from the U.S. Geological Survey (USGS 1991-2010).
33 To develop these data, the U.S. Geological Survey (USGS; U.S. Bureau of Mines prior to 1997) obtained production
34 and use information by surveying domestic peat producers. The USGS often receives a response to the survey from
35 most of the smaller peat producers, but fewer of the larger ones. For example, of the four active operations
36 producing 23,000 or more metric tons per year, two did not respond to the survey in 2007. As a result, the USGS
37 estimates production from the non-respondent peat producers based on responses to previous surveys (responses
38 from 2004 and 2005, in the case above) or other sources.
39 The Alaska estimates rely on reported peat production from Alaska's annual Mineral Industry Reports (Szumigala et
40 al. 2010). Similar to the U.S. Geological Survey, Alaska's Mineral Industry Report methodology solicits voluntary
41 reporting of peat production from producers. However, the report does not estimate production for the non-reporting
42 producers, resulting in larger inter-annual variation in reported peat production from Alaska depending on the
43 number of producers who report in a given year (Szumigala 2011). In addition, in both the lower 48 states and
44 Alaska, large variations in peat production can also result from variations in precipitation and the subsequent
7-46 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 moisture conditions, since unusually wet years can hamper peat production (USGS 2010). The methodology
2 estimates Alaska emissions separately from lower 48 emissions because the state conducts its own mineral survey
3 and reports peat production by volume, rather than by weight (Table 7-40). However, volume production data was
4 used to calculate off-site CO2 emissions from Alaska applying the same methodology but with volume-specific
5 carbon fraction conversion factors from IPCC (2006).189
6 The apparent consumption of peat, which includes production plus imports minus exports plus the decrease in
7 stockpiles, in the United States is over two-and-a-half times the amount of domestic peat production. Therefore, off-
8 site CO2 emissions from the use of all horticultural peat within the United States are not accounted for using the Tier
9 1 approach. The United States has increasingly imported peat from Canada for horticultural purposes; from 2005 to
10 2008, imports of sphagnum moss (nutrient-poor) peat from Canada represented 97 percent of total U.S. peat imports
11 (USGS 2010). Most peat produced in the United States is reed-sedge peat, generally from southern states, which is
12 classified as nutrient rich by IPCC (2006). Higher-tier calculations of CO2 emissions from apparent consumption
13 would involve consideration of the percentages of peat types stockpiled (nutrient rich versus nutrient poor) as well
14 as the percentages of peat types imported and exported.
15 Table 7-39: Peat Production of Lower 48 States (in thousands of Metric Tons)
Type of Deposit 1990 2000 2005 2006 2007 2008 2009
Nutrient-Rich 595.1 728.6 657.6 529.0 581.0 559.7
Nutrient-Poor 55.4 63.4 27.4 22.0 54.0 55.4
Total Production 692.0 792.0 685.0 551.0 635.0 615.0 609.0
16 Sources: Minerals Yearbook: Peat (1990-2008 Reports), Mineral Commodity Summaries: Peat (1996-2009 Reports), and
17 Apodaca(2010). United States Geological Survey.
18
19 Table 7-40: Peat Production of Alaska (in thousands of Cubic Meters)
1990 2000 2005 2006 2007 2008 2009
Total Production 49.7 27.2 47.8 50.8 52.3 64.1 183.9
20 Sources: Alaska's Mineral Industry (1992-2009) Reports. Division of Geological & Geophysical Surveys, Alaska Department
21 of Natural Resources.
22
23 On-site CO2 Emissions
24 IPCC (2006) suggests basing the calculation of on-site emissions estimates on the area of peatlands managed for
25 peat extraction differentiated by the nutrient type of the deposit (rich versus poor). Information on the area of land
26 managed for peat extraction is currently not available for the United States, but in accordance with IPCC (2006), an
27 average production rate for the industry was applied to derive an area estimate. In a mature industrialized peat
28 industry, such as exists in the United States and Canada, the vacuum method190 can extract up to 100 metric ton per
29 hectare per year (Cleary et al. 2005 as cited in IPCC 2006). The area of land managed for peat extraction in the
30 United States was estimated using nutrient-rich and nutrient-poor production data and the assumption that 100
31 metric tons of peat are extracted from a single hectare in a single year. The annual land area estimates were then
32 multiplied by the appropriate nutrient-rich or nutrient-poor IPCC (2006) default emission factor in order to calculate
33 on-site CO2 emission estimates. Production data are not available by weight for Alaska. In order to calculate on-site
34 emissions resulting from Peatlands Remaining Peatlands in Alaska, the production data by volume were converted
35 to weight using annual average bulk peat density values, and then converted to land area estimates using the same
36 assumption that a single hectare yields 100 metric tons. The IPCC (2006) on-site emissions equation also includes a
37 term which accounts for emissions resulting from the change in carbon stocks that occurs during the clearing of
38 vegetation prior to peat extraction. Area data on land undergoing conversion to peatlands for peat extraction is also
39 unavailable for the United States. However, USGS records show that the number of active operations in the United
40 States has been declining since 1990; therefore it seems reasonable to assume that no new areas are being cleared of
189 Peat produced from Alaska was assumed to be nutrient poor; as is the case in Canada, "where deposits of high-quality [but
nutrient poor] sphagnum moss are extensive" (USGS 2008).
190 The vacuum method is one type of extraction that annually "mills" or breaks up the surface of the peat into particles, which
then dry during the summer months. The air-dried peat particles are then collected by vacuum harvesters and transported from
the area to stockpiles (IPCC 2006).
Land Use, Land Use Change, and Forestry 7-47
-------
1 vegetation for managed peat extraction. Other changes in carbon stocks in living biomass on managed peatlands are
2 also assumed to be zero under the Tier 1 methodology (IPCC 2006).
4
5
6
7
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
On-site N2O Emissions
IPCC (2006) suggests basing the calculation of on-site N2O emissions estimates on the area of nutrient-rich
peatlands managed for peat extraction. These area data are not available directly for the United States, but the on-
site CO2 emissions methodology above details the calculation of area data from production data. In order to
estimate N2O emissions, the area of nutrient rich Peatlands Remaining Peatlands was multiplied by the appropriate
default emission factor taken from IPCC (2006).
Uncertainty
The uncertainty associated with peat production data was estimated to be ± 25 percent (Apodaca 2008) and assumed
to be normally distributed. The uncertainty associated with peat production data stems from the fact that the USGS
receives data from the smaller peat producers but estimates production from some larger peat distributors. This
same uncertainty and distribution was assumed for the peat type production percentages. The uncertainty associated
with the Alaskan reported production data was assumed to be the same as the lower 48 states, or ± 25 percent with a
normal distribution. It should be noted that the Alaskan Department of Natural Resources estimate that around half
of producers do not respond to their survey with peat production data; therefore, the production numbers reported
are likely to underestimate Alaska peat production (Szumigala 2008). The uncertainty associated with the average
bulk density values was estimated to be ± 25 percent with a normal distribution (Apodaca 2008). IPCC (2006) gives
uncertainty values for the emissions factors for the area of peat deposits managed for peat extraction based on the
range of underlying data used to determine the emissions factors. The uncertainty associated with the emission
factors was assumed to be triangularly distributed. The uncertainty values surrounding the carbon fractions were
based on IPCC (2006) and the uncertainty was assumed to be uniformly distributed. Based on these values and
distributions, a Monte Carlo (Tier 2) uncertainty analysis was applied to estimate the uncertainty of CO2 and N2O
emissions from Peatlands Remaining Peatlands. The results of the Tier 2 quantitative uncertainty analysis are
summarized in Table 7-41. CO2 emissions from Peatlands Remaining Peatlands in 2009 were estimated to be
between 0.8 and 1.5 Tg CO2 Eq. at the 95 percent confidence level. This indicates a range of 30 percent below to 34
percent above the 2009 emission estimate of 1.1 Tg CO2 Eq. N2O emissions from Peatlands Remaining Peatlands
in 2009 were estimated to be between 0.001 and 0.007 Tg CO2 Eq. at the 95 percent confidence level. This indicates
a range of 74 percent below to 41 percent above the 2009 emission estimate of 0.005 Tg CO2 Eq.
Table 7-41: Tier-2 Quantitative Uncertainty Estimates for CO2 Emissions from Peatlands Remaining Peatlands
2009 Emissions
Estimate Uncertainty Range Relative to Emissions Estimate"
Source Gas (Tg CO2 Eq.) (Tg CO2 Eq.) (%)
31
32
33
Peatlands
Remaining
Peatlands
C02 1.1
N2O +
Lower
Bound
0.8
+
Upper
Bound
1.5
+
Lower
Bound
-30%
-74%
Upper
Bound
34%
41%
+ Does not exceed 0.01 Tg CO2 Eq. or 0.5 Gg.
a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
34 QA/QC and Verification
35 A QA/QC analysis was performed for data gathering and input, documentation, and calculation. The QA/QC
36 analysis did not reveal any inaccuracies or incorrect input values.
37 Recalculations Discussion
38 This is only the third year that emissions from Peatlands Remaining Peatlands are included in the/wvewtory of U.S.
39 Greenhouse Gas Emissions and Sinks. A revised 2008 estimate of peat production by volume for Alaska was
40 reported in 2010 (Szumigala et al. 2010). Updating the 2008 production data with this revised estimate led to a 5
41 percent increase over the previous 2008 total emissions estimate.
7-48 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Planned Improvements
2 In order to further improve estimates of CO2 and N2O emissions from Peatlands Remaining Peatlands, future efforts
3 will consider options for obtaining better data on the quantity of peat harvested per hectare and the total area
4 undergoing peat extraction.
5 7.9. Settlements Remaining Settlements
6 Changes in Carbon Stocks in Urban Trees (IPCC Source Category 5E1)
7 Urban forests constitute a significant portion of the total U.S. tree canopy cover (Dwyer et al. 2000). Urban areas
8 (cities, towns, and villages) are estimated to cover over 4 percent of the United States (Nowak et al. 2005). With an
9 average tree canopy cover of 27 percent, urban areas account for approximately 3 percent of total tree cover in the
10 continental United States (Nowak et al. 2001). Trees in urban areas of the United States were estimated to account
11 for an average annual net sequestration of 76.5 Tg CO2 Eq. (20.9 Tg C) over the period from 1990 through 2009.
12 Net C flux from urban trees in 2009 was estimated to be -95.9 Tg CO2 Eq. (-26.2 Tg C). Annual estimates of CO2
13 flux (Table 7-42) were developed based on periodic (1990 and 2000) U.S. Census data on urbanized area. This
14 estimated urban area is smaller than the area categorized as Settlements in the Representation of the U. S. Land Base
15 developed for this report, by an average of 21 percent over the 1990 through 2009 time series—i.e., the Census
16 urban area is a subset of the Settlements area. Census area data are preferentially used to develop C flux estimates
17 for this source category since these data are more applicable for use with the available peer-reviewed data on urban
18 tree canopy cover and urban tree C sequestration. Annual sequestration increased by 68 percent between 1990 and
19 2009 due to increases in urban land area. Data on C storage and urban tree coverage were collected since the early
20 1990s and have been applied to the entire time series in this report.
21 Net C flux from urban trees is proportionately greater on an area basis than that of forests. This trend is primarily
22 the result of different net growth rates in urban areas versus forests—urban trees often grow faster than forest trees
23 because of the relatively open structure of the urban forest (Nowak and Crane 2002). However, areas in each case
24 are accounted for differently. Because urban areas contain less tree coverage than forest areas, the C storage per
25 hectare of land is in fact smaller for urban areas. However, urban tree reporting occurs on a basis of C sequestered
26 per unit area of tree cover, rather than C sequestered per total land area. Areas covered by urban trees, therefore,
27 appear to have a greater C density than do forested areas (Nowak and Crane 2002).
28 Table 7-42: Net C Flux from Urban Trees (Tg CO2 Eq. and Tg C)
Year
1990
2000
2005
2006
2007
2008
2009
Tg CO2 Eq.
(57.1)
(77.5)
(87.8)
(89.8)
(91.9)
(93.9)
(95.9)
TgC
(15.6)
(21.1)
(23.9)
(24.5)
(25.1)
(25.6)
(26.2)
29 Note: Parentheses indicate net sequestration.
30 Methodology
31 Methods for quantifying urban tree biomass, C sequestration, and C emissions from tree mortality and
32 decomposition were taken directly from Nowak and Crane (2002) and Nowak (1994). In general, the methodology
33 used by Nowak and Crane (2002) to estimate net C sequestration in urban trees followed three steps. First, field
34 data from 14 cities were used to generate allometric estimates of biomass from measured tree dimensions. Second,
35 estimates of tree growth and biomass increment were generated from published literature and adjusted for tree
36 condition and land-use class to generate estimates of gross C sequestration in urban trees. Third, estimates of C
37 emissions due to mortality and decomposition were subtracted from gross C sequestration values to derive estimates
38 of net C sequestration. Sequestration estimates for these cities, in units of carbon sequestered per unit area of tree
39 cover, were then used to estimate urban forest C sequestration in the U.S. by using urban area estimates from U.S.
Land Use, Land Use Change, and Forestry 7-49
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1 Census data and urban tree cover estimates from remote sensing data, an approach consistent with Nowak and Crane
2 (2002).
3 This approach is also consistent with the default IPCC methodology in IPCC (2006), although sufficient data are not
4 yet available to separately determine interannual gains and losses in C stocks in the living biomass of urban trees.
5 Annual changes in net C flux from urban trees are based solely on changes in total urban area in the United States.
6 In order to generate the allometric relationships between tree dimensions and tree biomass, Nowak and Crane (2002)
7 and Nowak (1994, 2007c, 2009) collected field measurements in a number of U.S. cities between 1989 and 2002.
8 For a sample of trees in each of the cities in Table 7-43, data including tree measurements of stem diameter, tree
9 height, crown height and crown width, and information on location, species, and canopy condition were collected.
10 The data for each tree were converted into C storage by applying allometric equations to estimate aboveground
11 biomass, a root-to-shoot ratio to convert aboveground biomass estimates to whole tree biomass, moisture content, a
12 C content of 50 percent (dry weight basis), and an adjustment factor of 0.8 to account for urban trees having less
13 aboveground biomass for a given stem diameter than predicted by allometric equations based on forest trees (Nowak
14 1994). C storage estimates for deciduous trees include only carbon stored in wood. These calculations were then
15 used to develop an allometric equation relating tree dimensions to C storage for each species of tree, encompassing a
16 range of diameters.
17 Tree growth was estimated using annual height growth and diameter growth rates for specific land uses and diameter
18 classes. Growth calculations were adjusted by a factor to account for tree condition (fair to excellent, poor, critical,
19 dying, or dead). For each tree, the difference in carbon storage estimates between year 1 and year (x + 1) gave the
20 gross amount of C sequestered. These annual gross C sequestration rates for each species (or genus), diameter class,
21 and land-use condition (e.g., parks, transportation, vacant, golf courses) were then scaled up to city estimates using
22 tree population information. The area of assessment for each city was defined by its political boundaries; parks and
23 other forested urban areas were thus included in sequestration estimates (Nowak 2011).
24 Most of the field data used to develop the methodology of Nowak et al. were analyzed using the U.S. Forest
25 Service's Urban Forest Effects (UFORE) model. UFORE is a computer model that uses standardized field data
26 from random plots in each city and local air pollution and meteorological data to quantify urban forest structure,
27 values of the urban forest, and environmental effects, including total C stored and annual C sequestration. UFORE
28 was used with field data from a stratified random sample of plots in each city to quantify the characteristics of the
29 urban forest. (Nowak et al. 2007a).
30 Gross C emissions result from tree death and removals. Estimates of gross C emissions from urban trees were
31 derived by applying estimates of annual mortality and condition, and assumptions about whether dead trees were
32 removed from the site to the total C stock estimate for each city. Estimates of annual mortality rates by diameter
33 class and condition class were derived from a study of street-tree mortality (Nowak 1986). Different decomposition
34 rates were applied to dead trees left standing compared with those removed from the site. For removed trees,
35 different rates were applied to the removed/aboveground biomass in contrast to the belowground biomass. The
36 estimated annual gross C emission rates for each species (or genus), diameter class, and condition class were then
37 scaled up to city estimates using tree population information.
38 The field data for 13 of the 14 cities are described in Nowak and Crane (2002), Nowak et al. (2007a), and references
39 cited therein. Data for the remaining city, Chicago, were taken from unpublished results (Nowak 2009). The
40 allometric equations applied to the field data for each tree were taken from the scientific literature (see Nowak 1994,
41 Nowak et al. 2002), but if no allometric equation could be found for the particular species, the average result for the
42 genus was used. The adjustment (0.8) to account for less live tree biomass in urban trees was based on information
43 in Nowak (1994). A root-to-shoot ratio of 0.26 was taken from Cairns et al. (1997), and species- or genus-specific
44 moisture contents were taken from various literature sources (see Nowak 1994). Tree growth rates were taken from
45 existing literature. Average diameter growth was based on the following sources: estimates for trees in forest stands
46 came from Smith and Shifley (1984); estimates for trees on land uses with a park-like structure came from deVries
47 (1987); and estimates for more open-grown trees came from Nowak (1994). Formulas from Fleming (1988) formed
48 the basis for average height growth calculations. As described above, growth rates were adjusted to account for tree
49 condition. Growth factors for Atlanta, Boston, Freehold, Jersey City, Moorestown, New York, Philadelphia, and
50 Woodbridge were adjusted based on the typical growth conditions of different land-use categories (e.g., forest
51 stands, park-like stands). Growth factors for the more recent studies in Baltimore, Chicago, Minneapolis, San
52 Francisco, Syracuse, and Washington were adjusted using an updated methodology based on the condition of each
53 individual tree, which is determined using tree competition factors (depending on whether it is open grown or
7-50 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1
2
o
6
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
suppressed) (Nowak 2007b). Assumptions for which dead trees would be removed versus left standing were
developed specific to each land use and were based on expert judgment of the authors. Decomposition rates were
based on literature estimates (Nowak and Crane 2002).
Estimates of gross and net sequestration rates for each of the 14 cities (Table 7-43) were compiled in units of C
sequestration per unit area of tree canopy cover. These rates were used in conjunction with estimates of national
urban area and urban tree cover data to calculate national annual net C sequestration by urban trees for the United
States. This method was described in Nowak and Crane (2002) and has been modified to incorporate U.S. Census
data.
Specifically, urban area estimates were based on 1990 and 2000 U.S. Census data. The 1990 U.S. Census defined
urban land as "urbanized areas," which included land with a population density greater than 1,000 people per square
mile, and adjacent "urban places," which had predefined political boundaries and a population total greater than
2,500. In 2000, the U.S. Census replaced the "urban places" category with a new category of urban land called an
"urban cluster," which included areas with more than 500 people per square mile. Urban land area increased by
approximately 36 percent from 1990 to 2000; Nowak et al. (2005) estimate that the changes in the definition of
urban land are responsible for approximately 20 percent of the total reported increase in urban land area from 1990
to 2000. Under both 1990 and 2000 definitions, the urban category encompasses most cities, towns, and villages
(i.e., it includes both urban and suburban areas).
Settlements area, as assessed in the Representation of the U.S. Land Base developed for this report, encompassed all
developed parcels greater than 0.1 hectares in size, including rural transportation corridors, and as previously
mentioned represent a larger area than the Census-derived urban area estimates. However, the Census-derived
urban area estimates were deemed to be more suitable for estimating national urban tree cover given the data
available in the peer-reviewed literature. Specifically, tree canopy cover of U.S. urban areas was estimated by
Nowak et al. (2001) to be 27 percent, assessed across Census-delineated urbanized areas, urban places, and places
containing urbanized area. This canopy cover percentage is multiplied by the urban area estimated for each year to
produce an estimate of national urban tree cover area.
Net annual C sequestration estimates were derived for the 14 cities by subtracting the gross annual emission
estimates from the gross annual sequestration estimates. The gross and net annual C sequestration values for each
city were divided by each city's area of tree cover to determine the average annual sequestration rates per unit of
tree area for each city. The median value for gross sequestration per unit area of tree cover (0.29 kg C/m2-yr) was
then multiplied by the estimate of national urban tree cover area to estimate national annual gross sequestration, per
the methods of Nowak and Crane (2002). To estimate national annual net sequestration, the estimate of national
annual gross sequestration was multiplied by the average of the ratios of net to gross sequestration (0.72) for those
cities that had both estimates. The urban tree cover estimates for each of the 14 cities and the United States were
obtained from Dwyer et al. (2000), Nowak et al. (2002), Nowak (2007a), and Nowak (2009). The urban area
estimates were taken from Nowak et al. (2005).
Table 7-43 : C Stocks (Metric Tons C), Annual C Sequestration (Metric
Annual C Sequestration per Area of Tree Cover (kg C/m2-yr) for 14 U.S
City
Atlanta, GA
Baltimore, MD
Boston, MA
Chicago, IL
Freehold, NJ
Jersey City, NJ
Minneapolis, MN
Moorestown, NJ
New York, NY
Philadelphia, PA
San Francisco, CA
Syracuse, NY
Carbon
Stocks
1,219,256
541,589
289,392
649,000
18,144
19,051
226,796
106,141
1,224,699
480,808
175,994
156,943
Gross Annual
Sequestration
42,093
14,696
9,525
22,800
494
807
8,074
3,411
38,374
14,606
4,627
4,917
Net Annual
Sequestration
32,169
9,261
6,966
16,100
318
577
4,265
2,577
20,786
10,530
4,152
4,270
Tree
Cover
36.7%
21.0%
22.3%
17.2%
34.4%
11.5%
26.4%
28.0%
20.9%
15.7%
11.9%
23.1%
Tons C/yr), Tree
. Cities
Gross Annual
Sequestration
per Area of
Tree Cover
0.34
0.35
0.30
0.22
0.28
0.18
0.20
0.32
0.23
0.27
0.33
0.33
Cover (Percent), and
Net Annual
Sequestration
per Area of
Tree Cover
0.26
0.22
0.22
0.16
0.18
0.13
0.11
0.24
0.12
0.20
0.29
0.29
Net: Gross
Annual
Sequestration
Ratio
0.76
0.63
0.73
0.71
0.64
0.71
0.53
0.76
0.54
0.72
0.90
0.87
Land Use, Land Use Change, and Forestry 7-51
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Washington, DC
Woodbridge, NJ
477,179
145,150
14,696
5,044
11,661
3,663
28.6%
29.5%
0.32
0.28
Median: 0.29
0.26
0.21
0.79
0.73
Mean: 0.72
1 NA = not analyzed.
2 Sources: Nowak and Crane (2002), Nowak (2007a,c), and Nowak (2009).
5
6
7
8
9
10
1 1
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Uncertainty and Time-Series Consistency
Uncertainty associated with changes in C stocks in urban trees includes the uncertainty associated with urban area,
percent urban tree coverage, and estimates of gross and net C sequestration for each of the 14 U.S. cities. A 10
percent uncertainty was associated with urban area estimates while a 5 percent uncertainty was associated with
percent urban tree coverage. Both of these uncertainty estimates were based on expert judgment. Uncertainty
associated with estimates of gross and net C sequestration for each of the 14 U.S. cities was based on standard error
estimates for each of the city -level sequestration estimates reported by Nowak (2007c) and Nowak (2009). These
estimates are based on field data collected in each of the 14 U.S. cities, and uncertainty in these estimates increases
as they are scaled up to the national level.
Additional uncertainty is associated with the biomass equations, conversion factors, and decomposition assumptions
used to calculate C sequestration and emission estimates (Nowak et al. 2002). These results also exclude changes in
soil C stocks, and there may be some overlap between the urban tree C estimates and the forest tree C estimates.
Due to data limitations, urban soil flux is not quantified as part of this analysis, while reconciliation of urban tree
and forest tree estimates will be addressed through the land-representation effort described in the Planned
Improvements section of this chapter.
A Monte Carlo (Tier 2) uncertainty analysis was applied to estimate the overall uncertainty of the sequestration
estimate. The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 7-44. The net C flux
from changes in C stocks in urban trees in 2009 was estimated to be between -1 16.8 and -77.7 Tg CO2 Eq. at a 95
percent confidence level. This indicates a range of 22 percent below and 19 percent above the 2009 flux estimate of
-95.9TgCO2Eq.
Table 7-44: Tier 2 Quantitative Uncertainty Estimates for Net C Flux from Changes in C Stocks in Urban Trees
(Tg CO2 Eq. and Percent)
2009 Flux Estimate Uncertainty Range Relative to Flux Estimate
Source Gas (TgCO2Eq.) (Tg CO2 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Changes in C Stocks
in Urban Trees CO2 (95.9)
(116.8) (77.7) -22% +19%
26 Note: Parentheses indicate negative values or net sequestration.
27 Details on the emission trends through time are described in more detail in the Methodology section, above.
28 QA/QC and Verification
29 The net C flux resulting from urban trees was predominately calculated using estimates of gross and net C
30 sequestration estimates for urban trees and urban tree coverage area published in the literature. The validity of these
31 data for their use in this section of the inventory was evaluated through correspondence established with an author of
32 the papers. Through this correspondence, the methods used to collect the urban tree sequestration and area data
33 were further clarified and the use of these data in the inventory was reviewed and validated (Nowak 2002a, 2007b,
34 2011).
35 Recalculations Discussion
36 The estimation methodology is the same as that used for the previous report. Accordingly, previous sequestration
37 estimates have not changed.
7-52 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 Planned Improvements
2 A consistent representation of the managed land base in the United States is being developed. A component of this
3 effort, which is discussed at the beginning of the Land Use, Land-Use Change, and Forestry chapter, will involve
4 reconciling the overlap between urban forest and non-urban forest greenhouse gas inventories. It is highly likely
5 that urban forest inventories are including areas also defined as forest land under the Forest Inventory and Analysis
6 (FIA) program of the USD A Forest Service, resulting in "double-counting" of these land areas in estimates of C
7 stocks and fluxes for the inventory. The Forest Service is currently conducting research that will define urban area
8 boundaries and make it possible to distinguish forest from forested urban areas. Once those data become available,
9 they will be incorporated into estimates of net C flux resulting from urban trees.
10 Urban forest data for additional cities are expected in the near future, as are updated data for cities currently
11 included in the estimates. The use of these data will further refine the estimated median sequestration value. It may
12 also be possible to report C losses and gains separately in the future. It is currently not possible, since existing
13 studies estimate rather than measure natality or mortality; net sequestration estimates are based on assumptions
14 about whether dead trees are being removed, burned, or chipped. There is an effort underway to assess urban tree
15 loss to mortality and removals, which would allow for direct calculation of C losses and gains from observed rather
16 than estimated natality and mortality of trees.
17 Data from the 2010 U.S. Census is expected to provide updated U.S. urbanized area, which would allow for
18 refinement of the urban area time series. Revisions to urban area time series will result in revisions to prioryears' C
19 flux estimates.
20 A revised average tree canopy cover percentage for U.S. urban areas is anticipated to become available in the peer-
21 reviewed literature in the near future, which would allow for updated C flux estimates. Furthermore, urban tree
22 cover data specific to each state is also expected in the near future. It may be possible to develop a set of state-
23 specific sequestration rates for more granular and regionally precise C flux estimates by coupling these data with
24 adjusted growth rates for each U.S. state.Future research may also enable more complete coverage of changes in the
25 C stock in urban trees for all Settlements land. To provide estimates for all Settlements, research would need to
26 establish the extent of overlap between Settlements and Census-defined urban areas, and would have to characterize
27 sequestration on non-urban Settlements land.Direct N2O Fluxes from Settlement Soils (IPCC Source Category 5E1)
28 Of the synthetic N fertilizers applied to soils in the United States, approximately 2.5 percent are currently applied to
29 lawns, golf courses, and other landscaping occurring within settlement areas. Application rates are lower than those
30 occurring on cropped soils, and, therefore, account for a smaller proportion of total U.S. soil N2O emissions per unit
31 area. In addition to synthetic N fertilizers, a portion of surface applied sewage sludge is applied to settlement areas.
32 In 2009, N2O emissions from this source were 1.5 Tg CO2 Eq. (4.9 Gg). There was an overall increase of 55 percent
33 over the period from 1990 through 2009 due to a general increase in the application of synthetic N fertilizers to an
34 expanding settlement area. Interannual variability in these emissions is directly attributable to interannual variability
35 in total synthetic fertilizer consumption and sewage sludge applications in the United States. Emissions from this
36 source are summarized in Table 7-45.
37 Table 7-45: Direct N2O Fluxes from Soils in Settlements Remaining Settlements (Tg CO2 Eq. and Gg N2O)
38
39
40
2005
2006
2007
2008
2009
.5 4.7
.5 4.8
.6 5.1
.5 4.9
.5 4.9
Note: These estimates include direct N2O emissions fromN fertilizer additions only.
additions are reported in the Agriculture chapter. These estimates include emissions
Settlements and from Land Converted to Settlements.
Indirect N2O emissions from fertilizer
from both Settlements Remaining
Land Use, Land Use Change, and Forestry 7-53
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1 Methodology
2 For soils within Settlements Remaining Settlements, the IPCC Tier 1 approach was used to estimate soil N2O
3 emissions from synthetic N fertilizer and sewage sludge additions. Estimates of direct N2O emissions from soils in
4 settlements were based on the amount of N in synthetic commercial fertilizers applied to settlement soils, and the
5 amount of N in sewage sludge applied to non-agricultural land and surface disposal of sewage sludge (see Annex
6 3.11 for a detailed discussion of the methodology for estimating sewage sludge application).
7 Nitrogen applications to settlement soils are estimated using data compiled by the USGS (Ruddy et al. 2006). The
8 USGS estimated on-farm and non-farm fertilizer use is based on sales records at the county level from 1982 through
9 2001 (Ruddy et al. 2006). Non-farm N fertilizer was assumed to be applied to settlements and forest lands; values
10 for 2002 through 2008 were based on 2001 values adjusted for annual total N fertilizer sales in the United States
11 because there is no new activity data on application after 2001. Settlement application was calculated by subtracting
12 forest application from total non-farm fertilizer use. Sewage sludge applications were derived from national data on
13 sewage sludge generation, disposition, and N content (see Annex 3.11 for further detail). The total amount of N
14 resulting from these sources was multiplied by the IPCC default emission factor for applied N (1 percent) to
15 estimate direct N2O emissions (IPCC 2006). The volatilized and leached/runoff N fractions for settlements,
16 calculated with the IPCC default volatilization factors (10 or 20 percent, respectively, for synthetic or organic N
17 fertilizers) and leaching/runoff factor for wet areas (30 percent), were included with indirect emissions, as reported
18 in the N2O Emissions from Agricultural Soil Management source category of the Agriculture chapter (consistent
19 with reporting guidance that all indirect emissions are included in the Agricultural Soil Management source
20 category).
21 Uncertainty and Time-Series Consistency
22 The amount of N2O emitted from settlements depends not only on N inputs and fertilized area, but also on a large
23 number of variables, including organic C availability, oxygen gas partial pressure, soil moisture content, pH,
24 temperature, and irrigation/watering practices. The effect of the combined interaction of these variables on N2O flux
25 is complex and highly uncertain. The IPCC default methodology does not explicitly incorporate any of these
26 variables, except variations in fertilizer N and sewage sludge application rates. All settlement soils are treated
27 equivalently under this methodology.
28 Uncertainties exist in both the fertilizer N and sewage sludge application rates in addition to the emission factors.
29 Uncertainty in fertilizer N application was assigned a default level191 of ±50 percent. Uncertainty in the amounts of
30 sewage sludge applied to non-agricultural lands and used in surface disposal was derived from variability in several
31 factors, including: (1) N content of sewage sludge; (2) total sludge applied in 2000; (3) wastewater existing flow in
32 1996 and 2000; and (4) the sewage sludge disposal practice distributions to non-agricultural land application and
33 surface disposal. Uncertainty in the emission factors was provided by the IPCC (2006).
34 Quantitative uncertainty of this source category was estimated through the IPCC-recommended Tier 2 uncertainty
35 estimation methodology. The uncertainty ranges around the 2005 activity data and emission factor input variables
36 were directly applied to the 2009 emission estimates. The results of the quantitative uncertainty analysis are
37 summarized in Table 7-46. N2O emissions from soils in Settlements Remaining Settlements in 2009 were estimated
38 to be between 0.8 and 4.0 Tg CO2 Eq. at a 95 percent confidence level. This indicates a range of 49 percent below
39 to 163 percent above the 2009 emission estimate of 1.5 Tg CO2 Eq.
40
41
42
43
44
45
191 No uncertainty is provided with the USGS application data (Ruddy et al. 2006) so a conservative ±50% was used in the
analysis.
7-54 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Table 7-46: Quantitative Uncertainty Estimates of N2O Emissions from Soils in Settlements Remaining Settlements
1 (Tg CO2 Eq. and Percent)
2009 Uncertainty Range Relative to Emission
Source Gas Emissions Estimate
(Tg C02 Eq.) (Tg C02 Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper
Bound
Settlements Remaining Settlements:
N2O Fluxes from Soils N2O L5 0.8 4.0 -49% 163%
3 Note: This estimate includes direct N2O emissions from N fertilizer additions to both Settlements Remaining
4 Settlements and from Land Converted to Settlements.
6 Recalculations Discussion
7 There were no changes in methodology for this source.
8 Planned Improvements
9 A minor improvement is planned to update the uncertainty analysis for direct emissions from settlements to be
10 consistent with the most recent activity data for this source.
11 7.10. Land Converted to Settlements (Source Category 5E2)
12 Land-use change is constantly occurring, and land under a number of uses undergoes urbanization in the United
13 States each year. However, data on the amount of land converted to settlements is currently lacking. Given the lack
14 of available information relevant to this particular IPCC source category, it is not possible to separate CO2 or N2O
15 fluxes on Land Converted to Settlements from fluxes on Settlements Remaining Settlements at this time.
16 7.11. Other (IPCC Source Category 5G)
17 Changes in Yard Trimming and Food Scrap Carbon Stocks in Landfills
18 In the United States, a significant change in C stocks results from the removal of yard trimmings (i.e., grass
19 clippings, leaves, and branches) and food scraps from settlements to be disposed in landfills. Yard trimmings and
20 food scraps account for a significant portion of the municipal waste stream, and a large fraction of the collected yard
21 trimmings and food scraps are discarded in landfills. C contained in landfilled yard trimmings and food scraps can
22 be stored for very long periods.
23 Carbon storage estimates are associated with particular land uses. For example, harvested wood products are
24 accounted for under Forest Land Remaining Forest Land because these wood products are a component of the forest
25 ecosystem. The wood products serve as reservoirs to which C resulting from photosynthesis in trees is transferred,
26 but the removals in this case occur in the forest. C stock changes in yard trimmings and food scraps are associated
27 with settlements, but removals in this case do not occur within settlements. To address this complexity, yard
28 trimming and food scrap C storage is therefore reported under the "Other" source category.
29 Both the amount of yard trimmings collected annually and the fraction that is landfilled have declined over the last
30 decade. In 1990, over 53 million metric tons (wet weight) of yard trimmings and food scraps were generated (i.e.,
31 put at the curb for collection to be taken to disposal sites or to composting facilities) (EPA 2011; Schneider 2007,
32 2008). Since then, programs banning or discouraging yard trimmings disposal have led to an increase in backyard
33 composting and the use of mulching mowers, and a consequent 5 percent decrease in the tonnage generated (i.e.,
34 collected for composting or disposal). At the same time, an increase in the number of municipal composting
35 facilities has reduced the proportion of collected yard trimmings that are discarded in landfills—from 72 percent in
36 1990 to 33 percent in 2009. The net effect of the reduction in generation and the increase in composting is a 57
37 percent decrease in the quantity of yard trimmings disposed in landfills since 1990.
38 Food scraps generation has grown by 44 percent since 1990, and though the proportion of food scraps discarded in
Land Use, Land Use Change, and Forestry 7-55
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1 landfills has decreased slightly from 82 percent in 1990 to 80 percent in 2009, the tonnage disposed in landfills has
2 increased considerably (by 40%). Overall, the decrease in the yard trimmings landfill disposal rate has more than
3 compensated for the increase in food scrap disposal in landfills, and the net result is a decrease in annual landfill
4 carbon storage from 24.2 Tg CO2 Eq. in 1990 to 12.6 Tg CO2 Eq. in 2009 (Table 7-47 and Table 7-48).
Table 7-47: Net Changes in Yard Trimming and Food Scrap Stocks in Landfills (Tg CO2 Eq.)
Carbon Pool
1990
2000
2005
2006
2007
6 Note: Totals may not sum due to independent rounding.
7
8 Table 7-48: Net Changes in Yard Trimming and Food Scrap Stocks in Landfills (Tg C)
Carbon Pool
1990
2000
2005
2006
2007
2008 2009
Yard Trimmings
Grass
Leaves
Branches
Food Scraps
Total Net Flux
(21.0)
(1.8)
(9.0)
(10.2)
(3.2)
(24.2)
(8.8)
(0.7)
(3.9)
(4.2)
(4.4)
(13.2)
(7.3)
(0.6)
(3.3)
(3.3)
(4.3)
(11.5)
(7.5)
(0.6)
(3.4)
(3.4)
(3.5)
(11.0)
(7.0)
(0.6)
(3.2)
(3.2)
(3.9)
(10.9)
(7.3)
(0.7)
(3.4)
(3.3)
(3.9)
(11.2)
(8.5)
(0.8)
(3.9)
(3.8)
(4.1)
(12.6)
2008
2009
9
10
Yard Trimmings
Grass
Leaves
Branches
Food Scraps
Total Net Flux
(5.7) (2.4)
(0.5) (0.2)
(2.5) (1.1)
(2.8) (1.2)
(0.9) (1.2)
(6.6) (3.6)
(2.0)
(0.2)
(0.9)
(0.9)
(1.2)
(3.1)
(2.0)
(0.2)
(0.9)
(0.9)
(1.0)
(3.0)
(1.9)
(0.2)
(0.9)
(0.9)
(1.1)
(3.0)
(2.0)
(0.2)
(0.9)
(0.9)
(1.1)
(3.1)
(2.3)
(0.2)
(1.1)
(1.0)
(1.1)
(3.4)
Note: Totals may not sum due to independent rounding.
11 Methodology
12 When wastes of biogenic origin (such as yard trimmings and food scraps) are landfilled and do not completely
13 decompose, the C that remains is effectively removed from the global C cycle. Empirical evidence indicates that
14 yard trimmings and food scraps do not completely decompose in landfills (Barlaz 1998, 2005, 2008; De la Cruz and
15 Barlaz 2010), and thus the stock of carbon in landfills can increase, with the net effect being a net atmospheric
16 removal of carbon. Estimates of net C flux resulting from landfilled yard trimmings and food scraps were developed
17 by estimating the change in landfilled C stocks between inventory years, based on methodologies presented for the
18 Land Use, Land-Use Change, and Forestry sector in IPCC (2003). C stock estimates were calculated by determining
19 the mass of landfilled C resulting from yard trimmings or food scraps discarded in a given year; adding the
20 accumulated landfilled C from previous years; and subtracting the mass of C landfilled in previous years that
21 decomposed.
22 To determine the total landfilled C stocks for a given year, the following were estimated: (1) the composition of the
23 yard trimmings; (2) the mass of yard trimmings and food scraps discarded in landfills; (3) the C storage factor of the
24 landfilled yard trimmings and food scraps; and (4) the rate of decomposition of the degradable C. The composition
25 of yard trimmings was assumed to be 30 percent grass clippings, 40 percent leaves, and 30 percent branches on a
26 wet weight basis (Oshins and Block 2000). The yard trimmings were subdivided, because each component has its
27 own unique adjusted C storage factor and rate of decomposition. The mass of yard trimmings and food scraps
28 disposed of in landfills was estimated by multiplying the quantity of yard trimmings and food scraps discarded by
29 the proportion of discards managed in landfills. Data on discards (i.e., the amount generated minus the amount
30 diverted to centralized composting facilities) for both yard trimmings and food scraps were taken primarily from
31 Municipal Solid Waste Generation, Recycling, and Disposal in the United States: Facts and Figures for 2009 (EPA
32 2011), which provides datafor 1960, 1970, 1980, 1990, 2000, and 2005 through 2009. To provide data for some of
33 the missing years, detailed backup data were obtained from Schneider (2007, 2008). Remaining years in the time
34 series for which data were not provided were estimated using linear interpolation. The EPA (2011) report does not
35 subdivide discards of individual materials into volumes landfilled and combusted, although it provides an estimate
36 of the proportion of overall waste stream discards managed in landfills192 and combustors with energy recovery
192
EPA (2011) reports discards in two categories: "combustion with energy recovery" and "landfill, other disposal," which
7-56 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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1 (i.e., ranging from 100 percent and 0 percent respectively in 1960 to 81 percent and 19 percent in 2000); it is
2 assumed that the proportion of each individual material (food scraps, grass, leaves, branches) that is landfilled is the
3 same as the proportion across the overall waste stream.
4 The amount of C disposed of in landfills each year, starting in 1960, was estimated by converting the discarded
5 landfilled yard trimmings and food scraps from a wet weight to a dry weight basis, and then multiplying by the
6 initial (i.e., pre-decomposition) C content (as a fraction of dry weight). The dry weight of landfilled material was
7 calculated using dry weight to wet weight ratios (Tchobanoglous et al. 1993, cited by Barlaz 1998) and the initial C
8 contents and the C storage factors were determined by Barlaz (1998, 2005, 2008) (Table 7-49).
9 The amount of C remaining in the landfill for each subsequent year was tracked based on a simple model of C fate.
10 As demonstrated by Barlaz (1998, 2005, 2008), a portion of the initial C resists decomposition and is essentially
11 persistent in the landfill environment. Barlaz (1998, 2005, 2008) conducted a series of experiments designed to
12 measure biodegradation of yard trimmings, food scraps, and other materials, in conditions designed to promote
13 decomposition (i.e., by providing ample moisture and nutrients). After measuring the initial C content, the materials
14 were placed in sealed containers along with a "seed" containing methanogenic microbes from a landfill. Once
15 decomposition was complete, the yard trimmings and food scraps were re-analyzed for C content; the C remaining
16 in the solid sample can be expressed as a proportion of initial C (shown in the row labeled "CS" in Table 7-49).
17 The modeling approach applied to simulate U.S. landfill C flows builds on the findings of Barlaz (1998, 2005,
18 2008). The proportion of C stored is assumed to persist in landfills. The remaining portion is assumed to degrade,
19 resulting in emissions of CH4 and CO2 (the CH4 emissions resulting from decomposition of yard trimmings and food
20 scraps are accounted for in the "Waste" chapter). The degradable portion of the C is assumed to decay according to
21 first-order kinetics.
22 The first-order decay rates, k, for each component were derived from De la Cruz and Barlaz (2010). De la Cruz and
23 Barlaz (2010) calculate first-order decay rates using laboratory data published in Eleazer et al. (1997), and a
24 correction factor,/ is found so that the weighted average decay rate for all components is equal to the AP-42 default
25 decay rate (0.04) for mixed MSW for regions that receive more than 25 inches of rain annually. Because AP-42
26 values were developed using landfill data from approximately 1990, 1990 waste composition for the United States
27 from EPA's Characterization of Municipal Solid Waste in the United States: 1990 Update was used to calculate/
28 This correction factor is then multiplied by the Eleazer et al. (1997) decay rates of each waste component to develop
29 field-scale first-order decay rates.
30 De la Cruz and Barlaz (2010) also use other assumed initial decay rates for mixed MS W in place of the AP-42
31 default value based on different types of environments in which landfills in the United States are found, including
32 dry conditions (less than 25 inches of rain annually, k=0.02) and bioreactor landfill conditions (moisture is
33 controlled for rapid decomposition, k=0.l2). The Landfills section of the Inventory (which estimates CH4
34 emissions) estimates the overall MSW decay rate by partitioning the U.S. landfill population into three categories,
35 based on annual precipitation ranges of (1) less than 20 inches of rain per year, (2) 20 to 40 inches of rain per year,
36 and (3) greater than 40 inches of rain per year. These correspond to overall MSW decay rates of 0.020, 0.038, and
37 0.057 yr'1, respectively.
38 De la Cruz and Barlaz (2010) calculate component-specific decay rates corresponding to the first value (0.020 yr~:),
39 but not for the other two overall MSW decay rates. To maintain consistency between landfill methodologies across
40 the Inventory, the correction factors (/) were developed for decay rates of 0.038 and 0.057 yr~: through linear
41 interpolation. A weighted national average component-specific decay rate was calculated by assuming that waste
42 generation is proportional to population (the same assumption used in the landfill methane emission estimate), based
43 on population data from the 2000 U.S. Census. The component-specific decay rates are shown in Table 7-49.
44 For each of the four materials (grass, leaves, branches, food scraps), the stock of C in landfills for any given year is
45 calculated according to the following formula:
46
47 LFCy = E W^ x (1 - MC,) x ICC, x {[CS, x ICC,] + [(1 - (CS,• x ICC,)) x e^' ~n)]}
includes combustion without energy recovery. For years in which there is data from previous EPA reports on combustion without
energy recovery, EPA assumes these estimates are still applicable. For 2000 to present, EPA assumes that any combustion of
MSW that occurs includes energy recovery, so all discards to "landfill, other disposal" are assumed to go to landfills.
Land Use, Land Use Change, and Forestry 7-57
-------
where,
J
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
/ = Year for which C stocks are being estimated (year),
/' = Waste type for which C stocks are being estimated (grass, leaves, branches, food scraps),
LFCtf = Stock of C in landfills in year /, for waste /' (metric tons),
Win = Mass of waste /' disposed in landfills in yearn (metric tons, wet weight),
n = Year in which the waste was disposed (year, where 1960 <«
-------
1 Uncertainty and Time-Series Consistency
2 The uncertainty analysis for landfilled yard trimmings and food scraps includes an evaluation of the effects of
3 uncertainty for the following data and factors: disposal in landfills per year (tons of C), initial C content, moisture
4 content, decay rate, and proportion of C stored. The C storage landfill estimates are also a function of the
5 composition of the yard trimmings (i.e., the proportions of grass, leaves and branches in the yard trimmings
6 mixture). There are respective uncertainties associated with each of these factors.
7 A Monte Carlo (Tier 2) uncertainty analysis was applied to estimate the overall uncertainty of the sequestration
8 estimate. The results of the Tier 2 quantitative uncertainty analysis are summarized in Table 7-51. Total yard
9 trimmings and food scraps CO2 flux in 2009 was estimated to be between -21.2 and -6.2 Tg CO2 Eq. at a 95 percent
10 confidence level (or 19 of 20 Monte Carlo stochastic simulations). This indicates a range of 68 percent below to 51
11 percent above the 2009 flux estimate of -12.6 Tg CO2 Eq. More information on the uncertainty estimates for Yard
12 Trimmings and Food Scraps in Landfills is contained within the Uncertainty Annex.
13 Table 7-51: Tier 2 Quantitative Uncertainty Estimates for CO2 Flux from Yard Trimmings and Food Scraps in
14 Landfills (Tg CO2 Eq. and Percent)
Source
2009 Flux
Estimate
Gas (Tg CO2 Eq.)
Uncertainty Range Relative to Flux Estimate"
(Tg C02 Eq.) (%)
Lower Upper Lower Upper
Bound Bound Bound Bound
Yard Trimmings and
Food Scraps CO2 (12.6) (21.2) (6.2) -68% +51%
15 a Range of flux estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
16 Note: Parentheses indicate negative values or net C sequestration.
17
18 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
19 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
20 above.
21 QA/QC and Verification
22 A QA/QC analysis was performed for data gathering and input, documentation, and calculation.
23 Recalculations Discussion
24 First-order decay rate constants were updated based on De la Cruz and Barlaz (2010), as described in the
25 methodology section. Input data were updated for the years: 1990, 2000, 2005, and 2007 through 2009 based on the
26 updated values reported in Municipal Solid Waste Generation, Recycling, and Disposal in the United States: Facts
27 and Figures for 2009 (EPA 2011). As a result, C storage estimates for those years were revised relative to the
28 previous Inventory. While data inputs for intervening years in the timeseries were not revised, overall C storage in
29 any given year is dependent on the previous year's storage (as shown in the second equation above), and so C
30 storage estimates for those years were also revised. These revisions resulted in an annual average increase in C
31 stored in landfills of 4.2 percent across the timeseries.
32 Planned Improvements
33 Future work is planned to evaluate the potential contribution of inorganic C, primarily in the form of carbonates, to
34 landfill sequestration, as well as the consistency between the estimates of C storage described in this chapter and the
35 estimates of landfill CH4 emissions described in the Waste chapter.
36
37
38
Land Use, Land Use Change, and Forestry 7-59
-------
Figure 7-1
Percent of Total Land Area in the General Land Use Categories for 2009
Croplands
Forest Lands
Grasslands
Settlements
Wetlands
Other Lands
10% M1%-30% •31%-50% B>50%
Note: Land use/land-use change categories were aggregated into the 6 general land-use categories based on the current use in 2009.
-------
Figure 7-2
Forest Sector Carbon Pools and Flows
Combustion from
forest fires (carbon
dioxide, methane)
Combustion from forest fires
(carbon dioxide, methane)
Harvest
Processing/ Residue
/^^Consumption
* ^4
Soil Organic
Material
Methane
Flaring
and
Utilization
Legend
Carbon Pool
Carbon transfer or flux
Combustion
Source: Heath et al. 2003
-------
Harvested Wood
Soil
Forest, Nonsoil
Total Net Change
Figure 7-3: Estimates of Net Annual Changes in C Stocks for Major C Pools
-------
Figure 7-4
Average C Density in the Forest Tree Pool in the Conterminous United States, 2009
-------
Figure 7-5
Total Net Annual C02 Flux for Mineral Soils Under Agricultural Management within States,
2009, Cropland Remaining Cropland
Note: Values greater than zero represent emissions, and values less than zero represent sequestration. Map accounts for fluxes associated with the
Tier 2 and 3 Inventory computations. See Methodology for additional details.
-------
Figure 7-6
Total Net Annual C02 Flux for Organic Soils Under Agricultural Management within States,
2009, Cropland Remaining Cropland
O
0
Tg C02Eq./year
• >2
• 1to2
• 0.5 to 1
D 0.1 to 0.5
DO to 0.1
n No organic soils
Note: Values greater than zero represent emissions.
-------
Figure 7-7
Total Net Annual C02 Flux for Mineral Soils Under Agricultural Management within States,
2009, Land Converted to Cropland
o
Note: Values greater than zero represent emissions, and values less than zero represent sequestration. Map accounts for fluxes associated with the
Tier 2 and 3 Inventory computations. See Methodology for additional details.
-------
Figure 7-8
Total Net Annual C02 Flux for Organic Soils Under Agricultural Management within States,
2009, Land Converted to Cropland
Tg C02Eq./year
• 0.5 to 1
D 0.1 to 0.5
Do to 0.1
EH No organic soils
Note: Values greater than zero represent emissions.
-------
Figure 7-9
Total Net Annual C02 Flux for Mineral Soils Under Agricultural Management within States,
2009, Grassland Remaining Grassland
Tg C02 Eq./year
D>0
D -0.1 to 0
D-0.5 to-0.1
• -1 to -0.5
• -2 to -1
Note: Values greater than zero represent emissions, and values less than zero represent sequestration. Map accounts for fluxes associated with the
Tier 2 and 3 Inventory computations. See Methodology for additional details.
-------
Figure 7-10
Total Net Annual C02 Flux for Organic Soils Under Agricultural Management within States,
2009, Grassland Remaining Grassland
Tg C02Eq./year
|1to2
| 0.5 to 1
Q0.1 to 0.5
[]0 to 0.1
Q No organic soils
Note: Values greater than zero represent emissions.
-------
Figure 7-11
Total Net Annual C02 Flux for Mineral Soils Under Agricultural Management within States,
2009, Land Converted to Grassland
Note: Values greater than zero represent emissions, and values less than zero represent sequestration. Map accounts for fluxes associated with the
Tier 2 and 3 Inventory computations. See Methodology for additional details.
-------
Figure 7-12
Total Net Annual C02 Flux for Organic Soils Under Agricultural Management within States,
2009, Land Converted to Grassland
Tg C02Eq./year
• 0.5 to 1
D 0.1 to 0.5
Do to 0.1
CH No organic soils
Note: Values greater than zero represent emissions.
-------
i 8. Waste
2 Waste management and treatment activities are sources of greenhouse gas emissions (see Figure 8-1). Landfills
3 accounted for approximately 17 percent of total U.S. anthropogenic methane (CH4) emissions in 2009, the third
4 largest contribution of any CH4 source in the United States. Additionally, wastewater treatment and composting of
5 organic waste accounted for approximately 4 percent and less than 1 percent of U.S. CH4 emissions, respectively.
6 Nitrous oxide (N2O) emissions from the discharge of wastewater treatment effluents into aquatic environments were
7 estimated, as were N2O emissions from the treatment process itself. N2O emissions from composting were also
8 estimated. Together, these waste activities account for less than 3 percent of total U.S. N2O emissions. Nitrogen
9 oxides (NOX), carbon monoxide (CO), and non-CH4 volatile organic compounds (NMVOCs) are emitted by waste
10 activities, and are addressed separately at the end of this chapter. A summary of greenhouse gas emissions from the
11 Waste chapter is presented in Table 8-1 and Table 8-2.
12 CO2, N2O, and CH4 emissions from the incineration of waste are accounted for in the Energy sector rather than in
13 the Waste sector because almost all incineration of municipal solid waste (MSW) in the United States occurs at
14 waste-to-energy facilities where useful energy is recovered. Similarly, the Energy sector also includes an estimate of
15 emissions from burning waste tires because virtually all of the combustion occurs in industrial and utility boilers that
16 recover energy. The incineration of waste in the United States in 2009 resulted in 12.7 Tg CO2 Eq. emissions, nearly
17 half of which is attributable to the combustion of plastics. For more details on emissions from the incineration of
18 waste, see Section 3.3.
19
20 Figure 8-1: 2009 Waste Chapter Greenhouse Gas Sources
21
22 [BEGIN BOX]
23 Box 8-1: Methodological approach for estimating and reporting U.S. emissions and sinks
24 In following the UNFCCC requirement under Article 4.1 to develop and submit national greenhouse gas emissions
25 inventories, the emissions and sinks presented in this report, and this chapter, are organized by source and sink
26 categories and calculated using internationally-accepted methods provided by the Intergovernmental Panel on
27 Climate Change (IPCC) (http://www.ipcc-nggip.iges.or.jp/public/index.html). Additionally, the calculated
28 emissions and sinks in a given year for the U.S. are presented in a common manner in line with the UNFCCC
29 reporting guidelines for the reporting of inventories under this international agreement
30 (http://unfccc.int/national reports/annex ighg inventories/national inventories submissions/items/5270.php). The
31 use of consistent methods to calculate emissions and sinks by all nations providing their inventories to the UNFCCC
32 ensures that these reports are comparable. In this regard, U.S. emissions and sinks reported in this inventory report
33 are comparable to emissions and sinks reported by other countries. Emissions and sinks provided in this inventory
34 do not preclude alternative examinations (for example, see http://www.epa.gov/aboutepa/oswer.html), but rather this
35 inventory report presents emissions and sinks in a common format consistent with how countries are to report
36 inventories under the UNFCCC. The report itself, and this chapter, follows this standardized format, and provides
37 an explanation of the IPCC methods used to calculate emissions and sinks, and the manner in which those
38 calculations are conducted.
39 [END BOX]
40 Overall, in 2009, waste activities generated emissions of 150.5 Tg CO2 Eq., or just over 2 percent of total U.S.
41 greenhouse gas emissions.
42 Table 8-1. Emissions from Waste (Tg CO2 Eq.)
Gas/Source
CH4
Landfills
Wastewater Treatment
Composting
N2O
Domestic Wastewater
1990
171.2
147.4
23.5
0.3
4.0
3.7
2000
138.1
111.7
25.2
1.3
5.9
4.5
2005
138.4
112.5
24.3
1.6
6.5
4.8
2006
137.8
111.7
24.5
1.6
6.6
4.8
2007
137.4
111.3
24.4
1.7
6.7
4.9
2008
142.1
115.9
24.5
1.7
6.8
5.0
2009
143.6
117.5
24.5
1.7
6.9
5.0
Waste 8-1
-------
1
2
3
Treatment
Composting
Total
Note: Totals may not sum due to
0.4
175.2
1.4
143.9
1.7
144.9
1.8
144.4
1.8
144.1
1.9
149.0
1.8
150.5
independent rounding.
Table 8-2. Emissions from Waste (Gg)
Gas/Source
CH4
Landfills
Wastewater Treatment
Composting
N20
Domestic Wastewater
Treatment
Composting
1990
8,152
7,018
1,118
15
13
12
1
2000
6,576
5,317
1,199
60
19
14
4
2005
6,591
5,358
1,159
75
21
15
6
2006
6,566
5,324
1,167
75
21
16
6
2007
6,541
5,299
1,163
79
22
16
6
2008
6,769
5,520
1,168
80
22
16
6
2009
6,840
5,593
1,167
79
22
16
6
Note: Totals may not sum due to independent rounding.
5 8.1. Landfills (IPCC Source Category 6A1)
6 In 2009, landfill CH4 emissions were approximately 117.5 Tg CO2 Eq. (5,593 Gg of CH4), representing the third
7 largest source of CH4 emissions in the United States, behind natural gas systems and enteric fermentation.
8 Emissions from municipal solid waste (MSW) landfills, which received about 64.5 percent of the total solid waste
9 generated in the United States, accounted for about 94 percent of total landfill emissions, while industrial landfills
10 accounted for the remainder. Approximately 1,800 operational landfills exist in the United States, with the largest
11 landfills receiving most of the waste and generating the majority of the CH4 (BioCycle 2006, adjusted to include
12 missing data from five states).
13 After being placed in a landfill, waste (such as paper, food scraps, and yard trimmings) is initially decomposed by
14 aerobic bacteria. After the oxygen has been depleted, the remaining waste is available for consumption by anaerobic
15 bacteria, which break down organic matter into substances such as cellulose, amino acids, and sugars. These
16 substances are further broken down through fermentation into gases and short-chain organic compounds that form
17 the substrates for the growth of methanogenic bacteria. These CH4-producing anaerobic bacteria convert the
18 fermentation products into stabilized organic materials and biogas consisting of approximately 50 percent carbon
19 dioxide (CO2) and 50 percent CH4, by volume. Significant CH4 production typically begins one or two years after
20 waste disposal in a landfill and continues for 10 to 60 years or longer.
21 Methane emissions from landfills are a function of several factors, including: (1) the total amount of waste in MSW
22 landfills, which is related to total waste landfilled annually; (2) the characteristics of landfills receiving waste (i.e.,
23 composition of waste-in-place, size, climate); (3) the amount of CH4 that is recovered and either flared or used for
24 energy purposes; and (4) the amount of CH4 oxidized in landfills instead of being released into the atmosphere.
25 From 1990 to 2009, net CH4 emissions from landfills decreased by approximately 20 percent (see Table 8-3 and
26 Table 8-4). This net CH4 emissions decrease can be attributed to many factors, including changes in waste
27 composition, an increase in the amount of landfill gas collected and combusted, a higher frequency of composting,
28 and increased rates of recovery for degradeable materials (e.g, paper and paperboard).
29 The estimated annual quantity of waste placed in MSW landfills increased from about 209 Tg in 1990 to 297 Tg in
30 2009, an increase of 42 percent (see Annex 3.14). Despite increased waste disposal, the amount of decomposable
31 materials (i.e., paper and paperboard, food scraps, and yard trimmings) discarded in MSW landfills has decreased by
32 approximately 21percent from 1990 to 2008 (EPA, 2009b). In addition, the amount of landfill gas collected and
33 combusted has increased. In 1990, for example, approximately 970 Gg of CH4 were recovered and combusted (i.e.,
34 used for energy or flared) from landfills, while in 2009, 7,208 Gg CH4 was combusted, which represents a 3 percent
35 increase in the quantity of CH4 recovered and combusted from 2008 levels. In 2009, an estimated 49 new landfill
36 gas-to-energy (LFGTE) projects and 32 new flares began operation.
37 Over the past 9 years, however, the net CH4 emissions have fluctuated from year to year, but a slowly increasing
38 trend has been observed. While the amount of landfill gas collected and combusted continues to increase every
39 year, the rate of increase in collection and combustion no longer exceeds the rate of additional CH4 generation from
40 the amount of organic MSW landfilled as the U.S. population grows.
8-2 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Over the next several years, the total amount of municipal solid waste generated is expected to increase as the U.S.
2 population continues to grow. The percentage of waste landfilled, however, may decline due to increased recycling
3 and composting practices. In addition, the quantity of CH4 that is recovered and either flared or used for energy
4 purposes is expected to continue to increase as a result of 1996 federal regulations that require large municipal solid
5 waste landfills to collect and combust landfill gas (see 40 CFR Part 60, Subpart Cc 2005 and 40 CFR Part 60,
6 Subpart WWW 2005), voluntary programs that encourage CH4 recovery and use such as EPA's Landfill Methane
7 Outreach Program (LMOP), and federal and state incentives that promote renewable energy (e.g., tax credits, low
8 interest loans, and Renewable Portfolio Standards).
9 Table 8-3. CH4 Emissions from Landfills (Tg CO2 Eq.)
10
11
12
13
14
15
Activity
MSW Landfills
Industrial Landfills
Recovered
Gas-to-Energy
Flared
Oxidized3
Total
1990
172.6
11.5
(13.6)
(6.7)
(16.4)
147.4
2000
206.9
14.3
(49.4)
(47.8)
(12.4)
111.7
2005
241.2
15.2
(56.5)
(74.9)
(12.5)
112.5
2006
248.1
15.3
(59.0)
(80.2)
(12.4)
111.7
Note: Totals may not sum due to independent rounding. Parentheses indicate ne£
a Includes oxidation at both municipal and industrial landfills.
Table 8-4. CH4 Emissions from Landfills (Gg)
Activity
MSW Landfills
Industrial Landfills
Recovered
Gas-to-Energy
Flared
Oxidized3
Total
1990
8,219
549
(649)
(321)
(780)
7,018
2000
9,854
682
(2,352)
(2,276)
(591)
5,317
Note: Totals may not sum due to independent rounding.
a Includes oxidation at municipal and industrial landfills.
2005
11,486
724
(2,691)
(3,566)
(596)
5,358
2006
11,813
727
(2,807)
(3,820)
(592)
5,321
Parentheses indicate ne£
2007
254.2
15.4
(63.7)
(82.3)
(12.4)
111.3
'ative values.
2007
12,107
732
(3,033)
(3,918)
(589)
5,299
'ative values.
2008
260.3
15.5
(67.0)
(80.0)
(12.9)
115.9
2008
12,395
738
(3,189)
(3,810)
(614)
5,520
2009
266.3
15.6
(72.0)
(79.4)
(13.1)
117.5
2009
12,679
744
(3,429)
(3,779)
(622)
5,593
16 Methodology
17 A detailed description of the methodology used to estimate CH4 emissions from landfills can be found in
18 Annex 3.14.
19 CH4 emissions from landfills were estimated to equal the CH4 produced from municipal solid waste landfills, plus
20 the CH4 produced by industrial landfills, minus the CH4 recovered and combusted, minus the CH4 oxidized before
21 being released into the atmosphere:
22 CH4)s0i1(j waste= [CH4)MSW + CH4)In(j — R] — Ox
23 where,
24 CH4)Soild waste = CH4 emissions from solid waste
25 CH4MSW = CH4 generation from municipal solid waste landfills,
26 CH4jnd = CH4 generation from industrial landfills,
27 R CH4 recovered and combusted, and
28 Ox = CH4 oxidized from MSW and industrial landfills before release to the atmosphere.
29 The methodology for estimating CH4 emissions from municipal solid waste landfills is based on the first order decay
30 model described by the Intergovernmental Panel on Climate Change (IPCC 2006). Values for the CH4 generation
31 potential (L0) and rate constant (k) were obtained from an analysis of CH4 recovery rates for a database of 52
32 landfills and from published studies of other landfills (RTI2004; EPA 1998; SWANA 1998; Peer, Thorneloe, and
33 Epperson 1993). The rate constant was found to increase with average annual rainfall; consequently, values of k
34 were developed for 3 ranges of rainfall. The annual quantity of waste placed in landfills was apportioned to the 3
Waste 8-3
-------
1 ranges of rainfall based on the percent of the U.S. population in each of the 3 ranges, and historical census data were
2 used to account for the shift in population to more arid areas over time. For further information, see Annex 3.14.
3 National landfill waste generation and disposal data for 2007, 2008, and 2009 were extrapolated based on BioCycle
4 data and the U.S. Census population from 2009. Data for 1989 through 2006 were obtained from BioCycle (2008).
5 Because BioCycle does not account for waste generated in U. S. territories, waste generation for the territories was
6 estimated using population data obtained from the U.S. Census Bureau (2010) and national per capita solid waste
7 generation from BioCycle (2008). Estimates of the annual quantity of waste landfilled for 1960 through 1988 were
8 obtained from EPA's Anthropogenic Methane Emissions in the United States, Estimates for 1990: Report to
9 Congress (EPA 1993) and an extensive landfill survey by the EPA's Office of Solid Waste in 1986 (EPA 1988).
10 Although waste placed in landfills in the 1940s and 1950s contributes very little to current CH4 generation, estimates
11 for those years were included in the first order decay model for completeness in accounting for CH4 generation rates
12 and are based on the population in those years and the per capita rate for land disposal for the 1960s. For
13 calculations in this inventory, wastes landfilled prior to 1980 were broken into two groups: wastes disposed in
14 landfills (Methane Conversion Factor, MCF, of 1) and those disposed in dumps (MCF of 0.6). Please see Annex
15 3.14 for more details.
16 The estimated landfill gas recovered per year was based on updated data collected from vendors of flaring
17 equipment, a database of landfill gas-to-energy (LFGTE) projects compiled by LMOP (EPA 2009a), and a database
18 maintained by the Energy Information Administration (El A) for the voluntary reporting of greenhouse gases (El A
19 2007). As the EIA database only included data through 2006, 2007 to 2009 recovery for projects included in the
20 EIA database were assumed to be the same as in 2006. The three databases were carefully compared to identify
21 landfills that were in two or all three of the databases to avoid double counting reductions. Based on the information
22 provided by the EIA and flare vendor databases, the CH4 combusted by flares in operation from 1990 to 2009 was
23 estimated. This quantity likely underestimates flaring because these databases do not have information on all flares
24 in operation. Additionally, the EIA and LMOP databases provided data on landfill gas flow and energy generation
25 for landfills with LFGTE projects. If a landfill in the EIA database was also in the LMOP and/or the flare vendor
26 database, the emissions avoided were based on the EIA data because landfill owners or operators reported the
27 amount recovered based on measurements of gas flow and concentration, and the reporting accounted for changes
28 over time. If both flare data and LMOP recovery data were available for any of the remaining landfills (i.e., not in
29 the EIA database), then the emissions recovery was based on the LMOP data, which provides reported landfill-
30 specific data on gas flow for direct use projects and project capacity (i.e., megawatts) for electricity projects. The
31 flare data, on the other hand, only provided a range of landfill gas flow for a given flare size. Given that each
32 LFGTE project is likely to also have a flare, double counting reductions from flares and LFGTE projects in the
33 LMOP database was avoided by subtracting emission reductions associated with LFGTE projects for which a flare
34 had not been identified from the emission reductions associated with flares. A further explanation of the
35 improvements made to estimate the landfill gas recovered for the current Inventory can be found in Annex 3.14.
36 A destruction efficiency of 99 percent was applied to CH4 recovered to estimate CH4 emissions avoided. The value
37 for efficiency was selected based on the range of efficiencies (98 to 100 percent) recommended for flares in EPA's
38 AP-42 Compilation of Air Pollutant Emission Factors, Chapter 2.4 (EPA 1998), efficiencies used to establish new
39 source performance standards (NSPS) for landfills, and in recommendations for closed flares used in LMOP.
40 Emissions from industrial landfills were estimated from activity data for industrial production (ERG 2010), waste
41 disposal factors, and the first order decay model. As over 99 percent of the organic waste placed in industrial
42 landfills originated from the food processing (meat, vegetables, fruits) and pulp and paper industries, estimates of
43 industrial landfill emissions focused on these two sectors (EPA 1993). The amount of CH4 oxidized by the landfill
44 cover at both municipal and industrial landfills was assumed to be ten percent of the CH4 generated that is not
45 recovered (IPCC 2006, Mancinelli and McKay 1985, Czepiel et al. 1996). To calculate net CH4 emissions, both
46 CH4 recovered and CH4 oxidized were subtracted from CH4 generated at municipal and industrial landfills.
47 Uncertainty and Time-Series Consistency
48 Several types of uncertainty are associated with the estimates of CH4 emissions from landfills. The primary
49 uncertainty concerns the characterization of landfills. Information is not available on two fundamental factors
50 affecting CH4 production: the amount and composition of waste placed in every landfill for each year of its
51 operation. The approach used here assumes that the CH4 generation potential and the rate of decay that produces
52 CH4, as determined from several studies of CH4 recovery at landfills, are representative of U.S. landfills.
8-4 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Additionally, the approach used to estimate the contribution of industrial wastes to total CH4 generation introduces
2 uncertainty. Aside from uncertainty in estimating CH4 generation potential, uncertainty exists in the estimates of
3 oxidation by cover soils. There is also uncertainty in the estimates of CH4 that is recovered by flaring and energy
4 projects. The IPCC default value of 10 percent for uncertainty in recovery estimates was used in the uncertainty
5 analysis when metering was in place (for about 64 percent of the CH4 estimated to be recovered). For flaring
6 without metered recovery data (approximately 34 percent of the CH4 estimated to be recovered), a much higher
7 uncertainty of approximately 50 percent was used (e.g., when recovery was estimated as 50 percent of the flare's
8 design capacity).
9 N2O emissions from the application of sewage sludge on landfills are not explicitly modeled as part of greenhouse
10 gas emissions from landfills. N2O emissions from sewage sludge applied to landfills would be relatively small
11 because the microbial environment in landfills is not very conducive to the nitrification and denitrification processes
12 that result in N2O emissions. Furthermore, the 2006 IPCC Guidelines (IPCC 2006) did not include a methodology
13 for estimating N2O emissions from solid waste disposal sites "because they are not significant." Therefore, any
14 uncertainty or bias caused by not including N2O emissions from landfills is expected to be minimal.
15 The results of the IPCC Good Practice Guidance Tier 2 quantitative uncertainty analysis are summarized in Table
16 8-5. Landfill CH4 emissions in 2009 were estimated to be between 61.160.8 and 164.5 Tg CO2 Eq., which indicates
17 a range of 48 percent below to 40 percent above the 2009 emission estimate of 117.5 Tg CO2 Eq.
18 Table 8-5. Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Landfills (Tg CO2 Eq. and Percent)
2009 Emission
Estimate Uncertainty Range Relative to Emission Estimate"
Source Gas (Tg CO2 Eq.) (Tg CO2 Eq.) (%)
Landfills
MSW
Industrial
CH4
CH4
CH4
117.5
103.4
14.1
Lower
Bound
61.1
61.0
10.2
Upper
Bound
164.5
167.5
17.1
Lower
Bound
-48%
-41%
-28%
Upper
Bound
+40%
+62%
+21%
19 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
20 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
21 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
22 above.
23 QA/QC and Verification
24 A QA/QC analysis was performed for data gathering and input, documentation, and calculation. A primary focus of
25 the QA/QC checks was to ensure that methane recovery estimates were not double-counted. Both manual and
26 electronic checks were made to ensure that emission avoidance from each landfill was calculated in only one of the
27 three databases. The primary calculation spreadsheet is tailored from the IPCC waste model and has been verified
28 previously using the original, peer-reviewed IPCC waste model. All model input values were verified by secondary
29 QA/QC review.
30 Recalculations Discussion
31 In developing the current Inventory, a separate Monte Carlo analysis was conducted for MSW and industrial
32 landfills to better characterize the greater amount of uncertainty surrounding industrial waste data. Additional steps
33 were also taken to further better characterize the food waste decay rate and the methodology for the flare correction
34 factor. A weighted component-specific decay rate for food waste of 0.156 yf: was used in the current Inventory as
35 recommended by ICF International (2009). This replaced the previous Inventory's default food waste decay rate of
36 0.185 yr"1 and resulted in a decrease of landfill emissions of less than 1 percent. The majority of changes in CH4
37 emissions from landfills over the time series resulted from improvements made to the flare correction factor to better
38 associate flares in the flare vendor database with a landfill and/or Landfill Gas to Energy (LFGTE) project in the
39 EIA and LMOP databases.
40 The flare correction factor for the previous Inventory (1990-2008) consisted of approximately 512 cases where
41 flares were not directly associated with a landfill and/or LFGTE project in the EIA and/or LMOP databases. For
42 these projects, CH4 avoided would be overestimated as both the CH4 avoided from flaring and the LFGTE project
Waste 8-5
-------
1 would be counted. To abstain from overestimating emissions avoided from flaring, the CH4 avoided from flares with
2 no identified landfill or LFGTE project were determined and the flaring estimate from the flare vendor database was
3 reduced by this quantity (referred to as a flare correction factor) on a state-by-state basis.
4 If comprehensive data on flares were available, the majority of LFGTE projects in the EIA and LMOP databases
5 would have an identified flare because it is assumed that most LFGTE projects have flares. However, given that the
6 flare vendor data only covers approximately 50 to 75 percent of the flare population, an associated flare was not
7 identified for all LFGTE projects. These LFGTE projects likely have flares; however, flares were unable to be
8 identified due to one of two reasons: 1) inadequate identifier information provided by the flare vendor; or 2) a lack
9 of the flare in the flare vendor database.
10 Additional effort was undertaken to improve the methodology behind the flare correction factor for the current
11 Inventory to reduce the overall number of flares that were not matched (512) to landfills and/or LFGTE projects in
12 the EIA and LMOP databases. Each flare in the flare vendor database not associated with a LFGTE project in the
13 EIA or LMOP databases was investigated to determine if it could be matched to either a landfill in the EIA database
14 or a LFGTE project in the LMOP database. For some unmatched flares, the location information was missing or
15 incorrectly transferred to the flare vendor database. In other instances, the landfill names were slightly different
16 between what the flare vendor provided and the actual landfill name as listed in the EIA and/or LMOP databases.
17 It was found that a large majority of the unidentified flares are associated with landfills in LMOP that are currently
18 flaring, but are also considering LFGTE. These landfill projects considering a LFGTE project are labeled as
19 candidate, potential, or construction in the LMOP database. The flare vendor database was improved to match flares
20 with operational, shutdown as well as candidate, potential, and construction LFGTE projects, thereby reducing the
21 total number of unidentified flares in the flare vendor database, all of which are used in the flare correction factor.
22 The results of this effort significantly decreased the number of flares used in the flare correction factor from 512 to
23 27, impacted emission estimates for the entire time series, and resulted in an average annual decrease of 8.2 Tg CO2
24 Eq. (6.5 percent) in CH4 emissions from the Landfills source category for the period 1990 through 2008.
25 Planned Improvements
26 Beginning in 2010, all MSW landfills that accepted waste on or after January 1, 1980 and generate CH4 in amounts
27 equivalent to 25,000 metric tons or more of carbon dioxide equivalent (CO2e) will be required to calculate and
28 report their GHG emissions to EPA through its Greenhouse Gas Reporting Program (GHGRP). This source category
29 consists of the landfill, landfill gas collection systems, and landfill gas destruction devices including flares. In
30 addition to reporting GHG information to EPA, landfill specific characteristics such as annual waste disposal
31 quantity, waste composition data, surface area, and cover type must also be reported. The data collected from the
32 GHGRP will be used in future inventories to revise the parameters used in the CH4 generation calculations including
33 degradeable organic carbon (DOC), the flare correction factor, the methane correction factor (MCF), fraction of
34 DOC dissimilated (DOCF), the destruction efficiency of flares, the oxidation factor (Ox), and the rate constant (k).
35 The addition of this higher tier data will improve the emission calculations to provide a more accurate representation
36 of GHG emissions from MSW landfills.
37
38 [Begin Text Box]
39 Box 8-1: Biogenic Wastes in Landfills
40 Regarding the depositing of wastes of biogenic origin in landfills, empirical evidence shows, some of these wastes
41 degrade very slowly in landfills, and the carbon they contain is effectively sequestered in landfills over a period of
42 time (Barlaz 1998, 2006). Estimates of carbon removals from landfilling of forest products, yard trimmings, and
43 food scraps are further described in the Land Use, Land-Use Change, and Forestry chapter, based on methods
44 presented in IPCC (2003) and IPCC (2006).
45 [End Box]
46
8-6 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
i 8.2. Wastewater Treatment (IPCC Source Category 6B)
2 Wastewater treatment processes can produce anthropogenic CH4 and N2O emissions. Wastewater from domestic193
3 and industrial sources is treated to remove soluble organic matter, suspended solids, pathogenic organisms, and
4 chemical contaminants. Treatment may either occur on site, most commonly through septic systems or package
5 plants, or off site at centralized treatment systems. Centralized wastewater treatment systems may include a variety
6 of processes, ranging from lagooning to advanced tertiary treatment technology for removing nutrients. In the
7 United States, approximately 20 percent of domestic wastewater is treated in septic systems or other on-site systems,
8 while the rest is collected and treated centrally (U.S. Census Bureau 2009).
9 Soluble organic matter is generally removed using biological processes in which microorganisms consume the
10 organic matter for maintenance and growth. The resulting biomass (sludge) is removed from the effluent prior to
11 discharge to the receiving stream. Microorganisms can biodegrade soluble organic material in wastewater under
12 aerobic or anaerobic conditions, where the latter condition produces CH4. During collection and treatment,
13 wastewater may be accidentally or deliberately managed under anaerobic conditions. In addition, the sludge may be
14 further biodegraded under aerobic or anaerobic conditions. The generation of N2O may also result from the
15 treatment of domestic wastewater during both nitrification and denitrification of the N present, usually in the form of
16 urea, ammonia, and proteins. These compounds are converted to nitrate (NO3) through the aerobic process of
17 nitrification. Denitrification occurs under anoxic conditions (without free oxygen), and involves the biological
18 conversion of nitrate into dinitrogen gas (N2). N2O can be an intermediate product of both processes, but is more
19 often associated with denitrification.
20 The principal factor in determining the CH4 generation potential of wastewater is the amount of degradable organic
21 material in the wastewater. Common parameters used to measure the organic component of the wastewater are the
22 Biochemical Oxygen Demand (BOD) and Chemical Oxygen Demand (COD). Under the same conditions,
23 wastewater with higher COD (or BOD) concentrations will generally yield more CH4 than wastewater with lower
24 COD (or BOD) concentrations. BOD represents the amount of oxygen that would be required to completely
25 consume the organic matter contained in the wastewater through aerobic decomposition processes, while COD
26 measures the total material available for chemical oxidation (both biodegradable and non-biodegradable). Because
27 BOD is an aerobic parameter, it is preferable to use COD to estimate CH4 production. The principal factor in
28 determining the N2O generation potential of wastewater is the amount of N in the wastewater.
29 In 2009, CH4 emissions from domestic wastewater treatment were 16.0 Tg CO2 Eq. (760 Gg). Emissions gradually
30 increased from 1990 through 1997, but have decreased since that time due to decreasing percentages of wastewater
31 being treated in anaerobic systems, including reduced use of on-site septic systems and central anaerobic treatment
32 systems. In 2009, CH4 emissions from industrial wastewater treatment were estimated to be 8.5 Tg CO2 Eq. (407
33 Gg). Industrial emission sources have increased across the time series through 1999 and then fluctuated up and
34 down with production changes associated with the treatment of wastewater from the pulp and paper manufacturing,
35 meat and poultry processing, fruit and vegetable processing, starch-based ethanol production, and petroleum refining
36 industries. Table 8-6 and Table 8-7 provide CH4 and N2O emission estimates from domestic and industrial
37 wastewater treatment. With respect to N2O, the United States identifies two distinct sources for N2O emissions from
38 domestic wastewater: emissions from centralized wastewater treatment processes, and emissions from effluent from
39 centralized treatment systems that has been discharged into aquatic environments. The 2009 emissions of N2O from
40 centralized wastewater treatment processes and from effluent were estimated to be 0.3 Tg CO2 Eq. (1 Gg) and 4.7
41 Tg CO2 Eq. (15.2 Gg), respectively. Total N2O emissions from domestic wastewater were estimated to be 5.0 Tg
42 CO2 Eq. (16.2 Gg). N2O emissions from wastewater treatment processes gradually increased across the time series
43 as a result of increasing U.S. population and protein consumption.
44 Table 8-6. CH4 and N2O Emissions from Domestic and Industrial Wastewater Treatment (Tg CO2 Eq.)
Activity
CH4
Domestic
Industrial*
N2O
1990
23.5
16.4
7.1
3.7
2000
25.2
16.8
8.4
4.5
2005
24.3
16.2
8.2
4.8
2006
24.5
16.0
8.5
4.8
2007
24.4
15.9
8.5
4.9
2008
24.5
15.8
8.6
5.0
2009
24.5
16.0
8.5
5.0
193 Throughout the inventory, emissions from domestic wastewater also include any commercial and industrial wastewater
collected and co-treated with domestic wastewater.
Waste 8-7
-------
Domestic 3/7 4.5 4.8 4.8 4.9 5.0 5.0
Total 27.2 29.6 29.1 29.3 29.3 29.5 29.5
1 Industrial activity includes the pulp and paper manufacturing, meat and poultry processing, fruit and vegetable processing,
2 starch-based ethanol production, and petroleum refining industries.
3 Note: Totals may not sum due to independent rounding.
4
5 Table 8-7. CH4 and N2O Emissions from Domestic and Industrial Wastewater Treatment (Gg)
Activity
CH4
Domestic
Industrial*
N2O
Domestic
1990
1,118
780
338
11.9
11.9
2000
1,199
801
398
14.4
14.4
2005
1,159
770
389
15.4
15.4
2006
1,167
764
403
15.5
15.5
2007
1,163
758
405
15.8
15.8
2008
1,168
759
409
16.0
16.0
2009
1,167
760
407
16.2
16.2
6 * Industrial activity includes the pulp and paper manufacturing, meat and poultry processing, fruit and vegetable processing,
7 starch-based ethanol production, and petroleum refining industries.
8 Note: Totals may not sum due to independent rounding.
9 Methodology
10 Domestic Wastewater CH4 Emission Estimates
11 Domestic wastewater CH4 emissions originate from both septic systems and from centralized treatment systems,
12 such as publicly owned treatment works (POTWs). Within these centralized systems, CH4 emissions can arise from
13 aerobic systems that are not well managed or that are designed to have periods of anaerobic activity (e.g.,
14 constructed wetlands), anaerobic systems (anaerobic lagoons and facultative lagoons), and from anaerobic digesters
15 when the captured biogas is not completely combusted. CH4 emissions from septic systems were estimated by
16 multiplying the total 5-day BOD (BOD5) produced in the United States by the percent of wastewater treated in
17 septic systems (20 percent), the maximum CH4 producing capacity for domestic wastewater (0.60 kg CH^g BOD),
18 and the CH4 correction factor (MCF) for septic systems (0.5). CH4 emissions from POTWs were estimated by
19 multiplying the total BOD5 produced in the United States by the percent of wastewater treated centrally (80 percent),
20 the relative percentage of wastewater treated by aerobic and anaerobic systems, the relative percentage of
21 wastewater facilities with primary treatment, the percentage of BOD5 treated after primary treatment (67.5 percent),
22 the maximum CH4-producing capacity of domestic wastewater (0.6), and the relative MCFs for aerobic (zero or 0.3)
23 and anaerobic (0.8) systems with all aerobic systems assumed to be well-managed. CH4 emissions from anaerobic
24 digesters were estimated by multiplying the amount of biogas generated by wastewater sludge treated in anaerobic
25 digesters by the proportion of CH4 in digester biogas (0.65), the density of CH4 (662 g CH4/m3 CH4), and the
26 destruction efficiency associated with burning the biogas in an energy/thermal device (0.99). The methodological
27 equations are:
28 Emissions from Septic Systems = A
29 = (% onsite) x (total BOD5 produced) x (B0) x (MCF-septic) x 1/10A6
30 Emissions from Centrally Treated Aerobic Systems = B
31 = [(% collected) x (total BOD5 produced) x (% aerobic) x (% aerobic w/out primary) + (% collected) x (total BOD5
32 produced) x (% aerobic) x (% aerobic w/primary) x (l-% BOD removed in prim, treat.)] x (% operations not well
33 managed) x (B0) x (MCF-aerobic_not_well_man) x 1/10A6
34 Emissions from Centrally Treated Anaerobic Systems = C
35 = [(% collected) x (total BOD5 produced) x (% anaerobic) x (% anaerobic w/out primary) + (% collected) x (total
36 BOD5 produced) x (% anaerobic) x (% anaerobic w/primary) x (1-%BOD removed in prim, treat.)] x (B0) x (MCF-
37 anaerobic) x 1/10A6
3 8 Emissions from Anaerobic Digesters = D
39 = [(POTW_flow_AD) x (digester gas)/ (per capita flow)] x conversion to m3 x (FRAC_CH4) x (365.25) x (density
40 ofCH4) x(l-DE) x 1/10A9
8-8 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1
2
o
J
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
Total CH4 Emissions (Gg) = A + B + C + D
Where:
% onsite
% collected
% aerobic
% anaerobic
% aerobic w/out primary
% aerobic w/primary
% BOD removed in prim, treat.
% operations not well managed
% anaerobic w/out primary
% anaerobic w/primary
Total BOD5 produced
Bo
MCF-septic
1/10A6
MCF-aerobic_not_well_man.
MCF-anaerobic
DE
POTW_flow
digester gas
AD
per capita flow
conversion to m3
FRAC_CH4
density of CH4
1/10A9
= Flow to septic systems / total flow
= Flow to POTWs / total flow
= Flow to aerobic systems / total flow to POTWs
= Flow to anaerobic systems / total flow to POTWs
= Percent of aerobic systems that do not employ primary treatment
= Percent of aerobic systems that employ primary treatment
= 32.5%
= Percent of aerobic systems that are not well managed and in which
some anaerobic degradation occurs
= Percent of anaerobic systems that do not employ primary treatment
= Percent of anaerobic systems that employ primary treatment
= kg BOD/capita/day x U.S. population x 365.25 days/yr
= Maximum CH4-producing capacity for domestic wastewater (0.60 kg
CH4/kgBOD)
= CH4 correction factor for septic systems (0.5)
= Conversion factor, kg to Gg
= CH4 correction factor for aerobic systems that are not well managed
(0.3)
= CH4 correction factor for anaerobic systems (0.8)
= CH4 destruction efficiency from flaring or burning in engine (0.99 for
enclosed flares)
= Wastewater influent flow to POTWs that have anaerobic digesters (gal)
= Cubic feet of digester gas produced per person per day (1.0
ft3/person/day) (Metcalf and Eddy 1991)
= Wastewater flow to POTW per person per day (100 gal/person/day)
= Conversion factor, ft3 to m3 (0.0283)
= Proportion CH4 in biogas (0.65)
= 662 (g CH^rn3 CH4)
= Conversion factor, g to Gg
U.S. population data were taken from the U.S. Census Bureau International Database (U.S. Census 2010) and
include the populations of the United States, American Samoa, Guam, Northern Mariana Islands, Puerto Rico, and
the Virgin Islands. Table 8-8 presents U.S. population and total BOD5 produced for 1990 through 2009, while Table
8-9 presents domestic wastewater CH4 emissions for both septic and centralized systems in 2009. The proportions
of domestic wastewater treated onsite versus at centralized treatment plants were based on data from the 1989, 1991,
1993, 1995, 1997, 1999, 2001, 2003, 2005, 2007, and 2009 American Housing Surveys conducted by the U.S.
Census Bureau (U.S. Census 2009), with data for intervening years obtained by linear interpolation. The percent of
wastewater flow to aerobic and anaerobic systems, the percent of aerobic and anaerobic systems that do and do not
employ primary treatment, and the wastewater flow to POTWs that have anaerobic digesters were obtained from the
1992, 1996, 2000, and 2004 Clean Watershed Needs Survey (EPA 1992, 1996, 2000, and 2004a). Data for
intervening years were obtained by linear interpolation and the years 2004 through 2009 were forecasted from the
rest of the time series. The BOD5 production rate (0.09 kg/capita/day) and the percent BOD5 removed by primary
treatment for domestic wastewater were obtained from Metcalf and Eddy (1991 and 2003). The CH4 emission
factor (0.6 kg CH4/kg BOD5) and the MCFs were taken from IPCC (2006). The CH4 destruction efficiency for
methane recovered from sludge digestion operations, 99 percent, was selected based on the range of efficiencies (98
to 100 percent) recommended for flares in AP-42 Compilation of Air Pollutant Emission Factors, Chapter 2.4 (EPA
1998), efficiencies used to establish new source performance standards (NSPS) for landfills, and in
recommendations for closed flares used by the Landfill Methane Outreach Program (LMOP). The cubic feet of
digester gas produced per person per day (1.0 ft3/person/day) and the proportion of CH4 in biogas (0.65) come from
Metcalf and Eddy (1991). The wastewater flow to a POTW (100 gal/person/day) was taken from the Great Lakes-
Upper Mississippi River Board of State and Provincial Public Health and Environmental Managers, "Recommended
Standards for Wastewater Facilities (Ten-State Standards)" (2004).
Waste 8-9
-------
Table 8-8. U.S. Population (Millions) and Domestic Wastewater BOD5 Produced (Gg)
Year Population BODS
1990
254
80 o o
,333
2000
286
9,414
2005
2006
2007
2008
2009
300
303
306
309
311
9,864
9,958
10,057
10,149
10,236
Source: U.S. Census Bureau (2010); Metcalf & Eddy 1991 and 2003.
Table 8-9. Domestic Wastewater CH4 Emissions from Septic and Centralized Systems (2009)
CH4 emissions (Tg CO2 Eq.) % of Domestic Wastewater CH4
Septic Systems
Centralized Systems
13.2
2.8
82.5%
17.5%
Total
16.0
100%
Note: Totals may not sum due to independent rounding.
Industrial Wastewater CH4 Emission Estimates
7 CH4 emissions estimates from industrial wastewater were developed according to the methodology described in
8 IPCC (2006). Industry categories that are likely to produce significant CH4 emissions from wastewater treatment
9 were identified. High volumes of wastewater generated and a high organic wastewater load were the main criteria.
10 The top five industries that meet these criteria are pulp and paper manufacturing; meat and poultry processing;
1 1 vegetables, fruits, and juices processing; starch-based ethanol production; and petroleum refining. Wastewater
12 treatment emissions for these sectors for 2009 are displayed in Table 8-10 below. Table 8-1 1 contains production
1 3 data for these industries.
14
15 Table 8-10. Industrial Wastewater CH4 Emissions by Sector (2009)
Pulp & Paper
Meat & Poultry
Petroleum Refineries
Fruit & Vegetables
Ethanol Refineries
Total
CH4 emissions (Tg CO2 Eq.)
4.1
3.6
0.6
0.1
0.1
8.5
16 Note: Totals may not sum due to independent rounding.
17 Table 8-11. U.S. Pulp and Paper, Meat, Poultry, Vegetables,
18 Production (Tg)
Pulp and
Year Paper
Meat Poultry
(Live Weight (Live Weight
Killed) Killed)
% of Industrial Wastewater CH4
48%
42%
7%
1%
1%
100%
Fruits and Juices, Ethanol, and Petroleum Refining
Vegetables,
Fruits and Petroleum
Juices Ethanol Refining
1990
128.9
27.3
14.6
38.7
2.7
702.4
2000
32.1
22.2
50.9
4.9
795.2
19
2005
2006
2007
2008
2009
131.4
137.4
135.9
134.5
137.0
31.4
32.5
33.4
34.4
33.8
25.1
25.5
26.0
26.6
25.2
42.9
42.9
44.7
45.1
47.0
11.7
14.5
19.4
26.9
31.7
818.6
826.7
827.6
836.8
822.4
8-10 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 CH4 emissions from these categories were estimated by multiplying the annual product output by the average
2 outflow, the organics loading (in COD) in the outflow, the percentage of organic loading assumed to degrade
3 anaerobically, and the emission factor. Ratios of BOD: COD in various industrial wastewaters were obtained from
4 EPA (1997a) and used to estimate COD loadings. The B0 value used for all industries is the IPCC default value of
5 0.25 kg CH4/kg COD (IPCC 2006).
6 For each industry, the percent of plants in the industry that treat wastewater on site, the percent of plants that have a
7 primary treatment step prior to biological treatment, and the percent of plants that treat wastewater anaerobically
8 were defined. The percent of wastewater treated anaerobically onsite (TA) was estimated for both primary treatment
9 and secondary treatment. For plants that have primary treatment in place, an estimate of COD that is removed prior
10 to wastewater treatment in the anaerobic treatment units was incorporated.
11 The methodological equations are:
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Where:
CH4 (industrial wastewater) = P x W x COD x %TA x B0 x MCF
%TAp = [%Plants0 x %WWa,p x %CODp]
%TAS = [%Plantsa x %WWa,s x %CODS] + [%Plantst x %WWa,t x %CODS
CH4 (industrial wastewater) = Total CH4 emissions from industrial wastewater (kg/year)
P = Industry output (metric tons/year)
W = Wastewater generated (nrVmetric ton of product)
COD = Organics loading in wastewater (kg/m3)
%TA = Percent of wastewater treated anaerobically on site
%TAP = Percent of wastewater treated anaerobically on site in primary treatment
%TAS = Percent of wastewater treated anaerobically on site in secondary treatment
%Plants0 = Percent of plants with onsite treatment
%WWaj, = Percent of wastewater treated anaerobically in primary treatment
%CODp = Percent of COD entering primary treatment
%Plantsa = Percent of plants with anaerobic secondary treatment
%Plantst = Percent of plants with other secondary treatment
"/oWW^s = Percent of wastewater treated anaerobically in anaerobic secondary treatment
"/oWW^t = percent of wastewater treated anaerobically in other secondary treatment
%CODS = percent of COD entering secondary treatment
B0 = Maximum CH4 producing potential of industrial wastewater (default value of
0.25 kg CH4/kg COD)
MCF = CH4 correction factor, indicating the extent to which the organic content
(measured as COD) degrades anaerobically
36 As described below, the values presented in Table 8-12 were used in the emission calculations.
37 Table 8-12. Variables Used to Calculate Percent Wastewater Treated Anaerobically by Industry (%
Industry
Variable
%TAP
%TAS
%Plants0
%Plantsa
%Plantst
%wwap
%wwa,s
%wwa,t
%CODD
Pulp
and
Paper
0
10.5
60
25
35
0
100
0
100
Meat
Processing
0
33
100
33
67
0
100
0
100
Poultry
Processing
0
25
100
25
75
0
100
0
100
Fruit/
Vegetable
Processing
0
4.2
11
5.5
5.5
0
100
0
100
Ethanol
Production
-Wet Mill
0
33.3
100
33.3
66.7
0
100
0
100
Ethanol
Production
- Dry Mill
0
75
100
75
25
0
100
0
100
Petroleum
Refining
0
100
100
100
0
0
100
0
100
Waste 8-11
-------
%COD5 42 100 100 77 100 100 100
1
2 Pulp and Paper. Wastewater treatment for the pulp and paper industry typically includes neutralization, screening,
3 sedimentation, and flotation/hydrocycloning to remove solids (World Bank 1999, Nemerow and Dasgupta 1991).
4 Secondary treatment (storage, settling, and biological treatment) mainly consists of lagooning. In determining the
5 percent that degrades anaerobically, both primary and secondary treatment were considered. In the United States,
6 primary treatment is focused on solids removal, equalization, neutralization, and color reduction (EPA 1993). The
7 vast majority of pulp and paper mills with on-site treatment systems use mechanical clarifiers to remove suspended
8 solids from the wastewater. About 10 percent of pulp and paper mills with treatment systems use settling ponds for
9 primary treatment and these are more likely to be located at mills that do not perform secondary treatment (EPA
10 1993). However, because the vast majority of primary treatment operations at U.S. pulp and paper mills use
11 mechanical clarifiers, and less than 10 percent of pulp and paper wastewater is managed in primary settling ponds
12 that are not expected to have anaerobic conditions, negligible emissions are assumed to occur during primary
13 treatment.
14 Approximately 42 percent of the BOD passes on to secondary treatment, which consists of activated sludge, aerated
15 stabilization basins, or non-aerated stabilization basins. No anaerobic activity is assumed to occur in activated
16 sludge systems or aerated stabilization basins (note: although IPCC recognizes that some CH4 can be emitted from
17 anaerobic pockets, they recommend an MCF of zero). However, about 25 percent of the wastewater treatment
18 systems used in the United States are non-aerated stabilization basins. These basins are typically 10 to 25 feet deep.
19 These systems are classified as anaerobic deep lagoons (MCF = 0.8).
20 A time series of CH4 emissions for 1990 through 2001 was developed based on production figures reported in the
21 Lockwood-Post Directory (Lockwood-Post 2002). Published data from the American Forest and Paper Association,
22 data published by Paper Loop, and other published statistics were used to estimate production for 2002 through 2009
23 (Pulp and Paper 2005, 2006, and monthly reports from 2003 through 2008; Paper 360° 2007). The overall
24 wastewater outflow was estimated to be 85 nrYmetric ton, and the average BOD concentrations in raw wastewater
25 was estimated to be 0.4 gram BOD/liter (EPA 1997b, EPA 1993, World Bank 1999).
26 Meat and Poultry Processing. The meat and poultry processing industry makes extensive use of anaerobic lagoons
27 in sequence with screening, fat traps and dissolved air flotation when treating wastewater on site. About 33 percent
28 of meat processing operations (EPA 2002) and 25 percent of poultry processing operations (U.S. Poultry 2006)
29 perform on-site treatment in anaerobic lagoons. The IPCC default B0 of 0.25 kg CH4/kg COD and default MCF of
30 0.8 for anaerobic lagoons were used to estimate the CH4 produced from these on-site treatment systems. Production
31 data, in carcass weight and live weight killed for the meat and poultry industry, were obtained from the USDA
32 Agricultural Statistics Database and the Agricultural Statistics Annual Reports (USDA 2010). Data collected by
33 EPA's Office of Water provided estimates for wastewater flows into anaerobic lagoons: 5.3 and 12.5 nrVmetric ton
34 for meat and poultry production (live weight killed), respectively (EPA 2002). The loadings are 2.8 and 1.5 g
35 BOD/liter for meat and poultry, respectively.
36 Vegetables, Fruits, and Juices Processing. Treatment of wastewater from fruits, vegetables, and juices processing
37 includes screening, coagulation/settling, and biological treatment (lagooning). The flows are frequently seasonal,
38 and robust treatment systems are preferred for on-site treatment. Effluent is suitable for discharge to the sewer.
39 This industry is likely to use lagoons intended for aerobic operation, but the large seasonal loadings may develop
40 limited anaerobic zones. In addition, some anaerobic lagoons may also be used (Nemerow and Dasgupta 1991).
41 Consequently, 4.2 percent of these wastewater organics are assumed to degrade anaerobically. The IPCC default B0
42 of 0.25 kg CH/^kg COD and default MCF of 0.8 for anaerobic treatment were used to estimate the CH4 produced
43 from these on-site treatment systems. The USDA National Agricultural Statistics Service (USDA 2010) provided
44 production data for potatoes, other vegetables, citrus fruit, non-citrus fruit, and grapes processed for wine. Outflow
45 and BOD data, presented in Table 8-13, were obtained from EPA (1974) for potato, citrus fruit, and apple
46 processing, and from EPA (1975) for all other sectors.
47 Table 8-13. Wastewater Flow (nrVton) and BOD Production (g/L) for U.S. Vegetables, Fruits, and Juices Production
Commodity Wastewater Outflow (m3/ton) BOD (g/L)
Vegetables
Potatoes 10.27 1.765
Other Vegetables 8.74 0.801
Fruit
8-12 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Apples 3.66 1.371
Citrus 10.11 0.317
Non-citrus 12.42 1.204
Grapes (for wine) _ 2.783 _ 1.831
1
2 Ethanol Production. Ethanol, or ethyl alcohol, is produced primarily for use as a fuel component, but is also used in
3 industrial applications and in the manufacture of beverage alcohol. Ethanol can be produced from the fermentation
4 of sugar-based feedstocks (e.g., molasses and beets), starch- or grain-based feedstocks (e.g., corn, sorghum, and
5 beverage waste), and cellulosic biomass feedstocks (e.g., agricultural wastes, wood, and bagasse). Ethanol can also
6 be produced synthetically from ethylene or hydrogen and carbon monoxide. However, synthetic ethanol comprises
7 only about 2 percent of ethanol production, and although the Department of Energy predicts cellulosic ethanol to
8 greatly increase in the coming years, currently it is only in an experimental stage in the United States. According to
9 the Renewable Fuels Association, 82 percent of ethanol production facilities use corn as the sole feedstock and 7
10 percent of facilities use a combination of corn and another starch-based feedstock. The fermentation of corn is the
1 1 principal ethanol production process in the United States and is expected to increase through 20 12, and potentially
12 more; therefore, emissions associated with wastewater treatment at starch-based ethanol production facilities were
13 estimated (ERG 2006).
14 Ethanol is produced from corn (or other starch-based feedstocks) primarily by two methods: wet milling and dry
15 milling. Historically, the majority of ethanol was produced by the wet milling process, but now the majority is
16 produced by the dry milling process. The wastewater generated at ethanol production facilities is handled in a
17 variety of ways. Dry milling facilities often combine the resulting evaporator condensate with other process
18 wastewaters, such as equipment wash water, scrubber water, and boiler blowdown and anaerobically treat this
19 wastewater using various types of digesters. Wet milling facilities often treat their steepwater condensate in
20 anaerobic systems followed by aerobic polishing systems. Wet milling facilities may treat the stillage (or processed
2 1 stillage) from the ethanol fermentation/distillation process separately or together with steepwater and/or wash water.
22 CH4 generated in anaerobic digesters is commonly collected and either flared or used as fuel in the ethanol
23 production process (ERG 2006).
24 Available information was compiled from the industry on wastewater generation rates, which ranged from 1.25
25 gallon per gallon ethanol produced (for dry milling) to 10 gallons per gallon ethanol produced (for wet milling)
26 (Ruocco 2006a,b; Merrick 1998; Donovan 1996; and NRBP 2001). COD concentrations were also found to be
27 about 3 g/L (Ruocco 2006a; Merrick 1998; White and Johnson 2003). The amount of wastewater treated
28 anaerobically was estimated, along with how much of the CH4 is recovered through the use of biomethanators (ERG
29 2006). CH4 emissions were then estimated as follows:
30
3 1 Methane = [Production x Flow x COD x 3.785 x ([%Plants0 x %WWa>p x %CODP] + [%Plantsa x %WWa,s
32 x%CODs] + [%PlantSt x %WWa,t x %CODS]) x B0 x MCF x % Not Recovered] + [Production x Flow x 3.785 x
33 COD x ([%Plants0 x %WWa,p x %CODP] + [%Plantsa x %WWa,s x %CODS] + [%Plantst x %WWa,t x %CODS])
x
a,p P
34 B0 x MCF x (% Recovered) x (1-DE)] x 1/10A9
35 Where:
36
37 Production = gallons ethanol produced (wet milling or dry milling)
38 Flow = gallons wastewater generated per gallon ethanol produced (1.25 dry milling, 10 wet
39 milling)
40 COD = COD concentration in influent (3 g/1)
41 3.785 = conversion, gallons to liters
42 %Plants0 = percent of plants with onsite treatment (100%)
43 %WWa>p = percent of wastewater treated anaerobically in primary treatment (0%)
44 %CODP = percent of COD entering primary treatment (100%)
45 %Plantsa = percent of plants with anaerobic secondary treatment (33.3% wet, 75% dry)
46 %Plantst = percent of plants with other secondary treatment (66.7% wet, 25% dry)
47 %WWa>s = percent of wastewater treated anaerobically in anaerobic secondary treatment (100%)
48 %WWa>t = percent of wastewater treated anaerobically in other secondary treatment (0%)
49 %CODS = percent of COD entering secondary treatment (100%)
50 B0 = maximum methane producing capacity (0.25 g CH4/g COD)
Waste 8-13
-------
1 MCF = methane conversion factor (0.8 for anaerobic systems)
2 % Recovered = percent of wastewater treated in system with emission recovery
3 % Not Recovered= 1 - percent of wastewater treated in system with emission recovery
4 DE = destruction efficiency of recovery system (99%)
5 1/10A9 = conversion factor, g to Gg
6 A time series of CH4 emissions for 1990 through 2009 was developed based on production data from the Renewable
7 Fuels Association (RFA 2010).
8 Petroleum Refining. Petroleum refining wastewater treatment operations produce CH4 emissions from anaerobic
9 wastewater treatment. The wastewater inventory section includes CH4 emissions from petroleum refining
10 wastewater treated on site under intended or unintended anaerobic conditions. Most facilities use aerated biological
11 systems, such as trickling filters or rotating biological contactors; these systems can also exhibit anaerobic
12 conditions that can result in the production of CH4. Oil/water separators are used as a primary treatment method;
13 however, it is unlikely that any COD is removed in this step.
14 Available information from the industry was compiled. The wastewater generation rate, from CARD (2007) and
15 Timm (1985), was determined to be 35 gallons per barrel of finished product. An average COD value in the
16 wastewater was estimated at 0.45 kg/m3 (Benyahia et al. 2006).
17 The equation used to calculate CH4 generation at petroleum refining wastewater treatment systems is presented
18 below:
19 Methane = Flow x COD x B0 x MCF
20 Where:
21 Flow = Annual flow treated through anaerobic treatment system (m3/year)
22 COD = COD loading in wastewater entering anaerobic treatment system (kg/m3)
23 B0 = maximum methane producing potential of industrial wastewater (default value of 0.25
24 kg CH4 /kg COD)
25 MCF = methane conversion factor (0.3)
26
27 A time series of CH4 emissions for 1990 through 2009 was developed based on production data from the Energy
28 Information Association (EIA 2010).
29 Domestic Wastewater N2O Emission Estimates
30 N2O emissions from domestic wastewater (wastewater treatment) were estimated using the IPCC (2006)
31 methodology, including calculations that take into account N removal with sewage sludge, non-consumption and
32 industrial wastewater N, and emissions from advanced centralized wastewater treatment plants:
33 • In the United States, a certain amount of N is removed with sewage sludge, which is applied to land, incinerated,
34 or landfilled (NSLUDGE). The N disposal into aquatic environments is reduced to account for the sewage sludge
35 application.
36 • The IPCC methodology uses annual, per capita protein consumption (kg protein/[person-year]). For this
37 inventory, the amount of protein available to be consumed is estimated based on per capita annual food
38 availability data and its protein content, and then adjusts that data using a factor to account for the fraction of
39 protein actually consumed.
40 • Small amounts of gaseous nitrogen oxides are formed as by-products in the conversion of nitrate to N gas in
41 anoxic biological treatment systems. Approximately 7 grams N2O is generated per capita per year if wastewater
42 treatment includes intentional nitrification and denitrification (Scheehle and Doom 2001). Analysis of the 2004
43 CWNS shows that plants with denitrification as one of their unit operations serve a population of 2.4 million
44 people. Based on an emission factor of 7 grams per capita per year, approximately 21.2 metric tons of additional
45 N2O may have been emitted via denitrification in 2004. Similar analyses were completed for each year in the
46 Inventory using data from CWNS on the amount of wastewater in centralized systems treated in denitrification
47 units. Plants without intentional nitrification/denitrification are assumed to generate 3.2 grams N2O per capita
48 per year.
8-14 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 N2O emissions from domestic wastewater were estimated using the following methodology:
2 N2OTOTAL = N2OpLANT + N2OEFFLUENT
3 N2OpLANT = N2C>NIT/DEMT + N2OwOUT MT/DEMT
4 N2ONiT/DEMT= [(USpopND) x EF2 x FIND-COM] x 1/10A9
5 N20WOUT MT/DEMT = {[(USPOP x WWTP) - USpoPNc] x FIND-COM x EFj} x 1/10A9
6 N2OEFFLUENT = {[((USpop - (0.9 x USpopNTj)) x Protein x FNPR x FNON-CON x F^D-COM) - NSLUDGE] x EF3 x 44/28} x
7 1/10A6
8 where,
9 N2OTOTAL = Annual emissions of N2O (Gg)
10 N2OPLANT = N2O emissions from centralized wastewater treatment plants (Gg)
11 ^OMIT/DEMIT = N2O emissions from centralized wastewater treatment plants with
12 nitrification/denitrification (Gg)
13 N2Owour NIT/DENIT = N2O emissions from centralized wastewater treatment plants without
14 nitrification/denitrification (Gg)
15 N2OEFFLUENT = N2O emissions from wastewater effluent discharged to aquatic environments (Gg)
16 USpop = U.S. population
17 USpopND = U.S. population that is served by biological denitrification (from CWNS)
18 WWTP = Fraction of population using WWTP (as opposed to septic systems)
19 EFi = Emission factor (3.2 g N2O/person-year) - plant with no intentional denitrification
20 EF2 = Emission factor (7 g N2O/person-year) - plant with intentional denitrification
21 Protein = Annual per capita protein consumption (kg/person/year)
22 FNPR = Fraction of N in protein, default = 0.16 (kg N/kg protein)
23 FNON-CON = Factor for non-consumed protein added to wastewater (1.4)
24 FIND-COM =Factor for industrial and commercial co-discharged protein into the sewer system
25 (1.25)
26 NSLUDGE = N removed with sludge, kg N/yr
27 EF3 = Emission factor (0.005 kg N2O -N/kg sewage-N produced) - from effluent
28 0.9 = Amount of nitrogen removed by denitrification systems
29 44/28 = Molecular weight ratio of N2O to N2
30 U.S. population data were taken from the U.S. Census Bureau International Database (U.S. Census 2010) and
31 include the populations of the United States, American Samoa, Guam, Northern Mariana Islands, Puerto Rico, and
32 the Virgin Islands. The fraction of the U.S. population using wastewater treatment plants is based on data from the
33 1989, 1991, 1993, 1995, 1997, 1999, 2001, 2003, 2005, 2007, and 2009 American Housing Survey (U.S. Census
34 2009). Data for intervening years were obtained by linear interpolation. The emission factor (EFi) used to estimate
35 emissions from wastewater treatment was taken from IPCC (2006). Data on annual per capita protein intake were
36 provided by U.S. Department of Agriculture Economic Research Service (USDA 2009). Protein consumption data
37 for 2005 through 2009 were extrapolated from data for 1990 through 2004. Table 8-14 presents the data for U.S.
38 population and average protein intake. An emission factor to estimate emissions from effluent (EF3) has not been
39 specifically estimated for the United States, thus the default IPCC value (0.005 kg N2O-N/kg sewage-N produced)
40 was applied. The fraction of N in protein (0.16 kg N/kg protein) was also obtained from IPCC (2006). The factor
41 for non-consumed protein and the factor for industrial and commercial co-discharged protein were obtained from
42 IPCC (2006). Sludge generation was obtained from EPA (1999) for 1988, 1996, and 1998 and from Beecher et al.
43 (2007) for 2004. Intervening years were interpolated, and estimates for 2005 through 2009 were forecasted from the
44 rest of the time series. An estimate for the nitrogen removed as sludge (NSLUDGE) was obtained by determining the
45 amount of sludge disposed by incineration, by land application (agriculture or other), through surface disposal, in
46 landfills, or through ocean dumping. In 2009, 271 Tg N was removed with sludge.
47 Table 8-14. U.S. Population (Millions), Available Protein (kg/person-year), and Protein Consumed (kg/person-year)
Year Population Available Protein Protein Consumed
1990 254 38.7 29.6
2000 286 41.3 31.6
2005 300 41.7 32.1
Waste 8-15
-------
2006
2007
2008
2009
303
306
309
311
41.9
42.1
42.2
42.4
32.1
32.2
32.4
32.5
1 Source: U.S. Census Bureau 2010, USDA 2009.
2 Uncertainty and Time-Series Consistency
3 The overall uncertainty associated with both the 2009 CH4 and N2O emission estimates from wastewater treatment
4 and discharge was calculated using the IPCC Good Practice Guidance Tier 2 methodology (2000). Uncertainty
5 associated with the parameters used to estimate CH4 emissions include that of numerous input variables used to
6 model emissions from domestic wastewater, and wastewater from pulp and paper manufacture, meat and poultry
7 processing, fruits and vegetable processing, ethanol production, and petroleum refining. Uncertainty associated with
8 the parameters used to estimate N2O emissions include that of sewage sludge disposal, total U.S. population,
9 average protein consumed per person, fraction of N in protein, non-consumption nitrogen factor, emission factors
10 per capita and per mass of sewage-N, and for the percentage of total population using centralized wastewater
11 treatment plants.
12 The results of this Tier 2 quantitative uncertainty analysis are summarized in Table 8-15. CH4 emissions from
13 wastewater treatment were estimated to be between 15.3 and 35.9 Tg CO2 Eq. at the 95 percent confidence level (or
14 in 19 out of 20 Monte Carlo Stochastic Simulations). This indicates a range of approximately 37 percent below to
15 47 percent above the 2009 emissions estimate of 24.5 Tg CO2 Eq. N2O emissions from wastewater treatment were
16 estimated to be between 1.2 and 9.7 Tg CO2 Eq., which indicates a range of approximately 76 percent below to 93
17 percent above the actual 2009 emissions estimate of 5.0 Tg CO2 Eq.
18 Table 8-15. Tier 2 Quantitative Uncertainty Estimates for CH4 Emissions from Wastewater Treatment (Tg CO2 Eq.
19 and Percent)
Source
Wastewater Treatment
Domestic
Industrial
Wastewater Treatment
2009 Emission
Gas Estimate
(Tg CO2 Eq.)
CH4
CH4
CH4
N2O
24.5
16.0
8.5
5.0
Uncertainty Range Relative to Emission
Estimate"
(Tg CO2 Eq.) (%)
Lower
Bound
15.3
7.6
5.1
1.2
Upper
Bound
35.9
26.6
13.1
9.7
Lower
Bound
-37%
-52%
-41%
-76%
Upper
Bound
+47%
+66%
+54%
+93%
20 a Range of emission estimates predicted by Monte Carlo Stochastic Simulation for a 95 percent confidence interval.
21 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
22 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
23 above.
24 QA/QC and Verification
25 A QA/QC analysis was performed on activity data, documentation, and emission calculations. This effort included a
26 Tier 1 analysis, including the following checks:
27 • Checked for transcription errors in data input;
28 • Ensured references were specified for all activity data used in the calculations;
29 • Checked a sample of each emission calculation used for the source category;
30 • Checked that parameter and emission units were correctly recorded and that appropriate conversion factors
31 were used;
32 • Checked for temporal consistency in time series input data for each portion of the source category;
33 • Confirmed that estimates were calculated and reported for all portions of the source category and for all years;
34 • Investigated data gaps that affected emissions estimates trends; and
35 • Compared estimates to previous estimates to identify significant changes.
36 All transcription errors identified were corrected. The QA/QC analysis did not reveal any systemic inaccuracies or
8-16 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 incorrect input values.
2 Planned Improvements Discussion
3 The methodology to estimate CH4 emissions from domestic wastewater treatment currently utilizes estimates for the
4 percentage of centrally treated wastewater that is treated by aerobic systems and anaerobic systems. These data
5 come from the 1992, 1996, 2000, and 2004 CWNS. The question of whether activity data for wastewater treatment
6 systems are sufficient across the timeline to further differentiate aerobic systems with the potential to generate small
7 amounts of CH4 (aerobic lagoons) versus other types of aerobic systems, and to differentiate between anaerobic
8 systems to allow for the use of different MCFs for different types of anaerobic treatment systems, continues to be
9 explored. Recently available CWNS data for 2008 also is being evaluated for incorporation into the inventory. Due
10 to significant changes in format, this dataset was unable to be included in the domestic wastewater calculations for
11 the 1990-2009 Inventory. However, EPA continues to evaluate ways to incorporate the updated data into future
12 years of the Inventory.
13 Currently, it is assumed that all aerobic systems are well managed and produce no CH4 and that all anaerobic
14 systems have an MCF of 0.8. Efforts to obtain better data reflecting emissions from various types of municipal
15 treatment systems are currently being pursued.
16 A review of other industrial wastewater treatment sources for those industries believed to discharge significant loads
17 of BOD and COD has been ongoing. Food processing industries have the highest potential for CH4 generation due
18 to the waste characteristics generated, and the greater likelihood to treat the wastes anaerobically. However, in all
19 cases there is dated information available on U.S. treatment operations for these industries. A review of the organic
20 chemicals industry was conducted in April 2010 during which only 1987 data was readily identified. It was
21 concluded that current industry-level treatment system information is very difficult to obtain, as is time series data.
22 Based on the 1987 data, emissions from this source are small and are not a likely industry category for significant
23 methane emissions. Therefore, this industry has not been included in the Inventory and there are no near future
24 plans to do so. Similarly, the seafood processing industry was reviewed to estimate its potential to generate CH4.
25 Due to minimal anaerobic wastewater treatment operations at processing facilities, this industry was not selected for
26 inclusion in the Inventory. Other industries will be reviewed as necessary for inclusion in future years of the
27 Inventory.
28 Available data will be reviewed regarding anaerobic treatment at petroleum refineries. If necessary, the %TA for
29 this industry will be revised accordingly. Currently, all petroleum plants are assumed to have anaerobic treatment.
30 With respect to estimating N2O emissions, the default emission factor for indirect N2O from wastewater effluent and
31 direct N2O from centralized wastewater treatment facilities has a high uncertainty. Current research is being
32 conducted by the Water Environment Research Foundation (WERF) to measure N2O emissions from municipal
33 treatment systems. Such data will be reviewed as they are available to determine if a country-specific N2O emission
34 factor can or should be developed. In addition, WERF recently conducted a study of greenhouse gas emissions from
35 septic systems located in California. This study concluded that the emission rate for methane and nitrous oxide were
36 10.7 and 0.20 g/capita-d, respectively. EPA is currently reviewing the results of this study to determine if the
37 systems evaluated are representative of U. S. operations and if a country-specific factor for septic systems can be
38 introduced into the inventory. The effect would be to lower current estimates of methane emissions by about half,
39 and to include nitrous oxide emission estimate where previously none were calculated.
40 In addition, the estimate of N entering municipal treatment systems is under review. The factor that accounts for
41 non-sewage nitrogen in wastewater (bath, laundry, kitchen, industrial components) also has a high uncertainty.
42 Obtaining data on the changes in average influent N concentrations to centralized treatment systems over the time
43 series would improve the estimate of total N entering the system, which would reduce or eliminate the need for other
44 factors for non-consumed protein or industrial flow. The dataset previously provided by the National Association of
45 Clean Water Agencies (NACWA) was reviewed to determine if it was representative of the larger population of
46 centralized treatment plants for potential inclusion into the inventory. However, this limited dataset was not
47 representative of the number of systems by state or the service populations served in the United States, and therefore
48 could not be incorporated into the inventory methodology. Additional data sources will continue to be researched
49 with the goal of improving the uncertainty of the estimate of N entering municipal treatment systems.
Waste 8-17
-------
i 8.3. Composting (IPCC Source Category 6D)
2 Composting of organic waste, such as food waste, garden (yard) and park waste, and sludge, is common in the
3 United States. Advantages of composting include reduced volume in the waste material, stabilization of the waste,
4 and destruction of pathogens in the waste material. The end products of composting, depending on its quality, can
5 be recycled as fertilizer and soil amendment, or be disposed in a landfill.
6 Composting is an aerobic process and a large fraction of the degradable organic carbon in the waste material is
7 converted into carbon dioxide (CO2). Methane (CH4) is formed in anaerobic sections of the compost, but it is
8 oxidized to a large extent in the aerobic sections of the compost. Anaerobic sections are created in composting piles
9 when there is excessive moisture or inadequate aeration (or mixing) of the compost pile. The estimated CH4
10 released into the atmosphere ranges from less than 1 percent to a few percent of the initial C content in the material
11 (IPCC 2006). Composting can also produce nitrous oxide (N2O) emissions. The range of the estimated emissions
12 varies from less than 0.5 percent to 5 percent of the initial nitrogen content of the material (IPCC 2006).
13 From 1990 to 2009, the amount of material composted in the United States has increased from 3,810 Ggto 19,857
14 Gg, an increase of approximately 421 percent. From 2000 to 2009, the amount of material composted in the United
15 States has increased by approximately 33 percent. Emissions of CH4 and N2O from composting have increased by
16 the same percentage (see Table 8-16 and Table 8-17). In 2009, CH4 emissions from composting were 1.7 Tg CO2
17 Eq. (79 Gg), and N2O emissions from composting were 1.8 Tg CO2 Eq. (6 Gg). The wastes that are composted
18 include primarily yard trimmings (grass, leaves, and tree and brush trimmings) and food scraps from residences and
19 commercial establishments (such as grocery stores, restaurants, and school and factory cafeterias). The composting
20 waste quantities reported here do not include backyard composting. The growth in composting is attributable
21 primarily to two factors: (1) steady growth in population and residential housing, and (2) state and local
22 governments started enacting legislation that discouraged the disposal of yard trimmings in landfills. In 1992, 11
23 states and the District of Columbia had legislation in effect that banned or discouraged disposal of yard trimmings in
24 landfills. In 2005, 21 states and the District of Columbia, representing about 50 percent of the nation's population,
25 had enacted such legislation (EPA 2008).
26 Table 8-16. CH4 and N2O Emissions from Composting (Tg CO2 Eq.)
27
28
Activity
CH4
N2O
Total
Table 8-17.
Activity
CH4
N2O
1990
0.3
0.4
0.7
CH4andN2O
1990
15
1
2000
1.3
1.4
2.7
Emissions
2000
60
4
2005
1.6
1.7
3.3
2006
1.6
1.8
3.3
2007
1.7
1.8
3.5
2008
1.7
1.9
3.5
2009
1.7
1.8
3.5
from Composting (Gg)
2005
75
6
2006
75
6
2007
79
6
2008
80
6
2009
79
6
29 Methodology
30 CH4 and N2O emissions from composting depend on factors such as the type of waste composted, the amount and
31 type of supporting material (such as wood chips and peat) used, temperature, moisture content and aeration during
32 the process.
33 The emissions shown in Table 8-16 and Table 8-17 were estimated using the IPCC default (Tier 1) methodology
34 (IPCC 2006), which is the product of an emission factor and the mass of organic waste composted (note: no CH4
35 recovery is expected to occur at composting operations):
36 Et=Mx EFl
37 where,
38 E! = CH4 or N2O emissions from composting, Gg CH4 or N2O,
39 M = mass of organic waste composted in Gg,
40 EF; = emission factor for composting, 4 g CH4/kg of waste treated (wet basis) and 0.3 g
41 N2O/kg of waste treated (wet basis), and
8-18 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 i = designates either CH4 or N2O.
2 Estimates of the quantity of waste composted (M) are presented in Table 8-18. Estimates of the quantity composted
3 for 1990 and 1995 were taken from the Characterization of Municipal Solid Waste in the United States: 1996
4 Update (Franklin Associates 1997); estimates of the quantity composted for 2000, 2005, 2006, 2007, and 2008 were
5 taken from EPA's Municipal Solid Waste In The United States: 2008 Facts and Figures (EPA 2009); estimates of
6 the quantity composted for 2009 were calculated using the 2008 quantity composted.
7 Table 8-18: U.S. Waste Composted (Gg)
Activity 1990 2000 2005 2006 2007 2008 2009
Waste Composted 3,810 14,923 18,643 18,852 19,695 20,049 19,857
8 Source: Franklin Associates 1997 and EPA 2009.
9 Uncertainty and Time-Series Consistency
10 The estimated uncertainty from the 2006 IPCC Guidelines is ±50 percent for the Tier 1 methodology. Emissions
11 from composting in 2009 were estimated to be between 1.8 and 5.3 Tg CO2 Eq., which indicates a range of 50
12 percent below to 50 percent above the actual 2009 emission estimate of 3.5 Tg CO2 Eq. (see Table 8-19).
13 Table 8-19 : Tier 1 Quantitative Uncertainty Estimates for Emissions from Composting (Tg CO2 Eq. and Percent)
2009 Emission
Source Gas Estimate Uncertainty Range Relative to Emission Estimate
(Tg CO2 Eq.) (Tg CO2 Eq.) (%)
Lower
Bound
Upper
Bound
Lower
Bound
Upper
Bound
Composting CH4, N2O 3.5 L8 5.3 -50% +50%
14 Methodological recalculations were applied to the entire time-series to ensure time-series consistency from 1990
15 through 2009. Details on the emission trends through time are described in more detail in the Methodology section,
16 above.
17 Planned Improvements
18 For future Inventories, additional efforts will be made to improve the estimates of CH4 and N2O emissions from
19 composting. For example, a literature search may be conducted to determine if emission factors specific to various
20 composting systems and composted materials are available.
21 8.4. Waste Sources of Indirect Greenhouse Gases - TO BE UPDATED
22
23
24
25
26
27
In addition to the main greenhouse gases addressed above, waste generating and handling processes are also sources
of indirect greenhouse gas emissions. Total emissions of NOX, CO, and NMVOCs from waste sources for the years
1990 through 2008 are provided in Table 8-20.
Table 8-20: Emissions of NOX, CO, and NMVOC from Waste (Gg)
Gas/Source
NOX
Landfills
Wastewater Treatment
Miscellaneous3
CO
Landfills
Wastewater Treatment
Miscellaneous3
NMVOCs
Wastewater Treatment
Miscellaneous3
Landfills
1990
+
+
+
+
1
1
+
+
673
58
57
557
a Miscellaneous includes TSDFs (Treatment, Stora^
[42 U.S.C. § 6924, SWDA §
1995
1
1
+
1
2
2
+
1
731
68
61
602
>e, and Disposal
2000
2
2
+
+
8
7
1
+
119
22
51
46
Facilities
2005
2
2
+
+
7
6
+
+
114
22
49
43
2006
2
2
+
+
7
6
+
+
113
21
49
43
2007
2
2
+
+
7
6
+
+
111
21
48
42
2008
2
2
+
+
7
6
+
+
109
21
47
41
under the Resource Conservation and Recovery Act
3004]) and other waste categories.
Waste 8-19
-------
1 Note: Totals may not sum due to independent rounding.
2 + Does not exceed 0.5 Gg.
3
4 Methodology
5 These emission estimates were obtained from preliminary data (EPA 2009), and disaggregated based on EPA
6 (2003), which, in its final iteration, will be published on the National Emission Inventory (NEI) Air Pollutant
7 Emission Trends web site. Emission estimates of these gases were provided by sector, using a "top down"
8 estimating procedure—emissions were calculated either for individual sources or for many sources combined, using
9 basic activity data (e.g., the amount of raw material processed) as an indicator of emissions. National activity data
10 were collected for individual source categories from various agencies. Depending on the source category, these
11 basic activity data may include data on production, fuel deliveries, raw material processed, etc.
12
13 Uncertainty and Time-Series Consistency
14 No quantitative estimates of uncertainty were calculated for this source category. Methodological recalculations
15 were applied to the entire time-series to ensure time-series consistency from 1990 through 2008.
8-20 DRAFT Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Landfills
Wastewater Treatment
Composting
I
25
Waste as a Portion of all
Emissions
2.3%
50 75
TgC02Eq.
100
Figure 8-1: 2009 Waste Chapter Greenhouse Gas Sources
125
-------
i 9. Other
2 The United States does not report any greenhouse gas emissions under the Intergovernmental Panel on Climate
3 Change (IPCC) "Other" sector.
Other 9-1
-------
i 10. Recalculations and Improvements
2 Each year, emission and sink estimates are recalculated and revised for all years in the Inventory of U. S. Greenhouse
3 Gas Emissions and Sinks, as attempts are made to improve both the analyses themselves, through the use of better
4 methods or data, and the overall usefulness of the report. In this effort, the United States follows the 2006 IPCC
5 Guidelines (IPCC 2006), which states, "Both methodological changes and refinements over time are an essential
6 part of improving inventory quality. It is good practice to change or refine methods" when: available data have
7 changed; the previously used method is not consistent with the IPCC guidelines for that category; a category has
8 become key; the previously used method is insufficient to reflect mitigation activities in a transparent manner; the
9 capacity for inventory preparation has increased; new inventory methods become available; and for correction of
10 errors."
11 The results of all methodological changes and historical data updates are presented in this section; detailed
12 descriptions of each recalculation are contained within each source's description found in this report, if applicable.
13 Table 10-1 summarizes the quantitative effect of these changes on U.S. greenhouse gas emissions and Table 10-2
14 summarizes the quantitative effect on net CO2 flux to the atmosphere, both relative to the previously published U.S.
15 Inventory (i.e., the 1990 through 2008 report). These tables present the magnitude of these changes in units of
16 teragrams of carbon dioxide equivalent (Tg CO2 Eq.).
17 The Recalculations Discussion section of each source presents the details of each recalculation. In general, when
18 methodological changes have been implemented, the entire time series (i.e., 1990 through 2008) has been
19 recalculated to reflect the change, per IPCC (2006). Changes in historical data are generally the result of changes in
20 statistical data supplied by other agencies.
21 The following emission sources, which are listed in descending order of absolute average annual change in
22 emissions between 1990 and 2008, underwent some of the most important methodological and historical data
23 changes. A brief summary of the recalculation and/or improvement undertaken is provided for each emission source.
24 • Natural Gas Systems (CH^. For the current Inventory, methodologies for gas well cleanups and condensate
25 storage tanks were revised, and new data sources for centrifugal compressors with wet seals, unconventional
26 gas well completions, and unconventional gas well workovers were used, relative to the previous Inventory. The
27 net effect of these changes increased total CH4 emissions from natural gas systems between 46.5 and 119.7
28 percent each year between 1990 and 2008, resulting in an overall annual average increase of 79.3 Tg CO2 Eq.
29 (66.4 percent). The natural gas production segment accounted for the largest increases, largely due to the
30 methodological changes to gas well cleanups and the addition of unconventional gas well completions and
31 workovers.
32 • Landfills (CH4) Changes in CH4 emissions from Landfills relative to the previous Inventory resulted from
33 improvements made to better associate flares with the correct landfills or Landfill Gas to Energy projects across
34 the nation. In addition, steps were also taken to further better characterize the food waste decay rate. A weighted
35 component-specific decay rate for food waste of 0.156 yr"1 was used in the current Inventory replacing the
36 previous Inventory's default food waste decay rate of 0.185 yr"1 These revisions impacted emission estimates
37 for the entire time series and resulted in an average annual decrease of 8.3 Tg CO2 Eq. (6.5 percent) in CH4
38 emissions from Landfills for the period 1990 through 2008.
39 • Non-Energy Uses of Fossil Fuels (CO 2). Updates to the El A Manufacturer's Energy Consumption Survey
40 (MECS) for 2006 resulted in changes to CO2 emissions from Non-Energy Uses of Fossil Fuels for 2003 through
41 2008 relative to the previous Inventory. Adjustments were made to the entire MECS time series to remove scrap
42 tire consumption for use as a fuel, which is associated with the Waste Incineration chapter. In addition,
43 emissions from synthetic rubber were revised across the entire time series. These changes impacted emission
44 estimates from 1990 through 2008 resulting in an average annual decrease in CO2 emissions of 4.1 Tg CO2 Eq.
45 (2.1 percent) across the entire time series.
46 • Fossil Fuel Combustion (CO^. The Energy Information Administration updated energy consumption statistics
47 across the time series, relative to the previous Inventory, which resulted in changes to CO2 emissions from
48 Fossil Fuel Combustion. These revisions primarily impacted the emission estimates for 2007 and 2008.
49 Additionally, the coal emissions for U.S. Territories decreased from 2001 to 2008 due to the closure of a coal
50 power plant in the U.S. Virgin Islands. Overall, these changes resulted in an average annual increase of 3.8 Tg
51 CO2 Eq. (less than 0.1 percent) in CO2 emissions from Fossil Fuel Combustion for the period 1990 through
Recalculations and Improvements 10-1
-------
1 2008 relative to the previous Inventory.
2 • Manure Management (CH4). Changes in CH4 emissions from Manure Management relative to the previous
3 Inventory resulted from several updates. Volatile solid production rates for all animal types were updated based
4 on data from the USDA and EPA's Cattle Enteric Fermentation Model. In addition, USDA data on swines were
5 re-categorized, which changed the typical animal mass for two categories. These changes impacted emission
6 estimates for the entire time series and resulted in an average annual increase of 3.5 Tg CO2 Eq. (9.4 percent) in
7 CH4 emissions from Manure Management across the entire time series relative to the previous Inventory.
8 • Agricultural Soil Management (N2O). Changes in N2O emissions from Agricultural Soil Management relative to
9 the previous Inventory resulted from methodological changes for estimating grassland areas and livestock
10 manure nitrogen. These recalculations have opposing effects on emissions; grassland area was reduced,
11 resulting in lower emissions, and livestock manure nitrogen increased, resulting in higher emissions. These
12 changes affected the entire time series, resulting in an average annual reduction in N2O emissions of 3.2 Tg CO2
13 Eq. (1.5 percent) for the period 1990 through 2008 relative to the previous Inventory.
14 • Iron and Steel Production & Metallurgical Coke Production (CO2). A calculation error in the previous
15 Inventory regarding coal tar production and coke breeze production estimates was corrected for the current
16 Inventory, resulting in an average annual decrease in CO2 emissions from Iron and Steel Production &
17 Metallurgical Coke Production of 2.2 Tg CO2 Eq. (2.7 percent) for the period 1990 through 2008.
18 • Petroleum Systems (CH4). Well completion venting, well drilling, and offshore platform activity factors were
19 updated relative to the previous Inventory from existing data sources from 1990 onward, and the emission
20 factor for venting from fixed roof storage tanks in the crude oil production segment was increased to reflect the
21 occurrence of gas venting through storage tanks. These changes affected the entire time series from Petroleum
22 Systems, resulting in an average annual increase in CH4 emissions of 1.3 Tg CO2 Eq. (4.3 percent) for the
23 period 1990 through 2008 relative to the previous report.
24 • Nitric Acid Production (N2O). Changes in N2O emission from Nitric Acid Production relative to the previous
25 Inventory resulted from updated information on abatement technologies in use at production facilities and
26 revised production data from the U.S. Census Bureau. These changes resulted in an average annual decrease in
27 N2O emissions of 1.3 Tg CO2 Eq. (6.7 percent) across the entire time series relative to the previous report.
28 • Electrical Transmission and Distribution (SF6). SF6 emission estimates for the period 1990 through 2008 were
29 updated relative to the previous Inventory based on 1) new data from EPA's SF6 Emission Reduction
30 Partnership; 2) revisions to interpolated and extrapolated non-reported Partner data; and 3) a correction made to
31 2004 transmission mile data for a large Partnership utility that had been interpreted incorrectly from the UDI
32 database in previous years. In addition, the method for estimating potential emissions from the sector was
33 updated for the current Inventory to assume that all SF6 purchased by equipment manufacturers is either emitted
34 or sent to utilities. These changes affected the entire time series, resulting in an average annual increase of 1.2
35 Tg CO2 Eq. (6.6 percent) for the period 1990 through 2008 relative to the previous report.
36
37 Table 10-1: Revisions to U.S. Greenhouse Gas Emissions (Tg CO2 Eq.)
Gas/Source
C02
Fossil Fuel Combustion
Electricity Generation
Transportation
Industrial
Residential
Commercial
U.S. Territories
Non-Energy Use of Fuels
Iron and Steel Production & Metallurgical
Coke Production
Natural Gas Systems
Cement Production
1990
(0.7)
5.5
+
0.2
3.9
(0.8)
2.3
NC
(3.4)
(3.0)
0.3
NC
2000
(1.0)
4.3
+
+
1.7
(0.5)
3.2
NC
(3.7)
(2.2)
0.5
NC
2005
6.3
2.3
+
1.3
(0.1)
(0.5)
2.3
(0.7)
4.7
(1.8)
0.4
NC
2006
5.4
4.1
NC
1.4
1.3
(0.5)
2.6
(0.7)
1.0
(1.8)
1.2
NC
2007
1.2
3.6
+
0.2
3.7
0.7
2.0
(3.0)
(1.2)
(1.8)
0.2
NC
2008
1.3
(4.1)
(2.6)
4.7
(13.7)
5.5
4.7
(2.7)
4.5
(3.0)
2.9
NC
10-2 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
Incineration of Waste
Ammonia Production and Urea Consumption
Lime Production
Cropland Remaining Cropland
Limestone and Dolomite Use
Soda Ash Production and Consumption
Aluminum Production
Petrochemical Production
Carbon Dioxide Consumption
Ferroalloy Production
Titanium Dioxide Production
Wetlands Remaining Wetlands
Phosphoric Acid Production
Zinc Production
Lead Production
Petroleum Systems
Silicon Carbide Production and Consumption
Land Use, Land-Use Change, and Forestry
(Sink)"
Biomass - Wood3
International Bunker Fuels"
Biomass - Ethanof
CH4
Natural Gas Systems
Enteric Fermentation
Landfills
Coal Mining
Manure Management
Petroleum Systems
Wastewater Treatment
Forest Land Remaining Forest Land
Rice Cultivation
Stationary Combustion
Abandoned Underground Coal Mines
Mobile Combustion
Composting
Petrochemical Production
Iron and Steel Production & Metallurgical
Coke Production
Field Burning of Agricultural Residues
Ferroalloy Production
Silicon Carbide Production and Consumption
Incineration of Waste
International Bunker Fuels"
N2O
Agricultural Soil Management
Mobile Combustion
Manure Management
Nitric Acid Production
Stationary Combustion
Forest Land Remaining Forest Land
Wastewater Treatment
N2O from Product Uses
Adipic Acid Production
Composting
Settlements Remaining Settlements
(0.1)
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
(0.3)
0.2
+
NC
47.9
NC
NC
(0.1)
61.5
60.3
(0.3)
(1.9)
NC
2.4
1.5
+
+
NC
+
NC
+
NC
NC
NC
(0.5)
NC
NC
NC
NC
(7.1)
(5.7)
+
0.1
(1.2)
+
+
+
NC
+
NC
NC
(0.2)
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
(0.1)
0.3
+
NC
87.7
NC
NC
(0.2)
73.9
78.6
(0.2)
(9.0)
NC
3.8
1.3
+
+
NC
+
NC
+
NC
NC
NC
(0.6)
NC
NC
NC
NC
(4.5)
(3.3)
+
0.4
(1.3)
+
+
+
NC
+
NC
NC
(0.2)
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
NC
0.6
0.3
+
NC
(106.1)
NC
NC
(0.4)
78.3
86.8
(0.2)
(13.1)
NC
4.3
1.1
+
+
NC
+
+
+
NC
NC
NC
(0.7)
NC
NC
NC
NC
(5.4)
(4.5)
+
0.6
(1.1)
+
+
+
NC
NC
NC
NC
(0.2)
NC
NC
NC
NC
NC
NC
NC
+
NC
NC
NC
NC
0.6
0.3
+
NC
(105.2)
(4.0)
NC
(0.6)
103.9
114.6
(0.2)
(15.3)
+
4.4
1.1
+
+
NC
+
(0.1)
+
NC
NC
NC
(0.7)
NC
NC
NC
NC
(3.1)
(2.3)
+
0.7
(1.1)
+
+
+
NC
NC
NC
NC
(0.6)
0.1
NC
(0.1)
NC
NC
NC
NC
NC
NC
NC
NC
NC
0.7
0.3
+
NC
(105.5)
(4.1)
NC
(0.7)
95.4
105.7
(0.2)
(15.2)
(0.2)
4.9
1.2
+
+
NC
+
(0.1)
+
NC
NC
NC
(0.7)
NC
NC
+
NC
(2.6)
(1.6)
+
0.8
(1.3)
(0.1)
+
+
NC
NC
NC
+
(1.0)
0.2
NC
1.0
(0.3)
NC
NC
NC
NC
NC
NC
0.1
+
0.8
0.3
+
NC
(100.1)
(0.1)
NC
(0.6)
109.1
115.4
(0.2)
(10.4)
(0.5)
4.4
1.1
0.2
+
NC
(0.2)
+
+
+
NC
NC
(0.7)
NC
NC
+
NC
(7.4)
(5.1)
+
0.8
(2.6)
+
+
+
NC
NC
+
(0.1)
Recalculations and Improvements 10-3
-------
1
2
3
4
5
6
9
10
11
12
13
Incineration of Waste
Field Burning of Agricultural Residues
Wetlands Remaining Wetlands
International Bunker Fuels"
HFCs
Substitution of Ozone Depleting Substances
HCFC-22 Production
Semiconductor Manufacture
PFCs
Semiconductor Manufacture
Aluminum Production
SF6
Electrical Transmission and Distribution
Magnesium Production and Processing
Semiconductor Manufacture
Net Change in Total Emissions'"
Percent Change
NC
(0.3)
NC
NC
NC
NC
NC
NC
NC
NC
NC
1.8
1.8
NC
NC
55.5
0.9%
NC
(0.4)
NC
NC
+
+
NC
NC
NC
NC
NC
1.0
1.0
NC
NC
69.4
1.0%
NC
(0.4)
NC
NC
1.0
1.0
NC
NC
NC
NC
NC
1.2
1.2
+
NC
81.3
1.1%
NC
(0.4)
NC
NC
1.6
1.6
NC
NC
NC
NC
NC
0.9
0.9
+
NC
108.5
1.5%
+
(0.4)
NC
NC
2.1
2.1
NC
+
+
+
NC
0.5
0.5
+
+
96.7
1.3%
+
(0.4)
+
NC
2.2
2.2
NC
+
+
+
NC
+
0.3
(0.1)
(0.2)
105.2
1.5%
+ Absolute value does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.
NC (No Change)
a Not included in emissions total.
b Excludes net CO2 flux from Land Use, Land-Use Change, and Forestry, and emissions from International Bunker Fuels.
Note: Totals may not sum due to independent rounding.
Table 10-2: Revisions to Net Flux of CO2 to the Atmosphere from Land Use, Land-Use Change, and Forestry (Tg
C02Eq.)
Component: Net CO2 Flux From Land
Use, Land-Use Change, and Forestry
Forest Land Remaining Forest Land
Cropland Remaining Cropland
Land Converted to Cropland
Grassland Remaining Grassland
Land Converted to Grassland
Settlements Remaining Settlements
Other
Net Change in Total Flux
Percent Change
1990
48.8
NC
NC
(0.1)
+
NC
(0.7)
47.9
5.3%
2000
89.4
NC
NC
+
+
NC
(1.9)
87.7
13.2%
2005 2006 2007 2008
(105.0) (105.0) (105.0) (99.1)
NC NC NC NC
NC NC NC NC
0.1 0.1 0.2 0.2
0.2 0.3 0.3 0.4
NC NC NC NC
(1.4) (0.6) (1.1) (1.7)
(106.1) (105.2) (105.5) (100.1)
(11.2%) (11.0%) (11.0%) (10.6%)
NC (No Change)
Note: Numbers in parentheses indicate a decrease in estimated net flux of CO2 to the atmosphere, or an increase in net
sequestration.
Note: Totals may not sum due to independent rounding.
+ Absolute value does not exceed 0.05 Tg CO2 Eq. or 0.05 percent.
14
15
16
10-4 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
i 11. References
2 Executive Summary
3 BEA (2010) 2009 Comprehensive Revision of the National Income and Product Accounts: Current-dollar and
4 "real" GDP, 1929-2009. Bureau of Economic Analysis (BEA), U.S. Department of Commerce, Washington, DC.
5 July 29, 2010. Available online at < http://www.bea.gov/national/index.htnrfgdp >.
6 EIA (2010) Supplemental Tables on Petroleum Product detail. Monthly Energy Review, September 2010, Energy
7 Information Administration, U.S. Department of Energy, Washington, DC. DOE/EIA-0035(2009/09).
8 EIA (2009) International Energy Annual 2007. Energy Information Administration (EIA), U.S. Department of
9 Energy. Washington, DC. Updated October 2008. Available online at
10 .
11 EPA (2009). "1970 - 2008 Average annual emissions, all criteria pollutants in MS Excel." National Emissions
12 Inventory (NEI) Air Pollutant Emissions Trends Data. Office of Air Quality Planning and Standards. Available
13 online at
14 EPA (2003) E-mail correspondence containing preliminary ambient air pollutant data. Office of Air Pollution and
15 the Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency. December 22, 2003.
16 IPCC (2007) Climate Change 2007: The Physical Science Basis. Contribution of Working Group I to the Fourth
17 Assessment Report of the Intergovernmental Panel on Climate Change. S. Solomon, D. Qin, M. Manning, Z. Chen,
18 M. Marquis, K.B. Averyt, M. Tignor and H.L. Miller (eds.). Cambridge University Press. Cambridge, United
19 Kingdom 996 pp.
20 IPCC (2006) 2006 IPCC Guidelines for National Greenhouse Gas Inventories. The National Greenhouse Gas
21 Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buendia, K. Miwa, T.
22 Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
23 IPCC (2003) Good Practice Guidance for Land Use, Land-Use Change, and Forestry. National Greenhouse Gas
24 Inventories Programme, The Intergovernmental Panel on Climate Change, J. Penman, et al. (eds.). Available
25 online at . August 13, 2004.
26 IPCC (2001) Climate Change 2001: The Scientific Basis. Intergovernmental Panel on Climate Change, J.T.
27 Houghton, Y. Ding, D.J. Griggs, M. Noguer, P.J. van der Linden, X. Dai, C.A. Johnson, and K. Maskell (eds.).
28 Cambridge University Press. Cambridge, United Kingdom.
29 IPCC (2000) Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories.,
30 National Greenhouse Gas Inventories Programme, Intergovernmental Panel on Climate Change. Montreal. May
31 2000. IPCC-XWDoc. 10 (1.IV.2000).
32 IPCC (1996) Climate Change 1995: The Science of Climate Change. Intergovernmental Panel on Climate Change,
33 J.T. Houghton, L.G. Meira Filho, B.A. Callander, N. Harris, A. Kattenberg, and K. Maskell. (eds.). Cambridge
34 University Press. Cambridge, United Kingdom.
3 5 IPCC/UNEP/OECD/IEA (1997) Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories.
36 Intergovernmental Panel on Climate Change, United Nations Environment Programme, Organization for Economic
37 Co-Operation and Development, International Energy Agency. Paris, France.
38 UNFCCC (2003) National Communications: Greenhouse Gas Inventories from Parties included in Annex I to the
39 Convention, UNFCCC Guidelines on Reporting and Review. Conference of the Parties, Eighth Session, New Delhi.
40 (FCCC/CP/2002/8). March 28, 2003.
41 U.S. Census Bureau (2010) U.S. Census Bureau International Database (IDE). Available online at
42 . August 15, 2010.
43 Introduction
44 CDIAC (2009) "Recent Greenhouse Gas Concentrations." T.J. Biasing; DOI: 10.3334/CDIAC/atg.032. Available
45 online at . 23 February 2010.
References 11-1
-------
1 EPA (2009) Technical Support Document for the Endangerment and Cause or Contribute Findings for Greenhouse
2 Gases Under Section 202(a) of the Clean Air Act. U.S. Environmental Protection Agency. December 2009.
3 IPCC (2007) Climate Change 2007: The Physical Science Basis. Contribution of Working Group I to the Fourth
4 Assessment Report of the Intergovernmental Panel on Climate Change. S. Solomon, D. Qin, M. Manning, Z. Chen,
5 M. Marquis, K.B. Averyt, M. Tignor and H.L. Miller (eds.). Cambridge University Press. Cambridge, United
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10 Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buendia, K. Miwa, T
11 Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
12 US Census Bureau (2010) Personal communication between Hilda Ward (of U.S. Census Bureau) and Caroline
13 Cochran (of ICF International). October 26, 2010 and November 5, 2010.
14 US Census Bureau (2009) Current Industrial Reports. Fertilizers and Related Chemicals: 2009. "Table 1:
15 Summary of Production of Principle Fertilizers and Related Chemicals: 2009 and 2008." June, 2010. MQ325B(08)-
16 5. Available online at < http://www.census.gov/manufacturing/cir/historical_data/mq325b/index.html>.
17 US Census Bureau (2009) Current Industrial Reports. Fertilizers and Related Chemicals: 2008. "Table 1:
18 Shipments and Production of Principal Fertilizers and Related Chemicals: 2004 to 2008." June, 2009. MQ325B(08)-
19 5. Available online at < http://www.census.gov/manufacturing/cir/historical_data/mq325b/index.html>.
20 US Census Bureau (2008) Current Industrial Reports. Fertilizers and Related Chemicals: 2007. "Table 1:
21 Shipments and Production of Principal Fertilizers and Related Chemicals: 2003 to 2007." June, 2008. MQ325B(07)-
22 5. Available online at < http://www.census.gov/manufacturing/cir/historical_data/mq325b/index.html >.
23 US Census Bureau (2006) Current Industrial Reports., "Table 995: Inorganic Chemicals and Fertilizers." August,
24 2006. Series MAQ325A Available online at .
25
26 Adipic Acid Production
27 ACC (2010) "Business of Chemistry (Annual Data).xls." American Chemistry Council Guide to the Business of
28 Chemistry. August 2010.
29 C&EN (1995) "Production of Top 50 Chemicals Increased Substantially in 1994." Chemical & Engineering News,
30 73(15): 17. April 10, 1995.
31 C&EN (1994) "Top 50 Chemicals Production Rose Modestly Last Year." Chemical & Engineering News,
32 72(15): 13. April 11, 1994.
33 C&EN (1993) "Top 50 Chemicals Production Recovered Last Year." Chemical & Engineer ing News, 71(15): 11.
34 April 12, 1993.
35 C&EN (1992) "Production of Top 50 Chemicals Stagnates in 1991." Chemical & Engineering News, 70(15): 17.
36 April 13, 1992.
37 CMR (2001) "Chemical Profile: Adipic Acid." Chemical Market Reporter. July 16, 2001.
38 CMR (1998) "Chemical Profile: Adipic Acid." Chemical Market Reporter. June 15, 1998.
39 CW (2007) "Product Focus: Adipic Acid." Chemical Week. August 1-8, 2007.
40 CW (2005) "Product Focus: Adipic Acid." Chemical Week. May 4, 2005.
41 CW (1999) "Product Focus: Adipic Acid/Adiponitrile." Chemical Week, p. 31. March 10, 1999.
42 Desai (2009) Personal communication. Mausami Desai, U.S. Environmental Protection Agency and Joseph Herr,
43 ICF International. November 19, 2009.
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1 Desai (2010) Personal communication. Mausami Desai, U.S. Environmental Protection Agency, and Caroline
2 Cochran, ICF International. November 8, 2010.
3 ICIS (2007) "Adipic Acid." ICIS Chemical Business Americas. July 9, 2007.
4 IPCC (2006) 2006IPCC Guidelines for National Greenhouse Gas Inventories. The National Greenhouse Gas
5 Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buendia, K. Miwa, T
6 Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
7 Reimer, R.A., Slaten, C.S., Seapan, M, Koch, T.A. and Triner, V.G. (1999) "Implementation of Technologies for
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12 Environment Institute Working Paper WP-US-1006. October 9, 2010.
13 Thiemens, M.H., and W.C. Trogler (1991) "Nylon production; an unknown source of atmospheric nitrous oxide."
14 Science 251:932-934.
15 VA DEQ (2010) Personal communication. Stanley Faggert, Virgina Department of Environmental Quality and
16 Joseph Herr, ICF International. March 12, 2010.
17 VA DEQ (2009) Personal communication. Stanley Faggert, Virgina Department of Environmental Quality and
18 Joseph Herr, ICF International. October 26, 2009.
19 VA DEQ (2006) Virginia Title V Operating Permit. Honeywell International Inc. Hopewell Plant. Virginia
20 Department of Environmental Quality. Permit No. PRO50232. Effective January 1, 2007.
21 Silicon Carbide Production
22 Corathers, L. (2007) Personal communication between Lisa Corathers, Commodity Specialist, U.S. Geological
23 Survey and Michael Obeiter of ICF International. September 2007.
24 Corathers, L. (2006) Personal communication between Lisa Corathers, Commodity Specialist, U.S. Geological
25 Survey and Erin Fraser of ICF International. October 2006.
26 IPCC (2006) 2006 IPCC Guidelines for National Greenhouse Gas Inventories. The National Greenhouse Gas
27 Inventories Programme, H.S. Eggleston, L. Buendia, K. Miwa, T. Ngara, and K. Tanabe, eds.; Institute for Global
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29 U.S. Census Bureau (2005 through 2010) U.SInternational Trade Commission (USITC) Trade DataWeb.
30 Available online at .
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32 USGS (1991a through 2009) Minerals Yearbook: Manufactured Abrasives Annual Report. U.S. Geological Survey,
33 Reston, VA.
34 USGS (1991b through 2007) Minerals Yearbook: Silicon Annual Report. U.S. Geological Survey, Reston, VA.
35 Petrochemical Production
36 ACC (2002, 2003, 2005 through 2010) Guide to the Business of Chemistry. American Chemistry Council,
37 Arlington, VA.
38 EIA (2004) Annual Energy Review 2003. Energy Information Administration, U.S. Department of Energy.
39 Washington, DC. DOE/EIA-0384(2003). September 2004.
40 EIA (2003) Emissions of Greenhouse Gases in the United States 2002. Office of Integrated Analysis and
41 Forecasting, Energy Information Administration, U.S. Department of Energy. Washington, DC. DOE-EIA-
42 0573(2002). February 2003.
43 European IPPC Bureau (2004) Draft Reference Document on Best Available Techniques in the Large Volumen
44 Inorganic Chemicals—Solid and Others Industry, Table 4.21. European Commission, 224. August 2004.
11-20 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 IPCC/UNEP/OECD/IEA (1997) Revised 1996IPCC Guidelines for National Greenhouse Gas Inventories.
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4 Johnson, G. L. (2010) Personal communication. Greg Johnson of Liskow & Lewis, on behalf of the International
5 Carbon Black Association (ICB A) and Caroline Cochran, ICF International. September 2010.
6 Johnson, G. L. (2009) Personal communication. Greg Johnson of Liskow & Lewis, on behalf of the International
7 Carbon Black Association (ICBA) and Jean Y. Kim, ICF International. October 2009.
8 Johnson, G. L. (2008) Personal communication. Greg Johnson of Liskow & Lewis, on behalf of the International
9 Carbon Black Association (ICBA) and Jean Y. Kim, ICF International. November 2008.
10 Johnson, G. L. (2007) Personal communication. Greg Johnson of Liskow & Lewis, on behalf of the International
11 Carbon Black Association (ICB A) and Tristan Kessler, ICF International. November 2007.
12 Johnson, G. L. (2006) Personal communication. Greg Johnson of Liskow & Lewis, on behalf of the International
13 Carbon Black Association (ICBA) and Erin Fraser, ICF International. October 2006.
14 Johnson, G. L. (2005) Personal communication. Greg Johnson of Liskow & Lewis, on behalf of the International
15 Carbon Black Association (ICBA) and Erin Fraser, ICF International. October 2005.
16 Johnson, G. L. (2003) Personal communication. Greg Johnson of Liskow & Lewis, on behalf of the International
17 Carbon Black Association (ICBA) and Caren Mintz, ICF International November 2003.
18 Othmer, K. (1992) Carbon (Carbon Black}, Vol. 4, 1045.
19 Srivastava, Manoj, I.D. Singh, and Himmat Singh (1999) "Structural Characterization of Petroleum Based
20 Feedstocks for Carbon Black Production," Table-1. Petroleum Science and Technology 17(1&2):67-80.
21 The Innovation Group (2004) Carbon Black Plant Capacity. Available online at .
23 U.S. Census Bureau (2007) 2006 Economic Census: Manufacturing—Industry Series: Carbon Black Manufacturing.
24 Department of Commerce. Washington, DC. EC0731I3. June 2009.
25 U.S. Census Bureau (2004) 2002 Economic Census: Manufacturing—Industry Series: Carbon Black Manufacturing.
26 Department of Commerce. Washington, DC. EC02-311-325182. September 2004.
27 U.S. Census Bureau (1999) 1997 Economic Census: Manufacturing—Industry Series: Carbon Black Manufacturing.
28 Department of Commerce. Washington, DC. EC97M-3251F. August 1999.
29 Titanium Dioxide Production
30 Gambogi, J. (2002) Telephone communication. Joseph Gambogi, Commodity Specialist, U.S. Geological Survey
31 and Philip Groth, ICF International. November 2002.
32 IPCC (2006) 2006 IPCC Guidelines for National Greenhouse Gas Inventories. The National Greenhouse Gas
33 Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buendia, K. Miwa, T
34 Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
35 Nelson, H.W. (1969) Petroleum Coke Handling Problems. Great Lakes Carbon Corporation.
36 USGS (2010) Mineral Commodity Summary: Titanium and Titanium Dioxide. U.S. Geological Survey, Reston, VA.
37 USGS (1991 through 2008) Mineral Yearbook: Titanium Annual Report. U.S. Geological Survey, Reston, VA.
38
39 Carbon Dioxide Consumption
40 Allis, R. et al. (2000) Natural CO2 Reservoirs on the Colorado Plateau and Southern Rocky Mountains: Candidates
41 for CO2 Sequestration. Utah Geological Survey and Utah Energy and Geoscience Institute. Salt Lake City, Utah.
42 ARI (1990 through 2010). CO2 Use in Enhanced Oil Recovery. Deliverable to ICF International under Task Order
43 67, July 8, 2010.
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7 Broadhead (2003). Personal communication. Ron Broadhead, Principal Senior Petroleum Geologist and Adjunct
8 faculty, Earth and Environmental Sciences Department, New Mexico Bureau of Geology and Mineral Resources,
9 and Robin Pestrusak, ICF International. September 5, 2003.
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17 the European Fertilizer Industry. Booklet 4 of 8. European Fertilizer Manufacturers Association. Available online at
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19 FIPR (2003) "Analyses of Some Phosphate Rocks." Facsimile Gary Albarelli, the Florida Institute of Phosphate
20 Research, Bartow, Florida, to Robert Lanza, ICF International. July 29, 2003.
21 FIPR (2003a) Florida Institute of Phosphate Research. Personal communication. Mr. Michael Lloyd, Laboratory
22 Manager, FIPR, Bartow, Florida, to Mr. Robert Lanza, ICF International. August 2003.
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26 Iron and Steel Production and Metallurgical Coke Production
27 AISI (2004 through 2010) Annual Statistical Report, American Iron and Steel Institute, Washington, DC.
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44 Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
45 IPCC/UNEP/OECD/IEA (1995) "Volume 3: Greenhouse Gas Inventory Reference Manual. Table 2-T.IPCC
11-22 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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5 Ferroalloy Production
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7 Sarah Menassian, ICF International. September 18, 2009.
8 IPCC (2006) 2006 IPCC Guidelines for National Greenhouse Gas Inventories. The National Greenhouse Gas
9 Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buendia, K. Miwa, T
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15 Aluminum Production
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17 Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buendia, K. Miwa, T
18 Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
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20 National Greenhouse Gas Inventories Programme, Intergovernmental Panel on Climate Change. Montreal. May
21 2000. IPCC-XWDoc. 10 (1.IV.2000).
22 USAA (2004, 2005, 2006) Primary Aluminum Statistics. U.S. Aluminum Association, Washington, DC.
23 USAA (2008, 2009) U.S. Primary Aluminum Production. U.S. Aluminum Association, Washington, DC.
24 USAA (2010) U.S. Primary Aluminum Production. U.S. Aluminum Association, Washington, DC.
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26 Reston, VA.
27 USGS (2007) 2006Mineral Yearbook: Aluminum. U.S. Geological Survey, Reston, VA.
28 USGS(2009a) 2008Mineral Yearbook: Aluminum. U.S. Geological Survey, Reston, VA.
29 USGS (2009b) Mineral Industry Surveys: Aluminum in December 2008. U.S. Geological Survey, Reston, VA.
30 USGS (2010a) 2009 Mineral Commodity Summaries: Aluminum. U.S. Geological Survey, Reston, VA.
31 USGS (2010b) Mineral Industry Surveys: Aluminum in December 2009. U.S. Geological Survey, Reston, VA.
32 USGS (2010c) Mineral Industry Surveys: Aluminum in September 2010. U.S. Geological Survey, Reston, VA.
33 Magnesium Production and Processing
34 Bartos S., C. Laush, J. Scharfenberg, and R. Kantamaneni (2007) "Reducing greenhouse gas emissions from
35 magnesium die casting," Journal of Cleaner Production, 15: 979-987, March.
36 Gjestland, H. and D. Magers (1996) "Practical Usage of Sulphur [Sulfur] Hexafluoride for Melt Protection in the
37 Magnesium Die Casting Industry," #13,1996 Annual Conference Proceedings, International Magnesium
38 Association. Ube City, Japan.
39 IPCC (2006) 2006 IPCC Guidelines for National Greenhouse Gas Inventories. The National Greenhouse Gas
40 Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buendia, K. Miwa, T
41 Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
42 RAND (2002) RAND Environmental Science and Policy Center, "Production and Distribution of SF6 by End-Use
43 Applications" Katie D. Smythe. International Conference on SF6 and the Environment: Emission Reduction
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3 Geological Survey, Reston, VA. Available online at
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6 online at < http://minerals.usgs.gov/minerals/pubs/commodity/magnesium/mcs-2010-mgmet.pdf>.
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8 Zinc Production
9 Horsehead Corp (2010). 10-k Annual Report for the Fiscal Year Ended December, 31 2009. Available at:
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11 Horsehead Corp (2008). 10-k Annual Report for the Fiscal Year Ended December, 31 2007. Available at:
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14 Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buendia, K. Miwa, T
15 Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
16 Sjardin (2003) CC>2 Emission Factors for Non-Energy Use in the Non-Ferrous Metal, Ferroalloys and Inorganics
17 Industry. Copernicus Institute. Utrecht, the Netherlands.
18 Steel Dust Recycling LLC (2010). Available at < http://steeldust.com/home.htm>. Accessed October 18, 2010.
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21 Steel." ISIJ International. Volume 40 No. 3: 292-299.
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23 Lead Production
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25 Society.
26 Guberman (2010) Personal communication. David Guberman, Commodity Specialist, USGS and Paul Stewart, ICF
27 International. September 22, 2010.
28 IPCC (2006) 2006 IPCC Guidelines for National Greenhouse Gas Inventories. The National Greenhouse Gas
29 Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buendia, K. Miwa, T
30 Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
31 Morris, D., F.R. Steward, and P. Evans (1983) Energy Efficiency of a Lead Smelter. Energy 8(5):337-349.
32 Sjardin, M. (2003) CO2 Emission Factors for Non-Energy Use in the Non-Ferrous Metal, Ferroalloys and
33 Inorganics Industry. Copernicus Institute. Utrecht, the Netherlands.
34 Ullman 's Encyclopedia of Industrial Chemistry: Fifth Edition (1997) Volume A5. John Wiley and Sons.
35 USGS (2010) Mineral Commodity Summary, Lead. U.S. Geological Survey, Reston, VA.
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37 USGS (2009b) Mineral Commodity Summary, Lead. U.S. Geological Survey, Reston, VA.
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39 HCFC-22 Production
40 ARAP (2010) Electronic mail communication from Dave Stirpe, Executive Director, Alliance for Responsible
41 Atmospheric Policy to Deborah Ottinger of the U.S. Environmental Protection Agency. September 10, 2010.
42 ARAP (2009) Electronic mail communication from Dave Stirpe, Executive Director, Alliance for Responsible
11-24 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
-------
1 Atmospheric Policy to Deborah Ottinger of the U.S. Environmental Protection Agency. September 21, 2009.
2 ARAP (2008) Electronic mail communication from Dave Stirpe, Executive Director, Alliance for Responsible
3 Atmospheric Policy to Deborah Ottinger of the U.S. Environmental Protection Agency. October 17, 2008.
4 ARAP (2007) Electronic mail communication from Dave Stirpe, Executive Director, Alliance for Responsible
5 Atmospheric Policy to Deborah Ottinger of the U.S. Environmental Protection Agency. October 2, 2007.
6 ARAP (2006) Electronic mail communication from Dave Stirpe, Executive Director, Alliance for Responsible
7 Atmospheric Policy to Sally Rand of the U.S. Environmental Protection Agency. July 11, 2006.
8 ARAP (2005) Electronic mail communication from Dave Stirpe, Executive Director, Alliance for Responsible
9 Atmospheric Policy to Deborah Ottinger of the U.S. Environmental Protection Agency. August 9, 2005.
10 ARAP (2004) Electronic mail communication from Dave Stirpe, Executive Director, Alliance for Responsible
11 Atmospheric Policy to Deborah Ottinger of the U.S. Environmental Protection Agency. June 3, 2004.
12 ARAP (2003) Electronic mail communication from Dave Stirpe, Executive Director, Alliance for Responsible
13 Atmospheric Policy to Sally Rand of the U.S. Environmental Protection Agency. August 18, 2003.
14 ARAP (2002) Electronic mail communication from Dave Stirpe, Executive Director, Alliance for Responsible
15 Atmospheric Policy to Deborah Ottinger of the U.S. Environmental Protection Agency. August 7, 2002.
16 ARAP (2001) Electronic mail communication from Dave Stirpe, Executive Director, Alliance for Responsible
17 Atmospheric Policy to Deborah Ottinger of the U.S. Environmental Protection Agency. August 6, 2001.
18 ARAP (2000) Electronic mail communication from Dave Stirpe, Executive Director, Alliance for Responsible
19 Atmospheric Policy to Sally Rand of the U.S. Environmental Protection Agency. August 13, 2000.
20 ARAP (1999) Facsimile from Dave Stirpe, Executive Director, Alliance for Responsible Atmospheric Policy to
21 Deborah Ottinger Schaefer of the U.S. Environmental Protection Agency. September 23, 1999.
22 ARAP (1997) Letter from Dave Stirpe, Director, Alliance for Responsible Atmospheric Policy to Elizabeth Dutrow
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24 IPCC (2006) 2006IPCC Guidelines for National Greenhouse Gas Inventories. The National Greenhouse Gas
25 Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buendia, K. Miwa, T
26 Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
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33 Substitution of Ozone Depleting Substances
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35 Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buendia, K. Miwa, T
36 Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
37 Semiconductor Manufacture
38 Burton, C.S., and R. Beizaie (2001) "EPA's PFC Emissions Model (PEVM) v. 2.14: Description and
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40 November 2001.
41 Citigroup Smith Barney (2005) Global Supply/Demand Model for Semiconductors. March 2005.
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45 . Information about the number of interconnect layers foryears 1990-2010 is contained in
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35 Solvent and Other Product Use
36 Nitrous Oxide from Product Uses
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41 Association. November 3, 2003.
42 CGA (2002) "CGA/NWSA Nitrous Oxide Fact Sheet." Compressed Gas Association. March 25, 2002.
11-26 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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27 IPCC (2006) 2006IPCC Guidelines for National Greenhouse Gas Inventories. The National Greenhouse Gas
28 Inventories Programme, The Intergovernmental Panel on Climate Change, H.S. Eggleston, L. Buendia, K. Miwa, T.
29 Ngara, and K. Tanabe (eds.). Hayama, Kanagawa, Japan.
30
31 Waste Sources of Indirect Greenhouse Gas Emissions
32 EPA (2009). "1970 - 2008 Average annual emissions, all criteria pollutants in MS Excel." National Emissions
33 Inventory (NEI) Air Pollutant Emissions Trends Data. Office of Air Quality Planning and Standards. Available
34 online at
35 EPA (2003) E-mail correspondence containing preliminary ambient air pollutant data. Office of Air Pollution and
36 the Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency. December 22, 2003.
37 EPA (1997) Compilation of Air Pollutant Emission Factors, AP-42. Office of Air Quality Planning and Standards,
38 U.S. Environmental Protection Agency. Research Triangle Park, NC. October 1997.
11-56 DRAFT - Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009
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